FirstEnergy (FE) 10-K 27 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	Jun. 30, 2013
Entity Information [Line Items]	'	'	'
Entity Registrant Name	'FIRSTENERGY CORP	'	'
Entity Central Index Key	'0001031296	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Common Stock Shares Outstanding	'	418,734,086	'
Entity Public Float	'	'	$15,570,961,427
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	'0001407703	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Document Fiscal Year Focus	'2013	'	'
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_Inc

Consolidated Statements of Income (FirstEnergy Corp.) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
REVENUES:	'		'		'
Electric utilities	$9,479		$9,800		$10,573
Unregulated businesses	5,438		5,473		5,532
Total revenues	14,917	[1]	15,273	[1]	16,105	[1]
OPERATING EXPENSES:	'		'		'
Fuel	2,496		2,471		2,317
Purchased power	3,963		4,246		4,874
Other operating expenses	3,593		3,760		3,949
Pensions and OPEB mark-to-market adjustment	-256		609		507
Provision for depreciation	1,202		1,119		1,062
Deferral of storm costs	0		-375		-145
Amortization of regulatory assets, net	539		307		474
General taxes	978		984		977
Impairment of long-lived assets (Note 11)	795		0		413
Total operating expenses	13,310		13,121		14,428
OPERATING INCOME (LOSS)	1,607		2,152		1,677
OTHER INCOME (EXPENSE):	'		'		'
Loss on debt redemptions	-132		0		0
Gain on partial sale of Signal Peak	0		0		569
Investment income	36		77		114
Interest expense	-1,016		-1,001		-1,008
Capitalized interest	75		72		70
Total other income (expense)	-1,037		-852		-255
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	570		1,300		1,422
INCOME TAXES	195		545		566
INCOME FROM CONTINUING OPERATIONS	375		755		856
Discontinued operations (net of income taxes of $9, $8 and $8, respectively) (Note 20)	17		16		13
NET INCOME (LOSS)	392		771		869
Income attributable to noncontrolling interest	0		1		-16
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$392		$770		$885
EARNINGS PER SHARE OF COMMON STOCK:	'		'		'
Basic - Continuing Operations, in dollars per share	$0.90		$1.81		$2.19
Basic - Discontinued Operations (Note 20), in dollars per share	$0.04		$0.04		$0.03
Basic - Earnings Available to FirstEnergy Corp., in dollars per share	$0.94		$1.85		$2.22
Diluted - Continuing Operations, in dollars per share	$0.90		$1.80		$2.18
Diluted - Discontinued Operations (Note 20), in dollars per share	$0.04		$0.04		$0.03
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share	$0.94		$1.84		$2.21
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:	'		'		'
Basic, in shares	418		418		399
Diluted, in shares	419		419		401
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share	$1.65		$2.20		$2.20
[1]	Includes excise tax collections of $458 million, $484 million and $511 million in 2013, 2012 and 2011, respectively.

Consolidated_Statements_of_Inc1

Consolidated Statements of Income (FirstEnergy Corp.) (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]	'	'	'
Tax effect of discontinued operations	$9	$8	$8
Excise tax collections included in Revenue	$458	$484	$511

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (FirstEnergy Corp.) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Other Comprehensive Income [Abstract]	'	'	'
NET INCOME	$392	$771	$869
OTHER COMPREHENSIVE INCOME (LOSS):	'	'	'
Pensions and OPEB prior service costs	-160	-115	-90
Amortized losses on derivative hedges	3	1	23
Change in unrealized gain on available-for-sale securities	-10	-6	19
Other comprehensive income (loss)	-167	-120	-48
Income tax benefits on other comprehensive loss	-66	-79	-49
Other comprehensive income (loss), net of tax	-101	-41	1
COMPREHENSIVE INCOME (LOSS)	291	730	870
Comprehensive income (loss) attributable to noncontrolling interest	0	1	-16
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	$291	$729	$886

Consolidated_Balance_Sheets_Fi

Consolidated Balance Sheets (FirstEnergy Corp.) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'
Cash and cash equivalents	$218	$172
Receivables-	'	'
Customers, net of allowance for uncollectible accounts of $52 in 2013 and $40 in 2012	1,720	1,614
Other, net of allowance for uncollectible accounts of $3 in 2013 and $4 in 2012	198	315
Materials and supplies, at average cost	752	861
Prepaid taxes	226	119
Derivatives	166	160
Accumulated deferred income taxes	366	319
Other	241	208
Total current assets	3,887	3,768
PROPERTY, PLANT AND EQUIPMENT:	'	'
In service	44,228	43,210
Less - Accumulated provision for depreciation	13,280	12,467
Property, plant and equipment in service net of accumulated provision for depreciation	30,948	30,743
Construction work in progress	2,304	2,293
Total net property, plant and equipment	33,252	33,036
INVESTMENTS:	'	'
Nuclear plant decommissioning trusts	2,201	2,204
Investments in lease obligation bonds	33	54
Other	870	936
Total other property and investments	3,104	3,194
ASSETS HELD FOR SALE (Note 20)	235	0
DEFERRED CHARGES AND OTHER ASSETS:	'	'
Goodwill	6,418	6,447
Regulatory assets	1,854	2,330
Other	1,674	1,719
Total deferred charges and other assets	9,946	10,496
Total assets	50,424	50,494
CURRENT LIABILITIES:	'	'
Currently payable long-term debt	1,415	1,999
Short-term borrowings	3,404	1,969
Accounts payable	1,250	1,599
Accrued taxes	485	543
Accrued compensation and benefits	351	331
Derivatives	111	126
Other	621	1,038
Total current liabilities	7,637	7,605
Common stockholders' equity-	'	'
Common stock, $0.10 par value, authorized 490,000,000 shares - 418,628,559 shares outstanding	42	42
Other paid-in capital	9,776	9,769
Accumulated other comprehensive income	284	385
Retained earnings	2,590	2,888
Total common stockholders' equity	12,692	13,084
Noncontrolling interest	3	9
Total equity	12,695	13,093
Long-term debt and other long-term obligations	15,831	15,179
Total capitalization	28,526	28,272
NONCURRENT LIABILITIES:	'	'
Accumulated deferred income taxes	6,968	6,616
Retirement benefits	2,689	3,080
Asset retirement obligations	1,678	1,599
Deferred gain on sale and leaseback transaction	858	892
Adverse power contract liability	290	506
Other	1,778	1,924
Total noncurrent liabilities	14,261	14,617
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 16)	'	'
Total liabilities and capitalization	$50,424	$50,494

Consolidated_Balance_Sheets_Fi1

Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, except Share data, unless otherwise specified
Common stockholders' equity-	'	'
Common stock, par value (in dollars per share)	$0.10	$0.10
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	418,628,559	418,628,559
Customer [Member]	'	'
Receivables-	'	'
Allowance for uncollectible accounts (in dollars)	$52	$40
Other [Member]	'	'
Receivables-	'	'
Allowance for uncollectible accounts (in dollars)	$3	$4

Consolidated_Statements_of_Com1

Consolidated Statements of Common Stockholders' Equity (FirstEnergy Corp.) (USD $)	Total	Common Stock	Other Paid-In Capital	Accumulated Other Comprehensive Income (Loss)	Retained Earnings (Accumulated Deficit)
In Millions, except Share data, unless otherwise specified
Beginning Balance at Dec. 31, 2010	'	$31	$5,444	$425	$3,084
Beginning Balance, Shares at Dec. 31, 2010	'	304,835,407	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Earnings available to Parent	885	'	'	'	885
Change in unrealized loss on derivative hedges, net of income taxes	'	'	'	15	'
Change in unrealized gain on investments, net of income taxes	'	'	'	12	'
Pensions and OPEB, net of income taxes	'	'	'	-26	'
Stock-based compensation	'	'	5	'	'
Allegheny merger, Shares	'	113,381,030	'	'	'
Allegheny merger	'	11	4,316	'	'
Cash dividends declared on common stock	'	'	'	'	-922
Ending Balance at Dec. 31, 2011	'	42	9,765	426	3,047
Ending Balance, Shares at Dec. 31, 2011	'	418,216,437	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Earnings available to Parent	770	'	'	'	770
Change in unrealized loss on derivative hedges, net of income taxes	'	'	'	2	'
Change in unrealized gain on investments, net of income taxes	'	'	'	-4	'
Pensions and OPEB, net of income taxes	'	'	'	-39	'
Stock-based compensation	'	'	4	'	'
Cash dividends declared on common stock	'	'	'	'	-920
Equity method adjustment (Note 9)	'	'	'	'	-9
Ending Balance at Dec. 31, 2012	13,084	42	9,769	385	2,888
Ending Balance, Shares at Dec. 31, 2012	418,628,559	418,216,437	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'
Earnings available to Parent	392	'	'	'	392
Change in unrealized 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 at Dec. 31, 2013	$12,692	$42	$9,776	$284	$2,590
Ending Balance, Shares at Dec. 31, 2013	418,628,559	418,628,559	'	'	'

Consolidated_Statements_of_Com2

Consolidated Statements of Common Stockholders' Equity (FirstEnergy Corp.) (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Stockholders' Equity [Abstract]	'	'	'
Unrealized gain (loss) on derivative hedges taxes	$1	($1)	$8
Unrealized gain (loss) on investment taxes	-4	-2	7
Taxes on pension and other postretirement taxes	($63)	($76)	($64)

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (FirstEnergy Corp.) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'	'
NET INCOME	$392	$771	$869
Adjustments to reconcile net income to net cash from operating activities-	'	'	'
Provision for depreciation	1,202	1,119	1,062
Asset removal costs charged to income	20	203	55
Amortization of regulatory assets, net	539	307	474
Deferral of storm costs	0	-375	-145
Nuclear fuel amortization	209	210	201
Deferred purchased power and other costs	-76	-238	-278
Deferred income taxes and investment tax credits, net	243	647	798
Impairments of long-lived assets	795	0	413
Investment impairments	90	27	19
Deferred rents and lease market valuation liability	-54	-104	-49
Pensions and OPEB mark-to-market adjustment	-256	609	507
Retirement benefits	-168	-127	-151
Gain on asset sales	-21	-17	-545
Commodity derivative transactions, net (Note 10)	4	-95	-27
Pension trust contributions	0	-600	-372
Cash collateral, net	-42	16	-79
Gain on sale of investment securities held in trusts, net	-56	-71	-59
Loss on debt redemptions	132	0	0
Make-whole premiums paid on debt redemptions	-187	0	0
Income from discontinued operations (Note 20)	-17	-16	-13
Decrease (increase) in operating assets-	'	'	'
Receivables	-114	-13	147
Materials and supplies	96	-50	14
Prepayments and other current assets	-126	-12	101
Increase (decrease) in operating liabilities-	'	'	'
Accounts payable	-25	100	60
Accrued taxes	85	-2	83
Accrued interest	-10	-12	-12
Accrued compensation and benefits	19	-55	69
Other	-12	98	-79
Net cash provided from operating activities	2,662	2,320	3,063
New Financing-	'	'	'
Long-term debt	3,745	750	604
Short-term borrowings, net	1,435	1,969	0
Redemptions and Repayments-	'	'	'
Long-term debt	-3,600	-940	-1,909
Short-term borrowings, net	0	0	-700
Tender premiums paid on debt redemptions	-110	0	0
Common stock dividend payments	-920	-920	-881
Other	-73	-52	-38
Net cash provided from (used for) financing activities	477	807	-2,924
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Property additions	-2,638	-2,678	-2,129
Nuclear fuel	-250	-286	-149
Proceeds from asset sales	4	17	840
Sales of investment securities held in trusts	2,047	2,980	4,207
Purchases of investment securities held in trusts	-2,096	-3,020	-4,309
Cash investments	-23	102	60
Cash received in Allegheny merger	0	0	590
Asset removal costs	-146	-229	-114
Other	9	-43	48
Net cash used for investing activities	-3,093	-3,157	-956
Net change in cash and cash equivalents	46	-30	-817
Cash and cash equivalents at beginning of period	172	202	1,019
Cash and cash equivalents at end of period	218	172	202
SUPPLEMENTAL CASH FLOW INFORMATION:	'	'	'
Non-cash transaction: common stock issued in merger with Allegheny	0	0	4,354
Interest (net of amounts capitalized)	969	962	935
Income taxes	$36	($6)	($358)

Consolidated_Statements_of_Inc2

Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
REVENUES:	'		'		'
Electric sales	$5,438		$5,473		$5,532
Total revenues	14,917	[1]	15,273	[1]	16,105	[1]
OPERATING EXPENSES:	'		'		'
Fuel	2,496		2,471		2,317
Purchased power	3,963		4,246		4,874
Other operating expenses	3,593		3,760		3,949
Pensions and OPEB mark-to-market adjustment	-256		609		507
Provision for depreciation	1,202		1,119		1,062
General taxes	978		984		977
Total operating expenses	13,310		13,121		14,428
OPERATING INCOME (LOSS)	1,607		2,152		1,677
OTHER INCOME (EXPENSE):	'		'		'
Loss on debt redemptions	-132		0		0
Investment income	36		77		114
Interest expense	-1,016		-1,001		-1,008
Capitalized interest	75		72		70
Total other income (expense)	-1,037		-852		-255
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	570		1,300		1,422
INCOME TAXES (BENEFITS)	195		545		566
INCOME FROM CONTINUING OPERATIONS	375		755		856
Discontinued operations (net of income taxes of $8, $8 and $5, respectively) (Note 20)	17		16		13
NET INCOME (LOSS)	392		771		869
STATEMENTS OF COMPREHENSIVE INCOME	'		'		'
NET INCOME	392		771		869
OTHER COMPREHENSIVE INCOME (LOSS):	'		'		'
Pensions and OPEB prior service costs	-160		-115		-90
Amortized loss (gain) on derivative hedges	3		1		23
Change in unrealized gain on available-for-sale securities	-10		-6		19
Other comprehensive income (loss)	-167		-120		-48
Income taxes (benefits) on other comprehensive income (loss)	-66		-79		-49
Other comprehensive income (loss), net of tax	-101		-41		1
COMPREHENSIVE INCOME (LOSS)	291		730		870
FES	'		'		'
REVENUES:	'		'		'
Other	143		126		223
Total revenues	6,173		5,894		5,453
OPERATING EXPENSES:	'		'		'
Fuel	1,262		1,287		1,344
Other operating expenses	1,487		1,356		1,619
Pensions and OPEB mark-to-market adjustment	-81		166		171
Provision for depreciation	306		272		272
General taxes	138		136		124
Impairment of long-lived assets	0		0		294
Total operating expenses	5,931		5,555		5,447
OPERATING INCOME (LOSS)	242		339		6
OTHER INCOME (EXPENSE):	'		'		'
Loss on debt redemptions	-103		0		0
Investment income	16		66		57
Miscellaneous income	28		35		30
Capitalized interest	39		37		35
Total other income (expense)	-190		-63		-89
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	52		276		-83
INCOME TAXES (BENEFITS)	6		103		-16
INCOME FROM CONTINUING OPERATIONS	46		173		-67
Discontinued operations (net of income taxes of $8, $8 and $5, respectively) (Note 20)	14		14		8
NET INCOME (LOSS)	60		187		-59
STATEMENTS OF COMPREHENSIVE INCOME	'		'		'
NET INCOME	60		187		-59
OTHER COMPREHENSIVE INCOME (LOSS):	'		'		'
Pensions and OPEB prior service costs	-15		6		-12
Amortized loss (gain) on derivative hedges	-6		-9		12
Change in unrealized gain on available-for-sale securities	-8		-5		16
Other comprehensive income (loss)	-29		-8		16
Income taxes (benefits) on other comprehensive income (loss)	-11		-4		2
Other comprehensive income (loss), net of tax	-18		-4		14
COMPREHENSIVE INCOME (LOSS)	42		183		-45
FES | Affiliates	'		'		'
REVENUES:	'		'		'
Electric sales	652		515		752
OPERATING EXPENSES:	'		'		'
Purchased power	486		451		242
OTHER INCOME (EXPENSE):	'		'		'
Interest expense	-10		-10		-8
FES | Non-Affiliates	'		'		'
REVENUES:	'		'		'
Electric sales	5,378		5,253		4,478
OPERATING EXPENSES:	'		'		'
Purchased power	2,333		1,887		1,381
OTHER INCOME (EXPENSE):	'		'		'
Interest expense	($160)		($191)		($203)
[1]	Includes excise tax collections of $458 million, $484 million and $511 million in 2013, 2012 and 2011, respectively.

Consolidated_Statements_of_Inc3

Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Tax effect of discontinued operations	$9	$8	$8
FES	'	'	'
Tax effect of discontinued operations	$8	$8	$5

Consolidated_Balance_Sheets_Fi2

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'
Cash and cash equivalents	$218	$172
Receivables-	'	'
Customers, net of allowance for uncollectible accounts of $11 in 2013 and $16 in 2012	1,720	1,614
Other, net of allowance for uncollectible accounts of $3 in 2013 and $2 in 2012	198	315
Materials and supplies	752	861
Derivatives	166	160
Prepayments and other	241	208
Total current assets	3,887	3,768
PROPERTY, PLANT AND EQUIPMENT:	'	'
In service	44,228	43,210
Less - Accumulated provision for depreciation	13,280	12,467
Property, plant and equipment in service net of accumulated provision for depreciation	30,948	30,743
Construction work in progress	2,304	2,293
Total net property, plant and equipment	33,252	33,036
INVESTMENTS:	'	'
Nuclear plant decommissioning trusts	2,201	2,204
Other	870	936
Total other property and investments	3,104	3,194
ASSETS HELD FOR SALE (NOTE 16)	235	0
DEFERRED CHARGES AND OTHER ASSETS:	'	'
Customer intangibles	588	'
Goodwill	6,418	6,447
Other	1,674	1,719
Total deferred charges and other assets	9,946	10,496
Total assets	50,424	50,494
CURRENT LIABILITIES:	'	'
Currently payable long-term debt	1,415	1,999
Short-term borrowings-	'	'
Short-term borrowings	3,404	1,969
Accounts payable-	'	'
Accrued taxes	485	543
Derivatives	111	126
Other	621	1,038
Total current liabilities	7,637	7,605
Common stockholders' equity-	'	'
Common stock, without par value, authorized 750 shares- 7 shares outstanding	42	42
Accumulated other comprehensive income	284	385
Retained earnings	2,590	2,888
Total common stockholders' equity	12,692	13,084
Long-term debt and other long-term obligations	15,831	15,179
Total capitalization	28,526	28,272
NONCURRENT LIABILITIES:	'	'
Deferred gain on sale and leaseback transaction	858	892
Accumulated deferred income taxes	6,968	6,616
Asset retirement obligations	1,678	1,599
Retirement benefits	2,689	3,080
Other	1,778	1,924
Total noncurrent liabilities	14,261	14,617
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 16)	'	'
Total liabilities and capitalization	50,424	50,494
FES	'	'
CURRENT ASSETS:	'	'
Cash and cash equivalents	2	3
Receivables-	'	'
Customers, net of allowance for uncollectible accounts of $11 in 2013 and $16 in 2012	539	483
Affiliated companies	1,036	379
Other, net of allowance for uncollectible accounts of $3 in 2013 and $2 in 2012	81	91
Notes receivable from affiliated companies	0	276
Materials and supplies	448	505
Derivatives	165	158
Prepayments and other	138	87
Total current assets	2,409	1,982
PROPERTY, PLANT AND EQUIPMENT:	'	'
In service	12,472	11,997
Less - Accumulated provision for depreciation	4,755	4,408
Property, plant and equipment in service net of accumulated provision for depreciation	7,717	7,589
Construction work in progress	1,308	1,141
Total net property, plant and equipment	9,025	8,730
INVESTMENTS:	'	'
Nuclear plant decommissioning trusts	1,276	1,283
Other	11	12
Total other property and investments	1,287	1,295
ASSETS HELD FOR SALE (NOTE 16)	122	0
DEFERRED CHARGES AND OTHER ASSETS:	'	'
Customer intangibles	95	110
Goodwill	23	24
Property taxes	41	36
Unamortized sale and leaseback costs	168	119
Derivatives	53	99
Other	279	253
Total deferred charges and other assets	659	641
Total assets	13,502	12,648
CURRENT LIABILITIES:	'	'
Currently payable long-term debt	892	1,102
Short-term borrowings-	'	'
Short-term borrowings	4	4
Accounts payable-	'	'
Affiliated companies	765	726
Other	290	159
Accrued taxes	66	171
Derivatives	110	124
Other	197	280
Total current liabilities	2,755	2,566
Common stockholders' equity-	'	'
Common stock, without par value, authorized 750 shares- 7 shares outstanding	3,080	1,573
Accumulated other comprehensive income	54	72
Retained earnings	2,178	2,118
Total common stockholders' equity	5,312	3,763
Long-term debt and other long-term obligations	2,130	3,118
Total capitalization	7,442	6,881
NONCURRENT LIABILITIES:	'	'
Deferred gain on sale and leaseback transaction	858	892
Accumulated deferred income taxes	741	515
Asset retirement obligations	1,015	965
Retirement benefits	185	241
Derivatives	14	37
Other	492	551
Total noncurrent liabilities	3,305	3,201
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 16)	'	'
Total liabilities and capitalization	13,502	12,648
FES | Affiliates	'	'
Short-term borrowings-	'	'
Other Short-term Borrowings	$431	$0

Consolidated_Balance_Sheets_Fi3

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, except Share data, unless otherwise specified
Common stockholders' equity-	'	'
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	418,628,559	418,628,559
Customer [Member]	'	'
Receivables-	'	'
Allowance for uncollectible accounts (in dollars)	52	40
Other Receivables [Member]	'	'
Receivables-	'	'
Allowance for uncollectible accounts (in dollars)	3	4
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)	11	16
FES | Other Receivables [Member]	'	'
Receivables-	'	'
Allowance for uncollectible accounts (in dollars)	3	2

Consolidated_Statements_of_Com3

Consolidated Statements of Common Stockholders' Equity (FirstEnergy Solutions Corp.) (USD $)	Total	Common Stock	Accumulated Other Comprehensive Income (Loss)	Retained Earnings (Accumulated Deficit)	FES	FES	FES	FES
In Millions, except Share data, unless otherwise specified						Common Stock	Accumulated Other Comprehensive Income (Loss)	Retained Earnings (Accumulated Deficit)
Beginning Balance at Dec. 31, 2010	'	$31	$425	$3,084	'	$1,567	$62	$1,990
Beginning Balance, Shares at Dec. 31, 2010	'	304,835,407	'	'	'	7	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'
NET INCOME	869	'	'	'	-59	'	'	-59
Change in unrealized loss on derivative hedges, net of income taxes	'	'	15	'	'	'	7	'
Change in unrealized gain on investments, net of income taxes	'	'	12	'	'	'	10	'
Pensions and OPEB, net of income taxes	'	'	-26	'	'	'	-3	'
Consolidated tax benefit allocation	'	'	'	'	'	3	'	'
Ending Balance at Dec. 31, 2011	'	42	426	3,047	'	1,570	76	1,931
Ending Balance, Shares at Dec. 31, 2011	'	418,216,437	'	'	'	7	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'
NET INCOME	306	'	'	'	122	'	'	'
Ending Balance at Mar. 31, 2012	'	'	'	'	'	'	'	'
Beginning Balance at Dec. 31, 2011	'	42	426	3,047	'	1,570	76	1,931
Beginning Balance, Shares at Dec. 31, 2011	'	418,216,437	'	'	'	7	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'
NET INCOME	771	'	'	'	187	'	'	187
Change in unrealized loss on derivative hedges, net of income taxes	'	'	2	'	'	'	-6	'
Change in unrealized gain on investments, net of income taxes	'	'	-4	'	'	'	-3	'
Pensions and OPEB, net of income taxes	'	'	-39	'	'	'	5	'
Stock-based compensation	'	'	'	'	'	2	'	'
Consolidated tax benefit allocation	'	'	'	'	'	1	'	'
Ending Balance at Dec. 31, 2012	13,084	42	385	2,888	3,763	1,573	72	2,118
Ending Balance, Shares at Dec. 31, 2012	418,628,559	418,216,437	'	'	7	7	'	'
Beginning Balance at Sep. 30, 2012	'	'	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'
NET INCOME	-148	'	'	'	-35	'	'	'
Ending Balance at Dec. 31, 2012	13,084	42	'	2,888	3,763	'	'	'
Ending Balance, Shares at Dec. 31, 2012	418,628,559	418,216,437	'	'	7	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'
NET INCOME	196	'	'	'	2	'	'	'
Ending Balance at Mar. 31, 2013	'	'	'	'	'	'	'	'
Beginning Balance at Dec. 31, 2012	13,084	42	385	2,888	3,763	1,573	72	2,118
Beginning Balance, Shares at Dec. 31, 2012	418,628,559	418,216,437	'	'	7	7	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'
NET INCOME	392	'	'	'	60	'	'	60
Change in unrealized 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	'	'
Ending Balance at Dec. 31, 2013	12,692	42	284	2,590	5,312	3,080	54	2,178
Ending Balance, Shares at Dec. 31, 2013	418,628,559	418,628,559	'	'	7	7	'	'
Beginning Balance at Sep. 30, 2013	'	'	'	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'
NET INCOME	142	'	'	'	89	'	'	'
Ending Balance at Dec. 31, 2013	$12,692	$42	'	$2,590	$5,312	'	'	'
Ending Balance, Shares at Dec. 31, 2013	418,628,559	418,628,559	'	'	7	'	'	'

Consolidated_Statements_of_Com4

Consolidated Statements of Common Stockholders' Equity (FirstEnergy Solutions Corp.) (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unrealized gain (loss) on derivative hedges taxes	$1	($1)	$8
Unrealized gain (loss) on investment taxes	-4	-2	7
Taxes on pension and other postretirement taxes	-63	-76	-64
FES	'	'	'
Unrealized gain (loss) on derivative hedges taxes	-2	-3	5
Unrealized gain (loss) on investment taxes	-3	-2	6
Taxes on pension and other postretirement taxes	($6)	$1	($9)

Consolidated_Statements_of_Cas1

Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'	'
NET INCOME	$392	$771	$869
Adjustments to reconcile net income (loss) to net cash from operating activities-	'	'	'
Provision for depreciation	1,202	1,119	1,062
Nuclear fuel amortization	209	210	201
Deferred rents and lease market valuation liability	-54	-104	-49
Deferred income taxes and investment tax credits, net	243	647	798
Impairments of long-lived assets	795	0	413
Investment impairments	90	27	19
Pensions and OPEB mark-to-market adjustment	-256	609	507
Pension and Other Postretirement Benefit Expense	-168	-127	-151
Pension trust contributions	0	-600	-372
Gain on sale of investment securities held in trusts	-56	-71	-59
Commodity derivative transactions, net (Note 10)	4	-95	-27
Cash collateral, net	-42	16	-79
Loss on debt redemptions	132	0	0
Make-whole premiums paid on debt redemptions	-187	0	0
Income from discontinued operations (Note 20)	-17	-16	-13
Decrease (increase) in operating assets-	'	'	'
Receivables	-114	-13	147
Materials and supplies	96	-50	14
Prepayments and other current assets	-126	-12	101
Increase (decrease) in operating liabilities-	'	'	'
Accounts payable	-25	100	60
Accrued taxes	85	-2	83
Accrued compensation and benefits	19	-55	69
Other	-12	98	-79
Net cash provided from operating activities	2,662	2,320	3,063
New financing-	'	'	'
Long-term debt	3,745	750	604
Short-term borrowings, net	1,435	1,969	0
Redemptions and Repayments-	'	'	'
Long-term debt	-3,600	-940	-1,909
Short-term borrowings, net	0	0	-700
Tender premiums paid on debt redemptions	-110	0	0
Other	-73	-52	-38
Net cash provided from (used for) financing activities	477	807	-2,924
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Property additions	-2,638	-2,678	-2,129
Nuclear fuel	-250	-286	-149
Proceeds from asset sales	4	17	840
Sales of investment securities held in trusts	2,047	2,980	4,207
Purchases of investment securities held in trusts	-2,096	-3,020	-4,309
Other	9	-43	48
Net cash used for investing activities	-3,093	-3,157	-956
Net change in cash and cash equivalents	46	-30	-817
Cash and cash equivalents at beginning of period	172	202	1,019
Cash and cash equivalents at end of period	218	172	202
Cash paid (received) during the year-	'	'	'
Interest (net of amounts capitalized)	969	962	935
Income taxes	36	-6	-358
FES	'	'	'
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'	'
NET INCOME	60	187	-59
Adjustments to reconcile net income (loss) to net cash from operating activities-	'	'	'
Provision for depreciation	306	272	272
Nuclear fuel amortization	209	210	200
Deferred rents and lease market valuation liability	-49	-100	-42
Deferred income taxes and investment tax credits, net	309	214	199
Impairments of long-lived assets	0	0	294
Investment impairments	79	14	17
Pensions and OPEB mark-to-market adjustment	-81	166	171
Pension and Other Postretirement Benefit Expense	-2	-7	-43
Pension trust contributions	0	-209	0
Gain on sale of investment securities held in trusts	-49	-65	-50
Gain on asset sales	-20	-17	0
Commodity derivative transactions, net (Note 10)	5	-74	-68
Cash collateral, net	-34	-33	-88
Loss on debt redemptions	103	0	0
Make-whole premiums paid on debt redemptions	-31	0	0
Income from discontinued operations (Note 20)	-14	-14	-8
Decrease (increase) in operating assets-	'	'	'
Receivables	-393	135	-126
Materials and supplies	57	-13	16
Prepayments and other current assets	-39	-18	22
Increase (decrease) in operating liabilities-	'	'	'
Accounts payable	-145	240	-38
Accrued taxes	-207	-64	154
Accrued compensation and benefits	2	8	2
Other	12	-11	-6
Net cash provided from operating activities	78	821	819
New financing-	'	'	'
Long-term debt	0	650	247
Short-term borrowings, net	431	3	0
Equity contribution from parent	1,500	0	0
Redemptions and Repayments-	'	'	'
Long-term debt	-1,202	-429	-856
Short-term borrowings, net	0	0	-11
Tender premiums paid on debt redemptions	-67	0	0
Other	-9	-12	-11
Net cash provided from (used for) financing activities	653	212	-631
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Property additions	-717	-795	-600
Nuclear fuel	-250	-286	-149
Proceeds from asset sales	21	17	599
Sales of investment securities held in trusts	940	1,464	1,843
Purchases of investment securities held in trusts	-1,000	-1,502	-1,890
Loans to affiliated companies, net	276	107	14
Other	-2	-42	-7
Net cash used for investing activities	-732	-1,037	-190
Net change in cash and cash equivalents	-1	-4	-2
Cash and cash equivalents at beginning of period	3	7	9
Cash and cash equivalents at end of period	2	3	7
Cash paid (received) during the year-	'	'	'
Interest (net of amounts capitalized)	157	174	167
Income taxes	$23	$72	($387)

Organization_Basis_of_Presenta

Organization, Basis of Presentation and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies [Abstract]	'
ORGANIZATION, BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES	'
	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. FirstEnergy’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, FES and its principal subsidiaries (FG and NG), FESC and during 2013, AE and its principal subsidiaries (AE Supply, AGC, MP, PE, WP, FET and its principal subsidiaries (ATSI, TrAIL and PATH), and AESC). In addition, FirstEnergy holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., and GPU Nuclear, Inc. As of January 1, 2014, AE merged with and into FirstEnergy Corp., therefore, AE's direct subsidiaries, AE Supply, MP, PE, WP and FET, became direct subsidiaries of FirstEnergy Corp.
	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 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 unless certain regulatory restrictions and rules apply. 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. These reclassifications include, but are not limited to, the classification of discontinued operations associated with our sale of hydro assets discussed in additional detail in Note 20, Discontinued Operations and Assets Held for Sale. Additionally, amounts collected in rates above actual charges related to asset removal have been reclassified as a regulatory liability which resulted in an increase to total assets and noncurrent liabilities of approximately $88 million.
	ACCOUNTING FOR THE EFFECTS OF REGULATION
	FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities, 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, 2013 and December 31, 2012, and the changes during the year ended December 31, 2013:
	Regulatory Assets by Source		December 31,				December 31,				Increase
			2013				2012				(Decrease)
			(In millions)
	Regulatory transition costs		$	266			$	293			$	(27	)
	Customer receivables for future income taxes		518				505				13
	Nuclear decommissioning and spent fuel disposal costs		(198		)		(219		)		21
	Asset removal costs		(362		)		(372		)		10
	Deferred transmission costs		112				352				(240		)
	Deferred generation costs		346				379				(33		)
	Deferred distribution costs		194				231				(37		)
	Contract valuations		260				463				(203		)
	Storm-related costs		455				469				(14		)
	Other		263				229				34
	Total		$	1,854			$	2,330			$	(476	)
	Regulatory assets that do not earn a current return totaled approximately $477 million as of December 31, 2013 primarily related to storm damage costs.
	As of December 31, 2013 and December 31, 2012, FirstEnergy had approximately $440 million and $480 million, respectively, 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' and AE Supply's 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 of the Ohio and Pennsylvania Companies 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, the Utilities, FES and AE Supply accrue the estimated unbilled amount receivable as revenue and reverse 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 and AE Supply. There was no material concentration of receivables as of December 31, 2013 and 2012 with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2013 and 2012 are shown below.
	Customer Receivables		FirstEnergy				FES
			(In millions)
	December 31, 2013
	Billed		$	1,010			$	301
	Unbilled		710				238
	Total		$	1,720			$	539
	December 31, 2012
	Billed		$	893			$	243
	Unbilled		721				240
	Total		$	1,614			$	483
	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		2013				2012				2011
			(In millions, except per share amounts)
	Income from continuing operations		$	375			$	755			$	856
	Less: Income attributable to noncontrolling interest		—				1				(16		)
	Income from continuing operations available to common shareholders		375				754				872
	Discontinued operations (Note 20)		17				16				13
	Earnings available to FirstEnergy Corp.		$	392			$	770			$	885
	Weighted average number of basic shares outstanding		418				418				399
	Assumed exercise of dilutive stock options and awards(1)		1				1				2
	Weighted average number of diluted shares outstanding		419				419				401
	Earnings per share:
	Basic earnings per share:
	Continuing operations		$	0.9			$	1.81			$	2.19
	Discontinued operations (Note 20)		0.04				0.04				0.03
	Net earnings per basic share		$	0.94			$	1.85			$	2.22
	Diluted earnings per share:
	Continuing operations		$	0.9			$	1.8			$	2.18
	Discontinued operations (Note 20)		0.04				0.04				0.03
	Net earnings per diluted share		$	0.94			$	1.84			$	2.21
	-1	For the year ended December 31, 2013, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect were not significant for the years ending December 31, 2012 or 2011.
	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 Property, plant and equipment and charged to fuel expense using the specific identification method. Net plant in service balances as of December 31, 2013 and 2012 were as follows:
		December 31, 2013											December 31, 2012
Property, Plant and Equipment		In Service				Accum. Depr.				Net Plant			In Service		Accum. Depr.			Net Plant
		(In millions)
Regulated Distribution		$	23,098			$	(6,514	)		$	16,584		$	21,473	$	(6,146	)	$	15,327
Regulated Transmission		5,564				(1,511		)		4,053			5,078		(1,451		)	3,627
Competitive		15,206				(5,088		)		10,118			16,338		(4,739		)	11,599
Other/Corporate		360				(167		)		193			321		(131		)	190
Total		$	44,228			$	(13,280	)		$	30,948		$	43,210	$	(12,467	)	$	30,743
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 2013, 2012 and 2011 are shown in the following table:
		Annual Composite Depreciation Rate
		2013			2012			2011
FirstEnergy		2.6	%		2.5	%		2.4	%
FES		3.1	%		3.1	%		3.1	%
Jointly Owned Plants
FE, through its subsidiary, AGC, owns an undivided 40% interest (1,200 MWs) in a 3,000 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 $672 million, excluding $28 million of CWIP, representing AGC's share in this facility as of December 31, 2013. 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 Statement 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. AROs as of December 31, 2013, are described further in Note 14, Asset Retirement Obligations.
ASSET IMPAIRMENTS
Long-lived Assets
FirstEnergy reviews long-lived assets, including regulatory 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. Impairments of long-lived assets recognized for the year ended December 31, 2013, are described further in Note 11, Impairment of Long-Lived Assets.
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. In evaluating goodwill for impairment, FirstEnergy first assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value, then the two-step goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any.
FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated Transmission, Competitive Energy Services and Other/Corporate. Goodwill is allocated to these reportable segments based on the original purchase price allocation of acquisitions. Total goodwill recognized by segment in FirstEnergy's Consolidated Balance Sheet is as follows:
Goodwill		Regulated Distribution				Regulated Transmission				Competitive Energy Services			Other/Corporate		Consolidated
		(In millions)
Balance as of December 31, 2012		$	5,025			$	526			$	896		$	—	$	6,447
Classification to Assets Held for Sale(1)		—				—				(29		)	—		(29		)
West Virginia asset transfer		67				—				(67		)	—		—
Balance as of December 31, 2013		$	5,092			$	526			$	800		$	—	$	6,418
-1	See Note 20, Discontinued Operations and Assets Held for Sale.
As of December 31, 2013 and 2012, total goodwill recognized by FES was $23 million and $24 million, respectively. Neither FirstEnergy nor FES has accumulated impairment charges as of December 31, 2013.
Annual impairment testing is conducted as of July 31 of each year and for 2013, 2012 and 2011, the analysis indicated no impairment of goodwill. FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission segments as of July 31, 2013. FirstEnergy assessed economic, industry and market considerations in addition to overall financial performance of its Regulated Distribution and Regulated Transmission segments. It was determined that the fair values of these segments were, more likely than not, greater than their carrying values.
Due to excess generation supply in the region, which has caused a period of protracted low power and capacity prices impacting Competitive operations, FirstEnergy performed a quantitative assessment of the Competitive Energy Services segment as of July 31, 2013. The fair value of the Competitive Energy Services segment was calculated using a discounted cash flow analysis which included the effects of the potential sale of certain hydroelectric power stations and the West Virginia asset transfer. Assumptions used in the analysis include discount rates, market performance, projected operating and capital cash flows and the fair value of debt. The estimated fair value of the Competitive Energy Services segment exceeded its carrying amount (including goodwill) as of July 31, 2013. Continued weak economic conditions, lower than forecasted power and capacity prices, and revised environmental requirements could have a negative impact on future goodwill assessments.
In October of 2013, in connection with the closing of the West Virginia asset transfer, as discussed in Note 15, Regulatory Matters, FirstEnergy transferred approximately $67 million of goodwill, net from the Competitive Energy Services segment to the Regulated Distribution segment based on the relative fair value of the generating plants to the fair value of the respective segment.
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. In 2013, 2012 and 2011, FirstEnergy recognized $90 million, $16 million and $19 million, respectively, of OTTI. During the same periods, FES recognized OTTI of $79 million, $14 million and $17 million, respectively. The fair values of FirstEnergy’s investments are disclosed in Note 9, Fair Value Measurements.
NEW ACCOUNTING PRONOUNCEMENTS
New accounting pronouncements not yet effective are not expected to have a material effect on the financial statements of FE or its subsidiaries.

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2013
Statement of Other Comprehensive Income [Abstract]	'
ACCUMULATED OTHER COMPREHENSIVE INCOME	'
	ACCUMULATED OTHER COMPREHENSIVE INCOME
	The changes in AOCI, net of tax, for the years ended December 31, 2013, 2012 and 2011 for FirstEnergy and FES are shown in the following tables:
	FirstEnergy
		Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
		(In millions)
	AOCI Balance, January 1, 2011	$	(54	)	$	7		$	472		$	425
	Other comprehensive income (loss) before reclassifications	(9		)	49			78			118
	Amounts reclassified from AOCI	24			(37		)	(104		)	(117		)
	Net other comprehensive income (loss)	15			12			(26		)	1
	AOCI Balance, December 31, 2011	$	(39	)	$	19		$	446		$	426
	Other comprehensive income before reclassifications	—			41			79			120
	Amounts reclassified from AOCI	1			(45		)	(117		)	(161		)
	Net other comprehensive income (loss)	1			(4		)	(38		)	(41		)
	AOCI Balance, December 31, 2012	$	(38	)	$	15		$	408		$	385
	Other comprehensive income before reclassifications	—			29			23			52
	Amounts reclassified from AOCI	2			(35		)	(120		)	(153		)
	Net other comprehensive income (loss)	2			(6		)	(97		)	(101		)
	AOCI Balance, December 31, 2013	$	(36	)	$	9		$	311		$	284
	FES
		Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
		(In millions)
	AOCI Balance, January 1, 2011	$	1		$	6		$	55		$	62
	Other comprehensive income (loss) before reclassifications	(9		)	42			8			41
	Amounts reclassified from AOCI	16			(32		)	(11		)	(27		)
	Net other comprehensive income (loss)	7			10			(3		)	14
	AOCI Balance, December 31, 2011	$	8		$	16		$	52		$	76
	Other comprehensive income before reclassifications	—			38			16			54
	Amounts reclassified from AOCI	(5		)	(41		)	(12		)	(58		)
	Net other comprehensive income (loss)	(5		)	(3		)	4			(4		)
	AOCI Balance, December 31, 2012	$	3		$	13		$	56		$	72
	Other comprehensive income before reclassifications	—			26			3			29
	Amounts reclassified from AOCI	(4		)	(31		)	(12		)	(47		)
	Net other comprehensive loss	(4		)	(5		)	(9		)	(18		)
	AOCI Balance, December 31, 2013	$	(1	)	$	8		$	47		$	54
	The following amounts were reclassified from AOCI in the years ended December 31, 2013, 2012 and 2011 for FirstEnergy and FES are shown in the following tables:
	FirstEnergy	Year Ended December 31									Affected Line Item in Consolidated Statements of Income
	Reclassifications from AOCI (2)	2013			2012			2011
		(In millions)
	Gains & losses on cash flow hedges
	Commodity contracts	$	(8	)	$	(9	)	$	26		Other operating expenses
	Long-term debt	11			10			12			Interest expense
		3			1			38			Total before taxes
		(1		)	—			(14		)	Income tax benefits
		$	2		$	1		$	24		Net of tax
	Unrealized gains on AFS securities
	Realized gains on sales of securities	$	(56	)	$	(72	)	$	(59	)	Investment income
		21			27			22			Income taxes
		$	(35	)	$	(45	)	$	(37	)	Net of tax
	Defined benefit pension and OPEB plans
	Prior-service costs	$	(195	)	$	(191	)	$	(169	)	(1)
		75			74			65			Income taxes
		$	(120	)	$	(117	)	$	(104	)	Net of tax
	(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
	(2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.
	FES	Year Ended December 31									Affected Line Item in Consolidated Statements of Income
	Reclassifications from AOCI (2)	2013			2012			2011
		(In millions)
	Gains & losses on cash flow hedges
	Commodity contracts	$	(8	)	$	(9	)	$	26		Other operating expenses
	Long-term debt	2			—			1			Interest expense - other
		(6		)	(9		)	27			Total before taxes
		2			4			(11		)	Income taxes (benefits)
		$	(4	)	$	(5	)	$	16		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(49	)	$	(65	)	$	(51	)	Investment income
	18			24			19			Income taxes
	$	(31	)	$	(41	)	$	(32	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(20	)	$	(20	)	$	(18	)	(1)
	8			8			7			Income taxes
	$	(12	)	$	(12	)	$	(11	)	Net of tax
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
(2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

Pension_and_Other_Postemployme

Pension and Other Postemployment Benefits	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS	'
	PENSIONS 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 pensions 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. On July 25, 2013, FirstEnergy announced that non-bargaining employees hired on or after January 1, 2014 will participate in a cash-balance defined benefit pension plan. The plan for existing employees will remain unchanged. Under the cash-balance pension plan, FirstEnergy will make contributions to eligible employee retirement accounts based on employee age and years of service. The balance of these accounts will be provided to employees when they leave the company.
	FirstEnergy’s pensions and OPEB funding policy is based on actuarial computations using the projected unit credit method. During the year ended December 31, 2013, FirstEnergy did not make any contributions to its qualified pension plan. 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.
			Pensions								OPEB
	Obligations and Funded Status		2013				2012				2013			2012
			(In millions)
	Change in benefit obligation:
	Benefit obligation as of January 1		$	8,975			$	7,977			$	1,076		$	1,037
	Service cost		197				161				13			12
	Interest cost		372				389				37			47
	Plan participants’ contributions		—				—				15			17
	Plan amendments		2				8				(37		)	(85		)
	Medicare retiree drug subsidy		—				—				5			—
	Actuarial (gain) loss		(846		)		861				(107		)	152
	Benefits paid		(437		)		(421		)		(123		)	(104		)
	Benefit obligation as of December 31		$	8,263			$	8,975			$	879		$	1,076
	Change in fair value of plan assets:
	Fair value of plan assets as of January 1		$	6,671			$	5,867			$	508		$	528
	Actual return on plan assets		(77		)		611				56			48
	Company contributions		14				614				39			19
	Plan participants’ contributions		—				—				15			17
	Benefits paid		(437		)		(421		)		(123		)	(104		)
	Fair value of plan assets as of December 31		$	6,171			$	6,671			$	495		$	508
	Funded Status:
	Qualified plan		$	(1,782	)		$	(1,967	)
	Non-qualified plans		(310		)		(336		)
	Funded Status		$	(2,092	)		$	(2,303	)		$	(384	)	$	(566	)
	Accumulated benefit obligation		$	7,800			$	8,355			$	—		$	—
	Amounts Recognized on the Balance Sheet:
	Current liabilities		$	(15	)		$	(14	)		$	—		$	—
	Noncurrent liabilities		(2,077		)		(2,289		)		(384		)	(566		)
	Net liability as of December 31		$	(2,092	)		$	(2,303	)		$	(384	)	$	(566	)
	Amounts Recognized in AOCI:
	Prior service cost (credit)		$	48			$	58			$	(558	)	$	(728	)
	Assumptions Used to Determine Benefit Obligations
	(as of December 31)
	Discount rate		5		%		4.25		%		4.75		%	4		%
	Rate of compensation increase		4.2		%		4.7		%		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				7.25-7.75%			7.5-8.0%
	Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)		N/A				N/A				5		%	5		%
	Year that the rate reaches the ultimate trend rate (pre/post-Medicare)		N/A				N/A				2020			2020
	Allocation of Plan Assets (as of December 31)
	Equity securities		18		%		15		%		47		%	39		%
	Bonds		40		%		47		%		40		%	40		%
	Absolute return strategies		23		%		22		%		3		%	4		%
	Real estate		6		%		5		%		1		%	1		%
	Private equities		—		%		1		%		—		%	—		%
	Cash and short-term securities		13		%		10		%		9		%	16		%
	Total		100		%		100		%		100		%	100		%
	The estimated 2014 amortization of pensions and OPEB prior service costs (credits) from AOCI into net periodic pensions and OPEB costs (credits) is approximately $8 million and $(176) million, respectively.
			Pensions											OPEB
	Components of Net Periodic Benefit Costs		2013				2012				2011			2013				2012			2011
			(In millions)
	Service cost		$	197			$	161			$	130		$	13			$	12		$	13
	Interest cost		372				389				374			37				47			48
	Expected return on plan assets		(501		)		(486		)		(446		)	(34		)		(37		)	(40		)
	Amortization of prior service cost (credit)		12				12				14			(207		)		(203		)	(203		)
	Other adjustments (settlements, curtailments, etc.)		—				—				6			—				—			—
	Pensions & OPEB mark-to-market adjustment		(267		)		735				729			(129		)		140			36
	Net periodic cost		$	(187	)		$	811			$	807		$	(320	)		$	(41	)	$	(146	)
	Assumptions Used to Determine Net Periodic Benefit Cost		Pensions									OPEB
for Years Ended December 31(1)		2013			2012			2011			2013		2012			2011
Weighted-average discount rate		4.25	%		5	%		5.5	%		4	%	4.75	%		5	%
Expected long-term return on plan assets		7.75	%		7.75	%		8.25	%		7.75	%	7.75	%		8.5	%
Rate of compensation increase		4.7	%		5.2	%		5.2	%		N/A		N/A			N/A
(1) Excludes Pensions & OPEB mark-to-market adjustment.
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 pensions and OPEB obligations. The assumed rates of return on plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy.
The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 9, Fair Value Measurements, for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2013 and 2012.
		December 31, 2013															Asset Allocation
		Level 1				Level 2				Level 3			Total
		(In millions)
Cash and short-term securities		$	—			$	782			$	—		$	782			13	%
Equity investments
Domestic		701				3				—			704				11	%
International		304				118				—			422				7	%
Fixed income
Government bonds		—				314				—			314				5	%
Corporate bonds		—				2,128				—			2,128				34	%
Mortgaged-backed securities (non-government)		—				87				—			87				1	%
Alternatives
Hedge funds		—				1,395				—			1,395				23	%
Derivatives		—				14				—			14				—	%
Private equity funds		—				—				27			27				—	%
Real estate funds		—				—				385			385				6	%
Total (1)		$	1,005			$	4,841			$	412		$	6,258			100	%
		December 31, 2012															Asset Allocation
		Level 1				Level 2				Level 3			Total
		(In millions)
Cash and short-term securities		$	—			$	652			$	—		$	652			10	%
Equity investments
Domestic		547				8				—			555				8	%
International		275				153				—			428				7	%
Fixed income
Government bonds		4				564				—			568				8	%
Corporate bonds		—				1,899				—			1,899				28	%
High yield debt		—				369				—			369				6	%
Mortgaged-backed securities (non-government)		—				330				—			330				5	%
Alternatives
Hedge funds		—				1,498				—			1,498				22	%
Derivatives		—				18				—			18				—	%
Private equity funds		—				—				33			33				1	%
Real estate funds		—				—				357			357				5	%
Total (1)		$	826			$	5,491			$	390		$	6,707			100	%
-1	Excludes ($87) million and ($36) million as of December 31, 2013 and December 31, 2012, respectively, 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 2013 and 2012:
		Private Equity Funds				Real Estate Funds				Derivatives
		(In millions)
Balance as of January 1, 2012		$	135			$	327			$	70
Actual return on plan assets:
Unrealized gains		(14		)		29				—
Realized gains		(10		)		4				—
Purchases, sales and settlements		—				—				(70		)
Transfers in (out)		(78		)		(3		)		—
Balance as of December 31, 2012		$	33			$	357			$	—
Actual return on plan assets:
Unrealized gains		1				17				—
Realized gains		5				13				—
Purchases, sales and settlements		—				—				—
Transfers out		(12		)		(2		)		—
Balance as of December 31, 2013		$	27			$	385			$	—
As of December 31, 2013 and 2012, the OPEB trust investments measured at fair value were as follows:
		December 31, 2013															Asset Allocation
		Level 1				Level 2				Level 3			Total
		(In millions)
Cash and short-term securities		$	—			$	47			$	—		$	47			9	%
Equity investment
Domestic		227				—				—			227				45	%
International		4				2				—			6				1	%
Mutual funds		5				—				—			5				1	%
Fixed income
U.S. treasuries		—				44				—			44				9	%
Government bonds		—				91				—			91				18	%
Corporate bonds		—				59				—			59				12	%
High yield debt		—				—				—			—				—	%
Mortgage-backed securities (non-government)		—				3				—			3				1	%
Alternatives
Hedge funds		—				17				—			17				3	%
Private equity funds		—				—				—			—				—	%
Real estate funds		—				—				5			5				1	%
Total (1)		$	236			$	263			$	5		$	504			100	%
		December 31, 2012															Asset Allocation
		Level 1				Level 2				Level 3			Total
		(In millions)
Cash and short-term securities		$	—			$	83			$	—		$	83			16	%
Equity investment
Domestic		183				—				—			183				36	%
International		4				2				—			6				1	%
Mutual funds		8				3				—			11				2	%
Fixed income
U.S. treasuries		—				48				—			48				9	%
Government bonds		—				88				—			88				17	%
Corporate bonds		—				59				—			59				11	%
High yield debt		—				5				—			5				1	%
Mortgage-backed securities (non-government)		—				9				—			9				2	%
Alternatives
Hedge funds		—				21				—			21				4	%
Private equity funds		—				—				—			—				—	%
Real estate funds		—				—				5			5				1	%
Total (1)		$	195			$	318			$	5		$	518			100	%
-1	Excludes ($9) million and ($10) million as of December 31, 2013 and December 31, 2012, respectively, 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 2013 and 2012:
		Private Equity Funds				Real Estate Funds
		(in millions)
Balance as of January 1, 2012		$	3			$	7
Actual return on plan assets:
Unrealized losses		(1		)		—
Realized gains (losses)		—				—
Purchases, sales and settlements		—				—
Transfers out		(2		)		(2		)
Balance as of December 31, 2012		$	—			$	5
Balance as of December 31, 2013		$	—			$	5
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 pensions and OPEB trust portfolios for 2013 and 2012 are shown in the following table:
		Target Asset Allocations
		2013			2012
Equities		26	%		20	%
Fixed income		40	%		51	%
Absolute return strategies		22	%		21	%
Real estate		5	%		5	%
Private equity		1	%		—	%
Cash		6	%		3	%
		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
		Pensions				Benefit Payments				Subsidy Receipts
		(in millions)
2014		$	449			$	129			$	(4	)
2015		466				67				(4		)
2016		484				67				(4		)
2017		500				67				(4		)
2018		524				65				(4		)
Years 2019-2023		2,867				382				(17		)
FES’ share of the net pensions and OPEB liability as of December 31, 2013 and 2012, was as follows:
		Pensions								OPEB
		2013				2012				2013			2012
		(In millions)
Net Liability		$	(149	)		$	(180	)		$	(8	)	$	(36	)
FES’ share of the net periodic pensions and OPEB costs for the three years ended December 31, 2013 was as follows:
		Pensions											OPEB
		2013				2012				2011			2013				2012			2011
		(In millions)
Net Periodic Costs		$	(30	)		$	78			$	80		$	(40	)		$	(11	)	$	(21	)

StockBased_Compensation_Plans

Stock-Based Compensation Plans	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Stock-Based Compensation Plans	'
	STOCK-BASED COMPENSATION PLANS
	FirstEnergy has four stock-based compensation plans - ICP, 401(k) Savings Plan, EDCP and DCPD, as described further below.
	ICP
	The ICP includes four forms of stock-based compensation — restricted stock, restricted stock units, stock options and performance shares.
	Under the ICP, total issuances cannot exceed 29 million shares of common stock or their equivalent. Stock options, restricted stock and restricted stock units have currently been designated to pay out in common stock, with vesting periods ranging from eight months to ten years. Performance share awards are currently designated to be paid in cash unless the recipient elects to defer the award, in which case, the award may be paid in stock depending upon the duration of the deferral. Shares available under the ICP are also used for bonuses earned under FirstEnergy’s Short-Term Incentive Program that are, at the election of the participant, deferred through the EDCP and paid in shares under the ICP. As of December 31, 2013, approximately 3.0 million shares were available for future issuance plus any shares that become available again under the ICP due to cancellations, forfeitures, cash settlements or other similar circumstances with respect to outstanding awards.
	FirstEnergy records the compensation costs for stock-based compensation awards over the vesting period based on the fair value on the grant date, less estimated forfeitures. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or distributed. Realized tax benefits during the years ended December 31, 2013, 2012 and 2011 were $13 million, $22 million and $14 million, respectively. The excess of the deductible amount over the recognized compensation cost is recorded as a component of stockholders’ equity and reported as an other financing activity on the Consolidated Statements of Cash Flows.
	Restricted Stock and Restricted Stock Units
	Restricted common stock (restricted stock) and restricted stock units (stock units) activity for the year ended December 31, 2013, was as follows:
	Outstanding as of January 1, 2013	2,180,422
	Granted	952,137
	Vested	(815,851	)
	Forfeited	(100,099	)
	Outstanding as of December 31, 2013	2,216,609
	The 952,137 shares of restricted stock and stock units granted during the year ended December 31, 2013, includes 212,211 stock units related to previous grants due to over-achievement of performance metrics, and had a grant-date fair value of $39.97 and a weighted-average vesting period of 3.02 years.
	Eligible employees receive awards of FE restricted stock or stock units subject to restrictions that lapse over a defined period of time or upon achieving performance results. Dividends are received on the restricted stock and are reinvested in additional shares. Restricted stock grants under the ICP were as follows:
			2013				2012				2011
	Restricted stock granted		27,561				263,771				297,859
	Weighted average market price		$	42.53			$	44.82			$	38.44
	Weighted average vesting period (years)		3.68				3.09				2.27
	Dividends restricted		Yes				Yes				Yes
	Vesting activity for restricted stock during 2013 was as follows (forfeitures were not material):
	Restricted Stock		Number of Shares			Weighted Average Grant-Date Fair Value
	Nonvested as of January 1, 2013		551,678			$	46.73
	Nonvested as of December 31, 2013		417,464			$	45.46
	Granted in 2013		27,561			$	42.53
	Vested in 2013(1)		167,751			$	37.1
	(1) Includes 23,446 shares for dividends earned during vesting period
	FirstEnergy grants two types of stock unit awards: discretionary-based and performance-based. The discretionary-based awards grant 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 each agreement. Performance-based awards grant 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.
			2013			2012			2011
	Restricted stock units granted		924,576			652,120			617,195
	Weighted average vesting period (years)		3			3			3
	Vesting activity for stock units during 2013 was as follows:
	Restricted Stock Units		Number of Shares			Weighted Average Grant-Date Fair Value
	Nonvested as of January 1, 2013		1,628,744			$	41.1
	Nonvested as of December 31, 2013		1,799,145			$	40.86
	Granted in 2013		924,576			$	39.9
	Forfeited in 2013		82,629			$	41.38
	Vested in 2013 (1)		792,113			$	40.74
	(1) Includes dividend equivalents of 120,567 earned during vesting period
	As of December 31, 2013, there was $35 million of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted for restricted stock and restricted stock units; that cost is expected to be recognized over a period of approximately 2 years.
	Stock Options
	Stock options were granted to eligible employees allowing them to purchase a specified number of common shares at a fixed grant price over a defined period of time. Stock option activity during 2013 was as follows:
	Stock Option Activity		Number of Shares			Weighted Average Exercise Price
	Balance, January 1, 2013 (2,348,469 options exercisable)		2,910,269			$	40.33
	Options exercised		(546,408	)		30.37
	Options forfeited		(4,735	)		71.21
	Balance, December 31, 2013 (1,997,969 options exercisable)		2,359,126			$	42.59
	Options outstanding and range of exercise prices as of December 31, 2013, were as follows:
			Options Outstanding
	Range of Exercise Prices		Shares			Weighted Average Exercise Price				Remaining Contractual Life
										(in years)
	$20.02-$35.44		66,125			$	22.83			0.47
	$35.45-$38.75		1,143,389			$	36.78			6.28
	$38.76-$53.04		835,039			$	38.81			0.19
	$53.05-$81.19		314,573			$	77.85			3.56
	Total		2,359,126			$	42.59			3.6
	Cash received from the exercise of stock options in 2013, 2012 and 2011 was $19 million, $50 million and $32 million, respectively. The total intrinsic value of options exercised during 2013 was $6 million.
	Performance Shares
	Performance shares are share equivalents and do not have voting rights. The shares track the performance of FE's common stock over a three-year vesting period. During that time, dividend equivalents accrue and at vesting are converted into additional performance shares. The final account value may be adjusted based on the ranking of FE stock performance to a composite of peer companies. During 2013, 2012 and 2011, no cash was paid to settle performance shares due to the criteria not being met for the previous three-year vesting period.
	401(k) Savings Plan
	In 2013, 2012 and 2011, shares of FE common stock were purchased on the market and contributed to participants’ accounts.
	EDCP
	Under the EDCP, covered employees can direct a portion of their compensation, including annual incentive awards and/or long-term incentive awards, into unfunded FE stock accounts to receive vested stock units or into an unfunded retirement cash account. Dividends are calculated quarterly on stock units outstanding and are credited in the form of additional stock units. Upon withdrawal, stock units are converted to FE shares. Payout of the stock accounts typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement. Interest is calculated on the cash allocated to the cash account and the total balance will pay out in cash upon retirement.
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 $7 million and $6 million as of December 31, 2013 and December 31, 2012, respectively, is included in the caption “Retirement benefits” on the Consolidated Balance Sheets.
Of the approximately 1.7 million shares authorized under the EDCP and DCPD, approximately 845,000 shares were available for future issuance as of December 31, 2013. The shareholder approved pools for the EDCP and DCPD terminate in May 2014.
Stock-based Compensation Expense
Pre-tax stock-based compensation costs, tax benefit associated with stock-based compensation expense, 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		2013				2012				2011
		(In millions)
Restricted Stock and Restricted Stock Units		$	42			$	42			$	29
Stock Options		—				1				1
Performance Shares		(10		)		5				3
401(k) Savings Plan		25				37				31
EDCP		(2		)		—				6
DCPD		5				4				4
Total		$	60			$	89			$	74
Stock-based compensation costs capitalized		$	20			$	29			$	21
FES		Years ended December 31,
Stock-based Compensation Plan		2013				2012				2011
		(In millions)
Restricted Stock and Restricted Stock Units		$	6			$	6			$	4
Performance Shares		(1		)		1				1
401(k) Savings Plan		4				6				5
EDCP		—				—				1
Total		$	9			$	13			$	11
Stock-based compensation costs capitalized		$	1			$	1			$	—
Tax benefits associated with stock based compensation plan expense was $23 million, $11 million and $10 million (FES - $1 million, $2 million and $2 million) for the years ended 2013, 2012 and 2011, respectively.

Taxes

Taxes	12 Months Ended
	Dec. 31, 2013
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.
	PROVISION FOR INCOME TAXES		FirstEnergy				FES
			(In millions)
	2013
	Currently payable (receivable)-
	Federal		$	(118	)		$	(300	)
	State		70				(3		)
			(48		)		(303		)
	Deferred, net-
	Federal		305				317
	State		(54		)		(4		)
			251				313
	Investment tax credit amortization		(8		)		(4		)
	Total provision for income taxes		$	195			$	6
	2012
	Currently payable (receivable)-
	Federal		$	(130	)		$	(128	)
	State		28				17
			(102		)		(111		)
	Deferred, net-
	Federal		580				209
	State		78				9
			658				218
	Investment tax credit amortization		(11		)		(4		)
	Total provision for income taxes		$	545			$	103
	2011
	Currently payable (receivable)-
	Federal		$	(251	)		$	(224	)
	State		19				9
			(232		)		(215		)
	Deferred, net-
	Federal		785				205
	State		24				(2		)
			809				203
	Investment tax credit amortization		(11		)		(4		)
	Total provision for income taxes		$	566			$	(16	)
	As discussed in Note 11, on July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating two coal-fired generating plants. As a result of the decision, FirstEnergy determined that it is more likely than not that certain state and local NOL carryforwards will not be realized through future operations or through the reversal of existing temporary differences. As a result, FirstEnergy recorded a valuation reserve of approximately $20 million against carryforwards in 2013.
	On July 9, 2013, Pennsylvania House Bill 465 (HB 465) was enacted, adopting new market-based sourcing rules for certain items of income as well as increasing the Pennsylvania NOL deduction credit for tax years beginning after December 31, 2013 and 2014 to the greater of 25% or $4 million of taxable income and 30% or $5 million of taxable income, respectively. Based on income projections, Pennsylvania NOL valuation reserves were reduced by approximately $8 million in 2013.
	During 2013, FirstEnergy made changes to state apportionment factors in certain jurisdictions based on sales sourcing rules for electricity, which reduced deferred tax liabilities by approximately $9 million. Furthermore, based on an assessment of business operations, FirstEnergy determined that income from certain subsidiaries should not be apportioned to certain tax jurisdictions due to the absence of business nexus. This assessment resulted in a reduction to deferred tax liabilities of approximately $22 million.
	In 2012, a $50 million valuation allowance was established for two unregulated subsidiaries of FirstEnergy based on current judgment as to the realization of certain state deferred tax assets, as impacted by changes in the business and the applicability of certain state law limitations on the long-term utilization of NOL carryforwards. The results of operations in 2012 for those companies decreased accumulated deferred income tax liabilities by approximately $50 million.
	In December 2012, two subsidiaries of FES, FG and NG, completed a conversion from corporations to limited liability companies (LLCs). For income tax purposes, these LLCs are treated as divisions (i.e., disregarded entities) of their parent company, FES. The LLC conversions, in combination with anticipated future taxable income, will contribute to the realization of certain state deferred tax assets. In 2011, an unregulated subsidiary of FirstEnergy converted to an LLC which, based on anticipated future taxable income, resulted in the partial reversal of a valuation allowance, reducing income tax expense in 2011 by $27 million.
	During 2012, certain FirstEnergy operating companies adopted a new federal tax accounting method (effective for the 2011 consolidated federal tax return) for the deductibility of expenses for repairs to transmission and distribution assets, pursuant to IRS safe harbor guidance. In accordance with the IRS guidance, a cumulative adjustment was made on the 2011 consolidated federal tax return, increasing tax deductions and decreasing taxable income by approximately $417 million. The increased federal tax deductions created a corresponding state tax benefit that reduced FirstEnergy's effective tax rate by approximately $12 million in 2012. The IRS has agreed that the new method of accounting is compliant with the IRS guidance.
	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.
	The following tables provide a reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes for the three years ended December 31, 2013:
		FirstEnergy				FES
		(In millions)
	2013
	Book income before provision for income taxes	$	570			$	52
	Federal income tax expense at statutory rate	$	199			$	18
	Increases (reductions) in taxes resulting from-
	Amortization of investment tax credits	(8		)		(4		)
	State income taxes, net of federal tax benefit	10				(5		)
	FirstEnergy effectively settled tax items	(2		)		—
	ESOP Dividend	(9		)		(2		)
	Nondeductible compensation	3				—
	Other permanent items	1				—
	AFUDC equity and other flow-through	(7		)		—
	Other, net	8				(1		)
	Total provision for income taxes	$	195			$	6
	2012
	Book income before provision for income taxes	$	1,299			$	276
	Federal income tax expense at statutory rate	$	455			$	97
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits	(11		)		(4		)
State income taxes, net of federal tax benefit	69				17
Medicare Part D	32				1
Effectively settled tax items	(20		)		(11		)
State valuation allowance	60				—
State apportionment remeasurement	(50		)		—
Other, net	10				3
Total provision for income taxes	$	545			$	103
2011
Book income before provision for income taxes	$	1,438			$	(83	)
Federal income tax expense (benefit) at statutory rate	$	503			$	(29	)
Increases (reductions) in taxes resulting from-
Amortization of investment tax credits	(11		)		(4		)
State income taxes, net of federal tax benefit	28				5
State unitary tax adjustments	33				—
Manufacturing deduction	16				13
Medicare Part D	36				4
Effectively settled tax items	(11		)		(2		)
State valuation allowance	(19		)		2
Other, net	(9		)		(5		)
Total provision for income taxes (benefits)	$	566			$	(16	)
Accumulated deferred income taxes as of December 31, 2013 and 2012 are as follows:
		FirstEnergy				FES
		(In millions)
December 31, 2013
Property basis differences		$	8,078			$	1,428
Regulatory transition charge		(26		)		—
Customer receivables for future income taxes		(2		)		—
Deferred MISO/PJM transmission costs		27				—
Other regulatory assets — RCP		69				—
Deferred sale and leaseback gain		(411		)		(370		)
Non-utility generation costs		(1		)		—
Unamortized investment tax credits		(62		)		(16		)
Unrealized losses on derivative hedges		(20		)		(1		)
Pensions and OPEB		(938		)		(77		)
Lease market valuation liability		(59		)		55
Oyster Creek securitization (Note 12)		57				—
Nuclear decommissioning activities		44				31
Mark-to-market adjustments		31				30
Deferred gain for asset sales — affiliated companies		781				—
Loss carryforwards and AMT credits		(1,599		)		(369		)
Loss carryforward valuation reserve		142				18
Storm damage		179				—
Market transition charge		81				—
All other		231				(13		)
Net deferred income tax liability		$	6,602			$	716
December 31, 2012
Property basis differences		$	7,868			$	1,060
Regulatory transition charge		79				—
Customer receivables for future income taxes		130				—
Deferred MISO/PJM transmission costs		125				—
Other regulatory assets — RCP		161				—
Deferred sale and leaseback gain		(431		)		(384		)
Non-utility generation costs		5				—
Unamortized investment tax credits		(67		)		(17		)
Unrealized losses on derivative hedges		(21		)		2
Pensions and OPEB		(1,102		)		(105		)
Lease market valuation liability		(81		)		33
Oyster Creek securitization (Note 12)		75				—
Nuclear decommissioning activities		127				111
Mark-to-market adjustments		30				30
Loss carryforwards and ATM credits		(1,199		)		(221		)
Loss carryforward valuation reserve		102				16
Storm damage		192				—
Market transition charge		65				—
All other		239				(22		)
Net deferred income tax liability		$	6,297			$	503
FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Accounting guidance prescribes a recognition threshold and measurement attribute 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, 2013 and 2012, FirstEnergy's total unrecognized income tax benefits were approximately $48 million and $43 million, respectively. All $48 million of unrecognized income tax benefits as of December 31, 2013, would impact the effective tax rate if ultimately recognized in future years. As of December 31, 2013, it is reasonably possible that approximately $35 million of unrecognized tax benefits may be resolved during 2014 as a result of the statute of limitations expiring, all of which would affect FirstEnergy's effective tax rate.
During 2013, the AE companies reduced reserves for unrecognized tax benefits related to various tax positions, with a total reduction to the effective tax rate of approximately $5 million.
During 2013, FirstEnergy settled a claim with the IRS for approximately $1.0 billion of additional accelerated (bonus) depreciation deductions for certain generation property for the 2010 taxable year, which resulted in a carryback refund of approximately $110 million, an increase in the NOL carryfoward of approximately $65 million, with a corresponding increase to accumulated deferred income taxes for this temporary tax item and an overall decrease to FirstEnergy's effective tax rate of approximately $2 million for adjustments to interest resulting from the settlement.
During 2012, FirstEnergy reached a settlement with state authorities related to state apportionment factors in Pennsylvania on an intercompany asset sale, which reduced FirstEnergy's effective tax rate by $3 million. During 2012, based on further IRS guidance related to the tax accounting for costs to repair and maintain fixed assets, the AE companies reduced their amount of unrecognized tax benefits by $21 million, with a corresponding adjustment to accumulated deferred income taxes for this temporary tax item, with no resulting impact to the effective tax rate.
During the fourth quarter of 2012, FirstEnergy reached a settlement with the IRS on deductions for prior year costs to repair generation assets, permitting the reduction of unrecognized tax benefits by approximately $34 million, with a corresponding adjustment to accumulated deferred income taxes for this temporary tax item, and an overall decrease to FirstEnergy's effective tax rate of approximately $10 million for adjustments to potential interest expense resulting from the settlement. Also during the fourth quarter of 2012, the AE companies reduced reserves for unrecognized tax benefits related to various tax positions, including the IRS's agreement on AE's deduction of merger-related expenses, with a total reduction to the effective tax rate of approximately $7 million.
The following table summarizes the changes in unrecognized tax positions for the years ended 2013, 2012 and 2011:
		FirstEnergy				FES
		(In millions)
Balance, January 1, 2011		$	45			$	41
Increase due to merger with AE		97				—
Prior years increases		10				8
Prior years decreases		(35		)		(4		)
Balance, December 31, 2011		$	117			$	45
Current year increases		2				—
Current year decreases		(7		)		—
Prior years increases		6				6
Prior years decreases		(37		)		(13		)
Decrease for settlements		(38		)		(35		)
Balance, December 31, 2012		$	43			$	3
Prior years increases		10				—
Prior years decreases		(5		)		—
Balance, December 31, 2013		$	48			$	3
FirstEnergy recognizes interest expense or income related to uncertain tax positions. 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 includes net interest and penalties in the provision for income taxes. FirstEnergy's reversal of accrued interest associated with unrecognized tax benefits was immaterial to FirstEnergy's effective tax rate in 2013 and reduced the 2012 effective tax rate by approximately $4 million. The interest associated with the 2011 settlement of a claim favorably affected FirstEnergy's effective tax rate by $7 million in 2011.
The following table summarizes the net interest expense (income) for the three years ended December 31, 2013 and the cumulative net interest payable as of December 31, 2013 and 2012:
		Net Interest Expense (Income)										Net Interest Payable
		For the Years Ended December 31,										As of December 31,
		2013				2012			2011			2013		2012
		(In millions)										(In millions)
FirstEnergy		$	1			$	(4	)	$	(5	)	$	9	$	8
FES		—				(4		)	1			1		1
FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS (2011-2013) and state tax authorities. FirstEnergy's tax returns for all state jurisdictions are open from 2009-2012. The IRS completed its audit of the 2011 tax year in December 2013 and is in the process of preparing the final audit report. Tax years 2012-2013 are under review by the IRS. In August 2013 the IRS completed its audit of AE for tax years 2009 and 2010 and the final federal tax return for the period January-February 2011. For the remainder of the 2011 taxable year and future years, the AE companies are part of the FirstEnergy federal consolidated group. State tax returns for tax years 2010 through 2012 remain subject to review in Pennsylvania, West Virginia, Maryland and Virginia for certain subsidiaries of AE.
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, 2013, the deferred income tax assets, before any valuation allowances, consisted of $1.1 billion of federal NOL carryforwards that expire from 2025 to 2033, federal AMT credits of $25 million that have an indefinite carryforward period, and $418 million of state and local NOL carryforwards that begin to expire in 2014.
The table below summarizes pre-tax NOL carryforwards for state and local income tax purposes of approximately $9.8 billion for FirstEnergy, of which approximately $6.3 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
2014-2018		$	14			$	2,289		$	8		$	1,243
2019-2023		2,513				—			23			—
2024-2028		2,051				—			60			—
2029-2033		2,891				—			752			—
		$	7,469			$	2,289		$	843		$	1,243
General Taxes
		FirstEnergy				FES
		(In millions)
2013
KWH excise		$	219			$	—
State gross receipts		240				77
Real and personal property		368				40
Social security and unemployment		110				19
Other		41				2
Total general taxes		$	978			$	138
2012
KWH excise		$	230			$	—
State gross receipts		251				77
Real and personal property		328				35
Social security and unemployment		126				20
Other		49				4
Total general taxes		$	984			$	136
2011
KWH excise		$	244			$	—
State gross receipts		264				62
Real and personal property		298				42
Social security and unemployment		109				14
Other		62				6
Total general taxes		$	977			$	124

Leases

Leases	12 Months Ended
	Dec. 31, 2013
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. 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. During the terms of their respective leases, OE, CEI and TE are responsible, to the extent of their leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. They 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. FES has unconditionally and irrevocably guaranteed all of FG’s obligations under each of the leases.
	During 2008, NG purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant and approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. In addition, NG purchased 158.5 MW of lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2. The Ohio Companies continue to lease these MW under their respective sale and leaseback arrangements and the related lease debt remains outstanding.
	During 2012, NG repurchased 70.1 MW of lessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for $129 million and FG acquired 441.9 MW of certain equity and other lessor interests in connection with the 1987 Bruce Mansfield Plant sale and leaseback transactions for approximately $262 million. In March of 2013, FG acquired the remaining lessor interests in the Bruce Mansfield sale and leaseback transaction for approximately $221 million. During 2013, NG purchased 12.2 MW of lessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for $23 million. Additionally, 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.
	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, 2013, FirstEnergy's leasehold interest was 8.11% of Perry Unit 1 and 93.83% of Bruce Mansfield Unit 1. After NG's purchase in February 2014, as discussed above, FirstEnergy's leasehold interest was 2.60% of Beaver Valley Unit 2.
	Operating lease expense for 2013, 2012 and 2011, is summarized as follows:
	(In millions)	2013			2012			2011
	FirstEnergy	$	224		$	291		$	319
	FES	97			140			154
	The future minimum capital lease payments as of December 31, 2013 are as follows:
	Capital leases	FirstEnergy			FES
		(In millions)
	2014	$	40		$	6
	2015	38			6
	2016	34			5
	2017	30			5
	2018	23			2
	Years thereafter	57			—
	Total minimum lease payments	222			24
	Interest portion	(34		)	(2		)
	Present value of net minimum lease payments	188			22
	Less current portion	34			5
	Noncurrent portion	$	154		$	17
	FirstEnergy's future minimum consolidated operating lease payments as of December 31, 2013, are as follows:
		FirstEnergy
	Operating Leases	Lease Payments			Capital Trust			Net
		(In millions)
	2014	$	250		$	48		$	202
	2015	245			40			205
	2016	213			13			200
	2017	128			3			125
	2018	126			—			126
	Years thereafter	1,564			—			1,564
	Total minimum lease payments	$	2,526		$	104		$	2,422
	FES' future minimum operating lease payments as of December 31, 2013, are as follows:
	Operating Leases	Lease Payments
		(In millions)
	2014	$	143
	2015	142
	2016	130
	2017	82
	2018	101
	Years thereafter	1,480
	Total minimum lease payments	$	2,078

Intangible_Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
INTANGIBLE ASSETS	'
	INTANGIBLE ASSETS
	As of December 31, 2013, 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		2013		2014		2015		2016		2017		2018		Thereafter
	NUG contracts(1)(2)		$	124	$	15	$	109	$	5	$	5	$	5	$	5	$	5	$	5	$	84
	OVEC(1)		54		5		49		2		2		2		2		2		2		39
	Coal contracts(1)(3)		556		222		334		62		55		51		51		45		30		49
	FES customer contracts		147		52		95		17		17		17		17		17		14		13
	Energy contracts(1)		136		135		1		14		1		—		—		—		—		—
			$	1,017	$	429	$	588	$	100	$	80	$	75	$	75	$	69	$	51	$	185
	-1	Fair value measurements of intangible assets recorded in connection with the Allegheny merger (see Note 21, Merger).
	-2	NUG contracts are subject to regulatory accounting and their amortization does not impact earnings.
	-3	A gross amount of $102 million ($53 million, net) of the coal contracts was recorded with a regulatory offset and the amortization does not impact 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, 2013
Variable Interest Entities [Abstract]	'
VARIABLE INTEREST ENTITIES	'
	VARIABLE INTEREST ENTITIES
	FirstEnergy performs qualitative analyses to determine whether a variable interest gives FirstEnergy a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 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.
	VIEs included in FirstEnergy’s consolidated financial statements are: FEV's joint venture in the Signal Peak mining and coal transportation operations, a portion of which was sold on October 18, 2011, and resulted in deconsolidation; the PNBV and Shippingport capital trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; wholly-owned limited liability companies of the Ohio Companies (as described below); wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs and special purpose limited liability companies created to issue environmental control bonds that were used to construct environmental control facilities (see Note 12, Capitalization for additional details).
	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. The change in noncontrolling interest within the Consolidated Balance Sheets during the year ended December 31, 2013, was primarily due to $7 million of distributions to owners. As of December 31, 2013, the caption noncontrolling interest on the consolidated Balance Sheets was primarily related to PNBV.
	In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into the following categories based on similar risk characteristics and significance.
	Ohio Securitization
	In September 2012, the Ohio Companies formed CEI Funding LLC, OE Funding LLC and TE Funding LLC, respectively, as separate, wholly-owned limited liability SPEs. Each SPE is a bankruptcy-remote, special purpose limited liability company that is restricted to activities necessary to issue phase-in recovery bonds and perform other functions in connection with the bond issuance. Creditors of FirstEnergy and the Ohio Companies have no recourse to any assets or revenues of the SPEs. The phase-in recovery bonds issued by these SPEs are payable only from, and secured by, phase-in recovery property held by the SPEs (i.e. the right to impose, charge and collect irrevocable non-bypassable usage-based charges payable by retail electric customers in the service territories of the Ohio Companies) and the bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. The SPEs are considered VIEs and each one is consolidated into its applicable utility. 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 with a weighted average coupon of 2.48% to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds were sold to a trust that concurrently sold a like aggregate amount of its pass through trust certificates to public investors. The proceeds were primarily used to redeem $410 million in existing taxable bonds of the Ohio Companies with a weighted average coupon of 5.71%, including $30 million of make-whole premiums. The securitization effectively allows for the recovery of the make-whole premiums and transactional costs through the imposition of non-bypassable phase-in recovery charges on retail electric customers of the Ohio Companies pursuant to Ohio law. The $410 million of redemption consisted of original maturities of $225 million due 2013, $150 million due 2015 and $35 million due 2020. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows.
	Mining Operations
	In 2008, FEV entered into a joint venture in the Signal Peak mining and coal transportation operations near Roundup, Montana. FEV made equity investments totaling $134 million in exchange for a 50% economic interest in the joint venture. On October 18, 2011, Pinesdale LLC, a subsidiary of Gunvor Group, Ltd., purchased a one-third interest in the Signal Peak joint venture in which FEV held a 50% interest. As part of the transaction, FirstEnergy received $258 million in proceeds and retained a 33-1/3% equity ownership in Global Holding, the holding company for the joint venture. The sale resulted in a pre-tax gain of approximately $569 million ($370 million after-tax), which included $379 million from the remeasurement of FEV's retained investment. The gain attributed to the retained investment remeasurement is being amortized as coal is extracted from the mine on a units of production method.
	Prior to the sale, FirstEnergy consolidated this joint venture since FEV was determined to be the primary beneficiary of the VIE. As a result of the sale, FEV was no longer determined to be the primary beneficiary and its retained 33-1/3%% interest is subject to the equity method of accounting.
	Trusts
	FirstEnergy's consolidated financial statements include PNBV and Shippingport. FirstEnergy used debt and available funds to purchase the notes issued by PNBV and Shippingport for the purchase of lease obligation bonds. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. During 2013, the investments held at Shippingport were liquidated.
	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 AE 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 the portion of the PATH project that was to be constructed by PATH-WV.
	On August 24, 2012, PJM removed the PATH project from its long-range expansion plans. See Note 15, Regulatory Matters, for additional information on the abandonment of PATH.
	Power Purchase Agreements
	FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities 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 21 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 two of these NUG entities, it does not have variable interests in the entities or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold variable interests in the remaining two entities; 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 to be recovered from customers. Purchased power costs related to the contracts that may contain a variable interest were $185 million and $253 million during the years ended December 31, 2013 and 2012, respectively.
	In 1998 the PPUC issued an order approving a transition plan for WP that disallowed certain costs, including an estimated amount for an adverse power purchase commitment related to the NUG entity wherein WP may hold a variable interest, for which WP has taken the scope exception. On November 20, 2012, WP entered into an agreement to terminate the adverse power purchase commitment and accrued a pre-tax loss of $17 million. WP terminated the adverse commitment on January 1, 2013. WP's liability for this adverse purchase power commitment was $60 million, which included the $17 million accrual and was paid in January 2013.
	Sale and Leaseback
	FirstEnergy has variable interests in certain sale and leaseback transactions. 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. See Note 6, Leases for additional details.
	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, 2013:
		Maximum		Discounted Lease		Net
		Exposure		Payments, net(1)		Exposure
		(In millions)
	FES	$	1,274	$	1,063	$	211
	Other FE subsidiaries	752		289		463
	(1)	The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.1 billion.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
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 process for FTRs, NUGs and LCAPPs 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 MWH. 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 MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement.
	LCAPP contracts are financially settled agreements that allow eligible generators to receive payments from, or make payments to, JCP&L, pursuant to an annually calculated load-ratio share of the capacity produced by the generator based upon the annual forecasted peak demand as determined by PJM. LCAPP contracts are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable input into the model is forecasted regional capacity prices. Pricing for the LCAPP contracts is a combination of PJM RPM capacity auction prices and internal models using historical trends and market data for the remaining years under contract. Capacity prices beyond the 2016/2017 delivery year are developed through a simulation of future PJM RPM auctions. The capacity price forecast assumes a continuation of the current PJM RPM market design and is reflective of the regional peak demand growth and generation fleet additions and retirements that underlie FirstEnergy’s long-term energy price forecast. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. During the fourth quarter of 2013, all LCAPP contracts were terminated. See Note 10, Derivative Instruments for additional information.
	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, 2013, from those used as of December 31, 2012. 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, 2013 and 2012. 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, 2013																December 31, 2012
		Level 1				Level 2				Level 3				Total				Level 1			Level 2			Level 3			Total
	Assets	(In millions)
	Corporate debt securities	$	—			$	1,365			$	—			$	1,365			$	—		$	1,259		$	—		$	1,259
	Derivative assets - commodity contracts	7				208				—				215				—			252			—			252
	Derivative assets - FTRs	—				—				4				4				—			—			8			8
	Derivative assets - NUG contracts(1)	—				—				20				20				—			—			36			36
	Equity securities(2)	317				—				—				317				310			—			—			310
	Foreign government debt securities	—				109				—				109				—			126			—			126
	U.S. government debt securities	—				165				—				165				—			179			—			179
	U.S. state debt securities	—				228				—				228				—			299			—			299
	Other(3)	187				255				—				442				126			227			—			353
	Total assets	$	511			$	2,330			$	24			$	2,865			$	436		$	2,342		$	44		$	2,822
	Liabilities
	Derivative liabilities - commodity contracts	$	(13	)		$	(100	)		$	—			$	(113	)		$	(3	)	$	(151	)	$	—		$	(154	)
	Derivative liabilities - FTRs	—				—				(12		)		(12		)		—			—			(9		)	(9		)
	Derivative liabilities - NUG contracts(1)	—				—				(222		)		(222		)		—			—			(290		)	(290		)
	Derivative liabilities - LCAPP contracts(1)	—				—				—				—				—			—			(144		)	(144		)
	Total liabilities	$	(13	)		$	(100	)		$	(234	)		$	(347	)		$	(3	)	$	(151	)	$	(443	)	$	(597	)
	Net assets (liabilities)(4)	$	498			$	2,230			$	(210	)		$	2,518			$	433		$	2,191		$	(399	)	$	2,225
	(1)	NUG and LCAPP 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 short-term cash investments.
	(4)	Excludes $10 million and $110 million as of December 31, 2013 and December 31, 2012, 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, LCAPP contracts, and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2013 and December 31, 2012:
		NUG Contracts(1)												LCAPP Contracts(1)										FTRs
		Derivative Assets				Derivative Liabilities				Net				Derivative Assets				Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
		(In millions)
	January 1, 2012 Balance	$	57			$	(349	)		$	(292	)		$	—			$	—		$	—		$	1		$	(23	)	$	(22	)
	Unrealized gain (loss)	(20		)		(180		)		(200		)		—				1			1			6			(6		)	—
	Purchases	—				—				—				—				(145		)	(145		)	13			(10		)	3
	Settlements	(1		)		239				238				—				—			—			(12		)	30			18
	December 31, 2012 Balance	$	36			$	(290	)		$	(254	)		$	—			$	(144	)	$	(144	)	$	8		$	(9	)	$	(1	)
	Unrealized gain (loss)	(8		)		(17		)		(25		)		—				(22		)	(22		)	3			1			4
	Purchases	—				—				—				—				—			—			6			(15		)	(9		)
	Terminations(2)	—				—				—				—				166			166			—			—			—
	Settlements	(8		)		85				77				—				—			—			(13		)	11			(2		)
	December 31, 2013 Balance	$	20			$	(222	)		$	(202	)		$	—			$	—		$	—		$	4		$	(12	)	$	(8	)
	(1)	Changes in the fair value of NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings.
	(2)	See Note 10, Derivative Instruments.
	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, 2013:
			Fair Value, Net (In millions)				Valuation		Significant Input		Range		Weighted Average		Units
							Technique
	FTRs		$	(8	)		Model		RTO auction clearing prices		($2.80) to $5.20		$0.60		Dollars/MWH
	NUG Contracts		$	(202	)		Model		Generation		600 to 5,641,000		1,529,000		MWH
Regional electricity prices									$51.70 to $57.30		$53.80		Dollars/MWH
FES
Recurring Fair Value Measurements	December 31, 2013																December 31, 2012
	Level 1				Level 2				Level 3				Total				Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—			$	792			$	—			$	792			$	—		$	703		$	—		$	703
Derivative assets - commodity contracts	7				208				—				215				—			252			—			252
Derivative assets - FTRs	—				—				3				3				—			—			6			6
Equity securities(1)	207				—				—				207				294			—			—			294
Foreign government debt securities	—				65				—				65				—			61			—			61
U.S. government debt securities	—				27				—				27				—			27			—			27
Other(2)	—				176				—				176				—			104			—			104
Total assets	$	214			$	1,268			$	3			$	1,485			$	294		$	1,147		$	6		$	1,447
Liabilities
Derivative liabilities - commodity contracts	$	(13	)		$	(100	)		$	—			$	(113	)		$	(3	)	$	(151	)	$	—		$	(154	)
Derivative liabilities - FTRs	—				—				(11		)		(11		)		—			—			(6		)	(6		)
Total liabilities	$	(13	)		$	(100	)		$	(11	)		$	(124	)		$	(3	)	$	(151	)	$	(6	)	$	(160	)
Net assets (liabilities)(3)	$	201			$	1,168			$	(8	)		$	1,361			$	291		$	996		$	—		$	1,287
(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 $9 million and $94 million as of December 31, 2013 and December 31, 2012, 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, 2013 and December 31, 2012:
		Derivative Asset FTRs				Derivative Liability FTRs				Net FTRs
		(In millions)
January 1, 2012 Balance		$	1			$	(7	)		$	(6	)
Unrealized gain (loss)		4				(4		)		—
Purchases		9				(7		)		2
Settlements		(8		)		12				4
December 31, 2012 Balance		$	6			$	(6	)		$	—
Unrealized loss		—				(2		)		(2		)
Purchases		5				(12		)		(7		)
Settlements		(8		)		9				1
December 31, 2013 Balance		$	3			$	(11	)		$	(8	)
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, 2013:
		Fair Value, Net (In millions)				Valuation		Significant Input		Range		Weighted Average		Units
						Technique
FTRs		$	(8	)		Model		RTO auction clearing prices		($2.80) to $5.20		$0.50		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, AFS securities and notes receivable.
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 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, 2013 and December 31, 2012:
		December 31, 2013(1)												December 31, 2012(2)
		Cost Basis				Unrealized Gains				Fair Value				Cost Basis				Unrealized Gains			Fair Value
		(In millions)
Debt securities
FirstEnergy		$	1,881			$	33			$	1,914			$	1,827			$	34		$	1,861
FES		918				17				935				778				14			792
Equity securities
FirstEnergy		$	308			$	9			$	317			$	293			$	16		$	309
FES		207				—				207				281				13			294
(1)	Excludes short-term cash investments: FE Consolidated - $204 million; FES - $135 million.
(2)	Excludes short-term cash investments: FE Consolidated - $326 million; FES - $196 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, 2013, 2012 and 2011 were as follows:
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
December 31, 2012		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and Dividend Income
		(In millions)
FirstEnergy		$	2,980			$	179			$	(83	)		$	(16	)		$	70
FES		1,464				124				(59		)		(14		)		39
December 31, 2011		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and
																		Dividend Income
		(In millions)
FirstEnergy		$	4,207			$	229			$	(71	)		$	(19	)		$	82
FES		1,843				80				(29		)		(17		)		47
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, 2013 and December 31, 2012:
		December 31, 2013												December 31, 2012
		Cost Basis				Unrealized Gains				Fair Value				Cost Basis				Unrealized Gains			Fair Value
		(In millions)
Debt Securities
FirstEnergy		$	33			$	2			$	35			$	54			$	30		$	84
Investments in emission allowances, employee benefit trusts and cost and equity method investments, including FirstEnergy's investment in Global Holding, totaling $636 million as of December 31, 2013, and $644 million as of December 31, 2012, 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, 2013								December 31, 2012
	Carrying				Fair				Carrying				Fair
	Value				Value				Value				Value
	(In millions)
FirstEnergy	$	17,049			$	17,957			$	16,957			$	19,460
FES	3,001				3,073				4,194				4,524
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, 2013 and December 31, 2012.

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2013
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 relating 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. Derivatives that meet those criteria are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance. Changes in the fair value of derivative instruments that qualified and were designated as cash flow hedge instruments are recorded in AOCI. Changes in the fair value of derivative instruments that are not designated as cash flow hedge instruments are recorded in net income on a mark-to-market basis. 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. The effective portion of gains and losses on a derivative contract is reported as a component of AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.
	Total net unamortized gains included in AOCI associated with instruments previously designated to be in a cash flow hedging relationship totaled $2 million and $10 million as of December 31, 2013 and December 31, 2012, respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $10 million is expected to be amortized to income during the next twelve months.
	FirstEnergy has used forward starting 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 treated 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 unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $59 million and $70 million as of December 31, 2013 and December 31, 2012, respectively. Based on current estimates, approximately $9 million will be amortized to interest expense during the next twelve months.
	As of December 31, 2013 and December 31, 2012, no commodity or interest rate derivatives were designated as cash flow hedges.
	Refer to Note 2, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the years ended December 31, 2013 and 2012.
	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. These derivative instruments were treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates.
	Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $44 million and $79 million as of December 31, 2013 and December 31, 2012, respectively. Based on current estimates, approximately $12 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $19 million and $22 million during the years ended December 31, 2013 and 2012, respectively. In connection with the redemptions of senior notes by FES, PN, and ME and taxable bonds by CEI and OE, unamortized gains associated with fixed for floating interest rate swap agreements of $17 million were included in the Loss on debt redemptions in the Consolidated Statements of Income for the year ended December 31, 2013. Refer to Note 12, Capitalization, for additional information regarding FirstEnergy's debt redemptions during the year ended December 31, 2013. In 2012, FirstEnergy terminated all forward starting swap agreements resulting in cash proceeds and a net gain, recorded as a reduction to interest expense, of approximately $6 million.
	As of December 31, 2013 and December 31, 2012, 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, 2013, FES' net asset position under commodity derivative contracts was $102 million. Under these commodity derivative contracts, FES posted $29 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $1 million of additional collateral if the credit rating for its debt were to fall below investment grade.
	Based on commodity derivative contracts held as of December 31, 2013, an adverse change of 10% in commodity prices would decrease net income by approximately $27 million during the next twelve months.
	NUGs
	As of December 31, 2013, FirstEnergy's net liability position under NUG contracts was $202 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.
	LCAPP
	The LCAPP law was enacted in New Jersey during 2011 to promote the construction of qualified electric generation facilities. JCP&L maintained two LCAPP contracts, which are financially settled agreements that allow eligible generators to receive payments from, or make payments to, JCP&L pursuant to an annually calculated load-ratio share of the capacity produced by the generator based upon the annual forecasted peak demand as determined by PJM. JCP&L expected to recover from its customers payments made to the generators and give credit to customers for payments from the generators under these contracts. As a result, the projected future obligations for the LCAPP contracts are considered derivative liabilities with a corresponding regulatory asset. Since the LCAPP contracts were subject to regulatory accounting, changes in their fair value did not impact earnings. On October 11, 2013, the U.S. District Court for the District of New Jersey declared that the LCAPP is preempted by the FPA and unconstitutional. On October 22, 2013, the Superior Court of New Jersey Appellate Division dismissed two consolidated appeals which had been taken from the final order of the NJBPU which accepted and adopted the recommendation of the NJBPU's Agent regarding implementation of the LCAPP law. Dismissal of the consolidated appeals, along with pending matters currently on remand to the NJBPU, was without prejudice subject to the parties exercising their appellate rights in the federal courts. The parties filed an appeal with the U.S. Court of Appeals for the Third Circuit with briefing by the parties to be completed by March 5, 2014. Consistent with the provisions of the LCAPP contracts, the U.S District Court's ruling is a termination event. During the fourth quarter of 2013, JCP&L issued termination notices to the counterparties and reversed the derivative liability and corresponding regulatory asset on its Consolidated Balance Sheet.
	FTRs
	As of December 31, 2013, FirstEnergy's and FES' net liability position under FTRs was $8 million and FES posted $5 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 the PJM RTO. The PJM RTO 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 the RTO, 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,
		2013				2012					2013				2012
		(In millions)									(In millions)
	Current Assets - Derivatives									Current Liabilities - Derivatives
	Commodity Contracts	$	162			$	153			Commodity Contracts	$	(102	)		$	(119	)
	FTRs	4				7				FTRs	(9		)		(7		)
		166				160					(111		)		(126		)
										Noncurrent Liabilities - Adverse Power Contract Liability
										NUGs	(222		)		(290		)
	Deferred Charges and Other Assets - Other									LCAAP	—				(144		)
	Commodity Contracts	53				99				Noncurrent Liabilities - Other
	FTRs	—				1				Commodity Contracts	(11		)		(36		)
	NUGs	20				36				FTRs	(3		)		(2		)
		73				136					(236		)		(472		)
	Derivative Assets	$	239			$	296			Derivative Liabilities	$	(347	)		$	(598	)
	FirstEnergy enters into contracts with counterparties that allow for net settlement of derivative assets and derivative liabilities. 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 instruments 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, 2013		Fair Value				Derivative Instruments				Cash Collateral (Received)/Pledged				Net Fair Value
			(In millions)
	Derivative Assets
	Commodity contracts		$	215			$	(106	)		$	(9	)		$	100
	FTRs		4				(4		)		—				—
	NUG contracts		20				—				—				20
			$	239			$	(110	)		$	(9	)		$	120
	Derivative Liabilities
	Commodity contracts		$	(113	)		$	106			$	7			$	—
	FTRs		(12		)		4				5				(3		)
	NUG contracts		(222		)		—				—				(222		)
			$	(347	)		$	110			$	12			$	(225	)
							Amounts Not Offset in Consolidated Balance Sheet
	December 31, 2012		Fair Value				Derivative Instruments				Cash Collateral (Received)/Pledged				Net Fair Value
			(In millions)
	Derivative Assets
	Commodity contracts		$	252			$	(142	)		$	(5	)		$	105
	FTRs		8				(8		)		—				—
NUG contracts		36				—				—				36
		$	296			$	(150	)		$	(5	)		$	141
Derivative Liabilities
Commodity contracts		$	(155	)		$	142			$	12			$	(1	)
FTRs		(9		)		8				1				—
NUG contracts		(290		)		—				—				(290		)
LCAPP contracts		(144		)		—				—				(144		)
		$	(598	)		$	150			$	13			$	(435	)
The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of December 31, 2013:
	Purchases			Sales			Net			Units
	(In millions)
Power Contracts	34			37			(3	)		MWH
FTRs	43			—			43			MWH
NUGs	11			—			11			MWH
Natural Gas	77			3			74			mmBTU
The effect of derivative instruments not in a hedging relationship on the Consolidated Statements of Income during 2013 and 2012 are summarized in the following tables:
	Year Ended December 31
	Commodity				FTRs				Interest Rate Swaps				Total
	Contracts
	(In millions)
2013
Unrealized Gain (Loss) Recognized in:
Other Operating Expense	$	11			$	(8	)		$	—			$	3
Realized Gain (Loss) Reclassified to:
Revenues	$	46			$	21			$	—			$	67
Purchased Power Expense	(38		)		—				—				(38		)
Other Operating Expense	—				(36		)		—				(36		)
Fuel Expense	(2		)		—				—				(2		)
2012
Unrealized Gain Recognized in:
Other Operating Expense	$	89			$	13			$	—			$	102
Realized Gain (Loss) Reclassified to:
Revenues	$	302			$	22			$	—			$	324
Purchased Power Expense	(277		)		—				—				(277		)
Other Operating Expense	—				(61		)		—				(61		)
Fuel Expense	5				—				—				5
Interest Expense	—				—				6				6
The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during 2013 and 2012 are summarized in the following table:
		Year Ended December 31
Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				LCAPP				Regulated FTRs				Total
		(In millions)
2013
Unrealized Gain (Loss) on Derivative Instrument		$	(23	)		$	(22	)		$	1			$	(44	)
Realized Gain (Loss) on Derivative Instrument		75				166				(1		)		240
2012
Unrealized Gain (Loss) on Derivative Instrument		$	(201	)		$	(144	)		$	1			$	(344	)
Realized Gain on Derivative Instrument		240				—				7				247
The following table provides a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or credit to) customers during 2013 and 2012:
		Year Ended December 31
Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				LCAPP				Regulated FTRs				Total
		(In millions)
Outstanding net liability as of January 1, 2013		$	(254	)		$	(144	)		$	—			$	(398	)
Additions/Change in value of existing contracts		(23		)		(22		)		1				(44		)
Settled contracts		75				166				(1		)		240
Outstanding net liability as of December 31, 2013		$	(202	)		$	—			$	—			$	(202	)
Outstanding net liability as of January 1, 2012		$	(293	)		$	—			$	(8	)		$	(301	)
Additions/Change in value of existing contracts		(201		)		(144		)		1				(344		)
Settled contracts		240				—				7				247
Outstanding net liability as of December 31, 2012		$	(254	)		$	(144	)		$	—			$	(398	)

Impairment_of_Longlived_Assets

Impairment of Long-lived Assets	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Impairment of Long-lived Assets	'
	IMPAIRMENT OF LONG-LIVED ASSETS
	FirstEnergy reviews long-lived assets, including regulatory 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.
	West Virginia Asset Transfer - 2013
	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. The $1.1 billion net consideration was originally financed by MP through an equity infusion from FE of approximately $527 million and a note payable to AE Supply of approximately $573 million. The note payable to AE Supply was repaid in the fourth quarter of 2013. In connection with the closing, in the fourth quarter of 2013, 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 the fourth quarter of 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.
	Generating Plant Retirements - 2013
	On July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating the following generating units by October 9, 2013:
	Generating Units	MW Capacity	Location
	Hatfield's Ferry, Units 1-3	1,710	Masontown, Pennsylvania
	Mitchell, Units 2-3	370	Courtney, Pennsylvania
	As a result of this decision, in the second quarter of 2013, 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 is included within the results of the Competitive Energy Services segment. On October 9, 2013, Hatfield's Ferry Units 1-3 and Mitchell Units 2-3 were deactivated.
	Approximately 240 plant employees and generation related positions were affected by these plant deactivations. FirstEnergy recorded approximately $6 million (pre-tax) severance related expenses that were recognized in Other operating expenses in the Consolidated Statements of Income during the year ended 2013.
	AE Supply has obligations, such as fuel supply, that could be affected by the plant deactivations and management is currently unable to reasonably estimate potential costs, or a range thereof, that could be incurred.
	Generating Plant Retirements - 2011
	On January 26, 2012 and February 8, 2012, FG, MP and AE Supply announced the deactivation by September 1, 2012 (subject to a reliability review by PJM) of nine coal-fired power plants (Albright, Armstrong, Ashtabula, Bay Shore except for generating unit 1, Eastlake, Lakeshore, R. Paul Smith, Rivesville and Willow Island) with a total capacity of 3,349 MW due to MATS and other environmental regulations. As a result of this decision, FirstEnergy recorded a pre-tax impairment of $334 million to continuing operations during the year ended 2011. This impairment consisted of a $311 million write down of the carrying value of the plant assets, approximately $5 million in excessive SO2 emission allowances and an $18 million charge for excessive or obsolete inventory at these facilities. On April 25, 2012, PJM concluded its initial analysis of the reliability impacts from the previously announced plant deactivations and requested RMR arrangements for Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 through the spring of 2015. In February 2014, PJM notified FirstEnergy that Eastlake Units 1-3 and Lake Shore Unit 18 will be released from RMR status as of September 15, 2014. On July 10, 2012, and as amended on October 31, 2012, FirstEnergy filed with FERC, for informational purposes, the compensation arrangements for these units which will remain in effect for as long as these generating units continue to operate. As of September 1, 2012, Albright, Armstrong, Bay Shore (except for generating unit 1), Eastlake Units 4-5, R. Paul Smith, Rivesville and Willow Island were deactivated. During the year ended December 31, 2012, FirstEnergy recognized pre-tax severance expense of approximately $14 million ($10 million by FES) as a result of the deactivations. These costs are included in "other operating expenses" in the Consolidated Statements of Income.
	In addition to the emission allowance impairments in connection with the plant closures, FirstEnergy recorded during 2011, pre-tax impairment charges of approximately $6 million ($1 million for FES and $5 million for AE Supply) for NOx emission allowances that were expected to be obsolete after 2011 and approximately $16 million ($13 million for FES and $3 million for AE Supply) for excess SO2 emission allowances in inventory that it expected will not be consumed in the future.
	Fremont Energy Center
	On March 11, 2011, FirstEnergy and American Municipal Power, Inc., entered into an agreement for the sale of Fremont Energy Center, which included two natural gas combined-cycle combustion turbines and a steam turbine capable of producing 544 MW of load-following capacity and 163 MW of peaking capacity. The execution of this agreement triggered a need to evaluate the recoverability of the carrying value of the assets associated with the Fremont Energy Center. The estimated fair value of the Fremont Energy Center was based on the purchase price outlined in the sale agreement with American Municipal Power, Inc. The result of this evaluation indicated that the carrying cost of the Fremont Energy Center was not fully recoverable. As a result of the recoverability evaluation, FirstEnergy recorded an impairment charge of $11 million to operating income in the first quarter of 2011. On July 28, 2011, FirstEnergy completed the sale of Fremont Energy Center to American Municipal Power, Inc.
	Peaking Facilities
	During 2011, FirstEnergy assessed the carrying values of certain peaking facilities that were to be sold or disposed of before the end of their useful lives. The estimated fair values were based on estimated sales prices quoted in an active market and indicated that the carrying costs of the peaking facilities were not fully recoverable. FirstEnergy recorded impairment charges of $23 million during 2011 and on October 18, 2011, FirstEnergy closed on the sale of the Richland and Stryker peaking facilities.

Capitalization

Capitalization	12 Months Ended
	Dec. 31, 2013
Capitalization, Long-term Debt and Equity [Abstract]	'
Capitalization	'
	CAPITALIZATION
	COMMON STOCK
	Retained Earnings and Dividends
	As of December 31, 2013, FirstEnergy’s unrestricted retained earnings were $2.6 billion. Dividends declared in 2013 were $1.65 per share, which included dividends of $0.55 per share paid in the second, third and fourth quarters of 2013. Dividends declared in 2012 were $2.20 per share, which included dividends of $0.55 per share paid in the second, third and fourth quarter of 2012 and dividends of $0.55 per share paid in the first quarter of 2013. 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 21, 2014 the Board of Directors declared a quarterly dividend of $0.36 per share to be paid in the first quarter of 2014.
	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 FE from paid-in capital accounts, as long as their FERC-defined equity to total capitalization ratio remains above 50% and 45%, respectively. 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, 2013.
	SIP/DRIP Program
	On September 25, 2013, FE filed a registration statement with the SEC to register 4 million shares of common stock to be issued to registered shareholders and its employees and the employees of its subsidiaries under its Stock Investment Plan. In addition, during December 2013, FE began fulfilling certain share-based benefit plan obligations through the issuance of authorized but unissued common stock.
	PREFERRED AND PREFERENCE STOCK
	FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2013, 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, 2013, and 2012, 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, 2013 and 2012:
		As of December 31, 2013				As of December 31
	(Dollar amounts in millions)	Maturity Date		Interest Rate		2013				2012
	FirstEnergy:
	FMBs	2014 - 2043		3.340% - 9.740%		$	3,166			$	2,587
	Secured notes - fixed rate	2017 - 2037		6.150% - 7.880%		1,804				2,113
	Secured notes - variable rate					—				50
	Total secured notes					1,804				2,163
	Unsecured notes - fixed rate	2014 - 2039		3.500% - 7.350%		11,076				11,145
	Unsecured notes - variable rate	2014 - 2015		0.020% - 1.665%		959				959
	Total unsecured notes					12,035				12,104
	Capital lease obligations					188				176
	Unamortized debt premiums					9				45
	Unamortized fair value adjustments					44				103
	Currently payable long-term debt					(1,415		)		(1,999		)
	Total long-term debt and other long-term obligations					$	15,831			$	15,179
	FES:
	Secured notes - fixed rate	2015 - 2017		5.150% - 12.000%		$	188			$	689
	Secured notes - variable rate					—				50
	Total secured notes					188				739
	Unsecured notes - fixed rate	2014 - 2039		2.150% - 6.800%		2,077				2,769
	Unsecured notes - variable rate	2014 - 2015		0.130% - 0.160%		736				686
	Total unsecured notes					2,813				3,455
	Capital lease obligations					22				27
	Unamortized debt discounts					(1		)		(1		)
	Currently payable long-term debt					(892		)		(1,102		)
	Total long-term debt and other long-term obligations					$	2,130			$	3,118
	On March 5, 2013, FE issued in aggregate $1.5 billion of senior unsecured notes in two series: $650 million of 2.75% senior notes due March 15, 2018 and $850 million of 4.25% senior notes due March 15, 2023. The stated interest rates are subject to adjustments based upon changes in the credit ratings of FirstEnergy but will not decrease below the issued rates. The proceeds were used to repay short-term borrowings and to invest in the money pool for FES and AE Supply's use in funding a portion of their concurrent tender offers.
	On March 28, 2013, pursuant to tender offers launched in February 2013, FES and AE Supply repurchased $369 million and $294 million, respectively, of outstanding senior notes with interest rates ranging from 5.75% to 6.8%. The $369 million of FES repurchases consisted of original maturities of $252 million due 2021 and $117 million due 2039. The $294 million of AE Supply repurchases consisted of original maturities of $194 million due 2019 and $100 million due 2039. FES and AE Supply paid $67 million and $43 million, respectively, in tender premiums to repurchase the tendered senior notes. FirstEnergy recorded a loss on debt redemption of $119 million (FES - $71 million), including such premiums and other related expenses. The tender premiums paid are included in cash flows from financing activities in the Consolidated Statement of Cash Flows.
	In March 2013, ME issued $300 million of 3.50% senior unsecured notes due March 15, 2023. Proceeds from this offering were used to repay $150 million of ME 4.95% senior unsecured notes that matured in March 2013 and short-term borrowings.
	On April 15, 2013, FES redeemed $400 million of its 4.80% senior notes due 2015 and recorded a loss on debt redemption of $32 million including $31 million of make-whole premiums paid. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows.
	On May 8, 2013, FE, FES, AE Supply and FE's other borrowing subsidiaries entered into extensions and amendments to the three existing multi-year syndicated revolving credit facilities. Each facility was extended until May 2018, unless the lenders agree, at the request of the applicable borrowers, to an additional one-year extension. The FE Facility was amended to increase the lending banks' commitments under the facility by $500 million to a total of $2.5 billion and to increase the individual borrower sub-limits for FE by $500 million to a total of $2.5 billion and for JCP&L by $175 million to a total of $600 million.
	On June 3, 2013, FG exercised a mandatory put option and repurchased approximately $235 million of PCRBs due 2023, which FG is currently holding for remarketing subject to future market and other conditions.
	As discussed in Note 8, Variable Interest Entities, 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 with a weighted average coupon of 2.48% to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds were sold to a trust that concurrently sold a like aggregate amount of its pass through trust certificates to public investors. The proceeds were primarily used to redeem $410 million in existing taxable bonds of the Ohio Companies with a weighted average coupon of 5.71%, including $30 million of make-whole premiums. The securitization effectively allows for the recovery of the make-whole premiums and transactional costs through the imposition of non-bypassable phase-in recovery charges on retail electric customers of the Ohio Companies pursuant to Ohio law. The $410 million of redemption consisted of original maturities of $225 million due 2013, $150 million due 2015 and $35 million due 2020. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows.
	During August, the Ohio Companies redeemed an additional $660 million of long-term debt with interest rates ranging from 5.65% to 7.25% and paid approximately $120 million of make-whole premiums which were deferred as a regulatory asset and will be amortized over the original life of the redeemed debt. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows. Additionally, during August, JCP&L issued $500 million of 4.7% unsecured notes due April 2024 and used the proceeds to pay down a portion of its short-term debt obligations.
	On November 15, 2013, AE Supply optionally redeemed $235 million of its 7.00% PCRBs due July 15, 2039 at 100% of the principal amount in connection with the deactivation of operations at Hatfield's Ferry.
	On November 27, 2013, MP issued $400 million of 4.10% FMBs due April 15, 2024 and $600 million of 5.40% FMBs due December 15, 2043. Proceeds from this offering were used by MP to: (i) repay at maturity $300 million of its FMBs, 7.95% Series due December 15, 2013; (ii) redeem $120 million of its FMBs, 6.70% Series due June 15, 2014; (iii) repay a $572.7 million short-term promissory note originally issued on October 9, 2013 to its affiliate, AE Supply in connection with MP’s acquisition of the remaining ownership of the Harrison Power Station; and (iv) for working capital needs and other general corporate purposes.
During December of 2013, FE entered into an agreement to extend and amend its $150 million term loan agreement with a maturity date of December 31, 2014. The maturity of the loan was extended to December 31, 2015 and the principal amount was increased to $200 million. On December 26, 2013, PN redeemed $150 million of its 5.13% Senior Notes due April 1,2014 and ME redeemed $100 million of its 4.88% Senior Notes due April 1, 2014.
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. 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. The right to collect environmental control charges is not included as an asset on FirstEnergy's consolidated balance sheets. 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, 2013 and 2012, $472 million and $493 million of environmental control bonds were outstanding, respectively.
Transition Bonds
The consolidated financial statements of FirstEnergy and JCP&L include the accounts of JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. 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, 2013 and 2012, $207 million and $243 million of the transition bonds were outstanding, respectively.
Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate annual servicing fees of up to $628 thousand that are payable from TBC collections.
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 with a weighted average coupon of 2.48% to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds were sold to a trust that concurrently sold a like aggregate amount of its pass through trust certificates to public investors.
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, 2013, the sinking fund requirement for all FMBs issued under the various mortgage indentures amounted to payments of $7 million in 2013, all of which relate to Penn. Penn expects to meet its 2013 annual sinking fund requirement with a replacement credit under its mortgage indenture.
As of December 31, 2013, FirstEnergy’s currently payable long-term debt included approximately $809 million (FES — $736 million) of 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, 2013. PCRBs that can be tendered for mandatory purchase prior to maturity are reflected in 2014.
Year	FirstEnergy				FES
	(In millions)
2014	$	1,376			$	887
2015	1,264				391
2016	1,041				417
2017	1,641				163
2018	1,453				266
The following table classifies the outstanding fixed rate put 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)
2014	$	835			$	762
2015	313				313
2016	391				391
2017	130				130
2018	125				125
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, NG and the applicable Utilities are entitled to a credit against their obligation to repay those bonds. FG, NG and the applicable Utilities pay annual fees based on the amounts of the LOCs to the issuing banks and are obligated to reimburse the banks or insurers, as the case may be, for any drawings thereunder. The insurers hold FMBs as security for such reimbursement obligations.
The amounts and annual fees for PCRB-related LOCs for FirstEnergy and FES as of December 31, 2013, are as follows:
	Aggregate LOC Amount				Annual Fees
	(In millions)
FirstEnergy	$	818			1.65% to 3.30%
FES	744				1.65% to 3.30%
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, 2013, 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 FirstEnergy 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 FirstEnergy. Also, defaults by FirstEnergy would generally not cross-default applicable financing arrangements of any of FirstEnergy’s subsidiaries. Cross-default provisions are not typically found in any of the senior notes or FMBs of FirstEnergy, FG, NG or the Utilities.

ShortTerm_Borrowings_and_Bank_

Short-Term Borrowings and Bank Lines of Credit	12 Months Ended
	Dec. 31, 2013
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
	FirstEnergy had $3,404 million and $1,969 million of short-term borrowings as of December 31, 2013 and December 31, 2012, respectively. FirstEnergy’s available liquidity as of January 31, 2014, was as follows:
	Borrower(s)		Type		Maturity		Commitment				Available Liquidity
							(In millions)
	FirstEnergy(1)		Revolving		May-18		$	2,500			$	224
	FES / AE Supply		Revolving		May-18		2,500				2,489
	FET(2)		Revolving		May-18		1,000				—
					Subtotal		$	6,000			$	2,713
					Cash		—				48
					Total		$	6,000			$	2,761
	-1	FE and the Utilities
	-2	Includes FET, ATSI and TrAIL as subsidiary borrowers
	Revolving Credit Facilities
	FirstEnergy, FES/AE Supply and FET Facilities
	FE and certain of its subsidiaries participate in three five-year syndicated revolving credit facilities with aggregate commitments of $6.0 billion (Facilities). The Facilities consist of a $2.5 billion aggregate FirstEnergy Facility, a $2.5 billion FES/AE Supply Facility and a $1.0 billion FET Facility, that are each available until May 2018, unless the lenders agree, at the request of the applicable borrowers, to an additional one-year extension. 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.
	On May 8, 2013, FE, FES, AE Supply and FE's other borrowing subsidiaries entered into extensions and amendments to the three existing multi-year syndicated revolving credit facilities. Each facility was extended until May 2018, unless the lenders agree, at the request of the applicable borrowers, to an additional one-year extension. The FE Facility was amended to increase the lending banks' commitments under the facility by $500 million to a total of $2.5 billion and to increase the individual borrower sub-limits for FE by $500 million to a total of $2.5 billion and for JCP&L by $175 million to a total of $600 million.
	On October 31, 2013, FE amended its existing $2.5 billion multi-year syndicated revolving credit facility to exclude certain after-tax, non-cash write-downs and non-cash charges of approximately $1.4 billion (primarily related to Pension and OPEB mark-to-market adjustments, impairment of long-lived assets and regulatory charges) from the debt to total capitalization ratio calculations incurred through September 30, 2013. Additionally, the amendment provides for a future allowance of approximately $1.35 billion for after-tax, non-cash write-downs and non-cash charges over the remaining life of the facility. Similarly, the FES/AE Supply $2.5 billion revolving credit facility was also amended to exclude certain similar after-tax, non-cash write-downs and non-cash charges of $785.7 million incurred through September 30, 2013 from the debt to total capitalization ratio calculations. As of December 31, 2013, the borrowers were in compliance with the applicable debt to total capitalization ratios under the respective Facilities.
	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, 2013:
	Borrower		Revolving Credit Facility Sub-Limits					Regulatory and Other Short-Term Debt Limitations
			(In millions)
	FE			$	2,500				$	—		(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					850			(3)
	ME			300					500			(3)
	PN			300					300			(3)
	WP			200					200			(3)
	MP			150					500			(3)
	PE			150					150			(3)
	ATSI			100					500			(3)
	Penn			50					50			(3)
	TrAIL			200					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, $700 million of the FirstEnergy 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.
	Term Loan
	During December of 2013, FE entered into an agreement to extend and amend its $150 million term loan agreement with a maturity date of December 31, 2014. The maturity of the loan was extended to December 31, 2015 and the principal amount was increased to $200 million.
	FirstEnergy Money Pools
	FirstEnergy's regulated 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 during 2013 was 0.67% per annum for the regulated companies' money pool and 1.34% 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, 2013 and 2012, were as follows:
			2013			2012
	FirstEnergy		1.8	%		1.97	%

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012 were as follows:
		2013			2012
		(In millions)
	FirstEnergy	$	2,201		$	2,204
	FES	$	1,276		$	1,283
	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 in the recognition of the liability.
	The following table summarizes the changes to the ARO balances during 2013 and 2012:
	ARO Reconciliation	FirstEnergy			FES
		(In millions)
	Balance, January 1, 2012	$	1,497		$	904
	Liabilities settled	(2		)	(1		)
	Accretion	104			62
	Balance, December 31, 2012	$	1,599		$	965
	Liabilities settled	(18		)	(18		)
	Accretion	115			71
	Revisions in estimated cash flows	(18		)	(3		)
	Balance, December 31, 2013	$	1,678		$	1,015
	During 2013, revisions to estimated cash flows as a result of increased cost estimates for the closure of LBR increased the associated ARO liability of FES by $163 million. The revised cost estimates were the result of a Closure Plan submitted to the PA DEP by FG on March 28, 2013, which provides for placing a final cap over LBR, and a response to a technical deficiency letter issued by the PA DEP on October 3, 2013. See Note 16, Commitments, Guarantees, and Contingencies for additional information related to the closure of LBR.
	During the third quarter of 2013, studies were completed to update the estimated cost of asbestos remediation for FES and TE. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and TE and increased the liability for FES and TE by approximately $5 million and $7 million, respectively.
	During the fourth quarter of 2013, revisions to estimated nuclear decommissioning cash flows associated with the ARO liability of FES, OE and TE decreased the liability by $171 million, $15 million and $7 million, respectively. The revision in estimates for the ARO balances is the result of a decommissioning study that was completed by a third-party in connection with Davis-Besse’s license renewal that was submitted to the NRC in February 2014. The most significant revision from this study was related to accelerating the expected date when the DOE would begin to accept spent fuel, to be more in line with the industry assumptions. Additionally, FirstEnergy also updated and revised its estimates for Perry and Beaver Valley Units 1 and 2, in a consistent manner.

Regulatory_Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2013
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 FES, AE Supply or any of their subsidiaries were to engage in the construction of significant new generation facilities in any of those states, they would also be subject to state siting authority.
	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 residential SOS for PE customers expired on December 31, 2012, by statute, service continues in the same manner unless changed by order of the MDPSC. The settlement provisions relating to non-residential SOS have also expired; however, by MDPSC order, the terms of service remain in place unless PE requests or the MDPSC orders a change. PE recovers its costs plus a return for providing SOS.
	The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals to reduce electric consumption by 10% and reduce electricity demand by 15%, in each case by 2015. PE's initial plan submitted in compliance with the statute was approved in 2009 and covered 2009-2011, the first three years of the statutory period. Expenditures were originally estimated to be approximately $101 million for the PE programs for the entire period of 2009-2015. Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, on August 31, 2011, PE filed a new comprehensive plan for the second three year period, 2012-2014, that includes additional and improved programs. The 2012-2014 plan is expected to cost approximately $66 million out of the original $101 million estimate for the entire EmPOWER program. On December 22, 2011, the MDPSC issued an order approving PE's second plan with various modifications and follow-up assignments. 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.
	Pursuant to a bill passed by the Maryland legislature in 2011, the MDPSC adopted rules, effective May 28, 2012, that create specific requirements related to a utility's obligation to address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. The MDPSC will be required to assess each utility's compliance with the new rules, and may assess penalties of up to $25,000 per day, per violation. The new rules set utility-specific SAIDI and SAIFI targets for 2012-2015; prescribe detailed tree-trimming requirements, outage restoration and downed wire response deadlines; and impose other reliability and customer satisfaction requirements. PE has advised the MDPSC that compliance with the new rules is expected to increase costs by approximately $106 million over the period 2012-2015. On April 1, 2013, the Maryland electric utilities, including PE, filed their first annual reports on compliance with the new rules. The MDPSC conducted a hearing on August 20, 2013 to discuss the reports, after which an order was issued on September 3, 2013, which accepted PE's filing and the operational changes proposed therein.
	Following a "derecho" storm through the region on June 29, 2012, the MDPSC convened a new proceeding to consider matters relating to the electric utilities' performance in responding to the storm. Hearings on the matter were conducted in September 2012. Concurrently, Maryland's governor convened a special panel to examine possible ways to improve the resilience of the electric distribution system. On October 3, 2012, that panel issued a report calling for various measures including: acceleration and expansion of some of the requirements contained in the reliability standards which had become final on May 28, 2012; selective increased investment in system hardening; creation of separate recovery mechanisms for the costs of those changes and investments; and penalties or bonuses on returns earned by the utilities based on their reliability performance. On February 27, 2013, the MDPSC issued an order (the February 27 Order) requiring the utilities to submit several reports over a series of months, 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 requires 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 has responded to the requirements in the order consistent with the schedule set forth therein. PE's final filing on September 3, 2013, 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 expect to make 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. The MDPSC has ordered that certain reports of its Staff relating to these matters be provided by May 1, 2014, and otherwise has not issued a schedule for further proceedings in this matter.
	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, which is comprised of two components, is provided through contracts procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component and auction, reflecting hourly real time energy prices, is available for larger commercial and industrial customers. The other BGS component and auction, providing a fixed price service, 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 September 7, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requested that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and reasonable. In its written Order issued July 31, 2012, the NJBPU found that a base rate proceeding "will assure that JCP&L's rates are just and reasonable and that JCP&L is investing sufficiently to assure the provision of safe, adequate and proper utility service to its customers" and ordered JCP&L to file a base rate case using a historical 2011 test year. The rate case petition was filed on November 30, 2012. In the filing, JCP&L requested approval to increase its revenues by approximately $31.5 million and reserved the right to update the filing to include costs associated with the impact of Hurricane Sandy. The NJBPU transmitted the case to the New Jersey Office of Administrative Law for further proceedings and an ALJ has been assigned. On February 22, 2013, JCP&L updated its filing to request recovery of $603 million of distribution-related Hurricane Sandy restoration costs, resulting in increasing the total revenues requested to approximately $112 million. On June 14, 2013, JCP&L further updated its filing to: 1) include the impact of a depreciation study which had been directed by the NJBPU; 2) remove costs associated with 2012 major storms, consistent with the NJBPU orders establishing a generic proceeding to review 2011 and 2012 major storm costs (discussed below); and 3) reflect other revisions to JCP&L's filing. That filing represented an increase of approximately $20.6 million over the revenues produced by existing base rates. Testimony has also been filed in the matter by the Division of Rate Counsel and several other intervening parties in opposition to the base rate increase JCP&L requested. Specifically, the testimony of the Division of Rate Counsel's witnesses recommended that revenues produced by JCP&L's base rates for electric service be reduced by approximately $202.8 million (such amount did not address the revenue requirements associated with major storm events of 2011 and 2012, which are subject to review in the generic proceeding). JCP&L filed rebuttal testimony in response to the testimony of other parties on August 7, 2013. Hearings in the rate case have concluded. In the initial briefs of the parties filed on January 27, 2014, the Division of Rate Counsel recommended that base rate revenues be reduced by $214.9 million while the NJBPU Staff recommended a $207.4 million reduction (such amounts do not address the revenue requirements associated with the major storm events of 2011 and 2012). Reply briefs were filed on February 24, 2014.
	On March 20, 2013, the NJBPU ordered that a generic proceeding be established to investigate the prudence of costs incurred by all New Jersey utilities for service restoration efforts associated with the major storm events of 2011 and 2012. The Order provided that if any utility had already filed a proceeding for recovery of such storm costs, to the extent the amount of approved recovery had not yet been determined, the prudence of such costs would be reviewed in the generic proceeding. On May 31, 2013, the NJBPU clarified its earlier order to indicate that the 2011 major storm costs would be reviewed expeditiously in the generic proceeding with the goal of maintaining the base rate case schedule established by the ALJ where recovery of such costs would be addressed. The NJBPU further indicated in the May 31 clarification that it would review the 2012 major storm costs in the generic proceeding and the recovery of such costs would be considered through a Phase II in the existing base rate case or through another appropriate method to be determined at the conclusion of the generic proceeding. On June 21, 2013, consistent with NJBPU's orders, JCP&L filed the detailed report in support of recovery of major storm costs with the NJBPU. On November 15, 2013, the Division of Rate Counsel filed testimony recommending that approximately $15 million of JCP&L’s costs be disallowed for recovery. Evidentiary hearings in this proceeding were scheduled for January 2014 but were subsequently adjourned by the NJBPU before their commencement. On February 24, 2014, a Stipulation was filed with the NJBPU by JCP&L, the Division of Rate Counsel and NJBPU Staff which will allow recovery of $736 million of JCP&L’s $744 million of costs related to the significant weather events of 2011 and 2012. As a result, FirstEnergy recorded a regulatory asset impairment charge of approximately $8 million (pre-tax) as of December 31, 2013, included in Amortization of regulatory assets, net within the Consolidated Statements of Income. The agreement, upon which no other party took a position to oppose or support, is now pending before the NJBPU. Recovery of 2011 storm costs will be addressed in the pending base rate case; recovery of 2012 storm costs will be determined by the NJBPU.
	Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held in September 2011 to solicit comments regarding the state of preparedness and responsiveness of New Jersey's EDCs prior to, during, and after Hurricane Irene, with additional hearings held in October 2011. Additionally, the NJBPU accepted written comments through October 28, 2011 related to this inquiry. On December 14, 2011, the NJBPU Staff filed a report of its preliminary findings and recommendations with respect to the electric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU selected a consultant to further review and evaluate the New Jersey EDCs' preparation and restoration efforts with respect to Hurricane Irene and the October 2011 snowstorm, and the consultant's report was submitted to and subsequently accepted by the NJBPU on September 12, 2012. JCP&L submitted written comments on the report. On January 24, 2013, based upon recommendations in its consultant's report, the NJBPU ordered the New Jersey EDCs to take a number of specific actions to improve their preparedness and responses to major storms. The order includes specific deadlines for implementation of measures with respect to preparedness efforts, communications, restoration and response, post event and underlying infrastructure issues. On May 31, 2013, the NJBPU ordered that the New Jersey EDCs implement a series of new communications enhancements intended to develop more effective communications among EDCs, municipal officials, customers and the NJBPU during extreme weather events and other expected periods of extended service interruptions. The new requirements include making information regarding estimated times of restoration available on the EDC's web sites and through other technological expedients. JCP&L is implementing the required measures consistent with the schedule set out in the above NJBPU's orders.
	OHIO
	The Ohio Companies primarily operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include:
	•	Generation supplied through a CBP;
	•	A load cap of no less than 80%, so that no single supplier is awarded more than 80% of the tranches, which also applies to tranches assigned post-auction;
	•	A 6% generation 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);
	•	No increase in base distribution rates through May 31, 2014; and
	•	A new distribution rider, Rider DCR, to recover a return of, and on, capital investments in the delivery system.
	The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI's integration into PJM 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 PJM proceedings. The Ohio Companies also agreed to establish a $12 million fund to assist low income customers over the term of the ESP and agreed to additional matters related to energy efficiency and alternative energy requirements.
	On April 13, 2012, the Ohio Companies filed an application with the PUCO to essentially extend the terms of their ESP for two years. The ESP 3 Application was approved by the PUCO on July 18, 2012. Several parties timely filed applications for rehearing. The PUCO issued an Entry on Rehearing on January 30, 2013 denying all applications for rehearing. Notices of appeal to the Supreme Court of Ohio were filed by two parties in the case, Northeast Ohio Public Energy Council and the ELPC. While briefing has been completed, the matter has not yet been scheduled for oral argument.
	As approved, the ESP 3 plan continues certain provisions from the current ESP including:
	•	Continuing the current base distribution rate freeze through May 31, 2016;
	•	Continuing to provide economic development and assistance to low-income customers for the two-year plan period at levels established in the existing 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);
	•	Continuing to provide power to non-shopping customers at a market-based price set through an auction process; and
	•	Continuing Rider DCR that allows continued investment in the distribution system for the benefit of customers.
	As approved, the ESP 3 plan provides additional provisions, including:
	•	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 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.
	Under SB221, the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of approximately 1,211 GWHs in 2012 (an increase of 416,000 MWHs over 2011 levels), 1,726 GWHs in 2013, 2,306 GWHs in 2014 and 2,903 GWHs for each year thereafter through 2025. The Ohio Companies were also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018. On May 15, 2013, the Ohio Companies filed their 2012 Status Update Report in which they indicated compliance with 2012 statutory energy efficiency and peak demand reduction benchmarks.
	In accordance with PUCO Rules and a PUCO directive, on July 31, 2012 the Ohio Companies filed their three-year portfolio plan for the period January 1, 2013 through December 31, 2015. Estimated costs for the three Ohio Companies' plans total approximately $250 million over the three-year period, which is expected to be recovered in rates to the extent approved by the PUCO. Hearings were held with the PUCO in October 2012. On March 20, 2013, the PUCO approved the three-year portfolio plan for 2013-2015. Applications for rehearing were filed by the Ohio Companies and several other parties on April 19, 2013. The Ohio Companies filed their request for rehearing primarily to challenge the PUCO's decision to mandate that they offer planned energy efficiency resources into PJM's base residual auction. On May 15, 2013, the PUCO granted the applications for rehearing for the sole purpose of further consideration of the matter. On July 17, 2013, the PUCO denied the Ohio Companies' application for rehearing, in part, but authorized the Ohio Companies to receive 20% of any revenues obtained from bidding energy efficiency and demand response 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. On August 16, 2013, ELPC and OCC filed applications for rehearing under the basis that the PUCO's authorization for the Ohio Companies to share in the PJM revenues was unlawful. The PUCO granted rehearing on September 11, 2013 for the sole purpose of further consideration of the issue.
	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. The Ohio Companies' response was filed on November 4, 2013. The motion is still pending and additional briefing has followed. The Ohio Companies filed their merit brief with the Supreme Court of Ohio on February 24, 2014.
	SB221 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 2024. The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet the renewable energy requirements established under SB221. 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 and selected auditors to perform a financial and management audit. Final audit reports filed with the PUCO generally supported the Ohio Companies' approach to procurement of RECs, but also recommended the PUCO examine, for possible disallowance, certain costs associated with the procurement of in-state renewable obligations that the auditor characterized as excessive. Following the hearing, 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 part of the purchases arising from one auction and directing the Ohio Companies to credit non-shopping customers in the amount of $43.3 million, plus interest, and to file tariff schedules reflecting the refund and interest costs within 60 days following the issuance of a final appealable order on the basis that the Ohio Companies did not prove such purchases were prudent. The Ohio Companies, along with other parties, timely filed applications for rehearing on September 6, 2013. On December 18, 2013, the PUCO denied all of the applications for rehearing. Based on the PUCO ruling, a regulatory charge of approximately $51 million, including interest, was recorded in the fourth quarter of 2013 included in Amortization of regulatory assets, net within the Consolidated Statement of Income. On December 24, 2013, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio. On February 10, 2014, the Supreme Court of Ohio granted the Ohio Companies' motion for stay, which went into effect on February 14, 2014. On February 18, 2014, the Office of Consumers' Counsel and the Environmental Law and Policy Center also filed appeals of the PUCO's order.
	In March 2012, the Ohio Companies conducted an RFP process to obtain SRECs to help meet the statutory benchmarks for 2012 and beyond. With the successful completion of this RFP, the Ohio Companies achieved their in-state solar compliance requirements for 2012. The Ohio Companies also held a short-term RFP process to obtain all state SRECs and both in-state and all state non-solar RECs to help meet the statutory benchmarks for 2012. The Ohio Companies recently reported that they met all of their annual renewable energy resource requirements for reporting year 2012. The Ohio Companies conducted an RFP in 2013 to cover their all-state SREC and their in-state and all-state REC compliance obligations.
	The PUCO instituted a statewide investigation on December 12, 2012 to evaluate the vitality of the competitive retail electric service market in Ohio. The PUCO provided interested stakeholders the opportunity to comment on twenty-two questions. The questions posed are categorized as market design and corporate separation. The Ohio Companies timely filed their comments on March 1, 2013, and filed reply comments on April 5, 2013. On June 5, 2013, the PUCO requested additional comments and reply comments on the topics of market design and corporate separation, which the Ohio Companies timely filed on July 8, 2013 and July 22, 2013, respectively. The PUCO held a series of workshops throughout 2013, which included an en banc workshop on December 11, 2013. The PUCO Staff filed a report on January 16, 2014, which contained a limited discussion of the workshops and the PUCO Staff’s recommendations. The Ohio Companies submitted comments on February 6, 2014 and Reply Comments on February 20, 2014.
	PENNSYLVANIA
	The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2015, 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 descending clock auctions, competitive requests for proposals and spot market purchases. On November 4, 2013, the Pennsylvania Companies filed a DSP that will provide the method by which they will procure the supply for their default service obligations for the period of June 1, 2015 through May 31, 2017. The Pennsylvania Companies proposed programs call for quarterly descending clock auctions to procure 3, 12, 24, and 48-month energy contracts, as well as, one RFP seeking 2-year contracts to secure SRECs for ME, PN, and Penn. Hearings on the plans are scheduled to be held March 4-7, 2014. The Pennsylvania Companies expect a decision from the PPUC by August 4, 2014.
	The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directed ME and PN to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC. Pursuant to a plan approved by the PPUC, ME and PN refunded those amounts to customers over a 29-month period that began in January of 2011. On appeal, the Commonwealth Court affirmed the PPUC's Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately $254 million in marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under ME's and PN's TSC riders. The Pennsylvania Supreme Court denied ME's and PN's Petition for Allowance of Appeal and the Supreme Court of the United States denied ME's and PN's Petition for Writ of Certiorari. ME and PN also filed a complaint in the U.S. District Court for the Eastern District of Pennsylvania to obtain an order that would enjoin enforcement of the PPUC and Pennsylvania court orders under a theory of federal preemption on the question of retail rate recovery of the marginal transmission loss charges. On September 30, 2013, the U.S. District Court granted the PPUC’s motion to dismiss. As a result of the U.S. District Court's September 30, 2013 decision, FirstEnergy recorded a regulatory asset impairment charge of approximately $254 million (pre-tax) in the quarter ended September 30, 2013 included in Amortization of regulatory assets, net within the Consolidated Statement of Income. The balance of marginal transmission losses was fully refunded to customers by the second quarter of 2013. On October 29, 2013, ME and PN filed a Notice of Appeal of the U.S. District Court’s decision to dismiss the complaint with the United States Court of Appeals for the Third Circuit. On December 30, 2013, ME and PN filed a brief with the Third Circuit that explained why it was legal error for the U.S. District Court to dismiss the complaint. The PPUC filed its brief on February 3, 2014, and ME and PN filed a reply brief on February 21, 2014. Oral argument has been scheduled for April 9, 2014.
	Pennsylvania adopted Act 129 in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan (EE&C Plan) by July 1, 2009, setting forth the utilities' plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed on utilities that fail to achieve the required reductions in consumption and peak demand. The Pennsylvania Companies submitted a report on November 15, 2011, in which they reported on their compliance with statutory May 31, 2011, energy efficiency benchmarks. ME, PN and Penn achieved the 2011 benchmarks; however WP did not. WP could be subject to a statutory penalty of between $1 and $20 million. On July 15, 2013, the Pennsylvania Companies filed their preliminary energy efficiency and demand reduction results for the period ending May 31, 2013, indicating that all Pennsylvania Companies are expected to meet their statutory obligations. On November 15, 2013, the Pennsylvania Companies submitted their energy efficiency and peak demand reduction report for the period ending May 31, 2013, in which they indicated that all of the Pennsylvania Companies met their statutory requirements.
	Pursuant to Act 129, the PPUC was charged with reviewing the cost effectiveness of energy efficiency and peak demand reduction programs. The PPUC found the energy efficiency programs to be cost effective and in an Order entered on August 3, 2012, the PPUC directed all of the electric utilities in Pennsylvania to submit by November 15, 2012, a Phase II EE&C Plan that would be in effect for the period June 1, 2013 through May 31, 2016. The PPUC has deferred ruling on the need to create peak demand reduction targets until it receives more information from the EE&C statewide evaluator. Based upon information received, the PPUC has not included a peak demand reduction requirement in the Phase II plans. The Pennsylvania Companies filed their Phase II plans and supporting testimony in November 2012. On January 16, 2013, the Pennsylvania Companies reached a settlement with all but one party on all but one issue. The settlement provides for the Pennsylvania Companies to meet with interested parties to discuss ways to expand upon the EE&C programs and incorporate any such enhancements after the plans are approved, provided that these enhancements will not jeopardize the Pennsylvania Companies' compliance with their required targets or exceed the statutory spending caps. On February 6, 2013, the Pennsylvania Companies filed revised Phase II EE&C Plans to conform the plans to the terms of the settlement. Total costs of these plans are expected to be approximately $234 million. All such costs are expected to be recoverable through the Pennsylvania Companies reconcilable Phase II EE&C Plan C riders. The remaining issue, raised by a natural gas company, involved the recommendation that the Pennsylvania Companies include in their plans incentives for natural gas space and water heating appliances. On March 14, 2013, the PPUC approved the 2013-2016 EE&C plans of the Pennsylvania Companies, adopting the settlement, and rejecting the natural gas companies recommendations.
	In addition, Act 129 required utilities to file a SMIP with the PPUC. On December 31, 2012, the Pennsylvania Companies filed their Smart Meter Deployment Plan. The Deployment Plan requests deployment of approximately 98.5% of the smart meters to be installed over the period 2013 to 2019, and the remaining meters in difficult to reach locations to be installed by 2022, with an estimated life cycle cost of about $1.25 billion. Such costs are expected to be recovered through the Pennsylvania Companies' PPUC-approved Riders SMT-C. Evidentiary hearings were held and briefs were submitted by the Pennsylvania Companies and the Office of Consumer Advocate. On November 8, 2013, the ALJ issued a Recommended Decision recommending that the Pennsylvania Companies' Deployment Plan be adopted with certain modifications, including, among other things, that the Pennsylvania Companies perform further benchmarking analyses on their costs and hire an independent consultant to perform further analyses on potential savings. On December 2, 2013, the Pennsylvania Companies submitted exceptions in which they challenged, among other things, certain recommendations in the ALJ’s decision, and requested approval of a modification to the deployment schedule so as to allow the entire Penn smart meter system (170,000 meters) to be built by the end of 2015, instead of the original proposed installation of 60,000 meters by the end of 2016. The Office of Consumer Advocate took exception to one issue and both parties filed replies to exceptions on December 12, 2013. The case is now before the PPUC for consideration.
	A decision is expected during the first quarter of 2014.
	In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania's retail electricity market would be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions concerning retail markets in Pennsylvania to investigate both intermediate and long term plans that could be adopted to further foster the competitive markets, and to explore the future of default service in Pennsylvania following the expiration of the upcoming DSPs on May 31, 2015. A final order was issued on February 15, 2013, providing recommendations on the entities to provide default service, the products to be offered, billing options, customer education, and licensing fees and assessments, among other items. Subsequently, the PPUC established five workgroups and one comment proceeding in order to seek resolution of certain matters and to clarify certain obligations that arose from that order.
	The PPUC issued a Proposed Rulemaking Order on August 25, 2011, which proposed a number of substantial modifications to the current Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electricity market in Pennsylvania. The proposed changes include, but are not limited to: an EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the EDC before using its trademark or service mark. The Proposed Rulemaking Order was published on February 11, 2012, and comments were filed by the Pennsylvania Companies and FES on March 27, 2012. If implemented these rules could require a significant change in the ways FES and the Pennsylvania Companies do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and financial condition. Pennsylvania's Independent Regulatory Review Commission subsequently issued comments on the proposed rulemaking on April 26, 2012, which called for the PPUC to further justify the need for the proposed revisions by citing a lack of evidence demonstrating a need for them. The House Consumer Affairs Committee of the Pennsylvania General Assembly also sent a letter to the Independent Regulatory Review Commission on July 12, 2012, noting its opposition to the proposed regulations as modified.
	WEST VIRGINIA
	MP and PE currently operate under a Joint Stipulation and Agreement of Settlement reached with the other parties and approved by the WVPSC in June 2010 that provided for:
	•	$40 million annualized base rate increases effective June 29, 2010;
	•	Deferral of February 2010 storm restoration expenses over a maximum five-year period;
	•	Additional $20 million annualized base rate increase effective in January 2011;
	•	Decrease of $20 million in ENEC rates effective January 2011, providing for deferral of related costs for later recovery in 2012; and
	•	Moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.
	The WVPSC opened a general investigation into the June 29, 2012, derecho windstorm with data requests for all utilities. A public meeting for presentations on utility responses and restoration efforts was held on October 22, 2012 and two public input hearings have been held. The WVPSC issued an Order in this matter on January 23, 2013 closing the proceeding and directing electric utilities to file a vegetation management plan within six months and to propose a cost recovery mechanism. This Order also requires MP and PE to file a status report regarding improvements to their storm response procedures by the same date. On July 23, 2013, MP and PE filed their vegetation management plans, which provided for recovery of costs through a surcharge mechanism. A hearing was held on December 3, 2013, and briefing followed but the WVPSC has not yet issued an opinion in this matter.
	MP and PE filed their Resource Plan with the WVPSC in August 2012 detailing both supply and demand forecasts and noting a substantial capacity deficiency. MP and PE filed a Petition for approval of a Generation Resource Transaction with the WVPSC in November 2012 that proposed a net ownership transfer of 1,476 MW of coal-fired generation capacity to MP. The proposed transfer involved MP's acquisition of the remaining ownership of the Harrison Power Station from AE Supply and the sale of MP's minority interest in the Pleasants Power Station to AE Supply. FERC authorized the transfers on April 23, 2013 and the financing on May 13, 2013. A Joint Settlement Agreement was filed by the majority of parties on August 21, 2013. On October 7, 2013, the WVPSC authorized the transaction, with certain conditions, and on October 9, 2013, the transaction closed resulting in MP recording a pre-tax impairment charge of approximately $322 million in the fourth quarter of 2013 to reduce the net book value of the Harrison Power Station to the amount that was permitted to be included in jurisdictional rate base. The charge is included in Impairment of long lived assets within the Consolidated Statement of Income. Concurrently, MP recognized a regulatory liability of approximately $23 million 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 transaction resulted in AE Supply receiving net consideration of $1.1 billion and MP's assumption of a $73.5 million pollution control note. The $1.1 billion net consideration was originally financed by MP through an equity infusion from FE of approximately $527 million and a note payable to AE Supply of approximately $573 million. The note payable to AE Supply was paid in the fourth quarter of 2013. In accordance with the settlement, MP and PE will file a base rate case by April 30, 2014. On November 6, 2013, the WVCAG petitioned for appeal with the West Virginia Supreme Court. MP and PE filed their response to the WVCAG petition on December 27, 2013 and WVCAG filed its reply on January 16, 2014. Oral argument before the Supreme Court is scheduled for March 5, 2014.
	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, 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 items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to RFC. Moreover, it is clear that the 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 power system could result in the imposition of financial penalties 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 advocated for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis - each customer in the zone would pay based on its total usage of energy within PJM. On August 6, 2009, the U.S. Court of Appeals for the Seventh Circuit found that FERC had not supported a prior FERC decision to allocate costs for new 500 kV and higher voltage facilities on a load ratio share basis and, based on that finding, remanded the rate design issue to FERC. In an order dated January 21, 2010, FERC set this matter for a “paper hearing” and requested parties to submit written comments. FERC identified nine separate issues for comment and directed PJM to file the first round of comments. PJM filed certain studies with FERC on April 13, 2010, which demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain LSEs in PJM bearing the majority of the costs. FirstEnergy and a number of other utilities, industrial customers and state utility commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Other utilities and state utility commissions supported continued socialization of these costs on a load ratio share basis. On March 30, 2012, FERC issued an order on remand reaffirming its prior decision that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp (or socialized) rate based on the amount of load served in a transmission zone and concluding that such methodology is just and reasonable and not unduly discriminatory or preferential. On April 30, 2012, FirstEnergy requested rehearing of FERC's March 30, 2012 order and on March 22, 2013, FERC denied rehearing. On March 29, 2013, FirstEnergy filed its Petition for Review with the U.S. Court of Appeals for the Seventh Circuit, and the case subsequently was consolidated for briefing and disposition before that court. Briefing is complete, and the case will be scheduled for oral argument, with a decision currently expected in 2014.
	Order No. 1000, issued by FERC on July 21, 2011, required the submission of a compliance filing by PJM or the PJM transmission owners demonstrating that the cost allocation methodology for new transmission projects directed by the PJM Board of Managers satisfied the principles set forth in the order. To demonstrate compliance with the regional cost allocation principles of the order, the PJM transmission owners, including FirstEnergy, submitted a filing to FERC on October 11, 2012, proposing a hybrid method of 50% beneficiary pays and 50% postage stamp to be effective for RTEP projects approved by the PJM Board of Managers on, and after, the effective date of the compliance filing. On January 31, 2013, FERC conditionally accepted the hybrid method to be effective on February 1, 2013, subject to refund and to a future order on PJM's separate Order No. 1000 compliance filing. On March 22, 2013, FERC granted final acceptance of the hybrid method. Certain parties have sought rehearing of parts of FERC's March 22, 2013 order. These requests for rehearing are pending before FERC. On July 10, 2013, the PJM transmission owners, including FirstEnergy, submitted filings to FERC setting forth the cost allocation method for projects that cross the borders between: (1) the PJM region and the NYISO region and; (2) the PJM region and the FERC-jurisdictional members of the SERTP region. These filings propose to allocate the cost of these interregional transmission projects based on the costs of projects that otherwise would have been constructed separately in each region. On the same date, also in response to Order No. 1000, the PJM transmission owners, including FirstEnergy, also submitted to FERC a filing stating that the cost allocation provisions for interregional transmission projects provided in the Joint Operating Agreement between PJM and MISO comply with the requirements of Order No. 1000. On December 30, 2013, FERC conditionally accepted the PJM/SERTP cross-border project cost allocation filing, subject to refund and future orders in PJM's and SERTP's related Order No. 1000 interregional compliance proceedings. The PJM/NYISO and PJM/MISO cross-border project cost allocation filings remain pending before FERC. On January 16, 2014, FERC issued an order regarding the effective date of PJM's separate Order No. 1000 compliance filing, noting that it would address the merits of the comments on and protests to that filing and related compliance filings in a future order.
Numerous parties, including ATSI, FES, TrAIL, OE, CEI, TE, Penn, JCP&L, ME, MP, PN, WP and PE, have sought judicial review of Order No. 1000 before the U.S. Court of Appeals for the D.C. Circuit. Briefing was completed in December 2013 and oral argument is scheduled for March 20, 2014.
The outcome of these proceedings and their impact, if any, on FirstEnergy cannot be predicted at this time.
RTO Realignment
On June 1, 2011, ATSI and the ATSI zone transferred from MISO to PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone. While many of the matters involved with the move have been resolved, FERC denied recovery by means of ATSI's transmission rate for certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation charges totaling approximately $78.8 million until such time as ATSI submits a cost/benefit analysis that demonstrates net benefits to customers from the move. On December 21, 2012, ATSI and other parties filed a proposed settlement agreement with FERC to resolve the exit fee and transmission cost allocation issues. However, FERC subsequently rejected that settlement stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. On October 21, 2013, FirstEnergy filed a request for rehearing of FERC's order.
Separately, the question of ATSI's responsibility of certain costs for the “Michigan Thumb” transmission project continues to be disputed. Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings in front of FERC and certain U.S. appellate courts. The MISO and its allied parties assert that the benefits to the ATSI zone for the Michigan Thumb project are roughly commensurate with the costs that MISO desires to charge to the ATSI zone, estimated to be as much as $16 million per year. ATSI has submitted evidence that the Michigan Thumb project provides no electric benefits to the ATSI zone and, on that basis, opposes the MISO’s efforts to impose these costs to the ATSI zone loads. The MISO and its allied parties also assert that certain language in the MISO Transmission Owners Agreement requires ATSI to pay these charges. In the event of a final non-appealable order that rules that ATSI must pay these charges, ATSI will seek recovery of these charges through its formula rate. While FERC proceedings regarding whether the MISO can charge ATSI for MVP costs remain pending, on February 24, 2014, the U.S. Supreme Court declined to hear appeals filed by FirstEnergy and other parties of the Seventh Circuit's June 2013 decision upholding FERC's acceptance of the MISO's generic MVP cost allocation proposal.
In the May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM could be charged to transmission customers in the ATSI zone. ATSI sought rehearing of the question of whether the ATSI zone should pay these legacy RTEP charges and, on September 20, 2012, FERC denied ATSI's request for rehearing. ATSI subsequently filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit. The case thereafter was briefed and oral arguments took place on December 11, 2013. A decision currently is expected in the second quarter of 2014.
The outcome of those proceedings that address the remaining open issues related to ATSI's move into PJM cannot be predicted at this time.
California Claims Matters
In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the U.S. Court of Appeals for the Ninth Circuit in several pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets, during 2000 and 2001. The Ninth Circuit had previously remanded one of those proceedings to FERC, which dismissed the claims of the California Parties in May 2011, and affirmed the dismissal in June 2012. On June 20, 2012, the California Parties appealed FERC's decision back to the Ninth Circuit. Briefing was completed before the Ninth Circuit on October 23, 2013. The timing of further action by the Ninth Circuit is unknown.
In another proceeding, in June 2009, the California Attorney General, on behalf of certain California parties, filed another complaint with FERC against various sellers, including AE Supply, again seeking refunds for transactions in the California energy markets during 2000 and 2001. The above-noted transactions with CDWR are the basis for including AE Supply in this complaint. AE Supply filed a motion to dismiss, which was granted by FERC in May 2011, and affirmed by FERC in June 2012. The California Attorney General has appealed FERC's dismissal of its complaint to the Ninth Circuit, which has consolidated the case with other pending appeals related to California refund claims, and stayed the proceedings pending further order.
FirstEnergy cannot predict the outcome of either of the above matters or estimate the possible loss or range of loss.
PATH Transmission Project
The PATH project was proposed to be comprised of a 765 kV transmission line from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland. PJM initially authorized construction of the PATH project in June 2007. On August 24, 2012, the PJM Board of Managers canceled the PATH project, which it had suspended in February 2011. As a result, approximately $62 million and approximately $59 million in costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery. On September 28, 2012, those companies requested authorization from FERC to recover the costs with a proposed return on equity of 10.9% (10.4% base plus 0.5% RTO membership) from PJM customers over the next five years. Several parties protested the request. On November 30, 2012, FERC issued an order denying the 0.5% return on equity adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to settlement judge procedures and hearing if the parties do not agree to a settlement. The issues subject to settlement include the prudence of the costs, the base return on equity and the period of recovery. PATH-Allegheny and PATH-WV are currently engaged in settlement discussions with the other parties. Depending on the outcome of a possible settlement or hearing, if settlement is not achieved, PATH-Allegheny and PATH-WV may be required to refund certain amounts that have been collected under their formula rate.
PATH-Allegheny and PATH-WV have requested rehearing of FERC's denial of the 0.5% return on equity adder for RTO membership; that request for rehearing remains pending before FERC. In addition, FERC has consolidated for settlement judge procedures and hearing purposes three formal challenges to the PATH formula rate annual updates submitted to FERC in June 2010, June 2011 and June 2012, with the September 28, 2012 filing for recovery of costs associated with the cancellation of the PATH project.
Hydroelectric Asset Sale
On September 4, 2013, certain of FirstEnergy’s subsidiaries submitted filings with FERC for authorization to sell eleven hydroelectric power plant projects to subsidiaries of Harbor Hydro Holdings, LLC (Harbor Hydro), a subsidiary of LS Power Equity Partners II, LP (LS Power). The eleven hydroelectric projects are: the Seneca Pumped Storage Project, Allegheny Lock & Dam No. 5, Allegheny Lock & Dam No. 6, the Lake Lynn Project, the Millville Hydro Project, the Dam No. 4 Project, the Dam No. 5 Project, and four additional projects located in Shenandoah, Front Royal and Luray, Virginia. The eleven projects have a combined generating capacity of approximately 527 MW. On February 12, 2014, the sale of the hydroelectric power plants to LS Power closed for approximately $395 million. See Note 20, Discontinued Operations and Assets Held for Sale for additional information regarding the assets sold.
MISO Capacity Portability
On June 11, 2012, FERC issued a Notice of Request for Comments regarding whether existing rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM. FERC is responding to suggestions from MISO and the MISO stakeholders that PJM's rules regarding the criteria and qualifications for external generation capacity resources be changed to ease participation by resources that are located in MISO in PJM's RPM capacity auctions. FirstEnergy submitted comments and reply comments in August 2012. In the fall of 2012, FirstEnergy participated in certain stakeholder meetings to review various proposals advanced by MISO. Although none of MISO's proposals attracted significant stakeholder support, in January 2013, MISO filed a pleading with FERC that renewed many of the arguments advanced in prior MISO filings and asked FERC to take expedited action to address MISO's allegations. FirstEnergy and other parties subsequently submitted filings arguing that MISO's concerns largely are without foundation and suggesting that FERC order that the remaining concerns be addressed in the existing stakeholder process that is described in the PJM/MISO Joint Operating Agreement. On April 2, 2013, FERC issued an order directing MISO and PJM to make presentations to FERC regarding ongoing regional efforts to address whether barriers to transfer capability exist between the MISO and PJM regions and the actions the FERC should take to address any such barriers. The RTOs presented their respective positions to FERC on June 20, 2013 and provided additional information regarding their stakeholder prioritization survey, in response to a FERC request on June 27, 2013. On September 26, 2013, the RTOs jointly submitted an informational filing providing a description of and schedule for their Joint and Common Market initiatives. On December 19, 2013, FERC issued an order directing that FERC staff are to attend the “joint and common market” stakeholder meetings for the purpose of monitoring progress on the initiatives described in the September 26, 2013 joint informational filing and establishing a new proceeding to reflect the broadened scope of issues contemplated by that filing and the RTOs' joint and common market initiatives. FERC has not acted on the presentations, and the RTOs and affected parties are working to address the MISO's proposal in stakeholder proceedings. Changes to the criteria and qualifications for participation in the PJM RPM capacity auctions could have a significant impact on the outcome of those auctions, including a negative impact on the prices at which those auctions would clear.
MOPR Reform
On December 7, 2012, PJM filed amendments to its tariff to revise the MOPR used in the RPM. PJM revised the MOPR to add two broad, categorical exemptions, eliminate an existing exemption, and to limit the applicability of the MOPR to certain capacity resources. The filing also included related and conforming changes to the RPM posting requirements and to those provisions describing the role of the Independent Market Monitor for the PJM Region. On May 2, 2013, FERC issued an order in large part accepting PJM's proposed reform of the MOPR, including the proposed exemptions and applicability but also requiring PJM to commit to future review and, if necessary, additional revisions to the MOPR to accommodate changing market conditions. On June 3, 2013, FirstEnergy submitted a request for rehearing of FERC's May 2, 2013 order. In its rehearing request, FirstEnergy referenced the results of the May 2013 PJM RPM capacity auction, and publicly-available data about the reasons for the unexpectedly low "rest-of-RTO" clearing price of $59 per MW-day, as supporting its contention that the MOPR reform depressed prices as predicted in FirstEnergy's December 28, 2012 and January 25, 2013 comments. FirstEnergy's request for rehearing is pending before FERC.
FTR Underfunding Complaint
In PJM, FTRs are a mechanism to hedge congestion and they operate as a financial replacement for physical firm transmission service. FTRs are financially-settled instruments that entitle the holder to a stream of revenues based on the hourly congestion price differences across a specific transmission path in the PJM Day-ahead Energy Market. FE also performs bilateral transactions for the purpose of hedging the price differences between the location of supply resources and retail load obligations. Due to certain language in the PJM tariff, the funds that are set aside to pay FTRs can be diverted to other uses, resulting in “underfunding” of FTR payments. Since June of 2010, FES and AE Supply have lost more than $65.5 million in revenues that they otherwise would have received as FTR holders to hedge congestion costs. FES and AE Supply expect to continue to experience significant underfunding.
On December 28, 2011, FES and AE Supply filed a complaint with FERC for the purpose of modifying certain provisions in the PJM tariff to eliminate FTR underfunding. On March 2, 2012, FERC issued an order dismissing the complaint. In its order, FERC ruled that it was not appropriate to initiate action at that time because of the unknown root causes of FTR underfunding. FERC directed PJM to convene stakeholder proceedings for the purpose of determining the root causes of the FTR underfunding. FERC went on to note that its dismissal of the complaint was without prejudice to FES and AE Supply or any other affected entity filing a complaint if the stakeholder proceedings proved unavailing. FES and AE Supply sought rehearing of FERC's order and, on July 19, 2012, FERC denied rehearing. In April, 2012, PJM issued a report on FTR underfunding. However, the PJM stakeholder process proved unavailing as the stakeholders were not willing to change the tariff to eliminate FTR underfunding. Accordingly, on February 15, 2013, FES and AE Supply refiled their complaint with FERC for the purpose of changing the PJM tariff to eliminate FTR underfunding. Various parties filed responsive pleadings, including PJM. On June 5, 2013, FERC issued its order denying the new complaint. On July 5, 2013, FirstEnergy filed a request for rehearing of FERC's order. FES and AE Supply's request for rehearing, and all subsequent filings in the docket, are pending before FERC.
PJM RPM Tariff Amendments
In November 2013, PJM began to submit a series of amendments to its RPM capacity tariff in order to address certain problems that have been observed in recent auctions. These problems can be grouped into three categories: (i) Demand Response (DR); (ii) imports; and (iii) modeling of transmission upgrades in calculating geographic clearing prices. The purpose of PJM’s tariff amendments is to ensure that resources that clear in the RPM auctions are available and able to satisfy all obligations under the PJM tariffs. In each of the affected dockets, FirstEnergy submitted comments as part of a coalition of utilities (generally including an affiliate of AEP, Duke and Dayton). The FirstEnergy/coalition position was that all of the PJM proposals should be accepted as proposed, and that the FERC should order PJM to take additional steps that should have the effect of eliminating additional distortions and flaws in the RPM market. FERC issued deficiency letters requesting additional information from PJM regarding the imports and modeling filings, and on January 30, 2014 accepted the DR filing as proposed. On February 18 and 21, 2014, respectively, PJM filed its responses to FERC's deficiency letters regarding the modeling and imports filings. PJM's compliance filings and all other filings in the dockets are pending before FERC.
Market-Based Rate Authority, Triennial Update
OE, CEI, TE, Penn, JCP&L, ME, PN, MP, WP, PE, AE Supply, FES, FG, NG, FirstEnergy Generation Mansfield Unit 1 Corp., Buchanan Generation, LLC, and Green Valley Hydro, LLC each hold authority from FERC to sell electricity at market-based rates. One condition for retaining this authority is that every three years each entity must file an update with the FERC that demonstrates that each entity continues to meet FERC’s requirements for holding market-based rate authority. On December 20, 2013, FESC submitted to FERC the most recent triennial market power analysis filing for each market-based rate holder for the current cycle of this filing requirement. That filing is pending before FERC.

Commitments_Guarantees_and_Con

Commitments, Guarantees and Contingencies	12 Months Ended
	Dec. 31, 2013
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 $13.6 billion (assuming 104 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $375 million; and (ii) $13.2 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 (OE-$44 million, NG-$442 million, and TE-$23 million) per incident but not more than $76 million (OE-$7 million, NG-$66 million, and TE-$3 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 yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $2 billion (OE-$168 million, NG-$1.7 billion, TE-$90 million) 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 $14 million (OE-$1.2 million, NG-$12 million and TE-$0.6 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 $79 million (OE-$7 million, NG-$68 million, TE-$3 million and ME-$1 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, 2013, outstanding guarantees and other assurances aggregated approximately $4.3 billion, consisting of parental guarantees ($1,375 million), subsidiaries' guarantees ($2,197 million) and other guarantees ($742 million).
	Of this amount, substantially all relates to guarantees of wholly-owned consolidated entities. 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, 2013, FES has posted collateral of $142 million and AE supply has posted collateral of $8 million. The Regulated Distribution segment has posted collateral of $11 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, 2013:
	Collateral Provisions	FES		AE Supply		Utilities		Total
		(In millions)
	Split Rating (One rating agency's rating below investment grade)	$	496	$	6	$	53	$	555
	BB+/Ba1 Credit Ratings	$	542	$	6	$	53	$	601
	Full impact of credit contingent contractual obligations	$	777	$	58	$	88	$	923
	Excluded from the preceding chart are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and Competitive Energy Services segment. As of December 31, 2013, 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 and AE Supply would be required to post $66 million and $2 million, respectively.
	OTHER COMMITMENTS AND CONTINGENCIES
	FirstEnergy is a guarantor under a syndicated three-year senior secured term loan facility due October 18, 2015, under which Global Holding borrowed $350 million. Proceeds from the loan were used to repay Signal Peak's and Global Rail's maturing $350 million syndicated two-year senior secured term loan facility. 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 new facility.
	In connection with the current facility, 69.99% of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral.
	FirstEnergy, FEV and the other two co-owners of Global Holding, Pinesdale LLC, a Gunvor Group, Ltd. subsidiary, and WMB Marketing Ventures, LLC, have agreed to use their best efforts to refinance the new facility no later than July 20, 2015, which reflects the terms of an amendment dated August 14, 2013, on a non-recourse basis so that FirstEnergy's guaranty can be terminated and/or released. If that refinancing does not occur, FirstEnergy may require each co-owner to lend to Global Holding, on a pro rata basis, funds sufficient to prepay the new facility in full. In lieu of providing such funding, the co-owners, at FirstEnergy's option, may provide their several guaranties of Global Holding's obligations under the facility. FirstEnergy receives a fee for providing its guaranty, payable semiannually, which accrued at a rate of 4% through December 31, 2012, and accrues at a rate of 5% from January 1, 2013 through October 18, 2015, which amends the rate in the prior agreement, in each case based upon the average daily outstanding aggregate commitments under the facility for such semiannual period.
	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.
	CAA Compliance
	FirstEnergy is required to meet federally-approved SO2 and NOx emissions regulations under the CAA. FirstEnergy complies with SO2 and NOx 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.
	In July 2008, three complaints representing multiple plaintiffs were filed against FG in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant. Two of these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner.” One complaint was filed on behalf of twenty-one individuals and the other is a class action complaint seeking certification as a class with the eight named plaintiffs as the class representatives. FG believes the claims are without merit and intends to vigorously defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
	In January 2009, the EPA issued an NOV to GenOn Energy, Inc. alleging NSR violations at the Keystone, Portland and Shawville coal-fired plants based on “modifications” dating back to the mid-1980s. JCP&L, as the former owner of 16.67% of the Keystone Station, ME, as a former owner and operator of the Portland Station, and PN as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter or estimate the possible loss or range of loss.
	In January 2011, the U.S. DOJ filed a complaint against PN in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against PN based on alleged “modifications” at the coal-fired Homer City generating plant during 1991 to 1994 without pre-construction NSR permitting in violation of the CAA's PSD and Title V permitting programs. The complaint was also filed against the former co-owner, NYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In addition, the Commonwealth of Pennsylvania and the states of New Jersey and New York intervened and filed separate complaints regarding Homer City seeking injunctive relief and civil penalties. In October 2011, the Court dismissed all of the claims with prejudice of the U.S. DOJ and the Commonwealth of Pennsylvania and the states of New Jersey and New York against all of the defendants, including PN. In December 2011, the U.S., the Commonwealth of Pennsylvania and the states of New Jersey and New York all filed notices appealing to the Third Circuit Court of Appeals which affirmed the dismissal on August 21, 2013 and then denied petitions for rehearing on December 12, 2013. PN believes the claims are without merit and intends to vigorously defend itself against the allegations made in these complaints. The parties dispute the scope of NYSEG's and PN's indemnity obligation to and from Edison International. PN is unable to predict the outcome of this matter or estimate the loss or possible range of loss.
	In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the PSD, NNSR and Title V regulations, at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. The EPA's NOV alleges equipment replacements during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically, opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. FG intends to comply with the CAA and Ohio regulations, but, at this time, is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
	In August 2000, AE received an information request pursuant to section 114(a) of the CAA from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten coal-fired plants, which collectively include 22 electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the NSR provisions under the CAA, which can require the installation of additional air emission control equipment when a major modification of an existing facility results in an increase in emissions. 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. On June 29, 2012, January 31, 2013, and March 27, 2013, EPA issued additional 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. AE intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
	In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply and the Allegheny Utilities in the U.S. District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the NSR provisions of the CAA and the Pennsylvania Air Pollution Control Act at the coal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. A non-jury trial on liability only was held in September 2010. On February 6, 2014, the Court entered judgment for AE, AE Supply, and the Allegheny Utilities finding they had not violated the CAA or the Pennsylvania Air Pollution Control Act. This decision does not change the status of these plants which remain deactivated.
	National Ambient Air Quality Standards
	The EPA's CAIR requires reductions of NOx and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the D.C. Circuit decided that CAIR violated the CAA but allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court's decision. In July 2011, the EPA finalized CSAPR, to replace CAIR, requiring reductions of NOx and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. On December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the D.C. Circuit and was ultimately vacated by the Court on August 21, 2012. The Court has ordered the EPA to continue administration of CAIR until it finalizes a valid replacement for CAIR. On January 24, 2013, EPA and intervenors' petitions seeking rehearing or rehearing en banc were denied by the U.S. Court of Appeals for the D.C. Circuit. On June 24, 2013, the Supreme Court of the United States agreed to review the decision vacating CSAPR and heard oral argument on December 10, 2013. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, the future cost of compliance may be substantial and changes to FirstEnergy's and FES' operations may result.
	Hazardous Air Pollutant Emissions
	On December 21, 2011, the EPA finalized the MATS imposing emission limits for mercury, PM, and HCL for all existing and new coal-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 stations. 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 stations. 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. MATS has been challenged in the U.S. Court of Appeals for the D.C. Circuit by various entities, including FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers, such as Bay Shore Unit 1. Oral arguments were heard on December 10, 2013. Depending on the outcome of these proceedings and how the MATS are ultimately implemented, FirstEnergy's total cost of compliance with MATS is currently estimated to be approximately $465 million (Competitive Energy Services segment of $240 million and Regulated Distribution segment of $225 million).
	As of September 1, 2012, Albright, Armstrong, Bay Shore Units 2-4, Eastlake Units 4-5, R. Paul Smith, Rivesville and Willow Island were deactivated. FG entered into RMR arrangements with PJM for Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 through the spring of 2015, when they are scheduled to be deactivated. In February 2014, PJM notified FG that Eastlake Units 1-3 and Lake Shore Unit 18 will be released from RMR status as of September 15, 2014. As of October 9, 2013, the Hatfield's Ferry and Mitchell stations were also deactivated.
	FirstEnergy and FES have various long-term coal transportation agreements, some of which run through 2025 and certain of which are related to the plants described above. FE and FES have asserted force majeure defenses for delivery shortfalls under certain agreements, and are in discussion with the applicable counterparties. As to two agreements, FE and FES have settled monetary claims for damages for the failure to take minimum quantities for the calendar year 2012 by the payments of approximately $70 million, and agreed to pay liquidated damages for delivery shortfalls for 2013 and 2014. FE and FES recorded $67 million in liquidated damages in the fourth quarter of 2013, associated with estimated 2013 delivery shortfalls, which were paid in the first quarter of 2014. Additionally, in January 2014, FE and FES reached an agreement in principle with Mepco Holdings LLC to terminate a contract for future coal deliveries to Hatfield for $18 million, which was approved by the United States Bankruptcy Court on February 26, 2014. If FE and FES fail to reach a resolution with applicable counterparties for coal transportation agreements associated with the deactivated plants or unresolved aspects of the transportation agreements and it were ultimately determined that, contrary to their belief, the force majeure provisions or other defenses do not excuse delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.
	Climate Change
	There are a number of initiatives to reduce GHG emissions under consideration at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs to control emissions of certain GHGs. In his 2013 State of the Union address, President Obama called for Congressional action on GHG emissions indicating his administration will take action in the event Congress fails to act. In June 2013, the President's Climate Action Plan outlined Executive action to: (1) cut carbon pollution in America, including the EPA carbon pollution standards for both new and existing power plants by 17% by 2020 (from 2005 levels); (2) prepare the United States for the impacts of climate change; and (3) lead international efforts to combat global climate change and prepare for its impacts.
	In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required the measurement and reporting of GHG emissions commencing in 2010. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA's finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when NSR pre-construction permits would be required including an emissions applicability threshold of 75,000 tons per year of CO2 equivalents for existing facilities under the CAA's PSD program. On April 13, 2012, the EPA proposed new source performance standards for GHG emissions from newly constructed fossil fuel generating units that are larger than 25 MW, which were ultimately withdrawn. On June 25, 2013, a Presidential memorandum directed the EPA to complete, in a timely fashion, proposed new source performance standards for GHG emissions from newly constructed fossil fuel generating units, starting with re-proposal by September 20, 2013. The memorandum further directed the EPA to propose by June 1, 2014 and complete by June 1, 2015, GHG emission standards for existing fossil fuel generating units. On September 20, 2013, the EPA proposed a new source performance standard of 1,000 lbs. CO2/MWH for large natural gas fired units (> 850 mmBTU/hr), and 1,100 lbs. CO2/MWH for other natural gas fired units (≤ 850 mmBTU/hr), and 1,100 lbs. CO2/MWH for fossil fuel fired units which would require partial carbon capture and storage. On October 15, 2013, the U.S. Supreme Court agreed to review a June 2012 D.C. Circuit Court of Appeals decision upholding the EPA's May 2010 regulations to decide a single narrow question: "Whether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the CAA for stationary sources that emit greenhouse gases?" Oral argument was held on February 24, 2014. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, the future cost of compliance may be substantial and changes to FirstEnergy's and FES' operations may result.
	At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement that recognized the scientific view that the increase in global temperature should be below two degrees Celsius; includes a commitment by developed countries to provide funds, approaching $30 billion over three years with a goal of increasing to $100 billion by 2020; and establishes the “Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets by 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification. In December 2010, the U.N. Climate Change Conference in Cancun, Mexico resulted in an acknowledgment to reduce emissions from industrialized countries by 25 to 40 percent from 1990 emissions by 2020 and support enhanced action on climate change in the developing world. In December 2011 the U.N. Climate Change Conference in Durban, South Africa, established a negotiating process to develop a new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to undertake legally binding commitments post-2020. In addition, certain countries agreed to extend the Kyoto Protocol for a second commitment period, commencing in 2013 and expiring in 2018 or 2020. In December 2012, the U.N. Climate Change Conference in Doha, Qatar, resulted in countries agreeing to a new commitment period under the Kyoto Protocol beginning in 2020. The new Doha Amendment to establish a second commitment period requires the ratification of three-quarters of the parties to the Kyoto Protocol before it becomes effective.
	FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 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-CO2 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.
	In 2004, the EPA established new performance standards under Section 316(b) of the CWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). In 2007, the U.S. Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit's opinion and decided that Section 316(b) of the CWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the CWA to reduce fish impingement to a 12% annual average and determine site-specific controls, if any, to reduce entrainment of aquatic life following studies to be provided to permitting authorities. The period for finalizing the Section 316(b) regulation was extended to April 17, 2014 under a Settlement Agreement between EPA and certain NGOs. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant's water intake channel to divert fish away from the plant's water intake system. Depending on the results of such studies and the EPA's further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
	On April 19, 2013, the EPA proposed regulatory changes to the waste water effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423). The EPA proposed eight treatment options for waste water discharges from electric power plants, of which four are "preferred" by the Agency. The preferred options range from more stringent chemical and biological treatment requirements to zero discharge requirements. The EPA is required to finalize this rulemaking by May 22, 2014, under a consent decree entered by a U.S. District Court and the treatment obligations are proposed to phase-in as waste water discharge permits are renewed on a 5-year cycle from 2017 to 2022. Depending on the content of the EPA's final rule, the future costs of compliance with these standards may require material capital expenditures.
	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 these appeals or estimate the possible loss or range of loss.
	In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP's recommended sulfate impairment designation which requires the development of a TMDL limit for the river, a process that will take PA DEP approximately five years. Based on the stringency of the TMDL, MP may incur significant costs to reduce sulfate discharges into the Monongahela River if the NPDES permit for the coal-fired Fort Martin plant in West Virginia is required to be modified or renewed to include more stringent effluent limitations for sulfate. However, the Hatfield's Ferry and Mitchell Plants in Pennsylvania that discharge into the Monongahela River were deactivated on October 9, 2013.
	FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.
	Regulation of Waste Disposal
	Federal and state hazardous waste regulations have been promulgated as a result of the RCRA of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel 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 2009, in an advance notice of public rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA's hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. On April 19, 2013, the EPA stated it would "align" its proposed coal combustion residuals regulations with revised waste water discharge effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423) that were proposed on that date. On July 25, 2013, the House of Representatives passed H.R. 221 that would require CCRs to be regulated under Subtitle D of RCRA, as non-hazardous. On January 29, 2014, EPA agreed to take final action by December 19, 2014 on whether or not to pursue the proposed non-hazardous waste option for regulating CCRs in a Consent Decree to be filed in pending litigation. Depending on the content of the EPA's final effluent limitations rule, the specifics of any "alignment", whether EPA chooses to pursue the non-hazardous or hazardous waste option and the enactment of legislation, the future costs of compliance with such standards may require material capital expenditures.
	On July 27, 2012, the PA DEP filed a complaint against FG in the U.S. District Court for the Western District of Pennsylvania with claims under the RCRA and Pennsylvania's Solid Waste Management Act regarding the LBR CCB Impoundment and simultaneously proposed a Consent Decree between PA DEP and FG to resolve those claims. On December 14, 2012, a modified Consent Decree that addresses public comments received by PA DEP was entered by the court, requiring FG to conduct monitoring studies and submit a closure plan to the PA DEP, no later than March 31, 2013, and discontinue disposal to LBR as currently permitted by December 31, 2016. The modified Consent Decree also requires payment of civil penalties of $800,000 to resolve claims under the Solid Waste Management Act. On February 1, 2013, FG submitted a Feasibility Study analyzing various technical issues relevant to the closure of LBR. On March 28, 2013, FG submitted to the PA DEP a Closure Plan Major Permit Modification Application which provides for placing a final cap over LBR that would require 15 years to fully implement following the closure of LBR. The estimated cost for the proposed closure plan is $234 million, including environmental and other post closure costs. On October 3, 2013, the PA DEP issued a technical deficiency letter citing four main deficiencies with the Closure Plan: (1) seeking to accelerate the 15 year period proposed by FG for closure activities to complete closure in 9 years by commencing closure activities prior to 2017 as proposed by FG; (2) seeking to extend bond closure and post closure activities beyond the 45 years proposed by FG; (3) seeking active dewatering of the CCBs in areas where there are seeps impacted by the Impoundment; and (4) seeking an abatement plan for groundwater impacted by arsenic. FG responded to the PA DEP on December 3, 2013, and as a result of the Closure Plan, FG increased its asset retirement obligation for LBR by $163 million in 2013. The Bruce Mansfield Plant is pursuing several options for its CCBs following December 31, 2016, and on January 23, 2013, announced a plan for beneficial use of its CCBs for mine reclamation in LaBelle, Pennsylvania. In June 2013, a complaint filed in the U.S. District Court for the Western District of Pennsylvania, alleges the LaBelle site is in violation of RCRA and state laws. In addition, on December 20, 2012, the Environmental Integrity Project and others served FG with a citizen suit notice alleging CWA and PA Clean Streams Law Violations at LBR.
	On October 10, 2013 and December 5, 2013, complaints were filed on behalf of approximately 50 individuals against FE, FG and FES in the U.S. District Court for the Northern District of West Virginia and approximately 15 individuals against FG in the U.S. District Court for the Western District of Pennsylvania seeking damages for alleged property damage, bodily injury and emotional distress related to the LBR CCB Impoundment. The complaints state claims for private nuisance, negligence, negligence per se, reckless conduct and trespass related to alleged groundwater contamination and odors emanating from the Impoundment. FE, FG and FES believe the claims are without merit and intend to vigorously defend themselves against the allegations made in the complaints, but, at this time, are unable to predict the outcome of the above matter or estimate the possible loss or range of loss.
	FirstEnergy's future cost of compliance with any coal combustion residuals regulations that may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition.
	Certain of FirstEnergy's utilities 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 Sheet as of December 31, 2013 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 $128 million have been accrued through December 31, 2013. Included in the total are accrued liabilities of approximately $82 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 possible losses 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, 2013, FirstEnergy had approximately $2.2 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 NDT 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 NDT. FE maintains a $125 million parental guaranty relating to a potential shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry. FE also maintains an $11 million parental guaranty in support of the decommissioning of the spent fuel storage facilities located at its Davis-Besse and Perry nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guaranty, as appropriate.
On October 4, 2013, during a refueling outage for Beaver Valley Unit 1, FENOC conducted a planned visual examination of the interior containment liner and coatings. The containment design for Beaver Valley includes an interior steel liner that is surrounded by reinforced concrete. A penetration through the containment steel liner plate of approximately 0.4 inches by 0.28 inches was discovered. A detailed investigation was initiated, including laboratory analysis that has indicated that the degraded area was initiated by foreign material inadvertently left in the concrete during construction. An assessment has been performed which concluded that any postulated leakage through the affected area was within overall allowable limits for the containment building. The structural integrity of the containment building is not affected. Repair of the containment liner was completed and Unit 1 was returned to service on November 4, 2013.
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. An NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. On July 9, 2012, the petitioners' proposed a contention on the environmental impacts of spent fuel storage in the Davis-Besse license renewal proceeding. In an order dated August 7, 2012, the NRC stated that it will not issue final licensing decisions until it has appropriately addressed the challenges to the NRC Waste Confidence Decision and Temporary Storage Rule and all pending contentions on this topic should be held in abeyance. The ASLB has suspended further consideration of the petitioners' proposed contention on the environmental impacts of spent fuel storage at Davis-Besse. The NRC Staff issued Waste Confidence Draft Generic Environmental Impact Statement and published a proposed rule on this subject in September of 2013. Other contentions proposed by the petitioners in this proceeding have been rejected by the ASLB. On February 18, 2014, Beyond Nuclear and Don't Waste Michigan, two of the petitioners in the Davis-Besse license renewal proceeding, requested that the NRC institute a rulemaking on the environmental impacts of high density spent fuel storage and mitigation alternatives. On February 27, 2014, these petitioners requested a suspension of the licensing decision in the Davis-Besse license renewal proceeding to allow the NRC to complete this rulemaking.
As part of routine inspections of the concrete shield building at Davis-Besse Nuclear Power Station in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. The shield building is a 2 1/2-foot thick reinforced concrete structure that provides biological shielding, protection from natural phenomena including wind and tornadoes and additional shielding in the event of an accident. FENOC then expanded its sample size to include all of the existing core bores in the shield building. These inspections, which are now complete, identified additional subsurface cracking that was determined to be pre-existing, but only now identified with the aid of improved inspection technology. These inspections also revealed that the cracking condition has propagated a small amount in select areas. Preliminary analysis of the inspections results confirm that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions.
On February 1, 2014, the Davis-Besse Nuclear Power Station entered into an outage to install two new steam generators, replace about a third of the unit’s 177 fuel assemblies and perform numerous safety inspections and preventative maintenance activities. During the preliminary stages of the outage an area of concrete that was not filled to the expected thickness within the shield building wall was discovered at the top of the temporary construction opening that was created as part of the 2011 outage. The 2011 temporary construction opening was created to install the new reactor head. FENOC has assessed the as-found condition of the concrete and has determined the shield building would have performed its design functions. This condition within the shield building wall will be repaired during this outage to conform to its original design configuration. This condition is not expected to extend the outage.
On March 12, 2012, the NRC issued orders requiring safety enhancements at U.S. reactors based on recommendations from the lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders require additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in spent fuel pools. The NRC also requested that licensees including FENOC: re-analyze earthquake and flooding risks using the latest information available; conduct earthquake and flooding hazard walkdowns at their nuclear plants; assess the ability of current communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power; and assess plant staffing levels needed to fill emergency positions. These and other NRC requirements adopted as a result of the accident at Fukushima Daiichi are likely to result in additional material costs from plant modifications and upgrades at FENOC's nuclear facilities.
ICG Litigation
On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against ICG, Anker WV, and Anker Coal. Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants' past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of $80 million in damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of $150 million for future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for $104 million ($90 million in future damages and $14 million for replacement coal/interest). On August 25, 2011, the Allegheny County Court denied all Motions for Post-Trial relief and the May 2, 2011 verdict became final. On August 26, 2011, the defendants posted bond and filed a Notice of Appeal with the Superior Court. On August 13, 2012, the Superior Court affirmed the $14 million past damages award but vacated the $90 million future damages award. While the Superior Court found that the defendants still owed future damages, it remanded the calculation of those damages back to the trial court. The specific amount of those future damages is not known at this time, but they are expected to be calculated at a market price of coal that is significantly lower than the price used by the trial court. On August 27, 2012, AE Supply and MP filed an Application for Reargument En Banc with the Superior Court, which was denied on October 19, 2012. AE Supply and MP filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court on November 19, 2012. On July 2, 2013, the Petition for Allowance of Appeal was denied and in the second quarter of 2013 the now final past damage award of $15.5 million (including interest) was recognized. The case was sent back to the trial court to recalculate the future damages only and is currently in the discovery phase. A hearing is scheduled for May 13-14, 2014.
Other Legal Matters
In 2010, a lawsuit was filed in Allegheny County Court of Common Pleas by Michael Goretzka, for wrongful death and negligence after his wife was fatally electrocuted when she contacted a downed power line. The trial resulted in a verdict against WP and the parties settled this matter. WP's portion of the settlement was covered by insurance subject to the remainder of its deductible. On May 30, 2012, the PPUC's Bureau of Investigation and Enforcement (I&E) filed a Formal Complaint at the PPUC regarding this matter. On February 13, 2013, WP and I&E filed a Joint Petition for Full Settlement that includes, among other things, WP's agreement to conduct an infrared inspection of its primary distribution system, modify certain training programs, and pay an $86,000 civil penalty, which settlement is subject to PPUC approval. On August 29, 2013, the PPUC entered an Order granting the Goretzka family limited party status for the sole purpose of submitting comments to the settlement and issuing the settlement for comment by the parties. On September 16, 2013, the Goretzka family filed Limited Objections to the settlement. Reply comments were filed by WP on September 30, 2013. The PPUC entered an Opinion and Order on January 9, 2014 approving the Settlement with limited modifications regarding the frequency of refresher training and reporting obligations. WP filed a letter on January 17, 2014 accepting those modifications and noting its intent to begin implementation of the settlement terms.
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The loss or range of loss in these matters is not expected to be material to FirstEnergy or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 15, Regulatory Matters of the Combined Notes to Consolidated Financial Statements.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Transactions_With_Affiliated_C

Transactions With Affiliated Companies	12 Months Ended
	Dec. 31, 2013
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, 2013 are as follows:
	FES	2013		2012		2011
		(In millions)
	Revenues:
	Electric sales to affiliates	$	652	$	515	$	752
	Other	6		16		80
	Expenses:
	Purchased power from affiliates	486		451		242
	Fuel	—		2		37
	Support services	619		570		655
	Investment Income:
	Interest income from FE	2		2		2
	Interest Expense:
	Interest expense to affiliates	4		10		8
	Interest expense to FE	6		1		1
	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, AESC 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, AESC 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_Informa

Supplemental Guarantor Information	12 Months Ended
	Dec. 31, 2013
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, 2013, 2012, and 2011, Condensed Consolidating Balance Sheets as of December 31, 2013 and December 31, 2012, and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2013, 2012, and 2011, for FES (parent and guarantor), FG and NG (non-guarantor) are presented below. 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 (LOSS) AND COMPREHENSIVE INCOME (LOSS)
	(Unaudited)
	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
	Pensions and OPEB mark-to-market adjustments	(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	5			1			25			(15		)	16
	Miscellaneous income, including net income from equity investees	846			24			—			(842		)	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	(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:
	Pensions 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 STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
	(Unaudited)
	For the Year Ended December 31, 2012	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	STATEMENTS OF INCOME
	REVENUES	$	5,804		$	2,100		$	1,895		$	(3,905	)	$	5,894
	OPERATING EXPENSES:
	Fuel	—			1,077			210			—			1,287
	Purchased power from affiliates	4,098			—			258			(3,905		)	451
	Purchased power from non-affiliates	1,881			6			—			—			1,887
	Other operating expenses	434			334			539			49			1,356
	Pensions and OPEB mark-to-market adjustments	(2		)	52			116			—			166
	Provision for depreciation	4			116			157			(5		)	272
	General taxes	79			36			21			—			136
	Total operating expenses	6,494			1,621			1,301			(3,861		)	5,555
	OPERATING INCOME (LOSS)	(690		)	479			594			(44		)	339
	OTHER INCOME (EXPENSE):
	Investment income	2			15			67			(18		)	66
	Miscellaneous income, including net income from equity investees	1,284			20			—			(1,269		)	35
Interest expense — affiliates	(18		)	(7		)	(4		)	19			(10		)
Interest expense — other	(93		)	(110		)	(50		)	62			(191		)
Capitalized interest	—			4			33			—			37
Total other income (expense)	1,175			(78		)	46			(1,206		)	(63		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	485			401			640			(1,250		)	276
INCOME TAXES (BENEFITS)	298			(269		)	62			12			103
INCOME FROM CONTINUING OPERATIONS	187			670			578			(1,262		)	173
Discontinued operations (net of income taxes of $8)	—			14			—			—			14
NET INCOME	$	187		$	684		$	578		$	(1,262	)	$	187
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	187		$	684		$	578		$	(1,262	)	$	187
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	6			6			—			(6		)	6
Amortized gain on derivative hedges	(9		)	—			—			—			(9		)
Change in unrealized gain on available-for-sale securities	(5		)	—			(5		)	5			(5		)
Other comprehensive income (loss)	(8		)	6			(5		)	(1		)	(8		)
Income taxes (benefits) on other comprehensive income (loss)	(4		)	1			(2		)	1			(4		)
Other comprehensive income (loss), net of tax	(4		)	5			(3		)	(2		)	(4		)
COMPREHENSIVE INCOME	$	183		$	689		$	575		$	(1,264	)	$	183
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)
For the Year Ended December 31, 2011	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	5,387		$	2,642		$	1,647		$	(4,223	)	$	5,453
OPERATING EXPENSES:
Fuel	12			1,138			194			—			1,344
Purchased power from affiliates	4,208			5			252			(4,223		)	242
Purchased power from non-affiliates	1,378			3			—			—			1,381
Other operating expenses	574			416			578			51			1,619
Pensions and OPEB mark-to-market adjustments	10			68			93			—			171
Provision for depreciation	4			124			150			(6		)	272
General taxes	64			37			23			—			124
Impairment of long-lived assets	—			294			—			—			294
Total operating expenses	6,250			2,085			1,290			(4,178		)	5,447
OPERATING INCOME (LOSS)	(863		)	557			357			(45		)	6
OTHER INCOME (EXPENSE):
Investment income	1			—			56			—			57
Miscellaneous income, including net income from equity investees	924			24			—			(918		)	30
Interest expense — affiliates	(2		)	(3		)	(2		)	(1		)	(8		)
Interest expense — other	(94		)	(109		)	(64		)	64			(203		)
Capitalized interest	—			12			23			—			35
Total other income (expense)	829			(76		)	13			(855		)	(89		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(34		)	481			370			(900		)	(83		)
INCOME TAXES (BENEFITS)	25			(117		)	58			18			(16		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	(59		)	598			312			(918		)	(67		)
Discontinued operations (net of income taxes of $5)	—			8			—			—			8
NET INCOME (LOSS)	$	(59	)	$	606		$	312		$	(918	)	$	(59	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(59	)	$	606		$	312		$	(918	)	$	(59	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(12		)	(13		)	—			13			(12		)
Amortized loss on derivative hedges	12			—			—			—			12
Change in unrealized gain on available-for-sale securities	16			—			15			(15		)	16
Other comprehensive income (loss)	16			(13		)	15			(2		)	16
Income taxes (benefits) on other comprehensive income (loss)	2			(8		)	5			3			2
Other comprehensive income (loss), net of tax	14			(5		)	10			(5		)	14
COMPREHENSIVE INCOME (LOSS)	$	(45	)	$	601		$	322		$	(923	)	$	(45	)
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of December 31, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—		$	2		$	—		$	—		$	2
Receivables-
Customers	539			—			—			—			539
Affiliated companies	938			787			227			(916		)	1,036
Other	52			12			17			—			81
Notes receivable from affiliated companies	203			23			683			(909		)	—
Materials and supplies	76			159			213			—			448
Derivatives	165			—			—			—			165
Prepayments and other	81			50			7			—			138
	2,054			1,033			1,147			(1,825		)	2,409
PROPERTY, PLANT AND EQUIPMENT:
In service	104			6,105			6,645			(382		)	12,472
Less — Accumulated provision for depreciation	28			1,953			2,962			(188		)	4,755
	76			4,152			3,683			(194		)	7,717
Construction work in progress	23			148			1,137			—			1,308
	99			4,300			4,820			(194		)	9,025
INVESTMENTS:
Nuclear plant decommissioning trusts	—			—			1,276			—			1,276
Investment in affiliated companies	5,801			—			—			(5,801		)	—
Other	—			11			—			—			11
	5,801			11			1,276			(5,801		)	1,287
ASSETS HELD FOR SALE (Note 20)	—			122			—			—			122
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—			131			—			(131		)	—
Customer intangibles	95			—			—			—			95
Goodwill	23			—			—			—			23
Property taxes	—			15			26			—			41
Unamortized sale and leaseback costs	—			—			—			168			168
Derivatives	53			—			—			—			53
Other	188			228			18			(155		)	279
	359			374			44			(118		)	659
	$	8,313		$	5,840		$	7,287		$	(7,938	)	$	13,502
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1		$	367		$	547		$	(23	)	$	892
Short-term borrowings-
Affiliated companies	977			212			151			(909		)	431
Other	—			4			—			—			4
Accounts payable-
Affiliated companies	741			400			362			(738		)	765
Other	94			196			—			—			290
Accrued taxes	204			23			23			(184		)	66
Derivatives	110			—			—			—			110
Other	70			63			18			46			197
	2,197			1,265			1,101			(1,808		)	2,755
CAPITALIZATION:
Total equity	5,312			2,283			3,493			(5,776		)	5,312
Long-term debt and other long-term obligations	712			1,860			742			(1,184		)	2,130
	6,024			4,143			4,235			(6,960		)	7,442
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—			—			—			858			858
Accumulated deferred income taxes	32			—			736			(27		)	741
Asset retirement obligations	—			187			828			—			1,015
Retirement benefits	22			163			—			—			185
Derivatives	14			—			—			—			14
Other	24			82			387			(1		)	492
	92			432			1,951			830			3,305
	$	8,313		$	5,840		$	7,287		$	(7,938	)	$	13,502
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of December 31, 2012	FES			FG			NG			Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—		$	3		$	—		$	—		$	3
Receivables-
Customers	483			—			—			—			483
Affiliated companies	232			417			478			(748		)	379
Other	56			19			16			—			91
Notes receivable from affiliated companies	366			7			607			(704		)	276
Materials and supplies	66			231			208			—			505
Derivatives	158			—			—			—			158
Prepayments and other	38			39			10			—			87
	1,399			716			1,319			(1,452		)	1,982
PROPERTY, PLANT AND EQUIPMENT:
In service	91			5,899			6,391			(384		)	11,997
Less — Accumulated provision for depreciation	32			1,915			2,646			(185		)	4,408
	59			3,984			3,745			(199		)	7,589
Construction work in progress	34			230			877			—			1,141
	93			4,214			4,622			(199		)	8,730
INVESTMENTS:
Nuclear plant decommissioning trusts	—			—			1,283			—			1,283
Investment in affiliated companies	4,972			—			—			(4,972		)	—
Other	—			12			—			—			12
	4,972			12			1,283			(4,972		)	1,295
ASSETS HELD FOR SALE	—			—			—			—			—
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—			313			—			(313		)	—
Customer intangibles	110			—			—			—			110
Goodwill	24			—			—			—			24
Property taxes	—			14			22			—			36
Unamortized sale and leaseback costs	—			—			—			119			119
Derivatives	99			—			—			—			99
Other	160			194			5			(106		)	253
	393			521			27			(300		)	641
	$	6,857		$	5,463		$	7,251		$	(6,923	)	$	12,648
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1		$	586		$	537		$	(22	)	$	1,102
Short-term borrowings-
Affiliated companies	358			346			—			(704		)	—
Other	—			4			—			—			4
Accounts payable-
Affiliated companies	748			143			583			(748		)	726
Other	63			96			—			—			159
Accrued taxes	126			25			20			—			171
Derivatives	124			—			—			—			124
Other	71			148			15			46			280
	1,491			1,348			1,155			(1,428		)	2,566
CAPITALIZATION:
Total equity	3,763			1,787			3,165			(4,952		)	3,763
Long-term debt and other long-term obligations	1,482			2,009			834			(1,207		)	3,118
	5,245			3,796			3,999			(6,159		)	6,881
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—			—			—			892			892
Accumulated deferred income taxes	28			—			714			(227		)	515
Asset retirement obligations	—			29			936			—			965
Retirement benefits	26			215			—			—			241
Derivatives	37			—			—			—			37
Other	30			75			447			(1		)	551
	121			319			2,097			664			3,201
	$	6,857		$	5,463		$	7,251		$	(6,923	)	$	12,648
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
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
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
For the Year Ended December 31, 2012	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(1,063	)	$	639		$	1,266		$	(21	)	$	821
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			351			299			—			650
Short-term borrowings, net	—			260			—			(257		)	3
Redemptions and Repayments-
Long-term debt	(1		)	(288		)	(161		)	21			(429		)
Short-term borrowings, net	(707		)	—			(32		)	739			—
Common stock dividend payment	—			(2,000		)	—			2,000			—
Other	(1		)	(8		)	(3		)	—			(12		)
Net cash provided from (used for) financing activities	(709		)	(1,685		)	103			2,503			212
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(14		)	(273		)	(508		)	—			(795		)
Nuclear fuel	—			—			(286		)	—			(286		)
Proceeds from asset sales	—			17			—			—			17
Sales of investment securities held in trusts	—			—			1,464			—			1,464
Purchases of investment securities held in trusts	—			—			(1,502		)	—			(1,502		)
Loans to affiliated companies, net	(211		)	1,338			(538		)	(482		)	107
Dividend received	2,000			—			—			(2,000		)	—
Other	(3		)	(40		)	1			—			(42		)
Net cash provided from (used for) investing activities	1,772			1,042			(1,369		)	(2,482		)	(1,037		)
Net change in cash and cash equivalents	—			(4		)	—			—			(4		)
Cash and cash equivalents at beginning of period	—			7			—			—			7
Cash and cash equivalents at end of period	$	—		$	3		$	—		$	—		$	3
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
For the Year Ended December 31, 2011	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(790	)	$	926		$	702		$	(19	)	$	819
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			140			107			—			247
Redemptions and Repayments-
Long-term debt	(136		)	(362		)	(377		)	19			(856		)
Short-term borrowings, net	1,065			78			32			(1,186		)	(11		)
Other	(9		)	(1		)	(1		)	—			(11		)
Net cash provided from (used for) financing activities	920			(145		)	(239		)	(1,167		)	(631		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(24		)	(205		)	(371		)	—			(600		)
Nuclear fuel	—			—			(149		)	—			(149		)
Proceeds from asset sales	9			590			—			—			599
Sales of investment securities held in trusts	—			—			1,843			—			1,843
Purchases of investment securities held in trusts	—			—			(1,890		)	—			(1,890		)
Loans to affiliated companies, net	(120		)	(1,157		)	105			1,186			14
Other	5			(11		)	(1		)	—			(7		)
Net cash used for investing activities	(130		)	(783		)	(463		)	1,186			(190		)
Net change in cash and cash equivalents	—			(2		)	—			—			(2		)
Cash and cash equivalents at beginning of period	—			9			—			—			9
Cash and cash equivalents at end of period	$	—		$	7		$	—		$	—		$	7

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
SEGMENT INFORMATION	'
	SEGMENT INFORMATION
	Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does not have separate reportable operating segments.
	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 in West Virginia and New Jersey that MP and JCP&L, respectively, own or contractually control. Its results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs. This business segment currently controls approximately 3,780 MWs of generation capacity, including the net transfer to Regulated Distribution of 1,476 MWs of capacity associated with the Harrison and Pleasants asset swap which occurred on October 9, 2013.
	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) and 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 derived from transmission services provided pursuant to the PJM open access transmission tariff to LSEs. Its results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities.
	The Competitive Energy Services segment, through FES and AE Supply, 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 approximately 14,000 MWs of capacity, including 885 MWs of capacity subject to RMR arrangements with PJM and excluding 1,476 MWs of generation capacity transferred to Regulated Distribution in connection with the Harrison and Pleasants asset swap that occurred on October 9, 2013. This segment also purchases electricity to meet sales obligations. The 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 charged by PJM to deliver energy to the segment’s customers.
	The Other/Corporate Segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment. Reconciling adjustments primarily consist of elimination of intersegment transactions.
	Segment Financial Information
	For the Years Ended December 31,	Regulated Distribution		Regulated Transmission		Competitive Energy Services			Other/Corporate			Reconciling Adjustments			Consolidated
		(In millions)
	2013
	External revenues	$	8,738	$	741	$	5,725		$	(121	)	$	(166	)	$	14,917
	Internal revenues	—		—		770			—			(770		)	—
	Total revenues	8,738		741		6,495			(121		)	(936		)	14,917
	Depreciation, amortization and deferrals	1,135		124		439			43			—			1,741
	Investment income	57		—		14			9			(44		)	36
	Interest expense	543		93		222			158			—			1,016
	Income taxes (benefits)	301		129		(141		)	(78		)	(16		)	195
	Income (loss) from continuing operations	501		214		(237		)	(130		)	27			375
	Discontinued operations, net of tax	—		—		17			—			—			17
	Net income (loss)	501		214		(220		)	(130		)	27			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
	2012
	External revenues	$	9,060	$	740	$	5,778		$	(119	)	$	(188	)	$	15,271
	Internal revenues	—		—		866			—			(864		)	2
	Total revenues	9,060		740		6,644			(119		)	(1,052		)	15,273
	Depreciation, amortization and deferrals	493		111		409			38			—			1,051
	Investment income (loss)	84		1		66			(5		)	(69		)	77
	Interest expense	540		92		284			85			—			1,001
	Income taxes (benefits)	295		133		83			(34		)	68			545
	Income (loss) from continuing operations	540		226		199			(155		)	(55		)	755
	Discontinued operations, net of tax	—		—		16			—			—			16
	Net income (loss)	540		226		215			(155		)	(55		)	771
	Total assets	27,150		4,865		18,087			392			—			50,494
	Total goodwill	5,025		526		896			—			—			6,447
	Property additions	1,074		507		1,014			83			—			2,678
	2011
	External revenues	$	9,913	$	660	$	5,783		$	(114	)	$	(204	)	$	16,038
	Internal revenues	—		—		1,237			—			(1,170		)	67
	Total revenues	9,913		660		7,020			(114		)	(1,374		)	16,105
	Depreciation, amortization and deferrals	846		110		411			24			—			1,391
	Investment income	99		—		56			1			(42		)	114
	Interest expense	530		89		298			91			—			1,008
	Income taxes (benefits)	287		114		214			(87		)	38			566
	Income (loss) from continuing operations	488		194		364			(149		)	(41		)	856
	Discontinued operations, net of tax	—		—		13			—			—			13
	Net income (loss)	488		194		377			(149		)	(41		)	869
	Total assets	25,534		4,463		16,796			617			—			47,410
	Total goodwill	5,025		526		890			—			—			6,441
	Property additions	868		390		778			93			—			2,129

Notes

(Notes)	12 Months Ended
	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Discontinued Operations and Assets Held for Sale	'
	DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE
	On September 4, 2013, certain of FirstEnergy's subsidiaries applied for authorization from the FERC to sell eleven hydroelectric power stations in Pennsylvania, Virginia and West Virginia to subsidiaries of Harbor Hydro, a subsidiary of LS Power. The asset purchase agreement was entered into on August 23, 2013, and amended and restated as of September 4, 2013. On February 12, 2014, the sale of the hydroelectric power plants to LS Power closed for approximately $395 million.
	As of December 31, 2013, FirstEnergy classified the hydroelectric power stations, with a carrying value of $235 million (FES - $122 million) as Assets held for sale in the Consolidated Balance Sheets. Included in the carrying value of the assets held for sale is goodwill of $29 million (FES - $1 million) which was allocated to the hydroelectric plants to be sold. Pre-tax income for the hydroelectric facilities of $26 million, $24 million and $21 million (FES - $22 million, $22 million and $13 million) for the years ended December 31, 2013, 2012 and 2011, respectively, are reported in FirstEnergy's and FES' Consolidated Statement of Income as discontinued operations. Revenues for the hydroelectric facilities of $33 million, $30 million and $42 million (FES - $31 million, $24 million and $24 million) for years ended December 31, 2013, 2012 and 2011, respectively, are reported in FirstEnergy's and FES' Consolidated Statement of Income as discontinued operations. In the first quarter of 2014, FirstEnergy expects to recognize a pre-tax gain of approximately $145 million (FES - $177 million).

Merger

Merger	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
MERGER	'
	MERGER
	Purchase Price Allocation
	On February 25, 2011, the merger between FE and AE closed. Pursuant to the terms of the Agreement and Plan of Merger among FE, Merger Sub and AE, Merger Sub merged with and into AE, with AE continuing as the surviving corporation and becoming a wholly owned subsidiary of FE. As part of the merger, AE shareholders received 0.667 of a share of FE common stock for each share of AE common stock outstanding as of the date the merger was completed, and all outstanding AE equity-based employee compensation awards were converted into FE equity-based awards on the same basis.
	The total consideration in the merger was based on the closing price of a share of FE common stock on February 24, 2011, the day prior to the date the merger was completed, and was calculated as follows (in millions, except per share data):
	Shares of AE common stock outstanding on February 24, 2011	$	170
	Exchange ratio	0.667
	Number of shares of FirstEnergy common stock issued	113
	Closing price of FirstEnergy common stock on February 24, 2011	38.16
	Fair value of shares issued by FirstEnergy	4,327
	Fair value of replacement share-based compensation awards relating to pre-merger service	27
	Total consideration transferred	$	4,354
	The allocation of the total consideration transferred in the merger to the assets acquired and liabilities assumed includes adjustments for the fair value of Allegheny coal contracts, energy supply contracts, emission allowances, unregulated property, plant and equipment, derivative instruments, goodwill, intangible assets, long-term debt and accumulated deferred income taxes. The allocation of the purchase price was as follows:
	(In millions)
	Current assets	$	1,493
	Property, plant and equipment	9,660
	Investments	138
	Goodwill	872
	Other noncurrent assets	1,353
	Current liabilities	(718		)
	Noncurrent liabilities	(3,450		)
	Long-term debt and other long-term obligations	(4,994		)
		$	4,354
	The allocation of purchase price in the table above reflects refinements made since the merger date in the determination of the fair values of income tax benefits, certain coal contracts and an adverse purchase power contract. This primarily resulted in an increase to property, plant and equipment, other noncurrent assets and current liabilities of approximately $4 million, $91 million and $4 million, respectively, and decreases to current assets and goodwill of $16 million and $80 million. The impact of the refinements on the amortization of purchase accounting adjustments recorded during 2011 was not significant.
	The estimated fair values of the assets acquired and liabilities assumed have been determined based on the accounting guidance for fair value measurements under GAAP, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
	The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The Allegheny delivery, transmission and unregulated generation businesses have been assigned to the Regulated Distribution, Regulated Transmission and Competitive Energy Services segments, respectively. The goodwill from the merger of $872 million has been assigned to the Competitive Energy Services segment based on expected synergies from the merger. The goodwill is not deductible for tax purposes.
	The valuation of the additional intangible assets and liabilities recorded as a result of the merger is as follows:
	(In millions)		Preliminary Valuation		Weighted Average Amortization Period
	Above market contracts:
	Energy contracts		$	189	10 years
	NUG contracts		124		25 years
	Coal supply contracts		516		8 years
			829
	Below market contracts:
	NUG contracts		143		13 years
	Coal supply contracts		83		7 years
	Transportation contract		35		8 years
			261
	Net intangible assets		$	568
	The fair value measurements of intangible assets and liabilities were based on significant unobservable inputs and thus represent level 3 measurements.
	The fair value of Allegheny’s energy, NUG and gas transportation contracts, both above-market and below-market, were estimated based on the present value of the above/below market cash flows attributable to the contracts based on the contract type, discounted by a current market interest rate consistent with the overall credit quality of the contract portfolio. The above/below market cash flows were estimated by comparing the expected cash flow based on existing contracted prices and expected volumes with the cash flows from estimated current market contract prices for the same expected volumes. The estimated current market contract prices were derived considering current market prices, such as the price of energy and transmission, miscellaneous fees and a normal profit margin. The weighted average amortization period was determined based on the expected volumes to be delivered over the life of the contract.
	The fair value of coal supply contracts was determined in a similar manner as the energy, NUG and gas transportation contracts, based on the present value of the above/below market cash flows attributable to the contracts. The fair value adjustments for these contracts are being amortized based on expected deliveries under each contract. See Note 7, Intangible Assets for additional information related to Intangible assets.
	In connection with the merger, FirstEnergy recorded merger transaction costs, which included change in control and other benefit payments to AE executives, of approximately $2 million ($1 million net of tax), $1 million ($1 million net of tax), $91 million ($73 million net of tax) during 2013, 2012 and 2011, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income.
	FirstEnergy also recorded approximately $6 million ($13 million net of tax) and $93 million ($91 million net of tax) in merger integration costs during 2012 and 2011, respectively, including an inventory valuation adjustment in 2011. In connection with the merger, FirstEnergy reviewed its inventory levels as a result of combining the inventory of both companies. Following this review, FirstEnergy management determined that the combined inventory stock contained excess and duplicative items. FirstEnergy management also adopted a consistent excess and obsolete inventory practice for the combined entity. Application of the revised practice, in conjunction with those items identified as excess and duplicative, resulted in an inventory valuation adjustment of $67 million ($42 million net of tax) in the first quarter of 2011.
	Revenues and earnings of Allegheny included in FirstEnergy’s Consolidated Statements of Income for the periods beginning on the February 25, 2011, merger date are as follows:
			February 25 -		Year Ended		Year Ended
	(In millions, except per share amounts)		31-Dec-11		31-Dec-12		31-Dec-13
	Total revenues		$	3,966	$	4,410	$	4,331
	Earnings (Losses) Available to FirstEnergy Corp.(1)		$	147	$	356	$	(31	)
	Basic Earnings (Losses) Per Share		$	0.37	$	0.85	$	(0.07	)
	Diluted Earnings (Losses) Per Share		$	0.37	$	0.85	$	(0.07	)
	-1	Includes Allegheny’s after-tax merger costs of $58 million, $1 million and $1 million during 2011, 2012 and 2013, respectively.
	Pro Forma Financial Information
	The following unaudited pro forma financial information reflects the consolidated results of operations of FirstEnergy as if the merger with AE had taken place on January 1, 2010. The unaudited pro forma information was calculated after applying FirstEnergy’s accounting policies and adjusting Allegheny’s results to reflect the depreciation and amortization that would have been charged assuming fair value adjustments to property, plant and equipment, debt and intangible assets had been applied on January 1, 2010, together with the consequential tax effects.
	FirstEnergy and Allegheny both incurred merger-related costs that have been included in the pro forma earnings presented below. Combined pre-tax transaction costs incurred were approximately $91 million in the year ended 2011. In addition, during 2011, $93 million of pre-tax merger integration costs and $36 million of pre-tax charges from merger settlements approved by regulatory agencies were recognized.
	The unaudited pro forma financial information has been presented below for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger been completed on January 1, 2010, or the future consolidated results of operations of the combined company.
	(Pro forma amounts in millions, except per share amounts)		2011
	Revenues		$	17,449
	Earnings available to FirstEnergy		$	979
	Basic Earnings Per Share		$	2.34
	Diluted Earnings Per Share		$	2.33

Summary_of_Quarterly_Financial

Summary of Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2013
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 2013 and 2012.
	FirstEnergy
	CONSOLIDATED STATEMENTS OF INCOME
	(In millions, except per share amounts)	2013											2012
		Dec. 31			Sept. 30		30-Jun			Mar. 31			Dec. 31			Sept. 30		30-Jun			Mar. 31
	Revenues	$	3,647		$	4,036	$	3,511		$	3,723		$	3,493		$	4,052	$	3,746		$	3,982
	Other operating expense	948			877		886			882			1,163			861		920			816
	Pensions and OPEB mark-to-market	(256		)	—		—			—			609			—		—			—
	Provision for depreciation	293			316		300			293			285			272		284			278
	Impairment of long-lived assets	322			—		473			—			—			—		—			—
	Operating Income (Loss)	401			512		46			648			(39		)	902		549			740
	Income (loss) from continuing operations before income taxes	208			286		(230		)	306			(258		)	729		307			522
	Income taxes (benefits)	66			77		(62		)	114			(105		)	307		123			220
	Income (loss) from continuing operations	142			209		(168		)	192			(153		)	422		184			302
	Discontinued operations (net of income taxes)	—			9		4			4			5			3		4			4
	Net Income (Loss)	142			218		(164		)	196			(148		)	425		188			306
	Earnings (loss) available to FirstEnergy Corp.	142			218		(164		)	196			(148		)	425		187			306
	Earnings (loss) per share of common stock-
	Basic - Continuing Operations	0.34			0.5		(0.40		)	0.46			(0.36		)	1.01		0.44			0.72
	Basic - Discontinued Operations (Note 20)	—			0.02		0.01			0.01			0.01			0.01		0.01			0.01
	Basic - Earnings Available to FirstEnergy Corp.	0.34			0.52		(0.39		)	0.47			(0.35		)	1.02		0.45			0.73
	Diluted - Continuing Operations	0.34			0.5		(0.40		)	0.46			(0.36		)	1		0.44			0.72
	Diluted - Discontinued Operations (Note 20)	—			0.02		0.01			0.01			0.01			0.01		0.01			0.01
	Diluted - Earnings Available to FirstEnergy Corp.	0.34			0.52		(0.39		)	0.47			(0.35		)	1.01		0.45			0.73
	FES
	CONSOLIDATED STATEMENTS OF INCOME
	(In millions)	2013											2012
		Dec. 31			Sept. 30		30-Jun			Mar. 31			Dec. 31			Sept. 30		30-Jun			Mar. 31
	Revenues	$	1,518		$	1,679	$	1,452		$	1,524		$	1,383		$	1,550	$	1,450		$	1,511
	Other operating expense	382			339		387			379			328			342		392			294
	Pensions and OPEB mark-to-market	(81		)	—		—			—			166			—		—			—
	Provision for depreciation	75			80		76			75			72			70		68			62
	Operating Income (Loss)	121			65		(39		)	95			(56		)	167		9			219
	Income (loss) from continuing operations before income taxes	114			56		(117		)	(1		)	(74		)	161		(6		)	195
	Income taxes (benefits)	25			23		(42		)	—			(36		)	65		(1		)	75
	Income (loss) from continuing operations	89			33		(75		)	(1		)	(38		)	96		(5		)	120
	Discontinued operations (net of income taxes)	—			7		4			3			3			5		4			2
	Net Income (Loss)	89			40		(71		)	2			(35		)	101		(1		)	122

Consolidated_Valuation_and_Qua

Consolidated Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2013
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, 2013, 2012 AND 2011
					Additions
	Description		Beginning Balance		Charged to Income			Charged to Other Accounts		(1)	Deductions		(2)	Ending Balance
			(In thousands)
	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
	Year Ended December 31, 2012:
	Accumulated provision for uncollectible accounts — customers		$	37,303	$	84,026		$	36,686		$	117,661		$	40,354
	— other		$	3,447	$	4,328		$	203		$	3,965		$	4,013
	Loss carryforward tax valuation reserve		$	34,236	$	67,461		$	—		$	—		$	101,697
	Year Ended December 31, 2011:
	Accumulated provision for uncollectible accounts — customers		$	36,272	$	78,521		$	38,042		$	115,532		$	37,303
	— other		$	8,252	$	663		$	927		$	6,395		$	3,447
	Loss carryforward tax valuation reserve		$	26,051	$	(18,933	)	$	27,118		$	—		$	34,236
	-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, 2013, 2012 AND 2011
					Additions
	Description		Beginning Balance		Charged to Income			Charged to Other Accounts		(1)	Deductions		(2)	Ending Balance
			(In thousands)
	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
	Year Ended December 31, 2012:
	Accumulated provision for uncollectible accounts — customers		$	16,441	$	10,410		$	—		$	10,663		$	16,188
	— other		$	2,500	$	1,290		$	—		$	1,290		$	2,500
	Loss carryforward tax valuation reserve		$	11,650	$	4,160		$	—		$	—		$	15,810
	Year Ended December 31, 2011:
	Accumulated provision for uncollectible accounts — customers		$	16,591	$	11,250		$	—		$	11,400		$	16,441
	— other		$	6,765	$	22		$	4		$	4,291		$	2,500
	Loss carryforward tax valuation reserve		$	9,290	$	2,360		$	—		$	—		$	11,650
	-1	Represents recoveries and reinstatements of accounts previously written off.
	-2	Represents the write-off of accounts considered to be uncollectible.

Organization_Basis_of_Presenta1

Organization, Basis of Presentation and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies (Policies) [Abstract]	'
Basis of Accounting [Text Block]	'
	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 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.
Inventory, Policy [Policy Text Block]	'
	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.
Investment, Policy [Policy Text Block]	'
	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.
Asset Retirement Obligations, Policy [Policy Text Block]	'
	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. AROs as of December 31, 2013, are described further in Note 14, Asset Retirement Obligations.
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, 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' and AE Supply's 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 of the Ohio and Pennsylvania Companies 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, the Utilities, FES and AE Supply accrue the estimated unbilled amount receivable as revenue and reverse 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 and AE Supply.
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 Property, plant and equipment and charged to fuel expense using the specific identification method.
ASSET IMPAIRMENTS	'
	ASSET IMPAIRMENTS
	Long-lived Assets
	FirstEnergy reviews long-lived assets, including regulatory 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. Impairments of long-lived assets recognized for the year ended December 31, 2013, are described further in Note 11, Impairment of Long-Lived Assets.
NEW ACCOUNTING PRONOUNCEMENTS	'
	NEW ACCOUNTING PRONOUNCEMENTS
	New accounting pronouncements not yet effective are not expected to have a material effect on the financial statements of FE or its subsidiaries.
Pension and Other Postretirement Plans, Policy	'
	PENSIONS 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 pensions 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. On July 25, 2013, FirstEnergy announced that non-bargaining employees hired on or after January 1, 2014 will participate in a cash-balance defined benefit pension plan. The plan for existing employees will remain unchanged. Under the cash-balance pension plan, FirstEnergy will make contributions to eligible employee retirement accounts based on employee age and years of service. The balance of these accounts will be provided to employees when they leave the company.
	FirstEnergy’s pensions and OPEB funding policy is based on actuarial computations using the projected unit credit method.
Consolidation, Variable Interest Entity, Policy	'
	VARIABLE INTEREST ENTITIES
	FirstEnergy performs qualitative analyses to determine whether a variable interest gives FirstEnergy a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 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.
Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]	'
	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. In evaluating goodwill for impairment, FirstEnergy first assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value, then the two-step goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any.
	FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated Transmission, Competitive Energy Services and Other/Corporate. Goodwill is allocated to these reportable segments based on the original purchase price allocation of acquisitions.
Consolidation, Policy [Policy Text Block]	'
	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 unless certain regulatory restrictions and rules apply. 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.
Reclassifications [Text Block]	'
	Certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications include, but are not limited to, the classification of discontinued operations associated with our sale of hydro assets discussed in additional detail in Note 20, Discontinued Operations and Assets Held for Sale. Additionally, amounts collected in rates above actual charges related to asset removal have been reclassified as a regulatory liability which resulted in an increase to total assets and noncurrent liabilities of approximately $88 million.

Organization_Basis_of_Presenta2

Organization, Basis of Presentation and Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies (Tables) [Abstract]	'
Regulatory assets on the Balance Sheets	'
	The following table provides information about the composition of net regulatory assets as of December 31, 2013 and December 31, 2012, and the changes during the year ended December 31, 2013:
	Regulatory Assets by Source	December 31,				December 31,				Increase
		2013				2012				(Decrease)
		(In millions)
	Regulatory transition costs	$	266			$	293			$	(27	)
	Customer receivables for future income taxes	518				505				13
	Nuclear decommissioning and spent fuel disposal costs	(198		)		(219		)		21
	Asset removal costs	(362		)		(372		)		10
	Deferred transmission costs	112				352				(240		)
	Deferred generation costs	346				379				(33		)
	Deferred distribution costs	194				231				(37		)
	Contract valuations	260				463				(203		)
	Storm-related costs	455				469				(14		)
	Other	263				229				34
	Total	$	1,854			$	2,330			$	(476	)
Receivables from customers	'
	Billed and unbilled customer receivables as of December 31, 2013 and 2012 are shown below.
	Customer Receivables	FirstEnergy				FES
		(In millions)
	December 31, 2013
	Billed	$	1,010			$	301
	Unbilled	710				238
	Total	$	1,720			$	539
	December 31, 2012
	Billed	$	893			$	243
	Unbilled	721				240
	Total	$	1,614			$	483
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	2013				2012				2011
		(In millions, except per share amounts)
	Income from continuing operations	$	375			$	755			$	856
	Less: Income attributable to noncontrolling interest	—				1				(16		)
	Income from continuing operations available to common shareholders	375				754				872
	Discontinued operations (Note 20)	17				16				13
	Earnings available to FirstEnergy Corp.	$	392			$	770			$	885
	Weighted average number of basic shares outstanding	418				418				399
	Assumed exercise of dilutive stock options and awards(1)	1				1				2
	Weighted average number of diluted shares outstanding	419				419				401
	Earnings per share:
	Basic earnings per share:
	Continuing operations	$	0.9			$	1.81			$	2.19
	Discontinued operations (Note 20)	0.04				0.04				0.03
	Net earnings per basic share	$	0.94			$	1.85			$	2.22
	Diluted earnings per share:
	Continuing operations	$	0.9			$	1.8			$	2.18
	Discontinued operations (Note 20)	0.04				0.04				0.03
	Net earnings per diluted share	$	0.94			$	1.84			$	2.21
Property, plant and equipment balances	'
	balances as of December 31, 2013 and 2012 were as follows:
		December 31, 2013											December 31, 2012
	Property, Plant and Equipment	In Service				Accum. Depr.				Net Plant			In Service		Accum. Depr.			Net Plant
		(In millions)
	Regulated Distribution	$	23,098			$	(6,514	)		$	16,584		$	21,473	$	(6,146	)	$	15,327
	Regulated Transmission	5,564				(1,511		)		4,053			5,078		(1,451		)	3,627
	Competitive	15,206				(5,088		)		10,118			16,338		(4,739		)	11,599
	Other/Corporate	360				(167		)		193			321		(131		)	190
	Total	$	44,228			$	(13,280	)		$	30,948		$	43,210	$	(12,467	)	$	30,743
Annual composite rates	'
	The respective annual composite rates for FirstEnergy's and FES' electric plant in 2013, 2012 and 2011 are shown in the following table:
		Annual Composite Depreciation Rate
		2013			2012			2011
	FirstEnergy	2.6	%		2.5	%		2.4	%
	FES	3.1	%		3.1	%		3.1	%
Summary of changes in goodwill	'
	Total goodwill recognized by segment in FirstEnergy's Consolidated Balance Sheet is as follows:
	Goodwill	Regulated Distribution				Regulated Transmission				Competitive Energy Services			Other/Corporate		Consolidated
		(In millions)
	Balance as of December 31, 2012	$	5,025			$	526			$	896		$	—	$	6,447
	Classification to Assets Held for Sale(1)	—				—				(29		)	—		(29		)
	West Virginia asset transfer	67				—				(67		)	—		—
	Balance as of December 31, 2013	$	5,092			$	526			$	800		$	—	$	6,418

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2013
Statement of Other Comprehensive Income [Abstract]	'
Schedule of Accumulated Other Comprehensive Income	'
	The changes in AOCI, net of tax, for the years ended December 31, 2013, 2012 and 2011 for FirstEnergy and FES are shown in the following tables:
	FirstEnergy
		Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
		(In millions)
	AOCI Balance, January 1, 2011	$	(54	)	$	7		$	472		$	425
	Other comprehensive income (loss) before reclassifications	(9		)	49			78			118
	Amounts reclassified from AOCI	24			(37		)	(104		)	(117		)
	Net other comprehensive income (loss)	15			12			(26		)	1
	AOCI Balance, December 31, 2011	$	(39	)	$	19		$	446		$	426
	Other comprehensive income before reclassifications	—			41			79			120
	Amounts reclassified from AOCI	1			(45		)	(117		)	(161		)
	Net other comprehensive income (loss)	1			(4		)	(38		)	(41		)
	AOCI Balance, December 31, 2012	$	(38	)	$	15		$	408		$	385
	Other comprehensive income before reclassifications	—			29			23			52
	Amounts reclassified from AOCI	2			(35		)	(120		)	(153		)
	Net other comprehensive income (loss)	2			(6		)	(97		)	(101		)
	AOCI Balance, December 31, 2013	$	(36	)	$	9		$	311		$	284
	FES
		Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
		(In millions)
	AOCI Balance, January 1, 2011	$	1		$	6		$	55		$	62
	Other comprehensive income (loss) before reclassifications	(9		)	42			8			41
	Amounts reclassified from AOCI	16			(32		)	(11		)	(27		)
	Net other comprehensive income (loss)	7			10			(3		)	14
	AOCI Balance, December 31, 2011	$	8		$	16		$	52		$	76
	Other comprehensive income before reclassifications	—			38			16			54
	Amounts reclassified from AOCI	(5		)	(41		)	(12		)	(58		)
	Net other comprehensive income (loss)	(5		)	(3		)	4			(4		)
	AOCI Balance, December 31, 2012	$	3		$	13		$	56		$	72
	Other comprehensive income before reclassifications	—			26			3			29
	Amounts reclassified from AOCI	(4		)	(31		)	(12		)	(47		)
	Net other comprehensive loss	(4		)	(5		)	(9		)	(18		)
	AOCI Balance, December 31, 2013	$	(1	)	$	8		$	47		$	54
Reclassification out of Accumulated Other Comprehensive Income	'
	The following amounts were reclassified from AOCI in the years ended December 31, 2013, 2012 and 2011 for FirstEnergy and FES are shown in the following tables:
	FirstEnergy	Year Ended December 31									Affected Line Item in Consolidated Statements of Income
	Reclassifications from AOCI (2)	2013			2012			2011
		(In millions)
	Gains & losses on cash flow hedges
	Commodity contracts	$	(8	)	$	(9	)	$	26		Other operating expenses
	Long-term debt	11			10			12			Interest expense
		3			1			38			Total before taxes
		(1		)	—			(14		)	Income tax benefits
		$	2		$	1		$	24		Net of tax
	Unrealized gains on AFS securities
	Realized gains on sales of securities	$	(56	)	$	(72	)	$	(59	)	Investment income
		21			27			22			Income taxes
		$	(35	)	$	(45	)	$	(37	)	Net of tax
	Defined benefit pension and OPEB plans
	Prior-service costs	$	(195	)	$	(191	)	$	(169	)	(1)
		75			74			65			Income taxes
		$	(120	)	$	(117	)	$	(104	)	Net of tax
	(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
	(2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.
	FES	Year Ended December 31									Affected Line Item in Consolidated Statements of Income
	Reclassifications from AOCI (2)	2013			2012			2011
		(In millions)
	Gains & losses on cash flow hedges
	Commodity contracts	$	(8	)	$	(9	)	$	26		Other operating expenses
	Long-term debt	2			—			1			Interest expense - other
		(6		)	(9		)	27			Total before taxes
		2			4			(11		)	Income taxes (benefits)
		$	(4	)	$	(5	)	$	16		Net of tax
	Unrealized gains on AFS securities
	Realized gains on sales of securities	$	(49	)	$	(65	)	$	(51	)	Investment income
		18			24			19			Income taxes
		$	(31	)	$	(41	)	$	(32	)	Net of tax
	Defined benefit pension and OPEB plans
	Prior-service costs	$	(20	)	$	(20	)	$	(18	)	(1)
		8			8			7			Income taxes
		$	(12	)	$	(12	)	$	(11	)	Net of tax
	(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
	(2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

Pension_and_Other_Postemployme1

Pension and Other Postemployment Benefits (Tables)	12 Months Ended
	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'
Obligations and Funded Status	'
		Pensions								OPEB
	Obligations and Funded Status	2013				2012				2013			2012
		(In millions)
	Change in benefit obligation:
	Benefit obligation as of January 1	$	8,975			$	7,977			$	1,076		$	1,037
	Service cost	197				161				13			12
	Interest cost	372				389				37			47
	Plan participants’ contributions	—				—				15			17
	Plan amendments	2				8				(37		)	(85		)
	Medicare retiree drug subsidy	—				—				5			—
	Actuarial (gain) loss	(846		)		861				(107		)	152
	Benefits paid	(437		)		(421		)		(123		)	(104		)
	Benefit obligation as of December 31	$	8,263			$	8,975			$	879		$	1,076
	Change in fair value of plan assets:
	Fair value of plan assets as of January 1	$	6,671			$	5,867			$	508		$	528
	Actual return on plan assets	(77		)		611				56			48
	Company contributions	14				614				39			19
	Plan participants’ contributions	—				—				15			17
	Benefits paid	(437		)		(421		)		(123		)	(104		)
	Fair value of plan assets as of December 31	$	6,171			$	6,671			$	495		$	508
	Funded Status:
	Qualified plan	$	(1,782	)		$	(1,967	)
	Non-qualified plans	(310		)		(336		)
	Funded Status	$	(2,092	)		$	(2,303	)		$	(384	)	$	(566	)
	Accumulated benefit obligation	$	7,800			$	8,355			$	—		$	—
	Amounts Recognized on the Balance Sheet:
	Current liabilities	$	(15	)		$	(14	)		$	—		$	—
	Noncurrent liabilities	(2,077		)		(2,289		)		(384		)	(566		)
	Net liability as of December 31	$	(2,092	)		$	(2,303	)		$	(384	)	$	(566	)
	Amounts Recognized in AOCI:
	Prior service cost (credit)	$	48			$	58			$	(558	)	$	(728	)
	Assumptions Used to Determine Benefit Obligations
	(as of December 31)
	Discount rate	5		%		4.25		%		4.75		%	4		%
	Rate of compensation increase	4.2		%		4.7		%		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				7.25-7.75%			7.5-8.0%
	Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	N/A				N/A				5		%	5		%
	Year that the rate reaches the ultimate trend rate (pre/post-Medicare)	N/A				N/A				2020			2020
	Allocation of Plan Assets (as of December 31)
	Equity securities	18		%		15		%		47		%	39		%
	Bonds	40		%		47		%		40		%	40		%
	Absolute return strategies	23		%		22		%		3		%	4		%
	Real estate	6		%		5		%		1		%	1		%
	Private equities	—		%		1		%		—		%	—		%
	Cash and short-term securities	13		%		10		%		9		%	16		%
	Total	100		%		100		%		100		%	100		%
Components of Net Periodic Benefit Costs	'
		Pensions											OPEB
	Components of Net Periodic Benefit Costs	2013				2012				2011			2013				2012			2011
		(In millions)
	Service cost	$	197			$	161			$	130		$	13			$	12		$	13
	Interest cost	372				389				374			37				47			48
	Expected return on plan assets	(501		)		(486		)		(446		)	(34		)		(37		)	(40		)
	Amortization of prior service cost (credit)	12				12				14			(207		)		(203		)	(203		)
	Other adjustments (settlements, curtailments, etc.)	—				—				6			—				—			—
	Pensions & OPEB mark-to-market adjustment	(267		)		735				729			(129		)		140			36
	Net periodic cost	$	(187	)		$	811			$	807		$	(320	)		$	(41	)	$	(146	)
Assumptions Used to Determine Net Periodic Benefit Cost	'
	Assumptions Used to Determine Net Periodic Benefit Cost	Pensions									OPEB
	for Years Ended December 31(1)	2013			2012			2011			2013		2012			2011
	Weighted-average discount rate	4.25	%		5	%		5.5	%		4	%	4.75	%		5	%
	Expected long-term return on plan assets	7.75	%		7.75	%		8.25	%		7.75	%	7.75	%		8.5	%
	Rate of compensation increase	4.7	%		5.2	%		5.2	%		N/A		N/A			N/A
Target asset allocations for pension and OPEB portfolio	'
	FirstEnergy’s target asset allocations for its pensions and OPEB trust portfolios for 2013 and 2012 are shown in the following table:
		Target Asset Allocations
		2013			2012
	Equities	26	%		20	%
	Fixed income	40	%		51	%
	Absolute return strategies	22	%		21	%
	Real estate	5	%		5	%
	Private equity	1	%		—	%
	Cash	6	%		3	%
		100	%		100	%
Effect of One-Percentage Point change in assumed health care cost trend rates	'
	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
		Pensions				Benefit Payments				Subsidy Receipts
		(in millions)
	2014	$	449			$	129			$	(4	)
	2015	466				67				(4		)
	2016	484				67				(4		)
	2017	500				67				(4		)
	2018	524				65				(4		)
	Years 2019-2023	2,867				382				(17		)
Net Pension and OPEB Asset (Liability)	'
	FES’ share of the net pensions and OPEB liability as of December 31, 2013 and 2012, was as follows:
		Pensions								OPEB
		2013				2012				2013			2012
		(In millions)
	Net Liability	$	(149	)		$	(180	)		$	(8	)	$	(36	)
Net Periodic Pension and OPEB Costs	'
	FES’ share of the net periodic pensions and OPEB costs for the three years ended December 31, 2013 was as follows:
		Pensions											OPEB
		2013				2012				2011			2013				2012			2011
		(In millions)
	Net Periodic Costs	$	(30	)		$	78			$	80		$	(40	)		$	(11	)	$	(21	)
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 2013 and 2012.
		December 31, 2013															Asset Allocation
		Level 1				Level 2				Level 3			Total
		(In millions)
	Cash and short-term securities	$	—			$	782			$	—		$	782			13	%
	Equity investments
	Domestic	701				3				—			704				11	%
	International	304				118				—			422				7	%
	Fixed income
	Government bonds	—				314				—			314				5	%
	Corporate bonds	—				2,128				—			2,128				34	%
	Mortgaged-backed securities (non-government)	—				87				—			87				1	%
	Alternatives
	Hedge funds	—				1,395				—			1,395				23	%
	Derivatives	—				14				—			14				—	%
	Private equity funds	—				—				27			27				—	%
	Real estate funds	—				—				385			385				6	%
	Total (1)	$	1,005			$	4,841			$	412		$	6,258			100	%
		December 31, 2012															Asset Allocation
		Level 1				Level 2				Level 3			Total
		(In millions)
	Cash and short-term securities	$	—			$	652			$	—		$	652			10	%
	Equity investments
	Domestic	547				8				—			555				8	%
	International	275				153				—			428				7	%
	Fixed income
	Government bonds	4				564				—			568				8	%
	Corporate bonds	—				1,899				—			1,899				28	%
	High yield debt	—				369				—			369				6	%
	Mortgaged-backed securities (non-government)	—				330				—			330				5	%
	Alternatives
	Hedge funds	—				1,498				—			1,498				22	%
	Derivatives	—				18				—			18				—	%
	Private equity funds	—				—				33			33				1	%
	Real estate funds	—				—				357			357				5	%
	Total (1)	$	826			$	5,491			$	390		$	6,707			100	%
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 2013 and 2012:
		Private Equity Funds				Real Estate Funds				Derivatives
		(In millions)
	Balance as of January 1, 2012	$	135			$	327			$	70
	Actual return on plan assets:
	Unrealized gains	(14		)		29				—
	Realized gains	(10		)		4				—
	Purchases, sales and settlements	—				—				(70		)
	Transfers in (out)	(78		)		(3		)		—
	Balance as of December 31, 2012	$	33			$	357			$	—
	Actual return on plan assets:
	Unrealized gains	1				17				—
	Realized gains	5				13				—
	Purchases, sales and settlements	—				—				—
	Transfers out	(12		)		(2		)		—
	Balance as of December 31, 2013	$	27			$	385			$	—
OPEB	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'
Pension investments measured at fair value	'
	As of December 31, 2013 and 2012, the OPEB trust investments measured at fair value were as follows:
		December 31, 2013															Asset Allocation
		Level 1				Level 2				Level 3			Total
		(In millions)
	Cash and short-term securities	$	—			$	47			$	—		$	47			9	%
	Equity investment
	Domestic	227				—				—			227				45	%
	International	4				2				—			6				1	%
	Mutual funds	5				—				—			5				1	%
	Fixed income
	U.S. treasuries	—				44				—			44				9	%
	Government bonds	—				91				—			91				18	%
	Corporate bonds	—				59				—			59				12	%
	High yield debt	—				—				—			—				—	%
	Mortgage-backed securities (non-government)	—				3				—			3				1	%
	Alternatives
	Hedge funds	—				17				—			17				3	%
	Private equity funds	—				—				—			—				—	%
	Real estate funds	—				—				5			5				1	%
	Total (1)	$	236			$	263			$	5		$	504			100	%
		December 31, 2012															Asset Allocation
		Level 1				Level 2				Level 3			Total
		(In millions)
	Cash and short-term securities	$	—			$	83			$	—		$	83			16	%
	Equity investment
	Domestic	183				—				—			183				36	%
	International	4				2				—			6				1	%
	Mutual funds	8				3				—			11				2	%
	Fixed income
	U.S. treasuries	—				48				—			48				9	%
	Government bonds	—				88				—			88				17	%
	Corporate bonds	—				59				—			59				11	%
	High yield debt	—				5				—			5				1	%
	Mortgage-backed securities (non-government)	—				9				—			9				2	%
	Alternatives
	Hedge funds	—				21				—			21				4	%
	Private equity funds	—				—				—			—				—	%
	Real estate funds	—				—				5			5				1	%
	Total (1)	$	195			$	318			$	5		$	518			100	%
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 2013 and 2012:
		Private Equity Funds				Real Estate Funds
		(in millions)
	Balance as of January 1, 2012	$	3			$	7
	Actual return on plan assets:
	Unrealized losses	(1		)		—
	Realized gains (losses)	—				—
	Purchases, sales and settlements	—				—
	Transfers out	(2		)		(2		)
	Balance as of December 31, 2012	$	—			$	5
	Balance as of December 31, 2013	$	—			$	5

StockBased_Compensation_Plans_

Stock-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Schedule of Nonvested Restricted Stock Units Activity	'
	Restricted common stock (restricted stock) and restricted stock units (stock units) activity for the year ended December 31, 2013, was as follows:
	Outstanding as of January 1, 2013	2,180,422
	Granted	952,137
	Vested	(815,851	)
	Forfeited	(100,099	)
	Outstanding as of December 31, 2013	2,216,609
Schedule of Restricted Stock Grants Under LTIP	'
	Restricted stock grants under the ICP were as follows:
			2013				2012				2011
	Restricted stock granted		27,561				263,771				297,859
	Weighted average market price		$	42.53			$	44.82			$	38.44
	Weighted average vesting period (years)		3.68				3.09				2.27
	Dividends restricted		Yes				Yes				Yes
Schedule of Vesting Activity for Restricted Stock	'
	Vesting activity for restricted stock during 2013 was as follows (forfeitures were not material):
	Restricted Stock		Number of Shares			Weighted Average Grant-Date Fair Value
	Nonvested as of January 1, 2013		551,678			$	46.73
	Nonvested as of December 31, 2013		417,464			$	45.46
	Granted in 2013		27,561			$	42.53
	Vested in 2013(1)		167,751			$	37.1
Schedule of Restricted Stock Units Granted and Weighted Average Vesting Period	'
			2013			2012			2011
	Restricted stock units granted		924,576			652,120			617,195
	Weighted average vesting period (years)		3			3			3
Schedule of Vesting Activity for Stock Units	'
	Vesting activity for stock units during 2013 was as follows:
	Restricted Stock Units		Number of Shares			Weighted Average Grant-Date Fair Value
	Nonvested as of January 1, 2013		1,628,744			$	41.1
	Nonvested as of December 31, 2013		1,799,145			$	40.86
	Granted in 2013		924,576			$	39.9
	Forfeited in 2013		82,629			$	41.38
	Vested in 2013 (1)		792,113			$	40.74
Schedule of Stock Option Activity	'
	Stock option activity during 2013 was as follows:
	Stock Option Activity		Number of Shares			Weighted Average Exercise Price
	Balance, January 1, 2013 (2,348,469 options exercisable)		2,910,269			$	40.33
	Options exercised		(546,408	)		30.37
	Options forfeited		(4,735	)		71.21
	Balance, December 31, 2013 (1,997,969 options exercisable)		2,359,126			$	42.59
Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, by Exercise Price Range	'
	Options outstanding and range of exercise prices as of December 31, 2013, were as follows:
			Options Outstanding
	Range of Exercise Prices		Shares			Weighted Average Exercise Price				Remaining Contractual Life
										(in years)
	$20.02-$35.44		66,125			$	22.83			0.47
	$35.45-$38.75		1,143,389			$	36.78			6.28
	$38.76-$53.04		835,039			$	38.81			0.19
	$53.05-$81.19		314,573			$	77.85			3.56
	Total		2,359,126			$	42.59			3.6
Schedule of Stock-based Compensation Expense	'
	Pre-tax stock-based compensation costs, tax benefit associated with stock-based compensation expense, 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		2013				2012				2011
			(In millions)
	Restricted Stock and Restricted Stock Units		$	42			$	42			$	29
	Stock Options		—				1				1
	Performance Shares		(10		)		5				3
	401(k) Savings Plan		25				37				31
	EDCP		(2		)		—				6
	DCPD		5				4				4
	Total		$	60			$	89			$	74
	Stock-based compensation costs capitalized		$	20			$	29			$	21
	FES		Years ended December 31,
	Stock-based Compensation Plan		2013				2012				2011
			(In millions)
	Restricted Stock and Restricted Stock Units		$	6			$	6			$	4
	Performance Shares		(1		)		1				1
	401(k) Savings Plan		4				6				5
	EDCP		—				—				1
	Total		$	9			$	13			$	11
	Stock-based compensation costs capitalized		$	1			$	1			$	—

Taxes_Tables

Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Taxes [Abstract]	'
Provision For Income Taxes	'
	PROVISION FOR INCOME TAXES		FirstEnergy				FES
			(In millions)
	2013
	Currently payable (receivable)-
	Federal		$	(118	)		$	(300	)
	State		70				(3		)
			(48		)		(303		)
	Deferred, net-
	Federal		305				317
	State		(54		)		(4		)
			251				313
	Investment tax credit amortization		(8		)		(4		)
	Total provision for income taxes		$	195			$	6
	2012
	Currently payable (receivable)-
	Federal		$	(130	)		$	(128	)
	State		28				17
			(102		)		(111		)
	Deferred, net-
	Federal		580				209
	State		78				9
			658				218
	Investment tax credit amortization		(11		)		(4		)
	Total provision for income taxes		$	545			$	103
	2011
	Currently payable (receivable)-
	Federal		$	(251	)		$	(224	)
	State		19				9
			(232		)		(215		)
	Deferred, net-
	Federal		785				205
	State		24				(2		)
			809				203
	Investment tax credit amortization		(11		)		(4		)
	Total provision for income taxes		$	566			$	(16	)
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 provision for income taxes for the three years ended December 31, 2013:
		FirstEnergy				FES
		(In millions)
	2013
	Book income before provision for income taxes	$	570			$	52
	Federal income tax expense at statutory rate	$	199			$	18
	Increases (reductions) in taxes resulting from-
	Amortization of investment tax credits	(8		)		(4		)
	State income taxes, net of federal tax benefit	10				(5		)
	FirstEnergy effectively settled tax items	(2		)		—
	ESOP Dividend	(9		)		(2		)
	Nondeductible compensation	3				—
	Other permanent items	1				—
	AFUDC equity and other flow-through	(7		)		—
	Other, net	8				(1		)
	Total provision for income taxes	$	195			$	6
	2012
	Book income before provision for income taxes	$	1,299			$	276
	Federal income tax expense at statutory rate	$	455			$	97
	Increases (reductions) in taxes resulting from-
	Amortization of investment tax credits	(11		)		(4		)
	State income taxes, net of federal tax benefit	69				17
	Medicare Part D	32				1
	Effectively settled tax items	(20		)		(11		)
	State valuation allowance	60				—
	State apportionment remeasurement	(50		)		—
	Other, net	10				3
	Total provision for income taxes	$	545			$	103
	2011
	Book income before provision for income taxes	$	1,438			$	(83	)
	Federal income tax expense (benefit) at statutory rate	$	503			$	(29	)
	Increases (reductions) in taxes resulting from-
	Amortization of investment tax credits	(11		)		(4		)
	State income taxes, net of federal tax benefit	28				5
	State unitary tax adjustments	33				—
	Manufacturing deduction	16				13
	Medicare Part D	36				4
	Effectively settled tax items	(11		)		(2		)
	State valuation allowance	(19		)		2
	Other, net	(9		)		(5		)
	Total provision for income taxes (benefits)	$	566			$	(16	)
Accumulated deferred income taxes	'
	Accumulated deferred income taxes as of December 31, 2013 and 2012 are as follows:
			FirstEnergy				FES
			(In millions)
	December 31, 2013
	Property basis differences		$	8,078			$	1,428
	Regulatory transition charge		(26		)		—
	Customer receivables for future income taxes		(2		)		—
	Deferred MISO/PJM transmission costs		27				—
	Other regulatory assets — RCP		69				—
	Deferred sale and leaseback gain		(411		)		(370		)
	Non-utility generation costs		(1		)		—
	Unamortized investment tax credits		(62		)		(16		)
	Unrealized losses on derivative hedges		(20		)		(1		)
	Pensions and OPEB		(938		)		(77		)
	Lease market valuation liability		(59		)		55
	Oyster Creek securitization (Note 12)		57				—
	Nuclear decommissioning activities		44				31
	Mark-to-market adjustments		31				30
	Deferred gain for asset sales — affiliated companies		781				—
	Loss carryforwards and AMT credits		(1,599		)		(369		)
	Loss carryforward valuation reserve		142				18
	Storm damage		179				—
	Market transition charge		81				—
	All other		231				(13		)
	Net deferred income tax liability		$	6,602			$	716
	December 31, 2012
	Property basis differences		$	7,868			$	1,060
	Regulatory transition charge		79				—
	Customer receivables for future income taxes		130				—
	Deferred MISO/PJM transmission costs		125				—
	Other regulatory assets — RCP		161				—
	Deferred sale and leaseback gain		(431		)		(384		)
	Non-utility generation costs		5				—
	Unamortized investment tax credits		(67		)		(17		)
	Unrealized losses on derivative hedges		(21		)		2
	Pensions and OPEB		(1,102		)		(105		)
	Lease market valuation liability		(81		)		33
	Oyster Creek securitization (Note 12)		75				—
	Nuclear decommissioning activities		127				111
	Mark-to-market adjustments		30				30
	Loss carryforwards and ATM credits		(1,199		)		(221		)
	Loss carryforward valuation reserve		102				16
	Storm damage		192				—
	Market transition charge		65				—
	All other		239				(22		)
	Net deferred income tax liability		$	6,297			$	503
Changes in unrecognized tax benefits	'
	The following table summarizes the changes in unrecognized tax positions for the years ended 2013, 2012 and 2011:
			FirstEnergy				FES
			(In millions)
	Balance, January 1, 2011		$	45			$	41
	Increase due to merger with AE		97				—
	Prior years increases		10				8
	Prior years decreases		(35		)		(4		)
	Balance, December 31, 2011		$	117			$	45
	Current year increases		2				—
	Current year decreases		(7		)		—
	Prior years increases		6				6
	Prior years decreases		(37		)		(13		)
	Decrease for settlements		(38		)		(35		)
	Balance, December 31, 2012		$	43			$	3
	Prior years increases		10				—
	Prior years decreases		(5		)		—
	Balance, December 31, 2013		$	48			$	3
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, 2013 and the cumulative net interest payable as of December 31, 2013 and 2012:
			Net Interest Expense (Income)										Net Interest Payable
			For the Years Ended December 31,										As of December 31,
			2013				2012			2011			2013		2012
			(In millions)										(In millions)
	FirstEnergy		$	1			$	(4	)	$	(5	)	$	9	$	8
	FES		—				(4		)	1			1		1
Pre-tax net operating loss expiration period	'
	Expiration Period		FirstEnergy							FES
			(In millions)
			State				Local			State			Local
	2014-2018		$	14			$	2,289		$	8		$	1,243
	2019-2023		2,513				—			23			—
	2024-2028		2,051				—			60			—
	2029-2033		2,891				—			752			—
			$	7,469			$	2,289		$	843		$	1,243
Details of general taxes	'
	General Taxes
			FirstEnergy				FES
			(In millions)
	2013
	KWH excise		$	219			$	—
	State gross receipts		240				77
	Real and personal property		368				40
	Social security and unemployment		110				19
	Other		41				2
	Total general taxes		$	978			$	138
	2012
	KWH excise		$	230			$	—
	State gross receipts		251				77
	Real and personal property		328				35
	Social security and unemployment		126				20
	Other		49				4
	Total general taxes		$	984			$	136
	2011
	KWH excise		$	244			$	—
	State gross receipts		264				62
	Real and personal property		298				42
	Social security and unemployment		109				14
	Other		62				6
	Total general taxes		$	977			$	124

Leases_Tables

Leases (Tables)	12 Months Ended
	Dec. 31, 2013
Leases [Abstract]	'
Rentals for capital and operating leases	'
	perating lease expense for 2013, 2012 and 2011, is summarized as follows:
	(In millions)	2013			2012			2011
	FirstEnergy	$	224		$	291		$	319
	FES	97			140			154
Future minimum capital lease payments	'
	The future minimum capital lease payments as of December 31, 2013 are as follows:
	Capital leases	FirstEnergy			FES
		(In millions)
	2014	$	40		$	6
	2015	38			6
	2016	34			5
	2017	30			5
	2018	23			2
	Years thereafter	57			—
	Total minimum lease payments	222			24
	Interest portion	(34		)	(2		)
	Present value of net minimum lease payments	188			22
	Less current portion	34			5
	Noncurrent portion	$	154		$	17
Future minimum operating lease payments	'
	irstEnergy's future minimum consolidated operating lease payments as of December 31, 2013, are as follows:
		FirstEnergy
	Operating Leases	Lease Payments			Capital Trust			Net
		(In millions)
	2014	$	250		$	48		$	202
	2015	245			40			205
	2016	213			13			200
	2017	128			3			125
	2018	126			—			126
	Years thereafter	1,564			—			1,564
	Total minimum lease payments	$	2,526		$	104		$	2,422
	FES' future minimum operating lease payments as of December 31, 2013, are as follows:
	Operating Leases	Lease Payments
		(In millions)
	2014	$	143
	2015	142
	2016	130
	2017	82
	2018	101
	Years thereafter	1,480
	Total minimum lease payments	$	2,078

Intangible_Assets_Tables

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
Future Amortization	'
	As of December 31, 2013, 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		2013		2014		2015		2016		2017		2018		Thereafter
	NUG contracts(1)(2)		$	124	$	15	$	109	$	5	$	5	$	5	$	5	$	5	$	5	$	84
	OVEC(1)		54		5		49		2		2		2		2		2		2		39
	Coal contracts(1)(3)		556		222		334		62		55		51		51		45		30		49
	FES customer contracts		147		52		95		17		17		17		17		17		14		13
	Energy contracts(1)		136		135		1		14		1		—		—		—		—		—
			$	1,017	$	429	$	588	$	100	$	80	$	75	$	75	$	69	$	51	$	185
	-1	Fair value measurements of intangible assets recorded in connection with the Allegheny merger (see Note 21, Merger).
	-2	NUG contracts are subject to regulatory accounting and their amortization does not impact earnings.
	-3	A gross amount of $102 million ($53 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, 2013
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, 2013:
		Maximum		Discounted Lease		Net
		Exposure		Payments, net(1)		Exposure
		(In millions)
	FES	$	1,274	$	1,063	$	211
	Other FE subsidiaries	752		289		463
	(1)	The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.1 billion.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013																December 31, 2012
		Level 1				Level 2				Level 3				Total				Level 1			Level 2			Level 3			Total
	Assets	(In millions)
	Corporate debt securities	$	—			$	1,365			$	—			$	1,365			$	—		$	1,259		$	—		$	1,259
	Derivative assets - commodity contracts	7				208				—				215				—			252			—			252
	Derivative assets - FTRs	—				—				4				4				—			—			8			8
	Derivative assets - NUG contracts(1)	—				—				20				20				—			—			36			36
	Equity securities(2)	317				—				—				317				310			—			—			310
	Foreign government debt securities	—				109				—				109				—			126			—			126
	U.S. government debt securities	—				165				—				165				—			179			—			179
	U.S. state debt securities	—				228				—				228				—			299			—			299
	Other(3)	187				255				—				442				126			227			—			353
	Total assets	$	511			$	2,330			$	24			$	2,865			$	436		$	2,342		$	44		$	2,822
	Liabilities
	Derivative liabilities - commodity contracts	$	(13	)		$	(100	)		$	—			$	(113	)		$	(3	)	$	(151	)	$	—		$	(154	)
	Derivative liabilities - FTRs	—				—				(12		)		(12		)		—			—			(9		)	(9		)
	Derivative liabilities - NUG contracts(1)	—				—				(222		)		(222		)		—			—			(290		)	(290		)
	Derivative liabilities - LCAPP contracts(1)	—				—				—				—				—			—			(144		)	(144		)
	Total liabilities	$	(13	)		$	(100	)		$	(234	)		$	(347	)		$	(3	)	$	(151	)	$	(443	)	$	(597	)
	Net assets (liabilities)(4)	$	498			$	2,230			$	(210	)		$	2,518			$	433		$	2,191		$	(399	)	$	2,225
	(1)	NUG and LCAPP 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 short-term cash investments.
	(4)	Excludes $10 million and $110 million as of December 31, 2013 and December 31, 2012, 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, LCAPP contracts, and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2013 and December 31, 2012:
		NUG Contracts(1)												LCAPP Contracts(1)										FTRs
		Derivative Assets				Derivative Liabilities				Net				Derivative Assets				Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
		(In millions)
	January 1, 2012 Balance	$	57			$	(349	)		$	(292	)		$	—			$	—		$	—		$	1		$	(23	)	$	(22	)
	Unrealized gain (loss)	(20		)		(180		)		(200		)		—				1			1			6			(6		)	—
	Purchases	—				—				—				—				(145		)	(145		)	13			(10		)	3
	Settlements	(1		)		239				238				—				—			—			(12		)	30			18
	December 31, 2012 Balance	$	36			$	(290	)		$	(254	)		$	—			$	(144	)	$	(144	)	$	8		$	(9	)	$	(1	)
	Unrealized gain (loss)	(8		)		(17		)		(25		)		—				(22		)	(22		)	3			1			4
	Purchases	—				—				—				—				—			—			6			(15		)	(9		)
	Terminations(2)	—				—				—				—				166			166			—			—			—
	Settlements	(8		)		85				77				—				—			—			(13		)	11			(2		)
	December 31, 2013 Balance	$	20			$	(222	)		$	(202	)		$	—			$	—		$	—		$	4		$	(12	)	$	(8	)
	(1)	Changes in the fair value of NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings.
	(2)	See Note 10, Derivative Instruments.
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, 2013:
			Fair Value, Net (In millions)				Valuation		Significant Input		Range		Weighted Average		Units
							Technique
	FTRs		$	(8	)		Model		RTO auction clearing prices		($2.80) to $5.20		$0.60		Dollars/MWH
	NUG Contracts		$	(202	)		Model		Generation		600 to 5,641,000		1,529,000		MWH
									Regional electricity prices		$51.70 to $57.30		$53.80		Dollars/MWH
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities	'
	he 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, 2013 and December 31, 2012:
			December 31, 2013(1)												December 31, 2012(2)
			Cost Basis				Unrealized Gains				Fair Value				Cost Basis				Unrealized Gains			Fair Value
			(In millions)
	Debt securities
	FirstEnergy		$	1,881			$	33			$	1,914			$	1,827			$	34		$	1,861
	FES		918				17				935				778				14			792
	Equity securities
	FirstEnergy		$	308			$	9			$	317			$	293			$	16		$	309
	FES		207				—				207				281				13			294
	(1)	Excludes short-term cash investments: FE Consolidated - $204 million; FES - $135 million.
	(2)	Excludes short-term cash investments: FE Consolidated - $326 million; FES - $196 million.
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income	'
	roceeds 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, 2013, 2012 and 2011 were as follows:
	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
	December 31, 2012		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and Dividend Income
			(In millions)
	FirstEnergy		$	2,980			$	179			$	(83	)		$	(16	)		$	70
	FES		1,464				124				(59		)		(14		)		39
	December 31, 2011		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and
																			Dividend Income
			(In millions)
	FirstEnergy		$	4,207			$	229			$	(71	)		$	(19	)		$	82
	FES		1,843				80				(29		)		(17		)		47
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities	'
	he 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, 2013 and December 31, 2012:
			December 31, 2013												December 31, 2012
			Cost Basis				Unrealized Gains				Fair Value				Cost Basis				Unrealized Gains			Fair Value
			(In millions)
	Debt Securities
	FirstEnergy		$	33			$	2			$	35			$	54			$	30		$	84
Fair value and related carrying amounts of long-term debt and other long-term obligations	'
	he 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, 2013								December 31, 2012
		Carrying				Fair				Carrying				Fair
		Value				Value				Value				Value
		(In millions)
	FirstEnergy	$	17,049			$	17,957			$	16,957			$	19,460
	FES	3,001				3,073				4,194				4,524
FES	'
Fair Value of Financial Instruments [Line Items]	'
Assets and liabilities measured on recurring basis	'
	(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 $9 million and $94 million as of December 31, 2013 and December 31, 2012, 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	'
	he 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, 2013 and December 31, 2012:
			Derivative Asset FTRs				Derivative Liability FTRs				Net FTRs
			(In millions)
	January 1, 2012 Balance		$	1			$	(7	)		$	(6	)
	Unrealized gain (loss)		4				(4		)		—
	Purchases		9				(7		)		2
	Settlements		(8		)		12				4
	December 31, 2012 Balance		$	6			$	(6	)		$	—
	Unrealized loss		—				(2		)		(2		)
	Purchases		5				(12		)		(7		)
	Settlements		(8		)		9				1
	December 31, 2013 Balance		$	3			$	(11	)		$	(8	)
Quantitative information for level 3 valuation	'
	he 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, 2013:
			Fair Value, Net (In millions)				Valuation		Significant Input		Range		Weighted Average		Units
							Technique
	FTRs		$	(8	)		Model		RTO auction clearing prices		($2.80) to $5.20		$0.50		Dollars/MWH

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
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,
		2013				2012					2013				2012
		(In millions)									(In millions)
	Current Assets - Derivatives									Current Liabilities - Derivatives
	Commodity Contracts	$	162			$	153			Commodity Contracts	$	(102	)		$	(119	)
	FTRs	4				7				FTRs	(9		)		(7		)
		166				160					(111		)		(126		)
										Noncurrent Liabilities - Adverse Power Contract Liability
										NUGs	(222		)		(290		)
	Deferred Charges and Other Assets - Other									LCAAP	—				(144		)
	Commodity Contracts	53				99				Noncurrent Liabilities - Other
	FTRs	—				1				Commodity Contracts	(11		)		(36		)
	NUGs	20				36				FTRs	(3		)		(2		)
		73				136					(236		)		(472		)
	Derivative Assets	$	239			$	296			Derivative Liabilities	$	(347	)		$	(598	)
Offsetting assets and liabilities	'
	The following tables summarize the fair value of derivative instruments 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, 2013		Fair Value				Derivative Instruments				Cash Collateral (Received)/Pledged				Net Fair Value
			(In millions)
	Derivative Assets
	Commodity contracts		$	215			$	(106	)		$	(9	)		$	100
	FTRs		4				(4		)		—				—
	NUG contracts		20				—				—				20
			$	239			$	(110	)		$	(9	)		$	120
	Derivative Liabilities
	Commodity contracts		$	(113	)		$	106			$	7			$	—
	FTRs		(12		)		4				5				(3		)
	NUG contracts		(222		)		—				—				(222		)
			$	(347	)		$	110			$	12			$	(225	)
							Amounts Not Offset in Consolidated Balance Sheet
	December 31, 2012		Fair Value				Derivative Instruments				Cash Collateral (Received)/Pledged				Net Fair Value
			(In millions)
	Derivative Assets
	Commodity contracts		$	252			$	(142	)		$	(5	)		$	105
	FTRs		8				(8		)		—				—
	NUG contracts		36				—				—				36
			$	296			$	(150	)		$	(5	)		$	141
	Derivative Liabilities
	Commodity contracts		$	(155	)		$	142			$	12			$	(1	)
	FTRs		(9		)		8				1				—
	NUG contracts		(290		)		—				—				(290		)
	LCAPP contracts		(144		)		—				—				(144		)
			$	(598	)		$	150			$	13			$	(435	)
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, 2013:
		Purchases			Sales			Net			Units
		(In millions)
	Power Contracts	34			37			(3	)		MWH
	FTRs	43			—			43			MWH
	NUGs	11			—			11			MWH
	Natural Gas	77			3			74			mmBTU
Effect of derivative instruments on statements of income and comprehensive income	'
	The effect of derivative instruments not in a hedging relationship on the Consolidated Statements of Income during 2013 and 2012 are summarized in the following tables:
		Year Ended December 31
		Commodity				FTRs				Interest Rate Swaps				Total
		Contracts
		(In millions)
	2013
	Unrealized Gain (Loss) Recognized in:
	Other Operating Expense	$	11			$	(8	)		$	—			$	3
	Realized Gain (Loss) Reclassified to:
	Revenues	$	46			$	21			$	—			$	67
	Purchased Power Expense	(38		)		—				—				(38		)
	Other Operating Expense	—				(36		)		—				(36		)
	Fuel Expense	(2		)		—				—				(2		)
	2012
	Unrealized Gain Recognized in:
	Other Operating Expense	$	89			$	13			$	—			$	102
	Realized Gain (Loss) Reclassified to:
	Revenues	$	302			$	22			$	—			$	324
	Purchased Power Expense	(277		)		—				—				(277		)
	Other Operating Expense	—				(61		)		—				(61		)
	Fuel Expense	5				—				—				5
	Interest Expense	—				—				6				6
Derivative instruments subject to regulatory accounting	'
	The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during 2013 and 2012 are summarized in the following table:
			Year Ended December 31
	Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				LCAPP				Regulated FTRs				Total
			(In millions)
	2013
	Unrealized Gain (Loss) on Derivative Instrument		$	(23	)		$	(22	)		$	1			$	(44	)
	Realized Gain (Loss) on Derivative Instrument		75				166				(1		)		240
	2012
	Unrealized Gain (Loss) on Derivative Instrument		$	(201	)		$	(144	)		$	1			$	(344	)
	Realized Gain on Derivative Instrument		240				—				7				247
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 certain contracts that are deferred for future recovery from (or credit to) customers during 2013 and 2012:
			Year Ended December 31
	Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				LCAPP				Regulated FTRs				Total
			(In millions)
	Outstanding net liability as of January 1, 2013		$	(254	)		$	(144	)		$	—			$	(398	)
	Additions/Change in value of existing contracts		(23		)		(22		)		1				(44		)
	Settled contracts		75				166				(1		)		240
	Outstanding net liability as of December 31, 2013		$	(202	)		$	—			$	—			$	(202	)
	Outstanding net liability as of January 1, 2012		$	(293	)		$	—			$	(8	)		$	(301	)
	Additions/Change in value of existing contracts		(201		)		(144		)		1				(344		)
	Settled contracts		240				—				7				247
	Outstanding net liability as of December 31, 2012		$	(254	)		$	(144	)		$	—			$	(398	)

Impairment_of_Longlived_Assets1

Impairment of Long-lived Assets (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Schedule of Generating Plant Retirements	'
	On July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating the following generating units by October 9, 2013:
	Generating Units	MW Capacity	Location
	Hatfield's Ferry, Units 1-3	1,710	Masontown, Pennsylvania
	Mitchell, Units 2-3	370	Courtney, Pennsylvania

Capitalization_Tables

Capitalization (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013, 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, 2013 and 2012:
		As of December 31, 2013				As of December 31
	(Dollar amounts in millions)	Maturity Date		Interest Rate		2013				2012
	FirstEnergy:
	FMBs	2014 - 2043		3.340% - 9.740%		$	3,166			$	2,587
	Secured notes - fixed rate	2017 - 2037		6.150% - 7.880%		1,804				2,113
	Secured notes - variable rate					—				50
	Total secured notes					1,804				2,163
	Unsecured notes - fixed rate	2014 - 2039		3.500% - 7.350%		11,076				11,145
	Unsecured notes - variable rate	2014 - 2015		0.020% - 1.665%		959				959
	Total unsecured notes					12,035				12,104
	Capital lease obligations					188				176
	Unamortized debt premiums					9				45
	Unamortized fair value adjustments					44				103
	Currently payable long-term debt					(1,415		)		(1,999		)
	Total long-term debt and other long-term obligations					$	15,831			$	15,179
	FES:
	Secured notes - fixed rate	2015 - 2017		5.150% - 12.000%		$	188			$	689
	Secured notes - variable rate					—				50
	Total secured notes					188				739
	Unsecured notes - fixed rate	2014 - 2039		2.150% - 6.800%		2,077				2,769
	Unsecured notes - variable rate	2014 - 2015		0.130% - 0.160%		736				686
	Total unsecured notes					2,813				3,455
	Capital lease obligations					22				27
	Unamortized debt discounts					(1		)		(1		)
	Currently payable long-term debt					(892		)		(1,102		)
	Total long-term debt and other long-term obligations					$	2,130			$	3,118
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, 2013. PCRBs that can be tendered for mandatory purchase prior to maturity are reflected in 2014.
	Year	FirstEnergy				FES
		(In millions)
	2014	$	1,376			$	887
	2015	1,264				391
	2016	1,041				417
	2017	1,641				163
	2018	1,453				266
Outstanding PCRBs for the next three years	'
	The following table classifies the outstanding fixed rate put 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)
	2014	$	835			$	762
	2015	313				313
	2016	391				391
	2017	130				130
	2018	125				125
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, 2013, are as follows:
		Aggregate LOC Amount				Annual Fees
		(In millions)
	FirstEnergy	$	818			1.65% to 3.30%
	FES	744				1.65% to 3.30%

ShortTerm_Borrowings_and_Bank_1

Short-Term Borrowings and Bank Lines of Credit (Tables)	12 Months Ended
	Dec. 31, 2013
Short-term Borrowings and Bank Lines of Credit [Abstract]	'
Liquidity	'
	FirstEnergy’s available liquidity as of January 31, 2014, was as follows:
	Borrower(s)		Type		Maturity		Commitment				Available Liquidity
							(In millions)
	FirstEnergy(1)		Revolving		May-18		$	2,500			$	224
	FES / AE Supply		Revolving		May-18		2,500				2,489
	FET(2)		Revolving		May-18		1,000				—
					Subtotal		$	6,000			$	2,713
					Cash		—				48
					Total		$	6,000			$	2,761
	-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, 2013:
	Borrower		Revolving Credit Facility Sub-Limits					Regulatory and Other Short-Term Debt Limitations
			(In millions)
	FE			$	2,500				$	—		(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					850			(3)
	ME			300					500			(3)
	PN			300					300			(3)
	WP			200					200			(3)
	MP			150					500			(3)
	PE			150					150			(3)
	ATSI			100					500			(3)
	Penn			50					50			(3)
	TrAIL			200					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, 2013 and 2012, were as follows:
			2013			2012
	FirstEnergy		1.8	%		1.97	%

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations (Tables) [Abstract]	'
Fair values of the decommissioning trust assets Text Block	'
	The fair values of the decommissioning trust assets as of December 31, 2013 and 2012 were as follows:
		2013			2012
		(In millions)
	FirstEnergy	$	2,201		$	2,204
	FES	$	1,276		$	1,283
Changes to the asset retirement obligations	'
	The following table summarizes the changes to the ARO balances during 2013 and 2012:
	ARO Reconciliation	FirstEnergy			FES
		(In millions)
	Balance, January 1, 2012	$	1,497		$	904
	Liabilities settled	(2		)	(1		)
	Accretion	104			62
	Balance, December 31, 2012	$	1,599		$	965
	Liabilities settled	(18		)	(18		)
	Accretion	115			71
	Revisions in estimated cash flows	(18		)	(3		)
	Balance, December 31, 2013	$	1,678		$	1,015

Commitments_Guarantees_and_Con1

Commitments, Guarantees and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013:
	Collateral Provisions	FES		AE Supply		Utilities		Total
		(In millions)
	Split Rating (One rating agency's rating below investment grade)	$	496	$	6	$	53	$	555
	BB+/Ba1 Credit Ratings	$	542	$	6	$	53	$	601
	Full impact of credit contingent contractual obligations	$	777	$	58	$	88	$	923

Transactions_With_Affiliated_C1

Transactions With Affiliated Companies (Tables)	12 Months Ended
	Dec. 31, 2013
Transactions With Affiliated Companies (Tables) [Abstract]	'
Affiliated Company Transactions	'
	The primary affiliated company transactions for FES during the three years ended December 31, 2013 are as follows:
	FES	2013		2012		2011
		(In millions)
	Revenues:
	Electric sales to affiliates	$	652	$	515	$	752
	Other	6		16		80
	Expenses:
	Purchased power from affiliates	486		451		242
	Fuel	—		2		37
	Support services	619		570		655
	Investment Income:
	Interest income from FE	2		2		2
	Interest Expense:
	Interest expense to affiliates	4		10		8
	Interest expense to FE	6		1		1

Supplemental_Guarantor_Informa1

Supplemental Guarantor Information (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Guarantor Information [Abstract]	'
Condensed Consolidating Statements of Income and Comprehensive Income	'
	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
	(Unaudited)
	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
	Pensions and OPEB mark-to-market adjustments	(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	5			1			25			(15		)	16
	Miscellaneous income, including net income from equity investees	846			24			—			(842		)	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	(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:
	Pensions 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 STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
	(Unaudited)
	For the Year Ended December 31, 2012	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	STATEMENTS OF INCOME
	REVENUES	$	5,804		$	2,100		$	1,895		$	(3,905	)	$	5,894
	OPERATING EXPENSES:
	Fuel	—			1,077			210			—			1,287
	Purchased power from affiliates	4,098			—			258			(3,905		)	451
	Purchased power from non-affiliates	1,881			6			—			—			1,887
	Other operating expenses	434			334			539			49			1,356
	Pensions and OPEB mark-to-market adjustments	(2		)	52			116			—			166
	Provision for depreciation	4			116			157			(5		)	272
	General taxes	79			36			21			—			136
	Total operating expenses	6,494			1,621			1,301			(3,861		)	5,555
	OPERATING INCOME (LOSS)	(690		)	479			594			(44		)	339
	OTHER INCOME (EXPENSE):
	Investment income	2			15			67			(18		)	66
	Miscellaneous income, including net income from equity investees	1,284			20			—			(1,269		)	35
	Interest expense — affiliates	(18		)	(7		)	(4		)	19			(10		)
	Interest expense — other	(93		)	(110		)	(50		)	62			(191		)
	Capitalized interest	—			4			33			—			37
Total other income (expense)	1,175			(78		)	46			(1,206		)	(63		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	485			401			640			(1,250		)	276
INCOME TAXES (BENEFITS)	298			(269		)	62			12			103
INCOME FROM CONTINUING OPERATIONS	187			670			578			(1,262		)	173
Discontinued operations (net of income taxes of $8)	—			14			—			—			14
NET INCOME	$	187		$	684		$	578		$	(1,262	)	$	187
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	187		$	684		$	578		$	(1,262	)	$	187
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	6			6			—			(6		)	6
Amortized gain on derivative hedges	(9		)	—			—			—			(9		)
Change in unrealized gain on available-for-sale securities	(5		)	—			(5		)	5			(5		)
Other comprehensive income (loss)	(8		)	6			(5		)	(1		)	(8		)
Income taxes (benefits) on other comprehensive income (loss)	(4		)	1			(2		)	1			(4		)
Other comprehensive income (loss), net of tax	(4		)	5			(3		)	(2		)	(4		)
COMPREHENSIVE INCOME	$	183		$	689		$	575		$	(1,264	)	$	183
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)
For the Year Ended December 31, 2011	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	5,387		$	2,642		$	1,647		$	(4,223	)	$	5,453
OPERATING EXPENSES:
Fuel	12			1,138			194			—			1,344
Purchased power from affiliates	4,208			5			252			(4,223		)	242
Purchased power from non-affiliates	1,378			3			—			—			1,381
Other operating expenses	574			416			578			51			1,619
Pensions and OPEB mark-to-market adjustments	10			68			93			—			171
Provision for depreciation	4			124			150			(6		)	272
General taxes	64			37			23			—			124
Impairment of long-lived assets	—			294			—			—			294
Total operating expenses	6,250			2,085			1,290			(4,178		)	5,447
OPERATING INCOME (LOSS)	(863		)	557			357			(45		)	6
OTHER INCOME (EXPENSE):
Investment income	1			—			56			—			57
Miscellaneous income, including net income from equity investees	924			24			—			(918		)	30
Interest expense — affiliates	(2		)	(3		)	(2		)	(1		)	(8		)
Interest expense — other	(94		)	(109		)	(64		)	64			(203		)
Capitalized interest	—			12			23			—			35
Total other income (expense)	829			(76		)	13			(855		)	(89		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(34		)	481			370			(900		)	(83		)
INCOME TAXES (BENEFITS)	25			(117		)	58			18			(16		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	(59		)	598			312			(918		)	(67		)
Discontinued operations (net of income taxes of $5)	—			8			—			—			8
NET INCOME (LOSS)	$	(59	)	$	606		$	312		$	(918	)	$	(59	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(59	)	$	606		$	312		$	(918	)	$	(59	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(12		)	(13		)	—			13			(12		)
Amortized loss on derivative hedges	12			—			—			—			12
Change in unrealized gain on available-for-sale securities	16			—			15			(15		)	16
Other comprehensive income (loss)	16			(13		)	15			(2		)	16
Income taxes (benefits) on other comprehensive income (loss)	2			(8		)	5			3			2
Other comprehensive income (loss), net of tax	14			(5		)	10			(5		)	14
COMPREHENSIVE INCOME (LOSS)	$	(45	)	$	601		$	322		$	(923	)	$	(45	)
Condensed Consolidating Balance Sheets	'
	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING BALANCE SHEETS
	(Unaudited)
	As of December 31, 2013	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	ASSETS
	CURRENT ASSETS:
	Cash and cash equivalents	$	—		$	2		$	—		$	—		$	2
	Receivables-
	Customers	539			—			—			—			539
	Affiliated companies	938			787			227			(916		)	1,036
	Other	52			12			17			—			81
	Notes receivable from affiliated companies	203			23			683			(909		)	—
	Materials and supplies	76			159			213			—			448
	Derivatives	165			—			—			—			165
	Prepayments and other	81			50			7			—			138
		2,054			1,033			1,147			(1,825		)	2,409
	PROPERTY, PLANT AND EQUIPMENT:
	In service	104			6,105			6,645			(382		)	12,472
	Less — Accumulated provision for depreciation	28			1,953			2,962			(188		)	4,755
		76			4,152			3,683			(194		)	7,717
	Construction work in progress	23			148			1,137			—			1,308
		99			4,300			4,820			(194		)	9,025
	INVESTMENTS:
	Nuclear plant decommissioning trusts	—			—			1,276			—			1,276
	Investment in affiliated companies	5,801			—			—			(5,801		)	—
	Other	—			11			—			—			11
		5,801			11			1,276			(5,801		)	1,287
	ASSETS HELD FOR SALE (Note 20)	—			122			—			—			122
	DEFERRED CHARGES AND OTHER ASSETS:
	Accumulated deferred income tax benefits	—			131			—			(131		)	—
	Customer intangibles	95			—			—			—			95
	Goodwill	23			—			—			—			23
	Property taxes	—			15			26			—			41
	Unamortized sale and leaseback costs	—			—			—			168			168
	Derivatives	53			—			—			—			53
	Other	188			228			18			(155		)	279
		359			374			44			(118		)	659
		$	8,313		$	5,840		$	7,287		$	(7,938	)	$	13,502
	LIABILITIES AND CAPITALIZATION
	CURRENT LIABILITIES:
	Currently payable long-term debt	$	1		$	367		$	547		$	(23	)	$	892
	Short-term borrowings-
	Affiliated companies	977			212			151			(909		)	431
	Other	—			4			—			—			4
	Accounts payable-
	Affiliated companies	741			400			362			(738		)	765
	Other	94			196			—			—			290
	Accrued taxes	204			23			23			(184		)	66
	Derivatives	110			—			—			—			110
	Other	70			63			18			46			197
		2,197			1,265			1,101			(1,808		)	2,755
	CAPITALIZATION:
	Total equity	5,312			2,283			3,493			(5,776		)	5,312
	Long-term debt and other long-term obligations	712			1,860			742			(1,184		)	2,130
		6,024			4,143			4,235			(6,960		)	7,442
	NONCURRENT LIABILITIES:
	Deferred gain on sale and leaseback transaction	—			—			—			858			858
	Accumulated deferred income taxes	32			—			736			(27		)	741
	Asset retirement obligations	—			187			828			—			1,015
	Retirement benefits	22			163			—			—			185
	Derivatives	14			—			—			—			14
	Other	24			82			387			(1		)	492
	92			432			1,951			830			3,305
	$	8,313		$	5,840		$	7,287		$	(7,938	)	$	13,502
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of December 31, 2012	FES			FG			NG			Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—		$	3		$	—		$	—		$	3
Receivables-
Customers	483			—			—			—			483
Affiliated companies	232			417			478			(748		)	379
Other	56			19			16			—			91
Notes receivable from affiliated companies	366			7			607			(704		)	276
Materials and supplies	66			231			208			—			505
Derivatives	158			—			—			—			158
Prepayments and other	38			39			10			—			87
	1,399			716			1,319			(1,452		)	1,982
PROPERTY, PLANT AND EQUIPMENT:
In service	91			5,899			6,391			(384		)	11,997
Less — Accumulated provision for depreciation	32			1,915			2,646			(185		)	4,408
	59			3,984			3,745			(199		)	7,589
Construction work in progress	34			230			877			—			1,141
	93			4,214			4,622			(199		)	8,730
INVESTMENTS:
Nuclear plant decommissioning trusts	—			—			1,283			—			1,283
Investment in affiliated companies	4,972			—			—			(4,972		)	—
Other	—			12			—			—			12
	4,972			12			1,283			(4,972		)	1,295
ASSETS HELD FOR SALE	—			—			—			—			—
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—			313			—			(313		)	—
Customer intangibles	110			—			—			—			110
Goodwill	24			—			—			—			24
Property taxes	—			14			22			—			36
Unamortized sale and leaseback costs	—			—			—			119			119
Derivatives	99			—			—			—			99
Other	160			194			5			(106		)	253
	393			521			27			(300		)	641
	$	6,857		$	5,463		$	7,251		$	(6,923	)	$	12,648
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1		$	586		$	537		$	(22	)	$	1,102
Short-term borrowings-
Affiliated companies	358			346			—			(704		)	—
Other	—			4			—			—			4
Accounts payable-
Affiliated companies	748			143			583			(748		)	726
Other	63			96			—			—			159
Accrued taxes	126			25			20			—			171
Derivatives	124			—			—			—			124
Other	71			148			15			46			280
	1,491			1,348			1,155			(1,428		)	2,566
CAPITALIZATION:
Total equity	3,763			1,787			3,165			(4,952		)	3,763
Long-term debt and other long-term obligations	1,482			2,009			834			(1,207		)	3,118
	5,245			3,796			3,999			(6,159		)	6,881
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—			—			—			892			892
Accumulated deferred income taxes	28			—			714			(227		)	515
Asset retirement obligations	—			29			936			—			965
Retirement benefits	26			215			—			—			241
Derivatives	37			—			—			—			37
Other	30			75			447			(1		)	551
	121			319			2,097			664			3,201
	$	6,857		$	5,463		$	7,251		$	(6,923	)	$	12,648
Condensed Consolidating Statements of Cash Flows	'
	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	(Unaudited)
	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
	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	(Unaudited)
	For the Year Ended December 31, 2012	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(1,063	)	$	639		$	1,266		$	(21	)	$	821
	CASH FLOWS FROM FINANCING ACTIVITIES:
	New Financing-
	Long-term debt	—			351			299			—			650
	Short-term borrowings, net	—			260			—			(257		)	3
	Redemptions and Repayments-
	Long-term debt	(1		)	(288		)	(161		)	21			(429		)
	Short-term borrowings, net	(707		)	—			(32		)	739			—
	Common stock dividend payment	—			(2,000		)	—			2,000			—
	Other	(1		)	(8		)	(3		)	—			(12		)
	Net cash provided from (used for) financing activities	(709		)	(1,685		)	103			2,503			212
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Property additions	(14		)	(273		)	(508		)	—			(795		)
	Nuclear fuel	—			—			(286		)	—			(286		)
	Proceeds from asset sales	—			17			—			—			17
	Sales of investment securities held in trusts	—			—			1,464			—			1,464
	Purchases of investment securities held in trusts	—			—			(1,502		)	—			(1,502		)
	Loans to affiliated companies, net	(211		)	1,338			(538		)	(482		)	107
	Dividend received	2,000			—			—			(2,000		)	—
	Other	(3		)	(40		)	1			—			(42		)
	Net cash provided from (used for) investing activities	1,772			1,042			(1,369		)	(2,482		)	(1,037		)
	Net change in cash and cash equivalents	—			(4		)	—			—			(4		)
	Cash and cash equivalents at beginning of period	—			7			—			—			7
	Cash and cash equivalents at end of period	$	—		$	3		$	—		$	—		$	3
	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	(Unaudited)
	For the Year Ended December 31, 2011	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(790	)	$	926		$	702		$	(19	)	$	819
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			140			107			—			247
Redemptions and Repayments-
Long-term debt	(136		)	(362		)	(377		)	19			(856		)
Short-term borrowings, net	1,065			78			32			(1,186		)	(11		)
Other	(9		)	(1		)	(1		)	—			(11		)
Net cash provided from (used for) financing activities	920			(145		)	(239		)	(1,167		)	(631		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(24		)	(205		)	(371		)	—			(600		)
Nuclear fuel	—			—			(149		)	—			(149		)
Proceeds from asset sales	9			590			—			—			599
Sales of investment securities held in trusts	—			—			1,843			—			1,843
Purchases of investment securities held in trusts	—			—			(1,890		)	—			(1,890		)
Loans to affiliated companies, net	(120		)	(1,157		)	105			1,186			14
Other	5			(11		)	(1		)	—			(7		)
Net cash used for investing activities	(130		)	(783		)	(463		)	1,186			(190		)
Net change in cash and cash equivalents	—			(2		)	—			—			(2		)
Cash and cash equivalents at beginning of period	—			9			—			—			9
Cash and cash equivalents at end of period	$	—		$	7		$	—		$	—		$	7

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Financial Information	'
	Segment Financial Information
	For the Years Ended December 31,	Regulated Distribution		Regulated Transmission		Competitive Energy Services			Other/Corporate			Reconciling Adjustments			Consolidated
		(In millions)
	2013
	External revenues	$	8,738	$	741	$	5,725		$	(121	)	$	(166	)	$	14,917
	Internal revenues	—		—		770			—			(770		)	—
	Total revenues	8,738		741		6,495			(121		)	(936		)	14,917
	Depreciation, amortization and deferrals	1,135		124		439			43			—			1,741
	Investment income	57		—		14			9			(44		)	36
	Interest expense	543		93		222			158			—			1,016
	Income taxes (benefits)	301		129		(141		)	(78		)	(16		)	195
	Income (loss) from continuing operations	501		214		(237		)	(130		)	27			375
	Discontinued operations, net of tax	—		—		17			—			—			17
	Net income (loss)	501		214		(220		)	(130		)	27			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
	2012
	External revenues	$	9,060	$	740	$	5,778		$	(119	)	$	(188	)	$	15,271
	Internal revenues	—		—		866			—			(864		)	2
	Total revenues	9,060		740		6,644			(119		)	(1,052		)	15,273
	Depreciation, amortization and deferrals	493		111		409			38			—			1,051
	Investment income (loss)	84		1		66			(5		)	(69		)	77
	Interest expense	540		92		284			85			—			1,001
	Income taxes (benefits)	295		133		83			(34		)	68			545
	Income (loss) from continuing operations	540		226		199			(155		)	(55		)	755
	Discontinued operations, net of tax	—		—		16			—			—			16
	Net income (loss)	540		226		215			(155		)	(55		)	771
	Total assets	27,150		4,865		18,087			392			—			50,494
	Total goodwill	5,025		526		896			—			—			6,447
	Property additions	1,074		507		1,014			83			—			2,678
	2011
	External revenues	$	9,913	$	660	$	5,783		$	(114	)	$	(204	)	$	16,038
	Internal revenues	—		—		1,237			—			(1,170		)	67
	Total revenues	9,913		660		7,020			(114		)	(1,374		)	16,105
	Depreciation, amortization and deferrals	846		110		411			24			—			1,391
	Investment income	99		—		56			1			(42		)	114
	Interest expense	530		89		298			91			—			1,008
	Income taxes (benefits)	287		114		214			(87		)	38			566
	Income (loss) from continuing operations	488		194		364			(149		)	(41		)	856
	Discontinued operations, net of tax	—		—		13			—			—			13
	Net income (loss)	488		194		377			(149		)	(41		)	869
	Total assets	25,534		4,463		16,796			617			—			47,410
	Total goodwill	5,025		526		890			—			—			6,441
	Property additions	868		390		778			93			—			2,129

Merger_Tables

Merger (Tables)	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Purchase price calculation	'
	The total consideration in the merger was based on the closing price of a share of FE common stock on February 24, 2011, the day prior to the date the merger was completed, and was calculated as follows (in millions, except per share data):
	Shares of AE common stock outstanding on February 24, 2011	$	170
	Exchange ratio	0.667
	Number of shares of FirstEnergy common stock issued	113
	Closing price of FirstEnergy common stock on February 24, 2011	38.16
	Fair value of shares issued by FirstEnergy	4,327
	Fair value of replacement share-based compensation awards relating to pre-merger service	27
	Total consideration transferred	$	4,354
The preliminary allocation of the total consideration transferred to the assets acquired and liabilities assumed	'
	The allocation of the purchase price was as follows:
	(In millions)
	Current assets	$	1,493
	Property, plant and equipment	9,660
	Investments	138
	Goodwill	872
	Other noncurrent assets	1,353
	Current liabilities	(718		)
	Noncurrent liabilities	(3,450		)
	Long-term debt and other long-term obligations	(4,994		)
		$	4,354
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger	'
	The valuation of the additional intangible assets and liabilities recorded as a result of the merger is as follows:
	(In millions)		Preliminary Valuation		Weighted Average Amortization Period
	Above market contracts:
	Energy contracts		$	189	10 years
	NUG contracts		124		25 years
	Coal supply contracts		516		8 years
			829
	Below market contracts:
	NUG contracts		143		13 years
	Coal supply contracts		83		7 years
	Transportation contract		35		8 years
			261
	Net intangible assets		$	568
Revenue and earnings of Allegheny	'
	Revenues and earnings of Allegheny included in FirstEnergy’s Consolidated Statements of Income for the periods beginning on the February 25, 2011, merger date are as follows:
			February 25 -		Year Ended		Year Ended
	(In millions, except per share amounts)		31-Dec-11		31-Dec-12		31-Dec-13
	Total revenues		$	3,966	$	4,410	$	4,331
	Earnings (Losses) Available to FirstEnergy Corp.(1)		$	147	$	356	$	(31	)
	Basic Earnings (Losses) Per Share		$	0.37	$	0.85	$	(0.07	)
	Diluted Earnings (Losses) Per Share		$	0.37	$	0.85	$	(0.07	)
	-1	Includes Allegheny’s after-tax merger costs of $58 million, $1 million and $1 million during 2011, 2012 and 2013, respectively.
Summary of consolidated results of operations	'
	The unaudited pro forma financial information has been presented below for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger been completed on January 1, 2010, or the future consolidated results of operations of the combined company.
	(Pro forma amounts in millions, except per share amounts)		2011
	Revenues		$	17,449
	Earnings available to FirstEnergy		$	979
	Basic Earnings Per Share		$	2.34
	Diluted Earnings Per Share		$	2.33

Summary_of_Quarterly_Financial1

Summary of Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data [Abstract]	'
Schedule of Quarterly Financial Information	'
	The following summarizes certain consolidated operating results by quarter for 2013 and 2012.
	FirstEnergy
	CONSOLIDATED STATEMENTS OF INCOME
	(In millions, except per share amounts)	2013											2012
		Dec. 31			Sept. 30		30-Jun			Mar. 31			Dec. 31			Sept. 30		30-Jun			Mar. 31
	Revenues	$	3,647		$	4,036	$	3,511		$	3,723		$	3,493		$	4,052	$	3,746		$	3,982
	Other operating expense	948			877		886			882			1,163			861		920			816
	Pensions and OPEB mark-to-market	(256		)	—		—			—			609			—		—			—
	Provision for depreciation	293			316		300			293			285			272		284			278
	Impairment of long-lived assets	322			—		473			—			—			—		—			—
	Operating Income (Loss)	401			512		46			648			(39		)	902		549			740
	Income (loss) from continuing operations before income taxes	208			286		(230		)	306			(258		)	729		307			522
	Income taxes (benefits)	66			77		(62		)	114			(105		)	307		123			220
	Income (loss) from continuing operations	142			209		(168		)	192			(153		)	422		184			302
	Discontinued operations (net of income taxes)	—			9		4			4			5			3		4			4
	Net Income (Loss)	142			218		(164		)	196			(148		)	425		188			306
	Earnings (loss) available to FirstEnergy Corp.	142			218		(164		)	196			(148		)	425		187			306
	Earnings (loss) per share of common stock-
	Basic - Continuing Operations	0.34			0.5		(0.40		)	0.46			(0.36		)	1.01		0.44			0.72
	Basic - Discontinued Operations (Note 20)	—			0.02		0.01			0.01			0.01			0.01		0.01			0.01
	Basic - Earnings Available to FirstEnergy Corp.	0.34			0.52		(0.39		)	0.47			(0.35		)	1.02		0.45			0.73
	Diluted - Continuing Operations	0.34			0.5		(0.40		)	0.46			(0.36		)	1		0.44			0.72
	Diluted - Discontinued Operations (Note 20)	—			0.02		0.01			0.01			0.01			0.01		0.01			0.01
	Diluted - Earnings Available to FirstEnergy Corp.	0.34			0.52		(0.39		)	0.47			(0.35		)	1.01		0.45			0.73
	FES
	CONSOLIDATED STATEMENTS OF INCOME
	(In millions)	2013											2012
		Dec. 31			Sept. 30		30-Jun			Mar. 31			Dec. 31			Sept. 30		30-Jun			Mar. 31
	Revenues	$	1,518		$	1,679	$	1,452		$	1,524		$	1,383		$	1,550	$	1,450		$	1,511
	Other operating expense	382			339		387			379			328			342		392			294
	Pensions and OPEB mark-to-market	(81		)	—		—			—			166			—		—			—
	Provision for depreciation	75			80		76			75			72			70		68			62
	Operating Income (Loss)	121			65		(39		)	95			(56		)	167		9			219
	Income (loss) from continuing operations before income taxes	114			56		(117		)	(1		)	(74		)	161		(6		)	195
	Income taxes (benefits)	25			23		(42		)	—			(36		)	65		(1		)	75
	Income (loss) from continuing operations	89			33		(75		)	(1		)	(38		)	96		(5		)	120
	Discontinued operations (net of income taxes)	—			7		4			3			3			5		4			2
	Net Income (Loss)	89			40		(71		)	2			(35		)	101		(1		)	122

Organization_Basis_of_Presenta3

Organization, Basis of Presentation and Significant Accounting Policies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory assets on the Balance Sheets	'	'
Regulatory Assets	$1,854	$2,330
Increase (Decrease) in Regulatory Assets	-476	'
Regulatory transition costs	'	'
Regulatory assets on the Balance Sheets	'	'
Regulatory Assets	266	293
Increase (Decrease) in Regulatory Assets	-27	'
Customer receivables for future income taxes	'	'
Regulatory assets on the Balance Sheets	'	'
Regulatory Assets	518	505
Increase (Decrease) in Regulatory Assets	13	'
Nuclear decommissioning and spent fuel disposal costs	'	'
Regulatory assets on the Balance Sheets	'	'
Regulatory Assets	-198	-219
Increase (Decrease) in Regulatory Assets	21	'
Asset removal costs	'	'
Regulatory assets on the Balance Sheets	'	'
Regulatory Assets	-362	-372
Increase (Decrease) in Regulatory Assets	10	'
Deferred transmission costs	'	'
Regulatory assets on the Balance Sheets	'	'
Regulatory Assets	112	352
Increase (Decrease) in Regulatory Assets	-240	'
Deferred generation costs	'	'
Regulatory assets on the Balance Sheets	'	'
Regulatory Assets	346	379
Increase (Decrease) in Regulatory Assets	-33	'
Deferred distribution costs	'	'
Regulatory assets on the Balance Sheets	'	'
Regulatory Assets	194	231
Increase (Decrease) in Regulatory Assets	-37	'
Contract valuations	'	'
Regulatory assets on the Balance Sheets	'	'
Regulatory Assets	260	463
Increase (Decrease) in Regulatory Assets	-203	'
Storm-related costs	'	'
Regulatory assets on the Balance Sheets	'	'
Regulatory Assets	455	469
Increase (Decrease) in Regulatory Assets	-14	'
Other	'	'
Regulatory assets on the Balance Sheets	'	'
Regulatory Assets	263	229
Increase (Decrease) in Regulatory Assets	$34	'

Organization_Basis_of_Presenta4

Organization, Basis of Presentation and Significant Accounting Policies (Details 1) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Receivables from customers	'	'
Customers	$1,720	$1,614
FES	'	'
Receivables from customers	'	'
Customers	539	483
Billed	'	'
Receivables from customers	'	'
Customers	1,010	893
Billed | FES	'	'
Receivables from customers	'	'
Customers	301	243
Unbilled	'	'
Receivables from customers	'	'
Customers	710	721
Unbilled | FES	'	'
Receivables from customers	'	'
Customers	$238	$240

Organization_Basis_of_Presenta5

Organization, Basis of Presentation and Significant Accounting Policies (Details 2) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	'	'	'	'	'	'	'	'	'	'	'
Income from continuing operations	$142	$209	($168)	$192	($153)	$422	$184	$302	$375	$755	$856
Less: Income attributable to noncontrolling interest	'	'	'	'	'	'	'	'	0	1	-16
Income from continuing operations available to common shareholders	'	'	'	'	'	'	'	'	375	754	872
Discontinued operations (Note 20)	0	9	4	4	5	3	4	4	17	16	13
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$142	$218	($164)	$196	($148)	$425	$187	$306	$392	$770	$885
Weighted average number of basic shares outstanding	'	'	'	'	'	'	'	'	418	418	399
Assumed exercise of dilutive stock options and awards	'	'	'	'	'	'	'	'	1	1	2
Weighted average number of diluted shares outstanding	'	'	'	'	'	'	'	'	419	419	401
Earnings per share:	'	'	'	'	'	'	'	'	'	'	'
Basic - Continuing Operations, in dollars per share	$0.34	$0.50	($0.40)	$0.46	($0.36)	$1.01	$0.44	$0.72	$0.90	$1.81	$2.19
Basic - Discontinued Operations (Note 20), in dollars per share	$0	$0.02	$0.01	$0.01	$0.01	$0.01	$0.01	$0.01	$0.04	$0.04	$0.03
Basic - Earnings Available to FirstEnergy Corp., in dollars per share	$0.34	$0.52	($0.39)	$0.47	($0.35)	$1.02	$0.45	$0.73	$0.94	$1.85	$2.22
Diluted earnings per share:	'	'	'	'	'	'	'	'	'	'	'
Diluted - Continuing Operations, in dollars per share	$0.34	$0.50	($0.40)	$0.46	($0.36)	$1	$0.44	$0.72	$0.90	$1.80	$2.18
Diluted - Discontinued Operations (Note 20), in dollars per share	$0	$0.02	$0.01	$0.01	$0.01	$0.01	$0.01	$0.01	$0.04	$0.04	$0.03
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share	$0.34	$0.52	($0.39)	$0.47	($0.35)	$1.01	$0.45	$0.73	$0.94	$1.84	$2.21
Shares excluded from the calculation of diluted shares outstanding, in shares	'	'	'	'	'	'	'	'	2	0	0

Organization_Basis_of_Presenta6

Organization, Basis of Presentation and Significant Accounting Policies (Details 3) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Property, Plant and Equipment	'	'
In service	$44,228	$43,210
Less - Accumulated depreciation	-13,280	-12,467
Property, plant and equipment in service net of accumulated provision for depreciation	30,948	30,743
Regulated Distribution	'	'
Property, Plant and Equipment	'	'
In service	23,098	21,473
Less - Accumulated depreciation	-6,514	-6,146
Property, plant and equipment in service net of accumulated provision for depreciation	16,584	15,327
Regulated Transmission	'	'
Property, Plant and Equipment	'	'
In service	5,564	5,078
Less - Accumulated depreciation	-1,511	-1,451
Property, plant and equipment in service net of accumulated provision for depreciation	4,053	3,627
Competitive Energy Services	'	'
Property, Plant and Equipment	'	'
In service	15,206	16,338
Less - Accumulated depreciation	-5,088	-4,739
Property, plant and equipment in service net of accumulated provision for depreciation	10,118	11,599
Other/Corporate	'	'
Property, Plant and Equipment	'	'
In service	360	321
Less - Accumulated depreciation	-167	-131
Property, plant and equipment in service net of accumulated provision for depreciation	$193	$190

Organization_Basis_of_Presenta7

Organization, Basis of Presentation and Significant Accounting Policies (Details 4)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Annual Composite Depreciation Rate	'	'	'
Annual Composite Depreciation Rate	2.60%	2.50%	2.40%
FES	'	'	'
Annual Composite Depreciation Rate	'	'	'
Annual Composite Depreciation Rate	3.10%	3.10%	3.10%

Organization_Basis_of_Presenta8

Organization, Basis of Presentation and Significant Accounting Policies (Details 5) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Scenario, Previously Reported

Regulated Distribution

Regulated Distribution

Regulated Distribution

Regulated Transmission

Regulated Transmission

Competitive Energy Services

Competitive Energy Services

Competitive Energy Services

Other/Corporate

Other/Corporate

Scenario, Previously Reported

Scenario, Previously Reported

Scenario, Previously Reported

Scenario, Previously Reported

Summary of changes in goodwill

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill, Beginning Balance

$6,447

$6,441

$6,447

$5,025

$5,025

$5,025

'

$526

$896

$890

$896

'

$0

Classification to Assets Held for Sale

-29

[1]

'

'

0

[1]

'

'

0

[1]

'

-29

[1]

'

'

0

[1]

'

West Virginia asset transfer

0

'

'

67

'

'

0

'

-67

'

'

0

'

Goodwill, Ending Balance

$6,418

$6,441

$6,447

$5,092

$5,025

$5,025

$526

$526

$800

$890

$896

$0

$0

[1]

See Note 20, Discontinued Operations and Assets Held for Sale.

Organization_Basis_of_Presenta9

Organization, Basis of Presentation and Significant Accounting Policies (Details Textuals) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jan. 31, 2009
Summary of Significant Accounting Policies (Textuals) [Abstract]	'	'	'	'
Prior period reclassification adjustment	$88	'	'	'
Regulatory assets that do not earn a current return	477	'	'	'
Net regulatory liabilities	440	480	'	'
Pumped storage hydroelectric station, Ownership percentage	'	'	'	16.67%
Net plant in service	30,948	30,743	'	'
Construction work in progress	2,304	2,293	'	'
Goodwill	6,418	6,447	6,441	'
West Virginia asset transfer	0	'	'	'
Other-than-temporary impairments	90	16	19	'
Bath County, Virginia	'	'	'	'
Summary of Significant Accounting Policies (Textuals) [Abstract]	'	'	'	'
Plant generation capacity	3,000	'	'	'
AGC | Bath County, Virginia	'	'	'	'
Summary of Significant Accounting Policies (Textuals) [Abstract]	'	'	'	'
Pumped storage hydroelectric station, Ownership percentage	40.00%	'	'	'
Plant generation capacity	1,200	'	'	'
Net plant in service	672	'	'	'
Construction work in progress	28	'	'	'
Virginia Electric and Power Company | Bath County, Virginia	'	'	'	'
Summary of Significant Accounting Policies (Textuals) [Abstract]	'	'	'	'
Pumped storage hydroelectric station, Ownership percentage	60.00%	'	'	'
FES	'	'	'	'
Summary of Significant Accounting Policies (Textuals) [Abstract]	'	'	'	'
Net plant in service	7,717	7,589	'	'
Construction work in progress	1,308	1,141	'	'
Goodwill	23	24	'	'
Other-than-temporary impairments	79	14	17	'
Competitive Energy Services	'	'	'	'
Summary of Significant Accounting Policies (Textuals) [Abstract]	'	'	'	'
Plant generation capacity	14,000	'	'	'
Net plant in service	10,118	11,599	'	'
Goodwill	800	896	890	'
West Virginia asset transfer	$67	'	'	'

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'
AOCI Beginning Balance	$385	$426	$425
Other comprehensive income (loss) before reclassifications	52	120	118
Amounts reclassified from AOCI	-153	-161	-117
Other comprehensive income (loss), net of tax	-101	-41	1
AOCI Ending Balance	284	385	426
FES	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'
AOCI Beginning Balance	72	76	62
Other comprehensive income (loss) before reclassifications	29	54	41
Amounts reclassified from AOCI	-47	-58	-27
Other comprehensive income (loss), net of tax	-18	-4	14
AOCI Ending Balance	54	72	76
Gains & Losses on Cash Flow Hedges	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'
AOCI Beginning Balance	-38	-39	-54
Other comprehensive income (loss) before reclassifications	0	0	-9
Amounts reclassified from AOCI	2	1	24
Other comprehensive income (loss), net of tax	2	1	15
AOCI Ending Balance	-36	-38	-39
Gains & Losses on Cash Flow Hedges | FES	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'
AOCI Beginning Balance	3	8	1
Other comprehensive income (loss) before reclassifications	0	0	-9
Amounts reclassified from AOCI	-4	-5	16
Other comprehensive income (loss), net of tax	-4	-5	7
AOCI Ending Balance	-1	3	8
Unrealized Gains on AFS Securities	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'
AOCI Beginning Balance	15	19	7
Other comprehensive income (loss) before reclassifications	29	41	49
Amounts reclassified from AOCI	-35	-45	-37
Other comprehensive income (loss), net of tax	-6	-4	12
AOCI Ending Balance	9	15	19
Unrealized Gains on AFS Securities | FES	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'
AOCI Beginning Balance	13	16	6
Other comprehensive income (loss) before reclassifications	26	38	42
Amounts reclassified from AOCI	-31	-41	-32
Other comprehensive income (loss), net of tax	-5	-3	10
AOCI Ending Balance	8	13	16
Defined Benefit Pension & OPEB Plans	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'
AOCI Beginning Balance	408	446	472
Other comprehensive income (loss) before reclassifications	23	79	78
Amounts reclassified from AOCI	-120	-117	-104
Other comprehensive income (loss), net of tax	-97	-38	-26
AOCI Ending Balance	311	408	446
Defined Benefit Pension & OPEB Plans | FES	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'
AOCI Beginning Balance	56	52	55
Other comprehensive income (loss) before reclassifications	3	16	8
Amounts reclassified from AOCI	-12	-12	-11
Other comprehensive income (loss), net of tax	-9	4	-3
AOCI Ending Balance	$47	$56	$52

Accumulated_Other_Comprehensiv3

Accumulated Other Comprehensive Income (Details 1) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Other operating expenses	$948	$877	$886	$882	$1,163	$861	$920	$816	$3,593	$3,760	$3,949
Interest expense - other	'	'	'	'	'	'	'	'	1,016	1,001	1,008
Investment income	'	'	'	'	'	'	'	'	-36	-77	-114
Total before taxes	'	'	'	'	'	'	'	'	-570	-1,300	-1,422
Income taxes (benefits)	66	77	-62	114	-105	307	123	220	195	545	566
Net of tax	-142	-218	164	-196	148	-425	-188	-306	-392	-771	-869
FES	'	'	'	'	'	'	'	'	'	'	'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Other operating expenses	382	339	387	379	328	342	392	294	1,487	1,356	1,619
Investment income	'	'	'	'	'	'	'	'	-16	-66	-57
Total before taxes	'	'	'	'	'	'	'	'	-52	-276	83
Income taxes (benefits)	25	23	-42	0	-36	65	-1	75	6	103	-16
Net of tax	-89	-40	71	-2	35	-101	1	-122	-60	-187	59
Reclassifications from AOCI | Gains & losses on cash flow hedges	'	'	'	'	'	'	'	'	'	'	'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total before taxes	'	'	'	'	'	'	'	'	3	1	38
Income taxes (benefits)	'	'	'	'	'	'	'	'	-1	0	-14
Net of tax	'	'	'	'	'	'	'	'	2	1	24
Reclassifications from AOCI | Gains & losses on cash flow hedges | FES	'	'	'	'	'	'	'	'	'	'	'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total before taxes	'	'	'	'	'	'	'	'	-6	-9	27
Income taxes (benefits)	'	'	'	'	'	'	'	'	2	4	-11
Net of tax	'	'	'	'	'	'	'	'	-4	-5	16
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts	'	'	'	'	'	'	'	'	'	'	'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Other operating expenses	'	'	'	'	'	'	'	'	-8	-9	26
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts | FES	'	'	'	'	'	'	'	'	'	'	'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Other operating expenses	'	'	'	'	'	'	'	'	-8	-9	26
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt	'	'	'	'	'	'	'	'	'	'	'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Interest expense - other	'	'	'	'	'	'	'	'	11	10	12
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	'	'	'	'	'	'	'	'	2	0	1
Reclassifications from AOCI | Unrealized gains on AFS securities	'	'	'	'	'	'	'	'	'	'	'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Investment income	'	'	'	'	'	'	'	'	-56	-72	-59
Income taxes (benefits)	'	'	'	'	'	'	'	'	21	27	22
Net of tax	'	'	'	'	'	'	'	'	-35	-45	-37
Reclassifications from AOCI | Unrealized gains on AFS securities | FES	'	'	'	'	'	'	'	'	'	'	'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Investment income	'	'	'	'	'	'	'	'	-49	-65	-51
Income taxes (benefits)	'	'	'	'	'	'	'	'	18	24	19
Net of tax	'	'	'	'	'	'	'	'	-31	-41	-32
Reclassifications from AOCI | Defined benefit pension and OPEB plans	'	'	'	'	'	'	'	'	'	'	'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Prior-service costs	'	'	'	'	'	'	'	'	-195	-191	-169
Income taxes (benefits)	'	'	'	'	'	'	'	'	75	74	65
Net of tax	'	'	'	'	'	'	'	'	-120	-117	-104
Reclassifications from AOCI | Defined benefit pension and OPEB plans | FES	'	'	'	'	'	'	'	'	'	'	'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Prior-service costs	'	'	'	'	'	'	'	'	-20	-20	-18
Income taxes (benefits)	'	'	'	'	'	'	'	'	8	8	7
Net of tax	'	'	'	'	'	'	'	'	($12)	($12)	($11)

Pension_and_Other_Postemployme2

Pension and Other Postemployment Benefits (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Amounts Recognized on the Balance Sheet:	'	'	'
Noncurrent liabilities	($2,689)	($3,080)	'
Pensions	'	'	'
Change in benefit obligation:	'	'	'
Benefit obligation as of January 1	8,975	7,977	'
Service cost	197	161	130
Interest cost	372	389	374
Plan participants' contributions	0	0	'
Plan amendments	2	8	'
Medicare retiree drug subsidy	0	0	'
Actuarial (gain) loss	-846	861	'
Benefits paid	-437	-421	'
Benefit obligation as of December 31	8,263	8,975	7,977
Change in fair value of plan assets:	'	'	'
Fair value of plan assets as of January 1	6,671	5,867	'
Actual return on plan assets	-77	611	'
Company contributions	14	614	'
Plan participants' contributions	0	0	'
Benefits paid	-437	-421	'
Fair value of plan assets as of December 31	6,171	6,671	5,867
Funded Status:	'	'	'
Funded Status	-2,092	-2,303	'
Accumulated benefit obligation	7,800	8,355	'
Amounts Recognized on the Balance Sheet:	'	'	'
Current liabilities	-15	-14	'
Noncurrent liabilities	-2,077	-2,289	'
Net liability as of December 31	-2,092	-2,303	'
Amounts Recognized in AOCI:	'	'	'
Prior service cost (credit)	48	58	'
Assumptions Used to Determine Benefit Obligations	'	'	'
Discount rate	5.00%	4.25%	'
Rate of compensation increase	4.20%	4.70%	'
Allocation of Plan Assets	'	'	'
Asset Allocation	100.00%	100.00%	'
Pensions | Equity securities	'	'	'
Allocation of Plan Assets	'	'	'
Asset Allocation	18.00%	15.00%	'
Pensions | Bonds	'	'	'
Allocation of Plan Assets	'	'	'
Asset Allocation	40.00%	47.00%	'
Pensions | Absolute return strategies	'	'	'
Allocation of Plan Assets	'	'	'
Asset Allocation	23.00%	22.00%	'
Pensions | Real estate	'	'	'
Allocation of Plan Assets	'	'	'
Asset Allocation	6.00%	5.00%	'
Pensions | Private equities	'	'	'
Allocation of Plan Assets	'	'	'
Asset Allocation	0.00%	1.00%	'
Pensions | Cash	'	'	'
Allocation of Plan Assets	'	'	'
Asset Allocation	13.00%	10.00%	'
Pensions | Qualified Plan	'	'	'
Funded Status:	'	'	'
Funded Status	-1,782	-1,967	'
Pensions | Non-qualified Plans	'	'	'
Funded Status:	'	'	'
Funded Status	-310	-336	'
OPEB	'	'	'
Change in benefit obligation:	'	'	'
Benefit obligation as of January 1	1,076	1,037	'
Service cost	13	12	13
Interest cost	37	47	48
Plan participants' contributions	15	17	'
Plan amendments	-37	-85	'
Medicare retiree drug subsidy	5	0	'
Actuarial (gain) loss	-107	152	'
Benefits paid	-123	-104	'
Benefit obligation as of December 31	879	1,076	1,037
Change in fair value of plan assets:	'	'	'
Fair value of plan assets as of January 1	508	528	'
Actual return on plan assets	56	48	'
Company contributions	39	19	'
Plan participants' contributions	15	17	'
Benefits paid	-123	-104	'
Fair value of plan assets as of December 31	495	508	528
Funded Status:	'	'	'
Funded Status	-384	-566	'
Accumulated benefit obligation	0	0	'
Amounts Recognized on the Balance Sheet:	'	'	'
Current liabilities	0	0	'
Noncurrent liabilities	-384	-566	'
Net liability as of December 31	-384	-566	'
Amounts Recognized in AOCI:	'	'	'
Prior service cost (credit)	($558)	($728)	'
Assumptions Used to Determine Benefit Obligations	'	'	'
Discount rate	4.75%	4.00%	'
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.00%	5.00%	'
Allocation of Plan Assets	'	'	'
Asset Allocation	100.00%	100.00%	'
OPEB | Equity securities	'	'	'
Allocation of Plan Assets	'	'	'
Asset Allocation	47.00%	39.00%	'
OPEB | Bonds	'	'	'
Allocation of Plan Assets	'	'	'
Asset Allocation	40.00%	40.00%	'
OPEB | Absolute return strategies	'	'	'
Allocation of Plan Assets	'	'	'
Asset Allocation	3.00%	4.00%	'
OPEB | Real estate	'	'	'
Allocation of Plan Assets	'	'	'
Asset Allocation	1.00%	1.00%	'
OPEB | Private equities	'	'	'
Allocation of Plan Assets	'	'	'
Asset Allocation	0.00%	0.00%	'
OPEB | Cash	'	'	'
Allocation of Plan Assets	'	'	'
Asset Allocation	9.00%	16.00%	'
OPEB | Pre Medicare	'	'	'
Assumptions Used to Determine Benefit Obligations	'	'	'
Health care cost trend rate assumed	7.25%	7.50%	'
Year that the rate reaches the ultimate trend rate	'2020	'2020	'
OPEB | Post Medicare	'	'	'
Assumptions Used to Determine Benefit Obligations	'	'	'
Health care cost trend rate assumed	7.75%	8.00%	'
Year that the rate reaches the ultimate trend rate	'2020	'2020	'

Pension_and_Other_Postemployme3

Pension and Other Postemployment Benefits (Details 1) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pensions	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Service cost	$197	$161	$130
Interest cost	372	389	374
Expected return on plan assets	-501	-486	-446
Amortization of prior service cost (credit)	12	12	14
Other adjustments (settlements, curtailments, etc.)	0	0	6
Pensions & OPEB mark-to-market adjustment	-267	735	729
Net periodic cost (credit)	-187	811	807
OPEB	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Service cost	13	12	13
Interest cost	37	47	48
Expected return on plan assets	-34	-37	-40
Amortization of prior service cost (credit)	-207	-203	-203
Other adjustments (settlements, curtailments, etc.)	0	0	0
Pensions & OPEB mark-to-market adjustment	-129	140	36
Net periodic cost (credit)	($320)	($41)	($146)

Pension_and_Other_Postemployme4

Pension and Other Postemployment Benefits (Details 2)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pensions	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Weighted-average discount rate	4.25%	5.00%	5.50%
Expected long-term return on plan assets	7.75%	7.75%	8.25%
Rate of compensation increase	4.70%	5.20%	5.20%
OPEB	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Weighted-average discount rate	4.00%	4.75%	5.00%
Expected long-term return on plan assets	7.75%	7.75%	8.50%

Pension_and_Other_Postemployme5

Pension and Other Postemployment Benefits (Details 3) (Pensions, USD $)	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
In Millions, unless otherwise specified
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	$6,258	$6,707	[1]	'
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	782	652		'
Asset Allocation	13.00%	10.00%		'
Domestic	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	704	555		'
Asset Allocation	11.00%	8.00%		'
International	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	422	428		'
Asset Allocation	7.00%	7.00%		'
Government bonds	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	314	568		'
Asset Allocation	5.00%	8.00%		'
Corporate bonds	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	2,128	1,899		'
Asset Allocation	34.00%	28.00%		'
High yield debt	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	'	369		'
Asset Allocation	'	6.00%		'
Mortgaged-backed securities (non-government)	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	87	330		'
Asset Allocation	1.00%	5.00%		'
Hedge funds	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	1,395	1,498		'
Asset Allocation	23.00%	22.00%		'
Derivatives	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	14	18		'
Asset Allocation	0.00%	0.00%		'
Private equity funds	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	27	33		'
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	385	357		'
Asset Allocation	6.00%	5.00%		'
Level 1	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	1,005	826	[1]	'
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	701	547		'
Level 1 | International	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	304	275		'
Level 1 | Government bonds	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	0	4		'
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		'
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	4,841	5,491	[1]	'
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	782	652		'
Level 2 | Domestic	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	3	8		'
Level 2 | International	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	118	153		'
Level 2 | Government bonds	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	314	564		'
Level 2 | Corporate bonds	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	2,128	1,899		'
Level 2 | High yield debt	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	'	369		'
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	87	330		'
Level 2 | Hedge funds	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	1,395	1,498		'
Level 2 | Derivatives	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	14	18		'
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	412	390	[1]	'
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		'
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		70
Level 3 | Private equity funds	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	27	33		135
Level 3 | Real estate funds	'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'		'
Pension investments measured at fair value	$385	$357		$327
[1]	Excludes ($87) million and ($36) million as of DecemberB 31, 2013 and DecemberB 31, 2012, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

Pension_and_Other_Postemployme6

Pension and Other Postemployment Benefits (Details 4) (Pensions, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Actual return on plan assets:	'	'
Ending balance	$6,258	$6,707	[1]
Private equity funds	'	'
Actual return on plan assets:	'	'
Ending balance	27	33
Real estate funds	'	'
Actual return on plan assets:	'	'
Ending balance	385	357
Derivatives	'	'
Actual return on plan assets:	'	'
Ending balance	14	18
Level 3	'	'
Actual return on plan assets:	'	'
Ending balance	412	390	[1]
Level 3 | Private equity funds	'	'
Reconciliation of changes in the fair value of pension investments	'	'
Beginning balance	33	135
Actual return on plan assets:	'	'
Unrealized gains (losses)	1	-14
Realized gains (losses)	5	-10
Purchases, sales and settlements	0	0
Transfers in (out)	-12	-78
Ending balance	27	33
Level 3 | Real estate funds	'	'
Reconciliation of changes in the fair value of pension investments	'	'
Beginning balance	357	327
Actual return on plan assets:	'	'
Unrealized gains (losses)	17	29
Realized gains (losses)	13	4
Purchases, sales and settlements	0	0
Transfers in (out)	-2	-3
Ending balance	385	357
Level 3 | Derivatives	'	'
Reconciliation of changes in the fair value of pension investments	'	'
Beginning balance	0	70
Actual return on plan assets:	'	'
Unrealized gains (losses)	0	0
Realized gains (losses)	0	0
Purchases, sales and settlements	0	-70
Transfers in (out)	0	0
Ending balance	$0	$0
[1]	Excludes ($87) million and ($36) million as of DecemberB 31, 2013 and DecemberB 31, 2012, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

Pension_and_Other_Postemployme7

Pension and Other Postemployment Benefits (Details 5) (OPEB, USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	$504	$518	'
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	47	83	'
Asset Allocation	9.00%	16.00%	'
Domestic	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	227	183	'
Asset Allocation	45.00%	36.00%	'
International	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	6	6	'
Asset Allocation	1.00%	1.00%	'
Mutual funds	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	5	11	'
Asset Allocation	1.00%	2.00%	'
U.S. treasuries	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	44	48	'
Asset Allocation	9.00%	9.00%	'
Government bonds	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	91	88	'
Asset Allocation	18.00%	17.00%	'
Corporate bonds	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	59	59	'
Asset Allocation	12.00%	11.00%	'
High yield debt	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	0	5	'
Asset Allocation	0.00%	1.00%	'
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	9	'
Asset Allocation	1.00%	2.00%	'
Hedge funds	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	17	21	'
Asset Allocation	3.00%	4.00%	'
Private equity funds	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	0	0	'
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	5	5	'
Asset Allocation	1.00%	1.00%	'
Level 1	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	236	195	'
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	227	183	'
Level 1 | International	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	4	4	'
Level 1 | Mutual funds	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	5	8	'
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 | 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	263	318	'
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	47	83	'
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	2	2	'
Level 2 | Mutual funds	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	0	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	44	48	'
Level 2 | Government bonds	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	91	88	'
Level 2 | Corporate bonds	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	59	59	'
Level 2 | High yield debt	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	0	5	'
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	9	'
Level 2 | Hedge funds	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	17	21	'
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	5	5	'
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 | Mutual funds	'	'	'
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 | Private equity funds	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	0	0	3
Level 3 | Real estate funds	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension investments measured at fair value	$5	$5	$7

Pension_and_Other_Postemployme8

Pension and Other Postemployment Benefits (Details 6) (OPEB, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013
Reconciliation of changes in the fair value of pension investments	'	'
Beginning balance	'	$504
Actual return on plan assets:	'	'
Ending balance	518	504
Private equity funds	'	'
Reconciliation of changes in the fair value of pension investments	'	'
Beginning balance	'	0
Actual return on plan assets:	'	'
Ending balance	0	0
Real estate funds	'	'
Reconciliation of changes in the fair value of pension investments	'	'
Beginning balance	'	5
Actual return on plan assets:	'	'
Ending balance	5	5
Level 3	'	'
Reconciliation of changes in the fair value of pension investments	'	'
Beginning balance	'	5
Actual return on plan assets:	'	'
Ending balance	5	5
Level 3 | Private equity funds	'	'
Reconciliation of changes in the fair value of pension investments	'	'
Beginning balance	3	0
Actual return on plan assets:	'	'
Unrealized gains (losses)	-1	'
Realized gains (losses)	0	'
Purchases, sales and settlements	0	'
Transfers in (out)	-2	'
Ending balance	0	0
Level 3 | Real estate funds	'	'
Reconciliation of changes in the fair value of pension investments	'	'
Beginning balance	7	5
Actual return on plan assets:	'	'
Unrealized gains (losses)	0	'
Realized gains (losses)	0	'
Purchases, sales and settlements	0	'
Transfers in (out)	-2	'
Ending balance	$5	$5

Pension_and_Other_Postemployme9

Pension and Other Postemployment Benefits (Details 7)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
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	26.00%	20.00%
Fixed income	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'
Target Asset Allocations	40.00%	51.00%
Absolute return strategies	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'
Target Asset Allocations	22.00%	21.00%
Real estate	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'
Target Asset Allocations	5.00%	5.00%
Private equities	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'
Target Asset Allocations	1.00%	0.00%
Cash	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'
Target Asset Allocations	6.00%	3.00%

Recovered_Sheet1

Pension and Other Postemployment Benefits (Details 8) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
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)

Recovered_Sheet2

Pension and Other Postemployment Benefits (Details 9) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Pensions	'
Estimated Future Benefit Payments	'
2014	$449
2015	466
2016	484
2017	500
2018	524
2019-2023	2,867
OPEB | Employer Subsidized Benefit	'
Estimated Future Benefit Payments	'
2014	129
2015	67
2016	67
2017	67
2018	65
2019-2023	382
OPEB | Medicare Rx Reimbursement	'
Estimated Future Benefit Payments	'
2014	-4
2015	-4
2016	-4
2017	-4
2018	-4
2019-2023	($17)

Recovered_Sheet3

Pension and Other Postemployment Benefits (Details 10) (FES, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Pensions	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'
Net Liability	($149)	($180)
OPEB	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'
Net Liability	($8)	($36)

Recovered_Sheet4

Pension and Other Postemployment Benefits (Details 11) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pensions	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Net Periodic Costs	($187)	$811	$807
Pensions | FES	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Net Periodic Costs	-30	78	80
OPEB	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Net Periodic Costs	-320	-41	-146
OPEB | FES	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Net Periodic Costs	($40)	($11)	($21)

Recovered_Sheet5

Pension and Other Postemployment Benefits (Details Textuals) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Pensions	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Excluded from total investments	($87)	($36)
Estimated 2014 amortization of prior service costs (credits) from AOCI	8	'
OPEB	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Excluded from total investments	-9	-10
Estimated 2014 amortization of prior service costs (credits) from AOCI	($176)	'

StockBased_Compensation_Plans_1

Stock-Based Compensation Plans (Details) (Restricted Stock and Restricted Stock Units Awards)	12 Months Ended
	Dec. 31, 2013
Restricted Stock and Restricted Stock Units Awards	'
Restricted stock and stock units outstanding [Roll Forward]	'
Number of Shares, Nonvested, Beginning Balance	2,180,422
Restricted stock granted	952,137
Vested	-815,851
Forfeited	-100,099
Number of Shares, Nonvested, Ending Balance	2,216,609

StockBased_Compensation_Plans_2

Stock-Based Compensation Plans (Details 1) (Restricted Stock, USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Restricted Stock	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Restricted stock granted	27,561	263,771	297,859
Weighted average market price	$42.53	$44.82	$38.44
Weighted average vesting period (years)	'3 years 8 months 5 days	'3 years 1 month 2 days	'2 years 3 months 7 days

StockBased_Compensation_Plans_3

Stock-Based Compensation Plans (Details 2) (Restricted Stock, USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Restricted Stock	'		'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'	'
Nonvested restricted stock balance, number of shares	417,464		551,678	'
Granted in 2013, number of shares	27,561		263,771	297,859
Vested in 2013, number of shares	167,751	[1]	'	'
Nonvested restricted stock balance, weighted average grant-date fair value (in dollars per share)	$45.46		$46.73	'
Granted in 2013, weighted average grant-date fair value (in dollars per share)	$42.53		$44.82	$38.44
Vested in 2013, weighted average grant-date fair value (in dollars per share)	$37.10		'	'
Dividend shares earned during period, number of shares	23,446		'	'
[1]	Includes 23,446 shares for dividends earned during vesting period

StockBased_Compensation_Plans_4

Stock-Based Compensation Plans (Details 3) (Restricted Stock Units)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Restricted Stock Units	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Restricted stock granted	924,576	652,120	617,195
Weighted average vesting period (years)	'3 years	'3 years	'3 years

StockBased_Compensation_Plans_5

Stock-Based Compensation Plans (Details 4) (Restricted Stock Units, USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Restricted Stock Units	'		'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'	'
Nonvested stock units balance, number of shares	1,799,145		1,628,744	'
Granted in 2013, number of shares	924,576		652,120	617,195
Forfeited in 2013, number of shares	82,629		'	'
Vested in 2013, number of shares	792,113	[1]	'	'
Nonvested stock units balance, weighted average grant-date fair value (in dollars per share)	$40.86		$41.10	'
Granted in 2013, weighted average grant-date fair value (in dollars per share)	$39.90		'	'
Forfeited in 2013, weighted average grant-date fair value (in dollars per share)	$41.38		'	'
Vested in 2013, weighted average grant-date fair value (in dollars per share)	$40.74		'	'
Dividend equivalents earned during vesting period, in shares	120,567		'	'
[1]	Includes dividend equivalents of 120,567 earned during vesting period

StockBased_Compensation_Plans_6

Stock-Based Compensation Plans (Details 5) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Summary of stock option activities	'	'
Options exercisable	1,997,969	2,348,469
Number of options, Beginning Balance	2,910,269	'
Options exercised	-546,408	'
Options forfeited	-4,735	'
Number of options, Ending Balance	2,359,126	'
Weighted Average Exercise Price, Beginning Balance	$40.33	'
Weighted Average Exercise Price of Options exercised	$30.37	'
Weighted Average Exercise Price of forfeited	$71.21	'
Weighted Average Exercise Price, Ending Balance	$42.59	'

StockBased_Compensation_Plans_7

Stock-Based Compensation Plans (Details 6) (USD $)	12 Months Ended
	Dec. 31, 2013
Summary of options outstanding by plan and range of exercise price	'
Shares	2,359,126
Weighted Average Exercise Price	$42.59
Remaining Contractual Life	'3 years 7 months 6 days
$20.02-$35.44	'
Summary of options outstanding by plan and range of exercise price	'
Options outstanding, Exercise Prices, Lower limit	$20.02
Options outstanding, Exercise Prices, Upper limit	$35.44
Shares	66,125
Weighted Average Exercise Price	$22.83
Remaining Contractual Life	'5 months 19 days
$35.45-$38.75	'
Summary of options outstanding by plan and range of exercise price	'
Options outstanding, Exercise Prices, Lower limit	$35.45
Options outstanding, Exercise Prices, Upper limit	$38.75
Shares	1,143,389
Weighted Average Exercise Price	$36.78
Remaining Contractual Life	'6 years 3 months 11 days
$38.76-$53.04	'
Summary of options outstanding by plan and range of exercise price	'
Options outstanding, Exercise Prices, Lower limit	$38.76
Options outstanding, Exercise Prices, Upper limit	$53.04
Shares	835,039
Weighted Average Exercise Price	$38.81
Remaining Contractual Life	'2 months 9 days
$53.05-$81.19	'
Summary of options outstanding by plan and range of exercise price	'
Options outstanding, Exercise Prices, Lower limit	$53.05
Options outstanding, Exercise Prices, Upper limit	$81.19
Shares	314,573
Weighted Average Exercise Price	$77.85
Remaining Contractual Life	'3 years 6 months 22 days

StockBased_Compensation_Plans_8

Stock-Based Compensation Plans (Details 7) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Pre-tax stock-based compensation expense	$60	$89	$74
Tax benefit associated with stock-based compensation expense	23	11	10
Stock-based compensation costs capitalized	20	29	21
Restricted Stock and Restricted Stock Units Awards	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Pre-tax stock-based compensation expense	42	42	29
Stock Options	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Pre-tax stock-based compensation expense	0	1	1
Performance Shares	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Pre-tax stock-based compensation expense	-10	5	3
401(k) Savings Plan	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Pre-tax stock-based compensation expense	25	37	31
EDCP	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Pre-tax stock-based compensation expense	-2	0	6
DCPD	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Pre-tax stock-based compensation expense	5	4	4
FES	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Pre-tax stock-based compensation expense	9	13	11
Tax benefit associated with stock-based compensation expense	1	2	2
Stock-based compensation costs capitalized	1	1	0
FES | Restricted Stock and Restricted Stock Units Awards	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Pre-tax stock-based compensation expense	6	6	4
FES | Performance Shares	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Pre-tax stock-based compensation expense	-1	1	1
FES | 401(k) Savings Plan	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Pre-tax stock-based compensation expense	4	6	5
FES | EDCP	'	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'	'
Pre-tax stock-based compensation expense	$0	$0	$1

StockBased_Compensation_Plans_9

Stock-Based Compensation Plans (Details Textuals) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Forms
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Tax benefit associated with stock-based compensation expense	$23	$11	$10
Number of stock based compensation programs	4	'	'
Maximum limit of total stock awards	29,000,000	'	'
Stock-based compensation award number of shares available for future	3,000,000	'	'
Employee Service Share-based Compensation, Tax Benefit Realized from Exercise of Stock Options	13	22	14
Number of types of restricted stock unit awards	2	'	'
Total intrinsic value of options exercised	6	'	'
Compensation expense (income)	60	89	74
Shares authorized for issuance	1,700,000	'	'
Number of shares available for grant	845,000	'	'
EDCP	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Compensation expense (income)	0	0	0
Deferral period	'3 years	'	'
DCPD	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Deferred Compensation Liability, Classified, Noncurrent	7	6	'
Restricted Stock and Restricted Stock Units Awards	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Restricted stock granted	952,137	'	'
Grant-date fair value	$39.97	'	'
Stock option weighted-average vesting period	'3 years 0 months 7 days	'	'
Unrecognized cost	35	'	'
Unrecognized cost, period for recognition	'	'2 years	'
Restricted Stock And Restricted Stock Units Awards, Performance Units	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Restricted stock granted	212,211	'	'
Stock Options	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Proceeds from options exercised	$19	$50	$32
Performance Shares	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Stock-based compensation award vesting period	'	'3 years	'
Minimum	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Stock-based compensation award vesting period	'	'8 months	'
Maximum	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Stock-based compensation award vesting period	'	'10 years	'

Taxes_Details

Taxes (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Currently payable (receivable)-	'	'	'	'	'	'	'	'	'	'	'
Federal	'	'	'	'	'	'	'	'	($118)	($130)	($251)
State	'	'	'	'	'	'	'	'	70	28	19
Currently payable (receivable) Total	'	'	'	'	'	'	'	'	-48	-102	-232
Deferred, net-	'	'	'	'	'	'	'	'	'	'	'
Federal	'	'	'	'	'	'	'	'	305	580	785
State	'	'	'	'	'	'	'	'	-54	78	24
Deferred Tax Total	'	'	'	'	'	'	'	'	251	658	809
Investment tax credit amortization	'	'	'	'	'	'	'	'	-8	-11	-11
Total provision for income taxes	66	77	-62	114	-105	307	123	220	195	545	566
FES	'	'	'	'	'	'	'	'	'	'	'
Currently payable (receivable)-	'	'	'	'	'	'	'	'	'	'	'
Federal	'	'	'	'	'	'	'	'	-300	-128	-224
State	'	'	'	'	'	'	'	'	-3	17	9
Currently payable (receivable) Total	'	'	'	'	'	'	'	'	-303	-111	-215
Deferred, net-	'	'	'	'	'	'	'	'	'	'	'
Federal	'	'	'	'	'	'	'	'	317	209	205
State	'	'	'	'	'	'	'	'	-4	9	-2
Deferred Tax Total	'	'	'	'	'	'	'	'	313	218	203
Investment tax credit amortization	'	'	'	'	'	'	'	'	-4	-4	-4
Total provision for income taxes	$25	$23	($42)	$0	($36)	$65	($1)	$75	$6	$103	($16)

Taxes_Details_1

Taxes (Details 1) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes	'	'	'	'	'	'	'	'	'	'	'
Book income before provision for income taxes	'	'	'	'	'	'	'	'	$570	$1,299	$1,438
Federal income tax expense at statutory rate	'	'	'	'	'	'	'	'	199	455	503
Increases (reductions) in taxes resulting from-	'	'	'	'	'	'	'	'	'	'	'
Amortization of investment tax credits	'	'	'	'	'	'	'	'	-8	-11	-11
State income taxes, net of federal tax benefit	'	'	'	'	'	'	'	'	10	69	28
State unitary tax adjustments	'	'	'	'	'	'	'	'	'	'	33
Manufacturing deduction	'	'	'	'	'	'	'	'	'	'	16
Medicare Part D	'	'	'	'	'	'	'	'	'	32	36
FirstEnergy effectively settled tax items	'	'	'	'	'	'	'	'	-2	-20	-11
Income Tax Rate Reconciliation, Deductions, Employee Stock Ownership Plan Dividends	'	'	'	'	'	'	'	'	-9	'	'
Income Tax Reconciliation, Nondeductible Expense, Other	'	'	'	'	'	'	'	'	3	0	'
Income Tax Reconciliation, Other Adjustments	'	'	'	'	'	'	'	'	1	0	'
ESOP Dividend	'	'	'	'	'	'	'	'	'	60	-19
AFUDC equity and other flow-through	'	'	'	'	'	'	'	'	-7	-50	'
Other, net	'	'	'	'	'	'	'	'	8	10	-9
Total provision for income taxes	66	77	-62	114	-105	307	123	220	195	545	566
FES	'	'	'	'	'	'	'	'	'	'	'
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes	'	'	'	'	'	'	'	'	'	'	'
Book income before provision for income taxes	'	'	'	'	'	'	'	'	52	276	-83
Federal income tax expense at statutory rate	'	'	'	'	'	'	'	'	18	97	-29
Increases (reductions) in taxes resulting from-	'	'	'	'	'	'	'	'	'	'	'
Amortization of investment tax credits	'	'	'	'	'	'	'	'	-4	-4	-4
State income taxes, net of federal tax benefit	'	'	'	'	'	'	'	'	-5	17	5
State unitary tax adjustments	'	'	'	'	'	'	'	'	'	'	0
Manufacturing deduction	'	'	'	'	'	'	'	'	'	'	13
Medicare Part D	'	'	'	'	'	'	'	'	'	1	4
FirstEnergy effectively settled tax items	'	'	'	'	'	'	'	'	0	-11	-2
Income Tax Rate Reconciliation, Deductions, Employee Stock Ownership Plan Dividends	'	'	'	'	'	'	'	'	-2	'	'
ESOP Dividend	'	'	'	'	'	'	'	'	'	0	2
AFUDC equity and other flow-through	'	'	'	'	'	'	'	'	0	0	'
Other, net	'	'	'	'	'	'	'	'	-1	3	-5
Total provision for income taxes	$25	$23	($42)	$0	($36)	$65	($1)	$75	$6	$103	($16)

Taxes_Details_2

Taxes (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Accumulated deferred income taxes	'	'
Property basis differences	$8,078	$7,868
Regulatory transition charge	-26	79
Customer receivables for future income taxes	-2	130
Deferred MISO/PJM transmission costs	27	125
Other regulatory assets b RCP	69	161
Deferred sale and leaseback gain	-411	-431
Non-utility generation costs	-1	5
Unamortized investment tax credits	-62	-67
Unrealized losses on derivative hedges	-20	-21
Pensions and OPEB	-938	-1,102
Lease market valuation liability	-59	-81
Oyster Creek securitization (Note 12)	57	75
Nuclear decommissioning activities	44	127
Mark-to-market adjustments	31	30
Deferred gain for asset sales b affiliated companies	781	'
Loss carryforwards and AMT credits	-1,599	-1,199
Loss carryforward valuation reserve	142	102
Storm damage	179	192
Market transition charge	81	65
All other	231	239
Net deferred income tax liability	6,602	6,297
FES	'	'
Accumulated deferred income taxes	'	'
Property basis differences	1,428	1,060
Regulatory transition charge	0	0
Customer receivables for future income taxes	0	0
Deferred MISO/PJM transmission costs	0	0
Other regulatory assets b RCP	0	0
Deferred sale and leaseback gain	-370	-384
Non-utility generation costs	0	0
Unamortized investment tax credits	-16	-17
Unrealized losses on derivative hedges	-1	2
Pensions and OPEB	-77	-105
Lease market valuation liability	55	33
Oyster Creek securitization (Note 12)	0	0
Nuclear decommissioning activities	31	111
Mark-to-market adjustments	30	30
Deferred gain for asset sales b affiliated companies	0	'
Loss carryforwards and AMT credits	-369	-221
Loss carryforward valuation reserve	18	16
Storm damage	0	0
Market transition charge	0	0
All other	-13	-22
Net deferred income tax liability	$716	$503

Taxes_Details_3

Taxes (Details 3) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in unrecognized tax benefits	'	'	'	'
Beginning balance	'	$43	$117	$45
Increase due to merger with AE	'	'	'	97
Current year increases	'	'	2	'
Current year decreases	'	'	-7	'
Prior years increases	'	10	6	10
Prior years decreases	'	-5	-37	-35
Decrease for settlements	-34	'	-38	'
Ending balance	43	48	43	117
FES	'	'	'	'
Changes in unrecognized tax benefits	'	'	'	'
Beginning balance	'	3	45	41
Increase due to merger with AE	'	'	'	0
Current year increases	'	'	0	'
Current year decreases	'	'	0	'
Prior years increases	'	0	6	8
Prior years decreases	'	0	-13	-4
Decrease for settlements	'	'	-35	'
Ending balance	$3	$3	$3	$45

Taxes_Details_4

Taxes (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net interest expense (income) and cumulative net interest payable (receivable)	'	'	'
Net Interest Expense (Income)	$1	($4)	($5)
Net Interest Payable	9	8	'
FES	'	'	'
Net interest expense (income) and cumulative net interest payable (receivable)	'	'	'
Net Interest Expense (Income)	0	-4	1
Net Interest Payable	$1	$1	'

Taxes_Details_5

Taxes (Details 5) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	$9,800
State Jurisdiction	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	7,469
State Jurisdiction | 2014-2018	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	14
State Jurisdiction | 2019-2023	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	2,513
State Jurisdiction | 2024-2028	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	2,051
State Jurisdiction | 2029-2033	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	2,891
Local Jurisdiction	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	2,289
Local Jurisdiction | 2014-2018	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	2,289
Local Jurisdiction | 2019-2023	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
Local Jurisdiction | 2024-2028	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
Local Jurisdiction | 2029-2033	'
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	843
FES | State Jurisdiction | 2014-2018	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	8
FES | State Jurisdiction | 2019-2023	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	23
FES | State Jurisdiction | 2024-2028	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	60
FES | State Jurisdiction | 2029-2033	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	752
FES | Local Jurisdiction	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,243
FES | Local Jurisdiction | 2014-2018	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,243
FES | Local Jurisdiction | 2019-2023	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
FES | Local Jurisdiction | 2024-2028	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
FES | Local Jurisdiction | 2029-2033	'
Pre-tax net operating loss expiration period	'
Pre-tax net operating loss carryforwards for state and local income tax purposes	$0

Taxes_Details_6

Taxes (Details 6) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
General Taxes	'	'	'
Total general taxes	$978	$984	$977
KWH excise	'	'	'
General Taxes	'	'	'
Total general taxes	219	230	244
State gross receipts	'	'	'
General Taxes	'	'	'
Total general taxes	240	251	264
Real and personal property	'	'	'
General Taxes	'	'	'
Total general taxes	368	328	298
Social security and unemployment	'	'	'
General Taxes	'	'	'
Total general taxes	110	126	109
Other	'	'	'
General Taxes	'	'	'
Total general taxes	41	49	62
FES	'	'	'
General Taxes	'	'	'
Total general taxes	138	136	124
FES | KWH excise	'	'	'
General Taxes	'	'	'
Total general taxes	0	0	0
FES | State gross receipts	'	'	'
General Taxes	'	'	'
Total general taxes	77	77	62
FES | Real and personal property	'	'	'
General Taxes	'	'	'
Total general taxes	40	35	42
FES | Social security and unemployment	'	'	'
General Taxes	'	'	'
Total general taxes	19	20	14
FES | Other	'	'	'
General Taxes	'	'	'
Total general taxes	$2	$4	$6

Taxes_Details_Textuals

Taxes (Details) (Textuals) (USD $)

1 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2012

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2012

Jul. 08, 2013

Dec. 31, 2012

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

subsidiary

subsidiary

New federal tax accounting method

FirstEnergy and AE Supply

Two unregulated subsidiaries

FES

FES

FES

FES

FES

FES

FES

FES

FES

FES

FES

FES

AE Companies

AE Companies

AE Companies

Operating Loss Carryforward

Federal

Federal

State and Local

State and Local

State and Local

State and Local

State and Local

plant

Tax Year 2010

New federal tax accounting method

PENNSYLVANIA

PENNSYLVANIA

After December 31, 2013

After December 31, 2014

Provision for Income Tax [Line Items]

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'

'

Impairment of Long-lived Assets, Number of Plants to be Deactivated

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Income Taxes (Textuals) [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reduction in income tax expense due to reversal of valuation allowance

'

'

'

'

'

'

'

'

'

'

'

$27,000,000

'

'

'

($50,000,000)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

($20,000,000)

'

'

'

'

'

'

'

Operating Loss Carryforward, Limitations on Use, Percent of Taxable Income

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25.00%

30.00%

Operating Loss Carryforward, Limitations on Use, Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,000,000

5,000,000

Valuation Allowance, Deferred Tax Asset, Change in Amount, Next Fiscal Quarter

'

'

'

'

'

'

'

'

'

-8,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferred Tax Liabilities, Decreases Resulting from Changes to State Apportionment Factors

'

'

'

'

'

'

'

'

'

9,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferred Tax Liabilities, Decreases Resulting from Changes in Assessment of Business Operations

'

'

'

'

'

'

'

'

'

22,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of unregulated subsidiaries involved in tax judgment

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of subsidiaries converted from corporations to limited liability companies (LLCs)

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Decrease in taxable income

'

208,000,000

286,000,000

-230,000,000

306,000,000

-258,000,000

729,000,000

307,000,000

522,000,000

'

'

'

'

-417,000,000

'

'

114,000,000

56,000,000

-117,000,000

-1,000,000

-74,000,000

161,000,000

-6,000,000

195,000,000

'

'

'

'

'

'

'

'

'

'

'

'

12,000,000

'

'

Unrecognized tax benefits

43,000,000

48,000,000

'

'

'

43,000,000

'

'

'

48,000,000

43,000,000

117,000,000

45,000,000

'

'

'

3,000,000

'

'

'

3,000,000

'

'

'

3,000,000

3,000,000

45,000,000

41,000,000

'

'

'

'

'

'

'

'

'

'

'

Unrecognized tax benefits, portion expected to be resolved in the next fiscal year

'

35,000,000

'

'

'

'

'

'

'

35,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized Tax Benefits, Resulting From Various Tax Positions, Resulting Reduction To Effective Tax Rate

'

'

'

'

'

'

'

'

'

5,000,000

37,000,000

35,000,000

'

'

'

'

'

'

'

'

'

'

'

'

0

13,000,000

4,000,000

'

'

5,000,000

'

'

'

'

'

'

'

'

'

Previously unrecognized tax benefit, impact on effective tax rate from settlement with authorities

'

'

'

'

'

34,000,000

'

'

'

'

38,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35,000,000

'

'

'

'

21,000,000

'

'

1,000,000,000

'

'

'

'

'

Proceeds from Income Tax Refunds

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

110,000,000

'

'

'

'

'

Pre-tax net operating loss carryforwards for state and local income tax purposes

'

9,800,000,000

'

'

'

'

'

'

'

9,800,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

65,000,000

'

'

'

'

'

Unrecognized tax benefits, decreases resulting from settlements with taxing authorities, resulting reduction to effective tax rate

'

'

'

'

'

10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,000,000

'

'

'

'

2,000,000

3,000,000

'

'

'

'

Reduction in effective tax rate

'

'

'

'

'

'

'

'

'

'

4,000,000

7,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferred tax assets, gross

'

1,100,000,000

'

'

'

'

'

'

'

1,100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating loss carryforwards, not subject to expiration

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000,000

'

'

'

'

'

'

Operating loss carryforwards, subject to expiration

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

418,000,000

'

'

'

Pre-tax net operating loss carryforwards expected to utilized

'

$6,300,000,000

'

'

'

'

'

'

'

$6,300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Leases_Details

Leases (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Rentals for capital and operating leases	'	'	'
Operating leases	$224	$291	$319
FES	'	'	'
Rentals for capital and operating leases	'	'	'
Operating leases	$97	$140	$154

Leases_Details_1

Leases (Details 1) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Future minimum capital lease payments	'
2014	$40
2015	38
2016	34
2017	30
2018	23
Years thereafter	57
Total minimum lease payments	222
Interest portion	-34
Present value of net minimum lease payments	188
Less current portion	34
Noncurrent portion	154
FES	'
Future minimum capital lease payments	'
2014	6
2015	6
2016	5
2017	5
2018	2
Years thereafter	0
Total minimum lease payments	24
Interest portion	-2
Present value of net minimum lease payments	22
Less current portion	5
Noncurrent portion	$17

Leases_Details_2

Leases (Details 2) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Future minimum operating lease payments	'
2014	$202
2015	205
2016	200
2017	125
2018	126
Years thereafter	1,564
Total minimum lease payments	2,422
Lease Payments	'
Future minimum operating lease payments	'
2014	250
2015	245
2016	213
2017	128
2018	126
Years thereafter	1,564
Total minimum lease payments	2,526
Capital Trust	'
Future minimum operating lease payments	'
2014	48
2015	40
2016	13
2017	3
2018	0
Years thereafter	0
Total minimum lease payments	104
FES	'
Future minimum operating lease payments	'
2014	143
2015	142
2016	130
2017	82
2018	101
Years thereafter	1,480
Total minimum lease payments	$2,078

Leases_Details_Textuals

Leases (Details Textuals) (USD $)

1 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

In Millions, unless otherwise specified

Mar. 31, 2013

Dec. 30, 1987

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2007

Dec. 31, 2012

Dec. 31, 2007

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2008

Dec. 31, 2008

Dec. 31, 2008

Feb. 12, 2014

Feb. 12, 2014

Bruce Mansfield Unit 1

Perry Power Plant Unit 1

FGCO

FGCO

FGCO

Nuclear Generation Corp

Nuclear Generation Corp

Nuclear Generation Corp

Nuclear Generation Corp

TE and CEI

Subsequent Event

Subsequent Event

Bruce Mansfield Plant

Bruce Mansfield Unit 1

Beaver Valley Unit 2

Beaver Valley Unit 2

Beaver Valley Unit 2

Perry Plant

Beaver Valley Unit 2

Beaver Valley Unit 2

Nuclear Generation Corp

MW

MW

MW

MW

MW

MW

Beaver Valley Unit 2

MW

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

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of undivided interest of FGCO in Bruce Mansfield Unit 1

'

'

'

'

93.83%

'

'

'

'

'

'

'

'

'

Basic terms of operating lease

'

'

'

'

'

'

'33 years

'

'

'

'

'

'

'

Purchase of lessor equity interests in sale and leaseback (in MW)

'

'

'

'

'

441.9

'

12.2

70.1

43.5

56.8

158.5

'

47.7

Purchase of lessor equity interests in sale and leaseback, value

$221

'

'

'

'

$262

'

$23

$129

'

'

'

'

$94

Percentage leased

'

'

93.83%

8.11%

'

'

'

'

'

'

'

'

2.60%

'

Intangible_Assets_Details

Intangible Assets (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Intangible Assets (Textuals) [Abstract]	'
Intangible Assets, Gross	$1,017
Intangible Assets, Accumulated Amortization	429
Intangible Assets, Net	588
Amortization Expense	'
Actual, 2013	100
Estimated, 2014	80
Estimated, 2015	75
Estimated, 2016	75
Estimated, 2017	69
Estimated, 2018	51
Estimated, Thereafter	185
NUG contracts	'
Intangible Assets (Textuals) [Abstract]	'
Intangible Assets, Gross	124	[1],[2]
Intangible Assets, Accumulated Amortization	15	[1],[2]
Intangible Assets, Net	109	[1],[2]
Amortization Expense	'
Actual, 2013	5	[1],[2]
Estimated, 2014	5	[1],[2]
Estimated, 2015	5	[1],[2]
Estimated, 2016	5	[1],[2]
Estimated, 2017	5	[1],[2]
Estimated, 2018	5	[1],[2]
Estimated, Thereafter	84	[1],[2]
OVEC	'
Intangible Assets (Textuals) [Abstract]	'
Intangible Assets, Gross	54	[1]
Intangible Assets, Accumulated Amortization	5	[1]
Intangible Assets, Net	49	[1]
Amortization Expense	'
Actual, 2013	2	[1]
Estimated, 2014	2	[1]
Estimated, 2015	2	[1]
Estimated, 2016	2	[1]
Estimated, 2017	2	[1]
Estimated, 2018	2	[1]
Estimated, Thereafter	39	[1]
Coal contracts	'
Intangible Assets (Textuals) [Abstract]	'
Intangible Assets, Gross	556	[1],[3]
Intangible Assets, Accumulated Amortization	222	[1],[3]
Intangible Assets, Net	334	[1],[3]
Amortization Expense	'
Actual, 2013	62	[1],[3]
Estimated, 2014	55	[1],[3]
Estimated, 2015	51	[1],[3]
Estimated, 2016	51	[1],[3]
Estimated, 2017	45	[1],[3]
Estimated, 2018	30	[1],[3]
Estimated, Thereafter	49	[1],[3]
Coal contracts | Recorded with Regulatory Offset	'
Intangible Assets (Textuals) [Abstract]	'
Intangible Assets, Gross	102
Intangible Assets, Net	53
Customer Contracts	'
Intangible Assets (Textuals) [Abstract]	'
Intangible Assets, Gross	147
Intangible Assets, Accumulated Amortization	52
Intangible Assets, Net	95
Amortization Expense	'
Actual, 2013	17
Estimated, 2014	17
Estimated, 2015	17
Estimated, 2016	17
Estimated, 2017	17
Estimated, 2018	14
Estimated, Thereafter	13
Energy contracts	'
Intangible Assets (Textuals) [Abstract]	'
Intangible Assets, Gross	136	[1]
Intangible Assets, Accumulated Amortization	135	[1]
Intangible Assets, Net	1	[1]
Amortization Expense	'
Actual, 2013	14	[1]
Estimated, 2014	1	[1]
Estimated, 2015	0	[1]
Estimated, 2016	0	[1]
Estimated, 2017	0	[1]
Estimated, 2018	0	[1]
Estimated, Thereafter	$0	[1]
[1]	(1)Fair value measurements of intangible assets recorded in connection with the Allegheny merger (see Note 21, Merger).
[2]	(2)NUG contracts are subject to regulatory accounting and their amortization does not impact earnings.
[3]	(3)A gross amount of $102 million ($53 million, net) of the coal contracts was recorded with a regulatory offset and the amortization does not impact earnings.

Variable_Interest_Entities_Det

Variable Interest Entities (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
FES	'
Net exposure to loss based upon the casualty value provisions	'
Maximum Exposure	$1,274
Discounted Lease Payments, net	1,063	[1]
Net Exposure	211
Other FE subsidiaries	'
Net exposure to loss based upon the casualty value provisions	'
Maximum Exposure	752
Discounted Lease Payments, net	289	[1]
Net Exposure	$463
[1]	The net present value of FirstEnergybs consolidated sale and leaseback operating lease commitments is $1.1 billion.

Variable_Interest_Entities_Det1

Variable Interest Entities (Details Textuals) (USD $)

12 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2011

Oct. 18, 2011

Dec. 31, 2008

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Aug. 31, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Dec. 31, 2012

entities

Power Purchase Agreements

Path-WV

Signal Peak

FEV

FEV

FEV

OE

Other FE subsidiaries

Other FE subsidiaries

Other FE subsidiaries

Ohio Funding Companies

Ohio Funding Companies

Ohio Funding Companies

Ohio Funding Companies

Ohio Funding Companies

Ohio Funding Companies

Ohio Funding Companies

WP

agreements

Signal Peak

Signal Peak

Signal Peak

Power Purchase Agreements

Power Purchase Agreements

Existing Taxable Bonds

Existing Taxable Bonds

Existing Taxable Bonds

Existing Taxable Bonds

Phase In Recovery Bonds

Power Purchase Agreements

Global Holding

Year 2013

Year 2015

Year 2020

Variable Interest Entities (Textuals) [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Distributions to owners

$7,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loan amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

410,000,000

225,000,000

150,000,000

35,000,000

445,000,000

'

Weighted average interest rate on debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.71%

'

'

'

2.48%

'

Make-whole premiums paid on debt redemptions

187,000,000

0

0

'

'

'

'

'

'

'

'

'

'

120,000,000

30,000,000

'

'

'

'

'

'

Equity Method Investments

'

'

'

'

'

'

'

134,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Noncontrolling Interest, Ownership Percentage by Parent

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Divestiture of Interest in Consolidated Subsidiaries

'

'

'

'

'

258,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ownership interest

'

'

'

'

'

'

'

'

33.33%

'

0.00%

'

'

'

'

'

'

'

'

'

'

Deconsolidation, Gain (Loss), Amount

'

'

'

'

'

569,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Gain (Loss) On Divestiture Net Of Tax

'

'

'

'

'

370,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deconsolidation, Revaluation of Retained Investment, Gain (Loss), Amount

'

'

'

'

'

379,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity interest by unaffiliated third party in PNBV

3.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity interest by OES Ventures in PNBV

'

'

'

'

'

'

'

'

'

3.00%

'

'

'

'

'

'

'

'

'

'

'

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%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities

'

'

'

21

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of contracts that may contain variable interest

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchased power

3,963,000,000

4,246,000,000

4,874,000,000

'

'

'

'

'

'

'

'

185,000,000

253,000,000

'

'

'

'

'

'

'

'

Reserve For Adverse Purchase Power Commitment, Pretax Loss

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

17,000,000

Reserve For Adverse Purchase Power Commitment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

60,000,000

Net present value of FirstEnergy's consolidated sale and leaseback operating lease commitments

$1,100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (Recurring, USD $)	Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Assets	'		'
Fair value, assets	$2,865		$2,822
Liabilities	'		'
Fair value, liabilities	-347		-597
Net assets (liabilities)	2,518	[1]	2,225	[1]
FES	'		'
Assets	'		'
Fair value, assets	1,485		1,447
Liabilities	'		'
Fair value, liabilities	-124		-160
Net assets (liabilities)	1,361	[2]	1,287	[2]
Commodity contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	-113		-154
Commodity contracts | Derivative Liabilities | FES	'		'
Liabilities	'		'
Fair value, liabilities	-113		-154
FTRs | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	-12		-9
FTRs | Derivative Liabilities | FES	'		'
Liabilities	'		'
Fair value, liabilities	-11		-6
NUG contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	-222	[3]	-290	[3]
LCAPP Contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	0	[3]	-144	[3]
Corporate debt securities	'		'
Assets	'		'
Fair value, assets	1,365		1,259
Corporate debt securities | FES	'		'
Assets	'		'
Fair value, assets	792		703
Commodity contracts | Derivative Assets	'		'
Assets	'		'
Fair value, assets	215		252
Commodity contracts | Derivative Assets | FES	'		'
Assets	'		'
Fair value, assets	215		252
FTRs | Derivative Assets	'		'
Assets	'		'
Fair value, assets	4		8
FTRs | Derivative Assets | FES	'		'
Assets	'		'
Fair value, assets	3		6
NUG contracts | Derivative Assets	'		'
Assets	'		'
Fair value, assets	20	[3]	36	[3]
Equity securities	'		'
Assets	'		'
Fair value, assets	317	[4]	310	[4]
Equity securities | FES	'		'
Assets	'		'
Fair value, assets	207	[5]	294	[5]
Foreign government debt securities	'		'
Assets	'		'
Fair value, assets	109		126
Foreign government debt securities | FES	'		'
Assets	'		'
Fair value, assets	65		61
U.S. government debt securities	'		'
Assets	'		'
Fair value, assets	165		179
U.S. government debt securities | FES	'		'
Assets	'		'
Fair value, assets	27		27
U.S. state debt securities	'		'
Assets	'		'
Fair value, assets	228		299
Other	'		'
Assets	'		'
Fair value, assets	442	[6]	353	[6]
Other | FES	'		'
Assets	'		'
Fair value, assets	176	[7]	104	[7]
Level 1	'		'
Assets	'		'
Fair value, assets	511		436
Liabilities	'		'
Fair value, liabilities	-13		-3
Net assets (liabilities)	498	[1]	433	[1]
Level 1 | FES	'		'
Assets	'		'
Fair value, assets	214		294
Liabilities	'		'
Fair value, liabilities	-13		-3
Net assets (liabilities)	201	[2]	291	[2]
Level 1 | Commodity contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	-13		-3
Level 1 | Commodity contracts | Derivative Liabilities | FES	'		'
Liabilities	'		'
Fair value, liabilities	-13		-3
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	[3]	0	[3]
Level 1 | LCAPP Contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	0	[3]	0	[3]
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	7		0
Level 1 | Commodity contracts | Derivative Assets | FES	'		'
Assets	'		'
Fair value, assets	7		0
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	[3]	0	[3]
Level 1 | Equity securities	'		'
Assets	'		'
Fair value, assets	317	[4]	310	[4]
Level 1 | Equity securities | FES	'		'
Assets	'		'
Fair value, assets	207	[5]	294	[5]
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 | Other	'		'
Assets	'		'
Fair value, assets	187	[6]	126	[6]
Level 1 | Other | FES	'		'
Assets	'		'
Fair value, assets	0	[7]	0	[7]
Level 2	'		'
Assets	'		'
Fair value, assets	2,330		2,342
Liabilities	'		'
Fair value, liabilities	-100		-151
Net assets (liabilities)	2,230	[1]	2,191	[1]
Level 2 | FES	'		'
Assets	'		'
Fair value, assets	1,268		1,147
Liabilities	'		'
Fair value, liabilities	-100		-151
Net assets (liabilities)	1,168	[2]	996	[2]
Level 2 | Commodity contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	-100		-151
Level 2 | Commodity contracts | Derivative Liabilities | FES	'		'
Liabilities	'		'
Fair value, liabilities	-100		-151
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	[3]	0	[3]
Level 2 | LCAPP Contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	0	[3]	0	[3]
Level 2 | Corporate debt securities	'		'
Assets	'		'
Fair value, assets	1,365		1,259
Level 2 | Corporate debt securities | FES	'		'
Assets	'		'
Fair value, assets	792		703
Level 2 | Commodity contracts | Derivative Assets	'		'
Assets	'		'
Fair value, assets	208		252
Level 2 | Commodity contracts | Derivative Assets | FES	'		'
Assets	'		'
Fair value, assets	208		252
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	[3]	0	[3]
Level 2 | Equity securities	'		'
Assets	'		'
Fair value, assets	0	[4]	0	[4]
Level 2 | Equity securities | FES	'		'
Assets	'		'
Fair value, assets	0	[5]	0	[5]
Level 2 | Foreign government debt securities	'		'
Assets	'		'
Fair value, assets	109		126
Level 2 | Foreign government debt securities | FES	'		'
Assets	'		'
Fair value, assets	65		61
Level 2 | U.S. government debt securities	'		'
Assets	'		'
Fair value, assets	165		179
Level 2 | U.S. government debt securities | FES	'		'
Assets	'		'
Fair value, assets	27		27
Level 2 | U.S. state debt securities	'		'
Assets	'		'
Fair value, assets	228		299
Level 2 | Other	'		'
Assets	'		'
Fair value, assets	255	[6]	227	[6]
Level 2 | Other | FES	'		'
Assets	'		'
Fair value, assets	176	[7]	104	[7]
Level 3	'		'
Assets	'		'
Fair value, assets	24		44
Liabilities	'		'
Fair value, liabilities	-234		-443
Net assets (liabilities)	-210	[1]	-399	[1]
Level 3 | FES	'		'
Assets	'		'
Fair value, assets	3		6
Liabilities	'		'
Fair value, liabilities	-11		-6
Net assets (liabilities)	-8	[2]	0	[2]
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	-12		-9
Level 3 | FTRs | Derivative Liabilities | FES	'		'
Liabilities	'		'
Fair value, liabilities	-11		-6
Level 3 | NUG contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	-222	[3]	-290	[3]
Level 3 | LCAPP Contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	0	[3]	-144	[3]
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	4		8
Level 3 | FTRs | Derivative Assets | FES	'		'
Assets	'		'
Fair value, assets	3		6
Level 3 | NUG contracts | Derivative Assets	'		'
Assets	'		'
Fair value, assets	20	[3]	36	[3]
Level 3 | Equity securities	'		'
Assets	'		'
Fair value, assets	0	[4]	0	[4]
Level 3 | Equity securities | FES	'		'
Assets	'		'
Fair value, assets	0	[5]	0	[5]
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 | Other	'		'
Assets	'		'
Fair value, assets	0	[6]	0	[6]
Level 3 | Other | FES	'		'
Assets	'		'
Fair value, assets	$0	[7]	$0	[7]
[1]	Excludes $10 million and $110 million as of DecemberB 31, 2013 and DecemberB 31, 2012, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
[2]	xcludes $9 million and $94 million as of DecemberB 31, 2013 and DecemberB 31, 2012, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
[3]	NUG and LCAPP contracts are subject to regulatory accounting treatment and do not impact earnings
[4]	NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.
[5]	DT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.(
[6]	Primarily consists of short-term cash investments.
[7]	rimarily consists of short-term cash investments.

Fair_Value_Measurements_Detail1

Fair Value Measurements (Details 1) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
NUG contracts	'		'
Reconciliation of changes in the fair value of NUG contracts	'		'
Terminations, Derivative Assets	$0	[1]	'
Terminations, Derivative Liability	0	[1]	'
Terminations, Net	0	[1]	'
Level 3 | NUG contracts	'		'
Reconciliation of changes in the fair value of NUG contracts	'		'
Beginning Balance, Derivative Assets	36	[1]	57	[1]
Beginning Balance, Derivative Liabilities	-290	[1]	-349	[1]
Beginning Balance, Net	-254	[1]	-292	[1]
Unrealized gain (loss), Derivative Assets	-8	[1]	-20	[1]
Unrealized gain (loss), Derivative Liabilities	-17	[1]	-180	[1]
Unrealized gain (loss), Net	-25	[1]	-200	[1]
Purchases, Derivative Assets	0	[1]	0	[1]
Purchases, Derivative Liabilities	0	[1]	0	[1]
Purchases, Net	0	[1]	0	[1]
Settlements, Derivative Assets	-8	[1]	-1	[1]
Settlements, Derivative Liabilities	85	[1]	239	[1]
Settlements, Net	77	[1]	238	[1]
Ending Balance, Derivative Assets	20	[1]	36	[1]
Ending Balance, Derivative Liabilities	-222	[1]	-290	[1]
Ending Balance, Net	-202	[1]	-254	[1]
Level 3 | LCAPP Contracts	'		'
Reconciliation of changes in the fair value of NUG contracts	'		'
Beginning Balance, Derivative Assets	0	[1]	0	[1]
Beginning Balance, Derivative Liabilities	-144	[1]	0	[1]
Beginning Balance, Net	-144	[1]	0	[1]
Unrealized gain (loss), Derivative Assets	0	[1]	0	[1]
Unrealized gain (loss), Derivative Liabilities	-22	[1]	1	[1]
Unrealized gain (loss), Net	-22	[1]	1	[1]
Purchases, Derivative Assets	0	[1]	0	[1]
Purchases, Derivative Liabilities	0	[1]	-145	[1]
Purchases, Net	0	[1]	-145	[1]
Terminations, Derivative Assets	0	[1]	'
Terminations, Derivative Liability	166	[1]	'
Terminations, Net	166	[1]	'
Settlements, Derivative Assets	0	[1]	0	[1]
Settlements, Derivative Liabilities	0	[1]	0	[1]
Settlements, Net	0	[1]	0	[1]
Ending Balance, Derivative Assets	0	[1]	0	[1]
Ending Balance, Derivative Liabilities	0	[1]	-144	[1]
Ending Balance, Net	0	[1]	-144	[1]
Level 3 | FTRs	'		'
Reconciliation of changes in the fair value of NUG contracts	'		'
Beginning Balance, Derivative Assets	8		1
Beginning Balance, Derivative Liabilities	-9		-23
Beginning Balance, Net	-1		-22
Unrealized gain (loss), Derivative Assets	3		6
Unrealized gain (loss), Derivative Liabilities	1		-6
Unrealized gain (loss), Net	4		0
Purchases, Derivative Assets	6		13
Purchases, Derivative Liabilities	-15		-10
Purchases, Net	-9		3
Terminations, Derivative Assets	0		'
Terminations, Derivative Liability	0		'
Terminations, Net	0		'
Settlements, Derivative Assets	-13		-12
Settlements, Derivative Liabilities	11		30
Settlements, Net	-2		18
Ending Balance, Derivative Assets	4		8
Ending Balance, Derivative Liabilities	-12		-9
Ending Balance, Net	-8		-1
FES | Level 3 | FTRs	'		'
Reconciliation of changes in the fair value of NUG contracts	'		'
Beginning Balance, Derivative Assets	6		1
Beginning Balance, Derivative Liabilities	-6		-7
Beginning Balance, Net	0		-6
Unrealized gain (loss), Derivative Assets	0		4
Unrealized gain (loss), Derivative Liabilities	-2		-4
Unrealized gain (loss), Net	-2		0
Purchases, Derivative Assets	5		9
Purchases, Derivative Liabilities	-12		-7
Purchases, Net	-7		2
Settlements, Derivative Assets	-8		-8
Settlements, Derivative Liabilities	9		12
Settlements, Net	1		4
Ending Balance, Derivative Assets	3		6
Ending Balance, Derivative Liabilities	-11		-6
Ending Balance, Net	($8)		$0
[1]	Changes in the fair value of NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings.

Fair_Value_Measurements_Detail2

Fair Value Measurements (Details 2) (Level 3, USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

In Millions, unless otherwise specified

FTRs

FTRs

FTRs

FTRs

FTRs

FTRs

NUG contracts

NUG contracts

NUG contracts

Model

Model

Model

Model

Model

Model

Model

Model

Model

Model

Model

Model

FES

FES

FES

FTRs

FTRs

NUG contracts

Minimum

Minimum

Minimum

Maximum

Maximum

Maximum

Weighted Average

Weighted Average

Weighted Average

FES

FTRs

FTRs

NUG contracts

FTRs

FTRs

NUG contracts

FTRs

FTRs

NUG contracts

FES

MWh

FES

MWh

FES

MWh

Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair Value

($8)

($1)

($22)

($8)

$0

($6)

($202)

[1]

($254)

[1]

($292)

[1]

($8)

($8)

($202)

'

'

'

'

'

'

'

'

'

Fair Value Inputs, RTO Auction Clearing Prices

'

'

'

'

'

'

'

'

'

'

'

'

-2.8

-2.8

'

5.2

5.2

'

0.6

0.5

'

Fair Value Inputs, Power

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600

'

'

5,641,000

'

'

1,529,000

Fair Value Inputs, Power, Regional Prices

'

'

'

'

'

'

'

'

'

'

'

'

'

'

51.7

'

'

57.3

'

'

53.8

[1]

Changes in the fair value of NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings.

Fair_Value_Measurements_Detail3

Fair Value Measurements (Details 3) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Debt Securities	'		'
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities	'		'
Cost Basis	$1,881	[1]	$1,827	[2]
Unrealized Gains	33	[1]	34	[2]
Fair Value	1,914	[1]	1,861	[2]
Equity securities	'		'
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities	'		'
Cost Basis	308	[1]	293	[2]
Unrealized Gains	9	[1]	16	[2]
Fair Value	317	[1]	309	[2]
FES | Debt Securities	'		'
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities	'		'
Cost Basis	918	[1]	778	[2]
Unrealized Gains	17	[1]	14	[2]
Fair Value	935	[1]	792	[2]
FES | Equity securities	'		'
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities	'		'
Cost Basis	207	[1]	281	[2]
Unrealized Gains	0	[1]	13	[2]
Fair Value	$207	[1]	$294	[2]
[1]	xcludes short-term cash investments: FE Consolidated - $204 million; FES - $135 million.
[2]	xcludes short-term cash investments: FE Consolidated - $326 million; FES - $196 million.

Fair_Value_Measurements_Detail4

Fair Value Measurements (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	$2,047	$2,980	$4,207
Realized Gains	92	179	229
Realized Losses	-46	-83	-71
OTTI	-90	-16	-19
Interest and Dividend Income	101	70	82
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	940	1,464	1,843
Realized Gains	70	124	80
Realized Losses	-21	-59	-29
OTTI	-79	-14	-17
Interest and Dividend Income	$60	$39	$47

Fair_Value_Measurements_Detail5

Fair Value Measurements (Details 5) (Debt Securities, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Debt Securities	'	'
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities	'	'
Cost Basis	$33	$54
Unrealized Gains	2	30
Fair Value	$35	$84

Fair_Value_Measurements_Detail6

Fair Value Measurements (Details 6) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Carrying Value	'	'
Fair value and related carrying amounts of long-term debt and other long-term obligations	'	'
Long-term debt and other long-term obligations	$17,049	$16,957
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	17,957	19,460
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	3,001	4,194
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	$3,073	$4,524

Fair_Value_Measurements_Detail7

Fair Value Measurements (Details Textuals) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013
In Millions, unless otherwise specified			FES	FES	NUG contracts
Fair Value of Financial Instruments [Line Items]	'	'	'	'	'
Period of future observable data to determine contract price	'	'	'	'	'3 years
Investment excludes Receivables, Payables and Accrued income	$10	$110	$9	$94	'
Cash balance excluded from available for sale securities	204	326	135	196	'
Investments not required to be disclosed	$636	$644	'	'	'

Derivative_Instruments_Details

Derivative Instruments (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Fair value of commodity derivatives	'	'
Derivative Assets	$239	$296
Derivative Liabilities	-347	-598
Current Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	166	160
Noncurrent Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	73	136
Current Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	-111	-126
Noncurrent Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	-236	-472
Commodity contracts | Current Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	162	153
Commodity contracts | Noncurrent Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	53	99
Commodity contracts | Current Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	-102	-119
Commodity contracts | Noncurrent Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	-11	-36
FTRs | Current Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	4	7
FTRs | Noncurrent Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	0	1
FTRs | Current Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	-9	-7
FTRs | Noncurrent Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	-3	-2
NUGs | Noncurrent Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	20	36
NUGs | Noncurrent Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	-222	-290
LCAPP | Noncurrent Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	$0	($144)

Derivative_Instruments_Details1

Derivative Instruments (Details 1) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivative Assets	'	'
Fair Value	$239	$296
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	-110	-150
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	-9	-5
Net Fair Value	120	141
Derivative Liabilities	'	'
Fair Value	-347	-598
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	110	150
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	12	13
Net Fair Value	-225	-435
Commodity contracts	'	'
Derivative Assets	'	'
Fair Value	215	252
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	-106	-142
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	-9	-5
Net Fair Value	100	105
Derivative Liabilities	'	'
Fair Value	-113	-155
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	106	142
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	7	12
Net Fair Value	0	-1
FTRs	'	'
Derivative Assets	'	'
Fair Value	4	8
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	-4	-8
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	0	0
Derivative Liabilities	'	'
Fair Value	-12	-9
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	4	8
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	5	1
Net Fair Value	-3	0
NUGs	'	'
Derivative Assets	'	'
Fair Value	20	36
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	20	36
Derivative Liabilities	'	'
Fair Value	-222	-290
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	-222	-290
LCAPP	'	'
Derivative Liabilities	'	'
Fair Value	'	-144
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	'	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	'	0
Net Fair Value	'	($144)

Derivative_Instruments_Details2

Derivative Instruments (Details 2)	Dec. 31, 2013
	MWh
Power Contracts	'
Volume of First Energy's outstanding derivative transactions	'
Purchases (in MWH or mmBTUs)	34,000,000
Sales (in MWH or mmBTUs)	37,000,000
Net (in MWH or mmBTUs)	-3,000,000
FTRs	'
Volume of First Energy's outstanding derivative transactions	'
Purchases (in MWH or mmBTUs)	43,000,000
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	43,000,000
NUGs	'
Volume of First Energy's outstanding derivative transactions	'
Purchases (in MWH or mmBTUs)	11,000,000
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	11,000,000
Natural Gas	'
Volume of First Energy's outstanding derivative transactions	'
Purchases (in MWH or mmBTUs)	77,000,000
Sales (in MWH or mmBTUs)	3,000,000
Net (in MWH or mmBTUs)	74,000,000

Derivative_Instruments_Details3

Derivative Instruments (Details 3) (Not Designated as Hedging Instrument, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
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	$67	$324
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	-38	-277
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	3	102
Realized Gain (Loss) Reclassified	-36	-61
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	-2	5
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	'	6
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	46	302
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	-38	-277
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	11	89
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	-2	5
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	21	22
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	-8	13
Realized Gain (Loss) Reclassified	-36	-61
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	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	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	0
Realized Gain (Loss) Reclassified	0	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	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	'	$6

Derivative_Instruments_Details4

Derivative Instruments (Details 4) (Not Designated as Hedging Instrument, Subject to Regulatory Accounting, Excluded from Earnings, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]	'	'
Unrealized Gain (Loss) on Derivative Instrument	($44)	($344)
Realized Gain (Loss) on Derivative Instrument	240	247
NUGs	'	'
Derivative [Line Items]	'	'
Unrealized Gain (Loss) on Derivative Instrument	-23	-201
Realized Gain (Loss) on Derivative Instrument	75	240
LCAPP	'	'
Derivative [Line Items]	'	'
Unrealized Gain (Loss) on Derivative Instrument	-22	-144
Realized Gain (Loss) on Derivative Instrument	166	0
Regulated FTRs	'	'
Derivative [Line Items]	'	'
Unrealized Gain (Loss) on Derivative Instrument	1	1
Realized Gain (Loss) on Derivative Instrument	($1)	$7

Derivative_Instruments_Details5

Derivative Instruments (Details 5) (Not Designated as Hedging Instrument, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Outstanding net asset (liability) [Roll Forward]	'	'
Outstanding net asset (liability), Beginning Balance	($398)	($301)
Additions/Change in value of existing contracts	-44	-344
Settled contracts	240	247
Outstanding net asset (liability), Ending Balance	-202	-398
NUGs	'	'
Outstanding net asset (liability) [Roll Forward]	'	'
Outstanding net asset (liability), Beginning Balance	-254	-293
Additions/Change in value of existing contracts	-23	-201
Settled contracts	75	240
Outstanding net asset (liability), Ending Balance	-202	-254
LCAPP	'	'
Outstanding net asset (liability) [Roll Forward]	'	'
Outstanding net asset (liability), Beginning Balance	-144	0
Additions/Change in value of existing contracts	-22	-144
Settled contracts	166	0
Outstanding net asset (liability), Ending Balance	0	-144
Regulated FTRs	'	'
Outstanding net asset (liability) [Roll Forward]	'	'
Outstanding net asset (liability), Beginning Balance	0	-8
Additions/Change in value of existing contracts	1	1
Settled contracts	-1	7
Outstanding net asset (liability), Ending Balance	$0	$0

Derivative_Instruments_Details6

Derivative Instruments (Details Textuals) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Oct. 22, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

NUGs

FTRs

FES

FES

JCP&L

JCP&L

Cash Flow Hedges

Cash Flow Hedges

Fair Value Hedging

Fair Value Hedging

Commodity contracts

FTRs

contracts

appeal

agreements

agreements

agreements

agreements

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Unamortized gains or losses associated with designated cash flow hedges

$2,000,000

$10,000,000

'

'

'

'

'

'

'

'

'

'

Gain (loss) on cash flow hedge expected to be reclassified to earnings in next twelve months

10,000,000

'

'

'

'

'

'

'

'

'

'

'

Unamortized gains or losses associated with prior interest rate hedges

59,000,000

70,000,000

'

'

'

'

'

'

'

'

'

'

Losses to be amortized to interest expenses during next twelve months

'

'

'

'

'

'

'

'

9,000,000

'

12,000,000

'

Number of forward starting swap agreements accounted for as a cash flow hedge outstanding

'

'

'

'

'

'

'

'

0

0

'

'

Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements

44,000,000

79,000,000

'

'

'

'

'

'

'

'

'

'

Reclassifications from long-term debt

'

'

'

'

'

'

'

'

'

'

19,000,000

22,000,000

Unamortized gain (loss) on extinguishment of debt

'

'

'

'

'

'

'

'

'

'

17,000,000

'

Proceeds from Interest Rate Derivative, Termination

'

6,000,000

'

'

'

'

'

'

'

'

'

'

Number of fixed-for-floating interest rate swap agreements outstanding

'

'

'

'

'

'

'

'

'

'

0

0

Net asset position under commodity derivative contracts

'

'

'

'

102,000,000

'

'

'

'

'

'

'

Collateral posted

'

'

'

'

29,000,000

5,000,000

'

'

'

'

'

'

Additional collateral related to commodity derivatives

'

'

'

'

1,000,000

'

'

'

'

'

'

'

Expected adverse change in quoted market prices of derivative instruments

10.00%

'

'

'

'

'

'

'

'

'

'

'

Decrease net income due to adverse change in commodity prices

27,000,000

'

'

'

'

'

'

'

'

'

'

'

Liability position

'

'

202,000,000

8,000,000

'

'

'

'

'

'

'

'

Number of outstanding LCAPP contracts

'

'

'

'

'

'

2

'

'

'

'

'

Number of appeals dismissed

'

'

'

'

'

'

'

2

'

'

'

'

Period in which LSEs may request direct allocation of FTRs

'2 years

'

'

'

'

'

'

'

'

'

'

'

Direct allocation of FTRs, cost

$0

'

'

'

'

'

'

'

'

'

'

'

Impairment_of_Longlived_Assets2

Impairment of Long-lived Assets (Details) (USD $)

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 30, 2013

Mar. 31, 2011

Dec. 31, 2011

Sep. 01, 2012

Dec. 31, 2011

Oct. 09, 2013

Dec. 31, 2013

Dec. 31, 2013

Oct. 09, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2011

Mar. 11, 2011

Dec. 31, 2011

Mar. 11, 2011

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2013

Jul. 08, 2013

Jul. 08, 2013

Excessive Inventories

Fremont Energy Center

Peaking Facilities

Hazardous Air Pollutant Emissions

Hazardous Air Pollutant Emissions

MP

MP

MP

AE Supply

AE Supply

FES

FES

FES

Excessive or Obsolete Inventory

Excessive or Obsolete Inventory

Write-down of carrying value

Write-down of carrying value

Mono-Nitrogen Oxide Emission Allowances

Mono-Nitrogen Oxide Emission Allowances

Mono-Nitrogen Oxide Emission Allowances

Sulfur Dioxide Emission Allowances

Sulfur Dioxide Emission Allowances

Sulfur Dioxide Emission Allowances

Long-Lived Assets to be Abandoned, Total

Hatfield's Ferry, Units 1-3

Mitchell, Units 2-3

CoalFiredPlants

Competitive Energy Services

Customer Receipts

Competitive Energy Services

Fremont Energy Center

Competitive Energy Services

Fremont Energy Center

Competitive Energy Services

AE Supply

FES

Competitive Energy Services

AE Supply

FES

employees

MW

MW

MW

MW

MW

Competitive Energy Services

Competitive Energy Services

Competitive Energy Services

Competitive Energy Services

turbine

Schedule of Generating Plant Retirements [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percent of ownership interest acquired

'

'

'

'

'

'

'

'

'

80.00%

'

'

8.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Value of interest acquired

'

'

'

'

'

'

'

'

'

$1,200,000,000

'

'

$73,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash consideration received in asset swap transaction

'

'

'

'

'

'

'

'

'

'

'

'

1,100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Assumption of pollution control note

'

'

'

'

'

'

'

'

'

'

'

'

73,500,000

73,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity contribution from parent

'

'

'

'

'

'

'

'

'

527,000,000

527,000,000

'

'

'

1,500,000,000

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

Loans to affiliated companies, net

'

'

'

'

'

'

'

'

'

573,000,000

573,000,000

'

'

'

276,000,000

107,000,000

14,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset Impairment Charges

473,000,000

795,000,000

0

413,000,000

13,000,000

11,000,000

23,000,000

'

'

'

322,000,000

'

'

'

0

0

294,000,000

'

'

'

'

6,000,000

5,000,000

1,000,000

'

'

'

'

'

'

Regulatory liability

'

'

'

'

'

'

'

'

'

'

'

23,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Plant capacity (in megawatts)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,710

370

Expected number of positions eliminated (in employees)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

240

'

'

Pre-tax severance expense related to closures

'

'

14,000,000

'

'

'

'

'

'

'

'

'

'

'

'

10,000,000

'

'

'

'

'

'

'

'

'

'

'

6,000,000

'

'

Number of retired coal-fired power plants

'

'

'

'

'

'

'

9

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total capacity of retired coal-fired plants (in megawatts)

'

'

'

'

'

'

'

3,349

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment of long-lived assets to be disposed of

'

'

'

'

'

'

'

'

334,000,000

'

'

'

'

'

'

'

'

18,000,000

'

311,000,000

'

'

'

'

5,000,000

'

'

'

'

'

Other asset impairment charges

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$16,000,000

$3,000,000

$13,000,000

'

'

'

Number Of Combined-Cycle Combustion Engines Included In Sale

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

Load Following Capacity (in megawatts)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

544

'

'

'

'

'

'

'

'

'

Peaking Capacity (in megawatts)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

163

'

'

'

'

'

'

'

'

'

'

'

Capitalization_Details

Capitalization (Details) (USD $)	Dec. 31, 2013
Preferred stock and preference stock authorizations	'
Shares Authorized	5,000,000
Par Value	$100
Penn	'
Preferred stock and preference stock authorizations	'
Shares Authorized	1,200,000
Par Value	$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	$0.01
WP	'
Preferred stock and preference stock authorizations	'
Shares Authorized	32,000,000
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	$25
Preferred Stock With Par Value $100 | OE	'
Preferred stock and preference stock authorizations	'
Shares Authorized	6,000,000
Par Value	$100
Preferred Stock With Par Value $100 | TE	'
Preferred stock and preference stock authorizations	'
Shares Authorized	3,000,000
Par Value	$100
Preferred Stock With Par Value $100 | MP	'
Preferred stock and preference stock authorizations	'
Shares Authorized	940,000
Par Value	$100
Preferred Stock With Par Value $25 | OE	'
Preferred stock and preference stock authorizations	'
Shares Authorized	8,000,000
Par Value	$25
Preferred Stock With Par Value $25 | TE	'
Preferred stock and preference stock authorizations	'
Shares Authorized	12,000,000
Par Value	$25

Capitalization_Details_1

Capitalization (Details 1) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Schedule of Capitalization [Line Items]	'	'
Secured notes	$1,804	$2,163
Unsecured debt	12,035	12,104
Capital lease obligations	188	176
Unamortized debt premiums (discounts)	9	45
Unamortized fair value adjustments	44	103
Currently payable long-term debt	-1,415	-1,999
Total long-term debt and other long-term obligations	15,831	15,179
FES	'	'
Schedule of Capitalization [Line Items]	'	'
Secured notes	188	739
Unsecured debt	2,813	3,455
Capital lease obligations	22	27
Unamortized debt premiums (discounts)	-1	-1
Currently payable long-term debt	-892	-1,102
Total long-term debt and other long-term obligations	2,130	3,118
FMBs	'	'
Schedule of Capitalization [Line Items]	'	'
Other Long-term Debt	3,166	2,587
FMBs | Minimum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	3.34%	'
FMBs | Maximum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	9.74%	'
Secured notes - fixed rate	'	'
Schedule of Capitalization [Line Items]	'	'
Secured notes	1,804	2,113
Secured notes - fixed rate | Minimum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	6.15%	'
Secured notes - fixed rate | Maximum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	7.88%	'
Secured notes - fixed rate | FES	'	'
Schedule of Capitalization [Line Items]	'	'
Secured notes	188	689
Secured notes - fixed rate | FES | Minimum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	5.15%	'
Secured notes - fixed rate | FES | Maximum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	12.00%	'
Secured notes - variable rate	'	'
Schedule of Capitalization [Line Items]	'	'
Secured notes	0	50
Secured notes - variable rate | FES	'	'
Schedule of Capitalization [Line Items]	'	'
Secured notes	0	50
Unsecured notes - fixed rate	'	'
Schedule of Capitalization [Line Items]	'	'
Unsecured debt	11,076	11,145
Unsecured notes - fixed rate | Minimum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	3.50%	'
Unsecured notes - fixed rate | Maximum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	7.35%	'
Unsecured notes - fixed rate | FES	'	'
Schedule of Capitalization [Line Items]	'	'
Unsecured debt	2,077	2,769
Unsecured notes - fixed rate | FES | Minimum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	2.15%	'
Unsecured notes - fixed rate | FES | Maximum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	6.80%	'
Unsecured notes - variable rate	'	'
Schedule of Capitalization [Line Items]	'	'
Unsecured debt	959	959
Unsecured notes - variable rate | Minimum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	0.02%	'
Unsecured notes - variable rate | Maximum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	1.67%	'
Unsecured notes - variable rate | FES	'	'
Schedule of Capitalization [Line Items]	'	'
Unsecured debt	$736	$686
Unsecured notes - variable rate | FES | Minimum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	0.13%	'
Unsecured notes - variable rate | FES | Maximum	'	'
Schedule of Capitalization [Line Items]	'	'
Interest Rate	0.16%	'

Capitalization_Details_2

Capitalization (Details 2) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases and variable rate PCRBs) for the next five years	'
2014	$1,376
2015	1,264
2016	1,041
2017	1,641
2018	1,453
FES	'
Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases and variable rate PCRBs) for the next five years	'
2014	887
2015	391
2016	417
2017	163
2018	$266

Capitalization_Details_3

Capitalization (Details 3) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Outstanding PCRBs for the next three years	'
2014	$1,376
2015	1,264
2016	1,041
2017	1,641
2018	1,453
PCRB	'
Outstanding PCRBs for the next three years	'
2014	835
2015	313
2016	391
2017	130
2018	125
FES	'
Outstanding PCRBs for the next three years	'
2014	887
2015	391
2016	417
2017	163
2018	266
FES | PCRB	'
Outstanding PCRBs for the next three years	'
2014	762
2015	313
2016	391
2017	130
2018	$125

Capitalization_Details_4

Capitalization (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Schedule of Capitalization [Line Items]	'
Aggregate LOC Amount	818
Minimum	'
Schedule of Capitalization [Line Items]	'
Annual Fees	1.65%
Maximum	'
Schedule of Capitalization [Line Items]	'
Annual Fees	3.30%
FES	'
Schedule of Capitalization [Line Items]	'
Aggregate LOC Amount	744
FES | Minimum	'
Schedule of Capitalization [Line Items]	'
Annual Fees	1.65%
FES | Maximum	'
Schedule of Capitalization [Line Items]	'
Annual Fees	3.30%

Capitalization_Details_Textual

Capitalization (Details Textuals) (USD $)

3 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

0 Months Ended

1 Months Ended

1 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jan. 21, 2014

Oct. 31, 2013

8-May-13

Oct. 31, 2013

Sep. 25, 2013

Dec. 31, 2013

Nov. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Nov. 15, 2013

Nov. 27, 2013

Nov. 27, 2013

Nov. 27, 2013

Nov. 27, 2013

Nov. 27, 2013

8-May-13

Mar. 31, 2013

Mar. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 03, 2013

Nov. 15, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

8-May-13

Mar. 31, 2013

Mar. 31, 2013

Mar. 31, 2013

Apr. 15, 2013

Mar. 31, 2013

8-May-13

Dec. 31, 2013

Aug. 31, 2013

Mar. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Mar. 31, 2013

Mar. 31, 2013

Aug. 31, 2013

Jun. 30, 2013

Aug. 31, 2013

Aug. 31, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Oct. 31, 2013

Oct. 31, 2013

Mar. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

series

Dividend Paid

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Stock Investment Plan

Term Loan

Term Loan

FMBs

FMBs

PCRB

MP

MP

MP

MP

MP

FE

FE

FE

FE

TrAIL

AGC

FirstEnergy Generation LLC [Member]

AE Supply

FES

FES

FES

FES

FES

FES

FES

FES

FES

JCP&L

JCP&L

JCP&L

ME

ME

ME

Allegheny Energy Inc

Allegheny Energy Inc

Allegheny Energy Inc

Ohio Funding Companies

Ohio Funding Companies

Ohio Funding Companies

Ohio Funding Companies

Ohio Funding Companies

Ohio Funding Companies

Ohio Funding Companies

Ohio Funding Companies

Ohio Funding Companies

FES Corp and Allegheny Energy Inc

FES Corp and Allegheny Energy Inc

FES Corp and Allegheny Energy Inc

FES Corp and Allegheny Energy Inc

PN

credit_facility

Subsequent Event

Common Stock

Minimum

Maximum

PCRB, 7.00% Due 2039

FMBs

FMBs

FMBs

FMBs

Revolving Credit Facility

Senior Notes

Senior Notes

Senior Notes

PCRB

Revolving Credit Facility

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Revolving Credit Facility

Maximum

Unsecured Debt

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Minimum

Maximum

Existing Taxable Bonds

Existing Taxable Bonds

Existing Taxable Bonds

Existing Taxable Bonds

Phase In Recovery Bonds

Revolving Credit Facility

Revolving Credit Facility

Senior Notes

Senior Notes

Senior Notes

FMB, 4.10% Due 2024

FMB, 5.40%, Due 2043

FMB, 7.95% Due 2013

FMB, 6.70% Due 2014

Senior Notes, 4.25% Due 2023

Senior Notes, 2.75% Due 2018

Year 2039

Year 2021

Senior Notes, 4.80% Due 2015

Senior Notes, 4.80% Due 2015

series

Notes, 4.7% Due 2024

Senior Notes, 3.50% Due 2023

Senior Notes, 3.50% Due 2023

Senior Notes, 4.88% Due 2014

Year 2019

Year 2039

Year 2020

Year 2015

Year 2013

Subsequent Event

Minimum

Maximum

Senior Notes, 5.13% Due 2014

Senior Notes, 4.95% Due 2013

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Retained earnings (accumulated deficit)

$2,590,000,000

'

'

'

$2,888,000,000

'

'

$2,590,000,000

$2,888,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$2,178,000,000

$2,118,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividends declared

'

'

'

'

'

'

'

$1.65

$2.20

$2.20

$0.36

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Stock Dividends Per Share Paid

$0.55

$0.55

$0.55

$0.55

$0.55

$0.55

$0.55

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum Equity To Total Capitalization Ratio To Be Maintained for Payment of Capital Dividend

'

'

'

'

'

'

'

35.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

45.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock registered

490,000,000

'

'

'

490,000,000

'

'

490,000,000

490,000,000

'

'

'

'

'

4,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

750

750

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred shares shares outstanding

0

'

'

'

0

'

'

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Face amount of loan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200,000,000

150,000,000

'

'

'

'

400,000,000

600,000,000

'

'

'

1,500,000,000

850,000,000

650,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

500,000,000

300,000,000

'

'

'

'

'

'

'

'

'

410,000,000

35,000,000

150,000,000

225,000,000

445,000,000

'

'

'

'

'

Number of series of notes

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.34%

9.74%

7.00%

'

4.10%

5.40%

7.95%

6.70%

'

'

4.25%

2.75%

'

'

'

'

'

'

'

'

'

'

'

4.80%

4.80%

'

'

4.70%

3.50%

4.95%

4.88%

'

'

'

'

'

5.65%

7.25%

'

'

'

'

'

'

'

5.75%

6.80%

5.13%

Number of credit facilities extended

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preference shares outstanding

0

'

'

'

0

'

'

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of debt redeemed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

572,700,000

'

'

300,000,000

'

'

'

'

'

'

'

235,000,000

235,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

150,000,000

100,000,000

'

'

'

660,000,000

'

'

'

'

'

'

'

'

'

'

'

'

150,000,000

Weighted average interest rate on debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.71%

'

'

'

2.48%

'

'

'

'

'

Make-whole premiums paid on debt redemptions

'

'

'

'

'

'

'

187,000,000

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

31,000,000

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

120,000,000

30,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Debt repurchased

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

120,000,000

'

'

'

'

'

'

'

'

'

'

'

'

369,000,000

117,000,000

252,000,000

400,000,000

'

'

'

'

'

'

'

294,000,000

194,000,000

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments of Debt Redemption Premiums

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

67,000,000

'

'

31,000,000

'

'

'

'

'

'

'

43,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss on debt redemptions

'

'

'

'

'

'

'

-132,000,000

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

119,000,000

'

'

'

'

'

'

-103,000,000

0

0

'

71,000,000

'

'

32,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of revolving line of credit

'

'

'

'

'

'

'

'

'

'

'

2,500,000,000

'

2,500,000,000

'

'

'

'

'

'

'

'

'

'

'

2,500,000,000

'

'

'

'

'

'

'

'

'

'

2,500,000,000

'

'

'

'

'

600,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,500,000,000

2,500,000,000

'

'

'

Line of Credit Facility, Amounts Excluded From Debt to Capital Ratio Calculation

'

'

'

'

'

'

'

'

'

'

'

1,400,000,000

'

1,400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

785,700,000

785,700,000

'

'

'

Line of Credit Facility, Increase, Amounts Excluded From Debt to Capital Ratio Calculation

'

'

'

'

'

'

'

'

'

'

'

1,400,000,000

'

1,350,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Term of extension period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in borrowing capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

500,000,000

'

'

'

'

'

'

'

'

'

'

500,000,000

'

'

'

'

'

175,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Repurchase Notice Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of subsidiaries that issued environmental control bonds

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Remarketed Pollution Control Revenue Bond

472,000,000

'

'

'

493,000,000

'

'

472,000,000

493,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Transition bond outstanding

207,000,000

'

'

'

243,000,000

'

'

207,000,000

243,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of series of bonds

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate annual servicing fees receivable on transition bonds

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

628,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual sinking fund requirement for FMB

'

'

'

'

'

'

'

7,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current payable of long term pollution control revenue bonds

809,000,000

'

'

'

'

'

'

809,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

736,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Principal default amount specified in debt covenants

'

'

'

'

'

'

'

$100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

ShortTerm_Borrowings_and_Bank_2

Short-Term Borrowings and Bank Lines of Credit (Details) (USD $)

Jan. 31, 2014

Jan. 31, 2014

Dec. 31, 2013

Jan. 31, 2014

Jan. 31, 2014

Jan. 31, 2014

Jan. 31, 2014

Dec. 31, 2013

Jan. 31, 2014

Jan. 31, 2014

Subsequent Event

FirstEnergy

FirstEnergy

FirstEnergy

FES / AE Supply

FES / AE Supply

FET

FET

FET

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Subsequent Event

Subsequent Event

Subsequent Event

Short-term Debt [Line Items]

'

'

'

'

'

'

'

'

'

'

Maximum amount borrowed under revolving credit facility

$6,000,000,000

'

$2,500,000,000

[1]

$2,500,000,000

[2]

'

$2,500,000,000

'

$1,000,000,000

[1]

$1,000,000,000

[3]

'

Available Liquidity

'

2,713,000,000

'

'

224,000,000

[2]

'

2,489,000,000

'

'

0

[3]

Cash, Available Liquidity

'

48,000,000

'

'

'

'

'

'

'

'

Total Available Liquidity

'

$2,761,000,000

'

'

'

'

'

'

'

'

[1]

(1)No limitations.

[2]

(1)FE and the Utilities

[3]

(2)Includes FET, ATSI and TrAIL as subsidiary borrowers

ShortTerm_Borrowings_and_Bank_3

Short-Term Borrowings and Bank Lines of Credit (Details 1) (USD $)

Jan. 31, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

FE

FES

AE Supply

FET

OE

CEI

TE

JCP&L

ME

PN

WP

MP

PE

ATSI

Penn

TrAIL

Borrowing sub-limits for each borrower and limitations on short-term indebtedness

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revolving Credit Facility Sub-Limit

$6,000,000,000

$2,500,000,000

[1]

$1,500,000,000

[2]

$1,000,000,000

[2]

$1,000,000,000

[1]

$500,000,000

[3]

$500,000,000

[3]

$500,000,000

[3]

$600,000,000

[3]

$300,000,000

[3]

$300,000,000

[3]

$200,000,000

[3]

$150,000,000

[3]

$150,000,000

[3]

$100,000,000

[3]

$50,000,000

[3]

$200,000,000

[3]

Regulatory and Other Short-Term Debt Limitations

'

$0

[1]

$0

[2]

$0

[2]

$0

[1]

$500,000,000

[3]

$500,000,000

[3]

$500,000,000

[3]

$850,000,000

[3]

$500,000,000

[3]

$300,000,000

[3]

$200,000,000

[3]

$500,000,000

[3]

$150,000,000

[3]

$500,000,000

[3]

$50,000,000

[3]

$400,000,000

[3]

[1]

(1)No limitations.

[2]

(2)No limitation based upon blanket financing authorization from the FERC under existing market-based rate tariffs.

[3]

(3)Excluding amounts which may be borrowed under the regulated companies' money pool.

ShortTerm_Borrowings_and_Bank_4

Short-Term Borrowings and Bank Lines of Credit (Details 2)	Dec. 31, 2013	Dec. 31, 2012
Short-term Borrowings and Bank Lines of Credit [Abstract]	'	'
Weighted average interest rate	1.80%	1.97%

ShortTerm_Borrowings_and_Bank_5

Short-Term Borrowings and Bank Lines of Credit (Details Textuals) (USD $)

Jan. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Nov. 30, 2013

Oct. 31, 2013

8-May-13

Mar. 31, 2013

8-May-13

Dec. 31, 2013

Dec. 31, 2012

8-May-13

Dec. 31, 2013

8-May-13

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Mar. 31, 2013

Oct. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Jan. 31, 2014

Dec. 31, 2013

Jan. 31, 2014

Jan. 31, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

money_pool

Amended Term Loan [Member]

Term Loan

Term Loan

Revolving Credit Facility

Revolving Credit Facility

FE

FE

FES

FES

FES

JCP&L

JCP&L

FirstEnergy

FET

PN

PN

ME

ME

FES Corp and Allegheny Energy Inc

FES Corp and Allegheny Energy Inc

FES Corp and Allegheny Energy Inc

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Available for Issuance of Letters of Credit

Available for Issuance of Letters of Credit

Available for Issuance of Letters of Credit

Available for Issuance of Letters of Credit

Money Pool

Money Pool

Money Pool

credit_facility

Senior Notes

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Revolving Credit Facility

extension

Minimum

FES / AE Supply

Parent and Certain Subsidiaries

FirstEnergy

FET

Minimum

FET

FET

Maximum

Unregulated Companies

Regulated Companies

Senior Notes, 5.13% Due 2014

Senior Notes, 4.88% Due 2014

Minimum

Maximum

credit_facility

Minimum

Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Short-term borrowings

'

$3,404,000,000

$1,969,000,000

'

'

'

'

'

'

'

$4,000,000

$4,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of credit facilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

Term of credit facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

Maximum amount borrowed under revolving credit facility

6,000,000,000

'

'

'

'

'

'

'

'

'

1,500,000,000

[1]

'

'

600,000,000

[2]

'

2,500,000,000

[3]

1,000,000,000

[3]

300,000,000

[2]

'

300,000,000

[2]

'

'

'

'

'

'

2,500,000,000

6,000,000,000

2,500,000,000

[4]

1,000,000,000

[5]

'

'

'

'

'

'

'

Number of credit facilities extended

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of extension periods

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

Term of extension period

'

'

'

'

'

'

'

'

'

'1 year

'

'

'1 year

'

'1 year

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

Term of revolving credit facility, in days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'364 days

'

'

'

'

'

'

'

'

'364 days

'

'

Increase in borrowing capacity

'

'

'

'

'

'

'

'

'

500,000,000

'

'

500,000,000

'

175,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of revolving line of credit

'

'

'

'

'

'

2,500,000,000

'

'

2,500,000,000

'

'

2,500,000,000

'

600,000,000

'

'

'

'

'

'

'

'

2,500,000,000

'

'

'

'

'

'

700,000,000

'

225,000,000

'

'

'

'

Line of Credit Facility, Amounts Excluded From Debt to Capital Ratio Calculation

'

'

'

'

'

'

1,400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

785,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Increase, Amounts Excluded From Debt to Capital Ratio Calculation

'

'

'

'

'

'

1,400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cross-default provision for other indebtedness

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

'

100

'

'

'

Face amount of loan

'

'

'

150,000,000

200,000,000

150,000,000

'

'

1,500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of debt redeemed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$150,000,000

'

$100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.13%

'

4.88%

5.75%

6.80%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of money pools

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Average interest rate for borrowings

'

1.80%

1.97%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.34%

0.67%

[1]

(2)No limitation based upon blanket financing authorization from the FERC under existing market-based rate tariffs.

[2]

(3)Excluding amounts which may be borrowed under the regulated companies' money pool.

[3]

(1)No limitations.

[4]

(1)FE and the Utilities

[5]

(2)Includes FET, ATSI and TrAIL as subsidiary borrowers

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligations [Line Items]	'	'	'	'
Asset Retirement Obligation, Legally Restricted Assets, Fair Value	$2,201	'	$2,201	$2,204
Changes to the asset retirement obligations	'	'	'	'
Beginning Balance	'	'	1,599	1,497
Liabilities settled	'	'	-18	-2
Accretion	'	'	115	104
Revisions in estimated cash flows	'	'	-18	'
Ending Balance	1,678	'	1,678	1,599
FES	'	'	'	'
Asset Retirement Obligations [Line Items]	'	'	'	'
Asset Retirement Obligation, Legally Restricted Assets, Fair Value	1,276	'	1,276	1,283
Changes to the asset retirement obligations	'	'	'	'
Beginning Balance	'	'	965	904
Liabilities settled	'	'	-18	-1
Accretion	'	'	71	62
Revisions in estimated cash flows	-171	5	-3	'
Ending Balance	1,015	'	1,015	965
FES | LBR	'	'	'	'
Changes to the asset retirement obligations	'	'	'	'
Revisions in estimated cash flows	'	'	163	'
OE	'	'	'	'
Changes to the asset retirement obligations	'	'	'	'
Revisions in estimated cash flows	-15	'	'	'
TE	'	'	'	'
Changes to the asset retirement obligations	'	'	'	'
Revisions in estimated cash flows	($7)	$7	'	'

Regulatory_Matters_Details

Regulatory Matters (Details) (USD $)

3 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

0 Months Ended

3 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Apr. 30, 2007

Dec. 31, 2013

Jan. 21, 2010

Sep. 04, 2013

31-May-13

Dec. 07, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Oct. 09, 2013

Dec. 31, 2013

Oct. 09, 2013

Dec. 31, 2013

Aug. 24, 2012

Dec. 31, 2013

Aug. 24, 2012

Aug. 24, 2012

Sep. 28, 2012

Dec. 31, 2013

Sep. 03, 2013

Dec. 22, 2011

Dec. 31, 2013

Dec. 31, 2008

Aug. 31, 2011

Oct. 06, 2009

Jun. 14, 2013

Dec. 31, 2013

Feb. 22, 2013

Nov. 30, 2012

Jun. 14, 2013

Aug. 07, 2013

Jan. 31, 2013

Apr. 13, 2012

Dec. 31, 2013

Dec. 31, 2009

Dec. 12, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Aug. 07, 2013

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2010

Dec. 12, 2013

Dec. 02, 2013

Feb. 15, 2013

Jan. 16, 2013

Dec. 31, 2012

31-May-11

Apr. 29, 2011

31-May-13

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Feb. 06, 2013

Apr. 30, 2010

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2010

Oct. 22, 2012

Oct. 31, 2006

Dec. 31, 2013

Jan. 27, 2014

Jan. 27, 2014

Feb. 24, 2014

Feb. 12, 2014

entities

FERC

FERC

FERC

FERC

FERC

FERC

PJM

FES

FES

FES

AE Supply

AE Supply

MP

MP

PATH

PATH

PATH-Allegheny

Path-WV

Path-WV

FES and AE Supply

MARYLAND

MARYLAND

MARYLAND

MARYLAND

MARYLAND

MARYLAND

NEW JERSEY

NEW JERSEY

NEW JERSEY

NEW JERSEY

NEW JERSEY

OHIO

OHIO

OHIO

OHIO

OHIO

OHIO

OHIO

OHIO

OHIO

OHIO

OHIO

OHIO

OHIO

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

PENNSYLVANIA

WEST VIRGINIA

WEST VIRGINIA

WEST VIRGINIA

WEST VIRGINIA

WEST VIRGINIA

California Claims Matters

California Claims Matters

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

kv

issues

Hydroelectric Asset Sale

MOPR Reform

MOPR Reform

FERC

FERC

FERC

FERC

FERC

FERC

FERC

component

JCP&L

Party

plan

questions

Year 2012

Year 2013

Year 2014

Annually Through 2025

Annually Through 2018

PUCO

PUCO

proposals

issues

smart_meter

comment

Party

questions

Year 2013

Three Month Period

Twelve Month Period

Twenty-Four Month Period

Forty-Eight Month Period

Unfavorable Regulatory Action

Unfavorable Regulatory Action

MW

hearing

FERC

FERC

NEW JERSEY

NEW JERSEY

NEW JERSEY

Hydroelectric Power Plant Projects [Member]

plant

exemption

kv

challenge

FTR Underfunding Complaint

bgs

MWh

MWh

MWh

MWh

auctions

workgroup

issues

Proceedings

JCP&L

JCP&L

JCP&L

MW

Minimum

Rate Counsel

NJBPU

NJBPU

Regulatory Matters [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proposed electric consumption reduction percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proposed electric demand reduction percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expenditures for cost recovery program

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$66,000,000

$101,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recovery period for expenditures for cost recovery program

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum penalty assessed, in dollars per day per violation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected increase in cost due to proposed plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

106,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected Infrastructure Investments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,700,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected Infrastructure Investments, Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'15 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Supply Components

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Basic Generation Services

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Requested increase in revenues

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

603,000,000

31,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Disallowed recovery costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15,000,000

8,000,000

'

'

Public Utilities, Requested Recovery of Deferred Costs, Allowed Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

736

'

Public Utilities, Requested Recovery of Deferred Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

744

'

Number of renewable energy auctions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization of Regulatory Asset

'

539,000,000

307,000,000

474,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

51,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Revenue Recovery Request

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

112,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Load cap percentage minimum

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

80.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum trance award to a single supplier

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

80.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Generation discount for low income customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recovery Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Costs avoided by customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

360,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fund to assist low income customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

ESP Extension Term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, New Claims Filed, Number

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Generation supply auction period, after approval

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Generation supply auction period, before approval

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual energy savings

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,211,000

1,726,000

2,306,000

2,903,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (decrease) in annual energy savings

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

416,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Utilities required to reduce peak demand

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Utilities required to additionally reduce peak demand

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of plans

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Portfolio Plan, Estimated Cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Portion of Revenue Obtained to be Received

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Credit to Non-Shopping Customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

43,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Credit to Non-Shopping Customers, Implementation Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'60 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Marginal Transmission Refund Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'29 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Marginal transmission losses

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

254,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset Impairment Charges

473,000,000

795,000,000

0

413,000,000

'

'

'

'

'

'

'

0

0

294,000,000

'

'

'

322,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

254,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

322,000,000

'

'

'

'

'

'

'

'

'

Regulatory Liabilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23,000,000

'

'

'

'

'

'

'

'

'

Minimum reduction in Utilities reduce energy consumption

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

3.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum reduction in Utilities peak demand

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Statutory penalty, minimum

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Statutory penalty, maximum

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20,000,000

234,000,000

'

'

'

'

'

'

'

'

'

'

'

Number of parties not settled

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of issues not settled

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Energy Contract, Term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 months

'12 months

'24 months

'48 months

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Requests For Proposal

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Request for Proposal, Project Term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number Of Smart Meters Requested To Be Installed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

170,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number Of Smart Meters Originally Proposed To Be Installed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

60,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annualized base rate increase

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

40,000,000

'

'

'

'

'

'

'

Storm Restoration Deferral Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

Number of public hearings held

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

Period of time to implement plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'6 months

'

'

'

'

'

'

'

'

Additional base rate increase

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20,000,000

'

'

'

'

'

'

'

Recommend Reduction in Base Rates for Electric Service

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

202,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

214,900,000

207,400,000

'

'

Decrease in ENEC rates

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20,000,000

'

'

'

'

'

'

'

Cash consideration received in asset swap transaction

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Assumption of pollution control note

'

'

'

'

'

'

'

'

'

'

'

'

'

'

73,500,000

73,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity contribution from parent

'

'

'

'

'

'

'

'

'

'

'

1,500,000,000

0

0

'

'

527,000,000

527,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loans to affiliated companies, net

'

'

'

'

'

'

'

'

'

'

'

276,000,000

107,000,000

14,000,000

'

'

573,000,000

573,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Power threshold for cost methodology

'

'

'

'

500

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Compliance Filing, Hybrid Methodology, Beneficiary Pays Cost Allocation

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Denied Recovery Charges of Exit Fees

'

'

'

'

'

78,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Identified issues for written comments

'

'

'

'

'

'

9

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual Revenue requirements in Zone

'

'

'

'

'

16,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Settlement proposal claims

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

190,000,000

'

'

'

'

Court proceedings from filed claims

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

New Voltage transmission facilities across PJM and a zonal transmission rate (In KV)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

765

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cost recovery, PP&E reclassified to Regulatory Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

62,000,000

59,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Formal Challenges

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Discontinued operations (net of income taxes of $9, $8 and $8, respectively) (Note 20)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

395,000,000

Auctioned Energy Price

'

'

'

'

'

'

'

'

59

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Application to Sell Power Plant Projects, Number

'

'

'

'

'

'

'

11

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Application to Sell Power Plant Projects, Combined Power

'

'

'

'

'

'

'

527

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Exemptions Added

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percent of Meters to be Installed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

98.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected Cost of Meter Installations

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Directed Questions for Investigation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

22

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Workgroups Established

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Comments Established

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory Asset, Cost Recovery, Proposed Return on Equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.90%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Base Return On Equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.40%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Return On Equity Granted For Regional Transmission Organization Participation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Remaining Recovery Period of Regulatory Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenues Lost of Which the Entity is Entitled

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$65,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Resource Plan, Proposed Transfer

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,476

'

'

'

'

'

'

'

'

Compliance Filing, Hybrid Methodology, Postage Stamp Cost Allocation

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regional Enforcement Entities

'

8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitments_Guarantees_and_Con2

Commitments, Guarantees and Contingencies (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	$923
Split Rating (One rating agency's rating below investment grade)	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	555
BB Plus/BA1 Credit Ratings	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	601
FES	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	777
FES | Split Rating (One rating agency's rating below investment grade)	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	496
FES | BB Plus/BA1 Credit Ratings	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	542
AE Supply	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	58
AE Supply | Split Rating (One rating agency's rating below investment grade)	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	6
AE Supply | BB Plus/BA1 Credit Ratings	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	6
Utilities	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	88
Utilities | Split Rating (One rating agency's rating below investment grade)	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	53
Utilities | BB Plus/BA1 Credit Ratings	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	$53

Commitments_Guarantees_and_Con3

Commitments, Guarantees and Contingencies (Details Textuals) (USD $)

12 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Apr. 19, 2013

Apr. 13, 2013

Dec. 31, 2010

Jan. 31, 2009

Jun. 30, 2013

Jun. 30, 2013

Dec. 31, 2013

Apr. 30, 2009

Oct. 10, 2013

Oct. 03, 2013

Mar. 28, 2013

Dec. 31, 2013

Dec. 31, 2013

Feb. 18, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jan. 31, 2014

Dec. 31, 2013

Apr. 13, 2012

Jan. 02, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 05, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Aug. 13, 2012

2-May-11

Feb. 13, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Apr. 13, 2012

Dec. 31, 2013

Apr. 13, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

NuclearPowerPlants

options

MW

mi

ICG Litigation

Year 2020

Clean Water Act

Clean Water Act

Regulation of Waste Disposal

Regulation of Waste Disposal

Regulation of Waste Disposal

Regulation of Waste Disposal

Nuclear Plant Matters

Nuclear Plant Matters

Caa Compliance

National Ambient Air Quality Standards

National Ambient Air Quality Standards

National Ambient Air Quality Standards

Hazardous Air Pollutant Emissions

Hazardous Air Pollutant Emissions

Climate Change

Climate Change

Climate Change

Climate Change

Senior Secured Term Loan

Competitive Energy Services

Regulated Distribution

Regulated Distribution

OE

FES

FES

FES

AE Supply

AE Supply

Global Holding

Global Holding

Global Holding

Signal Peak and Global Rail

Signal Peak and Global Rail

FEV

WMB Marketing Ventures, LLC

FGCO

FGCO

FGCO

FGCO

FGCO

FGCO

FGCO

AE Supply and MP

AE Supply and MP

Wp

NGC

TE

ME

Parental Guarantees

Subsidiaries' Guarantees

Other Guarantees

State and Local Agencies

Environmental Protection Agency

Minimum

Minimum

Maximum

Maximum

Transportation Commitment

Transportation Commitment

LBR

aspect_of_opinion

IndividualsInAComplaint

deficiency

options

Subsequent Event

ElectricGenerationUnits

T

CAIR

CSAPR

Mepco Holdings,LLC

celsius

lb

T

Year 2020

Senior Loans

Hazardous Air Pollutant Emissions

Hazardous Air Pollutant Emissions

ICG Litigation

Senior Secured Term Loan

Senior Secured Term Loan

Senior Secured Term Loan

Senior Secured Term Loan

Senior Secured Term Loan

Regulation of Waste Disposal

Caa Compliance

Caa Compliance

Caa Compliance

ICG Litigation

ICG Litigation

Hazardous Air Pollutant Emissions

Hazardous Air Pollutant Emissions

Clean Water Act

Climate Change

Clean Water Act

Climate Change

Hazardous Air Pollutant Emissions

Hazardous Air Pollutant Emissions

petitioners

CoalFiredPlants

phases

phases

Subsequent Event

Increase in funding

Senior Loans

Senior Loans

Senior Loans

Senior Loans

Senior Loans

IndividualsInAComplaint

Complaints

Claim One

Claim Two

contracts

Signal Peak, Global Rail and Affiliates

Signal Peak

Signal Peak

IndividualsInAComplaint

plaintiff

Global Holding

Global Holding

Complaints

Guarantor Obligations [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Liability Asses with Respect to Single Nuclear Incident Based On Act

$13,600,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding guarantees and other assurances aggregated

4,300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,375,000,000

2,197,000,000

742,000,000

'

'

'

'

'

'

'

'

'

Company posted collateral related to net liability positions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,000,000

'

'

142,000,000

'

'

8,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Potential collateral posted related to net liability positions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

66,000,000

'

'

2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Nuclear Insurance Policy, Environmental Plan, Submission Period

'30 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior secured term loan facility, term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

New syndicated senior secured term loan facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

350,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayments of senior secured term loan facility

3,600,000,000

940,000,000

1,909,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,202,000,000

429,000,000

856,000,000

'

'

'

'

'

'

350,000,000

'

'

364,000,000

288,000,000

362,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Investment ownership percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

69.99%

'

'

33.33%

33.33%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Guarantor obligations, guarantee fee receivable, percentage, remainder of fiscal year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Guarantor obligations, guarantee fee receivable, percentage, next twelve months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of complaints filed against FGCO

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of complaints seek enjoin plant

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Jointly Owned Utility Plant, Proportionate Ownership Share

'

'

'

'

'

'

16.67%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of individuals behalf of which complaint filed

'

'

'

'

'

'

'

'

'

'

'

50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15

'

21

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of named plaintiffs as class representatives

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reduction in air emissions and compliance

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25.00%

'

40.00%

'

'

'

Commitment, Proposed Regulation, Number Of Treatment Options

'

'

'

8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitment, Proposed Regulation, Number Of Preferred Treatment Options

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitment,Proposed Regulation, Waste Water Discharge Permit, Renewal Cycle

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of electric generation facilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of generation units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

22

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of phases under the EPAbs CAIR for reductions of Sulfur Dioxide and Mono-Nitrogen Oxides

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capping of SO2 emissions (In Tons)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capping of NOx emissions (In Tons)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capping of SO2 Emissions Under CSAPR

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capping of NOx emissions under CSAPR

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Potential cost of compliance, MATS

'

'

'

'

'

'

'

'

'

'

'

'

'

'

234,000,000

'

'

'

'

'

'

465,000,000

'

'

'

'

'

'

240,000,000

'

225,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Settlement Agreement, Consideration

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

70,000,000

67,000,000

'

Proposed Executive Action, Reduction in Power Plants Carbon Pollution, Percentage

'

'

'

'

'

'

'

'

17.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Pre-tax severance expense related to closures

'

14,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Upper threshold limit for carbon dioxide emission (Tons per Year)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proposed Green House Gas Performance Standards, Minimum Output Size To Be Effected

'

'

'

'

25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (decrease) in global temperature

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Funds provided for Copenhagen Green Climate Fund

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30,000,000,000

'

'

100,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitment Period by Developed Countries to Provide Funds, Years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitment, Proposed Emissions Standard, Other Natural Gas Fired Units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,100

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitment, Proposed Emissions Standard, Fossil Fuel Fired Units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,100

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aspects of opinion reversed

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual percentage that fish impingement should be reduced to, per CWA

'

'

'

'

'

'

'

'

'

12.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum capital investment required to install technology to meet TDS and Sulfate limits

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

150,000,000

'

300,000,000

'

'

'

'

Proposed Sulfate Impairment Designation, Length

'

'

'

'

'

68

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

TMDL Limit Development Period

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Deficiencies Identified in Plan

'

'

'

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Options proposed by EPA for additional regulation of coal combustion residuals

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Claims Resolution, Civil Penalties

'

'

'

'

'

'

'

'

'

'

'

'

'

'

800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

86,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period of time to implement plan

'

'

'

'

'

'

'

'

'

'

'

'

'9 years

'15 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Bond Closure and Post Closure Period

'

'

'

'

'

'

'

'

'

'

'

'

'45 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset Retirement Obligation, Period Increase (Decrease)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

163,000,000

Accrual for Environmental Loss Contingencies

'

'

'

'

'

'

'

'

'

'

'

'

'

'

128,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Environmental Liabilities Former Gas Facilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

82,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Decommissioning Fund Investments

2,201,000,000

2,204,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

2,200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,276,000,000

1,283,000,000

'

'

'

'

'

'

'

'

'

'

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Parental guarantee associated with the funding of decommissioning costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

125,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Parental Guarantee Associated With Funding Of Decommissioning Costs, Additions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Renewal length of operating license for Davis-Besse Nuclear Power Station

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'20 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss incurred in damages for replacement coal purchased

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

80,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Additional damages incurred for future shortfalls

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

150,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Verdict in Favor

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

104,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount for which verdict entered for future damages

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

90,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount for replacement coal and interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain contingency, unrecorded amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain Contingency, Damages Denied, Value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

90,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Potential MATS Extension Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'1 year

'

'

'

'

'

'

'

Contractual Obligation, Number of Agreements

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

Commitment, Proposed Emissions Standard, Large Natural Gas Fired Units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain contingency, damages denied

'

'

'

'

'

'

'

15,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected Number of Nuclear Power Plant Licensed to Operate

104

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Portion of Insurance Coverage of Private Insurer included in Single Nuclear Incident Liability

375,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Portion of Insurance Coverage by Industry Retrospective Rating Plan

13,200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

44,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

442,000,000

23,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

66,000,000

3,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Nuclear Insurance Policy, Aggregate Indemnity

2,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

168,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,700,000,000

90,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Nuclear Insurance Policy, Maximum Aggregate Assessments for Incidents at any Covered Nuclear Facility

14,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12,000,000

600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Coverage of Decontamination Costs As Per Property Damage Insurance

2,750,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Retrospective Assessments Liabilities

79,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

68,000,000

3,000,000

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Insurance Coverage For Replacement Power Costs

$1,060,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of petitioners requesting rulemaking

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Transactions_With_Affiliated_C2

Transactions With Affiliated Companies (Details) (FES, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Investment Income:	'	'	'
Interest income from FE	$2	$2	$2
Interest Expense:	'	'	'
Interest expense to affiliates	4	10	8
Interest expense to FE	6	1	1
Electric sales to affiliates	'	'	'
REVENUES:	'	'	'
Related Party Transaction, Revenues from Transactions with Related Party	652	515	752
Other	'	'	'
REVENUES:	'	'	'
Related Party Transaction, Revenues from Transactions with Related Party	6	16	80
Purchased power from affiliates	'	'	'
EXPENSES:	'	'	'
Related Party Transaction, Expenses from Transactions with Related Party	486	451	242
Fuel	'	'	'
EXPENSES:	'	'	'
Related Party Transaction, Expenses from Transactions with Related Party	0	2	37
Support services	'	'	'
EXPENSES:	'	'	'
Related Party Transaction, Expenses from Transactions with Related Party	$619	$570	$655

Supplemental_Guarantor_Informa2

Supplemental Guarantor Information (Details) (USD $)

3 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Consolidating Statements of Income

'

'

'

'

'

'

'

'

'

'

'

Revenue, Net

'

'

'

'

'

'

'

'

$14,917

[1]

$15,273

[1]

$16,105

[1]

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Fuel

'

'

'

'

'

'

'

'

2,496

2,471

2,317

Purchased power

'

'

'

'

'

'

'

'

3,963

4,246

4,874

Other operating expenses

948

877

886

882

1,163

861

920

816

3,593

3,760

3,949

Pensions and OPEB mark-to-market adjustment

-256

0

0

0

609

0

0

0

-256

609

507

Provision for depreciation

293

316

300

293

285

272

284

278

1,202

1,119

1,062

General taxes

'

'

'

'

'

'

'

'

978

984

977

Total operating expenses

'

'

'

'

'

'

'

'

13,310

13,121

14,428

OPERATING INCOME (LOSS)

401

512

46

648

-39

902

549

740

1,607

2,152

1,677

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Loss on debt redemptions

'

'

'

'

'

'

'

'

-132

0

0

Investment income

'

'

'

'

'

'

'

'

36

77

114

Interest expense

'

'

'

'

'

'

'

'

-1,016

-1,001

-1,008

Capitalized interest

'

'

'

'

'

'

'

'

75

72

70

Total other income (expense)

'

'

'

'

'

'

'

'

-1,037

-852

-255

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

'

'

'

'

'

'

'

'

570

1,300

1,422

INCOME TAXES (BENEFITS)

66

77

-62

114

-105

307

123

220

195

545

566

INCOME FROM CONTINUING OPERATIONS

142

209

-168

192

-153

422

184

302

375

755

856

Discontinued operations (Note 20)

0

9

4

4

5

3

4

4

17

16

13

NET INCOME (LOSS)

142

218

-164

196

-148

425

188

306

392

771

869

OTHER COMPREHENSIVE INCOME (LOSS):

'

'

'

'

'

'

'

'

'

'

'

NET INCOME

142

218

-164

196

-148

425

188

306

392

771

869

Pensions and OPEB prior service costs

'

'

'

'

'

'

'

'

-160

-115

-90

Amortized loss (gain) on derivative hedges

'

'

'

'

'

'

'

'

3

1

23

Change in unrealized gain on available-for-sale securities

'

'

'

'

'

'

'

'

-10

-6

19

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

-167

-120

-48

Income taxes (benefits) on other comprehensive income (loss)

'

'

'

'

'

'

'

'

-66

-79

-49

Other comprehensive income (loss), net of tax

'

'

'

'

'

'

'

'

-101

-41

1

COMPREHENSIVE INCOME (LOSS)

'

'

'

'

'

'

'

'

291

730

870

FES

'

'

'

'

'

'

'

'

'

'

'

Consolidating Statements of Income

'

'

'

'

'

'

'

'

'

'

'

Revenue, Net

'

'

'

'

'

'

'

'

6,068

5,804

5,387

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Fuel

'

'

'

'

'

'

'

'

0

0

12

Other operating expenses

'

'

'

'

'

'

'

'

635

434

574

Pensions and OPEB mark-to-market adjustment

'

'

'

'

'

'

'

'

-8

-2

10

Provision for depreciation

'

'

'

'

'

'

'

'

6

4

4

General taxes

'

'

'

'

'

'

'

'

80

79

64

Impairment of long-lived assets

'

'

'

'

'

'

'

'

'

'

0

Total operating expenses

'

'

'

'

'

'

'

'

7,187

6,494

6,250

OPERATING INCOME (LOSS)

'

'

'

'

'

'

'

'

-1,119

-690

-863

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Loss on debt redemptions

'

'

'

'

'

'

'

'

-103

'

'

Investment income

'

'

'

'

'

'

'

'

5

2

1

Miscellaneous income, including net income from equity investees

'

'

'

'

'

'

'

'

846

1,284

924

Capitalized interest

'

'

'

'

'

'

'

'

1

0

0

Total other income (expense)

'

'

'

'

'

'

'

'

673

1,175

829

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

'

'

'

'

'

'

'

'

-446

485

-34

INCOME TAXES (BENEFITS)

'

'

'

'

'

'

'

'

-506

298

25

INCOME FROM CONTINUING OPERATIONS

'

'

'

'

'

'

'

'

60

187

-59

Discontinued operations (Note 20)

'

'

'

'

'

'

'

'

0

0

0

NET INCOME (LOSS)

'

'

'

'

'

'

'

'

60

187

-59

OTHER COMPREHENSIVE INCOME (LOSS):

'

'

'

'

'

'

'

'

'

'

'

NET INCOME

'

'

'

'

'

'

'

'

60

187

-59

Pensions and OPEB prior service costs

'

'

'

'

'

'

'

'

-15

6

-12

Amortized loss (gain) on derivative hedges

'

'

'

'

'

'

'

'

-6

-9

12

Change in unrealized gain on available-for-sale securities

'

'

'

'

'

'

'

'

-8

-5

16

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

-29

-8

16

Income taxes (benefits) on other comprehensive income (loss)

'

'

'

'

'

'

'

'

-11

-4

2

Other comprehensive income (loss), net of tax

'

'

'

'

'

'

'

'

-18

-4

14

COMPREHENSIVE INCOME (LOSS)

'

'

'

'

'

'

'

'

42

183

-45

FES | Affiliates

'

'

'

'

'

'

'

'

'

'

'

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Purchased power

'

'

'

'

'

'

'

'

4,148

4,098

4,208

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

-13

-18

-2

FES | Non-Affiliates

'

'

'

'

'

'

'

'

'

'

'

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Purchased power

'

'

'

'

'

'

'

'

2,326

1,881

1,378

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

-63

-93

-94

FGCO

'

'

'

'

'

'

'

'

'

'

'

Consolidating Statements of Income

'

'

'

'

'

'

'

'

'

'

'

Revenue, Net

'

'

'

'

'

'

'

'

2,399

2,100

2,642

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Fuel

'

'

'

'

'

'

'

'

1,056

1,077

1,138

Other operating expenses

'

'

'

'

'

'

'

'

275

334

416

Pensions and OPEB mark-to-market adjustment

'

'

'

'

'

'

'

'

-37

52

68

Provision for depreciation

'

'

'

'

'

'

'

'

127

116

124

General taxes

'

'

'

'

'

'

'

'

34

36

37

Impairment of long-lived assets

'

'

'

'

'

'

'

'

'

'

294

Total operating expenses

'

'

'

'

'

'

'

'

1,462

1,621

2,085

OPERATING INCOME (LOSS)

'

'

'

'

'

'

'

'

937

479

557

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Loss on debt redemptions

'

'

'

'

'

'

'

'

0

'

'

Investment income

'

'

'

'

'

'

'

'

1

15

0

Miscellaneous income, including net income from equity investees

'

'

'

'

'

'

'

'

24

20

24

Capitalized interest

'

'

'

'

'

'

'

'

2

4

12

Total other income (expense)

'

'

'

'

'

'

'

'

-82

-78

-76

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

'

'

'

'

'

'

'

'

855

401

481

INCOME TAXES (BENEFITS)

'

'

'

'

'

'

'

'

365

-269

-117

INCOME FROM CONTINUING OPERATIONS

'

'

'

'

'

'

'

'

490

670

598

Discontinued operations (Note 20)

'

'

'

'

'

'

'

'

14

14

8

NET INCOME (LOSS)

'

'

'

'

'

'

'

'

504

684

606

OTHER COMPREHENSIVE INCOME (LOSS):

'

'

'

'

'

'

'

'

'

'

'

NET INCOME

'

'

'

'

'

'

'

'

504

684

606

Pensions and OPEB prior service costs

'

'

'

'

'

'

'

'

-13

6

-13

Amortized loss (gain) on derivative hedges

'

'

'

'

'

'

'

'

0

0

0

Change in unrealized gain on available-for-sale securities

'

'

'

'

'

'

'

'

0

0

0

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

-13

6

-13

Income taxes (benefits) on other comprehensive income (loss)

'

'

'

'

'

'

'

'

-5

1

-8

Other comprehensive income (loss), net of tax

'

'

'

'

'

'

'

'

-8

5

-5

COMPREHENSIVE INCOME (LOSS)

'

'

'

'

'

'

'

'

496

689

601

FGCO | Affiliates

'

'

'

'

'

'

'

'

'

'

'

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Purchased power

'

'

'

'

'

'

'

'

0

0

5

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

-5

-7

-3

FGCO | Non-Affiliates

'

'

'

'

'

'

'

'

'

'

'

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Purchased power

'

'

'

'

'

'

'

'

7

6

3

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

-104

-110

-109

Nuclear Generation Corp

'

'

'

'

'

'

'

'

'

'

'

Consolidating Statements of Income

'

'

'

'

'

'

'

'

'

'

'

Revenue, Net

'

'

'

'

'

'

'

'

1,634

1,895

1,647

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Fuel

'

'

'

'

'

'

'

'

206

210

194

Other operating expenses

'

'

'

'

'

'

'

'

529

539

578

Pensions and OPEB mark-to-market adjustment

'

'

'

'

'

'

'

'

-36

116

93

Provision for depreciation

'

'

'

'

'

'

'

'

178

157

150

General taxes

'

'

'

'

'

'

'

'

24

21

23

Impairment of long-lived assets

'

'

'

'

'

'

'

'

'

'

0

Total operating expenses

'

'

'

'

'

'

'

'

1,167

1,301

1,290

OPERATING INCOME (LOSS)

'

'

'

'

'

'

'

'

467

594

357

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Loss on debt redemptions

'

'

'

'

'

'

'

'

0

'

'

Investment income

'

'

'

'

'

'

'

'

25

67

56

Miscellaneous income, including net income from equity investees

'

'

'

'

'

'

'

'

0

0

0

Capitalized interest

'

'

'

'

'

'

'

'

36

33

23

Total other income (expense)

'

'

'

'

'

'

'

'

1

46

13

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

'

'

'

'

'

'

'

'

468

640

370

INCOME TAXES (BENEFITS)

'

'

'

'

'

'

'

'

135

62

58

INCOME FROM CONTINUING OPERATIONS

'

'

'

'

'

'

'

'

333

578

312

Discontinued operations (Note 20)

'

'

'

'

'

'

'

'

0

0

0

NET INCOME (LOSS)

'

'

'

'

'

'

'

'

333

578

312

OTHER COMPREHENSIVE INCOME (LOSS):

'

'

'

'

'

'

'

'

'

'

'

NET INCOME

'

'

'

'

'

'

'

'

333

578

312

Pensions and OPEB prior service costs

'

'

'

'

'

'

'

'

0

0

0

Amortized loss (gain) on derivative hedges

'

'

'

'

'

'

'

'

0

0

0

Change in unrealized gain on available-for-sale securities

'

'

'

'

'

'

'

'

-8

-5

15

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

-8

-5

15

Income taxes (benefits) on other comprehensive income (loss)

'

'

'

'

'

'

'

'

-3

-2

5

Other comprehensive income (loss), net of tax

'

'

'

'

'

'

'

'

-5

-3

10

COMPREHENSIVE INCOME (LOSS)

'

'

'

'

'

'

'

'

328

575

322

Nuclear Generation Corp | Affiliates

'

'

'

'

'

'

'

'

'

'

'

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Purchased power

'

'

'

'

'

'

'

'

266

258

252

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

-6

-4

-2

Nuclear Generation Corp | Non-Affiliates

'

'

'

'

'

'

'

'

'

'

'

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Purchased power

'

'

'

'

'

'

'

'

0

0

0

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

-54

-50

-64

Eliminations

'

'

'

'

'

'

'

'

'

'

'

Consolidating Statements of Income

'

'

'

'

'

'

'

'

'

'

'

Revenue, Net

'

'

'

'

'

'

'

'

-3,928

-3,905

-4,223

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Fuel

'

'

'

'

'

'

'

'

0

0

0

Other operating expenses

'

'

'

'

'

'

'

'

48

49

51

Pensions and OPEB mark-to-market adjustment

'

'

'

'

'

'

'

'

0

0

0

Provision for depreciation

'

'

'

'

'

'

'

'

-5

-5

-6

General taxes

'

'

'

'

'

'

'

'

0

0

0

Impairment of long-lived assets

'

'

'

'

'

'

'

'

'

'

0

Total operating expenses

'

'

'

'

'

'

'

'

-3,885

-3,861

-4,178

OPERATING INCOME (LOSS)

'

'

'

'

'

'

'

'

-43

-44

-45

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Loss on debt redemptions

'

'

'

'

'

'

'

'

0

'

'

Investment income

'

'

'

'

'

'

'

'

-15

-18

0

Miscellaneous income, including net income from equity investees

'

'

'

'

'

'

'

'

-842

-1,269

-918

Capitalized interest

'

'

'

'

'

'

'

'

0

0

0

Total other income (expense)

'

'

'

'

'

'

'

'

-782

-1,206

-855

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

'

'

'

'

'

'

'

'

-825

-1,250

-900

INCOME TAXES (BENEFITS)

'

'

'

'

'

'

'

'

12

12

18

INCOME FROM CONTINUING OPERATIONS

'

'

'

'

'

'

'

'

-837

-1,262

-918

Discontinued operations (Note 20)

'

'

'

'

'

'

'

'

0

0

0

NET INCOME (LOSS)

'

'

'

'

'

'

'

'

-837

-1,262

-918

OTHER COMPREHENSIVE INCOME (LOSS):

'

'

'

'

'

'

'

'

'

'

'

NET INCOME

'

'

'

'

'

'

'

'

-837

-1,262

-918

Pensions and OPEB prior service costs

'

'

'

'

'

'

'

'

13

-6

13

Amortized loss (gain) on derivative hedges

'

'

'

'

'

'

'

'

0

0

0

Change in unrealized gain on available-for-sale securities

'

'

'

'

'

'

'

'

8

5

-15

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

21

-1

-2

Income taxes (benefits) on other comprehensive income (loss)

'

'

'

'

'

'

'

'

8

1

3

Other comprehensive income (loss), net of tax

'

'

'

'

'

'

'

'

13

-2

-5

COMPREHENSIVE INCOME (LOSS)

'

'

'

'

'

'

'

'

-824

-1,264

-923

Eliminations | Affiliates

'

'

'

'

'

'

'

'

'

'

'

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Purchased power

'

'

'

'

'

'

'

'

-3,928

-3,905

-4,223

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

14

19

-1

Eliminations | Non-Affiliates

'

'

'

'

'

'

'

'

'

'

'

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Purchased power

'

'

'

'

'

'

'

'

0

0

0

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

61

62

64

FES

'

'

'

'

'

'

'

'

'

'

'

Consolidating Statements of Income

'

'

'

'

'

'

'

'

'

'

'

Revenue, Net

'

'

'

'

'

'

'

'

6,173

5,894

5,453

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Fuel

'

'

'

'

'

'

'

'

1,262

1,287

1,344

Other operating expenses

382

339

387

379

328

342

392

294

1,487

1,356

1,619

Pensions and OPEB mark-to-market adjustment

-81

0

0

0

166

0

0

0

-81

166

171

Provision for depreciation

75

80

76

75

72

70

68

62

306

272

272

General taxes

'

'

'

'

'

'

'

'

138

136

124

Impairment of long-lived assets

'

'

'

'

'

'

'

'

0

0

294

Total operating expenses

'

'

'

'

'

'

'

'

5,931

5,555

5,447

OPERATING INCOME (LOSS)

121

65

-39

95

-56

167

9

219

242

339

6

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Loss on debt redemptions

'

'

'

'

'

'

'

'

-103

0

0

Investment income

'

'

'

'

'

'

'

'

16

66

57

Miscellaneous income, including net income from equity investees

'

'

'

'

'

'

'

'

28

35

30

Capitalized interest

'

'

'

'

'

'

'

'

39

37

35

Total other income (expense)

'

'

'

'

'

'

'

'

-190

-63

-89

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

'

'

'

'

'

'

'

'

52

276

-83

INCOME TAXES (BENEFITS)

25

23

-42

0

-36

65

-1

75

6

103

-16

INCOME FROM CONTINUING OPERATIONS

89

33

-75

-1

-38

96

-5

120

46

173

-67

Discontinued operations (Note 20)

0

7

4

3

3

5

4

2

14

14

8

NET INCOME (LOSS)

89

40

-71

2

-35

101

-1

122

60

187

-59

OTHER COMPREHENSIVE INCOME (LOSS):

'

'

'

'

'

'

'

'

'

'

'

NET INCOME

89

40

-71

2

-35

101

-1

122

60

187

-59

Pensions and OPEB prior service costs

'

'

'

'

'

'

'

'

-15

6

-12

Amortized loss (gain) on derivative hedges

'

'

'

'

'

'

'

'

-6

-9

12

Change in unrealized gain on available-for-sale securities

'

'

'

'

'

'

'

'

-8

-5

16

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

-29

-8

16

Income taxes (benefits) on other comprehensive income (loss)

'

'

'

'

'

'

'

'

-11

-4

2

Other comprehensive income (loss), net of tax

'

'

'

'

'

'

'

'

-18

-4

14

COMPREHENSIVE INCOME (LOSS)

'

'

'

'

'

'

'

'

42

183

-45

FES | Affiliates

'

'

'

'

'

'

'

'

'

'

'

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Purchased power

'

'

'

'

'

'

'

'

486

451

242

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

-10

-10

-8

FES | Non-Affiliates

'

'

'

'

'

'

'

'

'

'

'

OPERATING EXPENSES:

'

'

'

'

'

'

'

'

'

'

'

Purchased power

'

'

'

'

'

'

'

'

2,333

1,887

1,381

OTHER INCOME (EXPENSE):

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

($160)

($191)

($203)

[1]

Includes excise tax collections of $458 million, $484 million and $511 million in 2013, 2012 and 2011, respectively.

Supplemental_Guarantor_Informa3

Supplemental Guarantor Information (Details 1) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	$218	$172	$202	$1,019
Receivables-	'	'	'	'
Customers	1,720	1,614	'	'
Other Receivables	198	315	'	'
Materials and supplies, at average cost	752	861	'	'
Derivatives	166	160	'	'
Prepayments and other	241	208	'	'
Total current assets	3,887	3,768	'	'
PROPERTY, PLANT AND EQUIPMENT:	'	'	'	'
In service	44,228	43,210	'	'
Less - Accumulated provision for depreciation	13,280	12,467	'	'
Property, plant and equipment in service net of accumulated provision for depreciation	30,948	30,743	'	'
Construction work in progress	2,304	2,293	'	'
Total net property, plant and equipment	33,252	33,036	'	'
INVESTMENTS:	'	'	'	'
Nuclear plant decommissioning trusts	2,201	2,204	'	'
Other	870	936	'	'
Total other property and investments	3,104	3,194	'	'
ASSETS HELD FOR SALE (Note 20)	235	0	'	'
DEFERRED CHARGES AND OTHER ASSETS:	'	'	'	'
Customer intangibles	588	'	'	'
Goodwill	6,418	6,447	6,441	'
Other	1,674	1,719	'	'
Total deferred charges and other assets	9,946	10,496	'	'
Total assets	50,424	50,494	47,410	'
CURRENT LIABILITIES:	'	'	'	'
Currently payable long-term debt	1,415	1,999	'	'
Short-term borrowings	3,404	1,969	'	'
Accounts payable-	'	'	'	'
Accrued taxes	485	543	'	'
Derivatives	111	126	'	'
Other	621	1,038	'	'
Total current liabilities	7,637	7,605	'	'
CAPITALIZATION:	'	'	'	'
Total equity	12,692	13,084	'	'
Long-term debt and other long-term obligations	15,831	15,179	'	'
Total capitalization	28,526	28,272	'	'
NONCURRENT LIABILITIES:	'	'	'	'
Deferred gain on sale and leaseback transaction	858	892	'	'
Accumulated deferred income taxes	6,968	6,616	'	'
Asset retirement obligations	1,678	1,599	'	'
Retirement benefits	2,689	3,080	'	'
Other	1,778	1,924	'	'
Total noncurrent liabilities	14,261	14,617	'	'
Total liabilities and capitalization	50,424	50,494	'	'
FES	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	0	0	0	0
Receivables-	'	'	'	'
Customers	539	483	'	'
Affiliated companies	938	232	'	'
Other Receivables	52	56	'	'
Notes receivable from affiliated companies	203	366	'	'
Materials and supplies, at average cost	76	66	'	'
Derivatives	165	158	'	'
Prepayments and other	81	38	'	'
Total current assets	2,054	1,399	'	'
PROPERTY, PLANT AND EQUIPMENT:	'	'	'	'
In service	104	91	'	'
Less - Accumulated provision for depreciation	28	32	'	'
Property, plant and equipment in service net of accumulated provision for depreciation	76	59	'	'
Construction work in progress	23	34	'	'
Total net property, plant and equipment	99	93	'	'
INVESTMENTS:	'	'	'	'
Nuclear plant decommissioning trusts	0	0	'	'
Investment in affiliated companies	5,801	4,972	'	'
Other	0	0	'	'
Total other property and investments	5,801	4,972	'	'
ASSETS HELD FOR SALE (Note 20)	0	0	'	'
DEFERRED CHARGES AND OTHER ASSETS:	'	'	'	'
Accumulated deferred income tax benefits	0	0	'	'
Customer intangibles	95	110	'	'
Goodwill	23	24	'	'
Property taxes	0	0	'	'
Unamortized sale and leaseback costs	0	0	'	'
Derivatives	53	99	'	'
Other	188	160	'	'
Total deferred charges and other assets	359	393	'	'
Total assets	8,313	6,857	'	'
CURRENT LIABILITIES:	'	'	'	'
Currently payable long-term debt	1	1	'	'
Short-term borrowings	0	0	'	'
Accounts payable-	'	'	'	'
Affiliated companies	741	748	'	'
Other	94	63	'	'
Accrued taxes	204	126	'	'
Derivatives	110	124	'	'
Other	70	71	'	'
Total current liabilities	2,197	1,491	'	'
CAPITALIZATION:	'	'	'	'
Total equity	5,312	3,763	'	'
Long-term debt and other long-term obligations	712	1,482	'	'
Total capitalization	6,024	5,245	'	'
NONCURRENT LIABILITIES:	'	'	'	'
Deferred gain on sale and leaseback transaction	0	0	'	'
Accumulated deferred income taxes	32	28	'	'
Asset retirement obligations	0	0	'	'
Retirement benefits	22	26	'	'
Derivatives	14	37	'	'
Other	24	30	'	'
Total noncurrent liabilities	92	121	'	'
Total liabilities and capitalization	8,313	6,857	'	'
FES | Affiliates	'	'	'	'
CURRENT LIABILITIES:	'	'	'	'
Other Short-term Borrowings	977	358	'	'
FGCO	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	2	3	7	9
Receivables-	'	'	'	'
Customers	0	0	'	'
Affiliated companies	787	417	'	'
Other Receivables	12	19	'	'
Notes receivable from affiliated companies	23	7	'	'
Materials and supplies, at average cost	159	231	'	'
Derivatives	0	0	'	'
Prepayments and other	50	39	'	'
Total current assets	1,033	716	'	'
PROPERTY, PLANT AND EQUIPMENT:	'	'	'	'
In service	6,105	5,899	'	'
Less - Accumulated provision for depreciation	1,953	1,915	'	'
Property, plant and equipment in service net of accumulated provision for depreciation	4,152	3,984	'	'
Construction work in progress	148	230	'	'
Total net property, plant and equipment	4,300	4,214	'	'
INVESTMENTS:	'	'	'	'
Nuclear plant decommissioning trusts	0	0	'	'
Investment in affiliated companies	0	0	'	'
Other	11	12	'	'
Total other property and investments	11	12	'	'
ASSETS HELD FOR SALE (Note 20)	122	0	'	'
DEFERRED CHARGES AND OTHER ASSETS:	'	'	'	'
Accumulated deferred income tax benefits	131	313	'	'
Customer intangibles	0	0	'	'
Goodwill	0	0	'	'
Property taxes	15	14	'	'
Unamortized sale and leaseback costs	0	0	'	'
Derivatives	0	0	'	'
Other	228	194	'	'
Total deferred charges and other assets	374	521	'	'
Total assets	5,840	5,463	'	'
CURRENT LIABILITIES:	'	'	'	'
Currently payable long-term debt	367	586	'	'
Short-term borrowings	4	4	'	'
Accounts payable-	'	'	'	'
Affiliated companies	400	143	'	'
Other	196	96	'	'
Accrued taxes	23	25	'	'
Derivatives	0	0	'	'
Other	63	148	'	'
Total current liabilities	1,265	1,348	'	'
CAPITALIZATION:	'	'	'	'
Total equity	2,283	1,787	'	'
Long-term debt and other long-term obligations	1,860	2,009	'	'
Total capitalization	4,143	3,796	'	'
NONCURRENT LIABILITIES:	'	'	'	'
Deferred gain on sale and leaseback transaction	0	0	'	'
Accumulated deferred income taxes	0	0	'	'
Asset retirement obligations	187	29	'	'
Retirement benefits	163	215	'	'
Derivatives	0	0	'	'
Other	82	75	'	'
Total noncurrent liabilities	432	319	'	'
Total liabilities and capitalization	5,840	5,463	'	'
FGCO | Affiliates	'	'	'	'
CURRENT LIABILITIES:	'	'	'	'
Other Short-term Borrowings	212	346	'	'
Nuclear Generation Corp	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	0	0	0	0
Receivables-	'	'	'	'
Customers	0	0	'	'
Affiliated companies	227	478	'	'
Other Receivables	17	16	'	'
Notes receivable from affiliated companies	683	607	'	'
Materials and supplies, at average cost	213	208	'	'
Derivatives	0	0	'	'
Prepayments and other	7	10	'	'
Total current assets	1,147	1,319	'	'
PROPERTY, PLANT AND EQUIPMENT:	'	'	'	'
In service	6,645	6,391	'	'
Less - Accumulated provision for depreciation	2,962	2,646	'	'
Property, plant and equipment in service net of accumulated provision for depreciation	3,683	3,745	'	'
Construction work in progress	1,137	877	'	'
Total net property, plant and equipment	4,820	4,622	'	'
INVESTMENTS:	'	'	'	'
Nuclear plant decommissioning trusts	1,276	1,283	'	'
Investment in affiliated companies	0	0	'	'
Other	0	0	'	'
Total other property and investments	1,276	1,283	'	'
ASSETS HELD FOR SALE (Note 20)	0	0	'	'
DEFERRED CHARGES AND OTHER ASSETS:	'	'	'	'
Accumulated deferred income tax benefits	0	0	'	'
Customer intangibles	0	0	'	'
Goodwill	0	0	'	'
Property taxes	26	22	'	'
Unamortized sale and leaseback costs	0	0	'	'
Derivatives	0	0	'	'
Other	18	5	'	'
Total deferred charges and other assets	44	27	'	'
Total assets	7,287	7,251	'	'
CURRENT LIABILITIES:	'	'	'	'
Currently payable long-term debt	547	537	'	'
Short-term borrowings	0	0	'	'
Accounts payable-	'	'	'	'
Affiliated companies	362	583	'	'
Other	0	0	'	'
Accrued taxes	23	20	'	'
Derivatives	0	0	'	'
Other	18	15	'	'
Total current liabilities	1,101	1,155	'	'
CAPITALIZATION:	'	'	'	'
Total equity	3,493	3,165	'	'
Long-term debt and other long-term obligations	742	834	'	'
Total capitalization	4,235	3,999	'	'
NONCURRENT LIABILITIES:	'	'	'	'
Deferred gain on sale and leaseback transaction	0	0	'	'
Accumulated deferred income taxes	736	714	'	'
Asset retirement obligations	828	936	'	'
Retirement benefits	0	0	'	'
Derivatives	0	0	'	'
Other	387	447	'	'
Total noncurrent liabilities	1,951	2,097	'	'
Total liabilities and capitalization	7,287	7,251	'	'
Nuclear Generation Corp | Affiliates	'	'	'	'
CURRENT LIABILITIES:	'	'	'	'
Other Short-term Borrowings	151	0	'	'
Eliminations	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	0	0	0	0
Receivables-	'	'	'	'
Customers	0	0	'	'
Affiliated companies	-916	-748	'	'
Other Receivables	0	0	'	'
Notes receivable from affiliated companies	-909	-704	'	'
Materials and supplies, at average cost	0	0	'	'
Derivatives	0	0	'	'
Prepayments and other	0	0	'	'
Total current assets	-1,825	-1,452	'	'
PROPERTY, PLANT AND EQUIPMENT:	'	'	'	'
In service	-382	-384	'	'
Less - Accumulated provision for depreciation	-188	-185	'	'
Property, plant and equipment in service net of accumulated provision for depreciation	-194	-199	'	'
Construction work in progress	0	0	'	'
Total net property, plant and equipment	-194	-199	'	'
INVESTMENTS:	'	'	'	'
Nuclear plant decommissioning trusts	0	0	'	'
Investment in affiliated companies	-5,801	-4,972	'	'
Other	0	0	'	'
Total other property and investments	-5,801	-4,972	'	'
ASSETS HELD FOR SALE (Note 20)	0	0	'	'
DEFERRED CHARGES AND OTHER ASSETS:	'	'	'	'
Accumulated deferred income tax benefits	-131	-313	'	'
Customer intangibles	0	0	'	'
Goodwill	0	0	'	'
Property taxes	0	0	'	'
Unamortized sale and leaseback costs	168	119	'	'
Derivatives	0	0	'	'
Other	-155	-106	'	'
Total deferred charges and other assets	-118	-300	'	'
Total assets	-7,938	-6,923	'	'
CURRENT LIABILITIES:	'	'	'	'
Currently payable long-term debt	-23	-22	'	'
Short-term borrowings	0	0	'	'
Accounts payable-	'	'	'	'
Affiliated companies	-738	-748	'	'
Other	0	0	'	'
Accrued taxes	-184	0	'	'
Derivatives	0	0	'	'
Other	46	46	'	'
Total current liabilities	-1,808	-1,428	'	'
CAPITALIZATION:	'	'	'	'
Total equity	-5,776	-4,952	'	'
Long-term debt and other long-term obligations	-1,184	-1,207	'	'
Total capitalization	-6,960	-6,159	'	'
NONCURRENT LIABILITIES:	'	'	'	'
Deferred gain on sale and leaseback transaction	858	892	'	'
Accumulated deferred income taxes	-27	-227	'	'
Asset retirement obligations	0	0	'	'
Retirement benefits	0	0	'	'
Derivatives	0	0	'	'
Other	-1	-1	'	'
Total noncurrent liabilities	830	664	'	'
Total liabilities and capitalization	-7,938	-6,923	'	'
Eliminations | Affiliates	'	'	'	'
CURRENT LIABILITIES:	'	'	'	'
Other Short-term Borrowings	-909	-704	'	'
FES	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	2	3	7	9
Receivables-	'	'	'	'
Customers	539	483	'	'
Affiliated companies	1,036	379	'	'
Other Receivables	81	91	'	'
Notes receivable from affiliated companies	0	276	'	'
Materials and supplies, at average cost	448	505	'	'
Derivatives	165	158	'	'
Prepayments and other	138	87	'	'
Total current assets	2,409	1,982	'	'
PROPERTY, PLANT AND EQUIPMENT:	'	'	'	'
In service	12,472	11,997	'	'
Less - Accumulated provision for depreciation	4,755	4,408	'	'
Property, plant and equipment in service net of accumulated provision for depreciation	7,717	7,589	'	'
Construction work in progress	1,308	1,141	'	'
Total net property, plant and equipment	9,025	8,730	'	'
INVESTMENTS:	'	'	'	'
Nuclear plant decommissioning trusts	1,276	1,283	'	'
Investment in affiliated companies	0	0	'	'
Other	11	12	'	'
Total other property and investments	1,287	1,295	'	'
ASSETS HELD FOR SALE (Note 20)	122	0	'	'
DEFERRED CHARGES AND OTHER ASSETS:	'	'	'	'
Accumulated deferred income tax benefits	0	0	'	'
Customer intangibles	95	110	'	'
Goodwill	23	24	'	'
Property taxes	41	36	'	'
Unamortized sale and leaseback costs	168	119	'	'
Derivatives	53	99	'	'
Other	279	253	'	'
Total deferred charges and other assets	659	641	'	'
Total assets	13,502	12,648	'	'
CURRENT LIABILITIES:	'	'	'	'
Currently payable long-term debt	892	1,102	'	'
Short-term borrowings	4	4	'	'
Accounts payable-	'	'	'	'
Affiliated companies	765	726	'	'
Other	290	159	'	'
Accrued taxes	66	171	'	'
Derivatives	110	124	'	'
Other	197	280	'	'
Total current liabilities	2,755	2,566	'	'
CAPITALIZATION:	'	'	'	'
Total equity	5,312	3,763	'	'
Long-term debt and other long-term obligations	2,130	3,118	'	'
Total capitalization	7,442	6,881	'	'
NONCURRENT LIABILITIES:	'	'	'	'
Deferred gain on sale and leaseback transaction	858	892	'	'
Accumulated deferred income taxes	741	515	'	'
Asset retirement obligations	1,015	965	'	'
Retirement benefits	185	241	'	'
Derivatives	14	37	'	'
Other	492	551	'	'
Total noncurrent liabilities	3,305	3,201	'	'
Total liabilities and capitalization	13,502	12,648	'	'
FES | Affiliates	'	'	'	'
CURRENT LIABILITIES:	'	'	'	'
Other Short-term Borrowings	$431	$0	'	'

Supplemental_Guarantor_Informa4

Supplemental Guarantor Information (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Consolidated Statements of Cash Flows [Abstract]	'	'	'
Net cash provided from operating activities	$2,662	$2,320	$3,063
New Financing-	'	'	'
Long-term debt	3,745	750	604
Short-term borrowings, net	1,435	1,969	0
Redemptions and Repayments-	'	'	'
Long-term debt	-3,600	-940	-1,909
Short-term borrowings, net	0	0	-700
Common stock dividend payments	-920	-920	-881
Tender premiums	-110	0	0
Other	-73	-52	-38
Net cash provided from (used for) financing activities	477	807	-2,924
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Property additions	-2,638	-2,678	-2,129
Nuclear fuel	-250	-286	-149
Proceeds from asset sales	4	17	840
Sales of investment securities held in trusts	2,047	2,980	4,207
Purchases of investment securities held in trusts	-2,096	-3,020	-4,309
Other	9	-43	48
Net cash used for investing activities	-3,093	-3,157	-956
Net change in cash and cash equivalents	46	-30	-817
Cash and cash equivalents at beginning of period	172	202	1,019
Cash and cash equivalents at end of period	218	172	202
FES	'	'	'
Consolidated Statements of Cash Flows [Abstract]	'	'	'
Net cash provided from operating activities	-1,429	-1,063	-790
New Financing-	'	'	'
Long-term debt	'	0	0
Short-term borrowings, net	864	0	'
Equity contribution from parent	1,500	'	'
Redemptions and Repayments-	'	'	'
Long-term debt	-770	-1	-136
Short-term borrowings, net	-244	-707	-1,065
Common stock dividend payments	'	0	'
Tender premiums	-67	'	'
Other	-4	-1	-9
Net cash provided from (used for) financing activities	1,279	-709	920
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Property additions	-12	-14	-24
Nuclear fuel	0	0	0
Proceeds from asset sales	0	0	9
Sales of investment securities held in trusts	0	0	0
Purchases of investment securities held in trusts	0	0	0
Loans to affiliated companies, net	163	-211	-120
Dividend received	'	2,000	'
Other	-1	-3	5
Net cash used for investing activities	150	1,772	-130
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	753	639	926
New Financing-	'	'	'
Long-term debt	'	351	140
Short-term borrowings, net	371	260	'
Equity contribution from parent	0	'	'
Redemptions and Repayments-	'	'	'
Long-term debt	-364	-288	-362
Short-term borrowings, net	-505	0	-78
Common stock dividend payments	'	-2,000	'
Tender premiums	0	'	'
Other	-5	-8	-1
Net cash provided from (used for) financing activities	-503	-1,685	-145
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Property additions	-256	-273	-205
Nuclear fuel	0	0	0
Proceeds from asset sales	21	17	590
Sales of investment securities held in trusts	0	0	0
Purchases of investment securities held in trusts	0	0	0
Loans to affiliated companies, net	-15	1,338	-1,157
Dividend received	'	0	'
Other	-1	-40	-11
Net cash used for investing activities	-251	1,042	-783
Net change in cash and cash equivalents	-1	-4	-2
Cash and cash equivalents at beginning of period	3	7	9
Cash and cash equivalents at end of period	2	3	7
Nuclear Generation Corp	'	'	'
Consolidated Statements of Cash Flows [Abstract]	'	'	'
Net cash provided from operating activities	776	1,266	702
New Financing-	'	'	'
Long-term debt	'	299	107
Short-term borrowings, net	150	0	'
Equity contribution from parent	0	'	'
Redemptions and Repayments-	'	'	'
Long-term debt	-90	-161	-377
Short-term borrowings, net	0	-32	-32
Common stock dividend payments	'	0	'
Tender premiums	0	'	'
Other	'	-3	-1
Net cash provided from (used for) financing activities	60	103	-239
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Property additions	-449	-508	-371
Nuclear fuel	-250	-286	-149
Proceeds from asset sales	0	0	0
Sales of investment securities held in trusts	940	1,464	1,843
Purchases of investment securities held in trusts	-1,000	-1,502	-1,890
Loans to affiliated companies, net	-77	-538	105
Dividend received	'	0	'
Other	0	1	-1
Net cash used for investing activities	-836	-1,369	-463
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	-22	-21	-19
New Financing-	'	'	'
Long-term debt	'	0	0
Short-term borrowings, net	-954	-257	'
Equity contribution from parent	0	'	'
Redemptions and Repayments-	'	'	'
Long-term debt	22	21	19
Short-term borrowings, net	749	739	1,186
Common stock dividend payments	'	2,000	'
Tender premiums	0	'	'
Other	'	0	0
Net cash provided from (used for) financing activities	-183	2,503	-1,167
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
Loans to affiliated companies, net	205	-482	1,186
Dividend received	'	-2,000	'
Other	0	0	0
Net cash used for investing activities	205	-2,482	1,186
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	78	821	819
New Financing-	'	'	'
Long-term debt	0	650	247
Short-term borrowings, net	431	3	0
Equity contribution from parent	1,500	0	0
Redemptions and Repayments-	'	'	'
Long-term debt	-1,202	-429	-856
Short-term borrowings, net	0	0	-11
Common stock dividend payments	'	0	'
Tender premiums	-67	0	0
Other	-9	-12	-11
Net cash provided from (used for) financing activities	653	212	-631
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Property additions	-717	-795	-600
Nuclear fuel	-250	-286	-149
Proceeds from asset sales	21	17	599
Sales of investment securities held in trusts	940	1,464	1,843
Purchases of investment securities held in trusts	-1,000	-1,502	-1,890
Loans to affiliated companies, net	276	107	14
Dividend received	'	0	'
Other	-2	-42	-7
Net cash used for investing activities	-732	-1,037	-190
Net change in cash and cash equivalents	-1	-4	-2
Cash and cash equivalents at beginning of period	3	7	9
Cash and cash equivalents at end of period	$2	$3	$7

Segment_Information_Details

Segment Information (Details) (USD $)

3 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Segment Financial Information

'

'

'

'

'

'

'

'

'

'

'

External revenues

'

'

'

'

'

'

'

'

$14,917

$15,271

$16,038

Internal revenues

'

'

'

'

'

'

'

'

0

2

67

Total revenues

'

'

'

'

'

'

'

'

14,917

[1]

15,273

[1]

16,105

[1]

Depreciation and amortization

'

'

'

'

'

'

'

'

1,741

1,051

1,391

Investment income

'

'

'

'

'

'

'

'

36

77

114

Interest expense

'

'

'

'

'

'

'

'

1,016

1,001

1,008

Income taxes (benefits)

66

77

-62

114

-105

307

123

220

195

545

566

Income from continuing operations

142

209

-168

192

-153

422

184

302

375

755

856

Discontinued operations (Note 20)

0

9

4

4

5

3

4

4

17

16

13

NET INCOME (LOSS)

142

218

-164

196

-148

425

188

306

392

771

869

Total assets

50,424

'

'

'

50,494

'

'

'

50,424

50,494

47,410

Total goodwill

6,418

'

'

'

6,447

'

'

'

6,418

6,447

6,441

Property additions

'

'

'

'

'

'

'

'

2,638

2,678

2,129

Regulated Distribution

'

'

'

'

'

'

'

'

'

'

'

Segment Financial Information

'

'

'

'

'

'

'

'

'

'

'

External revenues

'

'

'

'

'

'

'

'

8,738

9,060

9,913

Internal revenues

'

'

'

'

'

'

'

'

0

0

0

Total revenues

'

'

'

'

'

'

'

'

8,738

9,060

9,913

Depreciation and amortization

'

'

'

'

'

'

'

'

1,135

493

846

Investment income

'

'

'

'

'

'

'

'

57

84

99

Interest expense

'

'

'

'

'

'

'

'

543

540

530

Income taxes (benefits)

'

'

'

'

'

'

'

'

301

295

287

Income from continuing operations

'

'

'

'

'

'

'

'

501

540

488

Discontinued operations (Note 20)

'

'

'

'

'

'

'

'

0

0

0

NET INCOME (LOSS)

'

'

'

'

'

'

'

'

501

540

488

Total assets

27,683

'

'

'

27,150

'

'

'

27,683

27,150

25,534

Total goodwill

5,092

'

'

'

5,025

'

'

'

5,092

5,025

5,025

Property additions

'

'

'

'

'

'

'

'

1,272

1,074

868

Regulated Transmission

'

'

'

'

'

'

'

'

'

'

'

Segment Financial Information

'

'

'

'

'

'

'

'

'

'

'

External revenues

'

'

'

'

'

'

'

'

741

740

660

Internal revenues

'

'

'

'

'

'

'

'

0

0

0

Total revenues

'

'

'

'

'

'

'

'

741

740

660

Depreciation and amortization

'

'

'

'

'

'

'

'

124

111

110

Investment income

'

'

'

'

'

'

'

'

0

1

0

Interest expense

'

'

'

'

'

'

'

'

93

92

89

Income taxes (benefits)

'

'

'

'

'

'

'

'

129

133

114

Income from continuing operations

'

'

'

'

'

'

'

'

214

226

194

Discontinued operations (Note 20)

'

'

'

'

'

'

'

'

0

0

0

NET INCOME (LOSS)

'

'

'

'

'

'

'

'

214

226

194

Total assets

5,247

'

'

'

4,865

'

'

'

5,247

4,865

4,463

Total goodwill

526

'

'

'

526

'

'

'

526

526

526

Property additions

'

'

'

'

'

'

'

'

461

507

390

Competitive Energy Services

'

'

'

'

'

'

'

'

'

'

'

Segment Financial Information

'

'

'

'

'

'

'

'

'

'

'

External revenues

'

'

'

'

'

'

'

'

5,725

5,778

5,783

Internal revenues

'

'

'

'

'

'

'

'

770

866

1,237

Total revenues

'

'

'

'

'

'

'

'

6,495

6,644

7,020

Depreciation and amortization

'

'

'

'

'

'

'

'

439

409

411

Investment income

'

'

'

'

'

'

'

'

14

66

56

Interest expense

'

'

'

'

'

'

'

'

222

284

298

Income taxes (benefits)

'

'

'

'

'

'

'

'

-141

83

214

Income from continuing operations

'

'

'

'

'

'

'

'

-237

199

364

Discontinued operations (Note 20)

'

'

'

'

'

'

'

'

17

16

13

NET INCOME (LOSS)

'

'

'

'

'

'

'

'

-220

215

377

Total assets

16,782

'

'

'

18,087

'

'

'

16,782

18,087

16,796

Total goodwill

800

'

'

'

896

'

'

'

800

896

890

Property additions

'

'

'

'

'

'

'

'

827

1,014

778

Other/Corporate

'

'

'

'

'

'

'

'

'

'

'

Segment Financial Information

'

'

'

'

'

'

'

'

'

'

'

External revenues

'

'

'

'

'

'

'

'

-121

-119

-114

Internal revenues

'

'

'

'

'

'

'

'

0

0

0

Total revenues

'

'

'

'

'

'

'

'

-121

-119

-114

Depreciation and amortization

'

'

'

'

'

'

'

'

43

38

24

Investment income

'

'

'

'

'

'

'

'

9

-5

1

Interest expense

'

'

'

'

'

'

'

'

158

85

91

Income taxes (benefits)

'

'

'

'

'

'

'

'

-78

-34

-87

Income from continuing operations

'

'

'

'

'

'

'

'

-130

-155

-149

Discontinued operations (Note 20)

'

'

'

'

'

'

'

'

0

0

0

NET INCOME (LOSS)

'

'

'

'

'

'

'

'

-130

-155

-149

Total assets

712

'

'

'

392

'

'

'

712

392

617

Total goodwill

0

'

'

'

0

'

'

'

0

0

0

Property additions

'

'

'

'

'

'

'

'

78

83

93

Reconciling Adjustments

'

'

'

'

'

'

'

'

'

'

'

Segment Financial Information

'

'

'

'

'

'

'

'

'

'

'

External revenues

'

'

'

'

'

'

'

'

-166

-188

-204

Internal revenues

'

'

'

'

'

'

'

'

-770

-864

-1,170

Total revenues

'

'

'

'

'

'

'

'

-936

-1,052

-1,374

Depreciation and amortization

'

'

'

'

'

'

'

'

0

0

0

Investment income

'

'

'

'

'

'

'

'

-44

-69

-42

Interest expense

'

'

'

'

'

'

'

'

0

0

0

Income taxes (benefits)

'

'

'

'

'

'

'

'

-16

68

38

Income from continuing operations

'

'

'

'

'

'

'

'

27

-55

-41

Discontinued operations (Note 20)

'

'

'

'

'

'

'

'

0

0

0

NET INCOME (LOSS)

'

'

'

'

'

'

'

'

27

-55

-41

Total assets

0

'

'

'

0

'

'

'

0

0

0

Total goodwill

0

'

'

'

0

'

'

'

0

0

0

Property additions

'

'

'

'

'

'

'

'

$0

$0

$0

[1]

Includes excise tax collections of $458 million, $484 million and $511 million in 2013, 2012 and 2011, respectively.

Segment_Information_Details_Te

Segment Information (Details Textuals)	12 Months Ended
	Dec. 31, 2013	Oct. 09, 2013
	Customers	MW
	Companies
	sqmi
Regulated Distribution	'	'
Segment Reporting Information [Line Items]	'	'
Number of existing utility operating companies	10	'
Number of customers served by utility operating companies	6,000,000	'
Number of square miles in service area	65,000	'
Megawatts of net demonstrated capacity of competitive segment	'	3,780
Regulated Distribution | Harrison and Pleasants	'	'
Segment Reporting Information [Line Items]	'	'
Megawatts of net demonstrated capacity of competitive segment	'	1,476
Competitive Energy Services	'	'
Segment Reporting Information [Line Items]	'	'
Megawatts of net demonstrated capacity of competitive segment	14,000	'
Competitive Energy Services | Unregulated Plants Expected to be Closed by 9/1/2012	'	'
Segment Reporting Information [Line Items]	'	'
Megawatt capacity of plants expected to be closed	885	'

Discontinued_Operations_and_As

Discontinued Operations and Assets Held for Sale (Details) (USD $)	12 Months Ended			0 Months Ended	12 Months Ended			0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 12, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 12, 2014	Sep. 04, 2013
				Hydroelectric Power Plant Projects [Member]	FES	FES	FES	FES	FERC
				Subsequent Event				Hydroelectric Power Plant Projects [Member]	Hydroelectric Asset Sale
								Subsequent Event	plant
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'	'	'	'	'	'	'
Discontinued operations (net of income taxes of $9, $8 and $8, respectively) (Note 20)	'	'	'	$395	'	'	'	'	'
Application to Sell Power Plant Projects, Number	'	'	'	'	'	'	'	'	11
Assets Held-for-sale, Long Lived	235	0	'	'	122	0	'	'	'
Disposal Group, Including Discontinued Operation, Goodwill	29	'	'	'	1	'	'	'	'
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax	26	24	21	'	22	22	13	'	'
Disposal Group, Including Discontinued Operation, Revenue	33	30	42	'	31	24	24	'	'
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax	'	'	'	$145	'	'	'	$177	'

Merger_Details

Merger (Details) (USD $)	Feb. 24, 2011
In Millions, except Per Share data, unless otherwise specified
Purchase price calculation	'
Shares of Allegheny common stock outstanding	170
Exchange ratio	0.667
Number of shares of FirstEnergy common stock issued	113
Closing price of FirstEnergy common stock	$38.16
Fair value of shares issued by FirstEnergy	$4,327
Fair value of replacement share-based compensation awards relating to pre-merger service	27
Total consideration transferred	4,354
Allegheny Energy Inc	'
Purchase price calculation	'
Exchange ratio	0.667
Fair values of assets and liabilities acquired and related goodwill	'
Current assets	1,493
Property, plant and equipment	9,660
Investments	138
Goodwill	872
Other noncurrent assets	1,353
Current liabilities	-718
Noncurrent liabilities	-3,450
Long-term debt and other long-term obligations	-4,994
Assets Acquired (Liabilities Assumed), Net, Total	$4,354

Merger_Details_1

Merger (Details 1) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger	'
Preliminary Valuation	$568
Above Market Contracts	'
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger	'
Preliminary Valuation	829
Above Market Contracts | Energy contracts	'
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger	'
Preliminary Valuation	189
Weighted Average Amortization Period (in years)	'10 years
Above Market Contracts | NUG contracts	'
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger	'
Preliminary Valuation	124
Weighted Average Amortization Period (in years)	'25 years
Above Market Contracts | Coal supply contracts	'
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger	'
Preliminary Valuation	516
Weighted Average Amortization Period (in years)	'8 years
Below Market Contracts	'
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger	'
Preliminary Valuation	261
Below Market Contracts | NUG contracts	'
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger	'
Preliminary Valuation	143
Weighted Average Amortization Period (in years)	'13 years
Below Market Contracts | Coal supply contracts	'
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger	'
Preliminary Valuation	83
Weighted Average Amortization Period (in years)	'7 years
Below Market Contracts | Transportation contract	'
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger	'
Preliminary Valuation	$35
Weighted Average Amortization Period (in years)	'8 years

Merger_Details_2

Merger (Details 2) (USD $)	3 Months Ended								12 Months Ended			10 Months Ended		12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2011		Dec. 31, 2013		Dec. 31, 2012
												Allegheny Energy Inc		Allegheny Energy Inc		Allegheny Energy Inc
Revenue and earnings of Allegheny	'	'	'	'	'	'	'	'	'	'	'	'		'		'
Revenues	$3,647	$4,036	$3,511	$3,723	$3,493	$4,052	$3,746	$3,982	$9,479	$9,800	$10,573	$3,966		$4,331		$4,410
NET INCOME	$142	$218	($164)	$196	($148)	$425	$188	$306	$392	$771	$869	$147	[1]	($31)	[1]	$356	[1]
Basic earnings per share of common stock (in dollars per share)	$0.34	$0.52	($0.39)	$0.47	($0.35)	$1.02	$0.45	$0.73	$0.94	$1.85	$2.22	$0.37		($0.07)		$0.85
Diluted earnings per share of common stock (in dollars per share)	$0.34	$0.52	($0.39)	$0.47	($0.35)	$1.01	$0.45	$0.73	$0.94	$1.84	$2.21	$0.37		($0.07)		$0.85
[1]	(1)Includes Alleghenybs after-tax merger costs of $58 million, $1 million and $1 million during 2011, 2012 and 2013, respectively.

Merger_Details_3

Merger (Details 3) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2011
Summary of consolidated results of operations	'
Revenue	$17,449
Earnings available to FirstEnergy	$979
Basic Earnings Per Share	$2.34
Diluted Earnings Per Share	$2.33

Merger_Details_Textuals

Merger (Details Textuals) (USD $)

10 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Feb. 24, 2011

Dec. 31, 2011

Feb. 24, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Allegheny Energy Inc

Allegheny Energy Inc

Allegheny Energy Inc

Allegheny Energy Inc

Allegheny Energy Inc

Allegheny Energy Inc

Allegheny Energy Inc

Allegheny Energy Inc

Allegheny Energy Inc

Allegheny Energy Inc

Allegheny Energy Inc

Allegheny Energy Inc

Allegheny Energy Inc

Allegheny Energy Inc

Pre-tax

Pre-tax

Pre-tax

Pre-tax

Pre-tax

Pre-tax

Net of Tax

Net of Tax

Net of Tax

Net of Tax

Net of Tax

Net of Tax

Other Operating Expense

Other Operating Expense

Other Operating Expense

Other Operating Expense

Other Operating Expense

Other Operating Expense

Merger (Textuals) [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exchange ratio

'

'

'

0.667

'

0.667

'

'

'

'

'

'

'

'

'

'

'

'

Increase in Property Plant and Equipment Due to Business Acquisition Purchase Price Allocation

'

'

'

'

$4

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in noncurrent assets

'

'

'

'

91

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Current Liabilities Due to Business Acquisition Purchase Price Allocation

'

'

'

'

-4

'

'

'

'

'

'

'

'

'

'

'

'

'

Decrease in current assets

'

'

'

'

-16

'

'

'

'

'

'

'

'

'

'

'

'

'

Decrease in goodwill

'

'

'

'

-80

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill

'

'

'

'

'

872

'

'

'

'

'

'

'

'

'

'

'

'

Merger transaction costs

'

'

'

'

'

'

'

'

'

2

1

91

'

'

'

1

1

73

Merger integration costs

'

'

'

'

'

'

67

6

93

'

'

'

42

13

91

'

'

'

Merger related Expenses

58

1

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expenses related to merger settlements approved by regulatory agencies

'

'

'

'

'

'

'

'

$36

'

'

'

'

'

'

'

'

'

Summary_of_Quarterly_Financial2

Summary of Quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Data [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	$3,647	$4,036	$3,511	$3,723	$3,493	$4,052	$3,746	$3,982	$9,479	$9,800	$10,573
Other operating expenses	948	877	886	882	1,163	861	920	816	3,593	3,760	3,949
Pension and OPEB mark-to-market	-256	0	0	0	609	0	0	0	-256	609	507
Provision for depreciation	293	316	300	293	285	272	284	278	1,202	1,119	1,062
Impairment of long-lived assets	322	0	473	0	0	0	0	0	795	0	413
Operating Income (Loss)	401	512	46	648	-39	902	549	740	1,607	2,152	1,677
Income (loss) from continuing operations before income taxes	208	286	-230	306	-258	729	307	522	'	'	'
Total provision for income taxes	66	77	-62	114	-105	307	123	220	195	545	566
Income from continuing operations	142	209	-168	192	-153	422	184	302	375	755	856
Discontinued operations (Note 20)	0	9	4	4	5	3	4	4	17	16	13
NET INCOME	142	218	-164	196	-148	425	188	306	392	771	869
Earnings (loss) available to FirstEnergy Corp.	142	218	-164	196	-148	425	187	306	392	770	885
Earnings per share of common stock-	'	'	'	'	'	'	'	'	'	'	'
Basic - Continuing Operations, in dollars per share	$0.34	$0.50	($0.40)	$0.46	($0.36)	$1.01	$0.44	$0.72	$0.90	$1.81	$2.19
Basic - Discontinued Operations (Note 20), in dollars per share	$0	$0.02	$0.01	$0.01	$0.01	$0.01	$0.01	$0.01	$0.04	$0.04	$0.03
Basic - Earnings Available to FirstEnergy Corp., in dollars per share	$0.34	$0.52	($0.39)	$0.47	($0.35)	$1.02	$0.45	$0.73	$0.94	$1.85	$2.22
Diluted - Continuing Operations, in dollars per share	$0.34	$0.50	($0.40)	$0.46	($0.36)	$1	$0.44	$0.72	$0.90	$1.80	$2.18
Diluted - Discontinued Operations (Note 20), in dollars per share	$0	$0.02	$0.01	$0.01	$0.01	$0.01	$0.01	$0.01	$0.04	$0.04	$0.03
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share	$0.34	$0.52	($0.39)	$0.47	($0.35)	$1.01	$0.45	$0.73	$0.94	$1.84	$2.21
FES	'	'	'	'	'	'	'	'	'	'	'
Quarterly Financial Data [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	1,518	1,679	1,452	1,524	1,383	1,550	1,450	1,511	'	'	'
Other operating expenses	382	339	387	379	328	342	392	294	1,487	1,356	1,619
Pension and OPEB mark-to-market	-81	0	0	0	166	0	0	0	-81	166	171
Provision for depreciation	75	80	76	75	72	70	68	62	306	272	272
Operating Income (Loss)	121	65	-39	95	-56	167	9	219	242	339	6
Income (loss) from continuing operations before income taxes	114	56	-117	-1	-74	161	-6	195	'	'	'
Total provision for income taxes	25	23	-42	0	-36	65	-1	75	6	103	-16
Income from continuing operations	89	33	-75	-1	-38	96	-5	120	46	173	-67
Discontinued operations (Note 20)	0	7	4	3	3	5	4	2	14	14	8
NET INCOME	$89	$40	($71)	$2	($35)	$101	($1)	$122	$60	$187	($59)

Consolidated_Valuation_and_Qua1

Consolidated Valuation and Qualifying Accounts (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated provision for uncollectible accounts - customers	'	'	'
Consolidated Valuation and Qualifying Accounts	'	'	'
Beginning Balance	$40,354	$37,303	$36,272
Charged to Income	68,733	84,026	78,521
Charged to Other Accounts	39,775	36,686	38,042
Deductions	97,232	117,661	115,532
Ending Balance	51,630	40,354	37,303
Accumulated provision for uncollectible accounts - customers | FES	'	'	'
Consolidated Valuation and Qualifying Accounts	'	'	'
Beginning Balance	16,188	16,441	16,591
Charged to Income	14,294	10,410	11,250
Charged to Other Accounts	0	0	0
Deductions	19,409	10,663	11,400
Ending Balance	11,073	16,188	16,441
Accumulated provision for uncollectible accounts - other	'	'	'
Consolidated Valuation and Qualifying Accounts	'	'	'
Beginning Balance	4,013	3,447	8,252
Charged to Income	-1,464	4,328	663
Charged to Other Accounts	5,208	203	927
Deductions	4,781	3,965	6,395
Ending Balance	2,976	4,013	3,447
Accumulated provision for uncollectible accounts - other | FES	'	'	'
Consolidated Valuation and Qualifying Accounts	'	'	'
Beginning Balance	2,500	2,500	6,765
Charged to Income	28	1,290	22
Charged to Other Accounts	0	0	4
Deductions	5	1,290	4,291
Ending Balance	2,523	2,500	2,500
Loss carryforward tax valuation reserve	'	'	'
Consolidated Valuation and Qualifying Accounts	'	'	'
Beginning Balance	101,697	34,236	26,051
Charged to Income	23,663	67,461	-18,933
Charged to Other Accounts	0	0	27,118
Deductions	0	0	0
Ending Balance	125,360	101,697	34,236
Loss carryforward tax valuation reserve | FES	'	'	'
Consolidated Valuation and Qualifying Accounts	'	'	'
Beginning Balance	15,810	11,650	9,290
Charged to Income	11,065	4,160	2,360
Charged to Other Accounts	0	0	0
Deductions	0	0	0
Ending Balance	$26,875	$15,810	$11,650