FirstEnergy (FE) 10-K 16 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Jan. 31, 2016	Jun. 30, 2015
Entity Information [Line Items]
Entity Registrant Name	FIRSTENERGY CORP
Entity Central Index Key	1,031,296
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		423,650,645
Entity Public Float			$ 13,727,177,963
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
FES
Entity Information [Line Items]
Entity Registrant Name	FirstEnergy Solutions Corp.
Entity Central Index Key	1,407,703
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding		7
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

Consolidated Statements of Inco

Consolidated Statements of Income (FirstEnergy Corp.) - USD ($) shares in Millions, $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Investment Income, Net										$ (22)	$ 72	$ 33
REVENUES:
Electric utilities		$ 3,541	$ 4,123	$ 3,465	$ 3,897	$ 3,483	$ 3,888	$ 3,496	$ 4,182	10,636	9,871	9,451
Unregulated businesses										4,390	5,178	5,441
Total revenues	[1]									15,026	15,049	14,892
OPERATING EXPENSES:
Fuel										1,855	2,280	2,496
Purchased power										4,318	4,716	3,963
Other operating expenses		952	850	916	1,057	901	858	1,021	1,182	3,749	3,962	3,593
Pension and OPEB mark-to-market adjustment		242	0	0	0	835	0	0	0	242	835	(256)
Provision for depreciation		313	328	322	319	316	308	302	294	1,282	1,220	1,202
Amortization of regulatory assets, net										268	12	539
General taxes										978	962	978
Impairment of long-lived assets										42	0	795
Total operating expenses										12,734	13,987	13,310
OPERATING INCOME (LOSS)		236	908	554	594	(337)	716	292	391	2,292	1,062	1,582
OTHER INCOME (EXPENSE):
Loss on debt redemptions										0	(8)	(132)
Impairment of equity method investment										(362)	0	0
Interest expense										(1,132)	(1,073)	(1,016)
Capitalized financing costs										117	118	103
Total other expense										(1,399)	(891)	(1,012)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)										893	171	570
INCOME TAXES (BENEFITS)		(170)	226	115	144	(268)	152	26	48	315	(42)	195
INCOME (LOSS) FROM CONTINUING OPERATIONS		(226)	395	187	222	(306)	333	64	122	578	213	375
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)		0	0	0	0	0	0	0	86	0	86	17
NET INCOME (LOSS)		$ (226)	$ 395	$ 187	$ 222	$ (306)	$ 333	$ 64	$ 208	578	299	392
EARNINGS AVAILABLE TO FIRSTENERGY CORP.										$ 578	$ 299	$ 392
EARNINGS PER SHARE OF COMMON STOCK:
Basic - Continuing Operations, in dollars per share		$ (0.53)	$ 0.94	$ 0.44	$ 0.53	$ (0.73)	$ 0.79	$ 0.16	$ 0.29	$ 1.37	$ 0.51	$ 0.90
Basic - Discontinued Operations, in dollars per share		0	0	0	0	0	0	0	0.21	0	0.20	0.04
Basic - Earnings Available to FirstEnergy Corp., in dollars per share		(0.53)	0.94	0.44	0.53	(0.73)	0.79	0.16	0.50	1.37	0.71	0.94
Diluted - Continuing Operations, in dollars per share		(0.53)	0.93	0.44	0.53	(0.73)	0.79	0.15	0.29	1.37	0.51	0.90
Diluted - Discontinued Operations, in dollars per share		0	0	0	0	0	0	0	0.20	0	0.20	0.04
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share		$ (0.53)	$ 0.93	$ 0.44	$ 0.53	$ (0.73)	$ 0.79	$ 0.15	$ 0.49	$ 1.37	$ 0.71	$ 0.94
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic, in shares										422	420	418
Diluted, in shares										424	421	419
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share										$ 1.44	$ 1.44	$ 1.65
[1]	Includes excise tax collections of $416 million, $420 million and $458 million in 2015, 2014 and 2013, respectively.

Consolidated Statements of Inc3

Consolidated Statements of Income (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Tax effect of discontinued operations	$ 0	$ 69	$ 9
Excise tax collections included in Revenue	$ 416	$ 420	$ 458

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (FirstEnergy Corp.) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
NET INCOME	$ 578	$ 299	$ 392
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(116)	(76)	(160)
Amortized gains (losses) on derivative hedges	5	(2)	3
Change in unrealized gain on available-for-sale securities	(11)	26	(10)
Other comprehensive loss	(122)	(52)	(167)
Income tax benefits on other comprehensive loss	(47)	(14)	(66)
Other comprehensive loss, net of tax	(75)	(38)	(101)
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	$ 503	$ 261	$ 291

Consolidated Balance Sheets (Fi

Consolidated Balance Sheets (FirstEnergy Corp.) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 131	$ 85
Receivables-
Customers, net of allowance for uncollectible accounts of $69 in 2015 and $59 in 2014	1,415	1,554
Other, net of allowance for uncollectible accounts of $5 in 2015 and 2014	180	225
Materials and supplies, at average cost	785	817
Prepaid taxes	135	128
Derivatives	157	159
Collateral	70	230
Other	167	160
Total current assets	3,040	3,358
PROPERTY, PLANT AND EQUIPMENT:
In service	49,952	47,484
Less - Accumulated provision for depreciation	15,160	14,150
Property, plant and equipment in service net of accumulated provision for depreciation	34,792	33,334
Construction work in progress	2,422	2,449
Total net property, plant and equipment	37,214	35,783
INVESTMENTS:
Nuclear plant decommissioning trusts	2,282	2,341
Other	506	881
Total other property and investments	2,788	3,222
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418
Regulatory assets	1,348	1,411
Other	1,379	1,456
Total deferred charges and other assets	9,145	9,285
Total assets	52,187	51,648
CURRENT LIABILITIES:
Currently payable long-term debt	1,166	804
Short-term borrowings	1,708	1,799
Accounts payable	1,075	1,279
Accrued taxes	519	490
Accrued compensation and benefits	334	329
Derivatives	106	167
Other	694	693
Total current liabilities	5,602	5,561
Common stockholders' equity-
Common stock, $0.10 par value, authorized 490,000,000 shares - 423,560,397 and 421,102,570 shares outstanding as of December 31, 2015 and December 31, 2014, respectively	42	42
Other paid-in capital	9,952	9,847
Accumulated other comprehensive income	171	246
Retained earnings	2,256	2,285
Total common stockholders' equity	12,421	12,420
Noncontrolling interest	1	2
Total equity	12,422	12,422
Long-term debt and other long-term obligations	19,192	19,176
Total capitalization	31,614	31,598
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	6,773	6,539
Retirement benefits	4,245	3,932
Asset retirement obligations	1,410	1,387
Deferred gain on sale and leaseback transaction	791	824
Adverse power contract liability	197	217
Other	1,555	1,590
Total noncurrent liabilities	$ 14,971	$ 14,489
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	$ 52,187	$ 51,648

Consolidated Balance Sheets (F6

Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Common stockholders' equity-
Common stock, par value (in dollars per share)	$ 0.1	$ 0.1
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	423,560,397	421,102,570
Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 69	$ 59
Other [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 5	$ 5

Consolidated Statements of Comm

Consolidated Statements of Common Stockholders' Equity (FirstEnergy Corp.) - USD ($) $ in Millions	Total	Common Stock	Other Paid-In Capital	Accumulated Other Comprehensive Income	Retained Earnings
Beginning Balance, Shares at Dec. 31, 2012		418,216,437
Beginning Balance at Dec. 31, 2012		$ 42	$ 9,769	$ 385	$ 2,888
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	$ 392				392
Amortized loss on derivative hedges, net of income taxes				2
Change in unrealized gain on investments, net of income taxes				(6)
Pensions and OPEB, net of income taxes				(97)
Stock-based compensation			(4)
Cash dividends declared on common stock					(690)
Stock issuance - employee benefits, Shares		412,122
Stock issuance - employee benefits			11
Ending Balance, Shares at Dec. 31, 2013		418,628,559
Ending Balance at Dec. 31, 2013		$ 42	9,776	284	2,590
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	$ 299				299
Amortized loss on derivative hedges, net of income taxes				(1)
Change in unrealized gain on investments, net of income taxes				16
Pensions and OPEB, net of income taxes				(53)
Stock-based compensation			20
Cash dividends declared on common stock					(604)
Stock issuance - employee benefits, Shares		2,474,011
Stock issuance - employee benefits			51
Ending Balance, Shares at Dec. 31, 2014	421,102,570	421,102,570
Ending Balance at Dec. 31, 2014	$ 12,420	$ 42	9,847	246	2,285
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	$ 578				578
Amortized loss on derivative hedges, net of income taxes				4
Change in unrealized gain on investments, net of income taxes				(7)
Pensions and OPEB, net of income taxes				(72)
Stock-based compensation			45
Cash dividends declared on common stock					(607)
Stock issuance - employee benefits, Shares		2,457,827
Stock issuance - employee benefits			60
Ending Balance, Shares at Dec. 31, 2015	423,560,397	423,560,397
Ending Balance at Dec. 31, 2015	$ 12,421	$ 42	$ 9,952	$ 171	$ 2,256

Consolidated Statements of Com8

Consolidated Statements of Common Stockholders' Equity (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
Unrealized gain (loss) on derivative hedges taxes	$ 1	$ (1)	$ 1
Unrealized gain (loss) on investment taxes	4	10	(4)
Taxes on pension and other postretirement taxes	$ (44)	$ (23)	$ (63)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (FirstEnergy Corp.) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$ 578	$ 299	$ 392
Adjustments to reconcile net income to net cash from operating activities-
Depreciation and amortization, including nuclear fuel and customer intangible amortization	1,836	1,563	2,022
Impairments of long-lived assets	42	0	795
Investment impairment, including equity method investment	464	37	90
Pension and OPEB mark-to-market adjustment	242	835	(256)
Deferred income taxes and investment tax credits, net	284	162	243
Deferred costs on sale leaseback transaction, net	48	48	48
Deferred purchased power and other costs	(105)	(115)	(76)
Asset removal costs charged to income	55	28	20
Retirement benefits	(20)	(53)	(168)
Commodity derivative transactions, net	(73)	64	(3)
Pension trust contributions	(143)	0	0
Gain on sale of investment securities held in trusts	(23)	(64)	(56)
Loss on debt redemptions	0	8	132
Make-whole premiums paid on debt redemptions	0	0	(187)
Lease payments on sale and leaseback transaction	(131)	(137)	(136)
Income from discontinued operations	0	(86)	(17)
Changes in current assets and liabilities-
Receivables	184	139	(114)
Materials and supplies	(15)	(65)	96
Prepayments and other current assets	(10)	126	(126)
Accounts payable	(243)	42	(25)
Accrued taxes	29	(165)	85
Accrued interest	(6)	31	(10)
Accrued compensation and benefits	5	(22)	19
Other current liabilities	75	23	(62)
Cash collateral, net	140	(54)	(36)
Other	234	69	(8)
Net cash provided from operating activities	3,447	2,713	2,662
New Financing-
Long-term debt	1,311	4,528	3,745
Short-term borrowings, net	0	0	1,435
Redemptions and Repayments-
Long-term debt	(879)	(1,759)	(3,600)
Short-term borrowings, net	(91)	(1,605)	0
Tender premiums paid on debt redemptions	0	0	(110)
Common stock dividend payments	(607)	(604)	(920)
Other	(13)	(47)	(73)
Net cash provided from (used for) financing activities	(279)	513	477
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2,704)	(3,312)	(2,638)
Nuclear fuel	(190)	(233)	(250)
Proceeds from asset sales	20	394	4
Sales of investment securities held in trusts	1,534	2,133	2,047
Purchases of investment securities held in trusts	(1,648)	(2,236)	(2,096)
Cash investments	7	35	(23)
Asset removal costs	(142)	(153)	(146)
Other	1	13	9
Net cash used for investing activities	(3,122)	(3,359)	(3,093)
Net change in cash and cash equivalents	46	(133)	46
Cash and cash equivalents at beginning of period	85	218	172
Cash and cash equivalents at end of period	131	85	218
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest (net of amounts capitalized)	1,028	931	969
Income taxes (received), net of refunds	$ 37	$ (103)	$ 36

Consolidated Statements of In10

Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) (FirstEnergy Solutions Corp.) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES:
Electric sales		$ 4,390	$ 5,178	$ 5,441
Total revenues	[1]	15,026	15,049	14,892
OPERATING EXPENSES:
Fuel		1,855	2,280	2,496
Purchased power		4,318	4,716	3,963
Other operating expenses		3,749	3,962	3,593
Pension and OPEB mark-to-market adjustment		242	835	(256)
Provision for depreciation		1,282	1,220	1,202
General taxes		978	962	978
Total operating expenses		12,734	13,987	13,310
OPERATING INCOME (LOSS)		2,292	1,062	1,582
OTHER INCOME (EXPENSE):
Loss on debt redemptions		0	(8)	(132)
Investment Income, Net		(22)	72	33
Interest expense		(1,132)	(1,073)	(1,016)
Capitalized interest		117	118	103
Total other expense		(1,399)	(891)	(1,012)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)		893	171	570
INCOME TAXES (BENEFITS)		315	(42)	195
INCOME (LOSS) FROM CONTINUING OPERATIONS		578	213	375
Discontinued operations (net of income taxes of $70 and $8, respectively)		0	86	17
NET INCOME (LOSS)		578	299	392
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME		578	299	392
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(116)	(76)	(160)
Amortized gain on derivative hedges		5	(2)	3
Change in unrealized gain on available-for-sale securities		(11)	26	(10)
Other comprehensive loss		(122)	(52)	(167)
Income taxes (benefits) on other comprehensive income (loss)		(47)	(14)	(66)
Other comprehensive loss, net of tax		(75)	(38)	(101)
FES
REVENUES:
Other		188	169	143
Total revenues	[2]	5,005	6,144	6,173
OPERATING EXPENSES:
Fuel		871	1,253	1,262
Other operating expenses		1,341	1,635	1,487
Pension and OPEB mark-to-market adjustment		57	297	(81)
Provision for depreciation		324	319	306
General taxes		98	128	138
Total operating expenses		4,728	6,674	5,931
OPERATING INCOME (LOSS)		277	(530)	242
OTHER INCOME (EXPENSE):
Loss on debt redemptions		0	(6)	(103)
Investment Income, Net		(14)	61	16
Miscellaneous income		3	6	28
Capitalized interest		35	34	39
Total other expense		(130)	(58)	(190)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)		147	(588)	52
INCOME TAXES (BENEFITS)		65	(228)	6
INCOME (LOSS) FROM CONTINUING OPERATIONS		82	(360)	46
Discontinued operations (net of income taxes of $70 and $8, respectively)		0	116	14
NET INCOME (LOSS)		82	(244)	60
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME		82	(244)	60
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(6)	(6)	(15)
Amortized gain on derivative hedges		(3)	(10)	(6)
Change in unrealized gain on available-for-sale securities		(9)	21	(8)
Other comprehensive loss		(18)	5	(29)
Income taxes (benefits) on other comprehensive income (loss)		(7)	2	(11)
Other comprehensive loss, net of tax		(11)	3	(18)
COMPREHENSIVE INCOME (LOSS)		71	(241)	42
FES | Affiliates
REVENUES:
Electric sales		664	861	652
OPERATING EXPENSES:
Purchased power		353	271	486
OTHER INCOME (EXPENSE):
Interest expense		(7)	(7)	(10)
FES | Non-Affiliates
REVENUES:
Electric sales		4,153	5,114	5,378
OPERATING EXPENSES:
Purchased power		1,684	2,771	2,333
OTHER INCOME (EXPENSE):
Interest expense		$ (147)	$ (146)	$ (160)
[1]	Includes excise tax collections of $416 million, $420 million and $458 million in 2015, 2014 and 2013, respectively.
[2]	Includes excise tax collections of $44 million, $69 million and $78 million in 2015, 2014 and 2013, respectively.

Consolidated Statements of In11

Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Tax effect of discontinued operations	$ 0	$ 69	$ 9
Excise tax collections included in Revenue	416	420	458
FES
Tax effect of discontinued operations	0	70	8
Excise tax collections included in Revenue	$ 44	$ 69	$ 78

Consolidated Balance Sheets (12

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 131	$ 85
Receivables-
Customers, net of allowance for uncollectible accounts of $8 in 2015 and $18 in 2014	1,415	1,554
Other, net of allowance for uncollectible accounts of $3 in 2015 and 2014	180	225
Materials and supplies	785	817
Derivatives	157	159
Collateral	70	230
Prepayments and other	167	160
Total current assets	3,040	3,358
PROPERTY, PLANT AND EQUIPMENT:
In service	49,952	47,484
Less - Accumulated provision for depreciation	15,160	14,150
Property, plant and equipment in service net of accumulated provision for depreciation	34,792	33,334
Construction work in progress	2,422	2,449
Total net property, plant and equipment	37,214	35,783
INVESTMENTS:
Nuclear plant decommissioning trusts	2,282	2,341
Other	506	881
Total other property and investments	2,788	3,222
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	331
Goodwill	6,418	6,418
Other	1,379	1,456
Total deferred charges and other assets	9,145	9,285
Total assets	52,187	51,648
CURRENT LIABILITIES:
Currently payable long-term debt	1,166	804
Short-term borrowings-
Short-term borrowings	1,708	1,799
Accounts payable-
Accrued taxes	519	490
Derivatives	106	167
Other	694	693
Total current liabilities	5,602	5,561
Common stockholders' equity-
Common stock, without par value, authorized 750 shares- 7 shares outstanding as of December 31, 2015 and 2014	42	42
Accumulated other comprehensive income	171	246
Retained earnings	2,256	2,285
Total common stockholders' equity	12,421	12,420
Long-term debt and other long-term obligations	19,192	19,176
Total capitalization	31,614	31,598
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	791	824
Accumulated deferred income taxes	6,773	6,539
Retirement benefits	4,245	3,932
Asset retirement obligations	1,410	1,387
Other	1,555	1,590
Total noncurrent liabilities	$ 14,971	$ 14,489
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	$ 52,187	$ 51,648
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2
Receivables-
Customers, net of allowance for uncollectible accounts of $8 in 2015 and $18 in 2014	275	415
Affiliated companies	451	525
Other, net of allowance for uncollectible accounts of $3 in 2015 and 2014	59	107
Notes receivable from affiliated companies	11	0
Materials and supplies	470	492
Derivatives	154	147
Collateral	70	229
Prepayments and other	66	68
Total current assets	1,558	1,985
PROPERTY, PLANT AND EQUIPMENT:
In service	14,311	13,596
Less - Accumulated provision for depreciation	5,765	5,208
Property, plant and equipment in service net of accumulated provision for depreciation	8,546	8,388
Construction work in progress	1,157	1,010
Total net property, plant and equipment	9,703	9,398
INVESTMENTS:
Nuclear plant decommissioning trusts	1,327	1,365
Other	10	10
Total other property and investments	1,337	1,375
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	61	78
Goodwill	23	23
Property taxes	40	41
Derivatives	79	52
Other	384	331
Total deferred charges and other assets	587	525
Total assets	13,185	13,283
CURRENT LIABILITIES:
Currently payable long-term debt	512	506
Short-term borrowings-
Short-term borrowings	8	99
Accounts payable-
Affiliated companies	542	416
Other	139	248
Accrued taxes	76	102
Derivatives	104	166
Other	181	184
Total current liabilities	1,562	1,756
Common stockholders' equity-
Common stock, without par value, authorized 750 shares- 7 shares outstanding as of December 31, 2015 and 2014	3,613	3,594
Accumulated other comprehensive income	46	57
Retained earnings	1,946	1,934
Total common stockholders' equity	5,605	5,585
Long-term debt and other long-term obligations	2,527	2,608
Total capitalization	8,132	8,193
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	791	824
Accumulated deferred income taxes	600	484
Retirement benefits	332	324
Asset retirement obligations	831	841
Derivatives	38	14
Other	899	847
Total noncurrent liabilities	$ 3,491	$ 3,334
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	$ 13,185	$ 13,283
FES | Affiliates
Short-term borrowings-
Other Short-term Borrowings	$ 0	$ 35

Consolidated Balance Sheets (13

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Common stockholders' equity-
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	423,560,397	421,102,570
Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 69	$ 59
Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 5	$ 5
FES
Common stockholders' equity-
Common stock, no par value
Common stock, shares authorized	750	750
Common stock, shares outstanding	7	7
FES | Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 8	$ 18
FES | Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 3	$ 3

Consolidated Statements of Co14

Consolidated Statements of Common Stockholders' Equity (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	Total	Common Stock	Accumulated Other Comprehensive Income	Retained Earnings	FES	FESCommon Stock	FESAccumulated Other Comprehensive Income	FESRetained Earnings
Beginning Balance, Shares at Dec. 31, 2012		418,216,437				7
Beginning Balance at Dec. 31, 2012		$ 42	$ 385	$ 2,888		$ 1,573	$ 72	$ 2,118
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 392				$ 60			60
Amortized loss on derivative hedges, net of income taxes			2				(4)
Change in unrealized gain on investments, net of income taxes			(6)				(5)
Pensions and OPEB, net of income taxes			(97)				(9)
Equity contribution from parent						1,500
Stock-based compensation						1
Consolidated tax benefit allocation						$ 6
Cash dividends declared on common stock				(690)
Ending Balance, Shares at Dec. 31, 2013		418,628,559				7
Ending Balance at Dec. 31, 2013		$ 42	284	2,590		$ 3,080	54	2,178
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 299				$ (244)			(244)
Amortized loss on derivative hedges, net of income taxes			(1)				(6)
Change in unrealized gain on investments, net of income taxes			16				13
Pensions and OPEB, net of income taxes			(53)				(4)
Equity contribution from parent						500
Stock-based compensation						7
Consolidated tax benefit allocation						$ 7
Cash dividends declared on common stock				(604)
Ending Balance, Shares at Dec. 31, 2014	421,102,570	421,102,570			7	7
Ending Balance at Dec. 31, 2014	$ 12,420	$ 42	246	2,285	$ 5,585	$ 3,594	57	1,934
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 578				$ 82			82
Amortized loss on derivative hedges, net of income taxes			4				(2)
Change in unrealized gain on investments, net of income taxes			(7)				(5)
Pensions and OPEB, net of income taxes			(72)				(4)
Stock-based compensation						10
Consolidated tax benefit allocation						$ 9
Cash dividends declared on common stock				(607)				(70)
Ending Balance, Shares at Dec. 31, 2015	423,560,397	423,560,397			7	7
Ending Balance at Dec. 31, 2015	$ 12,421	$ 42	$ 171	$ 2,256	$ 5,605	$ 3,613	$ 46	$ 1,946

Consolidated Statements of Co15

Consolidated Statements of Common Stockholders' Equity (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Unrealized gain (loss) on derivative hedges taxes	$ 1	$ (1)	$ 1
Unrealized gain (loss) on investment taxes	4	10	(4)
Taxes on pension and other postretirement taxes	(44)	(23)	(63)
FES
Unrealized gain (loss) on derivative hedges taxes	(1)	(4)	(2)
Unrealized gain (loss) on investment taxes	(4)	8	(3)
Taxes on pension and other postretirement taxes	$ (2)	$ (2)	$ (6)

Consolidated Statements of Ca16

Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$ 578	$ 299	$ 392
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel and customer intangible amortization	1,836	1,563	2,022
Investment impairment, including equity method investment	464	37	90
Pension and OPEB mark-to-market adjustment	242	835	(256)
Deferred income taxes and investment tax credits, net	284	162	243
Deferred costs on sale leaseback transaction, net	48	48	48
Gain on sale of investment securities held in trusts	(23)	(64)	(56)
Commodity derivative transactions, net	(73)	64	(3)
Loss on debt redemptions	0	8	132
Make-whole premiums paid on debt redemptions	0	0	(187)
Lease payments on sale and leaseback transaction	(131)	(137)	(136)
Income from discontinued operations	0	(86)	(17)
Changes in current assets and liabilities-
Receivables	184	139	(114)
Materials and supplies	(15)	(65)	96
Prepayments and other current assets	(10)	126	(126)
Increase (decrease) in operating liabilities-
Accounts payable	(243)	42	(25)
Accrued taxes	29	(165)	85
Accrued compensation and benefits	5	(22)	19
Other current liabilities	75	23	(62)
Cash collateral, net	140	(54)	(36)
Other	234	69	(8)
Net cash provided from operating activities	3,447	2,713	2,662
New financing-
Long-term debt	1,311	4,528	3,745
Short-term borrowings, net	0	0	1,435
Redemptions and Repayments-
Long-term debt	(879)	(1,759)	(3,600)
Short-term borrowings, net	(91)	(1,605)	0
Tender premiums paid on debt redemptions	0	0	(110)
Common stock dividend payments	(607)	(604)	(920)
Other	(13)	(47)	(73)
Net cash provided from (used for) financing activities	(279)	513	477
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2,704)	(3,312)	(2,638)
Nuclear fuel	(190)	(233)	(250)
Proceeds from asset sales	20	394	4
Sales of investment securities held in trusts	1,534	2,133	2,047
Purchases of investment securities held in trusts	(1,648)	(2,236)	(2,096)
Cash investments	7	35	(23)
Other	1	13	9
Net cash used for investing activities	(3,122)	(3,359)	(3,093)
Net change in cash and cash equivalents	46	(133)	46
Cash and cash equivalents at beginning of period	85	218	172
Cash and cash equivalents at end of period	131	85	218
Cash paid (received) during the year-
Interest (net of amounts capitalized)	1,028	931	969
Income taxes (received), net of refunds	37	(103)	36
FES
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	82	(244)	60
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel and customer intangible amortization	569	599	533
Investment impairment, including equity method investment	90	33	79
Pension and OPEB mark-to-market adjustment	57	297	(81)
Deferred income taxes and investment tax credits, net	119	7	309
Deferred costs on sale leaseback transaction, net	48	48	48
Gain on sale of investment securities held in trusts	(24)	(61)	(49)
Commodity derivative transactions, net	(74)	65	5
Loss on debt redemptions	0	6	103
Make-whole premiums paid on debt redemptions	0	0	(31)
Lease payments on sale and leaseback transaction	(131)	(131)	(131)
Income from discontinued operations	0	(116)	(14)
Changes in current assets and liabilities-
Receivables	277	674	(393)
Materials and supplies	(25)	(44)	57
Prepayments and other current assets	14	14	(39)
Increase (decrease) in operating liabilities-
Accounts payable	(76)	(477)	(145)
Accrued taxes	(26)	(50)	(207)
Accrued compensation and benefits	(4)	(11)	2
Other current liabilities	47	(7)	15
Cash collateral, net	159	(92)	(34)
Other	49	61	(9)
Net cash provided from operating activities	1,151	571	78
New financing-
Long-term debt	341	878	0
Short-term borrowings, net	0	0	431
Equity contribution from parent	0	500	1,500
Redemptions and Repayments-
Long-term debt	(411)	(816)	(1,202)
Short-term borrowings, net	(126)	(301)	0
Tender premiums paid on debt redemptions	0	0	(67)
Common stock dividend payments	(70)	0	0
Other	(6)	(15)	(9)
Net cash provided from (used for) financing activities	(272)	246	653
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(627)	(839)	(717)
Nuclear fuel	(190)	(233)	(250)
Proceeds from asset sales	13	307	21
Sales of investment securities held in trusts	733	1,163	940
Purchases of investment securities held in trusts	(791)	(1,219)	(1,000)
Cash investments	(10)	0	0
Loans to affiliated companies, net	(11)	0	276
Other	4	4	(2)
Net cash used for investing activities	(879)	(817)	(732)
Net change in cash and cash equivalents	0	0	(1)
Cash and cash equivalents at beginning of period	2	2	3
Cash and cash equivalents at end of period	2	2	2
Cash paid (received) during the year-
Interest (net of amounts capitalized)	114	118	157
Income taxes (received), net of refunds	$ (5)	$ (384)	$ 23

Organization, Basis of Presenta

Organization, Basis of Presentation	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	ORGANIZATION AND BASIS OF PRESENTATION Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms. FirstEnergy Corp. was organized under the laws of the State of Ohio in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, FES and its principal subsidiaries (FG and NG), AE Supply, MP, PE, WP, FET and its principal subsidiaries (ATSI and TrAIL), and AESC. In addition, FE holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., GPU Nuclear, Inc., and AE Ventures, Inc. FirstEnergy and its subsidiaries are involved in the generation, transmission, and distribution of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, serving six million customers in the Midwest and Mid-Atlantic regions. Its generation subsidiaries control nearly 17,000 MW of capacity from a diverse mix of non-emitting nuclear, scrubbed coal, natural gas, hydroelectric and other renewables. FirstEnergy’s transmission operations include approximately 24,000 miles of lines and two regional transmission operation centers. FirstEnergy follows GAAP and complies with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued. FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 8, Variable Interest Entities). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but with respect to which they are not the primary beneficiary and do not exercise control, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income. These Notes to the Consolidated Financial Statements are combined for FirstEnergy and FES. Certain prior year amounts have been reclassified to conform to the current year presentation. ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities, AGC, ATSI, PATH and TrAIL since their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be charged to and collected from customers. FirstEnergy records regulatory assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These assets and liabilities are amortized in the Consolidated Statements of Income concurrent with the recovery or refund through customer rates. FirstEnergy believes that it is probable that its regulatory assets and liabilities will be recovered and settled, respectively, through future rates. FirstEnergy and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions. The following table provides information about the composition of net regulatory assets as of December 31, 2015 and December 31, 2014 , and the changes during the year ended December 31, 2015 : Regulatory Assets by Source December 31, December 31, Increase (Decrease) (In millions) Regulatory transition costs $ 185 $ 240 $ (55 ) Customer receivables for future income taxes 355 370 (15 ) Nuclear decommissioning and spent fuel disposal costs (272 ) (305 ) 33 Asset removal costs (372 ) (254 ) (118 ) Deferred transmission costs 115 90 25 Deferred generation costs 243 281 (38 ) Deferred distribution costs 335 182 153 Contract valuations 186 153 33 Storm-related costs 403 465 (62 ) Other 170 189 (19 ) Net Regulatory Assets included on the Consolidated Balance Sheets $ 1,348 $ 1,411 $ (63 ) Regulatory assets that do not earn a current return totaled approximately $148 million and $ 488 million as of December 31, 2015 and 2014 , respectively, primarily related to storm damage costs. JCP&L's regulatory asset related to 2011 and 2012 storm damage costs began earning a return on April 1, 2015. Effective with the approved settlement on April 9, 2015, associated with their general base rate case, the Pennsylvania Companies transferred the net book value of legacy meters from plant-in-service to regulatory assets, which is being recovered over five years. As of December 31, 2015 and December 31, 2014 , FirstEnergy had approximately $ 116 million and $243 million of net regulatory liabilities that are primarily related to asset removal costs. Net regulatory liabilities are classified within other noncurrent liabilities on the Consolidated Balance Sheets. REVENUES AND RECEIVABLES The Utilities' principal business is providing electric service to customers in Ohio, Pennsylvania, West Virginia, New Jersey and Maryland. FES' principal business is supplying electric power to end-use customers through retail and wholesale arrangements, including affiliated company power sales to meet a portion of the POLR and default service requirements, and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland. Retail customers are metered on a cycle basis. Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, FirstEnergy accrues the estimated unbilled amount as revenue and reverses the related prior period estimate. Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers for the Utilities, and retail and wholesale sales to customers for FES. There was no material concentration of receivables as of December 31, 2015 and 2014 with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2015 and 2014 are included below. Customer Receivables FirstEnergy FES (In millions) December 31, 2015 Billed $ 836 $ 165 Unbilled 579 110 Total $ 1,415 $ 275 December 31, 2014 Billed $ 914 $ 239 Unbilled 640 176 Total $ 1,554 $ 415 EARNINGS PER SHARE OF COMMON STOCK Basic earnings per share of common stock are computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock: Reconciliation of Basic and Diluted Earnings per Share of Common Stock 2015 2014 2013 (In millions, except per share amounts) Income from continuing operations available to common shareholders $ 578 $ 213 $ 375 Discontinued operations (Note 19) — 86 17 Net income $ 578 $ 299 $ 392 Weighted average number of basic shares outstanding 422 420 418 Assumed exercise of dilutive stock options and awards (1) 2 1 1 Weighted average number of diluted shares outstanding 424 421 419 Earnings per share: Basic earnings per share: Continuing operations $ 1.37 $ 0.51 $ 0.90 Discontinued operations (Note 19) — 0.20 0.04 Earnings per basic share $ 1.37 $ 0.71 $ 0.94 Diluted earnings per share: Continuing operations $ 1.37 $ 0.51 $ 0.90 Discontinued operations (Note 19) — 0.20 0.04 Earnings per diluted share $ 1.37 $ 0.71 $ 0.94 (1) For the years ended December 31, 2015 , 2014 and 2013, approximately one million , two million , and two million shares were excluded from the calculation of diluted shares outstanding, respectively, as their inclusion would be antidilutive. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred. The cost of nuclear fuel is capitalized within the CES segment's Property, plant and equipment and charged to fuel expense using the specific identification method. The cost of nuclear fuel included in CES' net plant as of December 31, 2015 was $418 million . Net plant in service balances by segment as of December 31, 2015 and 2014 were as follows: December 31, 2015 December 31, 2014 Property, Plant and Equipment In Service (2) Accum. Depr. Net Plant In Service (2) Accum. Depr. Net Plant (In millions) Regulated Distribution $ 24,553 $ (7,058 ) $ 17,495 $ 23,973 $ (6,759 ) $ 17,214 Regulated Transmission 7,703 (1,647 ) 6,056 6,634 (1,595 ) 5,039 Competitive Energy Services (1) 17,214 (6,213 ) 11,001 16,442 (5,598 ) 10,844 Corporate/Other 482 (242 ) 240 435 (198 ) 237 Total $ 49,952 $ (15,160 ) $ 34,792 $ 47,484 $ (14,150 ) $ 33,334 (1) Primarily consists of generating assets and nuclear fuel as discussed above. (2) Includes capital leases of $253 million and $281 million at December 31, 2015 and 2014, respectively. The major classes of Property, plant and equipment are largely consistent with the segment disclosures above, with the exception of Regulated Distribution, which has approximately $2.0 billion of regulated generation net plant in service. FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite rates for FirstEnergy's and FES' electric plant in 2015 , 2014 and 2013 are shown in the following table: Annual Composite Depreciation Rate 2015 2014 2013 FirstEnergy 2.5 % 2.5 % 2.6 % FES 3.2 % 3.1 % 3.1 % For the years ended December 31, 2015 , 2014 and 2013 , capitalized financing costs on FirstEnergy's Consolidated Statements of Income include $49 million , $49 million and $28 million , respectively, of allowance for equity funds used during construction and $68 million , $69 million and $75 million , respectively, of capitalized interest. Jointly Owned Plants FE, through its subsidiary, AGC, owns an undivided 40% interest ( 1,200 MWs) in a 3,003 MW pumped storage, hydroelectric station in Bath County, Virginia, operated by the 60% owner, Virginia Electric and Power Company, a non-affiliated utility. Net Property, plant and equipment includes $666 million representing AGC's share in this facility as of December 31, 2015 of which $484 million is unregulated and included within the CES segment. AGC is obligated to pay its share of the costs of this jointly-owned facility in the same proportion as its ownership interest using its own financing. AGC's share of direct expenses of the joint plant is included in FE's operating expenses on the Consolidated Statements of Income. Asset Retirement Obligations FE recognizes an ARO for the future decommissioning of its nuclear power plants and future remediation of other environmental liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FE's current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FE uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plant's current license, settlement based on an extended license term and expected remediation dates. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition. AROs as of December 31, 2015 , are described further in Note 13, Asset Retirement Obligations. ASSET IMPAIRMENTS Long-lived Assets FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, an impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. FirstEnergy utilizes the income approach, based upon discounted cash flows to estimate fair value. On October 9, 2013, MP sold its approximate 8% share of Pleasants at its fair market value of $ 73 million to AE Supply, and AE Supply sold its approximate 80% share of Harrison to MP at its book value of $ 1.2 billion . The transaction resulted in AE Supply receiving net consideration of $ 1.1 billion and MP's assumption of a $ 73.5 million pollution control note. In connection with the transaction, MP recorded a pre-tax impairment charge of approximately $ 322 million to reduce the net book value of the Harrison Power Station to the amount that was permitted to be included in jurisdictional rate base. Additionally, MP recognized a regulatory liability of approximately $ 23 million in 2013 representing refunds to customers associated with the excess purchase price received by MP above the net book value of MP's minority interest in the Pleasants Power Station. The impairment charge recognized in 2013 is included within the results of the Regulated Distribution segment. On July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating the Hatfield's Ferry, generating Units 1-3, and Mitchell, generating units 2-3. As a result of this decision FirstEnergy recorded a pre-tax impairment of approximately $473 million to continuing operations, which also includes pre-tax impairments of $13 million related to excessive inventory at these facilities. The impairment charge recognized in 2013 is included within the results of the CES segment. On October 9, 2013, Hatfield's Ferry Units 1-3 and Mitchell Units 2-3 were deactivated. During 2015, FirstEnergy recognized impairments totaling $42 million associated with certain non-core assets, including equipment and facilities. The impairment charges are included within the Regulated Distribution segment ( $8 million ) and the CES segment ( $34 million ). Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated Transmission, and CES. The following table presents goodwill by reporting unit: Goodwill Regulated Distribution Regulated Transmission Competitive Energy Services Consolidated (In millions) Balance as of December 31, 2015 $ 5,092 $ 526 $ 800 $ 6,418 There were no changes in goodwill for any reporting unit during 2015 . As of December 31, 2015 and 2014 , total goodwill recognized by FES was $23 million . Neither FirstEnergy nor FES has accumulated impairment charges as of December 31, 2015 . Annual impairment testing is conducted as of July 31 of each year and for 2015 , 2014 and 2013 , the analysis indicated no impairment of goodwill. For 2015, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units, assessing economic, industry and market considerations in addition to the reporting unit's overall financial performance. It was determined that the fair value of these reporting units were, more likely than not, greater than their carrying value and a quantitative analysis was not necessary for 2015. FirstEnergy performed a quantitative assessment of the CES reporting unit as of July 31, 2015. Key assumptions incorporated into the CES discounted cash flow analysis requiring significant management judgment included the following: • Future Energy and Capacity Prices: FirstEnergy used observable market information for near term forward power prices, PJM auction results for near term capacity pricing, and a longer-term pricing model for energy and capacity that considered the impact of key factors such as load growth, plant retirements, carbon and other environmental regulations, and natural gas pipeline construction, as well as coal and natural gas pricing. • Retail Sales and Margin: FirstEnergy used CES' current retail targeted portfolio to estimate future retail sales volume as well as historical financial results to estimate retail margins. • Operating and Capital Costs: FirstEnergy used estimated future operating and capital costs, including the estimated impact on costs of pending carbon and other environmental regulations, as well as costs associated with capacity performance reforms in the PJM market. • Discount Rate: A discount rate of 8.25% , based on a capital structure, return on debt and return on equity of selected comparable companies. • Terminal Value: A terminal value of 7.0x earnings before interest, taxes, depreciation and amortization based on consideration of peer group data and analyst consensus expectations. Based on the results of the quantitative analysis, the fair value of the CES reporting unit exceeded its carrying value by approximately 10% . Continued weak economic conditions, lower than expected power and capacity prices, a higher cost of capital and revised environmental requirements could have a negative impact on future goodwill assessments. Investments At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy first considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value. Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES, OE and TE are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of OTTI. The NDTs of JCP&L, ME and PN are subject to regulatory accounting with unrealized gains and losses offset in net regulatory assets. In 2015 , 2014 and 2013 , FirstEnergy recognized $102 million , $37 million and $90 million , respectively, of OTTI. During the same periods, FES recognized OTTI of $90 million , $33 million and $79 million , respectively. The fair values of FirstEnergy’s investments are disclosed in Note 9, Fair Value Measurements. FirstEnergy 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. In 2015, Global Holding incurred losses primarily as a result of declines in coal prices due to weakening global and U.S. coal demand. Based on the significant decline in coal pricing and the current outlook for the coal market, including the significant decline in the market capitalization of coal companies in 2015, FirstEnergy assessed the value of its investment in Global Holding and determined there was a decline in the fair value of the investment below its carrying value that was other than temporary, resulting in an a pre-tax impairment charge of $362 million . Key assumptions incorporated into the discounted cash flow analysis utilized in the impairment analysis included the discount rate, future long term coal prices, production levels, sales forecasts, projected capital and operating costs. The impairment charge is classified as a component of Other Income (Expense) in the Consolidated Statement of Income. See Note 8, Variable Interest Entities, for further discussion of FirstEnergy's investment in Global Holding. INVENTORY Materials and supplies inventory includes fuel inventory and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory. Materials are generally charged to inventory at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed. Fuel inventory is accounted for at weighted average cost when purchased, and recorded to fuel expense when consumed. NEW ACCOUNTING PRONOUNCEMENTS In May 2014, the FASB issued, ASU 2014-09 "Revenue from Contracts with Customers", requiring entities to recognize revenue by applying a five-step model in accordance with the core principle to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue recognition are expanded. In August 2015, the FASB issued a final Accounting Standards Update deferring the effective date until fiscal years beginning after December 15, 2017. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, (the original effective date). The standard shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In February 2015, the FASB issued, ASU 2015-02 "Consolidations: Amendments to the Consolidation Analysis", which amends current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate whether an entity should be consolidated. This standard is effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. A reporting entity must apply the amendments using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments retrospectively. FirstEnergy does not expect this amendment to have a material effect on its financial statements. In April 2015, the FASB issued, ASU 2015-03 "Simplifying the Presentation of Debt Issuance Costs", which requires debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount . The guidance is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been previously issued. Upon adoption, an entity must apply the new guidance retrospectively to all prior periods presented in the financial statements. I n addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements", which states given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to the line-of-credit arrangements, the SEC staff would not object to presenting those deferred debt issuance costs as an asset and subsequently amortizing the costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit. FirstEnergy will adopt ASU 2015-15 and ASU 2015-03 beginning January 1, 2016. As of December 31, 2015, FirstEnergy and FES debt issuance costs included in Deferred Charges and Other Assets were $93 million and $17 million , respectively. FirstEnergy will elect to continue presenting debt issuance costs relating to its revolving credit facilities as an asset. In August 2015, the FASB issued ASU 2015 -13, "Application of the NPNS Scope Exception to Certain Electricity Contracts within Nodal Energy Markets", which confirmed that forward physical contracts for the sale or purchase of electricity meet the physical delivery criterion within the NPNS scope exception when the electricity is transmitted through a grid managed by an ISO. As a result, an entity can elect the NPNS exception within the derivative accounting guidance for such contracts, provided that the other NPNS criteria are also met. The ASU was effective on issuance and requires prospective application. There was no material effect on FirstEnergy's financial statements resulting from the issuance of ASU 2015-13. In November 2015, the FASB issued ASU 2015 - 17, "Balance Sheet Classification of Deferred Taxes ", which requires all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The new guidance will be effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The guidance may be applied either prospectively, for all deferred tax assets and liabilities, or retrospectively. FirstEnergy early adopted ASU 2015-17 as of December 2015, and applied the new guidance retrospectively to all prior periods presented in the financial statements. There was no impact from the early adoption of ASU 2015-17 on the Consolidated Statements of Income. On the Consolidated Balance Sheet as of December 31, 2014, FirstEnergy and FES reclassified $518 million and $27 million of Accumulated Deferred Income Taxes from Current Assets to Noncurrent Liabilities. In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities". Changes to the current GAAP model primarily affect the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption can be elected for all financial statements of fiscal years and interim periods that have not yet been issued or that have not yet been made available for issuance . FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME	ACCUMULATED OTHER COMPREHENSIVE INCOME The changes in AOCI for the years ended December 31, 2015 , 2014 and 2013 for FirstEnergy are shown in the following table: FirstEnergy Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2013 $ (38 ) $ 15 $ 408 $ 385 Other comprehensive income before reclassifications — 46 35 81 Amounts reclassified from AOCI 3 (56 ) (195 ) (248 ) Other comprehensive income (loss) 3 (10 ) (160 ) (167 ) Income tax (benefits) on other comprehensive income (loss) 1 (4 ) (63 ) (66 ) Other comprehensive income (loss), net of tax 2 (6 ) (97 ) (101 ) AOCI Balance, December 31, 2013 $ (36 ) $ 9 $ 311 $ 284 Other comprehensive income before reclassifications — 89 92 181 Amounts reclassified from AOCI (2 ) (63 ) (168 ) (233 ) Other comprehensive income (loss) (2 ) 26 (76 ) (52 ) Income tax (benefits) on other comprehensive income (loss) (1 ) 10 (23 ) (14 ) Other comprehensive income (loss), net of tax (1 ) 16 (53 ) (38 ) AOCI Balance, December 31, 2014 $ (37 ) $ 25 $ 258 $ 246 Other comprehensive income before reclassifications — 14 10 24 Amounts reclassified from AOCI 5 (25 ) (126 ) (146 ) Other comprehensive income (loss) 5 (11 ) (116 ) (122 ) Income tax (benefits) on other comprehensive income (loss) 1 (4 ) (44 ) (47 ) Other comprehensive income (loss), net of tax 4 (7 ) (72 ) (75 ) AOCI Balance, December 31, 2015 $ (33 ) $ 18 $ 186 $ 171 The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2015 , 2014 and 2013 : FirstEnergy Year Ended December 31, Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (2) 2015 2014 2013 (In millions) Gains & losses on cash flow hedges Commodity contracts $ (3 ) $ (10 ) $ (8 ) Other operating expenses Long-term debt 8 8 11 Interest expense 5 (2 ) 3 Total before taxes (1 ) 1 (1 ) Income taxes (benefits) $ 4 $ (1 ) $ 2 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (25 ) $ (63 ) $ (56 ) Investment income (loss) 9 24 21 Income taxes (benefits) $ (16 ) $ (39 ) $ (35 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (126 ) $ (168 ) $ (195 ) (1) 49 65 75 Income taxes (benefits) $ (77 ) $ (103 ) $ (120 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details. (2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI. The changes in AOCI for the years ended December 31, 2015 , 2014 and 2013 for FES are shown in the following table: FES Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2013 $ 3 $ 13 $ 56 $ 72 Other comprehensive income before reclassifications — 41 5 46 Amounts reclassified from AOCI (6 ) (49 ) (20 ) (75 ) Other comprehensive loss (6 ) (8 ) (15 ) (29 ) Income tax benefits on other comprehensive loss (2 ) (3 ) (6 ) (11 ) Other comprehensive loss, net of tax (4 ) (5 ) (9 ) (18 ) AOCI Balance, December 31, 2013 $ (1 ) $ 8 $ 47 $ 54 Other comprehensive income before reclassifications — 80 13 93 Amounts reclassified from AOCI (10 ) (59 ) (19 ) (88 ) Other comprehensive income (loss) (10 ) 21 (6 ) 5 Income tax (benefits) on other comprehensive income (loss) (4 ) 8 (2 ) 2 Other comprehensive income (loss), net of tax (6 ) 13 (4 ) 3 AOCI Balance, December 31, 2014 $ (7 ) $ 21 $ 43 $ 57 Other comprehensive income before reclassifications — 15 10 25 Amounts reclassified from AOCI (3 ) (24 ) (16 ) (43 ) Other comprehensive loss (3 ) (9 ) (6 ) (18 ) Income tax benefits on other comprehensive loss (1 ) (4 ) (2 ) (7 ) Other comprehensive loss, net of tax (2 ) (5 ) (4 ) (11 ) AOCI Balance, December 31, 2015 $ (9 ) $ 16 $ 39 $ 46 The following amounts were reclassified from AOCI for FES in the years ended December 31, 2015 , 2014 and 2013 : FES Year Ended December 31, Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (2) 2015 2014 2013 (In millions) Gains & losses on cash flow hedges Commodity contracts $ (3 ) $ (10 ) $ (8 ) Other operating expenses Long-term debt — — 2 Interest expense - other (3 ) (10 ) (6 ) Total before taxes 1 4 2 Income taxes (benefits) $ (2 ) $ (6 ) $ (4 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (24 ) $ (59 ) $ (49 ) Investment income (loss) 9 22 18 Income taxes (benefits) $ (15 ) $ (37 ) $ (31 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (16 ) $ (19 ) $ (20 ) (1) 6 7 8 Income taxes (benefits) $ (10 ) $ (12 ) $ (12 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details. (2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

Pension and Other Postemploymen

Pension and Other Postemployment Benefits	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS	PENSION AND OTHER POSTEMPLOYMENT BENEFITS FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits. In 2014, the qualified pension plan was amended authorizing a voluntary cashout window program for certain eligible terminated participants with vested benefits. Payment of benefits for participants that elected an immediate lump sum cash payment or an annuity resulted in a $40 million reduction to the underfunded status of the pension plan. Additionally, during 2015 and 2014, certain unions ratified their labor agreements that ended subsidized retiree health care resulting in a reduction to the OPEB benefit obligation by approximately $10 million and $97 million , respectively. FirstEnergy recognizes as a pension and OPEB mark-to-market adjustment the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The remaining components of pension and OPEB expense, primarily service costs, interest on obligations, assumed return on assets and prior service costs, are recorded on a monthly basis. The pension and OPEB mark-to-market adjustment for the years ended December 31, 2015, 2014, and 2013 were $369 million ( $242 million net of amounts capitalized), $1,243 million ( $835 million net of amounts capitalized), and $(396) million ( $(256) million net of amounts capitalized), respectively. In 2015, the pension and OPEB mark-to-market adjustment primarily reflects lower than expected asset returns as well as the impact of other demographic assumptions, including revisions to mortality assumptions, partially offset by a 25 basis point increase in the discount rate. FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. During the year ended December 31, 2015 , FirstEnergy made contributions of $143 million to its qualified pension plan. In 2016, FirstEnergy has minimum required funding obligations of $381 million to its qualified pension plan, of which $160 million has been contributed to date. FirstEnergy expects to make future contributions to the qualified pension plan in 2016 with cash, equity or a combination thereof, depending on, among other things, market conditions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of the measurement date. FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2015 , FirstEnergy’s qualified pension and OPEB plan assets experienced losses of $(172) million , or (2.7)% compared to earnings of $387 million , or 6.2% in 2014 and losses of $(22) million , or (0.3)% in 2013, and assumed a 7.75% rate of return for each year on plan assets which generated $476 million , $496 million and $535 million of expected returns on plan assets, respectively. The expected return on pension and OPEB assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets will increase or decrease future net periodic pension and OPEB cost as the difference is recognized annually in the fourth quarter of each fiscal year or whenever a plan is determined to qualify for remeasurement. During 2014, the Society of Actuaries published new mortality tables and improvement scales reflecting improved life expectancies and an expectation that the trend will continue. An analysis of FirstEnergy pension and OPEB plan mortality data indicated the use of the RP2014 mortality table with blue collar adjustment for females and projection scale SS2014INT was most appropriate as of December 31, 2015. As such, the RP2014 mortality table with projection scale SS2014INT was utilized to determine the 2015 benefit cost and obligation as of December 31, 2015 for the FirstEnergy pension and OPEB plans. The impact of using the RP2014 mortality table and projection scale SS2014INT resulted in an increase in the projected benefit obligation of $49 million and $1 million for the pension and OPEB plans, respectively, and was included in the 2015 pension and OPEB mark-to-market adjustment. Pension OPEB Obligations and Funded Status 2015 2014 2015 2014 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 9,249 $ 8,263 $ 757 $ 879 Service cost 193 167 5 9 Interest cost 383 402 29 39 Plan participants’ contributions — — 6 16 Plan amendments — 5 (10 ) (97 ) Medicare retiree drug subsidy — — 1 — Actuarial (gain) loss (277 ) 1,123 (2 ) 13 Benefits paid (469 ) (711 ) (62 ) (102 ) Benefit obligation as of December 31 $ 9,079 $ 9,249 $ 724 $ 757 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 5,824 $ 6,171 $ 464 $ 495 Actual return (losses) on plan assets (178 ) 349 6 38 Company contributions 161 15 17 17 Plan participants’ contributions — — 6 16 Benefits paid (469 ) (711 ) (62 ) (102 ) Fair value of plan assets as of December 31 $ 5,338 $ 5,824 $ 431 $ 464 Funded Status: Qualified plan $ (3,366 ) $ (3,064 ) Non-qualified plans (375 ) (361 ) Funded Status $ (3,741 ) $ (3,425 ) $ (293 ) $ (293 ) Accumulated benefit obligation $ 8,579 $ 8,744 $ — $ — Amounts Recognized on the Balance Sheet: Current liabilities $ (18 ) $ (17 ) $ — $ — Noncurrent liabilities (3,723 ) (3,408 ) (293 ) (293 ) Net liability as of December 31 $ (3,741 ) $ (3,425 ) $ (293 ) $ (293 ) Amounts Recognized in AOCI: Prior service cost (credit) $ 37 $ 45 $ (355 ) $ (479 ) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate 4.50 % 4.25 % 4.25 % 4.00 % Rate of compensation increase 4.20 % 4.20 % N/A N/A Assumed Health Care Cost Trend Rates (as of December 31) Health care cost trend rate assumed (pre/post-Medicare) N/A N/A 6.0-5.5% 7.5-7.0% Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) N/A N/A 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate N/A N/A 2026 2026 Allocation of Plan Assets (as of December 31) Equity securities 40 % 36 % 51 % 49 % Bonds 34 % 33 % 43 % 40 % Absolute return strategies 7 % 14 % — % 1 % Real estate 11 % 7 % — % 1 % Derivatives — % 1 % — % — % Cash and short-term securities 8 % 9 % 6 % 9 % Total 100 % 100 % 100 % 100 % The estimated 2016 amortization of pension and OPEB prior service costs (credits) from AOCI into net periodic pension and OPEB costs (credits) is approximately $8 million and $(80) million , respectively. Pension OPEB Components of Net Periodic Benefit Costs 2015 2014 2013 2015 2014 2013 (In millions) Service cost $ 193 $ 167 $ 197 $ 5 $ 9 $ 13 Interest cost 383 402 372 29 39 37 Expected return on plan assets (443 ) (462 ) (501 ) (33 ) (34 ) (34 ) Amortization of prior service cost (credit) 8 8 12 (134 ) (176 ) (207 ) Pension & OPEB mark-to-market adjustment 344 1,235 (267 ) 25 8 (129 ) Net periodic cost (credit) $ 485 $ 1,350 $ (187 ) $ (108 ) $ (154 ) $ (320 ) Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Pension OPEB 2015 2014 2013 2015 2014 2013 Weighted-average discount rate 4.25 % 5.00 % 4.25 % 4.00 % 4.75 % 4.00 % Expected long-term return on plan assets 7.75 % 7.75 % 7.75 % 7.75 % 7.75 % 7.75 % Rate of compensation increase 4.20 % 4.20 % 4.70 % N/A N/A N/A In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed rates of return on plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy. In 2016, FirstEnergy decreased the expected long-term return on plan assets to 7.50% . The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 9, Fair Value Measurements, for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2015 and 2014 . December 31, 2015 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 427 $ — $ 427 8 % Equity investments Domestic 869 75 — 944 18 % International 395 794 — 1,189 22 % Fixed income Government bonds — 232 — 232 4 % Corporate bonds — 1,115 — 1,115 21 % High yield debt — 438 — 438 8 % Mortgage-backed securities (non-government) — 31 — 31 1 % Alternatives Hedge funds (Absolute return) — 343 — 343 7 % Derivatives — 15 — 15 — % Private equity funds — — 24 24 — % Real estate funds — — 587 587 11 % Total (1) $ 1,264 $ 3,470 $ 611 $ 5,345 100 % (1) Excludes $(7) million as of December 31, 2015 of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. December 31, 2014 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 517 $ — $ 517 9 % Equity investments Domestic 1,266 8 — 1,274 22 % International 355 414 — 769 14 % Fixed income Government bonds — 159 — 159 3 % Corporate bonds — 1,386 — 1,386 24 % High yield debt — 300 — 300 5 % Mortgage-backed securities (non-government) — 37 — 37 1 % Alternatives Hedge funds (Absolute return) — 809 — 809 14 % Derivatives — 35 — 35 1 % Private equity funds — — 25 25 — % Real estate funds — — 421 421 7 % Total (1) $ 1,621 $ 3,665 $ 446 $ 5,732 100 % (1) Excludes $92 million as of December 31, 2014 of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. The following table provides a reconciliation of changes in the fair value of pension investments classified as Level 3 in the fair value hierarchy during 2015 and 2014 : Private Equity Funds Real Estate Funds (In millions) Balance as of January 1, 2014 $ 27 $ 385 Actual return on plan assets: Unrealized gains (losses) (2 ) 17 Realized gains 1 14 Transfers in (out) (1 ) 5 Balance as of December 31, 2014 $ 25 $ 421 Actual return on plan assets: Unrealized gains — 42 Realized gains (losses) (1 ) 16 Transfers in — 108 Balance as of December 31, 2015 $ 24 $ 587 As of December 31, 2015 and 2014 , the OPEB trust investments measured at fair value were as follows: December 31, 2015 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 25 $ — $ 25 6 % Equity investment Domestic 219 — — 219 50 % International 1 3 — 4 1 % Fixed income U.S. treasuries — 42 — 42 10 % Government bonds — 114 — 114 26 % Corporate bonds — 27 — 27 6 % High yield debt — 1 — 1 — % Mortgage-backed securities (non-government) — 3 — 3 1 % Alternatives Hedge funds — 1 — 1 — % Real estate funds — — 2 2 — % Total (1) $ 220 $ 216 $ 2 $ 438 100 % (1) Excludes $(7) million as of December 31, 2015 of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. December 31, 2014 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 41 $ — $ 41 9 % Equity investment Domestic 230 — — 230 48 % International 3 3 — 6 1 % Fixed income U.S. treasuries — 41 — 41 9 % Government bonds — 110 — 110 23 % Corporate bonds — 32 — 32 7 % High yield debt — 2 — 2 — % Mortgage-backed securities (non-government) — 3 — 3 1 % Alternatives Hedge funds — 5 — 5 1 % Real estate funds — — 3 3 1 % Total (1) $ 233 $ 237 $ 3 $ 473 100 % (1) Excludes $(9) million as of December 31, 2014 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. The following table provides a reconciliation of changes in the fair value of OPEB trust investments classified as Level 3 in the fair value hierarchy during 2015 and 2014 : Real Estate Funds Balance as of January 1, 2014 $ 5 Transfers out (2 ) Balance as of December 31, 2014 $ 3 Transfers out (1 ) Balance as of December 31, 2015 $ 2 FirstEnergy follows a total return investment approach using a mix of equities, fixed income and other available investments while taking into account the pension plan liabilities to optimize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate and private equity are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements and periodic asset/liability studies. FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2015 and 2014 are shown in the following table: Target Asset Allocations 2015 2014 Equities 38 % 42 % Fixed income 30 % 32 % Absolute return strategies 8 % 14 % Real estate 10 % 5 % Alternative investments 8 % 1 % Cash 6 % 6 % 100 % 100 % Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects: 1-Percentage-Point Increase 1-Percentage-Point Decrease (In millions) Effect on total of service and interest cost $ 1 $ (1 ) Effect on accumulated benefit obligation $ 26 $ (23 ) Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contributions: OPEB Pension Benefit Payments Subsidy Receipts (In millions) 2016 $ 484 $ 54 $ (3 ) 2017 505 54 (3 ) 2018 522 54 (3 ) 2019 533 54 (3 ) 2020 551 54 (3 ) Years 2021-2025 2,946 259 (9 ) FES’ share of the pension and OPEB net (liability) asset as of December 31, 2015 and 2014 , was as follows: Pension OPEB 2015 2014 2015 2014 (In millions) Net (Liability) Asset $ (303 ) $ (295 ) $ 25 $ 10 FES’ share of the net periodic benefit cost (credit), including the pension and OPEB mark-to-market adjustment, for the three years ended December 31, 2015 was as follows: Pension OPEB 2015 2014 2013 2015 2014 2013 (In millions) Net Periodic Cost (Credit) $ 10 $ 150 $ (30 ) $ (22 ) $ (24 ) $ (40 )

Stock-Based Compensation Plans

Stock-Based Compensation Plans	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation Plans	STOCK-BASED COMPENSATION PLANS FirstEnergy grants stock-based awards through the ICP 2015, primarily in the form of restricted stock and performance-based restricted stock units. Under FirstEnergy's previous incentive compensation plan, the ICP 2007, FirstEnergy also granted stock options and performance shares. The ICP 2007 and ICP 2015 include shareholder authorization to issue 29 million shares and 10 million shares, respectively, of common stock or their equivalent. As of December 31, 2015 , approximately 9.9 million shares were available for future grants under the ICP 2015 assuming maximum performance metrics are achieved for the outstanding cycles of restricted stock units. No shares are available for future grants under the ICP 2007. Any shares not issued due to forfeitures or cancellations are added back to the ICP 2015. Shares used under the ICP 2007 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods range from one to ten years , with the majority of awards having a vesting period of three years . FirstEnergy also issues stock through its 401(k) Savings Plan, EDCP, and DCPD. FirstEnergy records the compensation costs for stock-based compensation awards that will be paid in stock over the vesting period based on the fair value on the grant date, less estimated forfeitures. FirstEnergy adjusts the compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or settled. Realized tax benefits during the years ended December 31, 2015 , 2014 and 2013 were $10 million , $13 million and $13 million , respectively. The excess of the deductible amount over the recognized compensation cost is recorded as a component of stockholders’ equity and reported as a financing activity on the Consolidated Statements of Cash Flows. Stock-based compensation costs and the amount of stock-based compensation expense capitalized related to FirstEnergy and FES plans are included in the following tables: FirstEnergy Years ended December 31, Stock-based Compensation Plan 2015 2014 2013 (In millions) Restricted Stock Units $ 46 $ 26 $ 36 Restricted Stock 2 5 6 Performance Shares — 5 (10 ) 401(k) Savings Plan 38 25 25 EDCP & DCPD 3 8 3 Total $ 89 $ 69 $ 60 Stock-based compensation costs capitalized $ 32 $ 23 $ 20 FES Years ended December 31, Stock-based Compensation Plan 2015 2014 2013 (In millions) Restricted Stock Units $ 6 $ 4 $ 6 Performance Shares — 1 (1 ) 401(k) Savings Plan 5 4 4 Total $ 11 $ 9 $ 9 Stock-based compensation costs capitalized $ 1 $ 1 $ 1 Stock option expense was not material for FirstEnergy or FES for the years December 31, 2015, 2014 or 2013. Income tax benefits associated with stock based compensation plan expense were $12 million , $14 million and $23 million (FES - $2 million , $2 million and $1 million ) for the years ended 2015 , 2014 and 2013 , respectively. Restricted Stock Units Beginning with the performance-based restricted stock units granted in 2015, two-thirds will be paid in stock and one-third will be paid in cash. Prior to 2015, all performance-based restricted stock units were paid in stock. Restricted stock units paid in stock provide the participant the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of stock units set forth in the agreement subject to adjustment based on FirstEnergy's performance relative to financial and operational performance targets. The grant date fair value of the stock portion of the restricted stock unit award is measured based on the average of the high and low prices of FE common stock on the date of grant. Compensation expense is recognized for the grant date fair value of awards that are expected to vest. Restricted stock units paid in cash provide the participant the right to receive cash based on the numbers of stock units set forth in the agreement and value of the equivalent number of shares of FE common stock as of the vesting date. The cash portion of the restricted stock unit award is considered a liability award, which is remeasured each period based on FE's stock price and projected performance adjustments. The liability recorded for cash performance based restricted stock units as of December 31, 2015 was $3 million . No cash was paid to settle the restricted stock unit obligations in 2015. The vesting period for each of the awards was three years. Dividend equivalents are received on the restricted stock units and are reinvested in additional restricted stock units and subject to the same performance conditions. Restricted stock unit activity for the year ended December 31, 2015, was as follows: Restricted Stock Unit Activity Shares Weighted-Average Grant Date Fair Value Nonvested as of January 1, 2015 2,069,518 $ 37.65 Granted in 2015 1,157,755 35.27 Forfeited in 2015 (231,271 ) 34.19 Vested in 2015 (1) (559,114 ) 44.58 Nonvested as of December 31, 2015 2,436,888 $ 35.26 (1 ) Excludes dividend equivalents of 89,681 earned during vesting period The weighted average fair value of awards granted in 2015, 2014 and 2013 were $35.27 , $32.17 and $39.90 respectively. For the years ended December 31, 2015, 2014, and 2013, the fair value of restricted stock units vested was $22 million , $28 million , and $37 million , respectively. As of December 31, 2015 , there was $32 million of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted for restricted stock units; that cost is expected to be recognized over a period of approximately two years. Restricted Stock Certain employees receive awards of FE restricted stock (as opposed to "units" with the right to receive shares at the end of the restriction period) subject to restrictions that lapse over a defined period of time or upon achieving performance results. The fair value of restricted stock is measured based on the average of the high and low prices of FirstEnergy common stock on the date of grant. Dividends are received on the restricted stock and are reinvested in additional shares of restricted stock. Restricted common stock (restricted stock) activity for the year ended December 31, 2015, was as follows: Restricted Stock Number of Shares Weighted Average Grant-Date Fair Value Nonvested as of January 1, 2015 342,286 $ 45.29 Granted in 2015 65,434 32.98 Forfeited in 2015 (26,079 ) 57.58 Vested in 2015 (1) (190,985 ) 43.17 Nonvested as of December 31, 2015 190,656 $ 40.65 (1 ) Excludes 52,872 shares for dividends earned during vesting period The weighted average vesting period for restricted stock granted in 2015 was 5.59 years. The weighted average fair value of awards granted in 2015, 2014, and 2013 were $32.98 , $32.71 and $42.53 respectively. For the years ended December 31, 2015, 2014, and 2013, the fair value of restricted stock vested was $8 million , $4 million , and $ 7 million , respectively. As of December 31, 2015 , there was $ 3 million of total unrecognized compensation cost related to non-vested restricted stock, which is expected to be recognized over a period of approximately three years. Stock Options Stock options have been granted to certain employees allowing them to purchase a specified number of common shares at a fixed exercise price over a defined period of time. Stock options generally expire ten years from the date of grant. There were no stock options granted in 2015. Stock option activity during 2015 was as follows: Stock Option Activity Number of Shares Weighted Average Exercise Price Balance, January 1, 2015 (1,077,988 options exercisable) 1,439,145 $ 44.83 Options exercised (18,551 ) 29.53 Options forfeited (8,623 ) 68.02 Balance, December 31, 2015 (1,211,358 options exercisable) 1,411,971 $ 44.89 Cash received from the exercise of stock options in 2015 , 2014 and 2013 was $1 million , $1 million and $19 million , respectively. The total intrinsic value of options exercised during 2015 was not material. The weighted-average remaining contractual term of options outstanding as of December 31, 2015 was 3.58 years. Performance Shares Prior to the 2015 grant of performance-based restricted stock units discussed above, the Company granted performance shares. Performance shares are share equivalents and do not have voting rights. The performance shares outstanding track the performance of FE's common stock over a three -year vesting period. Dividend equivalents accrue on performance shares and are reinvested into additional performance shares with the same performance conditions. The final account value may be adjusted based on the ranking of FE stock performance to a composite of peer companies. No performance shares were granted in 2015. In 2014, $3 million cash was paid to settle performance share obligations. During 2015 and 2013 , no cash was paid to settle performance shares due to the performance criteria not being met for the previous three -year vesting period. 401(k) Savings Plan In 2015 and 2014, 1,072,494 and 756,412 shares of FE common stock, respectively, were issued and contributed to participants' accounts. In 2013 , approximately 708,000 shares of FE common stock were purchased on the market and contributed to participants’ accounts. EDCP Under the EDCP, covered employees can defer a portion of their compensation, including base salary, annual incentive awards and/or long-term incentive awards, into unfunded accounts. Annual incentive and long-term incentive awards may be deferred in FE stock accounts. Base salary and annual incentive awards may be deferred into a retirement cash account which earns interest. Dividends are calculated quarterly on stock units outstanding and are credited in the form of additional stock units. The form of payout as stock or cash can vary depending upon the form of the award, the duration of the deferral and other factors. Certain types of deferrals such as dividend equivalent units, Short-Term Incentive Awards, and performance share awards are required to be paid in cash. Until 2015, payouts of the stock accounts typically occurred three years from the date of deferral, although participants could have elected to defer their shares into a retirement stock account that would pay out in cash upon retirement. In 2015, FirstEnergy amended the EDCP to eliminate the right to receive deferred shares after three years, effective for deferrals made on or after November 1, 2015. Awards deferred into a retirement stock account will pay out in cash upon separation from service, death or disability. Interest accrues on the cash allocated to the retirement cash account and the balance will pay out in cash over a time period as elected by the participant. DCPD Under the DCPD, members of the Board of Directors can elect to allocate all or a portion of their equity retainers to deferred stock and their cash retainers, meeting fees and chair fees to deferred stock or deferred cash accounts. The net liability recognized for DCPD of approximately $ 9 million and $8 million as of December 31, 2015 and December 31, 2014 , respectively, is included in the caption “Retirement benefits” on the Consolidated Balance Sheets.

Taxes

Taxes	12 Months Ended
	Dec. 31, 2015
Taxes [Abstract]
Taxes	TAXES FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. FES and the Utilities are party to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, are reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit. On December 18, 2015, the President signed into law the Protecting Americans from Tax Hikes Act of 2015 (the Act). The Act, among other things, made permanent the R&D tax credit, and also extended accelerated depreciation of qualified capital investments placed into service. This bonus depreciation provision is 50% for qualifying assets placed into service from 2015 through 2017, 40% for qualifying assets placed into service in 2018 and 30% for qualifying assets placed into service in 2019. FirstEnergy and FES recorded the effects of the Act that apply to 2015 in the fourth quarter of 2015. The extension of the tax benefits did not have a significant impact to the effective tax rate. INCOME TAXES (BENEFITS) (1) 2015 2014 2013 (In millions) FirstEnergy Currently payable (receivable)- Federal $ 1 $ (132 ) $ (118 ) State 30 (72 ) 70 31 (204 ) (48 ) Deferred, net- Federal 277 214 305 State 15 (42 ) (54 ) 292 172 251 Investment tax credit amortization (8 ) (10 ) (8 ) Total provision for income taxes (benefits) $ 315 $ (42 ) $ 195 FES Currently payable (receivable)- Federal $ (56 ) $ (222 ) $ (300 ) State 2 (13 ) (3 ) (54 ) (235 ) (303 ) Deferred, net- Federal 103 25 317 State 18 (14 ) (4 ) 121 11 313 Investment tax credit amortization (2 ) (4 ) (4 ) Total provision for income taxes (benefits) $ 65 $ (228 ) $ 6 (1) Provision for Income Taxes (Benefits) on Income from Continuing Operations. Currently payable (receivable) in 2014 excludes $106 million and $12 million of federal and state taxes, respectively, associated with discontinued operations. Deferred, net in 2014 excludes $44 million and $5 million of federal and state tax benefits, respectively, associated with discontinued operations. FirstEnergy and FES tax rates are affected by permanent items, such as AFUDC equity and other flow-through items as well as discrete items that may occur in any given period, but are not consistent from period to period. The following tables provide a reconciliation of federal income tax expense at the federal statutory rate to the total income taxes on continuing operations for the three years ended December 31: 2015 2014 2013 (In millions) FirstEnergy Income from Continuing Operations before income taxes $ 893 $ 171 $ 570 Federal income tax expense at statutory rate (35%) $ 313 $ 60 $ 199 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit 34 12 10 AFUDC equity and other flow-through (16 ) (13 ) (7 ) Amortization of investment tax credits (8 ) (10 ) (8 ) Change in accounting method (8 ) (27 ) — ESOP dividend (6 ) (6 ) (9 ) Tax basis balance sheet adjustments — (25 ) — Uncertain tax positions 1 (35 ) (2 ) Other, net 5 2 12 Total income taxes (benefits) $ 315 $ (42 ) $ 195 Effective income tax rate 35.3 % (24.6 )% 34.2 % FES Income (loss) from Continuing Operations before income taxes (benefits) $ 147 $ (588 ) $ 52 Federal income tax expense (benefit) at statutory rate (35%) $ 51 $ (206 ) $ 18 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit 16 (14 ) (5 ) Amortization of investment tax credits (2 ) (4 ) (4 ) ESOP dividend (1 ) (1 ) (2 ) Uncertain tax positions 5 — — Other, net (4 ) (3 ) (1 ) Total income taxes (benefits) $ 65 $ (228 ) $ 6 Effective income tax rate 44.2 % 38.8 % 11.5 % In 2015, FirstEnergy’s effective tax rate was 35.3% compared to (24.6)% in 2014. The increase in the effective tax rate year-over-year resulted from lower tax benefits in 2015 as compared to 2014, primarily related to IRS approved changes in accounting methods, reduced tax benefits on uncertain tax positions, partially offset by lower valuation allowances required on state and municipal net operating loss carryforwards that FirstEnergy believes are no longer realizable. Additionally, during 2014, income tax benefits of $25 million were recorded that related to prior periods. The out-of-period adjustment primarily related to the correction of amounts included in the FirstEnergy’s tax basis balance sheet. Management determined that this adjustment was not material to 2014 or any prior period. The increase in the effective rate was also impacted by higher income from continuing operations. In 2015, FES’ effective tax rate on income from continuing operations was 44.2% compared to 38.8% on a loss from continuing operations in 2014. The increase in the effective tax rate is primarily due to an increase in reserves associated with uncertain tax positions in 2015 and the absence of tax benefits recognized in 2014 associated with changes in state apportionment factors, partially offset by lower valuation allowances recorded on state and municipal NOL carryforwards that FirstEnergy believes are no longer realizable. Accumulated deferred income taxes as of December 31, 2015 and 2014 are as follows: 2015 2014 (In millions) FirstEnergy Property basis differences $ 9,920 $ 9,354 Deferred sale and leaseback gain (360 ) (381 ) Pension and OPEB (1,541 ) (1,433 ) Nuclear decommissioning activities 480 458 Asset retirement obligations (731 ) (641 ) Regulatory asset/liability 763 768 Loss carryforwards and AMT credits (1,965 ) (1,932 ) Loss carryforward valuation reserve 192 174 All other 15 172 Net deferred income tax liability $ 6,773 $ 6,539 FES Property basis differences $ 1,901 $ 1,749 Deferred sale and leaseback gain (342 ) (356 ) Pension and OPEB (393 ) (373 ) Lease market valuation liability 95 75 Nuclear decommissioning activities 483 489 Asset retirement obligations (509 ) (486 ) Loss carryforwards and AMT credits (687 ) (631 ) Loss carryforward valuation reserve 46 32 All other 6 (15 ) Net deferred income tax liability $ 600 $ 484 FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state taxing authorities. FirstEnergy's tax returns for all state jurisdictions are open from 2011-2014. In January 2015, the IRS completed its examination of the 2013 federal income tax return and issued a Revenue Agent Report and there were no material impacts to FirstEnergy's effective tax rate associated with this examination. Tax year 2014 is currently under review by the IRS. FirstEnergy has recorded as deferred income tax assets the effect of NOLs and tax credits that will more likely than not be realized through future operations and through the reversal of existing temporary differences. As of December 31, 2015 , the deferred income tax assets, before any valuation allowances, for loss carryforwards and AMT credits consisted of $1.5 billion of Federal NOL carryforwards, net of tax, that will begin to expire in 2030, Federal AMT credits of $26 million , net of tax, that have an indefinite carryforward period, and $398 million , net of tax, of state and local NOL carryforwards that will begin to expire in 2016 . The table below summarizes pre-tax NOL carryforwards for state and local income tax purposes of approximately $10 billion for FirstEnergy, of which approximately $6 billion is expected to be utilized based on current estimates and assumptions. The ultimate utilization of these NOLs may be impacted by statutory limitations on the use of NOLs imposed by state and local tax jurisdictions, changes in statutory tax rates, and changes in business which, among other things, impact both future profitability and the manner in which future taxable income is apportioned to various state and local tax jurisdictions. Expiration Period FirstEnergy FES (In millions) State Local State Local 2016-2020 $ 403 $ 2,983 $ 95 $ 1,820 2021-2025 1,323 — 68 — 2026-2030 2,205 — 259 — 2031-2035 3,245 — 1,128 — $ 7,176 $ 2,983 $ 1,550 $ 1,820 FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. A recognition threshold and measurement attribute is utilized for financial statement recognition and measurement of tax positions taken or expected to be taken on a company's tax return. As of December 31, 2015 and 2014 , FirstEnergy's total unrecognized income tax benefits were approximately $34 million . If ultimately recognized in future years, approximately $29 million of unrecognized income tax benefits as of December 31, 2015 , would impact the effective tax rate. As of December 31, 2015 , it is reasonably possible that approximately $9 million of unrecognized tax benefits may be resolved during 2016 as a result of the statute of limitations expiring, of which approximately $7 million would affect FirstEnergy's effective tax rate. The following table summarizes the changes in unrecognized tax positions for the years ended 2015 , 2014 and 2013 : FirstEnergy FES (In millions) Balance, January 1, 2013 $ 43 $ 3 Prior years increases 10 — Prior years decreases (5 ) — Balance, December 31, 2013 $ 48 $ 3 Current year increases 4 — Prior years increases 5 — Prior years decreases (23 ) — Balance, December 31, 2014 $ 34 $ 3 Current year increases 3 — Prior years increases 7 5 Prior years decreases (10 ) — Balance, December 31, 2015 $ 34 $ 8 FirstEnergy recognizes interest expense or income and penalties related to uncertain tax positions in income taxes. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the federal income tax return. FirstEnergy's reversal of accrued interest associated with unrecognized tax benefits reduced FirstEnergy's effective tax rate in 2015 and 2014 by approximately $1 million and $6 million , respectively. There was an increase of $1 million of accrued interest for the year ended December 31, 2013. The following table summarizes the net interest expense (income) for the three years ended December 31, 2015 and the cumulative net interest payable as of December 31, 2015 and 2014 (FES did not have net interest expense (income) or a net interest payable for the periods presented): Net Interest Expense (Income) For the Years Ended December 31, Net Interest Payable As of December 31, 2015 2014 2013 2015 2014 (In millions) (In millions) FirstEnergy $ (1 ) $ (6 ) $ 1 $ 1 $ 2 General Taxes 2015 2014 2013 (In millions) FirstEnergy KWH excise $ 193 $ 194 $ 219 State gross receipts 224 226 240 Real and personal property 410 393 368 Social security and unemployment 119 112 110 Other 32 37 41 Total general taxes $ 978 $ 962 $ 978 FES State gross receipts $ 44 $ 69 $ 77 Real and personal property 36 39 40 Social security and unemployment 16 17 19 Other 2 3 2 Total general taxes $ 98 $ 128 $ 138

Leases

Leases	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Leases	LEASES FirstEnergy leases certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases. In 1987, OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years, expiring in 2016. In that same year, CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years expiring in 2017. OE, CEI and TE have the right, at the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes. In 2007, FG completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1 and entered into operating leases for basic lease terms of approximately 33 years, expiring in 2040. FES has unconditionally and irrevocably guaranteed all of FG’s obligations under each of the leases. In 2013, FG acquired the remaining lessor interests in Bruce Mansfield Units 1, 2 and 3, which were part of the leases entered into by CEI and TE in 1987. In February 2014, NG purchased 47.7 MW of lessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for approximately $94 million . On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors' interests in Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), which right to repurchase was assigned to NG. Additionally, on June 24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor equity interests of the remaining non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the end of the lease term. In November 2014, NG repurchased 55.3 MW of lessor equity interests in OE's existing sale and leaseback of Perry Unit 1 for approximately $87 million . OE and TE continue to lease these MW under their respective sale and leaseback arrangements and the related lease debt remains outstanding. Established by OE in 1996, PNBV purchased a portion of the lease obligation bonds issued on behalf of lessors in OE’s Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. Similarly, CEI and TE established Shippingport in 1997 to purchase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. During 2013, the investments held at Shippingport were liquidated. The PNBV arrangements effectively reduce lease costs related to those transactions (see Note 8, Variable Interest Entities). As of December 31, 2015 , FirstEnergy's leasehold interest was 3.75% of Perry Unit 1, 93.83% of Bruce Mansfield Unit 1 and 2.60% of Beaver Valley Unit 2. Operating lease expense for 2015 , 2014 and 2013 , is summarized as follows: (In millions) 2015 2014 2013 FirstEnergy $ 174 $ 199 $ 224 FES $ 94 $ 95 $ 97 The future minimum capital lease payments as of December 31, 2015 are as follows: Capital leases FirstEnergy FES (In millions) 2016 $ 36 $ 6 2017 31 6 2018 24 2 2019 18 — 2020 14 — Years thereafter 27 — Total minimum lease payments 150 14 Interest portion (18 ) (1 ) Present value of net minimum lease payments 132 13 Less current portion 32 5 Noncurrent portion $ 100 $ 8 FirstEnergy's future minimum consolidated operating lease payments as of December 31, 2015 , are as follows: FirstEnergy Operating Leases Lease Payments PNBV Net (In millions) 2016 $ 197 $ 13 $ 184 2017 122 3 119 2018 135 — 135 2019 116 — 116 2020 91 — 91 Years thereafter 1,438 — 1,438 Total minimum lease payments $ 2,099 $ 16 $ 2,083 FES' future minimum operating lease payments as of December 31, 2015 , are as follows: Operating Leases Lease Payments (In millions) 2016 $ 131 2017 82 2018 101 2019 97 2020 68 Years thereafter 1,315 Total minimum lease payments $ 1,794

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
INTANGIBLE ASSETS	INTANGIBLE ASSETS As of December 31, 2015 , intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheet, include the following: Intangible Assets Amortization Expense Actual Estimated (In millions) Gross Accumulated Amortization Net 2015 2016 2017 2018 2019 2020 Thereafter NUG contracts (1) $ 124 $ 25 $ 99 $ 5 $ 5 $ 5 $ 5 $ 5 $ 5 $ 74 OVEC 54 9 45 2 2 2 2 2 2 35 Coal contracts (2)(3)(4) 556 430 126 116 38 32 17 17 6 — FES customer contracts 148 87 61 17 17 16 14 13 1 — $ 882 $ 551 $ 331 $ 140 $ 62 $ 55 $ 38 $ 37 $ 14 $ 109 (1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings. (2) A gross amount of $40 million ($ 23 million , net) of the coal contracts is related to FES. The 2015 and estimated 2016 to 2019 amortization expense for FES is $5.7 million annually. (3) A gross amount of $102 million ( $16 million , net) of the coal contracts was recorded with a regulatory offset and the amortization does not impact earnings. Accordingly, the amortization expense for these coal contracts is excluded from table above. (4) Amortization expense in 2015, includes a $67 million impairment of a coal contract intangible asset associated with the termination of a coal supply contract, which impacted earnings. FES acquired certain customer contract rights which were capitalized as intangible assets. These rights allow FES to supply electric generation to customers, and the recorded value is being amortized ratably over the term of the related contracts.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2015
Variable Interest Entities [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. The caption "noncontrolling interest" within the consolidated financial statements is used to reflect the portion of a VIE that FirstEnergy consolidates, but does not own. In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance. Consolidated VIEs VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements): • PNBV - PNBV , a business trust established by OE in 1996, issued certain beneficial interests and notes to fund the acquisition of a portion of the bonds issued by certain owner trusts in connection with the sale and leaseback in 1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. The beneficial ownership of PNBV includes a 3% interest by unaffiliated third parties. • Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly-owned limited liability companies (SPEs) which issued phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase-in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. As of December 31, 2015 and December 31, 2014, $362 million and $386 million of the phase-in recovery bonds were outstanding, respectively. • JCP&L Securitization - In June 2002, JCP&L Transition Funding sold transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consist primarily of bondable transition property. As of December 31, 2015 and December 31, 2014, $128 million and $168 million of the transition bonds were outstanding, respectively. • MP and PE Environmental Funding Companies - The entities issued bonds of which the proceeds were used to construct environmental control facilities. The special purpose limited liability companies own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's and PE's West Virginia service territories. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the special purpose limited liability companies, have no recourse to any assets or revenues of the special purpose limited liability companies. As of December 31, 2015 and December 31, 2014, $429 million and $450 million of the environmental control bonds were outstanding, respectively. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of the following VIEs: • Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture's economic performance. FEV's ownership interest is subject to the equity method of accounting. See Note 1, Organization, Basis of Presentation and Significant Accounting Policies - Investments, for additional information regarding FEV's investment in Global Holding. As discussed in Note 15, Commitments, Guarantees and Contingencies, FE is the guarantor under Global Holding's $300 million term loan facility. Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to be obligated under the provisions of its guarantee, resulting in consolidation of Global Holding by FE. • PATH WV - PATH is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting. • Power Purchase Agreements - FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy maintains 15 long-term power purchase agreements with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that for all but one of these NUG entities, it does not have a variable interest in the entities or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities. Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contracts that may contain a variable interest were $116 million and $185 million , respectively, during the years ended December 31, 2015 and 2014 . • Sale and Leaseback Transactions - FES and certain of the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to the Perry Unit 1, Beaver Valley Unit 2, and 2007 Bruce Mansfield Unit 1 sale and leaseback arrangements, which are satisfied through operating lease payments. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the arrangements. As of December 31, 2015 , FirstEnergy's leasehold interest was 3.75% of Perry Unit 1, 93.83% of Bruce Mansfield Unit 1 and 2.60% of Beaver Valley Unit 2. On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors' interests in Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), which right to repurchase was assigned to NG. Additionally, on June 24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor equity interests of the remaining non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the end of the lease term. Upon the completion of these transactions, NG will have obtained all of the lessor equity interests at Perry Unit 1 and Beaver Valley Unit 2. FES and other FE subsidiaries are exposed to losses under their applicable sale and leaseback agreements upon the occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions as of December 31, 2015 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy $ 1,225 $ 950 $ 275 FES $ 1,155 $ 933 $ 222

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS RECURRING FAIR VALUE MEASUREMENTS Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows: Level 1 - Quoted prices for identical instruments in active market Level 2 - Quoted prices for similar instruments in active market - Quoted prices for identical or similar instruments in markets that are not active - Model-derived valuations for which all significant inputs are observable market data Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 - Valuation inputs are unobservable and significant to the fair value measurement FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast, which has been reviewed and approved by FirstEnergy's Risk Policy Committee, are used to measure fair value. A more detailed description of FirstEnergy's valuation processes for FTRs and NUGs are as follows: FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term RTO auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent RTO auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 10, Derivative Instruments, for additional information regarding FirstEnergy's FTRs. NUG contracts represent purchase power agreements with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWHs. Pricing for the NUG contracts is a combination of market prices for the current year and next three years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on ICE quotes and management assumptions. Generation MWHs reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWHs. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of December 31, 2015 , from those used as of December 31, 2014 . The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements. Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the years ended December 31, 2015 and 2014 . The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: FirstEnergy Recurring Fair Value Measurements December 31, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,245 $ — $ 1,245 $ — $ 1,221 $ — $ 1,221 Derivative assets - commodity contracts 4 224 — 228 1 171 — 172 Derivative assets - FTRs — — 8 8 — — 39 39 Derivative assets - NUG contracts (1) — — 1 1 — — 2 2 Equity securities (2) 576 — — 576 592 — — 592 Foreign government debt securities — 75 — 75 — 76 — 76 U.S. government debt securities — 180 — 180 — 182 — 182 U.S. state debt securities — 246 — 246 — 237 — 237 Other (3) 105 212 — 317 55 256 — 311 Total assets $ 685 $ 2,182 $ 9 $ 2,876 $ 648 $ 2,143 $ 41 $ 2,832 Liabilities Derivative liabilities - commodity contracts $ (9 ) $ (122 ) $ — $ (131 ) $ (26 ) $ (141 ) $ — $ (167 ) Derivative liabilities - FTRs — — (13 ) (13 ) — — (14 ) (14 ) Derivative liabilities - NUG contracts (1) — — (137 ) (137 ) — — (153 ) (153 ) Total liabilities $ (9 ) $ (122 ) $ (150 ) $ (281 ) $ (26 ) $ (141 ) $ (167 ) $ (334 ) Net assets (liabilities) (4) $ 676 $ 2,060 $ (141 ) $ 2,595 $ 622 $ 2,002 $ (126 ) $ 2,498 (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (3) Primarily consists of cash and short-term cash investments. (4) Excludes $7 million and $40 million as of December 31, 2015 and December 31, 2014 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. Rollforward of Level 3 Measurements The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2015 and December 31, 2014 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2014 Balance $ 20 $ (222 ) $ (202 ) $ 4 $ (12 ) $ (8 ) Unrealized gain (loss) 2 (2 ) — 47 (1 ) 46 Purchases — — — 26 (16 ) 10 Settlements (20 ) 71 51 (38 ) 15 (23 ) December 31, 2014 Balance $ 2 $ (153 ) $ (151 ) $ 39 $ (14 ) $ 25 Unrealized gain (loss) 2 (49 ) (47 ) (5 ) (7 ) (12 ) Purchases — — — 22 (11 ) 11 Settlements (3 ) 65 62 (48 ) 19 (29 ) December 31, 2015 Balance $ 1 $ (137 ) $ (136 ) $ 8 $ (13 ) $ (5 ) (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings. Level 3 Quantitative Information The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended December 31, 2015 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ (5 ) Model RTO auction clearing prices ($3.90) to $6.90 $1.00 Dollars/MWH NUG Contracts $ (136 ) Model Generation 400 to 3,871,000 $38.10 to $45.60 839,000 $40.20 MWH FES Recurring Fair Value Measurements December 31, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 678 $ — $ 678 $ — $ 655 $ — $ 655 Derivative assets - commodity contracts 4 224 — 228 1 171 — 172 Derivative assets - FTRs — — 5 5 — — 27 27 Equity securities (1) 378 — — 378 360 — — 360 Foreign government debt securities — 59 — 59 — 57 — 57 U.S. government debt securities — 23 — 23 — 46 — 46 U.S. state debt securities — 4 — 4 — 4 — 4 Other (2) — 184 — 184 — 199 — 199 Total assets $ 382 $ 1,172 $ 5 $ 1,559 $ 361 $ 1,132 $ 27 $ 1,520 Liabilities Derivative liabilities - commodity contracts $ (9 ) $ (122 ) $ — $ (131 ) $ (26 ) $ (141 ) $ — $ (167 ) Derivative liabilities - FTRs — — (11 ) (11 ) — — (13 ) (13 ) Total liabilities $ (9 ) $ (122 ) $ (11 ) $ (142 ) $ (26 ) $ (141 ) $ (13 ) $ (180 ) Net assets (liabilities) (3) $ 373 $ 1,050 $ (6 ) $ 1,417 $ 335 $ 991 $ 14 $ 1,340 (1) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (2) Primarily consists of short-term cash investments. (3) Excludes $1 million and $44 million as of December 31, 2015 and December 31, 2014 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. Rollforward of Level 3 Measurements The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2015 and December 31, 2014 : Derivative Asset Derivative Liability Net Asset/(Liability) (In millions) January 1, 2014 Balance $ 3 $ (11 ) $ (8 ) Unrealized gain (loss) 34 (1 ) 33 Purchases 15 (16 ) (1 ) Settlements (25 ) 15 (10 ) December 31, 2014 Balance $ 27 $ (13 ) $ 14 Unrealized gain (loss) 2 (5 ) (3 ) Purchases 9 (10 ) (1 ) Settlements (33 ) 17 (16 ) December 31, 2015 Balance $ 5 $ (11 ) $ (6 ) Level 3 Quantitative Information The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended December 31, 2015 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ (6 ) Model RTO auction clearing prices ($3.90) to $5.70 $0.70 Dollars/MWH INVESTMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and AFS securities. At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy first considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value. Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES, OE and TE are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of OTTI. The NDTs of JCP&L, ME and PN are subject to regulatory accounting with unrealized gains and losses offset in net regulatory assets. The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries. AFS Securities FirstEnergy holds debt and equity securities within its NDT, nuclear fuel disposal and NUG trusts. These trust investments are considered AFS securities, recognized at fair market value. FirstEnergy has no securities held for trading purposes. The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT, nuclear fuel disposal and NUG trusts as of December 31, 2015 and December 31, 2014 : December 31, 2015 (1) December 31, 2014 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,778 $ 16 $ 1,794 $ 1,724 $ 27 $ 1,751 FES 801 9 810 788 13 801 Equity securities FirstEnergy $ 542 $ 34 $ 576 $ 533 $ 58 $ 591 FES 354 24 378 329 31 360 (1) Excludes short-term cash investments: FE Consolidated - $157 million ; FES - $139 million . (2) Excludes short-term cash investments: FE Consolidated - $241 million ; FES - $204 million . Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three years ended December 31, 2015 , 2014 and 2013 were as follows: December 31, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 1,534 $ 209 $ (191 ) $ (102 ) $ 101 FES 733 158 (134 ) (90 ) 57 December 31, 2014 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 2,133 $ 146 $ (75 ) $ (37 ) $ 96 FES 1,163 113 (54 ) (33 ) 56 December 31, 2013 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 2,047 $ 92 $ (46 ) $ (90 ) $ 101 FES 940 70 (21 ) (79 ) 60 Held-To-Maturity Securities The following table provides the amortized cost basis, unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of December 31, 2015 and December 31, 2014 : December 31, 2015 December 31, 2014 Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt Securities FirstEnergy $ 6 $ 2 $ 8 $ 13 $ 4 $ 17 The held-to-maturity debt securities contractually mature by June 30, 2017. Investments in employee benefit trusts and equity method investments totaling $255 million as of December 31, 2015 and $626 million as of December 31, 2014 , are excluded from the amounts reported above. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations, excluding capital lease obligations and net unamortized premiums and discounts: December 31, 2015 December 31, 2014 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 20,244 $ 21,519 $ 19,828 $ 21,733 FES 3,027 3,121 3,097 3,241 The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy and its subsidiaries. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of December 31, 2015 and December 31, 2014 .

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance. FirstEnergy has contractual derivative agreements through 2020 . Cash Flow Hedges FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating commodity prices and interest rates. Total pre-tax net unamortized losses included in AOCI associated with instruments previously designated as cash flow hedges totaled $11 million and $8 million as of December 31, 2015 and December 31, 2014 , respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $1 million of net unamortized losses is expected to be amortized to income during the next twelve months. FirstEnergy has used forward starting interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were designated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $42 million and $50 million as of December 31, 2015 and December 31, 2014 , respectively. Based on current estimates, approximately $9 million of these unamortized losses is expected to be amortized to interest expense during the next twelve months. Refer to Note 2, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the years ended December 31, 2015 and 2014 . As of December 31, 2015 and December 31, 2014 , no commodity or interest rate derivatives were designated as cash flow hedges. Fair Value Hedges FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. As of December 31, 2015 and December 31, 2014 , no fixed-for-floating interest rate swap agreements were outstanding. Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $20 million and $32 million as of December 31, 2015 and December 31, 2014 , respectively. During the next twelve months, approximately $10 million of unamortized gains is expected to be amortized to interest expense. Amortization of unamortized gains included in long-term debt totaled approximately $12 million during the years ended December 31, 2015 and 2014 . As of December 31, 2015 and December 31, 2014 , no commodity or interest rate derivatives were designated as fair value hedges. Commodity Derivatives FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances where the hedging relationship does not qualify for hedge accounting. Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas primarily for use in FirstEnergy’s combustion turbine units. Derivative instruments are not used in quantities greater than forecasted needs. As of December 31, 2015 , FirstEnergy's net asset position under commodity derivative contracts was $97 million , which related to FES positions. Under these commodity derivative contracts, FES posted $26 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $3 million of additional collateral if the credit rating for its debt were to fall below investment grade. Based on derivative contracts held as of December 31, 2015 , an increase in commodity prices of 10% would decrease net income by approximately $30 million during the next twelve months. Interest Rate Swaps As of December 31, 2015 and 2014 , no interest rate swaps were outstanding. NUGs As of December 31, 2015 , FirstEnergy's net liability position under NUG contracts was $136 million representing contracts held at JCP&L, ME and PN. NUG contracts represent purchased power agreements with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. Changes in the fair value of NUG contracts are subject to regulatory accounting treatment and do not impact earnings. FTRs As of December 31, 2015 , FirstEnergy's and FES' net liability position under FTRs was $5 million and $6 million , respectively and FES posted $6 million of collateral. FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of an RTO that have load serving obligations and through the direct allocation of FTRs from PJM. PJM has a rule that allows directly allocated FTRs to be granted to LSEs in zones that have newly entered PJM. For the first two planning years, PJM permits the LSEs to request a direct allocation of FTRs in these new zones at no cost as opposed to receiving ARRs. The directly allocated FTRs differ from traditional FTRs in that the ownership of all or part of the FTRs may shift to another LSE if customers choose to shop with the other LSE. The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets and have not been designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price less the obligation due to PJM, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FES and AE Supply are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s Utilities are recorded as regulatory assets or liabilities. Directly allocated FTRs are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance. FirstEnergy records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets: Derivative Assets Derivative Liabilities Fair Value Fair Value December 31, December 31, December 31, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 150 $ 121 Commodity Contracts $ (94 ) $ (154 ) FTRs 7 38 FTRs (12 ) (13 ) 157 159 (106 ) (167 ) Noncurrent Liabilities - Adverse Power Contract Liability Deferred Charges and Other Assets - Other NUGs (1) (137 ) (153 ) Commodity Contracts 78 51 Noncurrent Liabilities - Other FTRs 1 1 Commodity Contracts (37 ) (13 ) NUGs (1) 1 2 FTRs (1 ) (1 ) 80 54 (175 ) (167 ) Derivative Assets $ 237 $ 213 Derivative Liabilities $ (281 ) $ (334 ) (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings. FirstEnergy enters into contracts with counterparties that allow for the offsetting of derivative assets and derivative liabilities under netting arrangements with the same counterparty. Certain of these contracts contain margining provisions that require the use of collateral to mitigate credit exposure between FirstEnergy and these counterparties. In situations where collateral is pledged to mitigate exposures related to derivative and non-derivative instruments with the same counterparty, FirstEnergy allocates the collateral based on the percentage of the net fair value of derivative instruments to the total fair value of the combined derivative and non-derivative instruments. The following tables summarize the fair value of derivative assets and derivative liabilities on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet December 31, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 228 $ (125 ) $ — $ 103 FTRs 8 (8 ) — — NUG contracts 1 — — 1 $ 237 $ (133 ) $ — $ 104 Derivative Liabilities Commodity contracts $ (131 ) $ 125 $ 3 $ (3 ) FTRs (13 ) 8 5 — NUG contracts (137 ) — — (137 ) $ (281 ) $ 133 $ 8 $ (140 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2014 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 172 $ (126 ) $ — $ 46 FTRs 39 (14 ) — 25 NUG contracts 2 — — 2 $ 213 $ (140 ) $ — $ 73 Derivative Liabilities Commodity contracts $ (167 ) $ 126 $ 35 $ (6 ) FTRs (14 ) 14 — — NUG contracts (153 ) — — (153 ) $ (334 ) $ 140 $ 35 $ (159 ) The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of December 31, 2015 : Purchases Sales Net Units (In millions) Power Contracts 16 49 (33 ) MWH FTRs 29 — 29 MWH NUGs 4 — 4 MWH Natural Gas 83 — 83 mmBTU The effect of active derivative instruments not in a hedging relationship on the Consolidated Statements of Income during 2015 and 2014 are summarized in the following tables: Year Ended December 31, Commodity Contracts FTRs Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense (1) $ 93 $ (20 ) $ 73 Realized Gain (Loss) Reclassified to: Revenues (2) $ 111 $ 50 $ 161 Purchased Power Expense (3) (130 ) — (130 ) Other Operating Expense (4) — (49 ) (49 ) Fuel Expense (34 ) — (34 ) (1) Includes $93 million for commodity contracts and ($19) million for FTRs associated with FES. (2) Includes $111 million for commodity contracts and $49 million for FTRs associated with FES. (3) Includes ($130) million for commodity contracts associated with FES. (4) Includes ($49) million for FTRs associated with FES. Year Ended December 31, Commodity FTRs Interest Rate Swaps Total (In millions) 2014 Unrealized Gain (Loss) Recognized in: Other Operating Expense (5) $ (86 ) $ 22 $ — $ (64 ) Realized Gain (Loss) Reclassified to: Revenues (6) $ (6 ) $ 68 $ — $ 62 Purchased Power Expense (7) 365 — — 365 Other Operating Expense (8) — (44 ) — (44 ) Fuel Expense (6 ) — — (6 ) Interest Expense — — 14 14 (5) Includes ($86) million for commodity contracts and $21 million for FTRs associated with FES. (6) Includes ($6) million for commodity contracts and $67 million for FTRs associated with FES. (7) Realized losses on financially settled wholesale sales contracts of $252 million resulting from higher market prices were netted in purchased power. Includes $365 million for commodity contracts associated with FES. (8) Includes ($43) million for FTRs associated with FES. The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during 2015 and 2014 . Changes in the value of these contracts are deferred for future recovery from (or credit to) customers: Year Ended December 31, Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of January 1, 2015 $ (151 ) $ 11 $ (140 ) Unrealized loss (47 ) (9 ) (56 ) Purchases — 12 12 Settlements 62 (13 ) 49 Outstanding net asset (liability) as of December 31, 2015 $ (136 ) $ 1 $ (135 ) Outstanding net liability as of January 1, 2014 $ (202 ) $ — $ (202 ) Unrealized gain (loss) (1 ) 13 12 Purchases — 11 11 Settlements 52 (13 ) 39 Outstanding net asset (liability) as of December 31, 2014 $ (151 ) $ 11 $ (140 )

Capitalization

Capitalization	12 Months Ended
	Dec. 31, 2015
Capitalization, Long-term Debt and Equity [Abstract]
Capitalization	CAPITALIZATION COMMON STOCK Retained Earnings and Dividends As of December 31, 2015 , FirstEnergy’s unrestricted retained earnings were $2.3 billion . Dividends declared in 2015 and 2014 were $1.44 per share, which included dividends of $0.36 per share paid in the first, second, third and fourth quarters. The amount and timing of all dividend declarations are subject to the discretion of the Board of Directors and its consideration of business conditions, results of operations, financial condition and other factors. On January 19, 2016 the Board of Directors declared a quarterly dividend of $0.36 per share to be paid in the first quarter of 2016 . In addition to paying dividends from retained earnings, OE, CEI, TE, Penn, JCP&L, ME and PN have authorization from the FERC to pay cash dividends to FirstEnergy from paid-in capital accounts, as long as their FERC-defined equity to total capitalization ratio remains above 35% . In addition, TrAIL and AGC have authorization from the FERC to pay cash dividends to their respective parents from paid-in capital accounts, as long as their FERC-defined equity to total capitalization ratio remains above 45% . The articles of incorporation, indentures, regulatory limitations and various other agreements relating to the long-term debt of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock. None of these provisions materially restricted FirstEnergy’s subsidiaries’ abilities to pay cash dividends to FirstEnergy as of December 31, 2015 . Stock Issuance In each of 2015 and 2014, FE issued approximately 2.5 million shares of common stock to registered shareholders and its employees and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans. PREFERRED AND PREFERENCE STOCK FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2015 , as follows: Preferred Stock Preference Stock Shares Authorized Par Value Shares Authorized Par Value FirstEnergy 5,000,000 $ 100 OE 6,000,000 $ 100 8,000,000 no par OE 8,000,000 $ 25 Penn 1,200,000 $ 100 CEI 4,000,000 no par 3,000,000 no par TE 3,000,000 $ 100 5,000,000 $ 25 TE 12,000,000 $ 25 JCP&L 15,600,000 no par ME 10,000,000 no par PN 11,435,000 no par MP 940,000 $ 100 PE 10,000,000 $ 0.01 WP 32,000,000 no par As of December 31, 2015 , and 2014 , there were no preferred or preference shares outstanding. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS The following tables present outstanding long-term debt and capital lease obligations for FirstEnergy and FES as of December 31, 2015 and 2014 : As of December 31, 2015 As of December 31 (Dollar amounts in millions) Maturity Date Interest Rate 2015 2014 FirstEnergy: FMBs 2016 - 2045 3.340% - 9.740% $ 3,269 $ 3,190 Secured notes - fixed rate 2016 - 2037 0.679% - 12.000% 2,096 2,247 Secured notes - variable rate 2017 - 2017 3.500% - 3.500% 2 — Total secured notes 2,098 2,247 Unsecured notes - fixed rate 2016 - 2045 2.150% - 7.700% 13,580 13,078 Unsecured notes - variable rate 2017 - 2020 0.010% - 2.180% 1,292 1,292 Total unsecured notes 14,872 14,370 Capital lease obligations 132 160 Unamortized debt discounts (18 ) (8 ) Unamortized fair value adjustments 5 21 Currently payable long-term debt (1,166 ) (804 ) Total long-term debt and other long-term obligations $ 19,192 $ 19,176 FES: Secured notes - fixed rate 2016 - 2018 5.625% - 12.000% $ 340 $ 437 Secured notes - variable rate 2017 - 2017 3.500% - 3.500% 2 — Total secured notes 342 437 Unsecured notes - fixed rate 2016 - 2039 2.150% - 6.800% 2,593 2,568 Unsecured notes - variable rate 2017 - 2017 0.010% - 0.010% 92 92 Total unsecured notes 2,685 2,660 Capital lease obligations 13 18 Unamortized debt discounts (1 ) (1 ) Currently payable long-term debt (512 ) (506 ) Total long-term debt and other long-term obligations $ 2,527 $ 2,608 During the second quarter of 2015, FE refinanced a $200 million variable interest term loan, maturing on December 31, 2016 with a new $200 million variable interest term loan maturing on May 29, 2020 . On July 1, 2015, FG and NG remarketed approximately $43 million and $296 million, respectively, of PCRBs. The PCRBs were remarketed with fixed interest rates ranging from 3.125% to 4.00% and mandatory put dates ranging from July 2, 2018 to July 1, 2021. In August 2015, JCP&L issued $250 million of 4.30% senior notes due January 2026. The proceeds received from the issuance of the senior notes were used to repay a portion of JCP&L’s short-term borrowings under the FirstEnergy regulated companies' money pool and an external revolving credit facility. Also, in the second quarter of 2015, WP agreed to sell $150 million of new 4.45% FMBs due September 2045 and PE agreed to sell $145 million of new 4.47% FMBs due August 2045. The transactions closed on September 17, 2015 and August 17, 2015, respectively. The proceeds resulting from the issuance of the WP FMBs were used to repay WP’s borrowings under the FirstEnergy regulated companies' money pool and for other general corporate purposes. The proceeds resulting from the issuance of the PE FMBs were used to repay PE’s $145 million 5.125% FMBs that matured on August 15, 2015. In October 2015, TrAIL issued $75 million of 3.76% senior notes due May 2025. The proceeds resulting from the issuance of the senior notes were used: (i) to fund capital expenditures, including with respect to TrAIL's transmission expansion plans; and (ii) for working capital needs and other general business purposes. Additionally, in October 2015, ATSI issued in total $150 million of senior notes: $75 million of 4.00% senior notes due April 2026 and $75 million of 5.23% senior notes due October 2045. The proceeds resulting from the issuance of the senior notes were used: (i) to fund capital expenditures, including with respect to ATSI's transmission expansion plans; (ii) for working capital needs and other general business purposes; and (iii) to repay borrowings under the FirstEnergy regulated companies' money pool. See Note 6, Leases for additional information related to capital leases. Securitized Bonds Environmental Control Bonds The consolidated financial statements of FirstEnergy include environmental control bonds issued by two bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE. Proceeds from the bonds were used to construct environmental control facilities. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. As of December 31, 2015 and 2014 , $429 million and $450 million of environmental control bonds were outstanding, respectively. Transition Bonds The consolidated financial statements of FirstEnergy and JCP&L include transition bonds issued by JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. The proceeds were used to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station and to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. As of December 31, 2015 and 2014 , $128 million and $168 million of the transition bonds were outstanding, respectively. Phase-In Recovery Bonds In June 2013, the SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. As of December 31, 2015 and 2014 , $362 million and $386 million of the phase-in recovery bonds were outstanding, respectively. See Note 8, Variable Interest Entities for additional information on securitized bonds. Other Long-term Debt The Ohio Companies, Penn, FG and NG each have a first mortgage indenture under which they can issue FMBs secured by a direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property. Based on the amount of FMBs authenticated by the respective mortgage bond trustees as of December 31, 2015 , the sinking fund requirement for all FMBs issued under the various mortgage indentures amounted to payments of $3 million in 2015 , all of which relate to Penn. Penn expects to meet its 2016 annual sinking fund requirement with a replacement credit under its mortgage indenture. As of December 31, 2015 , FirstEnergy’s currently payable long-term debt included approximately $92 million of FES variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price. The following table presents scheduled debt repayments for outstanding long-term debt, excluding capital leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2015 . PCRBs that are scheduled to be tendered for mandatory purchase prior to maturity are reflected in the applicable year in which such PCRBs are scheduled to be tendered. Year FirstEnergy FES (In millions) 2016 $ 1,039 $ 414 2017 1,733 257 2018 1,702 516 2019 2,268 322 2020 1,231 667 The following table classifies the outstanding fixed rate PCRBs and variable rate PCRBs by year, excluding unamortized debt discounts and premiums, for the next five years based on the next date on which the debt holders may exercise their right to tender their PCRBs. Year FirstEnergy FES (In millions) 2016 $ 391 $ 391 2017 222 222 2018 375 375 2019 232 232 2020 490 490 Obligations to repay certain PCRBs are secured by several series of FMBs. Certain PCRBs are entitled to the benefit of irrevocable bank LOCs, to pay principal of, or interest on, the applicable PCRBs. To the extent that drawings are made under the LOCs, FG is entitled to a credit against its obligation to repay those bonds. FG pays annual fees based on the amounts of the LOCs to the issuing bank and is obligated to reimburse the bank for any drawings thereunder. The amounts and annual fees for PCRB-related LOCs for FirstEnergy and FES as of December 31, 2015 , are as follows: Aggregate LOC Amount (1) Annual Fees (In millions) FirstEnergy $ 93 1.25% FES 93 1.25% (1) Includes approximately $1 million of applicable interest coverage. Debt Covenant Default Provisions FirstEnergy has various debt covenants under certain financing arrangements, including its revolving credit facilities. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on such debt and the maintenance of certain financial ratios. The failure by FirstEnergy to comply with the covenants contained in its financing arrangements could result in an event of default, which may have an adverse effect on its financial condition. As of December 31, 2015 , FirstEnergy and FES remain in compliance with all debt covenant provisions. Additionally, there are cross-default provisions in a number of the financing arrangements. These provisions generally trigger a default in the applicable financing arrangement of an entity if it or any of its significant subsidiaries default under another financing arrangement in excess of a certain principal amount, typically $100 million . Although such defaults by any of the Utilities, ATSI or TrAIL would generally cross-default FE financing arrangements containing these provisions, defaults by any of AE Supply, FES, FG or NG would generally not cross-default to applicable financing arrangements of FE. Also, defaults by FE would generally not cross-default applicable financing arrangements of any of FE’s subsidiaries. Cross-default provisions are not typically found in any of the senior notes or FMBs of FE, FG, NG or the Utilities.

Short-Term Borrowings and Bank

Short-Term Borrowings and Bank Lines of Credit	12 Months Ended
	Dec. 31, 2015
Short-term Borrowings and Bank Lines of Credit [Abstract]
SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT	SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT FE and certain of its subsidiaries participate in three five-year syndicated revolving credit facilities with aggregate commitments of $6.0 billion (Facilities), which are available until March 31, 2019. FirstEnergy had $1,708 million and $1,799 million of short-term borrowings as of December 31, 2015 and 2014 , respectively. FirstEnergy’s available liquidity under the Facilities as of January 31, 2016 was as follows: Borrower(s) Type Maturity Commitment Available Liquidity (In millions) FirstEnergy (1) Revolving March 2019 $ 3,500 $ 1,595 FES / AE Supply Revolving March 2019 1,500 1,442 FET (2) Revolving March 2019 1,000 1,000 Subtotal $ 6,000 $ 4,037 Cash — 63 Total $ 6,000 $ 4,100 (1) FE and the Utilities (2) Includes FET, ATSI and TrAIL as subsidiary borrowers Generally, borrowings under each of the Facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the Facilities contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio (as defined under each of the Facilities) of no more than 65% , and 75% for FET, measured at the end of each fiscal quarter. The following table summarizes the borrowing sub-limits for each borrower under the Facilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations , as of December 31, 2015 : Borrower Revolving Credit Facility Sub-Limits Regulatory and Other Short-Term Debt Limitations (In millions) FE $ 3,500 $ — (1) FES 1,500 — (2) AE Supply 1,000 — (2) FET 1,000 — (1) OE 500 500 (3) CEI 500 500 (3) TE 500 500 (3) JCP&L 600 500 (3) ME 300 500 (3) PN 300 300 (3) WP 200 200 (3) MP 500 500 (3) PE 150 150 (3) ATSI 500 500 (3) Penn 50 100 (3) TrAIL 400 400 (3) (1) No limitations. (2) No limitation based upon blanket financing authorization from the FERC under existing market-based rate tariffs. (3) Excluding amounts which may be borrowed under the regulated companies' money pool. The entire amount of the FES/AE Supply Facility , $600 million of the FE Facility and $225 million of the FET Facility, subject to each borrower’s sub-limit, is available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the Facilities and against the applicable borrower’s borrowing sub-limit. The Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the Facilities is related to the credit ratings of the company borrowing the funds, other than the FET Facility, which is based on its subsidiaries' credit ratings. Additionally, borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million . As of December 31, 2015 , the borrowers were in compliance with the applicable debt to total capitalization ratio covenants under the respective Facilities. Term Loans FE has a $1 billion variable rate term loan credit agreement with a maturity date of March 31, 2019. The initial borrowing under the term loan, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. The proceeds from this term loan reduced borrowings under the FE Facility. Additionally, FE has a $200 million variable rate term loan with a maturity date of May 29, 2020. Each of the term loans contains covenants and other terms and conditions substantially similar to those of the FE Facility described above, including the same consolidated debt to total capitalization ratio requirement. As of December 31, 2015 , FE was in compliance with the applicable consolidated debt to total capitalization ratio covenants under each of these term loans. FirstEnergy Money Pools FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2015 was 0.84% per annum for the regulated companies’ money pool and 1.64% per annum for the unregulated companies’ money pool. Weighted Average Interest Rates The weighted average interest rates on short-term borrowings outstanding, including borrowings under the FirstEnergy Money Pools, as of December 31, 2015 and 2014 , were as follows: 2015 2014 FirstEnergy 2.16 % 1.96 % FES — % 3.34 %

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS FirstEnergy has recognized applicable legal obligations for AROs and their associated cost primarily for nuclear power plant decommissioning, reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks, wastewater treatment lagoons and transformers containing PCBs. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation. The ARO liabilities for FES primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities. FES uses an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs. FirstEnergy and FES maintain NDTs that are legally restricted for purposes of settling the nuclear decommissioning ARO. The fair values of the decommissioning trust assets as of December 31, 2015 and 2014 were as follows: 2015 2014 (In millions) FirstEnergy $ 2,282 $ 2,341 FES $ 1,327 $ 1,365 The following table summarizes the changes to the ARO balances during 2015 and 2014 : ARO Reconciliation FirstEnergy FES (In millions) Balance, January 1, 2014 $ 1,678 $ 1,015 Liabilities settled (9 ) (7 ) Accretion 113 66 Revisions in estimated cash flows (395 ) (233 ) Balance, December 31, 2014 $ 1,387 $ 841 Liabilities settled (13 ) (8 ) Accretion 92 55 Revisions in estimated cash flows (56 ) (57 ) Balance, December 31, 2015 $ 1,410 $ 831 During 2015, FE and FES reduced its ARO by $57 million based on the results of decommissioning cost studies for the Davis-Besse and Perry nuclear generating stations. During 2014, based on studies by a third-party to reassess the estimated costs of decommissioning certain nuclear generating facilities, FE decreased its ARO by $395 million ( $233 million at FES) of which $133 million was credited against a regulatory asset associated with nuclear decommissioning and spent fuel disposal costs for TMI-2. The decrease in the ARO primarily resulted from an extension in the number of years in which decommissioning activities are estimated to occur at Davis-Besse, Perry, TMI-2 and Beaver Valley Units 1 and 2.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2015
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. As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates. In addition, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility. 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 by 10% and reduce electricity demand by 15% , in each case by 2015, and requiring each electric utility to file a plan every three years. PE's current plan, covering the three-year period 2015-2017, was approved by the MDPSC on December 23, 2014. The costs of the 2015-2017 plan are expected to be approximately $66 million for that three-year period, of which $19 million was incurred through December 2015. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the level of savings achieved under PE's current plan for 2016, and ramping up 0.2% per year thereafter to reach 2%. PE continues to recover program costs subject to a five -year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE. On January 28, 2016, PE filed a request to increase plan spending by $2 million in order to reach the new goals for 2017 set in the July 16, 2015 order. On February 27, 2013, the MDPSC issued an order (the February 27 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. The order further required the Staff of the MDPSC to report on possible performance-based rate structures and to propose additional rules relating to feeder performance standards, outage communication and reporting, and sharing of special needs customer information. 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 27 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 27 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. The Staff of the MDPSC also recommended 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. I n addition, the Staff of the MDPSC proposed that the 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 March 3, 2014, pursuant to the MDPSC's regulations, PE filed its recommendations for SAIDI and SAIFI standards to apply during the period 2016-2019. The MDPSC directed the Staff of the MDPSC to file an analysis and recommendations with respect to the proposed 2016-2019 SAIDI and SAIFI standards and any related rule changes which the Staff of the MDPSC recommended. The Staff of the MDPSC made its filing on July 10, 2015, and recommended that PE be required to improve its SAIDI results by approximately 20% by 2019. The MDPSC held a hearing on the Staff's analysis and recommendations on September 1-2, 2015, and approved PE's revised proposal for an improvement of 8.6% in its SAIDI standard by 2019 and maintained its SAIFI standard at 2015 levels. The proposed regulations incorporating the new SAIDI and SAIFI standards were approved as final in December 2015. On April 1, 2015, PE filed its annual report on its performance relative to various service reliability standards set forth in the MDPSC’s regulations. The MDPSC conducted hearings on the reports filed by PE and the other electric utilities in Maryland on August 24, 2015 and subsequently closed its 2014 service reliability review. 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. On March 26, 2015, the NJBPU entered final orders which together provided an overall reduction in JCP&L's annual revenues of approximately $34 million , effective April 1, 2015. The final order in JCP&L's base rate case proceeding directed an annual base rate revenue reduction of approximately $115 million , including recovery of 2011 storm costs and the application of the NJBPU's modified CTA policy approved in the generic CTA proceeding referred to below. Additionally, the final order in the generic proceeding established to review JCP&L's major storm events of 2011 and 2012 approved the recovery of 2012 storm costs of $580 million resulting in an increase in annual revenues of approximately $81 million . JCP&L is required to file another base rate case no later than April 1, 2017. The NJBPU also directed that certain studies be completed. On July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which will include operational and financial components and is expected to take approximately one year to complete. 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 (Generic CTA proceeding), 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 New Jersey Superior Court and JCP&L has filed to participate as a respondent in that proceeding. Briefing has been completed, and oral argument has not yet been scheduled. On June 19, 2015, JCP&L, along with PN, ME, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. On January 8, 2016, the NJBPU President issued an Order granting Rate Counsel’s Motion on the legal issue of whether MAIT can be designated as a public utility. The procedural schedule has been suspended until a decision is made on this issue. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction. OHIO The Ohio Companies operate under their ESP 3 plan which expires on May 31, 2016. The material terms of ESP 3 include: • A base distribution rate freeze through May 31, 2016; • Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; • Economic development and assistance to low-income customers for the two -year plan period at levels established in the prior ESP; • A 6% generation rate discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); • A requirement to provide power to non-shopping customers at a market-based price set through an auction process; • Rider DCR that allows continued investment in the distribution system for the benefit of customers; • A commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million, subject to the outcome of certain FERC proceedings; • Securing generation supply for a longer period of time by conducting an auction for a three -year period rather than a one -year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility customers who do not switch to a competitive generation supplier; and • Extending the recovery period for costs associated with purchasing RECs mandated by SB221, Ohio's renewable energy and energy efficiency standard, through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the entire ESP period. Notices of appeal of the Ohio Companies' ESP 3 plan to the Supreme Court of Ohio were filed by the Northeast Ohio Public Energy Council and the ELPC. The oral argument in this matter occurred on January 6, 2016. The Ohio Companies filed an application with the PUCO on August 4, 2014 seeking approval of their ESP IV entitled Powering Ohio's Progress . The Ohio Companies filed a Stipulation and Recommendation on December 22, 2014, and supplemental stipulations and recommendations on May 28, 2015, and June 4, 2015. The evidentiary hearing on the ESP IV commenced on August 31, 2015 and concluded on October 29, 2015. On December 1, 2015, the Ohio Companies filed a Third Supplemental Stipulation and Recommendation, which included PUCO Staff as a signatory party in addition to other signatories. The PUCO completed a hearing on the Third Supplemental Stipulation and Recommendation in January 2016. Initial briefs are due on February 16, 2016 and reply briefs are due on February 26, 2016. A final PUCO decision is expected in March 2016. The proposed ESP IV supports FirstEnergy's strategic focus on regulated operations and better positions the Ohio Companies to deliver on their ongoing commitment to upgrade, modernize and maintain reliable electric service for customers while preserving electric security in Ohio. The material terms of the proposed ESP IV, as modified by the stipulations include: • An eight -year term (June 1, 2016 - May 31, 2024); • Contemplates continuing a base distribution rate freeze through May 31, 2024; • An Economic Stability Program that flows through charges or credits through Rider RRS representing the net result of the price paid to FES through a proposed eight -year FERC-jurisdictional PPA for the output of the Sammis and Davis-Besse plants and FES’ share of OVEC against the revenues received from selling such output into the PJM markets over the same period, subject to the PUCO’s termination of Rider RRS charges/credits associated with any plants or units that may be sold or transferred; • Continuing to provide power to non-shopping customers at a market-based price set through an auction process; • Continuing Rider DCR with increased revenue caps of approximately $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 that supports continued investment related to the distribution system for the benefit of customers; • Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; • A risk-sharing mechanism that would provide guaranteed credits under Rider RRS in years five through eight to customers as follows: $10 million in year five, $20 million in year six, $30 million in year seven and $40 million in year eight; • A continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided by customers for certain types of products totals $360 million, including such costs from MISO along with such costs from PJM, subject to the outcome of certain FERC proceedings; • Potential procurement of 100 MW of new Ohio wind or solar resources subject to a demonstrated need to procure new renewable energy resources as part of a strategy to further diversify Ohio's energy portfolio; • An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential customers; • An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval; • A contribution of $3 million per year ($24 million over the eight year term) to fund energy conservation programs, economic development and job retention in the Ohio Companies service territory; • Contributions of $2.4 million per year ($19 million over the eight year term) to fund a fuel-fund in each of the Ohio Companies service territories to assist low-income customers; and • A contribution of $1 million per year ($8 million over the eight year term) to establish a Customary Advisory Council to ensure preservation and growth of the competitive market in Ohio. On January 27, 2016, certain parties filed a complaint at FERC against FES, OE, CEI, and TE that requests FERC review of the ESP IV PPA under Section 205 of the FPA. In addition to such proceeding, parties have expressed an intention to challenge in the courts and/or before FERC, the PPA or PUCO approval of the ESP IV, if approved. Management intends to vigorously defend against such challenges. Under Ohio's energy efficiency standards (SB221 and SB310), and based on the Ohio Companies' amended energy efficiency plans, the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of 2,266 GWHs in 2015 and 2,288 GWHs in 2016, and then begin to increase by 1% each year in 2017, subject to legislative amendments to the energy efficiency standards discussed below. The Ohio Companies are also required to retain the 2014 peak demand reduction level for 2015 and 2016 and then increase the benchmark by an additional 0.75% thereafter through 2020, subject to legislative amendments to the peak demand reduction standards discussed below. On September 30, 2015, the Energy Mandates Study Committee issued its report related to energy efficiency and renewable energy mandates, recommending that the current level of mandates remain in place indefinitely. The report also recommended: (i) an expedited process for review of utility proposed energy efficiency plans; (ii) ensuring maximum credit for all of Ohio's Energy Initiatives; (iii) a switch from energy mandates to energy incentives; and (iv) a declaration be made that the General Assembly may determine energy policy of the state. No legislation has yet been introduced to change the standards described above. On March 20, 2013, the PUCO approved the three-year energy efficiency portfolio plans for 2013-2015, originally estimated to cost the Ohio Companies approximately $250 million over the three-year period, which is expected to be recovered in rates. Actual costs may be lower for a number of reasons including the approval of the amended portfolio plan under SB310. On July 17, 2013, the PUCO modified the plan to authorize the Ohio Companies to receive 20% of any revenues obtained from offering energy efficiency and DR reserves into the PJM auction. The PUCO also confirmed that the Ohio Companies can recover PJM costs and applicable penalties associated with PJM auctions, including the costs of purchasing replacement capacity from PJM incremental auctions, to the extent that such costs or penalties are prudently incurred. ELPC and OCC filed applications for rehearing, which were granted for the sole purpose of further consideration of the issue. On September 24, 2014, the Ohio Companies filed an amendment to their portfolio plan as contemplated by SB310, seeking to suspend certain programs for the 2015-2016 period in order to better align the plan with the new benchmarks under SB310. On November 20, 2014, the PUCO approved the Ohio Companies' amended portfolio plan. Several applications for rehearing were filed, and the PUCO granted those applications for further consideration of the matters specified in those applications. On September 16, 2013, the Ohio Companies filed with the Supreme Court of Ohio a notice of appeal of the PUCO's July 17, 2013 Entry on Rehearing related to energy efficiency, alternative energy, and long-term forecast rules stating that the rules issued by the PUCO are inconsistent with, and are not supported by, statutory authority. On October 23, 2013, the PUCO filed a motion to dismiss the appeal, which is still pending. The matter has not been scheduled for oral argument. 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, subject to legislative amendments discussed above, except 2015 and 2016 that remain at the 2014 level. 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. On February 18, 2014, the OCC and the ELPC also filed appeals of the PUCO's order. The Ohio Companies timely filed their merit brief with the Supreme Court of Ohio and the briefing process has concluded. The matter is not yet scheduled for oral argument. On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers. PENNSYLVANIA The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2017, and provide for the competitive procurement of generation supply for customers that do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. The default service supply is currently provided by wholesale suppliers through a mix of long-term and short-term contracts procured through spot market purchases, quarterly descending clock auctions for 3, 12- and 24-month energy contracts, and one RFP seeking 2-year contracts to serve SRECs for ME, PN and Penn. On November 3, 2015, the Pennsylvania Companies filed their proposed DSPs for the June 1, 2017 through May 31, 2019 delivery period, which would 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 proposed programs, the supply would be provided by wholesale suppliers though a mix of 12 and 24-month energy contracts, as well as one RFP for 2-year SREC contracts for ME, PN and Penn. In addition, the proposal includes modifications to the Pennsylvania Companies’ existing POR programs in order to reduce the level of uncollectibles the Pennsylvania Companies experience associated with alternative EGS charges. Pursuant to Pennsylvania's EE&C legislation (Act 129 of 2008) and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies' Phase II EE&C Plans are effective through May 31, 2016. Total costs of these plans are expected to be approximately $234 million and recoverable through the Pennsylvania Companies' reconcilable EE&C riders. 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 filed their Phase III EE&C plans for the June 2016 through May 2021 period on November 23, 2015, which are designed to achieve the targets established in the PPUC's Phase III Final Implementation Order. EDCs are permitted to recover costs for implementing their EE&C plans. On February 10, 2016, the Pennsylvania Companies and the parties intervening in the PPUC's Phase III proceeding filed a joint settlement that resolves all issues in the proceeding and is subject to PPUC approval. 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 October 19, 2015, each of the Pennsylvania Companies filed LTIIPs with the PPUC for infrastructure improvement over the five -year period of 2016 to 2020 for the following costs: WP $88.34 million ; PN $56.74 million ; Penn $56.35 million ; and ME $43.44 million . These amounts include all qualifying distribution capital additions identified in the revised implementation plan for the recent focused management and operations audit of the Pennsylvania Companies as discussed below. On February 11, 2016, the PPUC approved the Pennsylvania Companies' LTIIPs. On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery associated with the capital projects approved in the LTIIPs. The DSIC riders are expected to be effective July 1, 2016. Each of the Pennsylvania Companies currently offer distribution rates under their respective Joint Petitions for Settlement approved on April 9, 2015 by the PPUC, which, among other things, provided for a total increase in annual revenues for all Pennsylvania Companies of $292.8 million , ( $89.3 million for ME, $90.8 million for PN, $15.9 million for Penn and $96.8 million for WP), including the recovery of $87.7 million of additional annual operating expenses, including costs associated with service reliability enhancements to the distribution system, amortization of deferred storm costs and the remaining net book value of legacy meters, assistance for providing service to low-income customers, and the creation of a storm reserve for each utility. Additionally, the approved settlements include commitments to meet certain wait times for call centers and service reliability standards. The new rates were effective May 3, 2015. On July 16, 2013, the PPUC's Bureau of Audits initiated a focused management and operations audit of the Pennsylvania Companies as required every eight years by statute. The PPUC issued a report on its findings and recommendations on February 12, 2015, at which time the Pennsylvania Companies' associated implementation plan was also made public. In an order issued on March 30, 2015, the Pennsylvania Companies were directed to develop and file by May 29, 2015 a revised implementation plan regarding certain of the operational topics addressed in the report, including addressing certain reliability matters. The Pennsylvania Companies filed their revised implementation plan in compliance with this order. A final order adopting the plan, as revised, was entered on November 5, 2015. The cost of compliance for the Pennsylvania Companies is currently expected to range from approximately $200 million to $230 million . On June 19, 2015, ME and PN, along with JCP&L, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. Evidentiary hearings are scheduled to commence before the PPUC on February 29, 2016. A final decision from the PPUC is expected by mid-2016. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction. WEST VIRGINIA MP and PE currently operate under a Joint Stipulation and Agreement of Settlement approved by the WVPSC on February 3, 2015, that provided for: a $15 million increase in annual base rate revenues effective February 25, 2015; the implementation of a Vegetation Management Surcharge to recover all costs related to both new and existing vegetation maintenance programs; authority to establish a regulatory asset for MATS investments placed into service in 2016 and 2017; authority to defer, amortize and recover over a five- year period through base rates approximately $46 million of storm restoration costs; and elimination of the TTS for costs associated with MP's acquisition of the Harrison plant in October 2013 and movement of those costs into base rates. On August 14, 2015, MP and PE filed their annual ENEC case with the WVPSC proposing an approximate $165.1 million annual increase in rates effective January 1, 2016 or before, which would be a 12.5% overall increase over existing rates. The original proposed increase was comprised of a $97 million under-recovered balance as of June 30, 2015, a projected $23.7 million under-recovery for the 2016 calendar year, and an actual under-recovered balance from MP and PE's TTS for Harrison Power Station of $44.4 million . On September 10, 2015, MP and PE filed an amendment addressing the results of the recent PJM Transitional Auctions for Capacity Performance, which resulted in a net decrease of $20.6 million from the initial requested increase to $144.5 million . A settlement was reached among all the parties increasing revenues $96.9 million and deferring other costs for recovery into 2017. The settlement was presented to the WVPSC on November 19, 2015 , and a final order approving the settlement without changes was issued on December 22, 2015, with rates effective on January 1, 2016. On August 31, 2015, MP and PE filed with the WVPSC their biennial petition for reconciliation of the Vegetation Management Program Surcharge and regular review of the program proposing an approximate $37.7 million annual increase in rates over a two year period, which is a 2.8% overall increase over existing rates. The proposed increase was comprised of a $2.1 million under-recovered balance as of June 30, 2015, a projected $23.9 million in under-recovery for the 2016/2017 rate effective period, and recovery of previously authorized deferred vegetation management costs from April 14, 2014 through February 24, 2015 in the amount of $49.9 million . A settlement was reached among all the parties increasing revenues $36.7 million annually for the 2016-2017 two year rate recovery period, and was presented to the WVPSC on November 19, 2015. A final order approving the settlement without changes was issued on December 21, 2015, with rates effective on January 1, 2016. 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, FES, AE Supply, FG, FENOC, NG, ATSI 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, and obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations and cash flows. FERC MATTERS PJM Transmission Rates PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities. 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 Se

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS, GUARANTEES AND CONTINGENCIES	COMMITMENTS, GUARANTEES AND CONTINGENCIES NUCLEAR INSURANCE The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $13.5 billion (assuming 103 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $375 million ; and (ii) $13.1 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $127 million (but not more than $19 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s maximum potential assessment under these provisions would be $509 million (NG- $501 million ) per incident but not more than $76 million (NG- $75 million ) in any one year for each incident. In addition to the public liability insurance provided pursuant to the Price-Anderson Act, FirstEnergy has also obtained insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of NEIL, which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies, renewable annually, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $1.96 billion (NG- $1.93 billion ) for replacement power costs incurred during an outage after an initial 20-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy’s present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $15 million (NG- $15 million ). FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the operating company for each plant. Under these arrangements, up to $2.75 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. FirstEnergy pays annual premiums for this coverage and is liable for retrospective assessments of up to approximately $83 million (NG- $81 million ). FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of FirstEnergy’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by FirstEnergy’s insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs. The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.06 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds. GUARANTEES AND OTHER ASSURANCES FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. As of December 31, 2015 , outstanding guarantees and other assurances aggregated approximately $3.7 billion , consisting of parental guarantees ( $583 million ), subsidiaries' guarantees ( $2,137 million ), other guarantees ($ 300 million ) and other assurances ( $667 million ). Of this aggregate amount, substantially all relates to guarantees of wholly-owned consolidated entities of FirstEnergy. FES' debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each of FG and NG. Accordingly, present and future holders of indebtedness of FES, FG, and NG would have claims against each of FES, FG, and NG, regardless of whether their primary obligor is FES, FG, or NG. COLLATERAL AND CONTINGENT-RELATED FEATURES In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on FES' power portfolio exposure as of December 31, 2015 , FES has posted collateral of $188 million and AE Supply has posted no collateral . The Regulated Distribution segment has posted collateral of $1 million . These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required. Subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of FE or its subsidiaries. The following table discloses the additional credit contingent contractual obligations that may be required under certain events as of December 31, 2015 : Collateral Provisions FES AE Supply Utilities Total (In millions) Split Rating (One rating agency's rating below investment grade) $ 198 $ 6 $ 41 $ 245 BB+/Ba1 Credit Ratings $ 231 $ 6 $ 41 $ 278 Full impact of credit contingent contractual obligations $ 363 $ 16 $ 41 $ 420 Excluded from the preceding chart are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment. As of December 31, 2015 , neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES would be required to post $8 million with affiliated parties. OTHER COMMITMENTS AND CONTINGENCIES FirstEnergy is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding borrowed $300 million . In addition to FirstEnergy, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, have also provided their joint and several guaranties of the obligations of Global Holding under the facility. In connection with Global Holding's term loan facility, a portion of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with each of FEV's and WMB Marketing Ventures,LLC's 33-1/3% membership interests in Global Holding, are pledged to the lenders under Global Holding's facility as collateral. Failure by Global Holding to meet the terms and conditions under its term loan facility could require FirstEnergy to be obligated under the provisions of its guarantee, resulting in consolidation of Global Holding by FE. During the first quarter of 2015, a subsidiary of Global Holding eliminated its right to put 2 million tons annually through 2024 from the Signal Peak mine to FG in exchange for FirstEnergy extending its guarantee under Global Holding's $300 million senior secured term loan facility through 2020, resulting in a pre-tax charge of $24 million. See Note 8, Variable Interest Entities, and Note 1, Organization, Basis of Presentation and Significant Accounting Policies - Investments, for additional information regarding FEV's investment in Global Holding. ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Clean Air Act FirstEnergy complies with SO 2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls, generating more electricity from lower or non-emitting plants and/or using emission allowances. CSAPR requires reductions of NOx and SO 2 emissions in two phases (2015 and 2017), ultimately capping SO 2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions. The U.S. Court of Appeals for the D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO 2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding EPA’s regulatory approach under CSAPR, but questioning whether EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. EPA proposed a CSAPR update rule on November 16, 2015, that would reduce summertime NOx emissions from power plants in 23 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Depending on how the EPA and the states implement CSAPR, the future cost of compliance may be substantial and changes to FirstEnergy's and FES' operations may result. EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015. EPA stated the vast majority of U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and state rules and programs but EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017. States will then have roughly three years to develop implementation plans to attain the new 2015 ozone NAAQS. Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be substantial and changes to FirstEnergy’s and FES’ operations may result. MATS imposes emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. On December 28, 2012, the WVDEP granted a conditional extension through April 16, 2016 for MATS compliance at the Fort Martin, Harrison and Pleasants plants. On March 20, 2013, the PA DEP granted an extension through April 16, 2016 for MATS compliance at the Hatfield's Ferry and Bruce Mansfield plants. On February 5, 2015, the OEPA granted an extension through April 16, 2016 for MATS compliance at the Bay Shore and Sammis plants. Nearly all spending for MATS compliance at Bay Shore and Sammis has been completed through 2014. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On June 29, 2015, the United States Supreme Court reversed a U.S. Court of Appeals for the D.C. Circuit decision that upheld MATS, rejecting EPA’s regulatory approach that costs are not relevant to the decision of whether or not to regulate power plant emissions under Section 112 of the Clean Air Act and remanded the case back to the U.S. Court of Appeals for the D.C. Circuit for further proceedings. The U.S. Court of Appeals for the D.C. Circuit later remanded MATS back to EPA, who represented to such court that the EPA is on track to issue a finalized MATS by April 15, 2016. Subject to the outcome of any further proceedings before the U.S. Court of Appeals for the D.C. Circuit and how the MATS are ultimately implemented, FirstEnergy's total capital cost for compliance (over the 2012 to 2018 time period) is currently expected to be approximately $345 million (CES segment of $168 million and Regulated Distribution segment of $177 million ), of which $202 million has been spent through December 31, 2015 ( $80 million at CES and $122 million at Regulated Distribution). As a result of MATS, Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 were deactivated in April 2015, which completes the deactivation of 5,429 MW of coal-fired plants since 2012. On August 3, 2015, FG, a subsidiary of FES, submitted to the AAA office in New York, N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure that excuses FG’s performance under its coal transportation contract with these parties. Specifically, the dispute arises from a contract for the transportation by BNSF and CSX of a minimum of 3.5 million tons of coal annually through 2025 to certain coal-fired power plants owned by FG that are located in Ohio. As a result of and in compliance with MATS, those plants were deactivated by April 16, 2015. In January 2012, FG notified BNSF and CSX that MATS constituted a force majeure event under the contract that excused FG’s further performance. Separately, on August 4, 2015, BNSF and CSX submitted to the AAA office in Washington, D.C., a demand for arbitration and statement of claim against FG alleging that FG breached the contract and that FG’s declaration of a force majeure under the contract is not valid and seeking damages including, but not limited to, lost profits under the contract through 2025. As part of its statement of claim, a right to liquidated damages is alleged. The arbitration panel has determined to consolidate the claims with a liability hearing expected to begin in November 2016, and, if necessary, a damages hearing is expected to begin in May 2017. The decision on liability is expected to be issued within sixty days from the end of the liability hearings. FirstEnergy and FES continue to believe that MATS constitutes a force majeure event under the contract as it relates to the deactivated plants and that FG’s performance under the contract is therefore excused. FirstEnergy and FES intend to vigorously assert their position in the arbitration proceedings. If, however, the arbitration panel rules in favor of BNSF and CSX, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. FirstEnergy and FES are unable to estimate the loss or range of loss. FG is also a party to another coal transportation contract covering the delivery of 2.5 million tons annually through 2025, a portion of which is to be delivered to another coal-fired plant owned by FG that was deactivated as a result of MATS. FG has asserted a defense of force majeure in response to delivery shortfalls to such plant under this contract as well. If FirstEnergy and FES fail to reach a resolution with the applicable counterparties to the contract, and if it were ultimately determined that, contrary to FirstEnergy’s and FES’ belief, the force majeure provisions of that contract do not excuse the delivery shortfalls to the deactivated plant, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. FirstEnergy and FES are unable to estimate the loss or range of loss. As to both coal transportation agreements referenced above, FES paid in settlement approximately $70 million in liquidated damages for delivery shortfalls in 2014 related to its deactivated plants. As to a specific coal supply agreement, FirstEnergy and AE Supply have asserted termination rights effective in 2015. In response to notification of the termination, the coal supplier commenced litigation alleging FirstEnergy and AE Supply do not have sufficient justification to terminate the agreement. FirstEnergy and AE Supply have filed an answer denying any liability related to the termination. This matter is currently in the discovery phase of litigation and no trial date has been established. There are 6 million tons remaining under the contract for delivery. At this time, FirstEnergy cannot estimate the loss or range of loss regarding the on-going litigation with respect to this agreement. In September 2007, AE received an NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia. The EPA's NOV alleges equipment replacements during maintenance outages triggered the pre-construction permitting requirements under the NSR and PSD programs. On June 29, 2012, January 31, 2013, and March 27, 2013, EPA issued CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. On December 12, 2014, EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009. FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss. Climate Change There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation. A June 2013, Presidential Climate Action Plan outlined goals to: (i) cut carbon pollution in America by 17% by 2020 (from 2005 levels); (ii) prepare the United States for the impacts of climate change; and (iii) lead international efforts to combat global climate change and prepare for its impacts. GHG emissions have already been reduced by 10% between 2005 and 2012 according to an April, 2014 EPA Report. Due to plant deactivations and increased efficiencies, FirstEnergy anticipates its CO 2 emissions will be reduced 25% below 2005 levels by 2015, exceeding the President’s Climate Action Plan goals both in terms of timing and reduction levels. The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act” in December 2009, concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. The EPA released its final regulations in August 2015, to reduce CO 2 emissions from existing fossil fuel fired electric generating units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO 2 emission rate goals. The EPA’s CPP allows states to request a two -year extension to finalize SIPs by September 6, 2018. If states fail to develop SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions trading rules which states can also adopt in their SIPs. The EPA also finalized separate regulations imposing CO 2 emission limits for new, modified, and reconstructed fossil fuel fired electric generating units. On June 23, 2014, the United States Supreme Court decided that CO 2 or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies. Numerous states and private parties filed appeals and motions to stay the CPP with the U.S. Court of Appeals for the D.C. Circuit in October 2015. On January 21, 2015, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court. Depending on the outcome of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be substantial. At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide greenhouse gas emissions by 26 to 28 percent below 2005 levels by 2025 and joined in adopting the agreement reached on December 12, 2015 at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement must be ratified by at least 55 countries representing at least 55% of global GHG emissions before its non-binding obligations to limit global warming to well below two degrees Celsius become effective. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO 2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO 2 emitting gas-fired and nuclear generators. Clean Water Act Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from the plant's cooling water intake system. Depending on the results of such studies and any final action taken by the states based on those studies, the future capital costs of compliance with these standards may be substantial. The EPA proposed updates to the waste water effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423) in April 2013. On September 30, 2015, the EPA finalized new, more stringent effluent limits for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations will phase-in as permits are renewed on a five -year cycle from 2018 to 2023. The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's and FES' operations may result. In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the effluent limits that were effective immediately under the terms of the NPDES permit. MP appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require an initial capital investment ranging from $150 million to $300 million in order to install technology to meet the TDS and sulfate limits, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of the appeal or estimate the possible loss or range of loss. FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the loss or range of loss. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards regarding 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. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although unexpected, changes in timing and closure plan requirements in the future could impact our asset retirement obligations significantly. Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit requiring FE to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FE to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCRs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The Bruce Mansfield plant is pursuing several options for disposal of CCRs following December 31, 2016 and expects beneficial reuse and disposal options will be sufficient for the ongoing operation of the plant. On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR. On July 6, 2015 and October 22, 2015, the Sierra Club filed Notice of Appeals with the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility. FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 2015 based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $126 million have been accrued through December 31, 2015 . Included in the total are accrued liabilities of approximately $87 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FirstEnergy or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time. OTHER LEGAL PROCEEDINGS Nuclear Plant Matters Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of December 31, 2015 , FirstEnergy had approximately $2.3 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. The values of FirstEnergy's NDTs fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs. FE and FES have also entered into a total of $24.5 million in parental guarantees in support of the decommissioning of the spent fuel storage facilities located at the nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guaranties, as appropriate. In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years. On December 8, 2015, the NRC renewed the operating license for Davis-Besse, which is now authorized to continue operation through April 22, 2037. Prior to that decision, the NRC Commissioners denied an intervenor's

Transactions With Affiliated Co

Transactions With Affiliated Companies	12 Months Ended
	Dec. 31, 2015
Transactions With Affiliated Companies [Abstract]
TRANSACTIONS WITH AFFILIATED COMPANIES	TRANSACTIONS WITH AFFILIATED COMPANIES FES’ operating revenues, operating expenses, investment income and interest expenses include transactions with affiliated companies. These affiliated company transactions include affiliated company power sales agreements between FirstEnergy's competitive and regulated companies, support service billings, interest on affiliated company notes including the money pools and other transactions. FirstEnergy's competitive companies at times provide power through affiliated company power sales to meet a portion of the Utilities' POLR and default service requirements. The primary affiliated company transactions for FES during the three years ended December 31, 2015 are as follows: FES 2015 2014 2013 (In millions) Revenues: Electric sales to affiliates $ 664 $ 861 $ 652 Other 6 6 6 Expenses: Purchased power from affiliates 353 271 486 Fuel 1 1 — Support services 705 619 619 Investment Income: Interest income from FE 2 3 2 Interest Expense: Interest expense to affiliates 4 3 4 Interest expense to FE 3 4 6 FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to FES and the Utilities from FESC and FENOC. The majority of costs are directly billed or assigned at no more than cost. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC and FENOC. The current allocation or assignment formulas used and their bases include multiple factor formulas: each company’s proportionate amount of FirstEnergy’s aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Management believes that these allocation methods are reasonable. Intercompany transactions are generally settled under commercial terms within thirty days. FES purchases the entire output of the generation facilities owned by FG and NG, and may purchase the uncommitted output of AE Supply, as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements, and pursuant to full output, cost-of-service PSAs. FES and the Utilities are parties to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy are generally reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit (see Note 5, Taxes).

Supplemental Guarantor Informat

Supplemental Guarantor Information	12 Months Ended
	Dec. 31, 2015
Supplemental Guarantor Information [Abstract]
SUPPLEMENTAL GUARANTOR INFORMATION	SUPPLEMENTAL GUARANTOR INFORMATION In 2007, FG completed a sale and leaseback transaction for its undivided interest in Bruce Mansfield Unit 1. FES has fully and unconditionally and irrevocably guaranteed all of FG's obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FG, but the notes are secured by, among other things, each lessor trust's undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES' lease guaranty. This transaction is classified as an operating lease for FES and FirstEnergy and as a financing lease for FG. The Condensed Consolidating Statements of Income (Loss) and Comprehensive Income (Loss) for the years ended December 31, 2015 , 2014 , and 2013 , Condensed Consolidating Balance Sheets as of December 31, 2015 and December 31, 2014 , and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2015 , 2014 , and 2013 , for FES (parent and guarantor), FG and NG (non-guarantor) are presented below. These statements are provided as FES fully and unconditionally guarantees outstanding registered securities of FG as well as FG's obligations under the facility lease for the Bruce Mansfield sale and leaseback that underlie outstanding registered pass-through trust certificates. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FG and NG are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction. FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Year Ended December 31, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 4,824 $ 1,801 $ 2,138 $ (3,758 ) $ 5,005 OPERATING EXPENSES: Fuel — 679 192 — 871 Purchased power from affiliates 3,826 — 285 (3,758 ) 353 Purchased power from non-affiliates 1,684 — — — 1,684 Other operating expenses 399 275 618 49 1,341 Pension and OPEB mark-to-market adjustment (8 ) 10 55 — 57 Provision for depreciation 12 124 191 (3 ) 324 General taxes 45 26 27 — 98 Total operating expenses 5,958 1,114 1,368 (3,712 ) 4,728 OPERATING INCOME (LOSS) (1,134 ) 687 770 (46 ) 277 OTHER INCOME (EXPENSE): Investment income (loss), including net income from equity investees 844 17 (5 ) (870 ) (14 ) Miscellaneous income 1 2 — — 3 Interest expense — affiliates (29 ) (8 ) (4 ) 34 (7 ) Interest expense — other (52 ) (104 ) (49 ) 58 (147 ) Capitalized interest — 6 29 — 35 Total other income (expense) 764 (87 ) (29 ) (778 ) (130 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (370 ) 600 741 (824 ) 147 INCOME TAXES (BENEFITS) (452 ) 224 278 15 65 NET INCOME $ 82 $ 376 $ 463 $ (839 ) $ 82 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 82 $ 376 $ 463 $ (839 ) $ 82 OTHER COMPREHENSIVE LOSS: Pension and OPEB prior service costs (6 ) (5 ) — 5 (6 ) Amortized gain on derivative hedges (3 ) — — — (3 ) Change in unrealized gain on available-for-sale securities (9 ) — (8 ) 8 (9 ) Other comprehensive loss (18 ) (5 ) (8 ) 13 (18 ) Income tax benefits on other comprehensive loss (7 ) (2 ) (3 ) 5 (7 ) Other comprehensive loss, net of tax (11 ) (3 ) (5 ) 8 (11 ) COMPREHENSIVE INCOME $ 71 $ 373 $ 458 $ (831 ) $ 71 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Year Ended December 31, 2014 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 5,990 $ 1,902 $ 2,172 $ (3,920 ) $ 6,144 OPERATING EXPENSES: Fuel — 1,055 198 — 1,253 Purchased power from affiliates 3,920 — 271 (3,920 ) 271 Purchased power from non-affiliates 2,767 4 — — 2,771 Other operating expenses 790 269 527 49 1,635 Pension and OPEB mark-to-market adjustment 19 90 188 — 297 Provision for depreciation 10 119 193 (3 ) 319 General taxes 72 31 25 — 128 Total operating expenses 7,578 1,568 1,402 (3,874 ) 6,674 OPERATING INCOME (LOSS) (1,588 ) 334 770 (46 ) (530 ) OTHER INCOME (EXPENSE): Loss on debt redemptions (3 ) (1 ) (2 ) — (6 ) Investment income, including net income from equity investees 791 8 61 (799 ) 61 Miscellaneous income 2 4 — — 6 Interest expense — affiliates (12 ) (6 ) (4 ) 15 (7 ) Interest expense — other (53 ) (101 ) (52 ) 60 (146 ) Capitalized interest — 4 30 — 34 Total other income (expense) 725 (92 ) 33 (724 ) (58 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) (863 ) 242 803 (770 ) (588 ) INCOME TAXES (BENEFITS) (619 ) 87 298 6 (228 ) INCOME (LOSS) FROM CONTINUING OPERATIONS (244 ) 155 505 (776 ) (360 ) Discontinued operations (net of income taxes of $70) — 116 — — 116 NET INCOME (LOSS) $ (244 ) $ 271 $ 505 $ (776 ) $ (244 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (244 ) $ 271 $ 505 $ (776 ) $ (244 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (6 ) (5 ) — 5 (6 ) Amortized gain on derivative hedges (10 ) — — — (10 ) Change in unrealized gain on available-for-sale securities 21 — 21 (21 ) 21 Other comprehensive income (loss) 5 (5 ) 21 (16 ) 5 Income taxes (benefits) on other comprehensive income (loss) 2 (2 ) 8 (6 ) 2 Other comprehensive income (loss), net of tax 3 (3 ) 13 (10 ) 3 COMPREHENSIVE INCOME (LOSS) $ (241 ) $ 268 $ 518 $ (786 ) $ (241 ) FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Year Ended December 31, 2013 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 6,068 $ 2,399 $ 1,634 $ (3,928 ) $ 6,173 OPERATING EXPENSES: Fuel — 1,056 206 — 1,262 Purchased power from affiliates 4,148 — 266 (3,928 ) 486 Purchased power from non-affiliates 2,326 7 — — 2,333 Other operating expenses 635 275 529 48 1,487 Pension and OPEB mark-to-market adjustment (8 ) (37 ) (36 ) — (81 ) Provision for depreciation 6 127 178 (5 ) 306 General taxes 80 34 24 — 138 Total operating expenses 7,187 1,462 1,167 (3,885 ) 5,931 OPERATING INCOME (LOSS) (1,119 ) 937 467 (43 ) 242 OTHER INCOME (EXPENSE): Loss on debt redemptions (103 ) — — — (103 ) Investment income, including net income from equity investees 847 1 25 (857 ) 16 Miscellaneous income 4 24 — — 28 Interest expense — affiliates (13 ) (5 ) (6 ) 14 (10 ) Interest expense — other (63 ) (104 ) (54 ) 61 (160 ) Capitalized interest 1 2 36 — 39 Total other income (expense) 673 (82 ) 1 (782 ) (190 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) (446 ) 855 468 (825 ) 52 INCOME TAXES (BENEFITS) (506 ) 365 135 12 6 INCOME FROM CONTINUING OPERATIONS 60 490 333 (837 ) 46 Discontinued operations (net of income taxes of $8) — 14 — — 14 NET INCOME $ 60 $ 504 $ 333 $ (837 ) $ 60 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 60 $ 504 $ 333 $ (837 ) $ 60 OTHER COMPREHENSIVE LOSS: Pension and OPEB prior service costs (15 ) (13 ) — 13 (15 ) Amortized gain on derivative hedges (6 ) — — — (6 ) Change in unrealized gain on available-for-sale securities (8 ) — (8 ) 8 (8 ) Other comprehensive loss (29 ) (13 ) (8 ) 21 (29 ) Income tax benefits on other comprehensive loss (11 ) (5 ) (3 ) 8 (11 ) Other comprehensive loss, net of tax (18 ) (8 ) (5 ) 13 (18 ) COMPREHENSIVE INCOME $ 42 $ 496 $ 328 $ (824 ) $ 42 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2015 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 275 — — — 275 Affiliated companies 433 403 461 (846 ) 451 Other 36 4 19 — 59 Notes receivable from affiliated companies 406 1,210 805 (2,410 ) 11 Materials and supplies 53 204 213 — 470 Derivatives 154 — — — 154 Collateral 70 — — — 70 Prepayments and other 48 18 — — 66 1,475 1,841 1,498 (3,256 ) 1,558 PROPERTY, PLANT AND EQUIPMENT: In service 93 6,367 8,233 (382 ) 14,311 Less — Accumulated provision for depreciation 40 2,144 3,775 (194 ) 5,765 53 4,223 4,458 (188 ) 8,546 Construction work in progress 30 249 878 — 1,157 83 4,472 5,336 (188 ) 9,703 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,327 — 1,327 Investment in affiliated companies 7,452 — — (7,452 ) — Other — 10 — — 10 7,452 10 1,327 (7,452 ) 1,337 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 300 16 — (316 ) — Customer intangibles 61 — — — 61 Goodwill 23 — — — 23 Property taxes — 12 28 — 40 Derivatives 79 — — — 79 Other 33 318 21 12 384 496 346 49 (304 ) 587 $ 9,506 $ 6,669 $ 8,210 $ (11,200 ) $ 13,185 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 229 $ 308 $ (25 ) $ 512 Short-term borrowings- Affiliated companies 2,021 389 — (2,410 ) — Other — 8 — — 8 Accounts payable- Affiliated companies 884 146 368 (856 ) 542 Other 21 118 — — 139 Accrued taxes 7 93 62 (86 ) 76 Derivatives 103 1 — — 104 Other 66 61 9 45 181 3,102 1,045 747 (3,332 ) 1,562 CAPITALIZATION: Total equity 5,605 2,944 4,476 (7,420 ) 5,605 Long-term debt and other long-term obligations 694 2,122 847 (1,136 ) 2,527 6,299 5,066 5,323 (8,556 ) 8,132 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 791 791 Accumulated deferred income taxes 6 — 697 (103 ) 600 Asset retirement obligations — 191 640 — 831 Retirement benefits 27 305 — — 332 Derivatives 37 1 — — 38 Other 35 61 803 — 899 105 558 2,140 688 3,491 $ 9,506 $ 6,669 $ 8,210 $ (11,200 ) $ 13,185 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2014 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 415 — — — 415 Affiliated companies 484 487 674 (1,120 ) 525 Other 66 21 20 — 107 Notes receivable from affiliated companies 339 838 272 (1,449 ) — Materials and supplies 67 202 223 — 492 Derivatives 147 — — — 147 Collateral 229 — — — 229 Prepayments and other 48 19 — 1 68 1,795 1,569 1,189 (2,568 ) 1,985 PROPERTY, PLANT AND EQUIPMENT: In service 133 6,217 7,628 (382 ) 13,596 Less — Accumulated provision for depreciation 36 2,058 3,305 (191 ) 5,208 97 4,159 4,323 (191 ) 8,388 Construction work in progress 3 206 801 — 1,010 100 4,365 5,124 (191 ) 9,398 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,365 — 1,365 Investment in affiliated companies 6,607 — — (6,607 ) — Other — 10 — — 10 6,607 10 1,365 (6,607 ) 1,375 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 284 98 — (382 ) — Customer intangibles 78 — — — 78 Goodwill 23 — — — 23 Property taxes — 14 27 — 41 Unamortized sale and leaseback costs — — — — — Derivatives 52 — — — 52 Other 34 277 7 13 331 471 389 34 (369 ) 525 $ 8,973 $ 6,333 $ 7,712 $ (9,735 ) $ 13,283 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ 18 $ 164 $ 348 $ (24 ) $ 506 Short-term borrowings- Affiliated companies 1,135 321 28 (1,449 ) 35 Other 90 9 — — 99 Accounts payable- Affiliated companies 1,068 197 219 (1,068 ) 416 Other 46 202 — — 248 Accrued taxes 2 62 161 (123 ) 102 Derivatives 166 — — — 166 Other 72 56 9 47 184 2,597 1,011 765 (2,617 ) 1,756 CAPITALIZATION: Total equity 5,585 2,561 4,014 (6,575 ) 5,585 Long-term debt and other long-term obligations 695 2,215 859 (1,161 ) 2,608 6,280 4,776 4,873 (7,736 ) 8,193 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 824 824 Accumulated deferred income taxes 13 — 678 (207 ) 484 Asset retirement obligations — 189 652 — 841 Retirement benefits 36 288 — — 324 Derivatives 14 — — — 14 Other 33 69 744 1 847 96 546 2,074 618 3,334 $ 8,973 $ 6,333 $ 7,712 $ (9,735 ) $ 13,283 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2015 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (637 ) $ 551 $ 1,261 $ (24 ) $ 1,151 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 45 296 — 341 Short-term borrowings, net 796 67 — (863 ) — Redemptions and Repayments- Long-term debt (17 ) (70 ) (348 ) 24 (411 ) Short-term borrowings, net — — (28 ) (98 ) (126 ) Common stock dividend payment (70 ) — — — (70 ) Other — (5 ) (1 ) — (6 ) Net cash provided from (used for) financing activities 709 37 (81 ) (937 ) (272 ) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (5 ) (223 ) (399 ) — (627 ) Nuclear fuel — — (190 ) — (190 ) Proceeds from asset sales 10 3 — — 13 Sales of investment securities held in trusts — — 733 — 733 Purchases of investment securities held in trusts — — (791 ) — (791 ) Cash Investments (10 ) — — — (10 ) Loans to affiliated companies, net (67 ) (372 ) (533 ) 961 (11 ) Other — 4 — — 4 Net cash used for investing activities (72 ) (588 ) (1,180 ) 961 (879 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2014 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (600 ) $ 408 $ 785 $ (22 ) $ 571 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 431 447 — 878 Short-term borrowings, net 247 114 — (361 ) — Equity contribution from parent 500 — — — 500 Redemptions and Repayments- Long-term debt (1 ) (269 ) (568 ) 22 (816 ) Short-term borrowings, net — — (123 ) (178 ) (301 ) Other (1 ) (12 ) (2 ) — (15 ) Net cash provided from (used for) financing activities 745 264 (246 ) (517 ) 246 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (8 ) (169 ) (662 ) — (839 ) Nuclear fuel — — (233 ) — (233 ) Proceeds from asset sales — 307 — — 307 Sales of investment securities held in trusts — — 1,163 — 1,163 Purchases of investment securities held in trusts — — (1,219 ) — (1,219 ) Loans to affiliated companies, net (136 ) (815 ) 412 539 — Other (1 ) 5 — — 4 Net cash used for investing activities (145 ) (672 ) (539 ) 539 (817 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2013 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (1,429 ) $ 753 $ 776 $ (22 ) $ 78 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 864 371 150 (954 ) 431 Equity contribution from parent 1,500 — — — 1,500 Redemptions and Repayments- Long-term debt (770 ) (364 ) (90 ) 22 (1,202 ) Short-term borrowings, net (244 ) (505 ) — 749 — Tender premiums (67 ) — — — (67 ) Other (4 ) (5 ) — — (9 ) Net cash provided from (used for) financing activities 1,279 (503 ) 60 (183 ) 653 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (12 ) (256 ) (449 ) — (717 ) Nuclear fuel — — (250 ) — (250 ) Proceeds from asset sales — 21 — — 21 Sales of investment securities held in trusts — — 940 — 940 Purchases of investment securities held in trusts — — (1,000 ) — (1,000 ) Loans to affiliated companies, net 163 (15 ) (77 ) 205 276 Other (1 ) (1 ) — — (2 ) Net cash provided from (used for) investing activities 150 (251 ) (836 ) 205 (732 ) Net change in cash and cash equivalents — (1 ) — — (1 ) Cash and cash equivalents at beginning of period — 3 — — 3 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission and CES. Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does not have separate reportable operating segments. During the fourth quarter of 2015, management concluded that FEV's 33-1/3% equity investment in Global Holding was no longer a strategic asset to CES. Because of this decision, the segment reporting was modified to reflect how management now views and makes investment decisions regarding CES and Global Holding. The external segment reporting is consistent with the internal financial reports used by FirstEnergy's Chief Executive Officer (its chief operating decision maker) to regularly assess performance of the business and allocate resources. Disclosures for FirstEnergy's reportable operating segments for 2014 and 2013 have been reclassified to conform to the current presentation reflecting the activity of FEV's investment in Global Holding in Corporate/Other. The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes regulated electric generation facilities located primarily in West Virginia, Virginia and New Jersey that MP and JCP&L, respectively, own or contractually control. The segment's results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs. This business segment currently controls 3,790 MWs of generation capacity. The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, and certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP). This segment also includes the regulatory asset associated with the abandoned PATH project. The segment's revenues are primarily derived from rates that recover costs and provide a return on transmission capital investment. Except for the recovery of the PATH abandoned project regulatory asset, these revenues are primarily from transmission services provided pursuant to its PJM Tariff to LSEs. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities. The CES segment, through FES and AE Supply, primarily supplies electricity to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. This business segment currently controls 13,162 MWs of capacity. The CES segment’s net income is primarily derived from electric generation sales less the related costs of electricity generation, including fuel, purchased power and net transmission (including congestion) and ancillary costs and capacity costs charged by PJM to deliver energy to the segment’s customers. Corporate support and other businesses that do not constitute an operating segment, interest expense on stand-alone holding company debt and corporate income taxes are categorized as Corporate/Other for reportable business segment purposes. Additionally, reconciling adjustments for the elimination of inter-segment transactions are included in Corporate/Other. As of December 31, 2015, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of which 28% was subject to variable-interest rates and $1.7 billion was borrowed under the FE revolving credit facility. Segment Financial Information For the Years Ended December 31, Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Reconciling Adjustments Consolidated (In millions) 2015 External revenues $ 9,625 $ 1,011 $ 4,698 $ (168 ) $ (140 ) $ 15,026 Internal revenues — — 686 — (686 ) — Total revenues 9,625 1,011 5,384 (168 ) (826 ) 15,026 Depreciation 672 156 394 60 — 1,282 Amortization of regulatory assets, net 261 7 — — — 268 Impairment of long-lived assets 8 — 34 — — 42 Investment income (loss) 42 — (16 ) (9 ) (39 ) (22 ) Impairment of equity method investment — — — 362 — 362 Interest expense 586 161 192 193 — 1,132 Income taxes (benefits) 342 174 50 (262 ) 11 315 Income (loss) from continuing operations 618 298 89 (427 ) — 578 Discontinued operations, net of tax — — — — — — Net income (loss) 618 298 89 (427 ) — 578 Total assets 27,876 7,439 16,365 507 — 52,187 Total goodwill 5,092 526 800 — — 6,418 Property additions 1,108 952 588 56 — 2,704 2014 External revenues $ 9,102 $ 769 $ 5,470 $ (146 ) $ (146 ) $ 15,049 Internal revenues — — 819 — (819 ) — Total revenues 9,102 769 6,289 (146 ) (965 ) 15,049 Depreciation 658 127 387 48 — 1,220 Amortization of regulatory assets, net 1 11 — — — 12 Impairment of long-lived assets — — — — — — Investment income (loss) 56 — 54 2 (40 ) 72 Impairment of equity method investment — — — — — — Interest expense 589 131 189 168 (4 ) 1,073 Income taxes (benefits) 227 121 (223 ) (178 ) 11 (42 ) Income (loss) from continuing operations 465 223 (417 ) (58 ) — 213 Discontinued operations, net of tax — — 86 — — 86 Net income (loss) 465 223 (331 ) (58 ) — 299 Total assets 28,085 6,252 16,518 793 — 51,648 Total goodwill 5,092 526 800 — — 6,418 Property additions 972 1,329 939 72 — 3,312 2013 External revenues $ 8,720 $ 731 $ 5,728 $ (121 ) $ (166 ) $ 14,892 Internal revenues — — 770 — (770 ) — Total revenues 8,720 731 6,498 (121 ) (936 ) 14,892 Depreciation 606 114 439 43 — 1,202 Amortization of regulatory assets, net 529 10 — — — 539 Impairment of long-lived assets 322 — 473 — — 795 Investment income (loss) 57 — 14 6 (44 ) 33 Impairment of equity method investment — — — — — — Interest expense 543 93 222 148 10 1,016 Income taxes (benefits) 301 129 (140 ) (105 ) 10 195 Income (loss) from continuing operations 501 214 (235 ) (105 ) — 375 Discontinued operations, net of tax — — 17 — — 17 Net income (loss) 501 214 (218 ) (105 ) — 392 Total assets 27,683 5,247 16,782 712 — 50,424 Total goodwill 5,092 526 800 — — 6,418 Property additions 1,272 461 827 78 — 2,638

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	DISCONTINUED OPERATIONS On February 12, 2014, certain of FirstEnergy's subsidiaries sold eleven hydroelectric power stations to a subsidiary of LS Power for approximately $ 394 million (FES - $ 307 million ). The carrying value of the assets sold was $ 235 million (FES - $ 122 million ), including goodwill of $29 million (FES - $1 million ). Pre-tax income for the hydroelectric facilities of $ 155 million and $ 26 million (FES - $ 186 million and $ 22 million ) for the years ended December 31, 2014 and 2013, respectively, was included in discontinued operations in the Consolidated Statement of Income. Included in income for discontinued operations in the year ended December 31, 2014, was a pre-tax gain on the sale of assets of $ 142 million (FES - $ 177 million ). Revenues for the hydroelectric facilities of $ 5 million and $ 33 million (FES - $5 million and $ 31 million ) for years ended December 31, 2014 and 2013, respectively, were included in discontinued operations in the Consolidated Statement of Income.

Summary of Quarterly Financial

Summary of Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Data [Abstract]
SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)	SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED) The following summarizes certain consolidated operating results by quarter for 2015 and 2014 . FirstEnergy CONSOLIDATED STATEMENTS OF INCOME (In millions, except per share amounts) 2015 2014 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Revenues $ 3,541 $ 4,123 $ 3,465 $ 3,897 $ 3,483 $ 3,888 $ 3,496 $ 4,182 Other operating expense 952 850 916 1,057 901 858 1,021 1,182 Pension and OPEB mark-to-market adjustment 242 — — — 835 — — — Provision for depreciation 313 328 322 319 316 308 302 294 Operating Income (Loss) 236 908 554 594 (337 ) 716 292 391 Income (loss) from continuing operations before income taxes (benefits) (396 ) 621 302 366 (574 ) 485 90 170 Income taxes (benefits) (1) (170 ) 226 115 144 (268 ) 152 26 48 Income (loss) from continuing operations (226 ) 395 187 222 (306 ) 333 64 122 Discontinued operations (net of income taxes) — — — — — — — 86 Net Income (Loss) (226 ) 395 187 222 (306 ) 333 64 208 Earnings (loss) per share of common stock- (2) Basic - Continuing Operations (0.53 ) 0.94 0.44 0.53 (0.73 ) 0.79 0.16 0.29 Basic - Discontinued Operations (Note 19) — — — — — — — 0.21 Basic - Earnings Available to FirstEnergy Corp. (0.53 ) 0.94 0.44 0.53 (0.73 ) 0.79 0.16 0.50 Diluted - Continuing Operations (0.53 ) 0.93 0.44 0.53 (0.73 ) 0.79 0.15 0.29 Diluted - Discontinued Operations (Note 19) — — — — — — — 0.20 Diluted - Earnings Available to FirstEnergy Corp. (0.53 ) 0.93 0.44 0.53 (0.73 ) 0.79 0.15 0.49 (1) - During the fourth quarter of 2014, income tax benefits of $16 million were recorded that related to prior periods. The out-of-period adjustment primarily related to the correction of amounts included in the Company’s tax basis balance sheet. Management determined that this adjustment was not material to 2014 or any prior period. (2) - Total quarterly earnings per share information may not equal annual earnings per share due to the issuance of shares throughout the year. See FirstEnergy's Consolidated Statements of Stockholders' Equity and Note 4. Stock-Based Compensation for additional information. FES CONSOLIDATED STATEMENTS OF INCOME (In millions) 2015 2014 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Revenues $ 1,171 $ 1,338 $ 1,119 $ 1,377 $ 1,342 $ 1,521 $ 1,452 $ 1,829 Other operating expense 329 246 353 413 359 356 468 452 Pension and OPEB mark-to-market adjustment 57 — — — 297 — — — Provision for depreciation 84 79 81 80 83 83 79 74 Operating Income (Loss) 25 240 — 12 (321 ) 90 (151 ) (148 ) Income (loss) from continuing operations before income taxes (benefits) (13 ) 190 (25 ) (5 ) (347 ) 72 (154 ) (159 ) Income taxes (benefits) 1 70 (4 ) (2 ) (133 ) 28 (67 ) (56 ) Income (loss) from continuing operations (14 ) 120 (21 ) (3 ) (214 ) 44 (87 ) (103 ) Discontinued operations (net of income taxes) — — — — — — — 116 Net Income (Loss) (14 ) 120 (21 ) (3 ) (214 ) 44 (87 ) 13

Consolidated Valuation and Qual

Consolidated Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2015
Valuation and Qualifying Accounts Disclosure [Line Items]
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS	FIRSTENERGY CORP. CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2015 , 2014 AND 2013 Additions Description Beginning Balance Charged to Income Charged to Other Accounts (1) Deductions (2) Ending Balance (In thousands) Year Ended December 31, 2015: Accumulated provision for uncollectible accounts — customers $ 59,266 $ 114,249 $ 54,199 $ 158,939 $ 68,775 — other $ 5,197 $ 899 $ 4,189 $ 5,054 $ 5,231 Loss carryforward tax valuation reserve $ 174,004 $ 18,393 $ — $ — $ 192,397 Year Ended December 31, 2014: Accumulated provision for uncollectible accounts — customers $ 51,630 $ 90,144 $ 36,373 $ 118,881 $ 59,266 — other $ 2,976 $ 3,469 $ 8,264 $ 9,512 $ 5,197 Loss carryforward tax valuation reserve $ 125,360 $ 48,644 $ — $ — $ 174,004 Year Ended December 31, 2013: Accumulated provision for uncollectible accounts — customers $ 40,354 $ 68,733 $ 39,775 $ 97,232 $ 51,630 — other $ 4,013 $ (1,464 ) $ 5,208 $ 4,781 $ 2,976 Loss carryforward tax valuation reserve $ 101,697 $ 23,663 $ — $ — $ 125,360 (1) Represents recoveries and reinstatements of accounts previously written off. (2) Represents the write-off of accounts considered to be uncollectible.
FES
Valuation and Qualifying Accounts Disclosure [Line Items]
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS	FIRSTENERGY SOLUTIONS CORP. CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2015 , 2014 AND 2013 Additions Description Beginning Balance Charged to Income Charged to Other Accounts (1) Deductions (2) Ending Balance (In thousands) Year Ended December 31, 2015: Accumulated provision for uncollectible accounts — customers $ 17,862 $ 7,411 $ — $ 16,807 $ 8,466 — other $ 2,500 $ — $ — $ — $ 2,500 Loss carryforward tax valuation reserve $ 32,126 $ 13,682 $ — $ — $ 45,808 Year Ended December 31, 2014: Accumulated provision for uncollectible accounts — customers $ 11,073 $ 21,942 $ — $ 15,153 $ 17,862 — other $ 2,523 $ 9 $ — $ 32 $ 2,500 Loss carryforward tax valuation reserve $ 26,875 $ 5,251 $ — $ — $ 32,126 Year Ended December 31, 2013: Accumulated provision for uncollectible accounts — customers $ 16,188 $ 14,294 $ — $ 19,409 $ 11,073 — other $ 2,500 $ 28 $ — $ 5 $ 2,523 Loss carryforward tax valuation reserve $ 15,810 $ 11,065 $ — $ — $ 26,875 (1) Represents recoveries and reinstatements of accounts previously written off. (2) Represents the write-off of accounts considered to be uncollectible.

Organization and Basis of Prese

Organization and Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Derivatives, Policy [Policy Text Block]	FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance.
Fair Value Measurement, Policy [Policy Text Block]	Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows: Level 1 - Quoted prices for identical instruments in active market Level 2 - Quoted prices for similar instruments in active market - Quoted prices for identical or similar instruments in markets that are not active - Model-derived valuations for which all significant inputs are observable market data Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 - Valuation inputs are unobservable and significant to the fair value measurement FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast, which has been reviewed and approved by FirstEnergy's Risk Policy Committee, are used to measure fair value. A more detailed description of FirstEnergy's valuation processes for FTRs and NUGs are as follows: FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term RTO auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent RTO auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 10, Derivative Instruments, for additional information regarding FirstEnergy's FTRs. NUG contracts represent purchase power agreements with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWHs. Pricing for the NUG contracts is a combination of market prices for the current year and next three years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on ICE quotes and management assumptions. Generation MWHs reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWHs. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs.
Income Tax, Policy [Policy Text Block]	FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. FES and the Utilities are party to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, are reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit.
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]	Shares used under the ICP 2007 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods range from one to ten years , with the majority of awards having a vesting period of three years . FirstEnergy also issues stock through its 401(k) Savings Plan, EDCP, and DCPD. FirstEnergy records the compensation costs for stock-based compensation awards that will be paid in stock over the vesting period based on the fair value on the grant date, less estimated forfeitures. FirstEnergy adjusts the compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or settled
Basis of Accounting	FirstEnergy follows GAAP and complies with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued.
Consolidation	FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 8, Variable Interest Entities). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but with respect to which they are not the primary beneficiary and do not exercise control, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income. These Notes to the Consolidated Financial Statements are combined for FirstEnergy and FES.
Accounting for the Effects of Regulation	ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities, AGC, ATSI, PATH and TrAIL since their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be charged to and collected from customers. FirstEnergy records regulatory assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These assets and liabilities are amortized in the Consolidated Statements of Income concurrent with the recovery or refund through customer rates. FirstEnergy believes that it is probable that its regulatory assets and liabilities will be recovered and settled, respectively, through future rates. FirstEnergy and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions.
Revenues and Receivables	REVENUES AND RECEIVABLES The Utilities' principal business is providing electric service to customers in Ohio, Pennsylvania, West Virginia, New Jersey and Maryland. FES' principal business is supplying electric power to end-use customers through retail and wholesale arrangements, including affiliated company power sales to meet a portion of the POLR and default service requirements, and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland. Retail customers are metered on a cycle basis. Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, FirstEnergy accrues the estimated unbilled amount as revenue and reverses the related prior period estimate. Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers for the Utilities, and retail and wholesale sales to customers for FES.
Earnings Per Share of Common Stock	EARNINGS PER SHARE OF COMMON STOCK Basic earnings per share of common stock are computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised.
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred. The cost of nuclear fuel is capitalized within the CES segment's Property, plant and equipment and charged to fuel expense using the specific identification method.
Asset Retirement Obligations	Asset Retirement Obligations FE recognizes an ARO for the future decommissioning of its nuclear power plants and future remediation of other environmental liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FE's current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FE uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plant's current license, settlement based on an extended license term and expected remediation dates. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition. AROs as of December 31, 2015 , are described further in Note 13, Asset Retirement Obligations.
Asset Impairments	ASSET IMPAIRMENTS Long-lived Assets FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, an impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. FirstEnergy utilizes the income approach, based upon discounted cash flows to estimate fair value.
Goodwill	Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated Transmission, and CES.
Investments	Investments At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy first considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value.
Inventory	INVENTORY Materials and supplies inventory includes fuel inventory and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory. Materials are generally charged to inventory at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed. Fuel inventory is accounted for at weighted average cost when purchased, and recorded to fuel expense when consumed.
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS In May 2014, the FASB issued, ASU 2014-09 "Revenue from Contracts with Customers", requiring entities to recognize revenue by applying a five-step model in accordance with the core principle to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue recognition are expanded.
Pension and Other Postretirement Plans	PENSION AND OTHER POSTEMPLOYMENT BENEFITS FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits. In 2014, the qualified pension plan was amended authorizing a voluntary cashout window program for certain eligible terminated participants with vested benefits. Payment of benefits for participants that elected an immediate lump sum cash payment or an annuity resulted in a $40 million reduction to the underfunded status of the pension plan. Additionally, during 2015 and 2014, certain unions ratified their labor agreements that ended subsidized retiree health care resulting in a reduction to the OPEB benefit obligation by approximately $10 million and $97 million , respectively. FirstEnergy recognizes as a pension and OPEB mark-to-market adjustment the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The remaining components of pension and OPEB expense, primarily service costs, interest on obligations, assumed return on assets and prior service costs, are recorded on a monthly basis. The pension and OPEB mark-to-market adjustment for the years ended December 31, 2015, 2014, and 2013 were $369 million ( $242 million net of amounts capitalized), $1,243 million ( $835 million net of amounts capitalized), and $(396) million ( $(256) million net of amounts capitalized), respectively. In 2015, the pension and OPEB mark-to-market adjustment primarily reflects lower than expected asset returns as well as the impact of other demographic assumptions, including revisions to mortality assumptions, partially offset by a 25 basis point increase in the discount rate. FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method.
Variable Interest Entities	VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. The caption "noncontrolling interest" within the consolidated financial statements is used to reflect the portion of a VIE that FirstEnergy consolidates, but does not own. In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance.
Reclassifications	Certain prior year amounts have been reclassified to conform to the current year presentation.

Organization and Basis of Pre39

Organization and Basis of Presentation (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Regulatory assets on the Balance Sheets	The following table provides information about the composition of net regulatory assets as of December 31, 2015 and December 31, 2014 , and the changes during the year ended December 31, 2015 : Regulatory Assets by Source December 31, December 31, Increase (Decrease) (In millions) Regulatory transition costs $ 185 $ 240 $ (55 ) Customer receivables for future income taxes 355 370 (15 ) Nuclear decommissioning and spent fuel disposal costs (272 ) (305 ) 33 Asset removal costs (372 ) (254 ) (118 ) Deferred transmission costs 115 90 25 Deferred generation costs 243 281 (38 ) Deferred distribution costs 335 182 153 Contract valuations 186 153 33 Storm-related costs 403 465 (62 ) Other 170 189 (19 ) Net Regulatory Assets included on the Consolidated Balance Sheets $ 1,348 $ 1,411 $ (63 )
Receivables from customers	Billed and unbilled customer receivables as of December 31, 2015 and 2014 are included below. Customer Receivables FirstEnergy FES (In millions) December 31, 2015 Billed $ 836 $ 165 Unbilled 579 110 Total $ 1,415 $ 275 December 31, 2014 Billed $ 914 $ 239 Unbilled 640 176 Total $ 1,554 $ 415
Reconciliation of basic and diluted earnings per share	The following table reconciles basic and diluted earnings per share of common stock: Reconciliation of Basic and Diluted Earnings per Share of Common Stock 2015 2014 2013 (In millions, except per share amounts) Income from continuing operations available to common shareholders $ 578 $ 213 $ 375 Discontinued operations (Note 19) — 86 17 Net income $ 578 $ 299 $ 392 Weighted average number of basic shares outstanding 422 420 418 Assumed exercise of dilutive stock options and awards (1) 2 1 1 Weighted average number of diluted shares outstanding 424 421 419 Earnings per share: Basic earnings per share: Continuing operations $ 1.37 $ 0.51 $ 0.90 Discontinued operations (Note 19) — 0.20 0.04 Earnings per basic share $ 1.37 $ 0.71 $ 0.94 Diluted earnings per share: Continuing operations $ 1.37 $ 0.51 $ 0.90 Discontinued operations (Note 19) — 0.20 0.04 Earnings per diluted share $ 1.37 $ 0.71 $ 0.94 (1) For the years ended December 31, 2015 , 2014 and 2013, approximately one million , two million , and two million shares were excluded from the calculation of diluted shares outstanding, respectively, as their inclusion would be antidilutive.
Property, plant and equipment balances	Net plant in service balances by segment as of December 31, 2015 and 2014 were as follows: December 31, 2015 December 31, 2014 Property, Plant and Equipment In Service (2) Accum. Depr. Net Plant In Service (2) Accum. Depr. Net Plant (In millions) Regulated Distribution $ 24,553 $ (7,058 ) $ 17,495 $ 23,973 $ (6,759 ) $ 17,214 Regulated Transmission 7,703 (1,647 ) 6,056 6,634 (1,595 ) 5,039 Competitive Energy Services (1) 17,214 (6,213 ) 11,001 16,442 (5,598 ) 10,844 Corporate/Other 482 (242 ) 240 435 (198 ) 237 Total $ 49,952 $ (15,160 ) $ 34,792 $ 47,484 $ (14,150 ) $ 33,334 (1) Primarily consists of generating assets and nuclear fuel as discussed above. (2) Includes capital leases of $253 million and $281 million at December 31, 2015 and 2014, respectively.
Annual composite rates	The respective annual composite rates for FirstEnergy's and FES' electric plant in 2015 , 2014 and 2013 are shown in the following table: Annual Composite Depreciation Rate 2015 2014 2013 FirstEnergy 2.5 % 2.5 % 2.6 % FES 3.2 % 3.1 % 3.1 %
Summary of changes in goodwill	The following table presents goodwill by reporting unit: Goodwill Regulated Distribution Regulated Transmission Competitive Energy Services Consolidated (In millions) Balance as of December 31, 2015 $ 5,092 $ 526 $ 800 $ 6,418

Accumulated Other Comprehensi40

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Schedule of Accumulated Other Comprehensive Income	The changes in AOCI for the years ended December 31, 2015 , 2014 and 2013 for FirstEnergy are shown in the following table: FirstEnergy Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2013 $ (38 ) $ 15 $ 408 $ 385 Other comprehensive income before reclassifications — 46 35 81 Amounts reclassified from AOCI 3 (56 ) (195 ) (248 ) Other comprehensive income (loss) 3 (10 ) (160 ) (167 ) Income tax (benefits) on other comprehensive income (loss) 1 (4 ) (63 ) (66 ) Other comprehensive income (loss), net of tax 2 (6 ) (97 ) (101 ) AOCI Balance, December 31, 2013 $ (36 ) $ 9 $ 311 $ 284 Other comprehensive income before reclassifications — 89 92 181 Amounts reclassified from AOCI (2 ) (63 ) (168 ) (233 ) Other comprehensive income (loss) (2 ) 26 (76 ) (52 ) Income tax (benefits) on other comprehensive income (loss) (1 ) 10 (23 ) (14 ) Other comprehensive income (loss), net of tax (1 ) 16 (53 ) (38 ) AOCI Balance, December 31, 2014 $ (37 ) $ 25 $ 258 $ 246 Other comprehensive income before reclassifications — 14 10 24 Amounts reclassified from AOCI 5 (25 ) (126 ) (146 ) Other comprehensive income (loss) 5 (11 ) (116 ) (122 ) Income tax (benefits) on other comprehensive income (loss) 1 (4 ) (44 ) (47 ) Other comprehensive income (loss), net of tax 4 (7 ) (72 ) (75 ) AOCI Balance, December 31, 2015 $ (33 ) $ 18 $ 186 $ 171 The changes in AOCI for the years ended December 31, 2015 , 2014 and 2013 for FES are shown in the following table: FES Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2013 $ 3 $ 13 $ 56 $ 72 Other comprehensive income before reclassifications — 41 5 46 Amounts reclassified from AOCI (6 ) (49 ) (20 ) (75 ) Other comprehensive loss (6 ) (8 ) (15 ) (29 ) Income tax benefits on other comprehensive loss (2 ) (3 ) (6 ) (11 ) Other comprehensive loss, net of tax (4 ) (5 ) (9 ) (18 ) AOCI Balance, December 31, 2013 $ (1 ) $ 8 $ 47 $ 54 Other comprehensive income before reclassifications — 80 13 93 Amounts reclassified from AOCI (10 ) (59 ) (19 ) (88 ) Other comprehensive income (loss) (10 ) 21 (6 ) 5 Income tax (benefits) on other comprehensive income (loss) (4 ) 8 (2 ) 2 Other comprehensive income (loss), net of tax (6 ) 13 (4 ) 3 AOCI Balance, December 31, 2014 $ (7 ) $ 21 $ 43 $ 57 Other comprehensive income before reclassifications — 15 10 25 Amounts reclassified from AOCI (3 ) (24 ) (16 ) (43 ) Other comprehensive loss (3 ) (9 ) (6 ) (18 ) Income tax benefits on other comprehensive loss (1 ) (4 ) (2 ) (7 ) Other comprehensive loss, net of tax (2 ) (5 ) (4 ) (11 ) AOCI Balance, December 31, 2015 $ (9 ) $ 16 $ 39 $ 46
Reclassification out of Accumulated Other Comprehensive Income	The following amounts were reclassified from AOCI for FES in the years ended December 31, 2015 , 2014 and 2013 : FES Year Ended December 31, Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (2) 2015 2014 2013 (In millions) Gains & losses on cash flow hedges Commodity contracts $ (3 ) $ (10 ) $ (8 ) Other operating expenses Long-term debt — — 2 Interest expense - other (3 ) (10 ) (6 ) Total before taxes 1 4 2 Income taxes (benefits) $ (2 ) $ (6 ) $ (4 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (24 ) $ (59 ) $ (49 ) Investment income (loss) 9 22 18 Income taxes (benefits) $ (15 ) $ (37 ) $ (31 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (16 ) $ (19 ) $ (20 ) (1) 6 7 8 Income taxes (benefits) $ (10 ) $ (12 ) $ (12 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details. (2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI. The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2015 , 2014 and 2013 : FirstEnergy Year Ended December 31, Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (2) 2015 2014 2013 (In millions) Gains & losses on cash flow hedges Commodity contracts $ (3 ) $ (10 ) $ (8 ) Other operating expenses Long-term debt 8 8 11 Interest expense 5 (2 ) 3 Total before taxes (1 ) 1 (1 ) Income taxes (benefits) $ 4 $ (1 ) $ 2 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (25 ) $ (63 ) $ (56 ) Investment income (loss) 9 24 21 Income taxes (benefits) $ (16 ) $ (39 ) $ (35 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (126 ) $ (168 ) $ (195 ) (1) 49 65 75 Income taxes (benefits) $ (77 ) $ (103 ) $ (120 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details. (2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

Pension and Other Postemploym41

Pension and Other Postemployment Benefits (Tables)	12 Months Ended
	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Obligations and Funded Status	Pension OPEB Obligations and Funded Status 2015 2014 2015 2014 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 9,249 $ 8,263 $ 757 $ 879 Service cost 193 167 5 9 Interest cost 383 402 29 39 Plan participants’ contributions — — 6 16 Plan amendments — 5 (10 ) (97 ) Medicare retiree drug subsidy — — 1 — Actuarial (gain) loss (277 ) 1,123 (2 ) 13 Benefits paid (469 ) (711 ) (62 ) (102 ) Benefit obligation as of December 31 $ 9,079 $ 9,249 $ 724 $ 757 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 5,824 $ 6,171 $ 464 $ 495 Actual return (losses) on plan assets (178 ) 349 6 38 Company contributions 161 15 17 17 Plan participants’ contributions — — 6 16 Benefits paid (469 ) (711 ) (62 ) (102 ) Fair value of plan assets as of December 31 $ 5,338 $ 5,824 $ 431 $ 464 Funded Status: Qualified plan $ (3,366 ) $ (3,064 ) Non-qualified plans (375 ) (361 ) Funded Status $ (3,741 ) $ (3,425 ) $ (293 ) $ (293 ) Accumulated benefit obligation $ 8,579 $ 8,744 $ — $ — Amounts Recognized on the Balance Sheet: Current liabilities $ (18 ) $ (17 ) $ — $ — Noncurrent liabilities (3,723 ) (3,408 ) (293 ) (293 ) Net liability as of December 31 $ (3,741 ) $ (3,425 ) $ (293 ) $ (293 ) Amounts Recognized in AOCI: Prior service cost (credit) $ 37 $ 45 $ (355 ) $ (479 ) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate 4.50 % 4.25 % 4.25 % 4.00 % Rate of compensation increase 4.20 % 4.20 % N/A N/A Assumed Health Care Cost Trend Rates (as of December 31) Health care cost trend rate assumed (pre/post-Medicare) N/A N/A 6.0-5.5% 7.5-7.0% Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) N/A N/A 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate N/A N/A 2026 2026 Allocation of Plan Assets (as of December 31) Equity securities 40 % 36 % 51 % 49 % Bonds 34 % 33 % 43 % 40 % Absolute return strategies 7 % 14 % — % 1 % Real estate 11 % 7 % — % 1 % Derivatives — % 1 % — % — % Cash and short-term securities 8 % 9 % 6 % 9 % Total 100 % 100 % 100 % 100 %
Components of Net Periodic Benefit Costs	Pension OPEB Components of Net Periodic Benefit Costs 2015 2014 2013 2015 2014 2013 (In millions) Service cost $ 193 $ 167 $ 197 $ 5 $ 9 $ 13 Interest cost 383 402 372 29 39 37 Expected return on plan assets (443 ) (462 ) (501 ) (33 ) (34 ) (34 ) Amortization of prior service cost (credit) 8 8 12 (134 ) (176 ) (207 ) Pension & OPEB mark-to-market adjustment 344 1,235 (267 ) 25 8 (129 ) Net periodic cost (credit) $ 485 $ 1,350 $ (187 ) $ (108 ) $ (154 ) $ (320 )
Assumptions Used to Determine Net Periodic Benefit Cost	Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Pension OPEB 2015 2014 2013 2015 2014 2013 Weighted-average discount rate 4.25 % 5.00 % 4.25 % 4.00 % 4.75 % 4.00 % Expected long-term return on plan assets 7.75 % 7.75 % 7.75 % 7.75 % 7.75 % 7.75 % Rate of compensation increase 4.20 % 4.20 % 4.70 % N/A N/A N/A
Target asset allocations for pension and OPEB portfolio	FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2015 and 2014 are shown in the following table: Target Asset Allocations 2015 2014 Equities 38 % 42 % Fixed income 30 % 32 % Absolute return strategies 8 % 14 % Real estate 10 % 5 % Alternative investments 8 % 1 % Cash 6 % 6 % 100 % 100 %
Effect of One-Percentage Point change in assumed health care cost trend rates	Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects: 1-Percentage-Point Increase 1-Percentage-Point Decrease (In millions) Effect on total of service and interest cost $ 1 $ (1 ) Effect on accumulated benefit obligation $ 26 $ (23 )
Estimated Future Benefit Payments	Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contributions: OPEB Pension Benefit Payments Subsidy Receipts (In millions) 2016 $ 484 $ 54 $ (3 ) 2017 505 54 (3 ) 2018 522 54 (3 ) 2019 533 54 (3 ) 2020 551 54 (3 ) Years 2021-2025 2,946 259 (9 )
Net Pension and OPEB Asset (Liability)	FES’ share of the pension and OPEB net (liability) asset as of December 31, 2015 and 2014 , was as follows: Pension OPEB 2015 2014 2015 2014 (In millions) Net (Liability) Asset $ (303 ) $ (295 ) $ 25 $ 10
Net Periodic Pension and OPEB Costs	FES’ share of the net periodic benefit cost (credit), including the pension and OPEB mark-to-market adjustment, for the three years ended December 31, 2015 was as follows: Pension OPEB 2015 2014 2013 2015 2014 2013 (In millions) Net Periodic Cost (Credit) $ 10 $ 150 $ (30 ) $ (22 ) $ (24 ) $ (40 )
Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 9, Fair Value Measurements, for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2015 and 2014 . December 31, 2015 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 427 $ — $ 427 8 % Equity investments Domestic 869 75 — 944 18 % International 395 794 — 1,189 22 % Fixed income Government bonds — 232 — 232 4 % Corporate bonds — 1,115 — 1,115 21 % High yield debt — 438 — 438 8 % Mortgage-backed securities (non-government) — 31 — 31 1 % Alternatives Hedge funds (Absolute return) — 343 — 343 7 % Derivatives — 15 — 15 — % Private equity funds — — 24 24 — % Real estate funds — — 587 587 11 % Total (1) $ 1,264 $ 3,470 $ 611 $ 5,345 100 % (1) Excludes $(7) million as of December 31, 2015 of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. December 31, 2014 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 517 $ — $ 517 9 % Equity investments Domestic 1,266 8 — 1,274 22 % International 355 414 — 769 14 % Fixed income Government bonds — 159 — 159 3 % Corporate bonds — 1,386 — 1,386 24 % High yield debt — 300 — 300 5 % Mortgage-backed securities (non-government) — 37 — 37 1 % Alternatives Hedge funds (Absolute return) — 809 — 809 14 % Derivatives — 35 — 35 1 % Private equity funds — — 25 25 — % Real estate funds — — 421 421 7 % Total (1) $ 1,621 $ 3,665 $ 446 $ 5,732 100 % (1) Excludes $92 million as of December 31, 2014 of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
Reconciliation of changes in the fair value of pension investments	The following table provides a reconciliation of changes in the fair value of pension investments classified as Level 3 in the fair value hierarchy during 2015 and 2014 : Private Equity Funds Real Estate Funds (In millions) Balance as of January 1, 2014 $ 27 $ 385 Actual return on plan assets: Unrealized gains (losses) (2 ) 17 Realized gains 1 14 Transfers in (out) (1 ) 5 Balance as of December 31, 2014 $ 25 $ 421 Actual return on plan assets: Unrealized gains — 42 Realized gains (losses) (1 ) 16 Transfers in — 108 Balance as of December 31, 2015 $ 24 $ 587
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	As of December 31, 2015 and 2014 , the OPEB trust investments measured at fair value were as follows: December 31, 2015 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 25 $ — $ 25 6 % Equity investment Domestic 219 — — 219 50 % International 1 3 — 4 1 % Fixed income U.S. treasuries — 42 — 42 10 % Government bonds — 114 — 114 26 % Corporate bonds — 27 — 27 6 % High yield debt — 1 — 1 — % Mortgage-backed securities (non-government) — 3 — 3 1 % Alternatives Hedge funds — 1 — 1 — % Real estate funds — — 2 2 — % Total (1) $ 220 $ 216 $ 2 $ 438 100 % (1) Excludes $(7) million as of December 31, 2015 of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. December 31, 2014 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 41 $ — $ 41 9 % Equity investment Domestic 230 — — 230 48 % International 3 3 — 6 1 % Fixed income U.S. treasuries — 41 — 41 9 % Government bonds — 110 — 110 23 % Corporate bonds — 32 — 32 7 % High yield debt — 2 — 2 — % Mortgage-backed securities (non-government) — 3 — 3 1 % Alternatives Hedge funds — 5 — 5 1 % Real estate funds — — 3 3 1 % Total (1) $ 233 $ 237 $ 3 $ 473 100 % (1) Excludes $(9) million as of December 31, 2014 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
Reconciliation of changes in the fair value of pension investments	The following table provides a reconciliation of changes in the fair value of OPEB trust investments classified as Level 3 in the fair value hierarchy during 2015 and 2014 : Real Estate Funds Balance as of January 1, 2014 $ 5 Transfers out (2 ) Balance as of December 31, 2014 $ 3 Transfers out (1 ) Balance as of December 31, 2015 $ 2

Stock-Based Compensation Plans

Stock-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Stock-based Compensation Expense	Stock-based compensation costs and the amount of stock-based compensation expense capitalized related to FirstEnergy and FES plans are included in the following tables: FirstEnergy Years ended December 31, Stock-based Compensation Plan 2015 2014 2013 (In millions) Restricted Stock Units $ 46 $ 26 $ 36 Restricted Stock 2 5 6 Performance Shares — 5 (10 ) 401(k) Savings Plan 38 25 25 EDCP & DCPD 3 8 3 Total $ 89 $ 69 $ 60 Stock-based compensation costs capitalized $ 32 $ 23 $ 20 FES Years ended December 31, Stock-based Compensation Plan 2015 2014 2013 (In millions) Restricted Stock Units $ 6 $ 4 $ 6 Performance Shares — 1 (1 ) 401(k) Savings Plan 5 4 4 Total $ 11 $ 9 $ 9 Stock-based compensation costs capitalized $ 1 $ 1 $ 1
Schedule of Nonvested Restricted Stock Units Activity	Restricted stock unit activity for the year ended December 31, 2015, was as follows: Restricted Stock Unit Activity Shares Weighted-Average Grant Date Fair Value Nonvested as of January 1, 2015 2,069,518 $ 37.65 Granted in 2015 1,157,755 35.27 Forfeited in 2015 (231,271 ) 34.19 Vested in 2015 (1) (559,114 ) 44.58 Nonvested as of December 31, 2015 2,436,888 $ 35.26 (1 ) Excludes dividend equivalents of 89,681 earned during vesting period
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Stock Option Activity	Restricted common stock (restricted stock) activity for the year ended December 31, 2015, was as follows: Restricted Stock Number of Shares Weighted Average Grant-Date Fair Value Nonvested as of January 1, 2015 342,286 $ 45.29 Granted in 2015 65,434 32.98 Forfeited in 2015 (26,079 ) 57.58 Vested in 2015 (1) (190,985 ) 43.17 Nonvested as of December 31, 2015 190,656 $ 40.65 (1 ) Excludes 52,872 shares for dividends earned during vesting period
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Stock Option Activity	There were no stock options granted in 2015. Stock option activity during 2015 was as follows: Stock Option Activity Number of Shares Weighted Average Exercise Price Balance, January 1, 2015 (1,077,988 options exercisable) 1,439,145 $ 44.83 Options exercised (18,551 ) 29.53 Options forfeited (8,623 ) 68.02 Balance, December 31, 2015 (1,211,358 options exercisable) 1,411,971 $ 44.89

Taxes (Tables)

Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Taxes [Abstract]
Provision for income taxes (benefits)	INCOME TAXES (BENEFITS) (1) 2015 2014 2013 (In millions) FirstEnergy Currently payable (receivable)- Federal $ 1 $ (132 ) $ (118 ) State 30 (72 ) 70 31 (204 ) (48 ) Deferred, net- Federal 277 214 305 State 15 (42 ) (54 ) 292 172 251 Investment tax credit amortization (8 ) (10 ) (8 ) Total provision for income taxes (benefits) $ 315 $ (42 ) $ 195 FES Currently payable (receivable)- Federal $ (56 ) $ (222 ) $ (300 ) State 2 (13 ) (3 ) (54 ) (235 ) (303 ) Deferred, net- Federal 103 25 317 State 18 (14 ) (4 ) 121 11 313 Investment tax credit amortization (2 ) (4 ) (4 ) Total provision for income taxes (benefits) $ 65 $ (228 ) $ 6 (1) Provision for Income Taxes (Benefits) on Income from Continuing Operations. Currently payable (receivable) in 2014 excludes $106 million and $12 million of federal and state taxes, respectively, associated with discontinued operations. Deferred, net in 2014 excludes $44 million and $5 million of federal and state tax benefits, respectively, associated with discontinued operations.
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes	The following tables provide a reconciliation of federal income tax expense at the federal statutory rate to the total income taxes on continuing operations for the three years ended December 31: 2015 2014 2013 (In millions) FirstEnergy Income from Continuing Operations before income taxes $ 893 $ 171 $ 570 Federal income tax expense at statutory rate (35%) $ 313 $ 60 $ 199 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit 34 12 10 AFUDC equity and other flow-through (16 ) (13 ) (7 ) Amortization of investment tax credits (8 ) (10 ) (8 ) Change in accounting method (8 ) (27 ) — ESOP dividend (6 ) (6 ) (9 ) Tax basis balance sheet adjustments — (25 ) — Uncertain tax positions 1 (35 ) (2 ) Other, net 5 2 12 Total income taxes (benefits) $ 315 $ (42 ) $ 195 Effective income tax rate 35.3 % (24.6 )% 34.2 % FES Income (loss) from Continuing Operations before income taxes (benefits) $ 147 $ (588 ) $ 52 Federal income tax expense (benefit) at statutory rate (35%) $ 51 $ (206 ) $ 18 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit 16 (14 ) (5 ) Amortization of investment tax credits (2 ) (4 ) (4 ) ESOP dividend (1 ) (1 ) (2 ) Uncertain tax positions 5 — — Other, net (4 ) (3 ) (1 ) Total income taxes (benefits) $ 65 $ (228 ) $ 6 Effective income tax rate 44.2 % 38.8 % 11.5 %
Accumulated deferred income taxes	Accumulated deferred income taxes as of December 31, 2015 and 2014 are as follows: 2015 2014 (In millions) FirstEnergy Property basis differences $ 9,920 $ 9,354 Deferred sale and leaseback gain (360 ) (381 ) Pension and OPEB (1,541 ) (1,433 ) Nuclear decommissioning activities 480 458 Asset retirement obligations (731 ) (641 ) Regulatory asset/liability 763 768 Loss carryforwards and AMT credits (1,965 ) (1,932 ) Loss carryforward valuation reserve 192 174 All other 15 172 Net deferred income tax liability $ 6,773 $ 6,539 FES Property basis differences $ 1,901 $ 1,749 Deferred sale and leaseback gain (342 ) (356 ) Pension and OPEB (393 ) (373 ) Lease market valuation liability 95 75 Nuclear decommissioning activities 483 489 Asset retirement obligations (509 ) (486 ) Loss carryforwards and AMT credits (687 ) (631 ) Loss carryforward valuation reserve 46 32 All other 6 (15 ) Net deferred income tax liability $ 600 $ 484
Pre-tax net operating loss expiration period	The ultimate utilization of these NOLs may be impacted by statutory limitations on the use of NOLs imposed by state and local tax jurisdictions, changes in statutory tax rates, and changes in business which, among other things, impact both future profitability and the manner in which future taxable income is apportioned to various state and local tax jurisdictions. Expiration Period FirstEnergy FES (In millions) State Local State Local 2016-2020 $ 403 $ 2,983 $ 95 $ 1,820 2021-2025 1,323 — 68 — 2026-2030 2,205 — 259 — 2031-2035 3,245 — 1,128 — $ 7,176 $ 2,983 $ 1,550 $ 1,820
Changes in unrecognized tax benefits	The following table summarizes the changes in unrecognized tax positions for the years ended 2015 , 2014 and 2013 : FirstEnergy FES (In millions) Balance, January 1, 2013 $ 43 $ 3 Prior years increases 10 — Prior years decreases (5 ) — Balance, December 31, 2013 $ 48 $ 3 Current year increases 4 — Prior years increases 5 — Prior years decreases (23 ) — Balance, December 31, 2014 $ 34 $ 3 Current year increases 3 — Prior years increases 7 5 Prior years decreases (10 ) — Balance, December 31, 2015 $ 34 $ 8
Net interest expense (income) and cumulative net interest payable (receivable)	The following table summarizes the net interest expense (income) for the three years ended December 31, 2015 and the cumulative net interest payable as of December 31, 2015 and 2014 (FES did not have net interest expense (income) or a net interest payable for the periods presented): Net Interest Expense (Income) For the Years Ended December 31, Net Interest Payable As of December 31, 2015 2014 2013 2015 2014 (In millions) (In millions) FirstEnergy $ (1 ) $ (6 ) $ 1 $ 1 $ 2
Details of general taxes	General Taxes 2015 2014 2013 (In millions) FirstEnergy KWH excise $ 193 $ 194 $ 219 State gross receipts 224 226 240 Real and personal property 410 393 368 Social security and unemployment 119 112 110 Other 32 37 41 Total general taxes $ 978 $ 962 $ 978 FES State gross receipts $ 44 $ 69 $ 77 Real and personal property 36 39 40 Social security and unemployment 16 17 19 Other 2 3 2 Total general taxes $ 98 $ 128 $ 138

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Rentals for capital and operating leases	Operating lease expense for 2015 , 2014 and 2013 , is summarized as follows: (In millions) 2015 2014 2013 FirstEnergy $ 174 $ 199 $ 224 FES $ 94 $ 95 $ 97
Future minimum capital lease payments	The future minimum capital lease payments as of December 31, 2015 are as follows: Capital leases FirstEnergy FES (In millions) 2016 $ 36 $ 6 2017 31 6 2018 24 2 2019 18 — 2020 14 — Years thereafter 27 — Total minimum lease payments 150 14 Interest portion (18 ) (1 ) Present value of net minimum lease payments 132 13 Less current portion 32 5 Noncurrent portion $ 100 $ 8
Future minimum operating lease payments	FirstEnergy's future minimum consolidated operating lease payments as of December 31, 2015 , are as follows: FirstEnergy Operating Leases Lease Payments PNBV Net (In millions) 2016 $ 197 $ 13 $ 184 2017 122 3 119 2018 135 — 135 2019 116 — 116 2020 91 — 91 Years thereafter 1,438 — 1,438 Total minimum lease payments $ 2,099 $ 16 $ 2,083 FES' future minimum operating lease payments as of December 31, 2015 , are as follows: Operating Leases Lease Payments (In millions) 2016 $ 131 2017 82 2018 101 2019 97 2020 68 Years thereafter 1,315 Total minimum lease payments $ 1,794

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Future Amortization	As of December 31, 2015 , intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheet, include the following: Intangible Assets Amortization Expense Actual Estimated (In millions) Gross Accumulated Amortization Net 2015 2016 2017 2018 2019 2020 Thereafter NUG contracts (1) $ 124 $ 25 $ 99 $ 5 $ 5 $ 5 $ 5 $ 5 $ 5 $ 74 OVEC 54 9 45 2 2 2 2 2 2 35 Coal contracts (2)(3)(4) 556 430 126 116 38 32 17 17 6 — FES customer contracts 148 87 61 17 17 16 14 13 1 — $ 882 $ 551 $ 331 $ 140 $ 62 $ 55 $ 38 $ 37 $ 14 $ 109 (1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings. (2) A gross amount of $40 million ($ 23 million , net) of the coal contracts is related to FES. The 2015 and estimated 2016 to 2019 amortization expense for FES is $5.7 million annually. (3) A gross amount of $102 million ( $16 million , net) of the coal contracts was recorded with a regulatory offset and the amortization does not impact earnings.

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2015
Variable Interest Entities [Abstract]
Net exposure to loss based upon the casualty value provisions	The following table discloses each company’s net exposure to loss based upon the casualty value provisions as of December 31, 2015 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy $ 1,225 $ 950 $ 275 FES $ 1,155 $ 933 $ 222

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value of Financial Instruments [Line Items]
Assets and liabilities measured on recurring basis	The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: FirstEnergy Recurring Fair Value Measurements December 31, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,245 $ — $ 1,245 $ — $ 1,221 $ — $ 1,221 Derivative assets - commodity contracts 4 224 — 228 1 171 — 172 Derivative assets - FTRs — — 8 8 — — 39 39 Derivative assets - NUG contracts (1) — — 1 1 — — 2 2 Equity securities (2) 576 — — 576 592 — — 592 Foreign government debt securities — 75 — 75 — 76 — 76 U.S. government debt securities — 180 — 180 — 182 — 182 U.S. state debt securities — 246 — 246 — 237 — 237 Other (3) 105 212 — 317 55 256 — 311 Total assets $ 685 $ 2,182 $ 9 $ 2,876 $ 648 $ 2,143 $ 41 $ 2,832 Liabilities Derivative liabilities - commodity contracts $ (9 ) $ (122 ) $ — $ (131 ) $ (26 ) $ (141 ) $ — $ (167 ) Derivative liabilities - FTRs — — (13 ) (13 ) — — (14 ) (14 ) Derivative liabilities - NUG contracts (1) — — (137 ) (137 ) — — (153 ) (153 ) Total liabilities $ (9 ) $ (122 ) $ (150 ) $ (281 ) $ (26 ) $ (141 ) $ (167 ) $ (334 ) Net assets (liabilities) (4) $ 676 $ 2,060 $ (141 ) $ 2,595 $ 622 $ 2,002 $ (126 ) $ 2,498 (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (3) Primarily consists of cash and short-term cash investments. (4) Excludes $7 million and $40 million as of December 31, 2015 and December 31, 2014 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts	The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2015 and December 31, 2014 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2014 Balance $ 20 $ (222 ) $ (202 ) $ 4 $ (12 ) $ (8 ) Unrealized gain (loss) 2 (2 ) — 47 (1 ) 46 Purchases — — — 26 (16 ) 10 Settlements (20 ) 71 51 (38 ) 15 (23 ) December 31, 2014 Balance $ 2 $ (153 ) $ (151 ) $ 39 $ (14 ) $ 25 Unrealized gain (loss) 2 (49 ) (47 ) (5 ) (7 ) (12 ) Purchases — — — 22 (11 ) 11 Settlements (3 ) 65 62 (48 ) 19 (29 ) December 31, 2015 Balance $ 1 $ (137 ) $ (136 ) $ 8 $ (13 ) $ (5 ) (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
Quantitative information for level 3 valuation	The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended December 31, 2015 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ (5 ) Model RTO auction clearing prices ($3.90) to $6.90 $1.00 Dollars/MWH NUG Contracts $ (136 ) Model Generation 400 to 3,871,000 $38.10 to $45.60 839,000 $40.20 MWH
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities	The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT, nuclear fuel disposal and NUG trusts as of December 31, 2015 and December 31, 2014 : December 31, 2015 (1) December 31, 2014 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,778 $ 16 $ 1,794 $ 1,724 $ 27 $ 1,751 FES 801 9 810 788 13 801 Equity securities FirstEnergy $ 542 $ 34 $ 576 $ 533 $ 58 $ 591 FES 354 24 378 329 31 360 (1) Excludes short-term cash investments: FE Consolidated - $157 million ; FES - $139 million . (2) Excludes short-term cash investments: FE Consolidated - $241 million ; FES - $204 million .
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income	Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three years ended December 31, 2015 , 2014 and 2013 were as follows: December 31, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 1,534 $ 209 $ (191 ) $ (102 ) $ 101 FES 733 158 (134 ) (90 ) 57 December 31, 2014 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 2,133 $ 146 $ (75 ) $ (37 ) $ 96 FES 1,163 113 (54 ) (33 ) 56 December 31, 2013 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 2,047 $ 92 $ (46 ) $ (90 ) $ 101 FES 940 70 (21 ) (79 ) 60
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities	The following table provides the amortized cost basis, unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of December 31, 2015 and December 31, 2014 : December 31, 2015 December 31, 2014 Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt Securities FirstEnergy $ 6 $ 2 $ 8 $ 13 $ 4 $ 17
Fair value and related carrying amounts of long-term debt and other long-term obligations	The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations, excluding capital lease obligations and net unamortized premiums and discounts: December 31, 2015 December 31, 2014 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 20,244 $ 21,519 $ 19,828 $ 21,733 FES 3,027 3,121 3,097 3,241
FES
Fair Value of Financial Instruments [Line Items]
Assets and liabilities measured on recurring basis	FES Recurring Fair Value Measurements December 31, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 678 $ — $ 678 $ — $ 655 $ — $ 655 Derivative assets - commodity contracts 4 224 — 228 1 171 — 172 Derivative assets - FTRs — — 5 5 — — 27 27 Equity securities (1) 378 — — 378 360 — — 360 Foreign government debt securities — 59 — 59 — 57 — 57 U.S. government debt securities — 23 — 23 — 46 — 46 U.S. state debt securities — 4 — 4 — 4 — 4 Other (2) — 184 — 184 — 199 — 199 Total assets $ 382 $ 1,172 $ 5 $ 1,559 $ 361 $ 1,132 $ 27 $ 1,520 Liabilities Derivative liabilities - commodity contracts $ (9 ) $ (122 ) $ — $ (131 ) $ (26 ) $ (141 ) $ — $ (167 ) Derivative liabilities - FTRs — — (11 ) (11 ) — — (13 ) (13 ) Total liabilities $ (9 ) $ (122 ) $ (11 ) $ (142 ) $ (26 ) $ (141 ) $ (13 ) $ (180 ) Net assets (liabilities) (3) $ 373 $ 1,050 $ (6 ) $ 1,417 $ 335 $ 991 $ 14 $ 1,340 (1) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (2) Primarily consists of short-term cash investments. (3) Excludes $1 million and $44 million as of December 31, 2015 and December 31, 2014 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts	The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2015 and December 31, 2014 : Derivative Asset Derivative Liability Net Asset/(Liability) (In millions) January 1, 2014 Balance $ 3 $ (11 ) $ (8 ) Unrealized gain (loss) 34 (1 ) 33 Purchases 15 (16 ) (1 ) Settlements (25 ) 15 (10 ) December 31, 2014 Balance $ 27 $ (13 ) $ 14 Unrealized gain (loss) 2 (5 ) (3 ) Purchases 9 (10 ) (1 ) Settlements (33 ) 17 (16 ) December 31, 2015 Balance $ 5 $ (11 ) $ (6 )
Quantitative information for level 3 valuation	The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended December 31, 2015 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ (6 ) Model RTO auction clearing prices ($3.90) to $5.70 $0.70 Dollars/MWH

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair value of derivatives instruments	The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets: Derivative Assets Derivative Liabilities Fair Value Fair Value December 31, December 31, December 31, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 150 $ 121 Commodity Contracts $ (94 ) $ (154 ) FTRs 7 38 FTRs (12 ) (13 ) 157 159 (106 ) (167 ) Noncurrent Liabilities - Adverse Power Contract Liability Deferred Charges and Other Assets - Other NUGs (1) (137 ) (153 ) Commodity Contracts 78 51 Noncurrent Liabilities - Other FTRs 1 1 Commodity Contracts (37 ) (13 ) NUGs (1) 1 2 FTRs (1 ) (1 ) 80 54 (175 ) (167 ) Derivative Assets $ 237 $ 213 Derivative Liabilities $ (281 ) $ (334 )
Offsetting assets and liabilities	The following tables summarize the fair value of derivative assets and derivative liabilities on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet December 31, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 228 $ (125 ) $ — $ 103 FTRs 8 (8 ) — — NUG contracts 1 — — 1 $ 237 $ (133 ) $ — $ 104 Derivative Liabilities Commodity contracts $ (131 ) $ 125 $ 3 $ (3 ) FTRs (13 ) 8 5 — NUG contracts (137 ) — — (137 ) $ (281 ) $ 133 $ 8 $ (140 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2014 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 172 $ (126 ) $ — $ 46 FTRs 39 (14 ) — 25 NUG contracts 2 — — 2 $ 213 $ (140 ) $ — $ 73 Derivative Liabilities Commodity contracts $ (167 ) $ 126 $ 35 $ (6 ) FTRs (14 ) 14 — — NUG contracts (153 ) — — (153 ) $ (334 ) $ 140 $ 35 $ (159 )
Volume of First Energy's outstanding derivative transactions	The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of December 31, 2015 : Purchases Sales Net Units (In millions) Power Contracts 16 49 (33 ) MWH FTRs 29 — 29 MWH NUGs 4 — 4 MWH Natural Gas 83 — 83 mmBTU
Effect of derivative instruments on statements of income and comprehensive income	The effect of active derivative instruments not in a hedging relationship on the Consolidated Statements of Income during 2015 and 2014 are summarized in the following tables: Year Ended December 31, Commodity Contracts FTRs Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense (1) $ 93 $ (20 ) $ 73 Realized Gain (Loss) Reclassified to: Revenues (2) $ 111 $ 50 $ 161 Purchased Power Expense (3) (130 ) — (130 ) Other Operating Expense (4) — (49 ) (49 ) Fuel Expense (34 ) — (34 ) (1) Includes $93 million for commodity contracts and ($19) million for FTRs associated with FES. (2) Includes $111 million for commodity contracts and $49 million for FTRs associated with FES. (3) Includes ($130) million for commodity contracts associated with FES. (4) Includes ($49) million for FTRs associated with FES. Year Ended December 31, Commodity FTRs Interest Rate Swaps Total (In millions) 2014 Unrealized Gain (Loss) Recognized in: Other Operating Expense (5) $ (86 ) $ 22 $ — $ (64 ) Realized Gain (Loss) Reclassified to: Revenues (6) $ (6 ) $ 68 $ — $ 62 Purchased Power Expense (7) 365 — — 365 Other Operating Expense (8) — (44 ) — (44 ) Fuel Expense (6 ) — — (6 ) Interest Expense — — 14 14 (5) Includes ($86) million for commodity contracts and $21 million for FTRs associated with FES. (6) Includes ($6) million for commodity contracts and $67 million for FTRs associated with FES. (7) Realized losses on financially settled wholesale sales contracts of $252 million resulting from higher market prices were netted in purchased power. Includes $365 million for commodity contracts associated with FES. (8) Includes ($43) million for FTRs associated with FES.
Reconciliation of changes in the fair value of certain contracts that are deferred	The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during 2015 and 2014 . Changes in the value of these contracts are deferred for future recovery from (or credit to) customers: Year Ended December 31, Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of January 1, 2015 $ (151 ) $ 11 $ (140 ) Unrealized loss (47 ) (9 ) (56 ) Purchases — 12 12 Settlements 62 (13 ) 49 Outstanding net asset (liability) as of December 31, 2015 $ (136 ) $ 1 $ (135 ) Outstanding net liability as of January 1, 2014 $ (202 ) $ — $ (202 ) Unrealized gain (loss) (1 ) 13 12 Purchases — 11 11 Settlements 52 (13 ) 39 Outstanding net asset (liability) as of December 31, 2014 $ (151 ) $ 11 $ (140 )

Capitalization (Tables)

Capitalization (Tables)	12 Months Ended
	Dec. 31, 2015
Capitalization, Long-term Debt and Equity [Abstract]
Preferred stock and preference stock authorizations	FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2015 , as follows: Preferred Stock Preference Stock Shares Authorized Par Value Shares Authorized Par Value FirstEnergy 5,000,000 $ 100 OE 6,000,000 $ 100 8,000,000 no par OE 8,000,000 $ 25 Penn 1,200,000 $ 100 CEI 4,000,000 no par 3,000,000 no par TE 3,000,000 $ 100 5,000,000 $ 25 TE 12,000,000 $ 25 JCP&L 15,600,000 no par ME 10,000,000 no par PN 11,435,000 no par MP 940,000 $ 100 PE 10,000,000 $ 0.01 WP 32,000,000 no par
Outstanding consolidated long-term debt and other long-term obligations	The following tables present outstanding long-term debt and capital lease obligations for FirstEnergy and FES as of December 31, 2015 and 2014 : As of December 31, 2015 As of December 31 (Dollar amounts in millions) Maturity Date Interest Rate 2015 2014 FirstEnergy: FMBs 2016 - 2045 3.340% - 9.740% $ 3,269 $ 3,190 Secured notes - fixed rate 2016 - 2037 0.679% - 12.000% 2,096 2,247 Secured notes - variable rate 2017 - 2017 3.500% - 3.500% 2 — Total secured notes 2,098 2,247 Unsecured notes - fixed rate 2016 - 2045 2.150% - 7.700% 13,580 13,078 Unsecured notes - variable rate 2017 - 2020 0.010% - 2.180% 1,292 1,292 Total unsecured notes 14,872 14,370 Capital lease obligations 132 160 Unamortized debt discounts (18 ) (8 ) Unamortized fair value adjustments 5 21 Currently payable long-term debt (1,166 ) (804 ) Total long-term debt and other long-term obligations $ 19,192 $ 19,176 FES: Secured notes - fixed rate 2016 - 2018 5.625% - 12.000% $ 340 $ 437 Secured notes - variable rate 2017 - 2017 3.500% - 3.500% 2 — Total secured notes 342 437 Unsecured notes - fixed rate 2016 - 2039 2.150% - 6.800% 2,593 2,568 Unsecured notes - variable rate 2017 - 2017 0.010% - 0.010% 92 92 Total unsecured notes 2,685 2,660 Capital lease obligations 13 18 Unamortized debt discounts (1 ) (1 ) Currently payable long-term debt (512 ) (506 ) Total long-term debt and other long-term obligations $ 2,527 $ 2,608
Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases and variable rate PCRBs) for the next five years	The following table presents scheduled debt repayments for outstanding long-term debt, excluding capital leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2015 . PCRBs that are scheduled to be tendered for mandatory purchase prior to maturity are reflected in the applicable year in which such PCRBs are scheduled to be tendered. Year FirstEnergy FES (In millions) 2016 $ 1,039 $ 414 2017 1,733 257 2018 1,702 516 2019 2,268 322 2020 1,231 667
Outstanding PCRBs for the next three years	The following table classifies the outstanding fixed rate PCRBs and variable rate PCRBs by year, excluding unamortized debt discounts and premiums, for the next five years based on the next date on which the debt holders may exercise their right to tender their PCRBs. Year FirstEnergy FES (In millions) 2016 $ 391 $ 391 2017 222 222 2018 375 375 2019 232 232 2020 490 490
Amounts and percentages of LOCs and Insurance Policies for FirstEnergy, FES and Utilities	The amounts and annual fees for PCRB-related LOCs for FirstEnergy and FES as of December 31, 2015 , are as follows: Aggregate LOC Amount (1) Annual Fees (In millions) FirstEnergy $ 93 1.25% FES 93 1.25% (1) Includes approximately $1 million of applicable interest coverage.

Short-Term Borrowings and Ban50

Short-Term Borrowings and Bank Lines of Credit (Tables)	12 Months Ended
	Dec. 31, 2015
Short-term Borrowings and Bank Lines of Credit [Abstract]
Liquidity	FirstEnergy’s available liquidity under the Facilities as of January 31, 2016 was as follows: Borrower(s) Type Maturity Commitment Available Liquidity (In millions) FirstEnergy (1) Revolving March 2019 $ 3,500 $ 1,595 FES / AE Supply Revolving March 2019 1,500 1,442 FET (2) Revolving March 2019 1,000 1,000 Subtotal $ 6,000 $ 4,037 Cash — 63 Total $ 6,000 $ 4,100 (1) FE and the Utilities (2) Includes FET, ATSI and TrAIL as subsidiary borrowers
Borrowing sub-limits for each borrower and limitations on short-term indebtedness	The following table summarizes the borrowing sub-limits for each borrower under the Facilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations , as of December 31, 2015 : Borrower Revolving Credit Facility Sub-Limits Regulatory and Other Short-Term Debt Limitations (In millions) FE $ 3,500 $ — (1) FES 1,500 — (2) AE Supply 1,000 — (2) FET 1,000 — (1) OE 500 500 (3) CEI 500 500 (3) TE 500 500 (3) JCP&L 600 500 (3) ME 300 500 (3) PN 300 300 (3) WP 200 200 (3) MP 500 500 (3) PE 150 150 (3) ATSI 500 500 (3) Penn 50 100 (3) TrAIL 400 400 (3) (1) No limitations. (2) No limitation based upon blanket financing authorization from the FERC under existing market-based rate tariffs. (3) Excluding amounts which may be borrowed under the regulated companies' money pool.
Weighted average interest rates on short-term borrowings outstanding	The weighted average interest rates on short-term borrowings outstanding, including borrowings under the FirstEnergy Money Pools, as of December 31, 2015 and 2014 , were as follows: 2015 2014 FirstEnergy 2.16 % 1.96 % FES — % 3.34 %

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Fair values of the decommissioning trust assets	The fair values of the decommissioning trust assets as of December 31, 2015 and 2014 were as follows: 2015 2014 (In millions) FirstEnergy $ 2,282 $ 2,341 FES $ 1,327 $ 1,365
Changes to the asset retirement obligations	The following table summarizes the changes to the ARO balances during 2015 and 2014 : ARO Reconciliation FirstEnergy FES (In millions) Balance, January 1, 2014 $ 1,678 $ 1,015 Liabilities settled (9 ) (7 ) Accretion 113 66 Revisions in estimated cash flows (395 ) (233 ) Balance, December 31, 2014 $ 1,387 $ 841 Liabilities settled (13 ) (8 ) Accretion 92 55 Revisions in estimated cash flows (56 ) (57 ) Balance, December 31, 2015 $ 1,410 $ 831

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2015
Regulated Operations [Abstract]
Schedule of Capacity Performance	In August and September 2015, PJM conducted RPM auctions pursuant to the new Capacity Performance rules. FirstEnergy’s net competitive capacity position as a result of the BRA and Capacity Performance transition auctions is as follows: 2016 - 2017 2017 - 2018 2018 - 2019* Legacy Obligation Capacity Performance Legacy Obligation Capacity Performance Base Generation Capacity Performance (MW) ($/MWD) (MW) ($/MWD) (MW) ($/MWD) (MW) ($/MWD) (MW) ($/MWD) (MW) ($/MWD) ATSI 2,765 $114.23 4,210 $134.00 375 $120.00 6,245 $151.50 — $149.98 6,245 $164.77 RTO 875 $59.37 3,675 $134.00 985 $120.00 3,565 $151.50 240 $149.98 3,930 $164.77 All Other Zones 135 $119.13 — $134.00 150 $120.00 — $151.50 35 ** 20 ** 3,775 7,885 1,510 9,810 275 10,195 *Approximately 885 MWs remain uncommitted for the 2018/2019 delivery year. **Base Generation: 10 MWs cleared at $200.21/MWD and 25 MWs cleared at $149.98/MWD. Capacity Performance: 5 MWs cleared at $215.00/MWD and 15 MWs cleared at $164.77/MWD.

Commitments, Guarantees and C53

Commitments, Guarantees and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule of Guarantor Obligations	The following table discloses the additional credit contingent contractual obligations that may be required under certain events as of December 31, 2015 : Collateral Provisions FES AE Supply Utilities Total (In millions) Split Rating (One rating agency's rating below investment grade) $ 198 $ 6 $ 41 $ 245 BB+/Ba1 Credit Ratings $ 231 $ 6 $ 41 $ 278 Full impact of credit contingent contractual obligations $ 363 $ 16 $ 41 $ 420

Transactions With Affiliated 54

Transactions With Affiliated Companies (Tables)	12 Months Ended
	Dec. 31, 2015
Transactions With Affiliated Companies [Abstract]
Affiliated Company Transactions	The primary affiliated company transactions for FES during the three years ended December 31, 2015 are as follows: FES 2015 2014 2013 (In millions) Revenues: Electric sales to affiliates $ 664 $ 861 $ 652 Other 6 6 6 Expenses: Purchased power from affiliates 353 271 486 Fuel 1 1 — Support services 705 619 619 Investment Income: Interest income from FE 2 3 2 Interest Expense: Interest expense to affiliates 4 3 4 Interest expense to FE 3 4 6

Supplemental Guarantor Inform55

Supplemental Guarantor Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Guarantor Information [Abstract]
Condensed Consolidating Statements of Income and Comprehensive Income	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Year Ended December 31, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 4,824 $ 1,801 $ 2,138 $ (3,758 ) $ 5,005 OPERATING EXPENSES: Fuel — 679 192 — 871 Purchased power from affiliates 3,826 — 285 (3,758 ) 353 Purchased power from non-affiliates 1,684 — — — 1,684 Other operating expenses 399 275 618 49 1,341 Pension and OPEB mark-to-market adjustment (8 ) 10 55 — 57 Provision for depreciation 12 124 191 (3 ) 324 General taxes 45 26 27 — 98 Total operating expenses 5,958 1,114 1,368 (3,712 ) 4,728 OPERATING INCOME (LOSS) (1,134 ) 687 770 (46 ) 277 OTHER INCOME (EXPENSE): Investment income (loss), including net income from equity investees 844 17 (5 ) (870 ) (14 ) Miscellaneous income 1 2 — — 3 Interest expense — affiliates (29 ) (8 ) (4 ) 34 (7 ) Interest expense — other (52 ) (104 ) (49 ) 58 (147 ) Capitalized interest — 6 29 — 35 Total other income (expense) 764 (87 ) (29 ) (778 ) (130 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (370 ) 600 741 (824 ) 147 INCOME TAXES (BENEFITS) (452 ) 224 278 15 65 NET INCOME $ 82 $ 376 $ 463 $ (839 ) $ 82 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 82 $ 376 $ 463 $ (839 ) $ 82 OTHER COMPREHENSIVE LOSS: Pension and OPEB prior service costs (6 ) (5 ) — 5 (6 ) Amortized gain on derivative hedges (3 ) — — — (3 ) Change in unrealized gain on available-for-sale securities (9 ) — (8 ) 8 (9 ) Other comprehensive loss (18 ) (5 ) (8 ) 13 (18 ) Income tax benefits on other comprehensive loss (7 ) (2 ) (3 ) 5 (7 ) Other comprehensive loss, net of tax (11 ) (3 ) (5 ) 8 (11 ) COMPREHENSIVE INCOME $ 71 $ 373 $ 458 $ (831 ) $ 71 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Year Ended December 31, 2014 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 5,990 $ 1,902 $ 2,172 $ (3,920 ) $ 6,144 OPERATING EXPENSES: Fuel — 1,055 198 — 1,253 Purchased power from affiliates 3,920 — 271 (3,920 ) 271 Purchased power from non-affiliates 2,767 4 — — 2,771 Other operating expenses 790 269 527 49 1,635 Pension and OPEB mark-to-market adjustment 19 90 188 — 297 Provision for depreciation 10 119 193 (3 ) 319 General taxes 72 31 25 — 128 Total operating expenses 7,578 1,568 1,402 (3,874 ) 6,674 OPERATING INCOME (LOSS) (1,588 ) 334 770 (46 ) (530 ) OTHER INCOME (EXPENSE): Loss on debt redemptions (3 ) (1 ) (2 ) — (6 ) Investment income, including net income from equity investees 791 8 61 (799 ) 61 Miscellaneous income 2 4 — — 6 Interest expense — affiliates (12 ) (6 ) (4 ) 15 (7 ) Interest expense — other (53 ) (101 ) (52 ) 60 (146 ) Capitalized interest — 4 30 — 34 Total other income (expense) 725 (92 ) 33 (724 ) (58 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) (863 ) 242 803 (770 ) (588 ) INCOME TAXES (BENEFITS) (619 ) 87 298 6 (228 ) INCOME (LOSS) FROM CONTINUING OPERATIONS (244 ) 155 505 (776 ) (360 ) Discontinued operations (net of income taxes of $70) — 116 — — 116 NET INCOME (LOSS) $ (244 ) $ 271 $ 505 $ (776 ) $ (244 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (244 ) $ 271 $ 505 $ (776 ) $ (244 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (6 ) (5 ) — 5 (6 ) Amortized gain on derivative hedges (10 ) — — — (10 ) Change in unrealized gain on available-for-sale securities 21 — 21 (21 ) 21 Other comprehensive income (loss) 5 (5 ) 21 (16 ) 5 Income taxes (benefits) on other comprehensive income (loss) 2 (2 ) 8 (6 ) 2 Other comprehensive income (loss), net of tax 3 (3 ) 13 (10 ) 3 COMPREHENSIVE INCOME (LOSS) $ (241 ) $ 268 $ 518 $ (786 ) $ (241 ) FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Year Ended December 31, 2013 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 6,068 $ 2,399 $ 1,634 $ (3,928 ) $ 6,173 OPERATING EXPENSES: Fuel — 1,056 206 — 1,262 Purchased power from affiliates 4,148 — 266 (3,928 ) 486 Purchased power from non-affiliates 2,326 7 — — 2,333 Other operating expenses 635 275 529 48 1,487 Pension and OPEB mark-to-market adjustment (8 ) (37 ) (36 ) — (81 ) Provision for depreciation 6 127 178 (5 ) 306 General taxes 80 34 24 — 138 Total operating expenses 7,187 1,462 1,167 (3,885 ) 5,931 OPERATING INCOME (LOSS) (1,119 ) 937 467 (43 ) 242 OTHER INCOME (EXPENSE): Loss on debt redemptions (103 ) — — — (103 ) Investment income, including net income from equity investees 847 1 25 (857 ) 16 Miscellaneous income 4 24 — — 28 Interest expense — affiliates (13 ) (5 ) (6 ) 14 (10 ) Interest expense — other (63 ) (104 ) (54 ) 61 (160 ) Capitalized interest 1 2 36 — 39 Total other income (expense) 673 (82 ) 1 (782 ) (190 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) (446 ) 855 468 (825 ) 52 INCOME TAXES (BENEFITS) (506 ) 365 135 12 6 INCOME FROM CONTINUING OPERATIONS 60 490 333 (837 ) 46 Discontinued operations (net of income taxes of $8) — 14 — — 14 NET INCOME $ 60 $ 504 $ 333 $ (837 ) $ 60 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 60 $ 504 $ 333 $ (837 ) $ 60 OTHER COMPREHENSIVE LOSS: Pension and OPEB prior service costs (15 ) (13 ) — 13 (15 ) Amortized gain on derivative hedges (6 ) — — — (6 ) Change in unrealized gain on available-for-sale securities (8 ) — (8 ) 8 (8 ) Other comprehensive loss (29 ) (13 ) (8 ) 21 (29 ) Income tax benefits on other comprehensive loss (11 ) (5 ) (3 ) 8 (11 ) Other comprehensive loss, net of tax (18 ) (8 ) (5 ) 13 (18 ) COMPREHENSIVE INCOME $ 42 $ 496 $ 328 $ (824 ) $ 42
Condensed Consolidating Balance Sheets	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2015 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 275 — — — 275 Affiliated companies 433 403 461 (846 ) 451 Other 36 4 19 — 59 Notes receivable from affiliated companies 406 1,210 805 (2,410 ) 11 Materials and supplies 53 204 213 — 470 Derivatives 154 — — — 154 Collateral 70 — — — 70 Prepayments and other 48 18 — — 66 1,475 1,841 1,498 (3,256 ) 1,558 PROPERTY, PLANT AND EQUIPMENT: In service 93 6,367 8,233 (382 ) 14,311 Less — Accumulated provision for depreciation 40 2,144 3,775 (194 ) 5,765 53 4,223 4,458 (188 ) 8,546 Construction work in progress 30 249 878 — 1,157 83 4,472 5,336 (188 ) 9,703 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,327 — 1,327 Investment in affiliated companies 7,452 — — (7,452 ) — Other — 10 — — 10 7,452 10 1,327 (7,452 ) 1,337 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 300 16 — (316 ) — Customer intangibles 61 — — — 61 Goodwill 23 — — — 23 Property taxes — 12 28 — 40 Derivatives 79 — — — 79 Other 33 318 21 12 384 496 346 49 (304 ) 587 $ 9,506 $ 6,669 $ 8,210 $ (11,200 ) $ 13,185 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 229 $ 308 $ (25 ) $ 512 Short-term borrowings- Affiliated companies 2,021 389 — (2,410 ) — Other — 8 — — 8 Accounts payable- Affiliated companies 884 146 368 (856 ) 542 Other 21 118 — — 139 Accrued taxes 7 93 62 (86 ) 76 Derivatives 103 1 — — 104 Other 66 61 9 45 181 3,102 1,045 747 (3,332 ) 1,562 CAPITALIZATION: Total equity 5,605 2,944 4,476 (7,420 ) 5,605 Long-term debt and other long-term obligations 694 2,122 847 (1,136 ) 2,527 6,299 5,066 5,323 (8,556 ) 8,132 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 791 791 Accumulated deferred income taxes 6 — 697 (103 ) 600 Asset retirement obligations — 191 640 — 831 Retirement benefits 27 305 — — 332 Derivatives 37 1 — — 38 Other 35 61 803 — 899 105 558 2,140 688 3,491 $ 9,506 $ 6,669 $ 8,210 $ (11,200 ) $ 13,185 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2014 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 415 — — — 415 Affiliated companies 484 487 674 (1,120 ) 525 Other 66 21 20 — 107 Notes receivable from affiliated companies 339 838 272 (1,449 ) — Materials and supplies 67 202 223 — 492 Derivatives 147 — — — 147 Collateral 229 — — — 229 Prepayments and other 48 19 — 1 68 1,795 1,569 1,189 (2,568 ) 1,985 PROPERTY, PLANT AND EQUIPMENT: In service 133 6,217 7,628 (382 ) 13,596 Less — Accumulated provision for depreciation 36 2,058 3,305 (191 ) 5,208 97 4,159 4,323 (191 ) 8,388 Construction work in progress 3 206 801 — 1,010 100 4,365 5,124 (191 ) 9,398 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,365 — 1,365 Investment in affiliated companies 6,607 — — (6,607 ) — Other — 10 — — 10 6,607 10 1,365 (6,607 ) 1,375 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 284 98 — (382 ) — Customer intangibles 78 — — — 78 Goodwill 23 — — — 23 Property taxes — 14 27 — 41 Unamortized sale and leaseback costs — — — — — Derivatives 52 — — — 52 Other 34 277 7 13 331 471 389 34 (369 ) 525 $ 8,973 $ 6,333 $ 7,712 $ (9,735 ) $ 13,283 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ 18 $ 164 $ 348 $ (24 ) $ 506 Short-term borrowings- Affiliated companies 1,135 321 28 (1,449 ) 35 Other 90 9 — — 99 Accounts payable- Affiliated companies 1,068 197 219 (1,068 ) 416 Other 46 202 — — 248 Accrued taxes 2 62 161 (123 ) 102 Derivatives 166 — — — 166 Other 72 56 9 47 184 2,597 1,011 765 (2,617 ) 1,756 CAPITALIZATION: Total equity 5,585 2,561 4,014 (6,575 ) 5,585 Long-term debt and other long-term obligations 695 2,215 859 (1,161 ) 2,608 6,280 4,776 4,873 (7,736 ) 8,193 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 824 824 Accumulated deferred income taxes 13 — 678 (207 ) 484 Asset retirement obligations — 189 652 — 841 Retirement benefits 36 288 — — 324 Derivatives 14 — — — 14 Other 33 69 744 1 847 96 546 2,074 618 3,334 $ 8,973 $ 6,333 $ 7,712 $ (9,735 ) $ 13,283
Condensed Consolidating Statements of Cash Flows	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2015 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (637 ) $ 551 $ 1,261 $ (24 ) $ 1,151 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 45 296 — 341 Short-term borrowings, net 796 67 — (863 ) — Redemptions and Repayments- Long-term debt (17 ) (70 ) (348 ) 24 (411 ) Short-term borrowings, net — — (28 ) (98 ) (126 ) Common stock dividend payment (70 ) — — — (70 ) Other — (5 ) (1 ) — (6 ) Net cash provided from (used for) financing activities 709 37 (81 ) (937 ) (272 ) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (5 ) (223 ) (399 ) — (627 ) Nuclear fuel — — (190 ) — (190 ) Proceeds from asset sales 10 3 — — 13 Sales of investment securities held in trusts — — 733 — 733 Purchases of investment securities held in trusts — — (791 ) — (791 ) Cash Investments (10 ) — — — (10 ) Loans to affiliated companies, net (67 ) (372 ) (533 ) 961 (11 ) Other — 4 — — 4 Net cash used for investing activities (72 ) (588 ) (1,180 ) 961 (879 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2014 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (600 ) $ 408 $ 785 $ (22 ) $ 571 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 431 447 — 878 Short-term borrowings, net 247 114 — (361 ) — Equity contribution from parent 500 — — — 500 Redemptions and Repayments- Long-term debt (1 ) (269 ) (568 ) 22 (816 ) Short-term borrowings, net — — (123 ) (178 ) (301 ) Other (1 ) (12 ) (2 ) — (15 ) Net cash provided from (used for) financing activities 745 264 (246 ) (517 ) 246 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (8 ) (169 ) (662 ) — (839 ) Nuclear fuel — — (233 ) — (233 ) Proceeds from asset sales — 307 — — 307 Sales of investment securities held in trusts — — 1,163 — 1,163 Purchases of investment securities held in trusts — — (1,219 ) — (1,219 ) Loans to affiliated companies, net (136 ) (815 ) 412 539 — Other (1 ) 5 — — 4 Net cash used for investing activities (145 ) (672 ) (539 ) 539 (817 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2013 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (1,429 ) $ 753 $ 776 $ (22 ) $ 78 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 864 371 150 (954 ) 431 Equity contribution from parent 1,500 — — — 1,500 Redemptions and Repayments- Long-term debt (770 ) (364 ) (90 ) 22 (1,202 ) Short-term borrowings, net (244 ) (505 ) — 749 — Tender premiums (67 ) — — — (67 ) Other (4 ) (5 ) — — (9 ) Net cash provided from (used for) financing activities 1,279 (503 ) 60 (183 ) 653 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (12 ) (256 ) (449 ) — (717 ) Nuclear fuel — — (250 ) — (250 ) Proceeds from asset sales — 21 — — 21 Sales of investment securities held in trusts — — 940 — 940 Purchases of investment securities held in trusts — — (1,000 ) — (1,000 ) Loans to affiliated companies, net 163 (15 ) (77 ) 205 276 Other (1 ) (1 ) — — (2 ) Net cash provided from (used for) investing activities 150 (251 ) (836 ) 205 (732 ) Net change in cash and cash equivalents — (1 ) — — (1 ) Cash and cash equivalents at beginning of period — 3 — — 3 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segment Financial Information	Segment Financial Information For the Years Ended December 31, Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Reconciling Adjustments Consolidated (In millions) 2015 External revenues $ 9,625 $ 1,011 $ 4,698 $ (168 ) $ (140 ) $ 15,026 Internal revenues — — 686 — (686 ) — Total revenues 9,625 1,011 5,384 (168 ) (826 ) 15,026 Depreciation 672 156 394 60 — 1,282 Amortization of regulatory assets, net 261 7 — — — 268 Impairment of long-lived assets 8 — 34 — — 42 Investment income (loss) 42 — (16 ) (9 ) (39 ) (22 ) Impairment of equity method investment — — — 362 — 362 Interest expense 586 161 192 193 — 1,132 Income taxes (benefits) 342 174 50 (262 ) 11 315 Income (loss) from continuing operations 618 298 89 (427 ) — 578 Discontinued operations, net of tax — — — — — — Net income (loss) 618 298 89 (427 ) — 578 Total assets 27,876 7,439 16,365 507 — 52,187 Total goodwill 5,092 526 800 — — 6,418 Property additions 1,108 952 588 56 — 2,704 2014 External revenues $ 9,102 $ 769 $ 5,470 $ (146 ) $ (146 ) $ 15,049 Internal revenues — — 819 — (819 ) — Total revenues 9,102 769 6,289 (146 ) (965 ) 15,049 Depreciation 658 127 387 48 — 1,220 Amortization of regulatory assets, net 1 11 — — — 12 Impairment of long-lived assets — — — — — — Investment income (loss) 56 — 54 2 (40 ) 72 Impairment of equity method investment — — — — — — Interest expense 589 131 189 168 (4 ) 1,073 Income taxes (benefits) 227 121 (223 ) (178 ) 11 (42 ) Income (loss) from continuing operations 465 223 (417 ) (58 ) — 213 Discontinued operations, net of tax — — 86 — — 86 Net income (loss) 465 223 (331 ) (58 ) — 299 Total assets 28,085 6,252 16,518 793 — 51,648 Total goodwill 5,092 526 800 — — 6,418 Property additions 972 1,329 939 72 — 3,312 2013 External revenues $ 8,720 $ 731 $ 5,728 $ (121 ) $ (166 ) $ 14,892 Internal revenues — — 770 — (770 ) — Total revenues 8,720 731 6,498 (121 ) (936 ) 14,892 Depreciation 606 114 439 43 — 1,202 Amortization of regulatory assets, net 529 10 — — — 539 Impairment of long-lived assets 322 — 473 — — 795 Investment income (loss) 57 — 14 6 (44 ) 33 Impairment of equity method investment — — — — — — Interest expense 543 93 222 148 10 1,016 Income taxes (benefits) 301 129 (140 ) (105 ) 10 195 Income (loss) from continuing operations 501 214 (235 ) (105 ) — 375 Discontinued operations, net of tax — — 17 — — 17 Net income (loss) 501 214 (218 ) (105 ) — 392 Total assets 27,683 5,247 16,782 712 — 50,424 Total goodwill 5,092 526 800 — — 6,418 Property additions 1,272 461 827 78 — 2,638

Summary of Quarterly Financia57

Summary of Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Information	The following summarizes certain consolidated operating results by quarter for 2015 and 2014 . FirstEnergy CONSOLIDATED STATEMENTS OF INCOME (In millions, except per share amounts) 2015 2014 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Revenues $ 3,541 $ 4,123 $ 3,465 $ 3,897 $ 3,483 $ 3,888 $ 3,496 $ 4,182 Other operating expense 952 850 916 1,057 901 858 1,021 1,182 Pension and OPEB mark-to-market adjustment 242 — — — 835 — — — Provision for depreciation 313 328 322 319 316 308 302 294 Operating Income (Loss) 236 908 554 594 (337 ) 716 292 391 Income (loss) from continuing operations before income taxes (benefits) (396 ) 621 302 366 (574 ) 485 90 170 Income taxes (benefits) (1) (170 ) 226 115 144 (268 ) 152 26 48 Income (loss) from continuing operations (226 ) 395 187 222 (306 ) 333 64 122 Discontinued operations (net of income taxes) — — — — — — — 86 Net Income (Loss) (226 ) 395 187 222 (306 ) 333 64 208 Earnings (loss) per share of common stock- (2) Basic - Continuing Operations (0.53 ) 0.94 0.44 0.53 (0.73 ) 0.79 0.16 0.29 Basic - Discontinued Operations (Note 19) — — — — — — — 0.21 Basic - Earnings Available to FirstEnergy Corp. (0.53 ) 0.94 0.44 0.53 (0.73 ) 0.79 0.16 0.50 Diluted - Continuing Operations (0.53 ) 0.93 0.44 0.53 (0.73 ) 0.79 0.15 0.29 Diluted - Discontinued Operations (Note 19) — — — — — — — 0.20 Diluted - Earnings Available to FirstEnergy Corp. (0.53 ) 0.93 0.44 0.53 (0.73 ) 0.79 0.15 0.49 (1) - During the fourth quarter of 2014, income tax benefits of $16 million were recorded that related to prior periods. The out-of-period adjustment primarily related to the correction of amounts included in the Company’s tax basis balance sheet. Management determined that this adjustment was not material to 2014 or any prior period. (2) - Total quarterly earnings per share information may not equal annual earnings per share due to the issuance of shares throughout the year. See FirstEnergy's Consolidated Statements of Stockholders' Equity and Note 4. Stock-Based Compensation for additional information. FES CONSOLIDATED STATEMENTS OF INCOME (In millions) 2015 2014 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Revenues $ 1,171 $ 1,338 $ 1,119 $ 1,377 $ 1,342 $ 1,521 $ 1,452 $ 1,829 Other operating expense 329 246 353 413 359 356 468 452 Pension and OPEB mark-to-market adjustment 57 — — — 297 — — — Provision for depreciation 84 79 81 80 83 83 79 74 Operating Income (Loss) 25 240 — 12 (321 ) 90 (151 ) (148 ) Income (loss) from continuing operations before income taxes (benefits) (13 ) 190 (25 ) (5 ) (347 ) 72 (154 ) (159 ) Income taxes (benefits) 1 70 (4 ) (2 ) (133 ) 28 (67 ) (56 ) Income (loss) from continuing operations (14 ) 120 (21 ) (3 ) (214 ) 44 (87 ) (103 ) Discontinued operations (net of income taxes) — — — — — — — 116 Net Income (Loss) (14 ) 120 (21 ) (3 ) (214 ) 44 (87 ) 13

Organization and Basis of Pre58

Organization and Basis of Presentation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Regulatory assets on the Balance Sheets
Regulatory Assets	$ 1,348	$ 1,411
Increase (Decrease)	(63)
Regulatory transition costs
Regulatory assets on the Balance Sheets
Regulatory Assets	185	240
Increase (Decrease)	(55)
Customer receivables for future income taxes
Regulatory assets on the Balance Sheets
Regulatory Assets	355	370
Increase (Decrease)	(15)
Nuclear decommissioning and spent fuel disposal costs
Regulatory assets on the Balance Sheets
Regulatory Assets	(272)	(305)
Increase (Decrease)	33
Asset removal costs
Regulatory assets on the Balance Sheets
Regulatory Assets	(372)	(254)
Increase (Decrease)	(118)
Deferred transmission costs
Regulatory assets on the Balance Sheets
Regulatory Assets	115	90
Increase (Decrease)	25
Deferred generation costs
Regulatory assets on the Balance Sheets
Regulatory Assets	243	281
Increase (Decrease)	(38)
Deferred distribution costs
Regulatory assets on the Balance Sheets
Regulatory Assets	335	182
Increase (Decrease)	153
Contract valuations
Regulatory assets on the Balance Sheets
Regulatory Assets	186	153
Increase (Decrease)	33
Storm-related costs
Regulatory assets on the Balance Sheets
Regulatory Assets	403	465
Increase (Decrease)	(62)
Other
Regulatory assets on the Balance Sheets
Regulatory Assets	170	$ 189
Increase (Decrease)	$ (19)

Organization and Basis of Pre59

Organization and Basis of Presentation (Details 1) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Receivables from customers
Customers	$ 1,415	$ 1,554
FES
Receivables from customers
Customers	275	415
Billed
Receivables from customers
Customers	836	914
Billed | FES
Receivables from customers
Customers	165	239
Unbilled
Receivables from customers
Customers	579	640
Unbilled | FES
Receivables from customers
Customers	$ 110	$ 176

Organization and Basis of Pre60

Organization and Basis of Presentation (Details 2) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Basic and Diluted Earnings per Share of Common Stock
Income (loss) from continuing operations	$ (226)	$ 395	$ 187	$ 222	$ (306)	$ 333	$ 64	$ 122	$ 578	$ 213	$ 375
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 86	0	86	17
EARNINGS AVAILABLE TO FIRSTENERGY CORP.									$ 578	$ 299	$ 392
Weighted average number of basic shares outstanding									422	420	418
Assumed exercise of dilutive stock options and awards (in shares)									2	1	1
Weighted average number of diluted shares outstanding									424	421	419
Earnings per share:
Basic - Continuing Operations, in dollars per share	$ (0.53)	$ 0.94	$ 0.44	$ 0.53	$ (0.73)	$ 0.79	$ 0.16	$ 0.29	$ 1.37	$ 0.51	$ 0.90
Basic - Discontinued Operations, in dollars per share	0	0	0	0	0	0	0	0.21	0	0.20	0.04
Basic - Earnings Available to FirstEnergy Corp., in dollars per share	(0.53)	0.94	0.44	0.53	(0.73)	0.79	0.16	0.50	1.37	0.71	0.94
Diluted earnings per share:
Diluted - Continuing Operations, in dollars per share	(0.53)	0.93	0.44	0.53	(0.73)	0.79	0.15	0.29	1.37	0.51	0.90
Diluted - Discontinued Operations, in dollars per share	0	0	0	0	0	0	0	0.20	0	0.20	0.04
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share	$ (0.53)	$ 0.93	$ 0.44	$ 0.53	$ (0.73)	$ 0.79	$ 0.15	$ 0.49	$ 1.37	$ 0.71	$ 0.94
Shares excluded from the calculation of diluted shares outstanding, in shares									1	2	2

Organization and Basis of Pre61

Organization and Basis of Presentation (Details 3) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment
In service	$ 49,952	$ 47,484
Less - Accumulated depreciation	(15,160)	(14,150)
Property, plant and equipment in service net of accumulated provision for depreciation	34,792	33,334
Capital leased assets	253	281
Regulated Distribution
Property, Plant and Equipment
In service	24,553	23,973
Less - Accumulated depreciation	(7,058)	(6,759)
Property, plant and equipment in service net of accumulated provision for depreciation	17,495	17,214
Regulated Transmission
Property, Plant and Equipment
In service	7,703	6,634
Less - Accumulated depreciation	(1,647)	(1,595)
Property, plant and equipment in service net of accumulated provision for depreciation	6,056	5,039
Competitive Energy Services
Property, Plant and Equipment
In service	17,214	16,442
Less - Accumulated depreciation	(6,213)	(5,598)
Property, plant and equipment in service net of accumulated provision for depreciation	11,001	10,844
Other/Corporate
Property, Plant and Equipment
In service	482	435
Less - Accumulated depreciation	(242)	(198)
Property, plant and equipment in service net of accumulated provision for depreciation	$ 240	$ 237

Organization and Basis of Pre62

Organization and Basis of Presentation (Details 4)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Annual Composite Depreciation Rate
Annual Composite Depreciation Rate (percent)	2.50%	2.50%	2.60%
FES
Annual Composite Depreciation Rate
Annual Composite Depreciation Rate (percent)	3.20%	3.10%	3.10%

Organization and Basis of Pre63

Organization and Basis of Presentation (Details 5) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Summary of changes in goodwill
Goodwill, Ending Balance	$ 6,418	$ 6,418
Regulated Distribution
Summary of changes in goodwill
Goodwill, Ending Balance	5,092	5,092
Regulated Transmission
Summary of changes in goodwill
Goodwill, Ending Balance	526
Competitive Energy Services
Summary of changes in goodwill
Goodwill, Ending Balance	$ 800	$ 800

Organization and Basis of Pre64

Organization and Basis of Presentation (Details Textuals) mi in Thousands, customer in Millions, $ in Millions	Oct. 09, 2013USD ($)MW	Jul. 08, 2013USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2015USD ($)customertransmission_centercompanymiMW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Regulatory Assets [Line Items]
Length of transmission lines | mi				24
Number of regional transmission centers | transmission_center				2
Regulatory assets that do not earn a current return				$ 148	$ 488
Net regulatory liabilities				116	243
Cost of nuclear fuel				418
Capitalized financing costs				49	49	$ 28
Interest costs capitalized				68	69	75
Net plant in service				34,792	33,334
Impairments of long-lived assets		$ (473)		(42)	0	(795)
Goodwill			$ 6,418	6,418	6,418	6,418
Other than temporary impairments				$ 102	37	90
Aggregate amount of capacity (in MWs) | MW				17,000
Ownership interest (percent)				3.00%
Deferred Tax Assets, Net, Noncurrent				$ 6,773	6,539
Deferred Tax Liabilities, Net, Noncurrent				$ 6,773	6,539
New Accounting Pronouncement, Early Adoption, Effect [Member]
Regulatory Assets [Line Items]
Deferred Tax Assets, Net, Noncurrent					518
Deferred Tax Liabilities, Net, Noncurrent					(518)
Bath County, Virginia
Regulatory Assets [Line Items]
Plant generation capacity | MW				3,003
Non-core [Member]
Regulatory Assets [Line Items]
Impairments of long-lived assets				$ (42)
Inventories
Regulatory Assets [Line Items]
Impairments of long-lived assets		$ (13)
Regulated Distribution
Regulatory Assets [Line Items]
Number of existing utility operating companies | company				10
Number of customers served by utility operating companies | customer				6
Property, plant and equipment, net				$ 2,000
Plant generation capacity | MW	3,790
Net plant in service				17,495	17,214
Goodwill			5,092	5,092	5,092	5,092
Regulated Distribution | Non-core [Member]
Regulatory Assets [Line Items]
Impairments of long-lived assets				$ (8)
Competitive Energy Services
Regulatory Assets [Line Items]
Plant generation capacity | MW				13,162
Net plant in service				$ 11,001	10,844
Goodwill			800	$ 800	800	800
Percentage of fair value in excess of carrying amount				10.00%
Competitive Energy Services | Non-core [Member]
Regulatory Assets [Line Items]
Impairments of long-lived assets				$ (34)
AE Supply
Regulatory Assets [Line Items]
Percent of ownership interest acquired	8.00%
Value of interest acquired	$ 73
Cash consideration received in asset swap transaction			$ 1,100
Assumption of pollution control note	$ 73.5
MP
Regulatory Assets [Line Items]
Percent of ownership interest acquired	80.00%
Value of interest acquired	$ 1,200
Impairments of long-lived assets						(322)
Regulatory liability						23
AGC | Bath County, Virginia
Regulatory Assets [Line Items]
Pumped storage hydroelectric station ownership percentage				40.00%
Plant generation capacity | MW				1,200
Net plant in service				$ 666
AGC | Competitive Energy Services
Regulatory Assets [Line Items]
Net plant in service				$ 484
Virginia Electric and Power Company | Bath County, Virginia
Regulatory Assets [Line Items]
Pumped storage hydroelectric station ownership percentage				60.00%
FES
Regulatory Assets [Line Items]
Net plant in service				$ 8,546	8,388
Goodwill				23	23
Other than temporary impairments				90	33	$ 79
Deferred Tax Assets, Net, Noncurrent				600	484
Deferred Tax Liabilities, Net, Noncurrent				$ 600	484
FES | New Accounting Pronouncement, Early Adoption, Effect [Member]
Regulatory Assets [Line Items]
Deferred Tax Assets, Net, Noncurrent					27
Deferred Tax Liabilities, Net, Noncurrent					$ (27)
Income Approach Valuation Technique | Goodwill [Member] | Competitive Energy Services
Regulatory Assets [Line Items]
Discount rate				8.25%
Fair Value Inputs, Earnings before Interest, Taxes, Depreciation, and Amortization Multiple				7
Signal Peak | Global Holding | FEV
Regulatory Assets [Line Items]
Impairments of long-lived assets				$ (362)
Ownership interest (percent)				33.33%
Deferred Charges and Other Assets [Member] | New Accounting Pronouncement, Early Adoption, Effect [Member]
Regulatory Assets [Line Items]
Deferred Finance Costs, Net				$ (93)
Deferred Charges and Other Assets [Member] | FES | New Accounting Pronouncement, Early Adoption, Effect [Member]
Regulatory Assets [Line Items]
Deferred Finance Costs, Net				$ (17)

Accumulated Other Comprehensi65

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
AOCI Beginning Balance	$ 246	$ 284	$ 385
Other comprehensive income before reclassifications	24	181	81
Amounts reclassified from AOCI	(146)	(233)	(248)
Other comprehensive loss	(122)	(52)	(167)
Income tax benefits on other comprehensive loss	(47)	(14)	(66)
Other comprehensive loss, net of tax	(75)	(38)	(101)
AOCI Ending Balance	171	246	284
FES
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
AOCI Beginning Balance	57	54	72
Other comprehensive income before reclassifications	25	93	46
Amounts reclassified from AOCI	(43)	(88)	(75)
Other comprehensive loss	(18)	5	(29)
Income tax benefits on other comprehensive loss	(7)	2	(11)
Other comprehensive loss, net of tax	(11)	3	(18)
AOCI Ending Balance	46	57	54
Gains & Losses on Cash Flow Hedges
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
AOCI Beginning Balance	(37)	(36)	(38)
Other comprehensive income before reclassifications	0	0	0
Amounts reclassified from AOCI	5	(2)	3
Other comprehensive loss	5	(2)	3
Income tax benefits on other comprehensive loss	1	(1)	1
Other comprehensive loss, net of tax	4	(1)	2
AOCI Ending Balance	(33)	(37)	(36)
Gains & Losses on Cash Flow Hedges | FES
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
AOCI Beginning Balance	(7)	(1)	3
Other comprehensive income before reclassifications	0	0	0
Amounts reclassified from AOCI	(3)	(10)	(6)
Other comprehensive loss	(3)	(10)	(6)
Income tax benefits on other comprehensive loss	(1)	(4)	(2)
Other comprehensive loss, net of tax	(2)	(6)	(4)
AOCI Ending Balance	(9)	(7)	(1)
Unrealized Gains on AFS Securities
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
AOCI Beginning Balance	25	9	15
Other comprehensive income before reclassifications	14	89	46
Amounts reclassified from AOCI	(25)	(63)	(56)
Other comprehensive loss	(11)	26	(10)
Income tax benefits on other comprehensive loss	(4)	10	(4)
Other comprehensive loss, net of tax	(7)	16	(6)
AOCI Ending Balance	18	25	9
Unrealized Gains on AFS Securities | FES
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
AOCI Beginning Balance	21	8	13
Other comprehensive income before reclassifications	15	80	41
Amounts reclassified from AOCI	(24)	(59)	(49)
Other comprehensive loss	(9)	21	(8)
Income tax benefits on other comprehensive loss	(4)	8	(3)
Other comprehensive loss, net of tax	(5)	13	(5)
AOCI Ending Balance	16	21	8
Defined Benefit Pension & OPEB Plans
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
AOCI Beginning Balance	258	311	408
Other comprehensive income before reclassifications	10	92	35
Amounts reclassified from AOCI	(126)	(168)	(195)
Other comprehensive loss	(116)	(76)	(160)
Income tax benefits on other comprehensive loss	(44)	(23)	(63)
Other comprehensive loss, net of tax	(72)	(53)	(97)
AOCI Ending Balance	186	258	311
Defined Benefit Pension & OPEB Plans | FES
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
AOCI Beginning Balance	43	47	56
Other comprehensive income before reclassifications	10	13	5
Amounts reclassified from AOCI	(16)	(19)	(20)
Other comprehensive loss	(6)	(6)	(15)
Income tax benefits on other comprehensive loss	(2)	(2)	(6)
Other comprehensive loss, net of tax	(4)	(4)	(9)
AOCI Ending Balance	$ 39	$ 43	$ 47

Accumulated Other Comprehensi66

Accumulated Other Comprehensive Income (Details 1) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	$ (952)	$ (850)	$ (916)	$ (1,057)	$ (901)	$ (858)	$ (1,021)	$ (1,182)	$ (3,749)	$ (3,962)	$ (3,593)
Interest expense - other									(1,132)	(1,073)	(1,016)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)									893	171	570
Income taxes (benefits)	170	(226)	(115)	(144)	268	(152)	(26)	(48)	(315)	42	(195)
NET INCOME (LOSS)	(226)	395	187	222	(306)	333	64	208	578	299	392
FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	(329)	(246)	(353)	(413)	(359)	(356)	(468)	(452)	(1,341)	(1,635)	(1,487)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)									147	(588)	52
Income taxes (benefits)	(1)	(70)	4	2	133	(28)	67	56	(65)	228	(6)
NET INCOME (LOSS)	$ (14)	$ 120	$ (21)	$ (3)	$ (214)	$ 44	$ (87)	$ 13	82	(244)	60
Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)									5	(2)	3
Income taxes (benefits)									(1)	1	(1)
NET INCOME (LOSS)									4	(1)	2
Reclassifications from AOCI | Gains & losses on cash flow hedges | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)									(3)	(10)	(6)
Income taxes (benefits)									1	4	2
NET INCOME (LOSS)									(2)	(6)	(4)
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses									(3)	(10)	(8)
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses									(3)	(10)	(8)
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense - other									8	8	11
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense - other									0	0	2
Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income									(25)	(63)	(56)
Income taxes (benefits)									9	24	21
NET INCOME (LOSS)									(16)	(39)	(35)
Reclassifications from AOCI | Unrealized gains on AFS securities | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income									(24)	(59)	(49)
Income taxes (benefits)									9	22	18
NET INCOME (LOSS)									(15)	(37)	(31)
Reclassifications from AOCI | Defined benefit pension and OPEB plans
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs									(126)	(168)	(195)
Income taxes (benefits)									49	65	75
NET INCOME (LOSS)									(77)	(103)	(120)
Reclassifications from AOCI | Defined benefit pension and OPEB plans | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs									(16)	(19)	(20)
Income taxes (benefits)									6	7	8
NET INCOME (LOSS)									$ (10)	$ (12)	$ (12)

Pension and Other Postemploym67

Pension and Other Postemployment Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Change in fair value of plan assets:
Company contributions	$ 143
Amounts Recognized on the Balance Sheet:
Noncurrent liabilities	(4,245)	$ (3,932)
Pensions
Change in benefit obligation:
Benefit obligation as of January 1	9,249	8,263
Service cost	193	167	$ 197
Interest cost	383	402	372
Plan participants' contributions	0	0
Plan amendments	0	5
Medicare retiree drug subsidy	0	0
Actuarial (gain) loss	(277)	1,123
Benefits paid	(469)	(711)
Benefit obligation as of December 31	9,079	9,249	8,263
Change in fair value of plan assets:
Fair value of plan assets as of January 1	5,824	6,171
Actual return (losses) on plan assets	(178)	349
Company contributions	161	15
Plan participants' contributions	0	0
Benefits paid	(469)	(711)
Fair value of plan assets as of December 31	5,338	5,824	6,171
Funded Status:
Funded Status	(3,741)	(3,425)
Accumulated benefit obligation	8,579	8,744
Amounts Recognized on the Balance Sheet:
Current liabilities	(18)	(17)
Noncurrent liabilities	(3,723)	(3,408)
Net liability as of December 31	(3,741)	(3,425)
Amounts Recognized in AOCI:
Prior service cost (credit)	$ 37	$ 45
Assumptions Used to Determine Benefit Obligations
Discount rate	4.50%	4.25%
Rate of compensation increase	4.20%	4.20%
Allocation of Plan Assets
Asset Allocation	100.00%	100.00%
Pensions | Equity securities
Allocation of Plan Assets
Asset Allocation	40.00%	36.00%
Pensions | Bonds
Allocation of Plan Assets
Asset Allocation	34.00%	33.00%
Pensions | Absolute return strategies
Allocation of Plan Assets
Asset Allocation	7.00%	14.00%
Pensions | Real estate
Allocation of Plan Assets
Asset Allocation	11.00%	7.00%
Pensions | Derivatives
Allocation of Plan Assets
Asset Allocation	0.00%	1.00%
Pensions | Cash
Allocation of Plan Assets
Asset Allocation	8.00%	9.00%
Pensions | Qualified Plan
Funded Status:
Funded Status	$ (3,366)	$ (3,064)
Pensions | Non-qualified Plans
Funded Status:
Funded Status	(375)	(361)
OPEB
Change in benefit obligation:
Benefit obligation as of January 1	757	879
Service cost	5	9	13
Interest cost	29	39	37
Plan participants' contributions	6	16
Plan amendments	(10)	(97)
Medicare retiree drug subsidy	1	0
Actuarial (gain) loss	(2)	13
Benefits paid	(62)	(102)
Benefit obligation as of December 31	724	757	879
Change in fair value of plan assets:
Fair value of plan assets as of January 1	464	495
Actual return (losses) on plan assets	6	38
Company contributions	17	17
Plan participants' contributions	6	16
Benefits paid	(62)	(102)
Fair value of plan assets as of December 31	431	464	$ 495
Funded Status:
Funded Status	(293)	(293)
Accumulated benefit obligation	0	0
Amounts Recognized on the Balance Sheet:
Current liabilities	0	0
Noncurrent liabilities	(293)	(293)
Net liability as of December 31	(293)	(293)
Amounts Recognized in AOCI:
Prior service cost (credit)	$ (355)	$ (479)
Assumptions Used to Determine Benefit Obligations
Discount rate	4.25%	4.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	4.50%	4.50%
Allocation of Plan Assets
Asset Allocation	100.00%	100.00%
OPEB | Equity securities
Allocation of Plan Assets
Asset Allocation	51.00%	49.00%
OPEB | Bonds
Allocation of Plan Assets
Asset Allocation	43.00%	40.00%
OPEB | Absolute return strategies
Allocation of Plan Assets
Asset Allocation	0.00%	1.00%
OPEB | Real estate
Allocation of Plan Assets
Asset Allocation	0.00%	1.00%
OPEB | Derivatives
Allocation of Plan Assets
Asset Allocation	0.00%	0.00%
OPEB | Cash
Allocation of Plan Assets
Asset Allocation	6.00%	9.00%
OPEB | Pre Medicare
Assumptions Used to Determine Benefit Obligations
Health care cost trend rate assumed	6.00%	7.50%
Year that the rate reaches the ultimate trend rate	2,026	2,026
OPEB | Post Medicare
Assumptions Used to Determine Benefit Obligations
Health care cost trend rate assumed	5.50%	7.00%
Year that the rate reaches the ultimate trend rate	2,026	2,026

Pension and Other Postemploym68

Pension and Other Postemployment Benefits (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 193	$ 167	$ 197
Interest cost	383	402	372
Expected return on plan assets	(443)	(462)	(501)
Amortization of prior service cost (credit)	8	8	12
Pension & OPEB mark-to-market adjustment	344	1,235	(267)
Net periodic cost (credit)	485	1,350	(187)
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	5	9	13
Interest cost	29	39	37
Expected return on plan assets	(33)	(34)	(34)
Amortization of prior service cost (credit)	(134)	(176)	(207)
Pension & OPEB mark-to-market adjustment	25	8	(129)
Net periodic cost (credit)	$ (108)	$ (154)	$ (320)

Pension and Other Postemploym69

Pension and Other Postemployment Benefits (Details 2)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term return on plan assets	7.50%
Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted-average discount rate		4.25%	5.00%	4.25%
Expected long-term return on plan assets		7.75%	7.75%	7.75%
Rate of compensation increase		4.20%	4.20%	4.70%
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted-average discount rate		4.00%	4.75%	4.00%
Expected long-term return on plan assets		7.75%	7.75%	7.75%

Pension and Other Postemploym70

Pension and Other Postemployment Benefits (Details 3) - Pensions - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 5,345	$ 5,732
Asset Allocation	100.00%	100.00%
Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 427	$ 517
Asset Allocation	8.00%	9.00%
Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 944	$ 1,274
Asset Allocation	18.00%	22.00%
International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 1,189	$ 769
Asset Allocation	22.00%	14.00%
Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 232	$ 159
Asset Allocation	4.00%	3.00%
Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 1,115	$ 1,386
Asset Allocation	21.00%	24.00%
High yield debt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 438	$ 300
Asset Allocation	8.00%	5.00%
Mortgaged-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 31	$ 37
Asset Allocation	1.00%	1.00%
Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 343	$ 809
Asset Allocation	7.00%	14.00%
Derivatives
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 15	$ 35
Asset Allocation	0.00%	1.00%
Private equity funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 24	$ 25
Asset Allocation	0.00%	0.00%
Real estate funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 587	$ 421
Asset Allocation	11.00%	7.00%
Level 1
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 1,264	$ 1,621
Level 1 | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	869	1,266
Level 1 | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	395	355
Level 1 | Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | High yield debt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Mortgaged-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Derivatives
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Private equity funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Real estate funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 2
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	3,470	3,665
Level 2 | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	427	517
Level 2 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	75	8
Level 2 | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	794	414
Level 2 | Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	232	159
Level 2 | Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	1,115	1,386
Level 2 | High yield debt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	438	300
Level 2 | Mortgaged-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	31	37
Level 2 | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	343	809
Level 2 | Derivatives
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	15	35
Level 2 | Private equity funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 2 | Real estate funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	611	446
Level 3 | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | High yield debt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Mortgaged-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Derivatives
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Private equity funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	24	25	$ 27
Level 3 | Real estate funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 587	$ 421	$ 385

Pension and Other Postemploym71

Pension and Other Postemployment Benefits (Details 4) - Pensions - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of changes in the fair value of pension investments
Beginning balance	$ 5,732
Actual return on plan assets:
Ending balance	5,345	$ 5,732
Private equity funds
Reconciliation of changes in the fair value of pension investments
Beginning balance	25
Actual return on plan assets:
Ending balance	24	25
Real estate funds
Reconciliation of changes in the fair value of pension investments
Beginning balance	421
Actual return on plan assets:
Ending balance	587	421
Level 3
Reconciliation of changes in the fair value of pension investments
Beginning balance	446
Actual return on plan assets:
Ending balance	611	446
Level 3 | Private equity funds
Reconciliation of changes in the fair value of pension investments
Beginning balance	25	27
Actual return on plan assets:
Unrealized gains (losses)	0	(2)
Realized gains (losses)	(1)	1
Transfers in (out)	0	(1)
Ending balance	24	25
Level 3 | Real estate funds
Reconciliation of changes in the fair value of pension investments
Beginning balance	421	385
Actual return on plan assets:
Unrealized gains (losses)	42	17
Realized gains (losses)	16	14
Transfers in (out)	108	5
Ending balance	$ 587	$ 421

Pension and Other Postemploym72

Pension and Other Postemployment Benefits (Details 5) - OPEB - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 438	$ 473
Asset Allocation	100.00%	100.00%
Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 25	$ 41
Asset Allocation	6.00%	9.00%
Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 219	$ 230
Asset Allocation	50.00%	48.00%
International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 4	$ 6
Asset Allocation	1.00%	1.00%
U.S. treasuries
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 42	$ 41
Asset Allocation	10.00%	9.00%
Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 114	$ 110
Asset Allocation	26.00%	23.00%
Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 27	$ 32
Asset Allocation	6.00%	7.00%
High yield debt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 1	$ 2
Asset Allocation	0.00%	0.00%
Mortgaged-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 3	$ 3
Asset Allocation	1.00%	1.00%
Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 1	$ 5
Asset Allocation	0.00%	1.00%
Real estate funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 2	$ 3
Asset Allocation	0.00%	1.00%
Level 1
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 220	$ 233
Level 1 | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	219	230
Level 1 | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	1	3
Level 1 | U.S. treasuries
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | High yield debt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Mortgaged-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Real estate funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 2
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	216	237
Level 2 | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	25	41
Level 2 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 2 | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	3	3
Level 2 | U.S. treasuries
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	42	41
Level 2 | Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	114	110
Level 2 | Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	27	32
Level 2 | High yield debt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	1	2
Level 2 | Mortgaged-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	3	3
Level 2 | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	1	5
Level 2 | Real estate funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	2	3
Level 3 | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | U.S. treasuries
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | High yield debt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Mortgaged-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Real estate funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 2	$ 3	$ 5

Pension and Other Postemploym73

Pension and Other Postemployment Benefits (Details 6) - OPEB - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of changes in the fair value of pension investments
Beginning balance	$ 473
Actual return on plan assets:
Ending balance	438	$ 473
Real estate funds
Reconciliation of changes in the fair value of pension investments
Beginning balance	3
Actual return on plan assets:
Ending balance	2	3
Level 3
Reconciliation of changes in the fair value of pension investments
Beginning balance	3
Actual return on plan assets:
Ending balance	2	3
Level 3 | Real estate funds
Reconciliation of changes in the fair value of pension investments
Beginning balance	3	5
Actual return on plan assets:
Transfers in (out)	(1)	(2)
Ending balance	$ 2	$ 3

Pension and Other Postemploym74

Pension and Other Postemployment Benefits (Details 7)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations	100.00%	100.00%
Equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations	38.00%	42.00%
Fixed income
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations	30.00%	32.00%
Absolute return strategies
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations	8.00%	14.00%
Real estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations	10.00%	5.00%
Alternative Investments [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations	8.00%	1.00%
Cash
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations	6.00%	6.00%

Pension and Other Postemploym75

Pension and Other Postemployment Benefits (Details 8) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Compensation and Retirement Disclosure [Abstract]
Effect of One percentage point increase on total of service and interest cost	$ 1
Effect of One percentage point increase on accumulated postretirement benefit obligation	26
Effect of One percentage point decrease on total of service and interest cost	(1)
Effect of One percentage point decrease on accumulated postretirement benefit obligation	$ (23)

Pension and Other Postemploym76

Pension and Other Postemployment Benefits (Details 9) $ in Millions	Dec. 31, 2015USD ($)
Pensions
Estimated Future Benefit Payments
2,016	$ 484
2,017	505
2,018	522
2,019	533
2,020	551
2021-2025	2,946
OPEB | Employer Subsidized Benefit
Estimated Future Benefit Payments
2,016	54
2,017	54
2,018	54
2,019	54
2,020	54
2021-2025	259
OPEB | Medicare Rx Reimbursement
Subsidy Receipts
2,016	(3)
2,017	(3)
2,018	(3)
2,019	(3)
2,020	(3)
Years 2021-2025	$ (9)

Pension and Other Postemploym77

Pension and Other Postemployment Benefits (Details 10) - FES - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net (Liability) Asset	$ (303)	$ (295)
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net (Liability) Asset	$ 25	$ 10

Pension and Other Postemploym78

Pension and Other Postemployment Benefits (Details 11) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net Periodic Cost (Credit)	$ 485	$ 1,350	$ (187)
Pensions | FES
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net Periodic Cost (Credit)	10	150	(30)
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net Periodic Cost (Credit)	(108)	(154)	(320)
OPEB | FES
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net Periodic Cost (Credit)	$ (22)	$ (24)	$ (40)

Pension and Other Postemploym79

Pension and Other Postemployment Benefits (Details Textuals) - USD ($) $ in Millions	2 Months Ended	12 Months Ended
	Feb. 16, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 01, 2014
Defined Benefit Plan Disclosure [Line Items]
Mark-to-market adjustment			$ 369	$ 1,243	$ (396)
Mark-to-market adjustment, net of capitalized amounts			242	835	(256)
Company contributions			143
Estimated 2016 contributions			$ 381
Expected long-term return on plan assets		7.50%
Decrease in mortality rate (percent)			0.25%
Pensions and OPEB
Defined Benefit Plan Disclosure [Line Items]
Actual return (losses) on plan assets			$ (172)	$ 387	$ (22)
Actual return on plan assets (percent)			(2.70%)	6.20%	(0.30%)
Expected return on plan assets			$ 476	$ 496	$ 535
Pensions
Defined Benefit Plan Disclosure [Line Items]
Decrease in underfunded status						$ 40
Company contributions			161	15
Actual return (losses) on plan assets			$ (178)	$ 349
Expected long-term return on plan assets			7.75%	7.75%	7.75%
Expected return on plan assets			$ 443	$ 462	$ 501
Increase in benefit obligation due to RP2014 mortality table			49
Estimated amortization of prior service costs (credits) from AOCI in next fiscal year			8
Excluded from total investments			(7)	92
OPEB
Defined Benefit Plan Disclosure [Line Items]
Effect of plan amendment on accumulated benefit obligation			10	97
Company contributions			17	17
Actual return (losses) on plan assets			$ 6	$ 38
Expected long-term return on plan assets			7.75%	7.75%	7.75%
Expected return on plan assets			$ 33	$ 34	$ 34
Increase in benefit obligation due to RP2014 mortality table			1
Estimated amortization of prior service costs (credits) from AOCI in next fiscal year			(80)
Excluded from total investments			$ (7)	$ (9)
Subsequent Event
Defined Benefit Plan Disclosure [Line Items]
Company contributions	$ 160

Stock-Based Compensation Plan80

Stock-Based Compensation Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost	$ 89	$ 69	$ 60
Stock-based compensation costs capitalized	32	23	20
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost	46	26	36
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost	2	5	6
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost	0	5	(10)
401(k) Savings Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost	38	25	25
EDCP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost	3	8	3
FES
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost	11	9	9
Stock-based compensation costs capitalized	1	1	1
FES | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost	6	4	6
FES | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost	0	1	(1)
FES | 401(k) Savings Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost	$ 5	$ 4	$ 4

Stock-Based Compensation Plan81

Stock-Based Compensation Plans (Details 1) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Weighted-Average Grant Date Fair Value
Dividend shares earned during period, number of shares	89,681
Restricted Stock Units (RSUs)
Shares
Nonvested, Beginning balance (shares)	2,069,518
Granted (shares)	1,157,755
Forfeited (shares)	(231,271)
Vested (shares)	(559,114)
Nonvested, Ending balance (shares)	2,436,888	2,069,518
Weighted-Average Grant Date Fair Value
Beginning balance (in dollars per share)	$ 37.65
Granted (in dollars per share)	35.27	$ 32.17	$ 39.90
Forfeited (in dollars per share)	34.19
Vested (in dollars per share)	44.58
Ending balance (in dollars per share)	$ 35.26	$ 37.65
Restricted Stock
Shares
Nonvested, Beginning balance (shares)	342,286
Granted (shares)	65,434
Forfeited (shares)	(26,079)
Vested (shares)	(190,985)
Nonvested, Ending balance (shares)	190,656	342,286
Weighted-Average Grant Date Fair Value
Beginning balance (in dollars per share)	$ 45.29
Granted (in dollars per share)	32.98	$ 32.71	$ 42.53
Forfeited (in dollars per share)	57.58
Vested (in dollars per share)	43.17
Ending balance (in dollars per share)	$ 40.65	$ 45.29
Dividend shares earned during period, number of shares	52,872

Stock-Based Compensation Plan82

Stock-Based Compensation Plans (Details 2) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Options exercisable (in shares)	1,211,358	1,077,988
Number of Shares
Beginning option balance (shares)	1,439,145
Options exercised (in shares)	(18,551)
Options forfeited (in shares)	(8,623)
Ending option balance (shares)	1,411,971
Weighted Average Exercise Price
Beginning balance (in dollars per share)	$ 44.83
Options exercised (in dollars per share)	29.53
Options forfeited (in dollars per share)	68.02
Ending balance (in dollars per share)	$ 44.89

Stock-Based Compensation Plan83

Stock-Based Compensation Plans (Details Textuals) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation award number of shares available for future	9,900,000
Stock-based compensation award vesting period	3 years
Realized tax benefits	$ 10	$ 13	$ 13
Tax benefit associated with stock-based compensation expense	$ 12	14	23
Stock option expiration period	10 years
Stock options granted in period (shares)	0
Share-based liabilities paid	$ 0	3	$ 0
EDCP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferral period (years)	3 years
DCPD
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net liability recognized	$ 9	$ 8
Performance-based Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award paid in stock (percent)	66.67%
Award paid in cash (percent)	33.33%
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation award vesting period	3 years
Granted (in dollars per share)	$ 35.27	$ 32.17	$ 39.90
Fair value of restricted stock units vested	$ 22	$ 28	$ 37
Unrecognized cost	32
Liability recognized	$ 3
Unrecognized cost, period for recognition	2 years
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining contractual life	3 years 7 months
Proceeds from options exercised	$ 1	$ 1	$ 19
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation award vesting period	3 years	3 years
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in dollars per share)	$ 32.98	$ 32.71	$ 42.53
Fair value of restricted stock units vested	$ 8	$ 4	$ 7
Unrecognized cost	$ 3
Unrecognized cost, period for recognition	3 years
Weighted average vesting period (years)	5 years 7 months 3 days
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation award vesting period	1 year
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation award vesting period	10 years
FES
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Tax benefit associated with stock-based compensation expense	$ 2	$ 2	$ 1
ICP 2007 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum limit of total stock awards (in shares)	29,000,000
ICP 2015 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum limit of total stock awards (in shares)	10,000,000
401(k) Savings Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for issuance	1,072,494	756,412
Contributed to participants accounts (in shares)			708,000

Taxes (Details)

Taxes (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Currently payable (receivable)-
Federal									$ 1	$ (132)	$ (118)
State									30	(72)	70
Currently payable (receivable) Total									31	(204)	(48)
Deferred, net-
Federal									277	214	305
State									15	(42)	(54)
Deferred Tax Total									292	172	251
Investment tax credit amortization									(8)	(10)	(8)
Total provision for income taxes	$ (170)	$ 226	$ 115	$ 144	$ (268)	$ 152	$ 26	$ 48	315	(42)	195
Internal Revenue Service (IRS)
Deferred, net-
Current tax effect of discontinued operation										106
Deferred tax effect of discontinued operation										44
State and Local
Deferred, net-
Current tax effect of discontinued operation										12
Deferred tax effect of discontinued operation										5
FES
Currently payable (receivable)-
Federal									(56)	(222)	(300)
State									2	(13)	(3)
Currently payable (receivable) Total									(54)	(235)	(303)
Deferred, net-
Federal									103	25	317
State									18	(14)	(4)
Deferred Tax Total									121	11	313
Investment tax credit amortization									(2)	(4)	(4)
Total provision for income taxes	$ 1	$ 70	$ (4)	$ (2)	$ (133)	$ 28	$ (67)	$ (56)	$ 65	$ (228)	$ 6

Taxes (Details 1)

Taxes (Details 1) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes
Income from Continuing Operations before income taxes									$ 893	$ 171	$ 570
Federal income tax expense at statutory rate (35%)									313	60	199
Increases (reductions) in taxes resulting from-
State income taxes, net of federal tax benefit									34	12	10
AFUDC equity and other flow-through									(16)	(13)	(7)
Amortization of investment tax credits									(8)	(10)	(8)
Change in accounting method									(8)	(27)	0
ESOP dividend									(6)	(6)	(9)
Tax basis balance sheet adjustments									0	(25)	0
Uncertain tax positions									1	(35)	(2)
Other, net									5	2	12
Total provision for income taxes	$ (170)	$ 226	$ 115	$ 144	$ (268)	$ 152	$ 26	$ 48	$ 315	$ (42)	$ 195
Effective income tax rate (percent)									35.30%	(24.60%)	34.20%
FES
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes
Income from Continuing Operations before income taxes									$ 147	$ (588)	$ 52
Federal income tax expense at statutory rate (35%)									51	(206)	18
Increases (reductions) in taxes resulting from-
State income taxes, net of federal tax benefit									16	(14)	(5)
Amortization of investment tax credits									(2)	(4)	(4)
ESOP dividend									(1)	(1)	(2)
Uncertain tax positions									5	0	0
Other, net									(4)	(3)	(1)
Total provision for income taxes	$ 1	$ 70	$ (4)	$ (2)	$ (133)	$ 28	$ (67)	$ (56)	$ 65	$ (228)	$ 6
Effective income tax rate (percent)									44.20%	38.80%	11.50%

Taxes (Details 2)

Taxes (Details 2) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accumulated deferred income taxes
Property basis differences	$ 9,920	$ 9,354
Deferred sale and leaseback gain	(360)	(381)
Pension and OPEB	(1,541)	(1,433)
Nuclear decommissioning activities	480	458
Asset retirement obligations	(731)	(641)
Regulatory asset/liability	763	768
Loss carryforwards and AMT credits	(1,965)	(1,932)
Loss carryforward valuation reserve	192	174
All other	15	172
Net deferred income tax liability	6,773	6,539
FES
Accumulated deferred income taxes
Property basis differences	1,901	1,749
Deferred sale and leaseback gain	(342)	(356)
Pension and OPEB	(393)	(373)
Lease market valuation liability	95	75
Nuclear decommissioning activities	483	489
Asset retirement obligations	(509)	(486)
Loss carryforwards and AMT credits	(687)	(631)
Loss carryforward valuation reserve	46	32
All other	6	(15)
Net deferred income tax liability	$ 600	$ 484

Taxes (Details 3)

Taxes (Details 3) $ in Millions	Dec. 31, 2015USD ($)
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	$ 10,000
State Jurisdiction
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	7,176
State Jurisdiction | 2016-2020
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	403
State Jurisdiction | 2021-2025
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,323
State Jurisdiction | 2023-2030
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	2,205
State Jurisdiction | 2031-2035
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	3,245
Local Jurisdiction
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	2,983
Local Jurisdiction | 2016-2020
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	2,983
Local Jurisdiction | 2021-2025
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
Local Jurisdiction | 2023-2030
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
Local Jurisdiction | 2031-2035
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
FES | State Jurisdiction
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,550
FES | State Jurisdiction | 2016-2020
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	95
FES | State Jurisdiction | 2021-2025
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	68
FES | State Jurisdiction | 2023-2030
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	259
FES | State Jurisdiction | 2031-2035
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,128
FES | Local Jurisdiction
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,820
FES | Local Jurisdiction | 2016-2020
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,820
FES | Local Jurisdiction | 2021-2025
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
FES | Local Jurisdiction | 2023-2030
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
FES | Local Jurisdiction | 2031-2035
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	$ 0

Taxes (Details 4)

Taxes (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net interest expense (income) and cumulative net interest payable (receivable)
Net Interest Expense (Income)	$ (1)	$ (6)	$ 1
Net Interest Payable	$ 1	$ 2

Taxes (Details 5)

Taxes (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in unrecognized tax benefits
Beginning balance	$ 34	$ 48	$ 43
Current year increases	3	4
Prior years increases	7	5	10
Prior years decreases	(10)	(23)	(5)
Ending balance	34	34	48
FES
Changes in unrecognized tax benefits
Beginning balance	3	3	3
Current year increases	0	0
Prior years increases	5	0	0
Prior years decreases	0	0	0
Ending balance	$ 8	$ 3	$ 3

Taxes (Details 6)

Taxes (Details 6) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
General Taxes
Total general taxes	$ 978	$ 962	$ 978
KWH excise
General Taxes
Total general taxes	193	194	219
State gross receipts
General Taxes
Total general taxes	224	226	240
Real and personal property
General Taxes
Total general taxes	410	393	368
Social security and unemployment
General Taxes
Total general taxes	119	112	110
Other
General Taxes
Total general taxes	32	37	41
FES
General Taxes
Total general taxes	98	128	138
FES | State gross receipts
General Taxes
Total general taxes	44	69	77
FES | Real and personal property
General Taxes
Total general taxes	36	39	40
FES | Social security and unemployment
General Taxes
Total general taxes	16	17	19
FES | Other
General Taxes
Total general taxes	$ 2	$ 3	$ 2

Taxes (Details Textuals)

Taxes (Details Textuals) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes (Textuals) [Abstract]
Effective income tax rate (percent)		35.30%	(24.60%)	34.20%
Change in accounting method		$ (8)	$ (27)	$ 0
Tax basis balance sheet adjustments	$ (16)		25
Pre-tax net operating loss carryforwards for state and local income tax purposes		10,000
Pre-tax net operating loss carryforwards expected to utilized		6,000
Unrecognized tax benefits	34	34	34	48	$ 43
Unrecognized tax benefits that would impact future tax rates		29
Unrecognized tax benefits, portion expected to be resolved in the next fiscal year		9
Unrecognized tax benefits that would impact effective tax rate		7
Reduction in effective tax rate		1	$ 6
Increase of accrued interest				$ 1
Federal
Income Taxes (Textuals) [Abstract]
Operating loss carryforwards, not subject to expiration		26
Operating loss carryforwards, subject to expiration		1,500
State and Local
Income Taxes (Textuals) [Abstract]
Operating loss carryforwards, subject to expiration		$ 398
FES
Income Taxes (Textuals) [Abstract]
Effective income tax rate (percent)		44.20%	38.80%	11.50%
Unrecognized tax benefits	$ 3	$ 8	$ 3	$ 3	$ 3

Leases (Details)

Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Rentals for capital and operating leases
Operating leases	$ 174	$ 199	$ 224
FES
Rentals for capital and operating leases
Operating leases	$ 94	$ 95	$ 97

Leases (Details 1)

Leases (Details 1) $ in Millions	Dec. 31, 2015USD ($)
Future minimum capital lease payments
2,016	$ 36
2,017	31
2,018	24
2,019	18
2,020	14
Years thereafter	27
Total minimum lease payments	150
Interest portion	(18)
Present value of net minimum lease payments	132
Less current portion	32
Noncurrent portion	100
FES
Future minimum capital lease payments
2,016	6
2,017	6
2,018	2
2,019	0
2,020	0
Years thereafter	0
Total minimum lease payments	14
Interest portion	(1)
Present value of net minimum lease payments	13
Less current portion	5
Noncurrent portion	$ 8

Leases (Details 2)

Leases (Details 2) $ in Millions	Dec. 31, 2015USD ($)
Future minimum operating lease payments
2,016	$ 184
2,017	119
2,018	135
2,019	116
2,020	91
Years thereafter	1,438
Total minimum lease payments	2,083
Lease Payments
Future minimum operating lease payments
2,016	197
2,017	122
2,018	135
2,019	116
2,020	91
Years thereafter	1,438
Total minimum lease payments	2,099
PNBV Capital Trust
Future minimum operating lease payments
2,016	13
2,017	3
2,018	0
2,019	0
2,020	0
Years thereafter	0
Total minimum lease payments	16
FES
Future minimum operating lease payments
2,016	131
2,017	82
2,018	101
2,019	97
2,020	68
Years thereafter	1,315
Total minimum lease payments	$ 1,794

Leases (Details Textuals)

Leases (Details Textuals) $ in Millions	Feb. 12, 2014USD ($)MW	Nov. 30, 2014USD ($)MW	Dec. 31, 2007	Dec. 30, 1987	Dec. 31, 2015
Leases (Textuals) [Abstract]
Period of lease terms on the portions sold by OE of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 in years				29 years
Period of lease terms on the portions sold by CEI and TE of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units				30 years
Beaver Valley Unit 2
Leases (Textuals) [Abstract]
Percentage leased					2.60%
Bruce Mansfield Unit 1
Leases (Textuals) [Abstract]
Percentage leased					93.83%
Perry Power Plant Unit 1
Leases (Textuals) [Abstract]
Percentage leased					3.75%
FGCO
Leases (Textuals) [Abstract]
Percentage of undivided interest of FGCO in Bruce Mansfield Unit 1			93.825%
FGCO | Bruce Mansfield Unit 1
Leases (Textuals) [Abstract]
Basic terms of operating lease			33 years
Nuclear Generation Corp | Beaver Valley Unit 2
Leases (Textuals) [Abstract]
Purchase of lessor equity interests in sale and leaseback (in MW) | MW	47.7
Purchase of lessor equity interests in sale and leaseback, value | $	$ 94
Nuclear Generation Corp | Perry Power Plant Unit 1
Leases (Textuals) [Abstract]
Purchase of lessor equity interests in sale and leaseback (in MW) | MW		55.3
Purchase of lessor equity interests in sale and leaseback, value | $		$ 87

Intangible Assets (Details)

Intangible Assets (Details) - USD ($) $ in Millions	Jul. 08, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Intangible Assets (Textuals) [Abstract]
Intangible Assets, Gross		$ 882
Intangible Assets, Accumulated Amortization		551
Intangible Assets, Net		331
Amortization Expense
Actual, 2015		140
Estimated, 2016		62
Estimated, 2017		55
Estimated, 2018		38
Estimated, 2019		37
Estimated, 2020		14
Estimated, Thereafter		109
Impairments of long-lived assets	$ 473	42	$ 0	$ 795
FES
Intangible Assets (Textuals) [Abstract]
Intangible Assets, Net		61	$ 78
NUG contracts
Intangible Assets (Textuals) [Abstract]
Intangible Assets, Gross		124
Intangible Assets, Accumulated Amortization		25
Intangible Assets, Net		99
Amortization Expense
Actual, 2015		5
Estimated, 2016		5
Estimated, 2017		5
Estimated, 2018		5
Estimated, 2019		5
Estimated, 2020		5
Estimated, Thereafter		74
OVEC
Intangible Assets (Textuals) [Abstract]
Intangible Assets, Gross		54
Intangible Assets, Accumulated Amortization		9
Intangible Assets, Net		45
Amortization Expense
Actual, 2015		2
Estimated, 2016		2
Estimated, 2017		2
Estimated, 2018		2
Estimated, 2019		2
Estimated, 2020		2
Estimated, Thereafter		35
Coal contracts
Intangible Assets (Textuals) [Abstract]
Intangible Assets, Gross		556
Intangible Assets, Accumulated Amortization		430
Intangible Assets, Net		126
Amortization Expense
Actual, 2015		116
Estimated, 2016		38
Estimated, 2017		32
Estimated, 2018		17
Estimated, 2019		17
Estimated, 2020		6
Estimated, Thereafter		0
Impairments of long-lived assets		67
Coal contracts | FES
Amortization Expense
Actual, 2015		5.7
Estimated, 2016		5.7
Estimated, 2017		5.7
Estimated, 2018		5.7
Estimated, 2019		5.7
Coal contracts | Recorded with Regulatory Offset
Intangible Assets (Textuals) [Abstract]
Intangible Assets, Gross		102
Intangible Assets, Net		16
Coal contracts | Recorded with Regulatory Offset | FES
Intangible Assets (Textuals) [Abstract]
Intangible Assets, Gross		40
Intangible Assets, Net		23
Customer Contracts
Intangible Assets (Textuals) [Abstract]
Intangible Assets, Gross		148
Intangible Assets, Accumulated Amortization		87
Intangible Assets, Net		61
Amortization Expense
Actual, 2015		17
Estimated, 2016		17
Estimated, 2017		16
Estimated, 2018		14
Estimated, 2019		13
Estimated, 2020		1
Estimated, Thereafter		$ 0

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	Dec. 31, 2015USD ($)
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	$ 1,225
Discounted Lease Payments, net	950
Net Exposure	275
FES
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	1,155
Discounted Lease Payments, net	933
Net Exposure	$ 222

Variable Interest Entities (D98

Variable Interest Entities (Details Textuals) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)agreemententity	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Variable Interest Entities (Textuals) [Abstract]
Transition bond outstanding	$ 128,000	$ 168,000
Environmental control bonds outstanding	$ 429,000	450,000
Number of contracts that may contain variable interest | entity	1
Ownership interest (percent)	3.00%
Purchased power	$ 4,318,000	4,716,000	$ 3,963,000
Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities | agreement	15
Path-WV
Variable Interest Entities (Textuals) [Abstract]
Percentage of high-voltage transmission line project owned by subsidiary of AE on the Allegheny Series	100.00%
Percentage of high-voltage transmission line project owned by subsidiary of AE on the West Virginia Series	50.00%
Other FE subsidiaries
Variable Interest Entities (Textuals) [Abstract]
Ownership interest (percent)	0.00%
Other FE subsidiaries | Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Purchased power	$ 116,000	185,000
Ohio Funding Companies
Variable Interest Entities (Textuals) [Abstract]
Aggregate Annual Servicing Fees Receivable For Phase-in Recovery Bonds	$ 445
Global Holding | FEV | Signal Peak
Variable Interest Entities (Textuals) [Abstract]
Ownership interest (percent)	33.33%
Phase In Recovery Bonds
Variable Interest Entities (Textuals) [Abstract]
Long-term debt and other long-term obligations	$ 362,000	$ 386,000
Senior Loans | Senior Secured Term Loan | Global Holding
Variable Interest Entities (Textuals) [Abstract]
Long-term debt and other long-term obligations	$ 300,000
Perry Power Plant Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage leased	3.75%
Bruce Mansfield Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage leased	93.83%
Beaver Valley Unit 2
Variable Interest Entities (Textuals) [Abstract]
Percentage leased	2.60%

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Recurring - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Assets
Fair value, assets	$ 2,876	$ 2,832
Liabilities
Fair value, liabilities	(281)	(334)
Net assets (liabilities)	2,595	2,498
FES
Assets
Fair value, assets	1,559	1,520
Liabilities
Fair value, liabilities	(142)	(180)
Net assets (liabilities)	1,417	1,340
Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(131)	(167)
Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(131)	(167)
FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(13)	(14)
FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(11)	(13)
NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(137)	(153)
Corporate debt securities
Assets
Fair value, assets	1,245	1,221
Corporate debt securities | FES
Assets
Fair value, assets	678	655
Commodity contracts | Derivative Assets
Assets
Fair value, assets	228	172
Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	228	172
FTRs | Derivative Assets
Assets
Fair value, assets	8	39
FTRs | Derivative Assets | FES
Assets
Fair value, assets	5	27
NUG contracts | Derivative Assets
Assets
Fair value, assets	1	2
Equity securities
Assets
Fair value, assets	576	592
Equity securities | FES
Assets
Fair value, assets	378	360
Foreign government debt securities
Assets
Fair value, assets	75	76
Foreign government debt securities | FES
Assets
Fair value, assets	59	57
U.S. government debt securities
Assets
Fair value, assets	180	182
U.S. government debt securities | FES
Assets
Fair value, assets	23	46
U.S. state debt securities
Assets
Fair value, assets	246	237
U.S. state debt securities | FES
Assets
Fair value, assets	4	4
Other
Assets
Fair value, assets	317	311
Other | FES
Assets
Fair value, assets	184	199
Level 1
Assets
Fair value, assets	685	648
Liabilities
Fair value, liabilities	(9)	(26)
Net assets (liabilities)	676	622
Level 1 | FES
Assets
Fair value, assets	382	361
Liabilities
Fair value, liabilities	(9)	(26)
Net assets (liabilities)	373	335
Level 1 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(9)	(26)
Level 1 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(9)	(26)
Level 1 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 1 | FTRs | Derivative Liabilities | FES
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 | Corporate debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	4	1
Level 1 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	4	1
Level 1 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 1 | NUG contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | Equity securities
Assets
Fair value, assets	576	592
Level 1 | Equity securities | FES
Assets
Fair value, assets	378	360
Level 1 | Foreign government debt securities
Assets
Fair value, assets	0	0
Level 1 | Foreign government debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | U.S. government debt securities
Assets
Fair value, assets	0	0
Level 1 | U.S. government debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | U.S. state debt securities
Assets
Fair value, assets	0	0
Level 1 | U.S. state debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | Other
Assets
Fair value, assets	105	55
Level 1 | Other | FES
Assets
Fair value, assets	0	0
Level 2
Assets
Fair value, assets	2,182	2,143
Liabilities
Fair value, liabilities	(122)	(141)
Net assets (liabilities)	2,060	2,002
Level 2 | FES
Assets
Fair value, assets	1,172	1,132
Liabilities
Fair value, liabilities	(122)	(141)
Net assets (liabilities)	1,050	991
Level 2 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(122)	(141)
Level 2 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(122)	(141)
Level 2 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2 | FTRs | Derivative Liabilities | FES
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	1,245	1,221
Level 2 | Corporate debt securities | FES
Assets
Fair value, assets	678	655
Level 2 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	224	171
Level 2 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	224	171
Level 2 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 2 | NUG contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | Equity securities
Assets
Fair value, assets	0	0
Level 2 | Equity securities | FES
Assets
Fair value, assets	0	0
Level 2 | Foreign government debt securities
Assets
Fair value, assets	75	76
Level 2 | Foreign government debt securities | FES
Assets
Fair value, assets	59	57
Level 2 | U.S. government debt securities
Assets
Fair value, assets	180	182
Level 2 | U.S. government debt securities | FES
Assets
Fair value, assets	23	46
Level 2 | U.S. state debt securities
Assets
Fair value, assets	246	237
Level 2 | U.S. state debt securities | FES
Assets
Fair value, assets	4	4
Level 2 | Other
Assets
Fair value, assets	212	256
Level 2 | Other | FES
Assets
Fair value, assets	184	199
Level 3
Assets
Fair value, assets	9	41
Liabilities
Fair value, liabilities	(150)	(167)
Net assets (liabilities)	(141)	(126)
Level 3 | FES
Assets
Fair value, assets	5	27
Liabilities
Fair value, liabilities	(11)	(13)
Net assets (liabilities)	(6)	14
Level 3 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 3 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 3 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(13)	(14)
Level 3 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(11)	(13)
Level 3 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(137)	(153)
Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 3 | Corporate debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 3 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 3 | FTRs | Derivative Assets
Assets
Fair value, assets	8	39
Level 3 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	5	27
Level 3 | NUG contracts | Derivative Assets
Assets
Fair value, assets	1	2
Level 3 | Equity securities
Assets
Fair value, assets	0	0
Level 3 | Equity securities | FES
Assets
Fair value, assets	0	0
Level 3 | Foreign government debt securities
Assets
Fair value, assets	0	0
Level 3 | Foreign government debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | U.S. government debt securities
Assets
Fair value, assets	0	0
Level 3 | U.S. government debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | U.S. state debt securities
Assets
Fair value, assets	0	0
Level 3 | U.S. state debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | Other
Assets
Fair value, assets	0	0
Level 3 | Other | FES
Assets
Fair value, assets	$ 0	$ 0

Fair Value Measurements (Det100

Fair Value Measurements (Details 1) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
NUG contracts
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	$ 2	$ 20
Beginning Balance, Derivative Liabilities	(153)	(222)
Beginning Balance, Net	(151)	(202)
Unrealized gain (loss), Derivative Assets	2	2
Unrealized gain (loss), Derivative Liabilities	(49)	(2)
Unrealized gain (loss), Net	(47)	0
Purchases, Derivative Assets	0	0
Purchases, Derivative Liabilities	0	0
Purchases, Net	0	0
Settlements, Derivative Assets	(3)	(20)
Settlements, Derivative Liabilities	65	71
Settlements, Net	62	51
Ending Balance, Derivative Assets	1	2
Ending Balance, Derivative Liabilities	(137)	(153)
Ending Balance, Net	(136)	(151)
FTRs
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	39	4
Beginning Balance, Derivative Liabilities	(14)	(12)
Beginning Balance, Net	25	(8)
Unrealized gain (loss), Derivative Assets	(5)	47
Unrealized gain (loss), Derivative Liabilities	(7)	(1)
Unrealized gain (loss), Net	(12)	46
Purchases, Derivative Assets	22	26
Purchases, Derivative Liabilities	(11)	(16)
Purchases, Net	11	10
Settlements, Derivative Assets	(48)	(38)
Settlements, Derivative Liabilities	19	15
Settlements, Net	(29)	(23)
Ending Balance, Derivative Assets	8	39
Ending Balance, Derivative Liabilities	(13)	(14)
Ending Balance, Net	(5)	25
FES | FTRs
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	27	3
Beginning Balance, Derivative Liabilities	(13)	(11)
Beginning Balance, Net	14	(8)
Unrealized gain (loss), Derivative Assets	2	34
Unrealized gain (loss), Derivative Liabilities	(5)	(1)
Unrealized gain (loss), Net	(3)	33
Purchases, Derivative Assets	9	15
Purchases, Derivative Liabilities	(10)	(16)
Purchases, Net	(1)	(1)
Settlements, Derivative Assets	(33)	(25)
Settlements, Derivative Liabilities	17	15
Settlements, Net	(16)	(10)
Ending Balance, Derivative Assets	5	27
Ending Balance, Derivative Liabilities	(11)	(13)
Ending Balance, Net	$ (6)	$ 14

Fair Value Measurements (Det101

Fair Value Measurements (Details 2) - Level 3 $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)MWh$ / MWh	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ (5)	$ 25	$ (8)
FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(6)	14	(8)
NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(136)	$ (151)	$ (202)
Model | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(5)
Model | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(6)
Model | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ (136)
Model | Minimum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices	(3.9)
Model | Minimum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices	(3.9)
Model | Minimum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power | MWh	400
Fair Value Inputs, Power, Regional Prices	38.10
Model | Maximum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices	6.90
Model | Maximum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices	5.70
Model | Maximum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power | MWh	3,871,000
Fair Value Inputs, Power, Regional Prices	45.60
Model | Weighted Average | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices	1
Model | Weighted Average | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices	0.70
Model | Weighted Average | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power | MWh	839,000
Fair Value Inputs, Power, Regional Prices	40.20

Fair Value Measurements (Det102

Fair Value Measurements (Details 3) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	$ 1,778	$ 1,724
Unrealized Gains	16	27
Fair Value	1,794	1,751
Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	542	533
Unrealized Gains	34	58
Fair Value	576	591
FES | Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	801	788
Unrealized Gains	9	13
Fair Value	810	801
FES | Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	354	329
Unrealized Gains	24	31
Fair Value	$ 378	$ 360

Fair Value Measurements (Det103

Fair Value Measurements (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income
Sales Proceeds	$ 1,534	$ 2,133	$ 2,047
Realized Gains	209	146	92
Realized Losses	(191)	(75)	(46)
OTTI	(102)	(37)	(90)
Interest and Dividend Income	101	96	101
FES
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income
Sales Proceeds	733	1,163	940
Realized Gains	158	113	70
Realized Losses	(134)	(54)	(21)
OTTI	(90)	(33)	(79)
Interest and Dividend Income	$ 57	$ 56	$ 60

Fair Value Measurements (Det104

Fair Value Measurements (Details 5) - Debt Securities - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities
Cost Basis	$ 6	$ 13
Unrealized Gains	2	4
Fair Value	$ 8	$ 17

Fair Value Measurements (Det105

Fair Value Measurements (Details 6) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
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	$ 20,244	$ 19,828
Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	21,519	21,733
FES | 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	3,027	3,097
FES | 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	$ 3,121	$ 3,241

Fair Value Measurements (Det106

Fair Value Measurements (Details Textuals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	$ 7	$ 40
Cash balance excluded from available for sale securities	157	241
Investments not required to be disclosed	255	626
FES
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	1	44
Cash balance excluded from available for sale securities	$ 139	$ 204
NUG contracts
Fair Value of Financial Instruments [Line Items]
Period of future observable data to determine contract price	3 years

Derivative Instruments (Details

Derivative Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair value of derivatives
Derivative Assets	$ 237	$ 213
Derivative Liabilities	(281)	(334)
Current Assets
Fair value of derivatives
Derivative Assets	157	159
Noncurrent Assets
Fair value of derivatives
Derivative Assets	80	54
Current Liabilities
Fair value of derivatives
Derivative Liabilities	(106)	(167)
Noncurrent Liabilities
Fair value of derivatives
Derivative Liabilities	(175)	(167)
Commodity contracts | Current Assets
Fair value of derivatives
Derivative Assets	150	121
Commodity contracts | Noncurrent Assets
Fair value of derivatives
Derivative Assets	78	51
Commodity contracts | Current Liabilities
Fair value of derivatives
Derivative Liabilities	(94)	(154)
Commodity contracts | Noncurrent Liabilities
Fair value of derivatives
Derivative Liabilities	(37)	(13)
FTRs | Current Assets
Fair value of derivatives
Derivative Assets	7	38
FTRs | Noncurrent Assets
Fair value of derivatives
Derivative Assets	1	1
FTRs | Current Liabilities
Fair value of derivatives
Derivative Liabilities	(12)	(13)
FTRs | Noncurrent Liabilities
Fair value of derivatives
Derivative Liabilities	(1)	(1)
NUGs | Noncurrent Assets
Fair value of derivatives
Derivative Assets	1	2
NUGs | Noncurrent Liabilities
Fair value of derivatives
Derivative Liabilities	$ (137)	$ (153)

Derivative Instruments (Deta108

Derivative Instruments (Details 1) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative Assets
Fair Value	$ 237	$ 213
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(133)	(140)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	104	73
Derivative Liabilities
Fair Value	(281)	(334)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	133	140
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	8	35
Net Fair Value	(140)	(159)
Commodity contracts
Derivative Assets
Fair Value	228	172
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(125)	(126)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	103	46
Derivative Liabilities
Fair Value	(131)	(167)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	125	126
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	3	35
Net Fair Value	(3)	(6)
FTRs
Derivative Assets
Fair Value	8	39
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(8)	(14)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	0	25
Derivative Liabilities
Fair Value	(13)	(14)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	8	14
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	5	0
Net Fair Value	0	0
NUGs
Derivative Assets
Fair Value	1	2
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	0	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	1	2
Derivative Liabilities
Fair Value	(137)	(153)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	0	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	$ (137)	$ (153)

Derivative Instruments (Deta109

Derivative Instruments (Details 2) MWh in Millions, MMBTU in Millions	Dec. 31, 2015MMBTUMWh
Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	16
Sales (in MWH or mmBTUs)	49
Net (in MWH or mmBTUs)	(33)
FTRs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	29
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	29
NUGs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	4
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	4
Natural Gas
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs) | MMBTU	83
Sales (in MWH or mmBTUs) | MMBTU	0
Net (in MWH or mmBTUs) | MMBTU	83

Derivative Instruments (Deta110

Derivative Instruments (Details 3) - Not Designated as Hedging Instrument - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Revenues
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	$ 161	$ 62
Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	(130)	365
Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	73	(64)
Realized Gain (Loss) Reclassified	(49)	(44)
Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	(34)	(6)
Interest Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified		14
Commodity contracts | Revenues
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	111	(6)
Commodity contracts | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	(130)	365
Commodity contracts | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	93	(86)
Realized Gain (Loss) Reclassified	0	0
Commodity contracts | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	(34)	(6)
Commodity contracts | Interest Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified		0
FTRs | Revenues
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	50	68
FTRs | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	0	0
FTRs | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	(20)	22
Realized Gain (Loss) Reclassified	(49)	(44)
FTRs | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	0	0
FTRs | Interest Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified		0
Interest rate swaps | Revenues
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified		0
Interest rate swaps | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified		0
Interest rate swaps | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized		0
Realized Gain (Loss) Reclassified		0
Interest rate swaps | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified		0
Interest rate swaps | Interest Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified		14
FES | Commodity contracts | Revenues
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	111	(6)
FES | Commodity contracts | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	(130)	365
FES | Commodity contracts | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	93	(86)
FES | FTRs | Revenues
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	49	67
FES | FTRs | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	(19)	21
Realized Gain (Loss) Reclassified	$ (49)	(43)
FES | Wholesale Sales Contracts | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified		$ 252

Derivative Instruments (Deta111

Derivative Instruments (Details 4) - Not Designated as Hedging Instrument - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	$ (140)	$ (202)
Unrealized gain (loss)	(56)	12
Purchases	12	11
Settlements	49	39
Outstanding net asset (liability), Ending Balance	(135)	(140)
NUGs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(151)	(202)
Unrealized gain (loss)	(47)	(1)
Purchases	0	0
Settlements	62	52
Outstanding net asset (liability), Ending Balance	(136)	(151)
Regulated FTRs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	11	0
Unrealized gain (loss)	(9)	13
Purchases	12	11
Settlements	(13)	(13)
Outstanding net asset (liability), Ending Balance	$ 1	$ 11

Derivative Instruments (Deta112

Derivative Instruments (Details Textuals)	12 Months Ended
	Dec. 31, 2015USD ($)agreement	Dec. 31, 2014USD ($)agreement
Derivative [Line Items]
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	$ 20,000,000	$ 32,000,000
Expected adverse change in quoted market prices of derivative instruments	10.00%
Decrease net income due to adverse change in commodity prices	$ 30,000,000
Period in which LSEs may request direct allocation of FTRs	2 years
Direct allocation of FTRs, cost	$ 0
NUGs
Derivative [Line Items]
Liability position	136,000,000
FTRs
Derivative [Line Items]
Net asset position under commodity derivative contracts	5,000,000
Cash Flow Hedges
Derivative [Line Items]
Unamortized gains or (losses) associated with designated cash flow hedges	11,000,000	8,000,000
Gain (loss) on cash flow hedge expected to be reclassified to earnings in next twelve months	1,000,000
Unamortized gains or losses associated with prior interest rate hedges	42,000,000	$ 50,000,000
Gains (Losses) to be amortized to interest expenses during next twelve months	$ (9,000,000)
Number of forward starting swap agreements accounted for as a cash flow hedge outstanding | agreement	0	0
Fair Value Hedging
Derivative [Line Items]
Gains (Losses) to be amortized to interest expenses during next twelve months	$ 10,000,000
Reclassifications from long-term debt	$ 12,000,000
Number of fixed-for-floating interest rate swap agreements outstanding | agreement	0	0
Interest rate swaps
Derivative [Line Items]
Number of interest rate swaps outstanding | agreement	0	0
FES | Commodity contracts
Derivative [Line Items]
Net asset position under commodity derivative contracts	$ 97,000,000
Collateral posted	26,000,000
Additional collateral related to commodity derivatives	3,000,000
FES | FTRs
Derivative [Line Items]
Collateral posted	6,000,000
Liability position	$ 6,000,000

Capitalization (Details)

Capitalization (Details)	Dec. 31, 2015$ / sharesshares
Preferred stock and preference stock authorizations
Shares Authorized	5,000,000
Par Value | $ / shares	$ 100
Penn
Preferred stock and preference stock authorizations
Shares Authorized	1,200,000
Par Value | $ / shares	$ 100
CEI
Preferred stock and preference stock authorizations
Shares Authorized	4,000,000
JCP&L
Preferred stock and preference stock authorizations
Shares Authorized	15,600,000
ME
Preferred stock and preference stock authorizations
Shares Authorized	10,000,000
PN
Preferred stock and preference stock authorizations
Shares Authorized	11,435,000
PE
Preferred stock and preference stock authorizations
Shares Authorized	10,000,000
Par Value | $ / shares	$ 0.01
WP
Preferred stock and preference stock authorizations
Shares Authorized	32,000,000
Preferred Stock With Par Value $100 | OE
Preferred stock and preference stock authorizations
Shares Authorized	6,000,000
Par Value | $ / shares	$ 100
Preferred Stock With Par Value $100 | TE
Preferred stock and preference stock authorizations
Shares Authorized	3,000,000
Par Value | $ / shares	$ 100
Preferred Stock With Par Value $100 | MP
Preferred stock and preference stock authorizations
Shares Authorized	940,000
Par Value | $ / shares	$ 100
Preferred Stock With Par Value $25 | OE
Preferred stock and preference stock authorizations
Shares Authorized	8,000,000
Par Value | $ / shares	$ 25
Preferred Stock With Par Value $25 | TE
Preferred stock and preference stock authorizations
Shares Authorized	12,000,000
Par Value | $ / shares	$ 25
Preference Stock | OE
Preferred stock and preference stock authorizations
Preference Stock Shares Authorized	8,000,000
Preference Stock | CEI
Preferred stock and preference stock authorizations
Preference Stock Shares Authorized	3,000,000
Preference Stock | TE
Preferred stock and preference stock authorizations
Preference Stock Shares Authorized	5,000,000
Preference Stock Par Value, in dollars per share | $ / shares	$ 25

Capitalization (Details 1)

Capitalization (Details 1) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Schedule of Capitalization [Line Items]
Secured notes	$ 2,098	$ 2,247
Unsecured debt	14,872	14,370
Capital lease obligations	132	160
Unamortized debt premiums (discounts)	(18)	(8)
Unamortized fair value adjustments	5	21
Currently payable long-term debt	(1,166)	(804)
Total long-term debt and other long-term obligations	19,192	19,176
FES
Schedule of Capitalization [Line Items]
Secured notes	342	437
Unsecured debt	2,685	2,660
Capital lease obligations	13	18
Unamortized debt premiums (discounts)	(1)	(1)
Currently payable long-term debt	(512)	(506)
Total long-term debt and other long-term obligations	2,527	2,608
FMBs
Schedule of Capitalization [Line Items]
FMBs	$ 3,269	3,190
FMBs | Minimum
Schedule of Capitalization [Line Items]
Interest rate (percent)	3.34%
FMBs | Maximum
Schedule of Capitalization [Line Items]
Interest rate (percent)	9.74%
Secured notes - fixed rate
Schedule of Capitalization [Line Items]
Secured notes	$ 2,096	2,247
Secured notes - fixed rate | Minimum
Schedule of Capitalization [Line Items]
Interest rate (percent)	0.679%
Secured notes - fixed rate | Maximum
Schedule of Capitalization [Line Items]
Interest rate (percent)	12.00%
Secured notes - fixed rate | FES
Schedule of Capitalization [Line Items]
Secured notes	$ 340	437
Secured notes - fixed rate | FES | Minimum
Schedule of Capitalization [Line Items]
Interest rate (percent)	5.625%
Secured notes - fixed rate | FES | Maximum
Schedule of Capitalization [Line Items]
Interest rate (percent)	12.00%
Secured notes - variable rate
Schedule of Capitalization [Line Items]
Secured notes	$ 2	0
Secured notes - variable rate | Minimum
Schedule of Capitalization [Line Items]
Interest rate (percent)	3.50%
Secured notes - variable rate | Maximum
Schedule of Capitalization [Line Items]
Interest rate (percent)	3.50%
Secured notes - variable rate | FES
Schedule of Capitalization [Line Items]
Secured notes	$ 2	0
Secured notes - variable rate | FES | Minimum
Schedule of Capitalization [Line Items]
Interest rate (percent)	3.50%
Secured notes - variable rate | FES | Maximum
Schedule of Capitalization [Line Items]
Interest rate (percent)	3.50%
Unsecured notes - fixed rate
Schedule of Capitalization [Line Items]
Unsecured debt	$ 13,580	13,078
Unsecured notes - fixed rate | Minimum
Schedule of Capitalization [Line Items]
Interest rate (percent)	2.15%
Unsecured notes - fixed rate | Maximum
Schedule of Capitalization [Line Items]
Interest rate (percent)	7.70%
Unsecured notes - fixed rate | FES
Schedule of Capitalization [Line Items]
Unsecured debt	$ 2,593	2,568
Unsecured notes - fixed rate | FES | Minimum
Schedule of Capitalization [Line Items]
Interest rate (percent)	2.15%
Unsecured notes - fixed rate | FES | Maximum
Schedule of Capitalization [Line Items]
Interest rate (percent)	6.80%
Unsecured notes - variable rate
Schedule of Capitalization [Line Items]
Unsecured debt	$ 1,292	1,292
Unsecured notes - variable rate | Minimum
Schedule of Capitalization [Line Items]
Interest rate (percent)	0.01%
Unsecured notes - variable rate | Maximum
Schedule of Capitalization [Line Items]
Interest rate (percent)	2.18%
Unsecured notes - variable rate | FES
Schedule of Capitalization [Line Items]
Unsecured debt	$ 92	$ 92
Unsecured notes - variable rate | FES | Minimum
Schedule of Capitalization [Line Items]
Interest rate (percent)	0.01%
Unsecured notes - variable rate | FES | Maximum
Schedule of Capitalization [Line Items]
Interest rate (percent)	0.01%

Capitalization (Details 2)

Capitalization (Details 2) $ in Millions	Dec. 31, 2015USD ($)
Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases and variable rate PCRBs) for the next five years
2,016	$ 1,039
2,017	1,733
2,018	1,702
2,019	2,268
2,020	1,231
FES
Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases and variable rate PCRBs) for the next five years
2,016	414
2,017	257
2,018	516
2,019	322
2,020	$ 667

Capitalization (Details 3)

Capitalization (Details 3) $ in Millions	Dec. 31, 2015USD ($)
Outstanding PCRBs
2,016	$ 1,039
2,017	1,733
2,018	1,702
2,019	2,268
2,020	1,231
PCRB
Outstanding PCRBs
2,016	391
2,017	222
2,018	375
2,019	232
2,020	490
FES
Outstanding PCRBs
2,016	414
2,017	257
2,018	516
2,019	322
2,020	667
FES | PCRB
Outstanding PCRBs
2,016	391
2,017	222
2,018	375
2,019	232
2,020	$ 490

Capitalization (Details 4)

Capitalization (Details 4) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Schedule of Capitalization [Line Items]
Aggregate LOC Amount	$ 93
Annual Fees	1.25%
Applicable interest coverage	$ 1
FES
Schedule of Capitalization [Line Items]
Aggregate LOC Amount	$ 93
Annual Fees	1.25%

Capitalization (Details Textual

Capitalization (Details Textuals)	Jan. 19, 2016$ / shares	Aug. 15, 2015USD ($)	Dec. 31, 2015USD ($)$ / sharesshares	Sep. 30, 2015$ / shares	Jun. 30, 2015USD ($)$ / shares	Mar. 31, 2015$ / shares	Dec. 31, 2014USD ($)$ / sharesshares	Sep. 30, 2014$ / shares	Jun. 30, 2014$ / shares	Mar. 31, 2014$ / shares	Dec. 31, 2015USD ($)subsidiary$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013$ / sharesshares	Oct. 31, 2015USD ($)	Sep. 17, 2015USD ($)	Aug. 31, 2015USD ($)	Aug. 17, 2015USD ($)	Jul. 01, 2015USD ($)	Jun. 30, 2013USD ($)
Debt Instrument [Line Items]
Retained earnings (accumulated deficit)			$ 2,256,000,000				$ 2,285,000,000				$ 2,256,000,000	$ 2,285,000,000
Dividends declared, in dollars per share | $ / shares											$ 1.44	$ 1.44	$ 1.65
Common stock dividends per share paid | $ / shares			$ 0.36	$ 0.36	$ 0.36	$ 0.36	$ 0.36	$ 0.36	$ 0.36	$ 0.36
FERC-defined equity to total capitalization ratio											35.00%
Preferred shares shares outstanding | shares			0				0				0	0
Preference shares outstanding | shares			0				0				0	0
Number of subsidiaries that issued environmental control bonds | subsidiary											2
Environmental control bonds outstanding			$ 429,000,000				$ 450,000,000				$ 429,000,000	$ 450,000,000
Transition bond outstanding			128,000,000				168,000,000				128,000,000	168,000,000
Currently payable long-term debt			1,166,000,000				804,000,000				1,166,000,000	804,000,000
Principal default amount specified in debt covenants											100,000,000
Subsequent Event
Debt Instrument [Line Items]
Dividends declared, in dollars per share | $ / shares	$ 0.36
Phase In Recovery Bonds
Debt Instrument [Line Items]
Long-term debt and other long-term obligations			362,000,000				386,000,000				$ 362,000,000	386,000,000
Senior Notes | Variable Rate Term Loan Due 2016
Debt Instrument [Line Items]
Face amount of loan					$ 200,000,000
Senior Notes | Variable Rate Term Loan Due 2020
Debt Instrument [Line Items]
Face amount of loan					$ 200,000,000
AGC
Debt Instrument [Line Items]
FERC-defined equity to total capitalization ratio											45.00%
ATSI | Senior Notes
Debt Instrument [Line Items]
Face amount of loan														$ 150,000,000
ATSI | Senior Notes | 4.00% Senior Notes Due 2026
Debt Instrument [Line Items]
Interest rate (percent)														4.00%
Face amount of loan														$ 75,000,000
ATSI | Senior Notes | 5.23% Senior Notes Due 2045
Debt Instrument [Line Items]
Interest rate (percent)														5.23%
Face amount of loan														$ 75,000,000
FES
Debt Instrument [Line Items]
Retained earnings (accumulated deficit)			1,946,000,000				1,934,000,000				$ 1,946,000,000	1,934,000,000
Currently payable long-term debt			512,000,000				$ 506,000,000				512,000,000	$ 506,000,000
FES | PCRB
Debt Instrument [Line Items]
Currently payable long-term debt			$ 92,000,000								92,000,000
FG | PCRB
Debt Instrument [Line Items]
Face amount of loan																		$ 43,000,000
NG | PCRB
Debt Instrument [Line Items]
Face amount of loan																		$ 296,000,000
JCP&L | Senior Notes | 4.3% Senior Notes Due 2026
Debt Instrument [Line Items]
Interest rate (percent)																4.30%
Face amount of loan																$ 250,000,000
WP | FMBs | 4.45% FMB Due 2045
Debt Instrument [Line Items]
Interest rate (percent)															4.45%
Face amount of loan															$ 150,000,000
PE | FMBs | 4.47% FMB Due 2045
Debt Instrument [Line Items]
Interest rate (percent)																	4.47%
Face amount of loan																	$ 145,000,000
PE | FMBs | 5.125% FMB Due August 2015
Debt Instrument [Line Items]
Interest rate (percent)																5.125%
Debt repaid		$ 145,000,000
TrAIL | Senior Notes | 3.76% Senior Notes Due 2025
Debt Instrument [Line Items]
Interest rate (percent)														3.76%
Face amount of loan														$ 75,000,000
Ohio Funding Companies | Phase In Recovery Bonds
Debt Instrument [Line Items]
Face amount of loan																			$ 445,000,000
Penn
Debt Instrument [Line Items]
Annual sinking fund requirement for FMB											$ 3,000,000
Common Stock
Debt Instrument [Line Items]
Stock issuance - employee benefits, Shares | shares											2,457,827	2,474,011	412,122
Minimum | FMBs
Debt Instrument [Line Items]
Interest rate (percent)			3.34%								3.34%
Minimum | PCRB
Debt Instrument [Line Items]
Interest rate (percent)																		3.125%
Maximum | FMBs
Debt Instrument [Line Items]
Interest rate (percent)			9.74%								9.74%
Maximum | PCRB
Debt Instrument [Line Items]
Interest rate (percent)																		4.00%

Short-Term Borrowings and Ba119

Short-Term Borrowings and Bank Lines of Credit (Details) - USD ($)	Jan. 31, 2016	Dec. 31, 2015
Subsequent Event
Short-term Debt [Line Items]
Maximum amount borrowed under revolving credit facility	$ 6,000,000,000
Available Liquidity	4,037,000,000
Cash, Available Liquidity	63,000,000
Total Available Liquidity	4,100,000,000
FirstEnergy
Short-term Debt [Line Items]
Maximum amount borrowed under revolving credit facility		$ 3,500,000,000
FirstEnergy | Line of Credit | Subsequent Event
Short-term Debt [Line Items]
Available Liquidity	1,595,000,000
FES / AE Supply | Line of Credit | Subsequent Event
Short-term Debt [Line Items]
Available Liquidity	1,442,000,000
FET
Short-term Debt [Line Items]
Maximum amount borrowed under revolving credit facility		1,000,000,000
FET | Line of Credit | Subsequent Event
Short-term Debt [Line Items]
Available Liquidity	1,000,000,000
Revolving Credit Facility | Line of Credit
Short-term Debt [Line Items]
Maximum amount borrowed under revolving credit facility		$ 6,000,000,000
Revolving Credit Facility | Line of Credit | Subsequent Event
Short-term Debt [Line Items]
Maximum amount borrowed under revolving credit facility	6,000,000,000
Revolving Credit Facility | FirstEnergy | Line of Credit | Subsequent Event
Short-term Debt [Line Items]
Maximum amount borrowed under revolving credit facility	3,500,000,000
Revolving Credit Facility | FES / AE Supply | Line of Credit | Subsequent Event
Short-term Debt [Line Items]
Maximum amount borrowed under revolving credit facility	1,500,000,000
Revolving Credit Facility | FET | Line of Credit | Subsequent Event
Short-term Debt [Line Items]
Maximum amount borrowed under revolving credit facility	$ 1,000,000,000

Short-Term Borrowings and Ba120

Short-Term Borrowings and Bank Lines of Credit (Details 1)	Dec. 31, 2015USD ($)
FE
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	$ 3,500,000,000
Regulatory and Other Short-Term Debt Limitations	0
FES
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	1,500,000,000
Regulatory and Other Short-Term Debt Limitations	0
AE Supply
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	1,000,000,000
Regulatory and Other Short-Term Debt Limitations	0
FET
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	1,000,000,000
Regulatory and Other Short-Term Debt Limitations	0
OE
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	500,000,000
Regulatory and Other Short-Term Debt Limitations	500,000,000
CEI
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	500,000,000
Regulatory and Other Short-Term Debt Limitations	500,000,000
TE
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	500,000,000
Regulatory and Other Short-Term Debt Limitations	500,000,000
JCP&L
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	600,000,000
Regulatory and Other Short-Term Debt Limitations	500,000,000
ME
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	300,000,000
Regulatory and Other Short-Term Debt Limitations	500,000,000
PN
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	300,000,000
Regulatory and Other Short-Term Debt Limitations	300,000,000
WP
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	200,000,000
Regulatory and Other Short-Term Debt Limitations	200,000,000
MP
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	500,000,000
Regulatory and Other Short-Term Debt Limitations	500,000,000
PE
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	150,000,000
Regulatory and Other Short-Term Debt Limitations	150,000,000
ATSI
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	500,000,000
Regulatory and Other Short-Term Debt Limitations	500,000,000
Penn
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	50,000,000
Regulatory and Other Short-Term Debt Limitations	100,000,000
TrAIL
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	400,000,000
Regulatory and Other Short-Term Debt Limitations	$ 400,000,000

Short-Term Borrowings and Ba121

Short-Term Borrowings and Bank Lines of Credit (Details 2)	Dec. 31, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Weighted average interest rate	2.16%	1.96%
FES
Line of Credit Facility [Line Items]
Weighted average interest rate	0.00%	3.34%

Short-Term Borrowings and Ba122

Short-Term Borrowings and Bank Lines of Credit (Details Textuals)	Mar. 31, 2014credit_facility	Dec. 31, 2015USD ($)money_poolcredit_facility	Dec. 31, 2014USD ($)
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Short-term borrowings		$ 1,708,000,000	$ 1,799,000,000
Number of money pools | money_pool		2
Average interest rate for borrowings		2.16%	1.96%
Revolving Credit Facility
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Number of credit facilities extended | credit_facility	3
Revolving Credit Facility | Maximum
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Term of revolving credit facility, in days		364 days
Consolidated debt to total capitalization ratio (percent)		65.00%
Parent Company | Term Loan | Variable Rate Term Loan Due 2019
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Face amount of loan		$ 1,000,000,000
Parent Company | Term Loan | Variable Rate Term Loan Due 2016
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Face amount of loan		200,000,000
FirstEnergy
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility		3,500,000,000
FET
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility		$ 1,000,000,000
FET | Revolving Credit Facility | Maximum
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Consolidated debt to total capitalization ratio (percent)		75.00%
Line of Credit | Revolving Credit Facility
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility		$ 6,000,000,000
Revolving Credit Facility | Parent and Certain Subsidiaries
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Number of credit facilities | credit_facility		3
Term of credit facility		5 years
Available for Issuance of Letters of Credit
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Amount of revolving line of credit		$ 600,000,000
Available for Issuance of Letters of Credit | Minimum
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Cross-default provision for other indebtedness		100,000,000
Available for Issuance of Letters of Credit | FET
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Amount of revolving line of credit		$ 225,000,000
Money Pool | Maximum
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Term of revolving credit facility, in days		364 days
Money Pool | Regulated Companies
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Average interest rate for borrowings		0.84%
Money Pool | Unregulated Companies
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Average interest rate for borrowings		1.64%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations [Line Items]
Nuclear plant decommissioning trusts	$ 2,282	$ 2,341
Fair value of decommissioning trust assets		2,341
Changes to the asset retirement obligations
Beginning Balance	1,387	1,678
Liabilities settled	(13)	(9)
Accretion	92	113
Revisions in estimated cash flows	56	395
Ending Balance	1,410	1,387
Decrease in ARO	(63)
FES
Asset Retirement Obligations [Line Items]
Nuclear plant decommissioning trusts	1,327	1,365
Fair value of decommissioning trust assets		1,365
Changes to the asset retirement obligations
Beginning Balance	841	1,015
Liabilities settled	(8)	(7)
Accretion	55	66
Revisions in estimated cash flows	57	233
Ending Balance	831	841
FES | Davis-Besse and Perry Nuclear Generating Stations
Changes to the asset retirement obligations
Revisions in estimated cash flows	$ 57
Asset Retirement Obligation Costs [Member] | TMI-2
Changes to the asset retirement obligations
Decrease in ARO		$ (133)

Regulatory Matters - Maryland a

Regulatory Matters - Maryland and New Jersey (Details) $ in Millions	Sep. 02, 2015	Jul. 22, 2015	Jul. 16, 2015	Jul. 10, 2015	Apr. 01, 2015USD ($)	Mar. 26, 2015USD ($)	Dec. 23, 2014USD ($)	Feb. 27, 2013USD ($)	Dec. 31, 2015USD ($)componentbgs	Dec. 31, 2008	Jan. 28, 2016USD ($)
Maryland
Regulatory Matters [Line Items]
Incremental energy savings goal in the next 12 months (percent)			0.20%
Incremental energy savings goal thereafter (percent)			2.00%
Proposed electric consumption reduction percentage										10.00%
Proposed electric demand reduction percentage										15.00%
Expenditures for cost recovery program							$ 66
Expenditures for cost recovery program incurred									$ 19
Recovery period for expenditures for cost recovery program							3 years
Amortization period for expenditures for cost recovery program									5 years
Expected infrastructure investments								$ 2,700
Expected infrastructure investments, period								15 years
Recommended reduction in average outage duration (percent)				20.00%
Maryland | MDPSC | SAIDI and SAIFI Standards
Regulatory Matters [Line Items]
Approved reduction in average outage duration (percent)	8.60%
New Jersey
Regulatory Matters [Line Items]
Number of supply components | component									2
Number of BGS | bgs									1
JCP&L | New Jersey | NJBPU
Regulatory Matters [Line Items]
Period to complete study		1 year
JCP&L | New Jersey | NJBPU | Major Storm Events
Regulatory Matters [Line Items]
Requested increase in revenues					$ (34)	$ 81
JCP&L | New Jersey | NJBPU | Final Order Base Rate Case
Regulatory Matters [Line Items]
Requested increase in revenues						(115)
2012 Storm Costs | JCP&L | New Jersey | NJBPU | Major Storm Events
Regulatory Matters [Line Items]
Requested increase in revenues						$ 580
Subsequent Event
Regulatory Matters [Line Items]
Requested increase in expenditures for cost recovery program											$ 2

Regulatory Matters - Ohio (Deta

Regulatory Matters - Ohio (Details) - Ohio $ in Millions	Aug. 07, 2013USD ($)auction	Mar. 20, 2013	Sep. 30, 2015MWh	Dec. 31, 2015USD ($)MW
Regulatory Matters [Line Items]
ESP extension term				2 years
Generation discount for low income customers				6.00%
Recovery period				5 years
Costs avoided by customers				$ 360
Generation supply auction period, after approval				3 years
EDA plan term				3 years
Proposed purchase power agreement term				8 years
EEPP term of plan		3 years
Generation supply auction period, before approval				1 year
Portfolio plan estimated cost				$ 250
Portion of revenue obtained to be received				20.00%
Credit to non-shopping customers	$ 43.4
Year 2,015
Regulatory Matters [Line Items]
Annual energy savings | MWh			2,266
Year 2,016
Regulatory Matters [Line Items]
Annual energy savings | MWh			2,288
Year 2,017
Regulatory Matters [Line Items]
Annual energy savings yearly increase (percent)				1.00%
Annually Through 2018
Regulatory Matters [Line Items]
Utilities required to additionally reduce peak demand				0.75%
Annually Through 2014
Regulatory Matters [Line Items]
Utilities required to additionally reduce peak demand				0.75%
Wind or Solar Power
Regulatory Matters [Line Items]
Proposed potential plant acquisition | MW				100
DCR Rider
Regulatory Matters [Line Items]
Annual revenue cap for rider				$ 30
Revenue cap for Rider for years 3-6				20
Revenue cap for Rider for years 6-8				15
RRS Rider
Regulatory Matters [Line Items]
Guaranteed credits in year five				10
Guaranteed credits in year six				20
Guaranteed credits in year seven				30
Guaranteed credits in year eight				$ 40
Number of renewable energy auctions | auction	1
Customary Advisory Council
Regulatory Matters [Line Items]
Proposed purchase power agreement term				8 years
Public Utilities, Annual Contribution Amount				$ 1
Public Utilities, Contribution Amount				$ 8
Ohio Companies | Energy Conservation, Economic Development and Job Retention
Regulatory Matters [Line Items]
Proposed purchase power agreement term				8 years
Public Utilities, Annual Contribution Amount				$ 3
Public Utilities, Contribution Amount				$ 24
Ohio Companies | Fuel-Fund
Regulatory Matters [Line Items]
Proposed purchase power agreement term				8 years
Public Utilities, Annual Contribution Amount				$ 2.4
Public Utilities, Contribution Amount				$ 19

Regulatory Matters - Pennsylvan

Regulatory Matters - Pennsylvania and West Virginia (Details)

Dec. 22, 2015USD ($)

Dec. 21, 2015USD ($)

Nov. 03, 2015proposal

Oct. 19, 2015USD ($)

Sep. 10, 2015USD ($)

Aug. 31, 2015USD ($)

Aug. 14, 2015USD ($)

Jun. 19, 2015

Apr. 09, 2015USD ($)

Feb. 03, 2015USD ($)

Jun. 30, 2015USD ($)

Feb. 24, 2015USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)proposal

Nov. 05, 2015USD ($)

Pennsylvania

Regulatory Matters [Line Items]

Number of requests for proposal | proposal

1,000,000

1

Project term

2 years

2 years

Requested rate increase (decrease)

$ 292,800,000

Approved additional operating expenses

87,700,000

Pennsylvania | 3 Month Period

Regulatory Matters [Line Items]

Energy contract term

3 months

Pennsylvania | 12 Month Period

Regulatory Matters [Line Items]

Energy contract term

12 months

12 months

Pennsylvania | 24 Month Period

Regulatory Matters [Line Items]

Energy contract term

24 months

24 months

Pennsylvania | Unfavorable Regulatory Action

Regulatory Matters [Line Items]

Statutory penalty, maximum

$ 234,000,000

Pennsylvania | ME

Regulatory Matters [Line Items]

Requested rate increase (decrease)

89,300,000

Pennsylvania | Penn

Regulatory Matters [Line Items]

Requested rate increase (decrease)

15,900,000

Pennsylvania | WP

Regulatory Matters [Line Items]

Requested rate increase (decrease)

96,800,000

Pennsylvania | PN

Regulatory Matters [Line Items]

Requested rate increase (decrease)

$ 90,800,000

Pennsylvania | Pennsylvania Companies | Unfavorable Regulatory Action

Regulatory Matters [Line Items]

Statutory penalty, maximum

$ 230,000,000

Minimum range of possible loss

$ 200,000,000

Pennsylvania | PPUC | ME

Regulatory Matters [Line Items]

Proposed ROE

1.80%

Energy consumption reduction targets (percent)

4.00%

Requested rate increase (decrease)

$ 43,440,000

Pennsylvania | PPUC | Penn

Regulatory Matters [Line Items]

Proposed ROE

1.70%

Energy consumption reduction targets (percent)

3.30%

Requested rate increase (decrease)

$ 56,350,000

Pennsylvania | PPUC | WP

Regulatory Matters [Line Items]

Proposed ROE

1.80%

Energy consumption reduction targets (percent)

2.60%

LTIP recovery period

5 years

Requested rate increase (decrease)

$ 88,340,000

Pennsylvania | PPUC | PN

Regulatory Matters [Line Items]

Proposed ROE

0.00%

Energy consumption reduction targets (percent)

3.90%

Requested rate increase (decrease)

$ 56,740,000

West Virginia | MP and PE

Regulatory Matters [Line Items]

Requested rate increase (decrease)

$ 165,100,000

Requested rate increase (decrease) (percent)

12.50%

Under-recovered balance

$ 97,000,000

Under-recovered balance for 2016

23,700,000

West Virginia | WVPSC | MP and PE

Regulatory Matters [Line Items]

Requested rate increase (decrease)

$ 15,000,000

Cost recovery period

5 years

Deferred storm and property reserve deficiency

$ 46,000,000

West Virginia | WVPSC | MP and PE | ENEC

Regulatory Matters [Line Items]

Requested rate increase (decrease)

$ 144,500,000

Settlement amount

$ 96,900,000

Amendment to requested rate increase (decrease)

$ (20,600,000)

West Virginia | WVPSC | MP and PE | Vegetation Management Program Surcharge

Regulatory Matters [Line Items]

Requested rate increase (decrease)

$ 37,700,000

$ 2,100,000

$ 49,900,000

Settlement amount

$ 36,700,000

Requested rate increase (decrease) (percent)

2.80%

Approved rate recovery period

2 years

West Virginia | WVPSC | MP and PE | Vegetation Management Program Surcharge | Scenario, Forecast

Regulatory Matters [Line Items]

Requested rate increase (decrease)

$ 23,900,000

West Virginia | WVPSC | MP and PE | Harrison Power Station | ENEC

Regulatory Matters [Line Items]

Requested rate increase (decrease)

$ 44,400,000

Regulatory Matters - Reliabilit

Regulatory Matters - Reliability and FERC Matters (Details) $ in Millions	Jan. 01, 2016	Aug. 24, 2012USD ($)	Apr. 30, 2007kv	Oct. 31, 2006proceeding	Dec. 31, 2015USD ($)	Jun. 30, 2015	Dec. 31, 2015USD ($)entitysubsidiary
Regulatory Matters [Line Items]
Regional enforcement entities | entity							8
FERC
Regulatory Matters [Line Items]
Power threshold for cost methodology (in KW) | kv			500
Denied recovery charges of exit fees					$ 78.8		$ 78.8
California Claims Matters | FERC
Regulatory Matters [Line Items]
Settlement proposal claims							$ 190
Court proceedings from filed claims | proceeding				1
FET | FERC
Regulatory Matters [Line Items]
Number of stand alone transmission subsidiaries | subsidiary							2
ATSI | FERC
Regulatory Matters [Line Items]
Requested ROE (percent)					11.06%	12.38%
ATSI | FERC | Scenario, Forecast
Regulatory Matters [Line Items]
Requested ROE (percent)	10.38%
PATH-Allegheny | FERC
Regulatory Matters [Line Items]
Cost recovery PP&E reclassified to Regulatory Assets		$ 62
Path-WV | FERC
Regulatory Matters [Line Items]
Cost recovery PP&E reclassified to Regulatory Assets		$ 59
PATH | FERC
Regulatory Matters [Line Items]
Cost recovery proposed ROE (percent)		10.90%
Base ROE (percent)		10.40%
ROE granted for RTO's (percent)		0.50%
Remaining recovery period of regulatory assets		5 years

Regulatory Matters - Capacity P

Regulatory Matters - Capacity Performance Transition Auctions (Details) - FERC - PJM Capacity - Scenario, Forecast	12 Months Ended
	Dec. 31, 2018$ / MWDMW	Dec. 31, 2017$ / MWDMW	Dec. 31, 2016$ / MWDMW
Public Utilities, General Disclosures [Line Items]
Legacy Obligation (in MW)		1,510	3,775
Capacity Performance (in MW)	10,195	9,810	7,885
Base Generation (in MW)	275
Uncommitted capacity (in MW)	885
ATSI
Public Utilities, General Disclosures [Line Items]
Legacy Obligation (in MW)		375	2,765
Legacy Obligation (in $/MWD) | $ / MWD		120	114.23
Capacity Performance (in MW)	6,245	6,245	4,210
Capacity Performance (in $/MWD) | $ / MWD	164.77	151.50	134
Base Generation (in MW)	0
Base Generation (in $/MWD) | $ / MWD	149.98
RTO
Public Utilities, General Disclosures [Line Items]
Legacy Obligation (in MW)		985	875
Legacy Obligation (in $/MWD) | $ / MWD		120	59.37
Capacity Performance (in MW)	3,930	3,565	3,675
Capacity Performance (in $/MWD) | $ / MWD	164.77	151.50	134
Base Generation (in MW)	240
Base Generation (in $/MWD) | $ / MWD	149.98
All Other Zones
Public Utilities, General Disclosures [Line Items]
Legacy Obligation (in MW)		150	135
Legacy Obligation (in $/MWD) | $ / MWD		120	119.13
Capacity Performance (in MW)	20	0	0
Capacity Performance (in $/MWD) | $ / MWD		151.50	134
Base Generation (in MW)	35
All Other Zones | Supply Obligation One
Public Utilities, General Disclosures [Line Items]
Capacity Performance (in MW)	5
Capacity Performance (in $/MWD) | $ / MWD	215
Base Generation (in MW)	10
Base Generation (in $/MWD) | $ / MWD	200.21
Rest-of-RTO and ATSI Regions | Supply Obligation Two
Public Utilities, General Disclosures [Line Items]
Capacity Performance (in MW)	15
Capacity Performance (in $/MWD) | $ / MWD	164.77
Base Generation (in MW)	25
Base Generation (in $/MWD) | $ / MWD	149.98

Commitments, Guarantees and 129

Commitments, Guarantees and Contingencies (Details) $ in Millions	Dec. 31, 2015USD ($)
Guarantor Obligations [Line Items]
Full impact of credit contingent contractual obligations	$ 420
Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Full impact of credit contingent contractual obligations	245
BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Full impact of credit contingent contractual obligations	278
FES
Guarantor Obligations [Line Items]
Full impact of credit contingent contractual obligations	363
FES | Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Full impact of credit contingent contractual obligations	198
FES | BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Full impact of credit contingent contractual obligations	231
AE Supply
Guarantor Obligations [Line Items]
Full impact of credit contingent contractual obligations	16
AE Supply | Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Full impact of credit contingent contractual obligations	6
AE Supply | BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Full impact of credit contingent contractual obligations	6
Utilities
Guarantor Obligations [Line Items]
Full impact of credit contingent contractual obligations	41
Utilities | Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Full impact of credit contingent contractual obligations	41
Utilities | BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Full impact of credit contingent contractual obligations	$ 41

Commitments, Guarantees and 130

Commitments, Guarantees and Contingencies - Nuclear Insurance, Commitments and Collateral (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2015USD ($)T	Dec. 31, 2015USD ($)Nuclear_Power_Plant
Loss Contingencies [Line Items]
Liability assessed with respect to single nuclear incident		$ 13,500,000,000
Plants licensed to operate | Nuclear_Power_Plant		103
Portion of insurance coverage of private insurer included in single nuclear incident		$ 375,000,000
Portion of insurance coverage by industry retrospective rating plan		13,100,000,000
Losses in excess of private insurance contributed for each nuclear unit license		127,000,000
Losses in excess of private insurance contributed for each nuclear unit license per unit		19,000,000
Nuclear incidence liability per incident of parent and subsidiary companys based on their present nuclear ownership and leasehold interests		509,000,000
Nuclear incident liability not more than in any one year per incident of parent and subsidiary companies based on their present nuclear ownership and leasehold interests		76,000,000
Aggregate indemnity		$ 1,960,000,000
Waiting period		140 days
Environmental plan, submission period		30 days
Maximum aggregate assessments for incidents at any covered nuclear facility		$ 15,000,000
Coverage of decontamination costs		2,750,000,000
Retrospective assessments liabilities		83,000,000
Insurance coverage for replacement power costs		1,060,000,000
Outstanding guarantees and other assurances aggregated		3,700,000,000
Full impact of credit contingent contractual obligations		420,000,000
Parental Guarantees
Loss Contingencies [Line Items]
Outstanding guarantees and other assurances aggregated		583,000,000
Subsidiaries' Guarantees
Loss Contingencies [Line Items]
Outstanding guarantees and other assurances aggregated		2,137,000,000
Other Guarantees
Loss Contingencies [Line Items]
Outstanding guarantees and other assurances aggregated		300,000,000
Other Assurances
Loss Contingencies [Line Items]
Outstanding guarantees and other assurances aggregated		667,000,000
Regulated Distribution
Loss Contingencies [Line Items]
Company posted collateral related to net liability positions		$ 1,000,000
FEV | Global Holding
Loss Contingencies [Line Items]
Loss in period	$ 24,000,000
FEV | Signal Peak | Put Option
Loss Contingencies [Line Items]
Put option right | T	2,000,000
FEV | Signal Peak | Senior Secured Term Loan | Senior Loans | Global Holding
Loss Contingencies [Line Items]
Investment ownership percentage		33.33%
NGC
Loss Contingencies [Line Items]
Nuclear incidence liability per incident of parent and subsidiary companys based on their present nuclear ownership and leasehold interests		$ 501,000,000
Nuclear incident liability not more than in any one year per incident of parent and subsidiary companies based on their present nuclear ownership and leasehold interests		75,000,000
Aggregate indemnity		1,930,000,000
Maximum aggregate assessments for incidents at any covered nuclear facility		15,000,000
Retrospective assessments liabilities		81,000,000
FES
Loss Contingencies [Line Items]
Company posted collateral related to net liability positions		188,000,000
Potential collateral posted related to net liability positions		8,000,000
Full impact of credit contingent contractual obligations		$ 363,000,000
WMB Marketing Ventures, LLC | Signal Peak | Senior Secured Term Loan | Senior Loans | Global Holding
Loss Contingencies [Line Items]
Investment ownership percentage		33.33%
Global Holding | Senior Secured Term Loan | Senior Loans
Loss Contingencies [Line Items]
Full impact of credit contingent contractual obligations	$ 300,000,000

Commitments, Guarantees and 131

Commitments, Guarantees and Contingencies - Clean Air Act and Climate Change (Details) $ in Millions	Oct. 01, 2015	Aug. 03, 2015T	Aug. 31, 2015	Dec. 31, 2015USD ($)phaseT	Dec. 31, 2014USD ($)	Dec. 31, 2015USD ($)T	Apr. 30, 2015MW	Nov. 12, 2014	Apr. 30, 2014	Jun. 30, 2013
Year 2,020
Loss Contingencies [Line Items]
Reduction in power plants carbon pollution, (percent)										17.00%
FES
Loss Contingencies [Line Items]
Loss Contingency, Damages Paid, Value					$ 70
National Ambient Air Quality Standards
Loss Contingencies [Line Items]
Capping of SO2 Emissions Under CSAPR | T				2,400,000
Capping of NOx emissions under CSAPR | T				1,200,000
National Ambient Air Quality Standards | CSAPR
Loss Contingencies [Line Items]
Number of phases under the EPA’s CAIR for reductions of Sulfur Dioxide and Mono-Nitrogen Oxides | phase				2
Hazardous Air Pollutant Emissions
Loss Contingencies [Line Items]
Potential cost of compliance, MATS				$ 345		$ 345
Hazardous Air Pollutant Emissions | CES
Loss Contingencies [Line Items]
Potential cost of compliance, MATS				168		168
Hazardous Air Pollutant Emissions | Regulated Distribution
Loss Contingencies [Line Items]
Potential cost of compliance, MATS				$ 177		177
Caa Compliance
Loss Contingencies [Line Items]
Loss in period						$ 202
Deactivated Power Plants, Coal-Fired, Capacity | MW							5,429
Mass remaining under contract | T				6,000,000		6,000,000
Caa Compliance | CES
Loss Contingencies [Line Items]
Loss in period						$ 80
Caa Compliance | Regulated Distribution
Loss Contingencies [Line Items]
Loss in period						$ 122
Mercury and Air Toxic Standards | FG | Certain Coal-Fired Power Plant
Loss Contingencies [Line Items]
Loss Contingency, Nonmonetary Contractual Amount in Dispute, Mass | T		3,500,000
Mercury and Air Toxic Standards | FG | Another Coal-Fired Power Plant
Loss Contingencies [Line Items]
Loss Contingency, Nonmonetary Contractual Amount in Dispute, Mass | T		2,500,000
Climate Change
Loss Contingencies [Line Items]
Reduction in GHG emissions between 2005 and 2012 (percent)									10.00%
Anticipated Reduction in Carbon Dioxide Emissions, Percent				25.00%		25.00%
Minimum | Climate Change
Loss Contingencies [Line Items]
Reduction in emissions (percent)								26.00%
Maximum | Climate Change
Loss Contingencies [Line Items]
Reduction in emissions (percent)								28.00%
EPA | Caa Compliance
Loss Contingencies [Line Items]
Period of time to implement plan	3 years
State and Local Agencies | Maximum | Climate Change
Loss Contingencies [Line Items]
Potential MATS extension period			2 years

Commitments, Guarantees and 132

Commitments, Guarantees and Contingencies - Clean Water Act and Regulation of Waste Disposal (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014	Apr. 19, 2013option
Loss Contingencies [Line Items]
Number of treatment options | option			8
Number of preferred treatment options | option			4
Renewal cycle of waste water discharge permit	5 years
Clean Water Act
Loss Contingencies [Line Items]
Annual percentage that fish impingement should be reduced to, per CWA	12.00%
TMDL limit development period	5 years
Regulation of Waste Disposal
Loss Contingencies [Line Items]
Accrual for environmental loss contingencies	$ 126
Environmental liabilities former gas facilities	87
Bond closure and post closure period		45 years
Period of time to implement plan		12 years
Minimum | Clean Water Act
Loss Contingencies [Line Items]
Maximum capital investment required to install technology to meet TDS and Sulfate limits	150
Maximum | Clean Water Act
Loss Contingencies [Line Items]
Maximum capital investment required to install technology to meet TDS and Sulfate limits	$ 300

Commitments, Guarantees and 133

Commitments, Guarantees and Contingencies - Other Legal Proceedings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Loss Contingencies [Line Items]
Nuclear plant decommissioning trusts	$ 2,282	$ 2,341
Nuclear Plant Matters
Loss Contingencies [Line Items]
Nuclear plant decommissioning trusts	2,300
Additions to parental guarantee associated with funding of decommissioning costs	$ 24.5
Renewal Of Operating License Length	20 years

Transactions With Affiliated134

Transactions With Affiliated Companies (Details) - FES - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Investment Income:
Interest income from FE	$ 2	$ 3	$ 2
Interest Expense:
Interest expense to affiliates	4	3	4
Interest expense to FE	3	4	6
Electric sales to affiliates
REVENUES:
Revenues	664	861	652
Other
REVENUES:
Revenues	6	6	6
Purchased power from affiliates
EXPENSES:
Expenses	353	271	486
Fuel
EXPENSES:
Expenses	1	1	0
Support services
EXPENSES:
Expenses	$ 705	$ 619	$ 619

Supplemental Guarantor Infor135

Supplemental Guarantor Information (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Consolidating Statements of Income
Revenues	[1]									$ 15,026	$ 15,049	$ 14,892
OPERATING EXPENSES:
Fuel										1,855	2,280	2,496
Purchased power										4,318	4,716	3,963
Other operating expenses		$ 952	$ 850	$ 916	$ 1,057	$ 901	$ 858	$ 1,021	$ 1,182	3,749	3,962	3,593
Pension and OPEB mark-to-market adjustment		242	0	0	0	835	0	0	0	242	835	(256)
Provision for depreciation		313	328	322	319	316	308	302	294	1,282	1,220	1,202
General taxes										978	962	978
Total operating expenses										12,734	13,987	13,310
OPERATING INCOME (LOSS)		236	908	554	594	(337)	716	292	391	2,292	1,062	1,582
OTHER INCOME (EXPENSE):
Loss on debt redemptions										0	(8)	(132)
Investment Income, Net										(22)	72	33
Interest expense										(1,132)	(1,073)	(1,016)
Capitalized financing costs										117	118	103
Total other expense										(1,399)	(891)	(1,012)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)										893	171	570
INCOME TAXES (BENEFITS)		(170)	226	115	144	(268)	152	26	48	315	(42)	195
INCOME (LOSS) FROM CONTINUING OPERATIONS		(226)	395	187	222	(306)	333	64	122	578	213	375
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)		0	0	0	0	0	0	0	86	0	86	17
NET INCOME (LOSS)		(226)	395	187	222	(306)	333	64	208	578	299	392
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME		(226)	395	187	222	(306)	333	64	208	578	299	392
Pension and OPEB prior service costs										(116)	(76)	(160)
Amortized gain on derivative hedges										5	(2)	3
Change in unrealized gain on available-for-sale securities										(11)	26	(10)
Other comprehensive loss										(122)	(52)	(167)
Income taxes (benefits) on other comprehensive income (loss)										(47)	(14)	(66)
Other comprehensive loss, net of tax										(75)	(38)	(101)
Tax effect of discontinued operations										0	69	9
FES
Consolidating Statements of Income
Revenues										4,824	5,990	6,068
OPERATING EXPENSES:
Fuel										0	0	0
Other operating expenses										399	790	635
Pension and OPEB mark-to-market adjustment										(8)	19	(8)
Provision for depreciation										12	10	6
General taxes										45	72	80
Total operating expenses										5,958	7,578	7,187
OPERATING INCOME (LOSS)										(1,134)	(1,588)	(1,119)
OTHER INCOME (EXPENSE):
Loss on debt redemptions											(3)	(103)
Investment Income, Net										844	791	847
Miscellaneous income, including net income from equity investees										1	2	4
Capitalized financing costs										0	0	1
Total other expense										764	725	673
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)										(370)	(863)	(446)
INCOME TAXES (BENEFITS)										(452)	(619)	(506)
INCOME (LOSS) FROM CONTINUING OPERATIONS											(244)	60
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)											0	0
NET INCOME (LOSS)										82	(244)	60
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME										82	(244)	60
Pension and OPEB prior service costs										(6)	(6)	(15)
Amortized gain on derivative hedges										(3)	(10)	(6)
Change in unrealized gain on available-for-sale securities										(9)	21	(8)
Other comprehensive loss										(18)	5	(29)
Income taxes (benefits) on other comprehensive income (loss)										(7)	2	(11)
Other comprehensive loss, net of tax										(11)	3	(18)
COMPREHENSIVE INCOME (LOSS)										71	(241)	42
FES | Affiliates
OPERATING EXPENSES:
Purchased power										3,826	3,920	4,148
OTHER INCOME (EXPENSE):
Interest expense										(29)	(12)	(13)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power										1,684	2,767	2,326
OTHER INCOME (EXPENSE):
Interest expense										(52)	(53)	(63)
FGCO
Consolidating Statements of Income
Revenues										1,801	1,902	2,399
OPERATING EXPENSES:
Fuel										679	1,055	1,056
Other operating expenses										275	269	275
Pension and OPEB mark-to-market adjustment										10	90	(37)
Provision for depreciation										124	119	127
General taxes										26	31	34
Total operating expenses										1,114	1,568	1,462
OPERATING INCOME (LOSS)										687	334	937
OTHER INCOME (EXPENSE):
Loss on debt redemptions											(1)	0
Investment Income, Net										17	8	1
Miscellaneous income, including net income from equity investees										2	4	24
Capitalized financing costs										6	4	2
Total other expense										(87)	(92)	(82)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)										600	242	855
INCOME TAXES (BENEFITS)										224	87	365
INCOME (LOSS) FROM CONTINUING OPERATIONS											155	490
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)											116	14
NET INCOME (LOSS)										376	271	504
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME										376	271	504
Pension and OPEB prior service costs										(5)	(5)	(13)
Amortized gain on derivative hedges										0	0	0
Change in unrealized gain on available-for-sale securities										0	0	0
Other comprehensive loss										(5)	(5)	(13)
Income taxes (benefits) on other comprehensive income (loss)										(2)	(2)	(5)
Other comprehensive loss, net of tax										(3)	(3)	(8)
COMPREHENSIVE INCOME (LOSS)										373	268	496
FGCO | Affiliates
OPERATING EXPENSES:
Purchased power										0	0	0
OTHER INCOME (EXPENSE):
Interest expense										(8)	(6)	(5)
FGCO | Non-Affiliates
OPERATING EXPENSES:
Purchased power										0	4	7
OTHER INCOME (EXPENSE):
Interest expense										(104)	(101)	(104)
Nuclear Generation Corp
Consolidating Statements of Income
Revenues										2,138	2,172	1,634
OPERATING EXPENSES:
Fuel										192	198	206
Other operating expenses										618	527	529
Pension and OPEB mark-to-market adjustment										55	188	(36)
Provision for depreciation										191	193	178
General taxes										27	25	24
Total operating expenses										1,368	1,402	1,167
OPERATING INCOME (LOSS)										770	770	467
OTHER INCOME (EXPENSE):
Loss on debt redemptions											(2)	0
Investment Income, Net										(5)	61	25
Miscellaneous income, including net income from equity investees										0	0	0
Capitalized financing costs										29	30	36
Total other expense										(29)	33	1
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)										741	803	468
INCOME TAXES (BENEFITS)										278	298	135
INCOME (LOSS) FROM CONTINUING OPERATIONS											505	333
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)											0	0
NET INCOME (LOSS)										463	505	333
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME										463	505	333
Pension and OPEB prior service costs										0	0	0
Amortized gain on derivative hedges										0	0	0
Change in unrealized gain on available-for-sale securities										(8)	21	(8)
Other comprehensive loss										(8)	21	(8)
Income taxes (benefits) on other comprehensive income (loss)										(3)	8	(3)
Other comprehensive loss, net of tax										(5)	13	(5)
COMPREHENSIVE INCOME (LOSS)										458	518	328
Nuclear Generation Corp | Affiliates
OPERATING EXPENSES:
Purchased power										285	271	266
OTHER INCOME (EXPENSE):
Interest expense										(4)	(4)	(6)
Nuclear Generation Corp | Non-Affiliates
OPERATING EXPENSES:
Purchased power										0	0	0
OTHER INCOME (EXPENSE):
Interest expense										(49)	(52)	(54)
Eliminations
Consolidating Statements of Income
Revenues										(3,758)	(3,920)	(3,928)
OPERATING EXPENSES:
Fuel										0	0	0
Other operating expenses										49	49	48
Pension and OPEB mark-to-market adjustment										0	0	0
Provision for depreciation										(3)	(3)	(5)
General taxes										0	0	0
Total operating expenses										(3,712)	(3,874)	(3,885)
OPERATING INCOME (LOSS)										(46)	(46)	(43)
OTHER INCOME (EXPENSE):
Loss on debt redemptions											0	0
Investment Income, Net										(870)	(799)	(857)
Miscellaneous income, including net income from equity investees										0	0	0
Capitalized financing costs										0	0	0
Total other expense										(778)	(724)	(782)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)										(824)	(770)	(825)
INCOME TAXES (BENEFITS)										15	6	12
INCOME (LOSS) FROM CONTINUING OPERATIONS											(776)	(837)
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)											0	0
NET INCOME (LOSS)										(839)	(776)	(837)
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME										(839)	(776)	(837)
Pension and OPEB prior service costs										5	5	13
Amortized gain on derivative hedges										0	0	0
Change in unrealized gain on available-for-sale securities										8	(21)	8
Other comprehensive loss										13	(16)	21
Income taxes (benefits) on other comprehensive income (loss)										5	(6)	8
Other comprehensive loss, net of tax										8	(10)	13
COMPREHENSIVE INCOME (LOSS)										(831)	(786)	(824)
Eliminations | Affiliates
OPERATING EXPENSES:
Purchased power										(3,758)	(3,920)	(3,928)
OTHER INCOME (EXPENSE):
Interest expense										34	15	14
Eliminations | Non-Affiliates
OPERATING EXPENSES:
Purchased power										0	0	0
OTHER INCOME (EXPENSE):
Interest expense										58	60	61
FES
Consolidating Statements of Income
Revenues	[2]									5,005	6,144	6,173
OPERATING EXPENSES:
Fuel										871	1,253	1,262
Other operating expenses		329	246	353	413	359	356	468	452	1,341	1,635	1,487
Pension and OPEB mark-to-market adjustment		57	0	0	0	297	0	0	0	57	297	(81)
Provision for depreciation		84	79	81	80	83	83	79	74	324	319	306
General taxes										98	128	138
Total operating expenses										4,728	6,674	5,931
OPERATING INCOME (LOSS)		25	240	0	12	(321)	90	(151)	(148)	277	(530)	242
OTHER INCOME (EXPENSE):
Loss on debt redemptions										0	(6)	(103)
Investment Income, Net										(14)	61	16
Miscellaneous income, including net income from equity investees										3	6	28
Capitalized financing costs										35	34	39
Total other expense										(130)	(58)	(190)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)										147	(588)	52
INCOME TAXES (BENEFITS)		1	70	(4)	(2)	(133)	28	(67)	(56)	65	(228)	6
INCOME (LOSS) FROM CONTINUING OPERATIONS		(14)	120	(21)	(3)	(214)	44	(87)	(103)	82	(360)	46
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)		0	0	0	0	0	0	0	116	0	116	14
NET INCOME (LOSS)		(14)	120	(21)	(3)	(214)	44	(87)	13	82	(244)	60
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME		$ (14)	$ 120	$ (21)	$ (3)	$ (214)	$ 44	$ (87)	$ 13	82	(244)	60
Pension and OPEB prior service costs										(6)	(6)	(15)
Amortized gain on derivative hedges										(3)	(10)	(6)
Change in unrealized gain on available-for-sale securities										(9)	21	(8)
Other comprehensive loss										(18)	5	(29)
Income taxes (benefits) on other comprehensive income (loss)										(7)	2	(11)
Other comprehensive loss, net of tax										(11)	3	(18)
COMPREHENSIVE INCOME (LOSS)										71	(241)	42
Tax effect of discontinued operations										0	70	8
FES | Affiliates
OPERATING EXPENSES:
Purchased power										353	271	486
OTHER INCOME (EXPENSE):
Interest expense										(7)	(7)	(10)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power										1,684	2,771	2,333
OTHER INCOME (EXPENSE):
Interest expense										$ (147)	$ (146)	$ (160)
[1]	Includes excise tax collections of $416 million, $420 million and $458 million in 2015, 2014 and 2013, respectively.
[2]	Includes excise tax collections of $44 million, $69 million and $78 million in 2015, 2014 and 2013, respectively.

Supplemental Guarantor Infor136

Supplemental Guarantor Information (Details 1) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash and cash equivalents	$ 131	$ 85	$ 218	$ 172
Receivables-
Customers	1,415	1,554
Other Receivables	180	225
Materials and supplies, at average cost	785	817
Derivatives	157	159
Collateral	70	230
Prepayments and other	167	160
Total current assets	3,040	3,358
PROPERTY, PLANT AND EQUIPMENT:
In service	49,952	47,484
Less - Accumulated provision for depreciation	15,160	14,150
Property, plant and equipment in service net of accumulated provision for depreciation	34,792	33,334
Construction work in progress	2,422	2,449
Total net property, plant and equipment	37,214	35,783
INVESTMENTS:
Nuclear plant decommissioning trusts	2,282	2,341
Other	506	881
Total other property and investments	2,788	3,222
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	331
Goodwill	6,418	6,418	6,418
Other	1,379	1,456
Total deferred charges and other assets	9,145	9,285
Total assets	52,187	51,648	50,424
CURRENT LIABILITIES:
Currently payable long-term debt	1,166	804
Short-term borrowings	1,708	1,799
Accounts payable-
Accrued taxes	519	490
Derivatives	106	167
Other	694	693
Total current liabilities	5,602	5,561
CAPITALIZATION:
Total equity	12,421	12,420
Long-term debt and other long-term obligations	19,192	19,176
Total capitalization	31,614	31,598
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	791	824
Accumulated deferred income taxes	6,773	6,539
Asset retirement obligations	1,410	1,387
Retirement benefits	4,245	3,932
Other	1,555	1,590
Total noncurrent liabilities	14,971	14,489
Total liabilities and capitalization	52,187	51,648
FES
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	275	415
Affiliated companies	433	484
Other Receivables	36	66
Notes receivable from affiliated companies	406	339
Materials and supplies, at average cost	53	67
Derivatives	154	147
Collateral	70	229
Prepayments and other	48	48
Total current assets	1,475	1,795
PROPERTY, PLANT AND EQUIPMENT:
In service	93	133
Less - Accumulated provision for depreciation	40	36
Property, plant and equipment in service net of accumulated provision for depreciation	53	97
Construction work in progress	30	3
Total net property, plant and equipment	83	100
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	7,452	6,607
Other	0	0
Total other property and investments	7,452	6,607
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	300	284
Customer intangibles	61	78
Goodwill	23	23
Property taxes	0	0
Unamortized sale and leaseback costs		0
Derivatives	79	52
Other	33	34
Total deferred charges and other assets	496	471
Total assets	9,506	8,973
CURRENT LIABILITIES:
Currently payable long-term debt	0	18
Short-term borrowings	0	90
Accounts payable-
Affiliated companies	884	1,068
Other	21	46
Accrued taxes	7	2
Derivatives	103	166
Other	66	72
Total current liabilities	3,102	2,597
CAPITALIZATION:
Total equity	5,605	5,585
Long-term debt and other long-term obligations	694	695
Total capitalization	6,299	6,280
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	6	13
Asset retirement obligations	0	0
Retirement benefits	27	36
Derivatives	37	14
Other	35	33
Total noncurrent liabilities	105	96
Total liabilities and capitalization	9,506	8,973
FES | Affiliates
CURRENT LIABILITIES:
Other Short-term Borrowings	2,021	1,135
FGCO
CURRENT ASSETS:
Cash and cash equivalents	2	2	2	3
Receivables-
Customers	0	0
Affiliated companies	403	487
Other Receivables	4	21
Notes receivable from affiliated companies	1,210	838
Materials and supplies, at average cost	204	202
Derivatives	0	0
Collateral	0	0
Prepayments and other	18	19
Total current assets	1,841	1,569
PROPERTY, PLANT AND EQUIPMENT:
In service	6,367	6,217
Less - Accumulated provision for depreciation	2,144	2,058
Property, plant and equipment in service net of accumulated provision for depreciation	4,223	4,159
Construction work in progress	249	206
Total net property, plant and equipment	4,472	4,365
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	0	0
Other	10	10
Total other property and investments	10	10
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	16	98
Customer intangibles	0	0
Goodwill	0	0
Property taxes	12	14
Unamortized sale and leaseback costs		0
Derivatives	0	0
Other	318	277
Total deferred charges and other assets	346	389
Total assets	6,669	6,333
CURRENT LIABILITIES:
Currently payable long-term debt	229	164
Short-term borrowings	8	9
Accounts payable-
Affiliated companies	146	197
Other	118	202
Accrued taxes	93	62
Derivatives	1	0
Other	61	56
Total current liabilities	1,045	1,011
CAPITALIZATION:
Total equity	2,944	2,561
Long-term debt and other long-term obligations	2,122	2,215
Total capitalization	5,066	4,776
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	0	0
Asset retirement obligations	191	189
Retirement benefits	305	288
Derivatives	1	0
Other	61	69
Total noncurrent liabilities	558	546
Total liabilities and capitalization	6,669	6,333
FGCO | Affiliates
CURRENT LIABILITIES:
Other Short-term Borrowings	389	321
Nuclear Generation Corp
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	461	674
Other Receivables	19	20
Notes receivable from affiliated companies	805	272
Materials and supplies, at average cost	213	223
Derivatives	0	0
Collateral	0	0
Prepayments and other	0	0
Total current assets	1,498	1,189
PROPERTY, PLANT AND EQUIPMENT:
In service	8,233	7,628
Less - Accumulated provision for depreciation	3,775	3,305
Property, plant and equipment in service net of accumulated provision for depreciation	4,458	4,323
Construction work in progress	878	801
Total net property, plant and equipment	5,336	5,124
INVESTMENTS:
Nuclear plant decommissioning trusts	1,327	1,365
Investment in affiliated companies	0	0
Other	0	0
Total other property and investments	1,327	1,365
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	0	0
Goodwill	0	0
Property taxes	28	27
Unamortized sale and leaseback costs		0
Derivatives	0	0
Other	21	7
Total deferred charges and other assets	49	34
Total assets	8,210	7,712
CURRENT LIABILITIES:
Currently payable long-term debt	308	348
Short-term borrowings	0	0
Accounts payable-
Affiliated companies	368	219
Other	0	0
Accrued taxes	62	161
Derivatives	0	0
Other	9	9
Total current liabilities	747	765
CAPITALIZATION:
Total equity	4,476	4,014
Long-term debt and other long-term obligations	847	859
Total capitalization	5,323	4,873
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	697	678
Asset retirement obligations	640	652
Retirement benefits	0	0
Derivatives	0	0
Other	803	744
Total noncurrent liabilities	2,140	2,074
Total liabilities and capitalization	8,210	7,712
Nuclear Generation Corp | Affiliates
CURRENT LIABILITIES:
Other Short-term Borrowings	0	28
Eliminations
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	(846)	(1,120)
Other Receivables	0	0
Notes receivable from affiliated companies	(2,410)	(1,449)
Materials and supplies, at average cost	0	0
Derivatives	0	0
Collateral	0	0
Prepayments and other	0	1
Total current assets	(3,256)	(2,568)
PROPERTY, PLANT AND EQUIPMENT:
In service	(382)	(382)
Less - Accumulated provision for depreciation	(194)	(191)
Property, plant and equipment in service net of accumulated provision for depreciation	(188)	(191)
Construction work in progress	0	0
Total net property, plant and equipment	(188)	(191)
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	(7,452)	(6,607)
Other	0	0
Total other property and investments	(7,452)	(6,607)
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	(316)	(382)
Customer intangibles	0	0
Goodwill	0	0
Property taxes	0	0
Unamortized sale and leaseback costs		0
Derivatives	0	0
Other	12	13
Total deferred charges and other assets	(304)	(369)
Total assets	(11,200)	(9,735)
CURRENT LIABILITIES:
Currently payable long-term debt	(25)	(24)
Short-term borrowings	0	0
Accounts payable-
Affiliated companies	(856)	(1,068)
Other	0	0
Accrued taxes	(86)	(123)
Derivatives	0	0
Other	45	47
Total current liabilities	(3,332)	(2,617)
CAPITALIZATION:
Total equity	(7,420)	(6,575)
Long-term debt and other long-term obligations	(1,136)	(1,161)
Total capitalization	(8,556)	(7,736)
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	791	824
Accumulated deferred income taxes	(103)	(207)
Asset retirement obligations	0	0
Retirement benefits	0	0
Derivatives	0	0
Other	0	1
Total noncurrent liabilities	688	618
Total liabilities and capitalization	(11,200)	(9,735)
Eliminations | Affiliates
CURRENT LIABILITIES:
Other Short-term Borrowings	(2,410)	(1,449)
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2	$ 2	$ 3
Receivables-
Customers	275	415
Affiliated companies	451	525
Other Receivables	59	107
Notes receivable from affiliated companies	11	0
Materials and supplies, at average cost	470	492
Derivatives	154	147
Collateral	70	229
Prepayments and other	66	68
Total current assets	1,558	1,985
PROPERTY, PLANT AND EQUIPMENT:
In service	14,311	13,596
Less - Accumulated provision for depreciation	5,765	5,208
Property, plant and equipment in service net of accumulated provision for depreciation	8,546	8,388
Construction work in progress	1,157	1,010
Total net property, plant and equipment	9,703	9,398
INVESTMENTS:
Nuclear plant decommissioning trusts	1,327	1,365
Investment in affiliated companies	0	0
Other	10	10
Total other property and investments	1,337	1,375
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	61	78
Goodwill	23	23
Property taxes	40	41
Unamortized sale and leaseback costs		0
Derivatives	79	52
Other	384	331
Total deferred charges and other assets	587	525
Total assets	13,185	13,283
CURRENT LIABILITIES:
Currently payable long-term debt	512	506
Short-term borrowings	8	99
Accounts payable-
Affiliated companies	542	416
Other	139	248
Accrued taxes	76	102
Derivatives	104	166
Other	181	184
Total current liabilities	1,562	1,756
CAPITALIZATION:
Total equity	5,605	5,585
Long-term debt and other long-term obligations	2,527	2,608
Total capitalization	8,132	8,193
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	791	824
Accumulated deferred income taxes	600	484
Asset retirement obligations	831	841
Retirement benefits	332	324
Derivatives	38	14
Other	899	847
Total noncurrent liabilities	3,491	3,334
Total liabilities and capitalization	13,185	13,283
FES | Affiliates
CURRENT LIABILITIES:
Other Short-term Borrowings	$ 0	$ 35

Supplemental Guarantor Infor137

Supplemental Guarantor Information (Details 2) - USD ($) $ in Millions	Feb. 12, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities		$ 3,447	$ 2,713	$ 2,662
New Financing-
Long-term debt		1,311	4,528	3,745
Short-term borrowings, net		0	0	1,435
Redemptions and Repayments-
Long-term debt		(879)	(1,759)	(3,600)
Short-term borrowings, net		(91)	(1,605)	0
Common stock dividend payments		(607)	(604)	(920)
Tender premiums		0	0	(110)
Other		(13)	(47)	(73)
Net cash provided from (used for) financing activities		(279)	513	477
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(2,704)	(3,312)	(2,638)
Nuclear fuel		(190)	(233)	(250)
Proceeds from asset sales	$ 394	20	394	4
Sales of investment securities held in trusts		1,534	2,133	2,047
Purchases of investment securities held in trusts		(1,648)	(2,236)	(2,096)
Cash investments		7	35	(23)
Other		1	13	9
Net cash used for investing activities		(3,122)	(3,359)	(3,093)
Net change in cash and cash equivalents		46	(133)	46
Cash and cash equivalents at beginning of period		85	218	172
Cash and cash equivalents at end of period		131	85	218
FES
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities		(637)	(600)	(1,429)
New Financing-
Long-term debt		0	0
Short-term borrowings, net		796	247	864
Equity contribution from parent			500	1,500
Redemptions and Repayments-
Long-term debt		(17)	(1)	(770)
Short-term borrowings, net		0	0	(244)
Common stock dividend payments		(70)
Tender premiums				(67)
Other			(1)	(4)
Net cash provided from (used for) financing activities		709	745	1,279
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(5)	(8)	(12)
Nuclear fuel		0	0	0
Proceeds from asset sales		10	0	0
Sales of investment securities held in trusts		0	0	0
Purchases of investment securities held in trusts		0	0	0
Cash investments		(10)
Loans to affiliated companies, net		(67)	(136)	163
Other		0	(1)	(1)
Net cash used for investing activities		(72)	(145)	150
Net change in cash and cash equivalents		0	0	0
Cash and cash equivalents at beginning of period		0	0	0
Cash and cash equivalents at end of period		0	0	0
FGCO
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities		551	408	753
New Financing-
Long-term debt		45	431
Short-term borrowings, net		67	114	371
Equity contribution from parent			0	0
Redemptions and Repayments-
Long-term debt		(70)	(269)	(364)
Short-term borrowings, net		0	0	(505)
Common stock dividend payments		0
Tender premiums				0
Other		(5)	(12)	(5)
Net cash provided from (used for) financing activities		37	264	(503)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(223)	(169)	(256)
Nuclear fuel		0	0	0
Proceeds from asset sales		3	307	21
Sales of investment securities held in trusts		0	0	0
Purchases of investment securities held in trusts		0	0	0
Cash investments		0
Loans to affiliated companies, net		(372)	(815)	(15)
Other		4	5	(1)
Net cash used for investing activities		(588)	(672)	(251)
Net change in cash and cash equivalents		0	0	(1)
Cash and cash equivalents at beginning of period		2	2	3
Cash and cash equivalents at end of period		2	2	2
Nuclear Generation Corp
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities		1,261	785	776
New Financing-
Long-term debt		296	447
Short-term borrowings, net		0	0	150
Equity contribution from parent			0	0
Redemptions and Repayments-
Long-term debt		(348)	(568)	(90)
Short-term borrowings, net		(28)	(123)	0
Common stock dividend payments		0
Tender premiums				0
Other		(1)	(2)	0
Net cash provided from (used for) financing activities		(81)	(246)	60
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(399)	(662)	(449)
Nuclear fuel		(190)	(233)	(250)
Proceeds from asset sales		0	0	0
Sales of investment securities held in trusts		733	1,163	940
Purchases of investment securities held in trusts		(791)	(1,219)	(1,000)
Cash investments		0
Loans to affiliated companies, net		(533)	412	(77)
Other		0	0	0
Net cash used for investing activities		(1,180)	(539)	(836)
Net change in cash and cash equivalents		0	0	0
Cash and cash equivalents at beginning of period		0	0	0
Cash and cash equivalents at end of period		0	0	0
Eliminations
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities		(24)	(22)	(22)
New Financing-
Long-term debt		0	0
Short-term borrowings, net		(863)	(361)	(954)
Equity contribution from parent			0	0
Redemptions and Repayments-
Long-term debt		24	22	22
Short-term borrowings, net		(98)	(178)	749
Common stock dividend payments		0
Tender premiums				0
Other			0	0
Net cash provided from (used for) financing activities		(937)	(517)	(183)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		0	0	0
Nuclear fuel		0	0	0
Proceeds from asset sales		0	0	0
Sales of investment securities held in trusts		0	0	0
Purchases of investment securities held in trusts		0	0	0
Cash investments		0
Loans to affiliated companies, net		961	539	205
Other		0	0	0
Net cash used for investing activities		961	539	205
Net change in cash and cash equivalents		0	0	0
Cash and cash equivalents at beginning of period		0	0	0
Cash and cash equivalents at end of period		0	0	0
FES
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities		1,151	571	78
New Financing-
Long-term debt		341	878	0
Short-term borrowings, net		0	0	431
Equity contribution from parent		0	500	1,500
Redemptions and Repayments-
Long-term debt		(411)	(816)	(1,202)
Short-term borrowings, net		(126)	(301)	0
Common stock dividend payments		(70)	0	0
Tender premiums		0	0	(67)
Other		(6)	(15)	(9)
Net cash provided from (used for) financing activities		(272)	246	653
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(627)	(839)	(717)
Nuclear fuel		(190)	(233)	(250)
Proceeds from asset sales	$ 307	13	307	21
Sales of investment securities held in trusts		733	1,163	940
Purchases of investment securities held in trusts		(791)	(1,219)	(1,000)
Cash investments		(10)	0	0
Loans to affiliated companies, net		(11)	0	276
Other		4	4	(2)
Net cash used for investing activities		(879)	(817)	(732)
Net change in cash and cash equivalents		0	0	(1)
Cash and cash equivalents at beginning of period		2	2	3
Cash and cash equivalents at end of period		$ 2	$ 2	$ 2

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Financial Information
External revenues										$ 15,026	$ 15,049	$ 14,892
Total revenues	[1]									15,026	15,049	14,892
Depreciation		$ 313	$ 328	$ 322	$ 319	$ 316	$ 308	$ 302	$ 294	1,282	1,220	1,202
Amortization of regulatory asset, net										268	12	539
Impairment of long-lived assets										42	0	795
Investment Income, Net										(22)	72	33
Impairment of equity method investment										362	0	0
Interest expense										1,132	1,073	1,016
Income taxes (benefits)		(170)	226	115	144	(268)	152	26	48	315	(42)	195
Income (loss) from continuing operations		(226)	395	187	222	(306)	333	64	122	578	213	375
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)		0	0	0	0	0	0	0	86	0	86	17
NET INCOME (LOSS)		(226)	$ 395	$ 187	$ 222	(306)	$ 333	$ 64	$ 208	578	299	392
Total assets		52,187				51,648				52,187	51,648	50,424
Total goodwill		6,418				6,418				6,418	6,418	6,418
Property additions										2,704	3,312	2,638
Intersegment Eliminations
Segment Financial Information
External revenues										0	0	0
Regulated Distribution
Segment Financial Information
External revenues										9,625	9,102	8,720
Total revenues										9,625	9,102	8,720
Depreciation										672	658	606
Amortization of regulatory asset, net										261	1	529
Impairment of long-lived assets										8	0	322
Investment Income, Net										42	56	57
Impairment of equity method investment										0	0	0
Interest expense										586	589	543
Income taxes (benefits)										342	227	301
Income (loss) from continuing operations										618	465	501
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)										0	0	0
NET INCOME (LOSS)										618	465	501
Total assets		27,876				28,085				27,876	28,085	27,683
Total goodwill		5,092				5,092				5,092	5,092	5,092
Property additions										1,108	972	1,272
Regulated Distribution | Intersegment Eliminations
Segment Financial Information
External revenues										0	0	0
Regulated Transmission
Segment Financial Information
External revenues										1,011	769	731
Total revenues										1,011	769	731
Depreciation										156	127	114
Amortization of regulatory asset, net										7	11	10
Impairment of long-lived assets										0	0	0
Investment Income, Net										0	0	0
Impairment of equity method investment										0	0	0
Interest expense										161	131	93
Income taxes (benefits)										174	121	129
Income (loss) from continuing operations										298	223	214
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)										0	0	0
NET INCOME (LOSS)										298	223	214
Total assets		7,439				6,252				7,439	6,252	5,247
Total goodwill		526				526				526	526	526
Property additions										952	1,329	461
Regulated Transmission | Intersegment Eliminations
Segment Financial Information
External revenues										0	0	0
Competitive Energy Services
Segment Financial Information
External revenues										4,698	5,470	5,728
Total revenues										5,384	6,289	6,498
Depreciation										394	387	439
Amortization of regulatory asset, net										0	0	0
Impairment of long-lived assets										34	0	473
Investment Income, Net										(16)	54	14
Impairment of equity method investment										0	0	0
Interest expense										192	189	222
Income taxes (benefits)										50	(223)	(140)
Income (loss) from continuing operations										89	(417)	(235)
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)										0	86	17
NET INCOME (LOSS)										89	(331)	(218)
Total assets		16,365				16,518				16,365	16,518	16,782
Total goodwill		800				800				800	800	800
Property additions										588	939	827
Competitive Energy Services | Intersegment Eliminations
Segment Financial Information
External revenues										686	819	770
Reconciling Adjustments
Segment Financial Information
External revenues										(140)	(146)	(166)
Total revenues										(826)	(965)	(936)
Depreciation										0	0	0
Amortization of regulatory asset, net										0	0	0
Impairment of long-lived assets										0	0	0
Investment Income, Net										(39)	(40)	(44)
Impairment of equity method investment										0	0	0
Interest expense										0	(4)	10
Income taxes (benefits)										11	11	10
Income (loss) from continuing operations										0	0	0
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)										0	0	0
NET INCOME (LOSS)										0	0	0
Total assets		0				0				0	0	0
Total goodwill		0				0				0	0	0
Property additions										0	0	0
Reconciling Adjustments | Intersegment Eliminations
Segment Financial Information
External revenues										(686)	(819)	(770)
Other/Corporate
Segment Financial Information
External revenues										(168)	(146)	(121)
Total revenues										(168)	(146)	(121)
Depreciation										60	48	43
Amortization of regulatory asset, net										0	0	0
Impairment of long-lived assets										0	0	0
Investment Income, Net										(9)	2	6
Impairment of equity method investment										362	0	0
Interest expense										193	168	148
Income taxes (benefits)										(262)	(178)	(105)
Income (loss) from continuing operations										(427)	(58)	(105)
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)										0	0	0
NET INCOME (LOSS)										(427)	(58)	(105)
Total assets		507				793				507	793	712
Total goodwill		$ 0				$ 0				0	0	0
Property additions										56	72	78
Other/Corporate | Intersegment Eliminations
Segment Financial Information
External revenues										$ 0	$ 0	$ 0
[1]	Includes excise tax collections of $416 million, $420 million and $458 million in 2015, 2014 and 2013, respectively.

Segment Information (Details Te

Segment Information (Details Textuals) mi² in Thousands, customer in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2015USD ($)mi²customercompanyMW	Oct. 09, 2013MW
Segment Reporting Information [Line Items]
Ownership interest (percent)	3.00%
Other/Corporate
Segment Reporting Information [Line Items]
Long-term debt and other long-term obligations | $	$ 4.2
Debt subject to variable interest rate (percent)	28.00%
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 | MW		3,790
CES
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment | MW	13,162
Parent Company | Revolving Credit Facility | Other/Corporate
Segment Reporting Information [Line Items]
Long-term line of credit | $	$ 1.7
Global Holding | Signal Peak | FEV
Segment Reporting Information [Line Items]
Ownership interest (percent)	33.33%

Discontinued Operations (Detail

Discontinued Operations (Details) $ in Millions	Feb. 12, 2014USD ($)plant	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales	$ 394	$ 20	$ 394	$ 4
Assets held-for-sale	235
Goodwill	29
Pre-tax income			155	26
Pre-tax gain on sale of assets			142
Revenue			5	33
FES
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales	307	$ 13	307	21
Assets held-for-sale	122
Goodwill	$ 1
Pre-tax income			186	22
Pre-tax gain on sale of assets			177
Revenue			$ 5	$ 31
FERC | Hydroelectric Asset Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Application to sell power plant projects, number | plant	11

Summary of Quarterly Financi141

Summary of Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Data [Line Items]
Revenues	$ 3,541	$ 4,123	$ 3,465	$ 3,897	$ 3,483	$ 3,888	$ 3,496	$ 4,182	$ 10,636	$ 9,871	$ 9,451
Other operating expenses	952	850	916	1,057	901	858	1,021	1,182	3,749	3,962	3,593
Pension and OPEB mark-to-market	242	0	0	0	835	0	0	0	242	835	(256)
Provision for depreciation	313	328	322	319	316	308	302	294	1,282	1,220	1,202
Impairment of long-lived assets									42	0	795
Operating Income (Loss)	236	908	554	594	(337)	716	292	391	2,292	1,062	1,582
Income (loss) from continuing operations before income taxes (benefits)	(396)	621	302	366	(574)	485	90	170
Total provision for income taxes	(170)	226	115	144	(268)	152	26	48	315	(42)	195
Income (loss) from continuing operations	(226)	395	187	222	(306)	333	64	122	578	213	375
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)	0	0	0	0	0	0	0	86	0	86	17
NET INCOME (LOSS)	$ (226)	$ 395	$ 187	$ 222	$ (306)	$ 333	$ 64	$ 208	$ 578	$ 299	$ 392
Earnings per share of common stock-
Basic - Continuing Operations, in dollars per share	$ (0.53)	$ 0.94	$ 0.44	$ 0.53	$ (0.73)	$ 0.79	$ 0.16	$ 0.29	$ 1.37	$ 0.51	$ 0.90
Basic - Discontinued Operations, in dollars per share	0	0	0	0	0	0	0	0.21	0	0.20	0.04
Basic - Earnings Available to FirstEnergy Corp., in dollars per share	(0.53)	0.94	0.44	0.53	(0.73)	0.79	0.16	0.50	1.37	0.71	0.94
Diluted - Continuing Operations, in dollars per share	(0.53)	0.93	0.44	0.53	(0.73)	0.79	0.15	0.29	1.37	0.51	0.90
Diluted - Discontinued Operations, in dollars per share	0	0	0	0	0	0	0	0.20	0	0.20	0.04
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share	$ (0.53)	$ 0.93	$ 0.44	$ 0.53	$ (0.73)	$ 0.79	$ 0.15	$ 0.49	$ 1.37	$ 0.71	$ 0.94
Adjustments from prior periods					$ 16					$ (25)
FES
Quarterly Financial Data [Line Items]
Revenues	$ 1,171	$ 1,338	$ 1,119	$ 1,377	1,342	$ 1,521	$ 1,452	$ 1,829
Other operating expenses	329	246	353	413	359	356	468	452	$ 1,341	1,635	$ 1,487
Pension and OPEB mark-to-market	57	0	0	0	297	0	0	0	57	297	(81)
Provision for depreciation	84	79	81	80	83	83	79	74	324	319	306
Operating Income (Loss)	25	240	0	12	(321)	90	(151)	(148)	277	(530)	242
Income (loss) from continuing operations before income taxes (benefits)	(13)	190	(25)	(5)	(347)	72	(154)	(159)
Total provision for income taxes	1	70	(4)	(2)	(133)	28	(67)	(56)	65	(228)	6
Income (loss) from continuing operations	(14)	120	(21)	(3)	(214)	44	(87)	(103)	82	(360)	46
Discontinued operations (net of income taxes of $0, $69 and $9, respectively) (Note 19)	0	0	0	0	0	0	0	116	0	116	14
NET INCOME (LOSS)	$ (14)	$ 120	$ (21)	$ (3)	$ (214)	$ 44	$ (87)	$ 13	$ 82	$ (244)	$ 60

Consolidated Valuation and Q142

Consolidated Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated provision for uncollectible accounts - customers
Consolidated Valuation and Qualifying Accounts
Beginning Balance	$ 59,266	$ 51,630	$ 40,354
Charged to Income	114,249	90,144	68,733
Charged to Other Accounts	54,199	36,373	39,775
Deductions	158,939	118,881	97,232
Ending Balance	68,775	59,266	51,630
Accumulated provision for uncollectible accounts - customers | FES
Consolidated Valuation and Qualifying Accounts
Beginning Balance	17,862	11,073	16,188
Charged to Income	7,411	21,942	14,294
Charged to Other Accounts	0	0	0
Deductions	16,807	15,153	19,409
Ending Balance	8,466	17,862	11,073
Accumulated provision for uncollectible accounts - other
Consolidated Valuation and Qualifying Accounts
Beginning Balance	5,197	2,976	4,013
Charged to Income	899	3,469	(1,464)
Charged to Other Accounts	4,189	8,264	5,208
Deductions	5,054	9,512	4,781
Ending Balance	5,231	5,197	2,976
Accumulated provision for uncollectible accounts - other | FES
Consolidated Valuation and Qualifying Accounts
Beginning Balance	2,500	2,523	2,500
Charged to Income	0	9	28
Charged to Other Accounts	0	0	0
Deductions	0	32	5
Ending Balance	2,500	2,500	2,523
Loss carryforward tax valuation reserve
Consolidated Valuation and Qualifying Accounts
Beginning Balance	174,004	125,360	101,697
Charged to Income	18,393	48,644	23,663
Charged to Other Accounts	0	0	0
Deductions	0	0	0
Ending Balance	192,397	174,004	125,360
Loss carryforward tax valuation reserve | FES
Consolidated Valuation and Qualifying Accounts
Beginning Balance	32,126	26,875	15,810
Charged to Income	13,682	5,251	11,065
Charged to Other Accounts	0	0	0
Deductions	0	0	0
Ending Balance	$ 45,808	$ 32,126	$ 26,875