FirstEnergy Solutions 10-Q 5 Aug 14 2014 Q2 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	6 Months Ended
	Jun. 30, 2014	Jul. 31, 2014
Entity Information [Line Items]	'	'
Entity Registrant Name	'FIRSTENERGY CORP	'
Entity Central Index Key	'0001031296	'
Document Type	'10-Q	'
Document Period End Date	30-Jun-14	'
Amendment Flag	'false	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q2	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock Shares Outstanding	'	420,344,546
FES	'	'
Entity Information [Line Items]	'	'
Entity Registrant Name	'FirstEnergy Solutions Corp.	'
Entity Central Index Key	'0001407703	'
Document Type	'10-Q	'
Document Period End Date	30-Jun-14	'
Amendment Flag	'false	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q2	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Non-accelerated Filer	'
Entity Common Stock Shares Outstanding	'	7

Consolidated_Statements_of_Inc

Consolidated Statements of Income (FirstEnergy Corp.) (USD $)	3 Months Ended				6 Months Ended
In Millions, except Per Share data, unless otherwise specified	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
REVENUES:	'		'		'		'
Electric utilities	$2,256		$2,217		$4,988		$4,602
Unregulated businesses	1,240		1,290		2,690		2,625
Total revenues	3,496	[1]	3,507	[1]	7,678	[1]	7,227	[1]
OPERATING EXPENSES:	'		'		'		'
Fuel	550		628		1,167		1,258
Purchased power	1,083		866		2,538		1,812
Other operating expenses	1,021		886		2,203		1,768
Provision for depreciation	302		300		596		593
Amortization (deferral) of regulatory assets, net	20		72		-8		131
General taxes	228		240		499		505
Impairment of long-lived assets	0		473		0		473
Total operating expenses	3,204		3,465		6,995		6,540
OPERATING INCOME (LOSS)	292		42		683		687
OTHER INCOME (EXPENSE):	'		'		'		'
Loss on debt redemptions (Note 7)	-1		-24		-8		-141
Investment income (loss)	29		-15		51		3
Interest expense	-262		-256		-527		-514
Capitalized financing costs	32		23		61		41
Total other income (expense)	-202		-272		-423		-611
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	90		-230		260		76
INCOME TAXES (BENEFITS)	26		-62		74		52
INCOME (LOSS) FROM CONTINUING OPERATIONS	64		-168		186		24
Discontinued operations (net of income taxes of $0, $4, $69 and $6, respectively) (Note 13)	0		4		86		8
NET INCOME (LOSS)	$64		($164)		$272		$32
EARNINGS PER SHARE OF COMMON STOCK:	'		'		'		'
Basic - Continuing Operations, in dollars per share	$0.16		($0.40)		$0.45		$0.06
Basic - Discontinued Operations (Note 13), in dollars per share	$0		$0.01		$0.20		$0.02
Basic - Earnings Available to FirstEnergy Corp., in dollars per share	$0.16		($0.39)		$0.65		$0.08
Diluted - Continuing Operations, in dollars per share	$0.15		($0.40)		$0.45		$0.06
Diluted - Discontinued Operations (Note 13), in dollars per share	$0		$0.01		$0.20		$0.02
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share	$0.15		($0.39)		$0.65		$0.08
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:	'		'		'		'
Basic, in shares	420		418		419		418
Diluted, in shares	421		418		420		419
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share	$0	[2]	$0	[2]	$0.72		$0.55
[1]	Includes excise tax collections of $99 million and $107 million in the three months ended June 30, 2014 and 2013, respectively, and $216 million and $229 million in the six months ended June 30, 2014 and 2013, respectively.
[2]	The six months ended June 30, 2014 includes a dividend declared of $0.36 per share on January 21, 2014, paid on March 1, 2014 and a dividend declared of $0.36 per share on March 18, 2014, paid on June 1, 2014. The six months ended June 30, 2013 includes a dividend declared of $0.55 per share on March 19, 2013, paid on June 1, 2013.

Consolidated_Statements_of_Inc1

Consolidated Statements of Income (FirstEnergy Corp.) (Parenthetical) (USD $)	3 Months Ended		6 Months Ended
In Millions, except Per Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Mar. 18, 2014	Jan. 21, 2014	Mar. 19, 2013
Income Statement [Abstract]	'	'	'	'	'	'	'
Tax effect of discontinued operations	$0	$4	$69	$6	'	'	'
Excise taxes collected	$99	$107	$216	$229	'	'	'
Dividends declared amount paid per declaration (in dollars per share)	'	'	'	'	$0.36	$0.36	$0.55

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (FirstEnergy Corp.) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Statement of Comprehensive Income [Abstract]	'	'	'	'
NET INCOME (LOSS)	$64	($164)	$272	$32
OTHER COMPREHENSIVE INCOME (LOSS):	'	'	'	'
Pension and OPEB prior service costs	-42	-55	-84	-101
Amortized gains (losses) on derivative hedges	-1	1	-1	2
Change in unrealized gain on available-for-sale securities	30	-8	51	-3
Other comprehensive income (loss)	-13	-62	-34	-102
Income tax benefits on other comprehensive loss	-6	-24	-14	-40
Other comprehensive income (loss), net of tax	-7	-38	-20	-62
COMPREHENSIVE INCOME (LOSS)	$57	($202)	$252	($30)

Consolidated_Balance_Sheets_Fi

Consolidated Balance Sheets (FirstEnergy Corp.) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'
Cash and cash equivalents	$76	$218
Receivables-	'	'
Customers, net of allowance for uncollectible accounts of $59 in 2014 and $52 in 2013	1,731	1,720
Other, net of allowance for uncollectible accounts of $3 in 2014 and $3 in 2013	231	198
Materials and supplies, at average cost	802	752
Prepaid taxes	246	226
Derivatives	249	166
Accumulated deferred income taxes	377	366
Collateral	266	155
Other	205	212
Total current assets	4,183	4,013
PROPERTY, PLANT AND EQUIPMENT:	'	'
In service	46,133	44,228
Less - Accumulated provision for depreciation	13,797	13,280
Property, plant and equipment in service net of accumulated provision for depreciation	32,336	30,948
Construction work in progress	2,180	2,304
Total net property, plant and equipment	34,516	33,252
INVESTMENTS:	'	'
Nuclear plant decommissioning trusts	2,364	2,201
Other	896	903
Total other property and investments	3,260	3,104
ASSETS HELD FOR SALE	0	235
DEFERRED CHARGES AND OTHER ASSETS:	'	'
Goodwill	6,418	6,418
Regulatory assets	1,732	1,854
Other	1,279	1,548
Total deferred charges and other assets	9,429	9,820
Total assets	51,388	50,424
CURRENT LIABILITIES:	'	'
Currently payable long-term debt	1,016	1,415
Short-term borrowings	2,323	3,404
Accounts payable	1,341	1,250
Accrued taxes	397	485
Accrued compensation and benefits	283	351
Derivatives	201	111
Other	612	621
Total current liabilities	6,173	7,637
Common stockholders' equity-	'	'
Common stock, $0.10 par value, authorized 490,000,000 shares - 420,271,254 and 418,628,559 shares outstanding as of June 30, 2014 and December 31, 2013, respectively	42	42
Other paid-in capital	9,817	9,776
Accumulated other comprehensive income	264	284
Retained earnings	2,560	2,590
Total common stockholders' equity	12,683	12,692
Noncontrolling interest	2	3
Total equity	12,685	12,695
Long-term debt and other long-term obligations	18,415	15,831
Total capitalization	31,100	28,526
NONCURRENT LIABILITIES:	'	'
Accumulated deferred income taxes	7,081	6,968
Retirement benefits	2,732	2,689
Asset retirement obligations	1,730	1,678
Deferred gain on sale and leaseback transaction	841	858
Adverse power contract liability	237	290
Other	1,494	1,778
Total noncurrent liabilities	14,115	14,261
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)	'	'
Total liabilities and capitalization	$51,388	$50,424

Consolidated_Balance_Sheets_Fi1

Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) (USD $)	Jun. 30, 2014	Dec. 31, 2013
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	420,271,254	418,628,559
Customer [Member]	'	'
Receivables-	'	'
Allowance for uncollectible accounts (in dollars)	$59	$52
Other [Member]	'	'
Receivables-	'	'
Allowance for uncollectible accounts (in dollars)	$3	$3

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (FirstEnergy Corp.) (USD $)	6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'
NET INCOME	$272	$32
Adjustments to reconcile net income to net cash from operating activities-	'	'
Provision for depreciation	596	593
Amortization (deferral) of regulatory assets, net	-8	131
Nuclear fuel amortization	98	98
Deferred purchased power and other costs	-47	-39
Deferred income taxes and investment tax credits, net	159	119
Impairments of long-lived assets	0	473
Investment impairments	3	53
Deferred rents and lease market valuation liability	-79	-75
Retirement benefits	-42	-104
Commodity derivative transactions, net (Note 8)	40	17
Loss on debt redemptions	8	141
Make-whole premiums paid on debt redemptions	0	-61
Income from discontinued operations (Note 13)	-86	-8
Changes in current assets and liabilities-	'	'
Receivables	-44	-125
Materials and supplies	-50	42
Prepayments and other current assets	-20	-185
Accounts payable	103	-312
Accrued taxes	-159	-205
Accrued compensation and benefits	-70	-34
Cash collateral, net	-127	-38
Other	75	-20
Net cash provided from operating activities	622	493
New Financing-	'	'
Long-term debt	3,137	2,245
Short-term borrowings, net	0	1,285
Redemptions and Repayments-	'	'
Long-term debt	-925	-1,968
Short-term borrowings, net	-1,081	0
Tender premiums paid on debt redemptions	0	-110
Common stock dividend payments	-302	-460
Other	-24	-16
Net cash provided from financing activities	805	976
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Property additions	-1,809	-1,412
Nuclear fuel	-58	-50
Proceeds from asset sales	394	0
Sales of investment securities held in trusts	1,164	1,177
Purchases of investment securities held in trusts	-1,221	-1,173
Asset removal costs	-47	-111
Other	8	-1
Net cash used for investing activities	-1,569	-1,570
Net change in cash and cash equivalents	-142	-101
Cash and cash equivalents at beginning of period	218	172
Cash and cash equivalents at end of period	$76	$71

Consolidated_Statements_of_Inc2

Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) (USD $)	3 Months Ended				6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
REVENUES:	'		'		'		'
Electric sales	$1,240		$1,290		$2,690		$2,625
Total revenues	3,496	[1]	3,507	[1]	7,678	[1]	7,227	[1]
OPERATING EXPENSES:	'		'		'		'
Fuel	550		628		1,167		1,258
Purchased power	1,083		866		2,538		1,812
Other operating expenses	1,021		886		2,203		1,768
Provision for depreciation	302		300		596		593
General taxes	228		240		499		505
Total operating expenses	3,204		3,465		6,995		6,540
OPERATING INCOME (LOSS)	292		42		683		687
OTHER INCOME (EXPENSE):	'		'		'		'
Loss on debt redemptions (Note 7)	-1		-24		-8		-141
Investment income (loss)	29		-15		51		3
Interest expense	-262		-256		-527		-514
Capitalized interest	32		23		61		41
Total other income (expense)	-202		-272		-423		-611
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	90		-230		260		76
INCOME TAXES (BENEFITS)	26		-62		74		52
INCOME (LOSS) FROM CONTINUING OPERATIONS	64		-168		186		24
Discontinued operations (net of income taxes of $0, $1, $70 and $3, respectively) (Note 13)	0		4		86		8
NET INCOME (LOSS)	64		-164		272		32
STATEMENTS OF COMPREHENSIVE INCOME	'		'		'		'
NET INCOME (LOSS)	64		-164		272		32
OTHER COMPREHENSIVE INCOME (LOSS):	'		'		'		'
Pension and OPEB prior service costs	-42		-55		-84		-101
Amortized loss (gain) on derivative hedges	-1		1		-1		2
Change in unrealized gain on available-for-sale securities	30		-8		51		-3
Other comprehensive income (loss)	-13		-62		-34		-102
Income taxes (benefits) on other comprehensive income (loss)	-6		-24		-14		-40
Other comprehensive income (loss), net of tax	-7		-38		-20		-62
COMPREHENSIVE INCOME (LOSS)	57		-202		252		-30
FES	'		'		'		'
REVENUES:	'		'		'		'
Other	42		35		82		69
Total revenues	1,452		1,452		3,281		2,976
OPERATING EXPENSES:	'		'		'		'
Fuel	334		332		653		632
Other operating expenses	468		387		920		766
Provision for depreciation	79		76		153		151
General taxes	29		34		68		71
Total operating expenses	1,603		1,491		3,580		2,920
OPERATING INCOME (LOSS)	-151		-39		-299		56
OTHER INCOME (EXPENSE):	'		'		'		'
Loss on debt redemptions (Note 7)	0		-32		-5		-103
Investment income (loss)	24		-18		44		-1
Miscellaneous income	4		6		4		8
Capitalized interest	8		10		20		19
Total other income (expense)	-3		-78		-14		-174
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	-154		-117		-313		-118
INCOME TAXES (BENEFITS)	-67		-42		-123		-42
INCOME (LOSS) FROM CONTINUING OPERATIONS	-87		-75		-190		-76
Discontinued operations (net of income taxes of $0, $1, $70 and $3, respectively) (Note 13)	0		4		116		7
NET INCOME (LOSS)	-87		-71		-74		-69
STATEMENTS OF COMPREHENSIVE INCOME	'		'		'		'
NET INCOME (LOSS)	-87		-71		-74		-69
OTHER COMPREHENSIVE INCOME (LOSS):	'		'		'		'
Pension and OPEB prior service costs	-5		-5		-10		-11
Amortized loss (gain) on derivative hedges	-3		-1		-5		-2
Change in unrealized gain on available-for-sale securities	25		-8		44		-3
Other comprehensive income (loss)	17		-14		29		-16
Income taxes (benefits) on other comprehensive income (loss)	7		-5		11		-6
Other comprehensive income (loss), net of tax	10		-9		18		-10
COMPREHENSIVE INCOME (LOSS)	-77		-80		-56		-79
FES | Affiliates	'		'		'		'
REVENUES:	'		'		'		'
Electric sales	176		140		525		296
OPERATING EXPENSES:	'		'		'		'
Purchased power	75		137		139		269
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense	-2		-5		-4		-6
FES | Non-Affiliates	'		'		'		'
REVENUES:	'		'		'		'
Electric sales	1,234		1,277		2,674		2,611
OPERATING EXPENSES:	'		'		'		'
Purchased power	618		525		1,647		1,031
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense	($37)		($39)		($73)		($91)
[1]	Includes excise tax collections of $99 million and $107 million in the three months ended JuneB 30, 2014 and 2013, respectively, and $216 million and $229 million in the six months ended JuneB 30, 2014 and 2013, respectively.

Consolidated_Statements_of_Inc3

Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) (Parenthetical) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Tax effect of discontinued operations	$0	$4	$69	$6
FES	'	'	'	'
Tax effect of discontinued operations	$0	$1	$70	$3

Consolidated_Balance_Sheets_Fi2

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'
Cash and cash equivalents	$76	$218
Receivables-	'	'
Customers, net of allowance for uncollectible accounts of $14 in 2014 and $11 in 2013	1,731	1,720
Other, net of allowance for uncollectible accounts of $3 in 2014 and 2013	231	198
Materials and supplies	802	752
Derivatives	249	166
Collateral	266	155
Prepayments and other	205	212
Total current assets	4,183	4,013
PROPERTY, PLANT AND EQUIPMENT:	'	'
In service	46,133	44,228
Less - Accumulated provision for depreciation	13,797	13,280
Property, plant and equipment in service net of accumulated provision for depreciation	32,336	30,948
Construction work in progress	2,180	2,304
Total net property, plant and equipment	34,516	33,252
INVESTMENTS:	'	'
Nuclear plant decommissioning trusts	2,364	2,201
Other	896	903
Total other property and investments	3,260	3,104
ASSETS HELD FOR SALE	0	235
DEFERRED CHARGES AND OTHER ASSETS:	'	'
Goodwill	6,418	6,418
Other	1,279	1,548
Total deferred charges and other assets	9,429	9,820
Total assets	51,388	50,424
CURRENT LIABILITIES:	'	'
Currently payable long-term debt	1,016	1,415
Other	2,323	3,404
Accounts payable-	'	'
Accrued taxes	397	485
Derivatives	201	111
Other	612	621
Total current liabilities	6,173	7,637
Common stockholders' equity-	'	'
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of June 30, 2014 and December 31, 2013	42	42
Accumulated other comprehensive income	264	284
Retained earnings	2,560	2,590
Total common stockholders' equity	12,683	12,692
Long-term debt and other long-term obligations	18,415	15,831
Total capitalization	31,100	28,526
NONCURRENT LIABILITIES:	'	'
Deferred gain on sale and leaseback transaction	841	858
Accumulated deferred income taxes	7,081	6,968
Asset retirement obligations	1,730	1,678
Retirement benefits	2,732	2,689
Other	1,494	1,778
Total noncurrent liabilities	14,115	14,261
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)	'	'
Total liabilities and capitalization	51,388	50,424
FES	'	'
CURRENT ASSETS:	'	'
Cash and cash equivalents	2	2
Receivables-	'	'
Customers, net of allowance for uncollectible accounts of $14 in 2014 and $11 in 2013	534	539
Affiliated companies	475	1,036
Other, net of allowance for uncollectible accounts of $3 in 2014 and 2013	97	81
Notes receivable from affiliated companies	168	0
Materials and supplies	466	448
Derivatives	238	165
Collateral	256	136
Prepayments and other	125	109
Total current assets	2,361	2,516
PROPERTY, PLANT AND EQUIPMENT:	'	'
In service	13,622	12,472
Less - Accumulated provision for depreciation	4,968	4,755
Property, plant and equipment in service net of accumulated provision for depreciation	8,654	7,717
Construction work in progress	682	1,308
Total net property, plant and equipment	9,336	9,025
INVESTMENTS:	'	'
Nuclear plant decommissioning trusts	1,379	1,276
Other	11	11
Total other property and investments	1,390	1,287
ASSETS HELD FOR SALE	0	122
DEFERRED CHARGES AND OTHER ASSETS:	'	'
Customer intangibles	86	95
Goodwill	23	23
Property taxes	19	41
Unamortized sale and leaseback costs	215	168
Derivatives	57	53
Other	112	172
Total deferred charges and other assets	512	552
Total assets	13,599	13,502
CURRENT LIABILITIES:	'	'
Currently payable long-term debt	291	892
Other	308	4
Accounts payable-	'	'
Affiliated companies	421	765
Other	259	290
Accrued taxes	98	66
Derivatives	200	110
Other	183	197
Total current liabilities	1,760	2,755
Common stockholders' equity-	'	'
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of June 30, 2014 and December 31, 2013	3,583	3,080
Accumulated other comprehensive income	72	54
Retained earnings	2,104	2,178
Total common stockholders' equity	5,759	5,312
Long-term debt and other long-term obligations	2,721	2,130
Total capitalization	8,480	7,442
NONCURRENT LIABILITIES:	'	'
Deferred gain on sale and leaseback transaction	841	858
Accumulated deferred income taxes	746	741
Asset retirement obligations	1,044	1,015
Retirement benefits	193	185
Derivatives	43	14
Other	492	492
Total noncurrent liabilities	3,359	3,305
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)	'	'
Total liabilities and capitalization	13,599	13,502
FES | Affiliated Entity [Member]	'	'
CURRENT LIABILITIES:	'	'
Affiliated companies	$0	$431

Consolidated_Balance_Sheets_Fi3

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) (USD $)	Jun. 30, 2014	Dec. 31, 2013
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	420,271,254	418,628,559
Customer [Member]	'	'
Receivables-	'	'
Allowance for uncollectible accounts (in dollars)	59	52
Other Receivables [Member]	'	'
Receivables-	'	'
Allowance for uncollectible accounts (in dollars)	3	3
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)	14	11
FES | Other Receivables [Member]	'	'
Receivables-	'	'
Allowance for uncollectible accounts (in dollars)	3	3

Consolidated_Statements_of_Cas1

Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) (USD $)	6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'
NET INCOME (LOSS)	$272	$32
Adjustments to reconcile net income (loss) to net cash from operating activities-	'	'
Provision for depreciation	596	593
Nuclear fuel amortization	98	98
Deferred rents and lease market valuation liability	-79	-75
Deferred income taxes and investment tax credits, net	159	119
Investment impairments	3	53
Retirement benefits	-42	-104
Commodity derivative transactions, net (Note 8)	40	17
Loss on debt redemptions	8	141
Make-whole premiums paid on debt redemptions	0	-61
Income from discontinued operations (Note 13)	-86	-8
Changes in current assets and liabilities-	'	'
Receivables	-44	-125
Materials and supplies	-50	42
Prepayments and other current assets	-20	-185
Accounts payable	103	-312
Accrued taxes	-159	-205
Accrued compensation and benefits	-70	-34
Cash collateral, net	-127	-38
Other	75	-20
Net cash provided from operating activities	622	493
New financing-	'	'
Long-term debt	3,137	2,245
Redemptions and Repayments-	'	'
Long-term debt	-925	-1,968
Short-term borrowings, net	-1,081	0
Tender premiums paid on debt redemptions	0	-110
Other	-24	-16
Net cash provided from financing activities	805	976
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Property additions	-1,809	-1,412
Nuclear fuel	-58	-50
Proceeds from asset sales	394	0
Sales of investment securities held in trusts	1,164	1,177
Purchases of investment securities held in trusts	-1,221	-1,173
Other	8	-1
Net cash used for investing activities	-1,569	-1,570
Net change in cash and cash equivalents	-142	-101
Cash and cash equivalents at beginning of period	218	172
Cash and cash equivalents at end of period	76	71
FES	'	'
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'
NET INCOME (LOSS)	-74	-69
Adjustments to reconcile net income (loss) to net cash from operating activities-	'	'
Provision for depreciation	153	151
Nuclear fuel amortization	98	98
Deferred rents and lease market valuation liability	-76	-72
Deferred income taxes and investment tax credits, net	-23	141
Investment impairments	3	45
Retirement benefits	-2	-3
Commodity derivative transactions, net (Note 8)	40	17
Loss on debt redemptions	5	103
Make-whole premiums paid on debt redemptions	0	-31
Income from discontinued operations (Note 13)	-116	-7
Changes in current assets and liabilities-	'	'
Receivables	550	-156
Materials and supplies	-18	52
Prepayments and other current assets	5	-40
Accounts payable	-339	-91
Accrued taxes	-57	-134
Accrued compensation and benefits	-7	3
Cash collateral, net	-117	2
Other	58	-9
Net cash provided from operating activities	83	0
New financing-	'	'
Long-term debt	637	0
Equity contribution from parent	500	1,500
Redemptions and Repayments-	'	'
Long-term debt	-664	-1,179
Short-term borrowings, net	-127	0
Tender premiums paid on debt redemptions	0	-67
Other	-10	-5
Net cash provided from financing activities	336	249
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Property additions	-477	-350
Nuclear fuel	-57	-50
Proceeds from asset sales	307	19
Sales of investment securities held in trusts	707	487
Purchases of investment securities held in trusts	-736	-515
Loans to affiliated companies, net	-168	156
Other	5	3
Net cash used for investing activities	-419	-250
Net change in cash and cash equivalents	0	-1
Cash and cash equivalents at beginning of period	2	3
Cash and cash equivalents at end of period	$2	$2

Organization_and_Basis_of_Pres

Organization and Basis of Presentation	6 Months Ended
	Jun. 30, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
ORGANIZATION AND BASIS OF PRESENTATION	'
	ORGANIZATION AND BASIS OF PRESENTATION
	Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms.
	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, FESC, FES and its principal subsidiaries (FG and NG), AE Supply, MP, PE, WP and FET. 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.
	These interim financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These interim financial statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2013.
	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 accompanying interim financial statements are unaudited, but reflect all adjustments, consisting of normal recurring adjustments, that, in the opinion of management, are necessary for a fair statement of the financial statements. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not 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. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 6, 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.
	For the three months ended June 30, 2014 and 2013, capitalized financing costs on FirstEnergy's Consolidated Statements of Income (Loss) includes $14 million and $4 million, respectively, of allowance for equity funds used during construction and $18 million and $19 million, respectively, of capitalized interest. For the six months ended June 30, 2014 and 2013, capitalized financing costs on FirstEnergy's Consolidated Statements of Income (Loss) includes $21 million and $7 million, respectively, of allowance for equity funds used during construction, and $40 million and $34 million, respectively, of capitalized interest.
	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 the sale of hydro assets discussed in additional detail in Note 13, Discontinued Operations.
	New Accounting Pronouncements
	In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, requiring entities to recognize revenue by applying a five-step model in accordance with the core principle to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, ASU No. 2014-09 specifies the accounting for costs to obtain or fulfill a contract with a customer and expands disclosure requirements for revenue recognition. This standard is effective for fiscal years beginning after December 15, 2016, with no early adoption permitted, and shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

Earnings_Per_Share_of_Common_S

Earnings Per Share of Common Stock	6 Months Ended
	Jun. 30, 2014
Earnings Per Share [Abstract]	'
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.
	The following table reconciles basic and diluted earnings (loss) per share of common stock:
	(In millions, except per share amounts)		Three Months Ended June 30					Six Months Ended June 30
	Reconciliation of Basic and Diluted Earnings (Loss) per Share of Common Stock		2014		2013			2014		2013
	Income (loss) from continuing operations		$	64	$	(168	)	$	186	$	24
	Discontinued operations (Note 13)		—		4			86		8
	Net income (loss)		$	64	$	(164	)	$	272	$	32
	Weighted average number of basic shares outstanding		420		418			419		418
	Assumed exercise of dilutive stock options and awards(1)		1		—			1		1
	Weighted average number of diluted shares outstanding		421		418			420		419
	Earnings (loss) per share:
	Basic earnings per share:
	Income (loss) from continuing operations		$	0.16	$	(0.40	)	$	0.45	$	0.06
	Discontinued operations (Note 13)		—		0.01			0.2		0.02
	Net earnings (loss) per basic share		$	0.16	$	(0.39	)	$	0.65	$	0.08
	Diluted earnings (loss) per share:
	Income (loss) from continuing operations		$	0.15	$	(0.40	)	$	0.45	$	0.06
	Discontinued operations (Note 13)		—		0.01			0.2		0.02
	Net earnings (loss) per diluted share		$	0.15	$	(0.39	)	$	0.65	$	0.08
	(1)	For the three months ended June 30, 2014 and June 30, 2013, 1 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the six months ended June 30, 2014, 2 million shares were excluded from the calculation of diluted shares outstanding. The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect was not significant for the six months ended June 30, 2013.

Pension_and_Other_Postemployme

Pension and Other Postemployment Benefits	6 Months Ended
	Jun. 30, 2014
Compensation and Retirement Disclosure [Abstract]	'
PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS	'
	PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS
	The components of the consolidated net periodic cost (credits) for pensions and OPEB (including amounts capitalized) were as follows:
	Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
	For the Three Months Ended June 30,	2014			2013			2014			2013
		(In millions)
	Service costs	$	41		$	49		$	2		$	3
	Interest costs	101			93			10			9
	Expected return on plan assets	(115		)	(125		)	(8		)	(8		)
	Amortization of prior service costs (credits)	2			3			(44		)	(58		)
	Net periodic costs (credits)	$	29		$	20		$	(40	)	$	(54	)
	Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
	For the Six Months Ended June 30,	2014			2013			2014			2013
		(In millions)
	Service costs	$	83		$	98		$	4		$	6
	Interest costs	201			186			20			18
	Expected return on plan assets	(230		)	(250		)	(16		)	(16		)
	Amortization of prior service costs (credits)	4			6			(88		)	(107		)
	Net periodic costs (credits)	$	58		$	40		$	(80	)	$	(99	)
	FES' share of the net periodic pensions and OPEB costs (credits) were as follows:
		Pensions						OPEB
		2014			2013			2014			2013
		(In millions)
	For the Three Months Ended June 30,	$	4		$	5		$	(5	)	$	(5	)
	For the Six Months Ended June 30,	$	8		$	10		$	(10	)	$	(10	)
	Pension and OPEB obligations are allocated to FE's subsidiaries employing the plan participants. The net periodic pension and OPEB costs (net of amounts capitalized) recognized in earnings by FE and FES were as follows:
	Net Periodic Benefit Expense (Credit)	Pensions						OPEB
	For the Three Months Ended June 30,	2014			2013			2014			2013
		(In millions)
	FirstEnergy	$	21		$	14		$	(27	)	$	(34	)
	FES	4			5			(5		)	(5		)
	Net Periodic Benefit Expense (Credit)	Pensions						OPEB
	For the Six Months Ended June 30,	2014			2013			2014			2013
		(In millions)
	FirstEnergy	$	42		$	25		$	(54	)	$	(64	)
	FES	8			8			(9		)	(8		)

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income	6 Months Ended
	Jun. 30, 2014
Statement of Comprehensive Income [Abstract]	'
ACCUMULATED OTHER COMPREHENSIVE INCOME	'
	ACCUMULATED OTHER COMPREHENSIVE INCOME
	The changes in AOCI, net of tax, in the three and six months ended June 30, 2014 and 2013, 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 as of April 1, 2014	$	(36	)	$	22		$	285		$	271
	Other comprehensive income before reclassifications	1			31			—			32
	Amounts reclassified from AOCI	(1		)	(12		)	(26		)	(39		)
	Net other comprehensive income (loss)	—			19			(26		)	(7		)
	AOCI Balance as of June 30, 2014	$	(36	)	$	41		$	259		$	264
	AOCI Balance as of April 1, 2013	$	(37	)	$	18		$	380		$	361
	Other comprehensive loss before reclassifications	—			(1		)	—			(1		)
	Amounts reclassified from AOCI	—			(4		)	(33		)	(37		)
	Net other comprehensive loss	—			(5		)	(33		)	(38		)
	AOCI Balance as of June 30, 2013	$	(37	)	$	13		$	347		$	323
	FES
		Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
		(In millions)
	AOCI Balance as of April 1, 2014	$	(2	)	$	20		$	44		$	62
	Other comprehensive income (loss) before reclassifications	(1		)	28			—			27
	Amounts reclassified from AOCI	(2		)	(12		)	(3		)	(17		)
	Net other comprehensive income (loss)	(3		)	16			(3		)	10
	AOCI Balance as of June 30, 2014	$	(5	)	$	36		$	41		$	72
	AOCI Balance as of April 1, 2013	$	2		$	17		$	52		$	71
	Other comprehensive loss before reclassifications	—			(1		)	—			(1		)
	Amounts reclassified from AOCI	(1		)	(4		)	(3		)	(8		)
	Net other comprehensive loss	(1		)	(5		)	(3		)	(9		)
	AOCI Balance as of June 30, 2013	$	1		$	12		$	49		$	62
	FirstEnergy
		Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
		(In millions)
	AOCI Balance as of January 1, 2014	$	(36	)	$	9		$	311		$	284
	Other comprehensive income before reclassifications	1			53			—			54
	Amounts reclassified from AOCI	(1		)	(21		)	(52		)	(74		)
	Net other comprehensive income (loss)	—			32			(52		)	(20		)
	AOCI Balance as of June 30, 2014	$	(36	)	$	41		$	259		$	264
	AOCI Balance as of January 1, 2013	$	(38	)	$	15		$	408		$	385
	Other comprehensive income before reclassifications	—			14			—			14
	Amounts reclassified from AOCI	1			(16		)	(61		)	(76		)
	Net other comprehensive income (loss)	1			(2		)	(61		)	(62		)
	AOCI Balance as of June 30, 2013	$	(37	)	$	13		$	347		$	323
	FES
		Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
		(In millions)
	AOCI Balance as of January 1, 2014	$	(1	)	$	8		$	47		$	54
	Other comprehensive income (loss) before reclassifications	(1		)	49			—			48
	Amounts reclassified from AOCI	(3		)	(21		)	(6		)	(30		)
	Net other comprehensive income (loss)	(4		)	28			(6		)	18
	AOCI Balance as of June 30, 2014	$	(5	)	$	36		$	41		$	72
	AOCI Balance as of January 1, 2013	$	3		$	13		$	56		$	72
	Other comprehensive income before reclassifications	—			13			—			13
	Amounts reclassified from AOCI	(2		)	(14		)	(7		)	(23		)
	Net other comprehensive loss	(2		)	(1		)	(7		)	(10		)
	AOCI Balance as of June 30, 2013	$	1		$	12		$	49		$	62
	The following amounts were reclassified from AOCI in the three months ended June 30, 2014 and 2013:
	FE	Three Months Ended June 30						Affected Line Item in Consolidated Statements of Income (Loss)
	Reclassifications from AOCI (b)	2014			2013
		(In millions)
	Gains & losses on cash flow hedges
	Commodity contracts	$	(3	)	$	(1	)	Other operating expenses
	Long-term debt	2			2			Interest expense
		(1		)	1			Total before taxes
		—			(1		)	Income taxes (benefits)
	$	(1	)	$	—		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(19	)	$	(6	)	Investment income (loss)
	7			2			Income taxes (benefits)
	$	(12	)	$	(4	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(42	)	$	(55	)	(a)
	16			22			Income taxes (benefits)
	$	(26	)	$	(33	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.
FES	Three Months Ended June 30						Affected Line Item in Consolidated Statements of Operations
Reclassifications from AOCI (b)	2014			2013
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(3	)	$	(1	)	Other operating expenses
	1			—			Income tax benefits
	$	(2	)	$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(18	)	$	(6	)	Investment income (loss)
	6			2			Income tax benefits
	$	(12	)	$	(4	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(5	)	$	(5	)	(a)
	2			2			Income tax benefits
	$	(3	)	$	(3	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Operations from AOCI.
The following amounts were reclassified from AOCI in the six months ended June 30, 2014 and 2013:
FE	Six Months Ended June 30						Affected Line Item in Consolidated Statements of Income (Loss)
Reclassifications from AOCI (b)	2014			2013
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(5	)	$	(4	)	Other operating expenses
Long-term debt	4			6			Interest expense
	(1		)	2			Total before taxes
	—			(1		)	Income taxes (benefits)
	$	(1	)	$	1		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(33	)	$	(25	)	Investment income (loss)
	12			9			Income taxes (benefits)
	$	(21	)	$	(16	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(84	)	$	(101	)	(a)
	32			40			Income taxes (benefits)
	$	(52	)	$	(61	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.
FES	Six Months Ended June 30						Affected Line Item in Consolidated Statements of Operations
Reclassifications from AOCI (b)	2014			2013
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(5	)	$	(4	)	Other operating expenses
Long-term debt	—			2			Interest expense
	(5		)	(2		)	Total before taxes
	2			—			Income tax benefits
	$	(3	)	$	(2	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(32	)	$	(22	)	Investment income (loss)
	11			8			Income tax benefits
	$	(21	)	$	(14	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(10	)	$	(11	)	(a)
	4			4			Income taxes benefits
	$	(6	)	$	(7	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Operations from AOCI.

Income_Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2014
Income Tax Disclosure [Abstract]	'
INCOME TAXES	'
	INCOME TAXES
	FirstEnergy’s and FES’ interim effective tax rates reflect the estimated annual effective tax rates for 2014 and 2013, adjusted for tax expense associated with certain discrete items that may occur in any given period, but are not consistent from period to period.
	FirstEnergy’s effective tax rates from continuing operations for the three months ended June 30, 2014 and 2013 were 28.9% and 27.0%, respectively. The 2014 effective tax rate was impacted primarily from a reduction in deferred tax liabilities associated with changes in state apportionment factors. The 2013 effective tax rate was impacted primarily from a valuation allowance against state and local NOL carryforwards that offset the benefit received from pre-tax losses. The effective tax rates from continuing operations for the six months ended June 30, 2014 and 2013 were 28.5% and 68.4%, respectively. The decrease in the effective tax rate is primarily due to an increase in the benefit of AFUDC equity flow through, the elimination of certain future tax liabilities associated with basis differences, and the reduction in state deferred tax liabilities resulting from changes in state apportionment factors. Additionally, as discussed above, the 2013 effective tax rate includes the impact of recording a valuation allowance against state and local net operating loss carryforwards.
	FES’ effective tax rates from continuing operations for the three months ended June 30, 2014 and 2013 were 43.5% and 35.9%, respectively, and the effective tax rates for the six months ended June 30, 2014 and 2013 were 39.3% and 35.6%, respectively. For both periods, the increase in the effective tax rate is primarily due to an increase in pre-tax losses from continuing operations in jurisdictions with higher tax rates, a benefit resulting from a reduction in state deferred tax liabilities associated with changes in apportionment factors, partially offset by valuation allowances on local net operating loss carryforwards recognized in 2013.
	In April 2014, the IRS completed its examination of FirstEnergy’s 2011 and 2012 federal income tax returns and issued Revenue Agent Reports for those years, which did not result in a material impact to FirstEnergy’s effective tax rate.

Variable_Interest_Entities

Variable Interest Entities	6 Months Ended
	Jun. 30, 2014
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: the PNBV 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.
	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 six months ended June 30, 2014, was primarily due to a distribution to owners.
	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.
	Mining Operations
	FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture's economic performance. FEV's ownership interest is subject to the equity method of accounting.
	Trusts
	FirstEnergy's consolidated financial statements include PNBV. FirstEnergy used debt and available funds to purchase the notes issued by PNBV 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.
	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 FirstEnergy 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 9, 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 at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy maintains 19 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 at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contracts that may contain a variable interest were $40 million and $41 million during the three months ended June 30, 2014 and 2013, respectively, and $102 million and $90 million during the six months ended June 30, 2014 and 2013, respectively.
	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.
	In March of 2013, FG acquired the remaining interests in connection with the 1987 Bruce Mansfield Plant sale and leaseback transactions for approximately $221 million. Also during 2013, NG purchased lessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for $23 million.
	In February 2014, NG purchased lessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for approximately $94 million. As of June 30, 2014, FirstEnergy's leasehold interest was 8.11% of Perry Unit 1, 93.83% of Bruce Mansfield Unit 1 and 2.60% of Beaver Valley Unit 2. On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors' interests in Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), which right to repurchase was assigned to NG. Additionally, on June 24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor equity interests representing approximately half of the remaining non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the end of the lease term.
	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 June 30, 2014:
		Maximum		Discounted Lease		Net
		Exposure		Payments, net(1)		Exposure
		(In millions)
	FES	$	1,212	$	1,000	$	212
	Other FE subsidiaries	701		393		308
	(1)The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.0 billion.

Fair_Value_Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2014
Fair Value Disclosures [Abstract]	'
FAIR VALUE MEASUREMENTS	'
	FAIR VALUE MEASUREMENTS
	RECURRING AND NONRECURRING 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 and NUGs are as follows:
	FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term RTO auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent RTO auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 8, 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. During the fourth quarter of 2013, all LCAPP contracts were terminated. See Note 8, 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 June 30, 2014, from those used as of December 31, 2013. 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 six months ended June 30, 2014. The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:
	FirstEnergy
	Recurring Fair Value Measurements	June 30, 2014																December 31, 2013
		Level 1				Level 2				Level 3				Total				Level 1			Level 2			Level 3			Total
	Assets	(In millions)
	Corporate debt securities	$	—			$	1,194			$	—			$	1,194			$	—		$	1,365		$	—		$	1,365
	Derivative assets - commodity contracts	7				262				—				269				7			208			—			215
	Derivative assets - FTRs	—				—				37				37				—			—			4			4
	Derivative assets - NUG contracts(1)	—				—				2				2				—			—			20			20
	Equity securities(2)	700				—				—				700				317			—			—			317
	Foreign government debt securities	—				80				—				80				—			109			—			109
	U.S. government debt securities	—				172				—				172				—			165			—			165
	U.S. state debt securities	—				242				—				242				—			228			—			228
	Other(3)	95				272				—				367				187			255			—			442
	Total assets	$	802			$	2,222			$	39			$	3,063			$	511		$	2,330		$	24		$	2,865
	Liabilities
	Derivative liabilities - commodity contracts	$	(16	)		$	(212	)		$	—			$	(228	)		$	(13	)	$	(100	)	$	—		$	(113	)
	Derivative liabilities - FTRs	—				—				(16		)		(16		)		—			—			(12		)	(12		)
	Derivative liabilities - NUG contracts(1)	—				—				(171		)		(171		)		—			—			(222		)	(222		)
	Total liabilities	$	(16	)		$	(212	)		$	(187	)		$	(415	)		$	(13	)	$	(100	)	$	(234	)	$	(347	)
	Net assets (liabilities)(4)	$	786			$	2,010			$	(148	)		$	2,648			$	498		$	2,230		$	(210	)	$	2,518
	(1)	NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
	(2)	NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.
	(3)	Primarily consists of short-term cash investments.
	(4)	Excludes $(36) million and $10 million as of June 30, 2014 and December 31, 2013, 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 June 30, 2014 and December 31, 2013:
		NUG Contracts(1)												LCAPP Contracts										FTRs
		Derivative Assets				Derivative Liabilities				Net				Derivative Assets				Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
		(In millions)
	January 1, 2013 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	)
	Unrealized gain	1				26				27				—				—			—			19			6			25
	Purchases	—				—				—				—				—			—			26			(17		)	9
	Settlements	(19		)		25				6				—				—			—			(12		)	7			(5		)
	June 30, 2014 Balance	$	2			$	(171	)		$	(169	)		$	—			$	—		$	—		$	37		$	(16	)	$	21
	(1)	Changes in the fair value of NUG contracts are generally subject to regulatory accounting treatment and do not impact earnings.
	(2)	See Note 8, 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 June 30, 2014:
			Fair Value, Net (In millions)				Valuation		Significant Input		Range		Weighted Average			Units
							Technique
	FTRs		$	21			Model		RTO auction clearing prices		($6.70) to $8.00		$1.10			Dollars/MWH
	NUG Contracts		$	(169	)		Model		Generation		600 to 5,202,000		955,000			MWH
									Electricity regional prices		$49.30 to $59.00		$54.10			Dollars/MWH
FES
Recurring Fair Value Measurements	June 30, 2014																December 31, 2013
	Level 1				Level 2				Level 3				Total				Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—			$	651			$	—			$	651			$	—		$	792		$	—		$	792
Derivative assets - commodity contracts	7				262				—				269				7			208			—			215
Derivative assets - FTRs	—				—				26				26				—			—			3			3
Equity securities(1)	459				—				—				459				207			—			—			207
Foreign government debt securities	—				57				—				57				—			65			—			65
U.S. government debt securities	—				30				—				30				—			27			—			27
U.S. state debt securities	—				9				—				9				—			—			—			—
Other(2)	—				198				—				198				—			176			—			176
Total assets	$	466			$	1,207			$	26			$	1,699			$	214		$	1,268		$	3		$	1,485
Liabilities
Derivative liabilities - commodity contracts	$	(15	)		$	(212	)		$	—			$	(227	)		$	(13	)	$	(100	)	$	—		$	(113	)
Derivative liabilities - FTRs	—				—				(16		)		(16		)		—			—			(11		)	(11		)
Total liabilities	$	(15	)		$	(212	)		$	(16	)		$	(243	)		$	(13	)	$	(100	)	$	(11	)	$	(124	)
Net assets (liabilities)(3)	$	451			$	995			$	10			$	1,456			$	201		$	1,168		$	(8	)	$	1,361
(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 $(25) million and $9 million as of June 30, 2014 and December 31, 2013, respectively, of receivables, payables, taxes and accrued income associated with the 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 June 30, 2014 and December 31, 2013:
		Derivative Asset FTRs				Derivative Liability FTRs				Net FTRs
		(In millions)
January 1, 2013 Balance		$	6			$	(6	)		$	—
Unrealized loss		—				(2		)		(2		)
Purchases		5				(12		)		(7		)
Settlements		(8		)		9				1
December 31, 2013 Balance		$	3			$	(11	)		$	(8	)
Unrealized gain		15				5				20
Purchases		15				(17		)		(2		)
Settlements		(7		)		7				—
June 30, 2014 Balance		$	26			$	(16	)		$	10
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 June 30, 2014:
		Fair Value, Net (In millions)				Valuation		Significant Input		Range		Weighted Average		Units
						Technique
FTRs		$	10			Model		RTO auction clearing prices		($6.70) to $8.00		$0.90		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 June 30, 2014 and December 31, 2013:
		June 30, 2014(1)												December 31, 2013(2)
		Cost Basis				Unrealized Gains				Fair Value				Cost Basis				Unrealized Gains			Fair Value
		(In millions)
Debt securities
FirstEnergy		$	1,715			$	51			$	1,766			$	1,881			$	33		$	1,914
FES		805				24				829				918				17			935
Equity securities
FirstEnergy		$	617			$	83			$	700			$	308			$	9		$	317
FES		411				48				459				207				—			207
(1)	Excludes short-term cash investments: FE Consolidated - $139 million; FES - $91 million.
(2)	Excludes short-term cash investments: FE Consolidated - $204 million; FES - $135 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 months and six months ended June 30, 2014 and 2013 were as follows:
Three Months Ended
June 30, 2014		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and
																		Dividend Income
		(In millions)
FirstEnergy		$	543			$	35			$	(15	)		$	(1	)		$	24
FES		284				30				(12		)		(1		)		14
June 30, 2013		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and Dividend Income
		(In millions)
FirstEnergy		$	638			$	16			$	(11	)		$	(46	)		$	22
FES		235				13				(8		)		(38		)		15
Six Months Ended
June 30, 2014		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and
																		Dividend Income
		(In millions)
FirstEnergy		$	1,164			$	63			$	(31	)		$	(3	)		$	49
FES		707				49				(17		)		(3		)		29
June 30, 2013		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and Dividend Income
		(In millions)
FirstEnergy		$	1,177			$	40			$	(16	)		$	(53	)		$	48
FES		487				33				(11		)		(45		)		28
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 June 30, 2014 and December 31, 2013:
		June 30, 2014												December 31, 2013
		Cost Basis				Unrealized Gains				Fair Value				Cost Basis				Unrealized Gains			Fair Value
		(In millions)
Debt Securities
FirstEnergy		$	19			$	8			$	27			$	33			$	2		$	35
Investments in employee benefit trusts and cost and equity method investments, including FirstEnergy's investment in Global Holding, totaling $636 million as of June 30, 2014 and December 31, 2013, 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:
	June 30, 2014								December 31, 2013
	Carrying				Fair				Carrying				Fair
	Value				Value				Value				Value
	(In millions)
FirstEnergy	$	19,258			$	20,816			$	17,049			$	17,957
FES	2,993				3,136				3,001				3,073
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 June 30, 2014 and December 31, 2013.
On March 31, 2014, FE, FES, AE Supply, FET and FE's other borrower subsidiaries entered into extensions and amendments to the three existing multi-year syndicated revolving credit facilities. Each Facility was extended until March 31, 2019. The FE facility was amended to increase the lending banks' commitments under the facility by $1 billion to a total of $3.5 billion and to increase the individual borrower sublimit for FE by $1 billion to a total of $3.5 billion. The FES/AE Supply facility was amended to decrease the lending banks' commitments by $1 billion to a total of $1.5 billion. The lending banks' commitments under the FET facility remain at $1 billion and that facility was amended to increase ATSI's individual borrower sublimit to $500 million from $100 million and TrAIL's individual borrower sublimit to $400 million from $200 million. FirstEnergy expensed approximately $5 million (FES - $3 million) of unamortized debt expense as a result of the amendments, included in Loss on Debt Redemptions in the Consolidated Statement of Income (Loss) in the first six months of 2014.
On March 31, 2014, FE executed, and fully utilized, a new $1 billion variable rate term loan credit agreement with a maturity date of March 31, 2019. The initial borrowing under the term loan, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. The proceeds from this term loan reduced borrowings under the FE Facility.
During the first quarter of 2014, FG and NG remarketed approximately $235 million and $182 million, respectively, of PCRBs, previously held by the companies. The NG PCRBs were remarketed with a fixed interest rate of 4% per annum and a mandatory put date of June 3, 2019 and the FG PCRBs were remarketed with a fixed interest rate of 3.75% per annum and a mandatory put date of December 3, 2018.
In addition, in the first quarter of 2014, FG and NG repurchased approximately $197 million and $16 million, respectively, of PCRBs, which were subject to a mandatory tender. The PCRBs are being held either for remarketing subject to future market and other conditions or have been remarketed in the second quarter as described below. Additionally, FG retired $50 million of PCRB's at maturity.
On April 1, 2014, PN and ME repurchased approximately $45 million and $29 million of PCRBs, respectively, which were subject to a mandatory put on such date. The companies are currently holding the PCRBs for remarketing subject to future market and other conditions. Additionally, on April 1, 2014, ME retired $150 million of long-term debt at maturity.
On May 19, 2014, FET issued $600 million of 4.35% senior notes due 2025 and $400 million of 5.45% senior notes due 2044. Proceeds received from the issuance of the senior notes were used to (i) repay borrowings under its revolving credit facility and the FirstEnergy unregulated company money pool; (ii) fund a capital contribution to ATSI; and (iii) for working capital needs and other general business purposes.
On June 11, 2014, ME and PN issued $250 million of 4% senior notes due 2025 and $200 million of 4.15% senior notes due 2025, respectively. Proceeds received from the issuance of the senior notes were used to repay ME and PN's borrowings under the FirstEnergy revolving credit facility and the FirstEnergy regulated utility money pool.
In addition, in the second quarter of 2014, FG and NG remarketed approximately $57 million and $164 million, respectively, of PCRBs previously held by the companies. The bonds were remarketed with a fixed interest rate of 3.50% per annum with a mandatory put date of June 1, 2020.

Derivative_Instruments

Derivative Instruments	6 Months Ended
	Jun. 30, 2014
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 (losses) included in AOCI associated with instruments previously designated to be in a cash flow hedging relationship totaled $(3) million and $2 million as of June 30, 2014 and December 31, 2013, respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $7 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. No forward starting swap agreements accounted for as a cash flow hedge were outstanding as of June 30, 2014 or December 31, 2013. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $54 million and $59 million as of June 30, 2014 and December 31, 2013, respectively. Based on current estimates, approximately $9 million will be amortized to interest expense during the next twelve months.
	As of June 30, 2014 and December 31, 2013, no commodity or interest rate derivatives were designated as cash flow hedges.
	Refer to Note 4, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the three and six months ended June 30, 2014 and 2013.
	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. As of June 30, 2014 and December 31, 2013, no fixed-for-floating interest rate swap agreements were outstanding.
	Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $38 million and $44 million as of June 30, 2014 and December 31, 2013, 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 $3 million and $5 million during the three months ended June 30, 2014 and 2013, respectively, and $6 million and $11 million during the six months ended June 30, 2014 and 2013, respectively.
	As of June 30, 2014 and December 31, 2013, 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. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s coal transportation contracts. Derivative instruments are not used in quantities greater than forecasted needs.
	As of June 30, 2014, FirstEnergy’s net asset position under commodity derivative contracts was $41 million, which related to FES positions. Under these commodity derivative contracts, FES posted $62 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $41 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 June 30, 2014, an adverse change of 10% in commodity prices would decrease net income by approximately $24 million during the next twelve months.
	Interest Rate Swaps
	During the three months ended June 30, 2014, FE executed notional $500 million of forward-starting, pay-fixed/receive-float, interest rate swaps with an effective date of December 31, 2015 and a weighted average 10-year fixed rate of 3.21%. On June 10, 2014, the interest rate swaps were terminated resulting in a realized gain and cash proceeds of approximately $6 million. The realized gain is recorded as a reduction to interest expense in the Consolidated Statements of Income (Loss).
	NUGs
	As of June 30, 2014, FirstEnergy's net liability position under NUG contracts was $169 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 were financially settled agreements that allowed 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 were 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 was 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 and briefing by the parties was completed by March 5, 2014. Consistent with the provisions of the LCAPP contracts, the U.S. District Court's ruling was 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 June 30, 2014, FirstEnergy's and FES's net asset position under FTRs was $21 million and $10 million, respectively, 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
		June 30,				December 31,					June 30,				December 31,
		2014				2013					2014				2013
		(In millions)									(In millions)
	Current Assets - Derivatives									Current Liabilities - Derivatives
	Commodity Contracts	$	213			$	162			Commodity Contracts	$	(186	)		$	(102	)
	FTRs	36				4				FTRs	(15		)		(9		)
		249				166					(201		)		(111		)
										Noncurrent Liabilities - Adverse Power Contract Liability
	Deferred Charges and Other Assets - Other									NUGs	(171		)		(222		)
	Commodity Contracts	56				53				Noncurrent Liabilities - Other
	FTRs	1				—				Commodity Contracts	(42		)		(11		)
	NUGs	2				20				FTRs	(1		)		(3		)
		59				73					(214		)		(236		)
	Derivative Assets	$	308			$	239			Derivative Liabilities	$	(415	)		$	(347	)
	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
	June 30, 2014		Fair Value				Derivative Instruments				Cash Collateral (Received)/Pledged				Net Fair Value
			(In millions)
	Derivative Assets
	Commodity contracts		$	269			$	(183	)		$	—			$	86
	FTRs		37				(16		)		—				21
	NUG contracts		2				(1		)		—				1
			$	308			$	(200	)		$	—			$	108
	Derivative Liabilities
	Commodity contracts		$	(228	)		$	183			$	13			$	(32	)
	FTRs		(16		)		16				—				—
	NUG contracts		(171		)		1				—				(170		)
			$	(415	)		$	200			$	13			$	(202	)
							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	)
The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of June 30, 2014:
	Purchases			Sales			Net			Units
	(In millions)
Power Contracts	33			35			(2	)		MWH
FTRs	82			—			82			MWH
NUGs	7			—			7			MWH
Natural Gas	60			3			57			mmBTU
The effect of derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income (Loss) during the three months ended June 30, 2014 and 2013, are summarized in the following tables:
	Three Months Ended June 30
	Commodity Contracts				FTRs				Interest Rate Swaps				Total
	(In millions)
2014
Unrealized Gain (Loss) Recognized in:
Other Operating Expense (1)	$	(70	)		$	13			$	—			$	(57	)
Realized Gain (Loss) Reclassified to:
Revenues (2)	$	2			$	(1	)		$	—			$	1
Purchased Power Expense (3)	22				—				—				22
Other Operating Expense (4)	—				(10		)		—				(10		)
Fuel Expense	2				—				—				2
Interest Expense	—				—				6				6
(1) Includes ($70) million for commodity contracts and $13 million for FTRs associated with FES.
(2) Represents losses on structured financial contracts. Includes $2 million for commodity contracts and ($1) million for FTRs associated with FES.
(3) Realized losses on financially settled wholesale sales contracts of $16 million resulting from higher market prices were netted in purchased power. Includes $22 million for commodity contracts associated with FES.
(4) Includes ($9) million for FTRs associated with FES.
	Three Months Ended June 30
	Commodity Contracts				FTRs				Interest Rate Swaps				Total
	(In millions)
2013
Unrealized Loss Recognized in:
Other Operating Expense (5)	$	(10	)		$	(1	)		$	—			$	(11	)
Realized Gain (Loss) Reclassified to:
Revenues (6)	$	6			$	5			$	—			$	11
Purchased Power Expense (7)	(2		)		—				—				(2		)
Other Operating Expense (8)	—				(9		)		—				(9		)
Fuel Expense	2				—				—				2
(5) Includes ($10) million for commodity contracts and ($1) million for FTRs associated with FES.
(6) Includes $5 million for commodity contracts and $5 million for FTRs associated with FES.
(7) Includes ($2) million for commodity contracts associated with FES.
(8) Includes ($8) million for FTRs associated with FES.
	Six Months Ended June 30
	Commodity				FTRs				Interest Rate Swaps				Total
	Contracts
	(In millions)
2014
Unrealized Gain (Loss) Recognized in:
Other Operating Expense(1)	$	(58	)		$	18			$	—			$	(40	)
Realized Gain (Loss) Reclassified to:
Revenues(2)	$	(11	)		$	51			$	—			$	40
Purchased Power Expense(3)	458				—				—				458
Other Operating Expense(4)	—				(17		)		—				(17		)
Fuel Expense	11				—				—				11
Interest Expense	—				—				6				6
(1) Includes ($58) million for commodity contracts and $18 million for FTRs associated with FES.
(2) Represents losses on structured financial contracts. Includes ($11) million for commodity contracts and $50 million for FTRs associated with FES.
(3) Realized losses on financially settled wholesale sales contracts of $337 million resulting from higher market prices were netted in purchased power. Includes $458 million for commodity contracts associated with FES.
(4) Includes ($16) million for FTRs associated with FES.
	Six Months Ended June 30
	Commodity				FTRs				Interest Rate Swaps				Total
	Contracts
	(In millions)
2013
Unrealized Loss Recognized in:
Other Operating Expense(5)	$	(15	)		$	(2	)		$	—			$	(17	)
Realized Gain (Loss) Reclassified to:
Revenues(6)	$	16			$	12			$	—			$	28
Purchased Power Expense(7)	(13		)		—				—				(13		)
Other Operating Expense(8)	—				(18		)		—				(18		)
Fuel Expense	2				—				—				2
(5) Includes ($15) million for commodity contracts and ($2) million for FTRs associated with FES.
(6) Includes $15 million for commodity contracts and $11 million for FTRs associated with FES.
(7) Includes ($13) million for commodity contracts associated with FES.
(8) Includes ($16) million for FTRs associated with FES.
The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during the three months and six months ended June 30, 2014 and 2013, are summarized in the following tables:
		Three Months Ended June 30
Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				LCAPP(1)				Regulated FTRs				Total
		(In millions)
2014
Unrealized Gain (Loss) on Derivative Instrument		$	(2	)		$	—			$	11			$	9
Realized Gain (Loss) on Derivative Instrument		18				—				(4		)		14
2013
Unrealized Loss on Derivative Instrument		$	(38	)		$	(12	)		$	—			$	(50	)
Realized Gain on Derivative Instrument		20				—				1				21
		Six Months Ended June 30
Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				LCAPP(1)				Regulated FTRs				Total
		(In millions)
2014
Unrealized Gain on Derivative Instrument		$	25			$	—			$	15			$	40
Realized Gain (Loss) on Derivative Instrument		8				—				(5		)		3
2013
Unrealized Loss on Derivative Instrument		$	(20	)		$	(14	)		$	—			$	(34	)
Realized Gain on Derivative Instrument		43				—				—				43
(1)	During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.
The following tables provide a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or credit to) customers during the three months and six months ended June 30, 2014 and 2013:
		Three Months Ended June 30
Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				LCAPP(1)				Regulated FTRs				Total
		(In millions)
Outstanding net liability as of April 1, 2014		$	(185	)		$	—			$	3			$	(182	)
Additions/Change in value of existing contracts		(2		)		—				11				9
Settled contracts		18				—				(4		)		14
Outstanding net liability as of June 30, 2014		$	(169	)		$	—			$	10			$	(159	)
Outstanding net liability as of April 1, 2013		$	(213	)		$	(146	)		$	(1	)		$	(360	)
Additions/Change in value of existing contracts		(38		)		(12		)		—				(50		)
Settled contracts		20				—				1				21
Outstanding net liability as of June 30, 2013		$	(231	)		$	(158	)		$	—			$	(389	)
		Six Months Ended June 30
Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				LCAPP(1)				Regulated FTRs				Total
		(In millions)
Outstanding net liability as of January 1, 2014		$	(202	)		$	—			$	—			$	(202	)
Additions/Change in value of existing contracts		25				—				15				40
Settled contracts		8				—				(5		)		3
Outstanding net liability as of June 30, 2014		$	(169	)		$	—			$	10			$	(159	)
Outstanding net liability as of January 1, 2013		$	(254	)		$	(144	)		$	—			$	(398	)
Additions/Change in value of existing contracts		(20		)		(14		)		—				(34		)
Settled contracts		43				—				—				43
Outstanding net liability as of June 30, 2013		$	(231	)		$	(158	)		$	—			$	(389	)
(1)	During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.

Regulatory_Matters

Regulatory Matters	6 Months Ended
	Jun. 30, 2014
Regulated Operations [Abstract]	'
REGULATORY MATTERS	'
	REGULATORY MATTERS
	STATE REGULATION
	Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.
	As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates. In addition, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility.
	MARYLAND
	PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third party monitor. Although settlements with respect to 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 adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption by 10% and reduce electricity demand by 15%, in each case by 2015. 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. PE filed its second annual report on March 27, 2014. The MDPSC held a hearing on the utility reports on July 10, 2014.
	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. On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting. The Staff also recommended the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff. In addition, the Staff proposed that the utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC has scheduled a hearing for September 15-18, 2014, to consider certain of these matters.
	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.
	In a 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. The record in the case was closed as of June 30, 2014, and the matter is pending before the ALJ. On July 24, 2014, Rate Counsel filed a motion with the NJBPU requesting that effective August 1, 2014, JCP&L's existing rates be continued on a provisional basis until the NJBPU's final order in the base rate case and subject to refund. JCP&L filed a brief opposing the motion on August 4, 2014.
	On January 23, 2013, the NJBPU opened a generic proceeding to review its policies with respect to the use of a CTA in base rate cases. The NJBPU and its Staff solicited, and were provided, input from interested stakeholders, including utilities and the Rate Counsel. On June 18, 2014, the NJBPU Staff proposed to amend current CTA policy by: 1) calculating savings using a 5 year look back from the beginning of the test year; 2) allocating savings with 75% retained by the company and 25% allocated to rate payers; and 3) excluding transmission assets of electric distribution companies in the savings calculation. Written comments on the Staff proposal are due August 18, 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 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) in the fourth quarter of 2013. By its Order of March 19, 2014, the NJBPU approved the Stipulation of Settlement and on March 25, 2014, transmitted a copy of that Order to the Office of Administrative Law so that “actual recovery of the 2011 costs can be determined in relation to the pending base rate case.” 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. As of June 6, 2014, JCP&L has completed the required compliance filings and continues to implement the required measures directed by the above NJBPU's orders.
	OHIO
	The Ohio Companies primarily operate under their ESP 3 plan which expires on May 31, 2016. The material terms of ESP 3 include:
	•	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 prior ESP;
	•	A 6% generation rate discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies);
	•	Continuing to provide power to non-shopping customers at a market-based price set through an auction process;
	•	Continuing Rider DCR that allows continued investment in the distribution system for the benefit of customers;
	•	Continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million, subject to the outcome of certain PJM proceedings;
	•	Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility customers who do not switch to a competitive generation supplier; and
	•	Extending the recovery period for costs associated with purchasing RECs mandated by SB221 through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the entire ESP period.
	Notices of appeal 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.
	The Ohio Companies filed an application with the PUCO on August 4, 2014 seeking approval of their ESP IV entitled "Powering Ohio's Progress". The Ohio Companies have requested a decision by the PUCO by April 8, 2015. The material terms of the proposed plan include:
	•	Continuing a base distribution rate freeze through May 31, 2019;
	•	Providing economic development and assistance to low-income customers for the three-year plan period;
	•	An Economic Stability Program providing for a retail rate stability rider to flow through charges or credits representing the net result of the costs paid to FES through a proposed 15-year purchase power agreement for the output of Sammis, Davis-Besse and FES’ share of OVEC against the revenues received from selling the output into the PJM markets over the same period;
	•	Continuing to provide power to non-shopping customers at a market-based price set through an auction process;
	•	Continuing Rider DCR with increased revenue caps of approximately $30 million per year that allows continued investment supporting the distribution system for the benefit of customers;
	•	A commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided by customers for certain types of products totals $360 million, including appropriately such costs from MISO along with such costs from PJM, subject to the outcome of certain PJM proceedings; and
	•	General updates to electric service regulations and tariffs to reflect regulatory orders, administrative rule changes, and current practices.
	Under R.C. 4928.66 (codification of SB221), the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of approximately 1,200 GWHs in 2012 (an increase of 408,000 MWHs over 2011 levels), 1,705 GWHs in 2013, and 2,237 GWHs in 2014, 2015, and 2016, if an amended plan is filed as contemplated by SB310. The Ohio Companies were also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2014, and retain the 2014 level for 2015 and 2016 if an amended plan is filed as contemplated by SB310, and then increase the benchmark by an additional 0.75% thereafter through 2020. 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. On May 15, 2014, the Ohio Companies filed their 2013 Annual Portfolio Status Report in which they indicated compliance with 2013 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. 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. While briefing has been completed, the matter has not been scheduled for oral argument.
	R.C. 4928.64 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. 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 ELPC also filed appeals of the PUCO's order. The Ohio Companies filed their merit brief with the Supreme Court of Ohio on March 6, 2014. On April 15, 2014, the Supreme Court of Ohio stayed the briefing schedule pending the court's resolution of the Ohio Companies' motion to seal certain confidential portions of the appendix and supplement to their merit brief. On May 6, 2014, the PUCO issued an Entry extending the confidential treatment to February 13, 2015, of all materials and information previously granted confidential treatment.
	The Ohio Companies conducted an RFP in 2013 to cover their all-state SREC and their in-state and all-state REC compliance obligations. On April 15, 2014, the Ohio Companies reported that they met all of their annual renewable energy resource requirements for reporting year 2013.
	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. The PUCO issued its Order in this matter on March 26, 2014, which included a wide range of issues such as, maintaining SSO service in its current form, requiring corporate separation audits of all EDUs, establishing a market development working group, and ordering changes to the bill format. The Ohio Companies filed their Application for Rehearing on April 25, 2014. The Ohio Companies filed their memorandum contra applications for rehearing of other stakeholders on May 5, 2014. The PUCO issued its Entry on Rehearing on May 21, 2014, to, among other things: 1) calculate the price to compare based on the current month's charges; and 2) allow EDUs to file for deferral authority when changing bill format.
	On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges.
	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. The Pennsylvania Companies reached a settlement with all parties on all issues raised in the case with the exception of the treatment of NITS charges. On May 6, 2014, the ALJ issued a Recommended Decision recommending adoption of the settlement without modification and the denial of several parties’ request for non-bypassable treatment of NITS charges. On July 24, 2014, the PPUC unanimously approved the settlement, but voted to deny the proposal to recover NITS on a non-bypassable basis.
	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 decision, FirstEnergy recorded a regulatory asset impairment charge of approximately $254 million (pre-tax) in the quarter ended September 30, 2013. 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. Oral argument was held on April 8, 2014, and, at the end of the argument, the Third Circuit directed ME and PN, and the PPUC, each to submit a brief on April 16, 2014 on the question of whether it is possible to waive the preemptive effect of FERC’s classification of line loss charges as transmission charges. On April 16, 2014, ME and PN, the PPUC, and the Pennsylvania Industrials each submitted briefs on the Third Circuit's questions.
	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 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 2013 statutory requirements. On March 20, 2014, the PPUC issued an Order initially determining that ME, PN and Penn achieved the 2011 and 2013 statutory energy efficiency benchmarks. The PPUC also initially determined that WP is not in compliance with the 2011 statutory energy efficiency benchmarks but is in compliance with the 2013 energy efficiency benchmarks. As such, the PPUC, with regards to WP’s compliance with the 2011 statutory benchmarks, referred the matter to the PPUC Bureau of Investigation and Enforcement for the initiation of an appropriate proceeding no later than May 30, 2014 to investigate whether WP is subject to statutory penalties. The PPUC also ordered that the initial determination will be deemed final unless any petitions challenging its initial determination are filed within 20 days of the Order. On April 9, 2014, WP filed its petition challenging the PPUC’s initial determination arguing, among other things, that the May 2011 target was not mandatory and WP is in compliance because it achieved its May 2013 targets. On April 21, 2014, WP filed an appeal with the Commonwealth Court of Pennsylvania in which it challenged the PPUC's initial finding of a violation of Act 129 on due process grounds. On that same day, the Bureau of Investigation and Enforcement, consistent with the PPUC's March 20, 2014 Order, initiated a proceeding by filing a Complaint against WP in which it alleges that WP violated Act 129 and recommended a penalty in the amount of $11.4 million. A prehearing conference was held on May 9, 2014 at which time the party requested, and the ALJ agreed, to stay the PPUC proceedings while the parties attempt to settle the matter. On July 30, 2014, a Joint Petition for settlement was filed, which would resolve all issues in the pending proceedings, and includes WP making a payment of $1.3 million. The settlement is subject to review and approval of the PPUC. WP's brief in the Commonwealth Court appeal proceeding is due on September 15, 2014.
	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 requested 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 OCA. 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 OCA took exception to one issue and both parties filed replies to exceptions on December 12, 2013. In its March 6, 2014 Opinion and Order, the PPUC rejected the OCA's exception and many of the ALJ's recommendations, including the recommendation to hire an independent consultant and the disallowance of $5.1 million of customer information system costs, and affirmed the ALJ's recommendation on the accounting treatment for legacy meter costs. The PPUC also directed the Pennsylvania Companies to file an amendment to the Deployment Plan within thirty days of the Order with sufficient supporting documentation for proper evaluation if the Pennsylvania Companies intend to pursue an accelerated deployment schedule, and the PPUC indicated that it would establish an expedited procedural schedule and rule on the filing within 90 days of the March 6, 2014 Order. The Pennsylvania Companies filed an amended Deployment Plan on March 19, 2014, to which, the OCA filed exceptions arguing that the amended plan failed to: 1) list certain potential cost saving categories that are to be considered by the Pennsylvania Companies; and 2) follow proper procedure. On April 7, 2014, the Pennsylvania Companies filed a reply to OCA’s exceptions explaining why they should be rejected. On June 25, 2014, the PPUC entered its Opinion and Order to approve the revised plan. The Pennsylvania Companies commenced the implementation phase of the deployment plan in July 2014.
	In the PPUC Order approving the FirstEnergy and AE 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.
	On August 4, 2014, the Pennsylvania Companies each filed tariffs with the PPUC proposing general rate increases associated with their distribution operations. The filings request approval to increase operating revenues by approximately $151.9 million at ME, $119.8 million at PN, $28.5 million at Penn, and $115.5 million at WP based upon fully projected future test years for the twelve months ending April 30, 2016 at each of the Pennsylvania Companies. The filings also propose several new cost recovery riders as well as revisions to certain existing cost recovery riders. An order on the proposed increases is expected in April 2015.
	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. The WVPSC issued an order on April 14, 2014 approving the plan, stating rate recovery will be addressed in the base rate case filed on April 30, 2014. In the interim, MP and PE are authorized to defer all costs associated with the plan.
	On April 30, 2014, MP and PE filed a rate case requesting a base rate increase of approximately $96 million, or 9.3%, based on an historic 2013 test year. The filing also included a surcharge to recover costs of MP's and PE's vegetation management program in the amount of approximately $48 million. On June 13, 2014, MP and PE amended their filing to add an additional $7.5 million of additional revenues to reimburse their expected costs of implementing monthly meter reading for residential and small commercial customers. The proposed total rate increase request, including the cost of the vegetation management program and monthly meter reading, is approximately $152 million, or 14.7%. MP and PE anticipate a decision from the WVPSC in February 2015.
	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 a petition for review with the U.S. Court of Appeals for the Seventh Circuit, and the case subsequently was consolidated with several other cases before that court. On June 25, 2014, the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from the new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines by means of a postage-stamp rate. The court also found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from them, and not based on load ratio share in PJM as a whole. The court again remanded the case back to FERC for further proceedings to implement its findings and ruling.
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 again accepted the hybrid method. Certain parties sought rehearing of parts of FERC's March 22, 2013 order. 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 the SERTP region participants' 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 regional transmission planning and cost allocation 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. On May 15, 2014, FERC issued an order denying rehearing of its March 22, 2013 order and accepting in part revisions to the PJM Operating Agreement and OATT proposed by PJM and the PJM Transmission Owners, including FirstEnergy. FERC also directed PJM and the PJM Transmission Owners to submit a further compliance filing by July 15, 2014. On May 27, 2014, FirstEnergy filed a petition for review of FERC's March 22, 2013 and May 15, 2014 orders with the U.S. Court of Appeals for the D.C. Circuit. The appeal is being held in abeyance pending the resolution of certain other appeals. Other parties' requests for rehearing of certain aspects of the May 15, 2014 order, other appeals of the March 22, 2013 and May 15, 2014 orders, and PJM's and the PJM Transmission Owners' compliance filings pursuant to the May 15, 2014 order are pending.
Numerous parties, including ATSI, FES, TrAIL, OE, CEI, TE, Penn, JCP&L, ME, MP, PN, WP and PE, sought judicial review of Order No. 1000 before the U.S. Court of Appeals for the D.C. Circuit. Briefing is complete and oral argument was held on 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 for 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 of 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 on 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 addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM approved before ATSI joined 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. On July 18, 2014, the court denied ATSI’s petition for review, finding that FERC properly determined that the ATSI zone is responsible for an allocation of the “legacy RTEP” project costs and affirming FERC’s orders. However, the amount to be paid is pending before FERC as a result of the June 25, 2014 order from the U.S. Court of Appeals for the Seventh Circuit that is described above in the PJM Transmission Rates section. Specifically, the Seventh Circuit found that eastern PJM utilities are the primary beneficiaries of certain RTEP projects, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from them, and not based on load ratio share in PJM as a whole. The Seventh Circuit remanded the case back to FERC for further proceedings to develop a cost-allocation methodology consistent with its findings and ruling.
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% for 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. PATH, 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 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.
On March 20, 2014, the settlement judge declared an impasse in efforts to achieve settlement. On March 24, 2014, the Chief ALJ terminated settlement judge procedures and appointed an ALJ to preside over the hearing phase of the case. The hearing is scheduled to commence on January 13, 2015. The issues set for hearing include the prudence of the costs, the base return on equity and the period of recovery. Depending on the outcome of the hearing, PATH-Allegheny and PATH-WV may be required to refund certain amounts that have been collected under their formula rate.
MISO Capacity Portability
On June 11, 2012, in response to certain arguments advanced by MISO, 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. FirstEnergy and other parties have 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 2010, FES and AE Supply have lost more than $94 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 re-filed 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, FESC, on behalf of FES and AE Supply, filed a request for rehearing of FERC's order. That request for rehearing, and all subsequent filings in the docket, are pending before FERC. The PJM stakeholders have recently begun discussing the problem of FTR underfunding again.
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 four categories: (i) DR; (ii) imports; (iii) modeling of transmission upgrades in calculating geographic clearing prices; and (iv) arbitrage/capacity replacement. The purpose of PJM’s tariff amendments is to ensure that resources that clear in the RPM auctions are available as physical resources in the delivery year and that the rules implement comparable obligations for different types of resources. In each of the relevant 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 largely approved the tariff amendments as proposed by PJM regarding DR, imports, and transmission upgrade modeling. Compliance filings pursuant to and requests for rehearing of certain of these orders are pending before FERC. On May 9, 2014, FERC rejected the arbitrage/capacity replacement tariff amendments and ordered a technical conference to further examine the issues. The technical conference has not yet been scheduled and requests for rehearing of the May 9, 2014 order are pending before FERC.
PJM RPM Auctions - Calculation of Unit-Specific Offer Caps
The PJM RPM capacity tariff describes the rules for calculating the “offer cap” for each unit that offers into the RPM auctions. In summary, the offer cap is calculated by identifying certain going-forward costs, including the going-forward capital requirements, for a given unit, and then subtracting the projected energy and ancillary services revenues, net of marginal costs, from the going-forward costs. The remainder becomes the offer cap. FES learned that the PJM Market Monitor’s practice for calculating the forecast energy and ancillary services revenues has been to use the lower of the unit’s economic or cost-based offers into the PJM energy market. The Market Monitor engages in this practice based on his interpretation of certain provisions of the PJM capacity tariff. However, review of the relevant tariff language suggests that only the cost-based offer data should be used. FES determined that the Market Monitor’s use of the lower of cost-based or economic offer data has the effect of suppressing the offer cap, which can distort the price signal that is intended to come out of the RPM auction process. On April 7, 2014, FES submitted a Petition for Declaratory Order to FERC, asking for an interpretation of the relevant provisions of the PJM capacity tariff. Specifically, FES identified the difference of opinion between FES and PJM and the Market Monitor regarding interpretation of the relevant provision. FES asked FERC to rule on the question of whether the tariff language permits the Market Monitor's use of the lower of cost-based or economic offer data or requires use of the cost-based offer data by May 9, 2014. On April 18, 2014, the Market Monitor and other parties filed protests to FES's petition, arguing that the PJM capacity tariff allows the Market Monitor to use market-based energy offers instead of cost-based energy offers in calculating RPM auction offer caps and asking FERC to delay action on the petition until after the May 2014 BRA. FES' petition, the protest, and related filings are pending before FERC. The timing of FERC action and the outcome of this proceeding cannot be predicted at this time.
PJM RPM Auctions - Complaint Regarding 2014 PJM BRA
On May 23, 2014, a divided three-judge panel of the U.S. Court of Appeals for the D.C. Circuit issued an opinion vacating FERC Order No. 745, which required that, under certain parameters, DR participating in organized wholesale energy markets be compensated at LMP, just as if DR were a traditional energy resource. The majority concluded that DR is a retail service, and therefore falls under state, and not federal, jurisdiction, and that FERC therefore lacked jurisdiction to regulate DR, such as via the PJM tariffs and programs. The majority also found that even if FERC had jurisdiction over DR, Order No. 745 would be arbitrary and capricious because, under its requirements, DR was receiving a double payment (LMP plus the savings of foregone energy purchases). On July 7, 2014, FERC and other parties requested that the U.S. Court of Appeals for the D.C. Circuit grant rehearing en banc, which is a procedural path to ask the full U.S. Court of Appeals for the D.C. Circuit to reconsider the panel's decision. On July 11, 2014, FERC clarified that it is petitioning for rehearing en banc solely regarding the issue of jurisdiction, and not any other issue, including compensation and cost allocation. On August 4, 2014, and acting pursuant to a court order, the original trade group petitioners and Old Dominion Electric Cooperative filed a joint response to FERC's petition for rehearing en banc. On May 23, 2014, FESC, on behalf of FE entities with market-based rate authority, filed a complaint asking FERC to direct PJM to remove all portions of the PJM OATT, which allows or requires PJM to include DR in the PJM capacity market, and to invalidate the results of the May 2014 RPM capacity auction on the grounds that the U.S. Court of Appeals for the D.C. Circuit’s May 23, 2014 decision required removal of DR from the wholesale capacity markets. In a subsequent pleading, FESC stated its intent to file an amended complaint. FESC expects to file the amended complaint in late summer 2014. The timing of FERC action and the outcome of this proceeding cannot be predicted at this time.
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	6 Months Ended
	Jun. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
COMMITMENTS, GUARANTEES AND CONTINGENCIES	'
	COMMITMENTS, GUARANTEES AND CONTINGENCIES
	GUARANTEES AND OTHER ASSURANCES
	FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party.
	As of June 30, 2014, outstanding guarantees and other assurances aggregated approximately $4.0 billion, consisting of parental guarantees ($717 million), subsidiaries' guarantees ($2,460 million) and other guarantees ($855 million).
	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 FirstEnergy and its subsidiaries have margining provisions that require posting of collateral. Based on the Competitive Energy Segments power portfolio exposures as of June 30, 2014, FES has posted collateral of $274 million and AE Supply has posted collateral of $4 million. The Regulated Distribution segment has posted collateral of $6 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 as of June 30, 2014:
	Collateral Provisions	FES		AE Supply		Utilities		Total
		(In millions)
	Split Rating (One rating agency's rating below investment grade)	$	517	$	6	$	53	$	576
	BB+/Ba1 Credit Ratings	$	560	$	6	$	53	$	619
	Full impact of credit contingent contractual obligations	$	825	$	71	$	89	$	985
	Excluded from the preceding chart is the potential collateral obligations due to affiliate transactions between the Regulated Distribution Segment and Competitive Energy Services Segment. As of June 30, 2014, neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES would be required to post $105 million.
	OTHER COMMITMENTS AND CONTINGENCIES
	FE is a guarantor under a syndicated three-year senior secured term loan facility dated October 18, 2011, as amended, that matures 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 FE, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, have also provided their joint and several guarantees of the obligations of Global Holding under the new facility.
	In connection with the facility, 69.99% of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective 33-1/3% membership interests in Global Holding, are pledged to the lenders as collateral.
	FE, FEV and the other two co-owners of Global Holding, Pinesdale LLC, a Gunvor Group, Ltd. subsidiary, and WMB Marketing Ventures, LLC, have agreed, most recently as of August 14, 2013, to use their best efforts to refinance the facility no later than July 20, 2015, on a non-recourse basis so that FE's guaranty can be terminated and/or released. If that refinancing does not occur, FE may require each co-owner to lend to Global Holding, on a pro rata basis, funds sufficient to prepay the facility in full. In lieu of providing such funding, the co-owners, at FE's option, may provide their several guaranties of Global Holding's obligations under the facility. Since January 1, 2013, FE has received a fee for providing its guaranty. The fee is payable semiannually, and accrues at a rate of 5% per annum on the average daily outstanding aggregate commitments under the facility for each 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 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. FirstEnergy 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, MP, PE and WP in the U.S. District Court for the Western District of Pennsylvania alleging, among other things, that AE 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, MP, PE and WP finding they had not violated the CAA or the Pennsylvania Air Pollution Control Act. On March 10, 2014, New York, Connecticut, and Maryland filed an appeal with the U.S. Court of Appeals for the Third Circuit. 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 April 29, 2014 the U.S. Supreme Court reversed the D.C Circuit decision vacating CSAPR and generally upheld the EPA's authority under the CAA to establish the regulatory structure underpinning CSAPR. Depending on the outcome of further proceedings in this matter and how the EPA and the states implement the final rules, 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 was 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. On April 15, 2014, MATS was upheld by the U.S. Court of Appeals for the D.C. Circuit, however, the Court refused to decide FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers due to a January 2013 petition for reconsideration still pending but not addressed by EPA. On July 14, 2014, various entities filed a petition seeking further review by the U.S. Supreme Court. Depending on the outcome of further appeals, if any, and how the MATS are ultimately implemented, FirstEnergy's total cost of compliance with MATS is currently estimated to be approximately $370 million (Competitive Energy Services segment of $178 million and Regulated Distribution segment of $192 million), reduced from the previous estimate of $465 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. FG intends to operate the plants through April 2015, subject to market conditions. 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 agreed to pay liquidated damages for delivery shortfalls for 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. If that were to occur, FE and FES are unable to estimate the loss or range of loss.
	On July 1, 2014, FES terminated a long-term fuel supply agreement. In connection with this termination, FES recognized a pre-tax charge of $67 million in the second quarter of 2014.
	Climate Change
	There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies to reduce GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation. 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 goals to: (1) cut carbon pollution in America 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. GHG emissions have already been reduced by 10% between 2005 and 2012 according to an April, 2014 EPA Report. Due to plant deactivations and increased efficiencies, FirstEnergy anticipates its CO2 emissions will be reduced 25% below 2005 levels by 2015, exceeding the President’s Climate Action Plan goals both in terms of timing and reduction levels.
	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 electric generating units. On September 20, 2013, the EPA proposed a new source performance standard, which would not apply to any existing, modified, or reconstructed fossil fuel generating units, 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 June 2, 2014, the EPA proposed regulations to reduce CO2 emissions from existing fossil fuel electric generating units that would require each state to develop implementation plans by June 30, 2016, to meet EPA’s state specific emission rate goals. EPA’s proposal allows states to request a 1-year extension for single-state implementation plans (June 30, 2017) or a 2-year extension for multi-state implementation plans (June 30, 2018). EPA also proposed separate regulations imposing additional CO2 emission limits on modified and reconstructed fossil fuel electric generating units. On October 15, 2013, the U.S. Supreme Court agreed to review a June 2012 U.S. Court of Appeals for the D.C. Circuit 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?" On June 23, 2014, the U.S. Supreme Court decided that CO2 or other greenhouse gas emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by EPA to install greenhouse gas control technologies. Depending on 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. In 1997, the U.S. Senate passed the Byrd-Hagel resolution by a unanimous vote of 95-0. The resolution stated that it is the sense of the Senate that the United States should not be a signatory to any protocol to, or other agreement regarding, the United Nations Framework Convention on Climate Change which would mandate new commitments to limit or reduce GHG emissions, unless the protocol or other agreement also mandates new specific scheduled commitments to limit or reduce GHG emissions for developing country parties within the same compliance period, or would not result in serious harm to the economy of the United States. 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. In November 2013, the U.N. Climate Change Conference in Warsaw, Poland advanced negotiations of a new global agreement to reduce GHG emissions by 2015. 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. On May 19, 2014, the EPA finalized Section 316(b) regulations requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement to a 12% annual average and determine site-specific controls, if any, to reduce entrainment of aquatic life following studies by cooling water intake structures exceeding 125 million gallons per day. 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 cooling water intake channel to divert fish away from the plant's water intake system. Depending on the results of such studies 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 September 30, 2015, 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. On April 21, 2014, PA DEP recommended that the sulfate impairment designation for the Monongahela River be removed in its bi-annual water report. A 45-day public comment period ended on June 10, 2014, and PA DEP must obtain EPA approval to remove the sulfate impairment designation which would eliminate the need to develop a TMDL.
	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 CCRs produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposed two options for additional regulation of CCRs, 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 CCRs. On April 19, 2013, the EPA stated it would "align" its proposed CCR 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 potential 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 required payment of civil penalties of $800,000 to resolve claims under the Solid Waste Management Act. 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 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 ARO for LBR by $163 million in 2013. On April 3, 2014, PA DEP issued a permit requiring FE to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizes FE to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCBs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The Bruce Mansfield Plant is pursuing several options for 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, against the owner and operator of that mine, alleged the LaBelle site is in violation of RCRA and state laws. On July 14, 2014, Citizens Coal Council served FE, FG and NRG with a citizen suit notice alleging violations of RCRA due to beneficial reuse of "coal ash" at the LaBelle Site.
	Lawsuits initially filed on October 10, 2013 and December 5, 2013, are pending against FG involving approximately 61 individuals in the U.S. District Court for the Northern District of West Virginia and approximately 26 individuals (16 of which have settled their claims) 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. FG believes the claims are without merit and intends to vigorously defend itself against the allegations made in the complaints, but, at this time, is 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 CCR 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 June 30, 2014 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 $130 million have been accrued through June 30, 2014. 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 June 30, 2014, FirstEnergy had approximately $2.4 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. By a letter dated July 2, 2014, FENOC submitted a $155 million FES parental guaranty relating to a shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry to the NRC for approval. FE and FES have also entered into a total of $23 million in parental guaranties in support of the decommissioning of the spent fuel storage facilities located at the nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guaranties, as appropriate.
	In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. A 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 GEIC and published a proposed rule on this subject in September of 2013. On July 17, 2014, the NRC rejected a separate request to suspend the licensing decision in the Davis-Besse proceeding to allow for a rulemaking on the environmental impacts of high density spent fuel storage and mitigation alternatives. On July 25, 2014, the NRC ASLB rejected a proposed contention on the Davis-Besse shield building.
	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. These inspections revealed that the cracking condition has propagated a small amount in select areas. FENOC's analysis confirms that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions.
	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 CSA 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. 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 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 claimed their performance was excused by the force majeure clause in the CSA and presented evidence at trial that they could 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 past damages/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 defendants still owed future damages, it remanded the calculation of those damages back to 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 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 a multi-day hearing was held beginning May 13, 2014. A ruling is expected in the fourth quarter of 2014. In a related proceeding before the same court, ICG is appealing a ruling by the court that prohibited their reliance on a price re-opener clause to limit future damages.
	Other Legal Matters
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 9, 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.

Supplemental_Guarantor_Informa

Supplemental Guarantor Information	6 Months Ended
	Jun. 30, 2014
Supplemental Guarantor Information [Abstract]	'
SUPPLEMENTAL GUARANTOR INFORMATION	'
	SUPPLEMENTAL GUARANTOR INFORMATION
	In 2007, FG completed a sale and leaseback transaction for a 93.83% 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 and Comprehensive Income for the three and six months ended June 30, 2014 and 2013, Condensed Consolidating Balance Sheets as of June 30, 2014 and December 31, 2013, and Condensed Consolidating Statements of Cash Flows for the six months ended June 30, 2014 and 2013, for FES (parent and guarantor), FG and NG (non-guarantor) are presented below. These statements are provided as FES fully and unconditionally guarantees outstanding registered securities of FG as well as FG's obligations under the facility lease for the Bruce Mansfield sale and leaseback that underlie outstanding registered pass-through trust certificates. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FG and NG are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.
	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
	(Unaudited)
	For the Three Months Ended June 30, 2014	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	STATEMENTS OF INCOME (LOSS)
	REVENUES	$	1,412		$	505		$	437		$	(902	)	$	1,452
	OPERATING EXPENSES:
	Fuel	—			288			46			—			334
	Purchased power from affiliates	902			—			75			(902		)	75
	Purchased power from non-affiliates	618			—			—			—			618
	Other operating expenses	242			79			135			12			468
	Provision for depreciation	2			30			48			(1		)	79
	General taxes	18			6			5			—			29
	Total operating expenses	1,782			403			309			(891		)	1,603
	OPERATING INCOME (LOSS)	(370		)	102			128			(11		)	(151		)
	OTHER INCOME (EXPENSE):
	Loss on debt redemptions	—			—			—			—			—
	Investment income	2			2			23			(3		)	24
	Miscellaneous income, including net income from equity investees	159			3			—			(158		)	4
	Interest expense — affiliates	(2		)	(2		)	(1		)	3			(2		)
	Interest expense — other	(14		)	(25		)	(13		)	15			(37		)
	Capitalized interest	—			—			8			—			8
	Total other income (expense)	145			(22		)	17			(143		)	(3		)
	INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	(225		)	80			145			(154		)	(154		)
	INCOME TAXES (BENEFITS)	(137		)	23			45			2			(67		)
	INCOME (LOSS) FROM CONTINUING OPERATIONS	(88		)	57			100			(156		)	(87		)
	Discontinued operations (Note 13)	—			—			—			—			—
	NET INCOME (LOSS)	$	(88	)	$	57		$	100		$	(156	)	$	(87	)
	STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
	NET INCOME (LOSS)	$	(88	)	$	57		$	100		$	(156	)	$	(87	)
	OTHER COMPREHENSIVE INCOME (LOSS):
	Pensions and OPEB prior service costs	(5		)	(5		)	—			5			(5		)
	Amortized gain on derivative hedges	(3		)	—			—			—			(3		)
	Change in unrealized gain on available-for-sale securities	25			—			25			(25		)	25
	Other comprehensive income (loss)	17			(5		)	25			(20		)	17
	Income taxes (benefits) on other comprehensive income (loss)	7			(1		)	9			(8		)	7
	Other comprehensive income (loss), net of tax	10			(4		)	16			(12		)	10
	COMPREHENSIVE INCOME (LOSS)	$	(78	)	$	53		$	116		$	(168	)	$	(77	)
	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
	(Unaudited)
	For the Six Months Ended June 30, 2014	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	STATEMENTS OF INCOME (LOSS)
	REVENUES	$	3,209		$	820		$	799		$	(1,547	)	$	3,281
	OPERATING EXPENSES:
	Fuel	—			560			93			—			653
	Purchased power from affiliates	1,547			—			139			(1,547		)	139
	Purchased power from non-affiliates	1,643			4			—			—			1,647
	Other operating expenses	470			141			285			24			920
	Provision for depreciation	4			59			91			(1		)	153
	General taxes	39			17			12			—			68
	Total operating expenses	3,703			781			620			(1,524		)	3,580
	OPERATING INCOME (LOSS)	(494		)	39			179			(23		)	(299		)
	OTHER INCOME (EXPENSE):
	Loss on debt redemptions	(3		)	(1		)	(1		)	—			(5		)
	Investment income	3			3			44			(6		)	44
	Miscellaneous income, including net income from equity investees	262			3			—			(261		)	4
	Interest expense — affiliates	(5		)	(3		)	(2		)	6			(4		)
Interest expense — other	(28		)	(49		)	(26		)	30			(73		)
Capitalized interest	—			1			19			—			20
Total other income (expense)	229			(46		)	34			(231		)	(14		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	(265		)	(7		)	213			(254		)	(313		)
INCOME TAXES (BENEFITS)	(189		)	(8		)	71			3			(123		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	(76		)	1			142			(257		)	(190		)
Discontinued operations (net of income taxes of $70) (Note 13)	—			116			—			—			116
NET INCOME (LOSS)	$	(76	)	$	117		$	142		$	(257	)	$	(74	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(76	)	$	117		$	142		$	(257	)	$	(74	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(10		)	(9		)	—			9			(10		)
Amortized gain on derivative hedges	(5		)	—			—			—			(5		)
Change in unrealized gain on available-for-sale securities	44			—			44			(44		)	44
Other comprehensive income (loss)	29			(9		)	44			(35		)	29
Income taxes (benefits) on other comprehensive income (loss)	11			(3		)	16			(13		)	11
Other comprehensive income (loss), net of tax	18			(6		)	28			(22		)	18
COMPREHENSIVE INCOME (LOSS)	$	(58	)	$	111		$	170		$	(279	)	$	(56	)
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)
For the Three Months Ended June 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME (LOSS)
REVENUES	$	1,425		$	553		$	457		$	(983	)	$	1,452
OPERATING EXPENSES:
Fuel	—			286			46			—			332
Purchased power from affiliates	1,050			—			70			(983		)	137
Purchased power from non-affiliates	524			1			—			—			525
Other operating expenses	175			69			131			12			387
Provision for depreciation	2			32			44			(2		)	76
General taxes	19			8			7			—			34
Total operating expenses	1,770			396			298			(973		)	1,491
OPERATING INCOME (LOSS)	(345		)	157			159			(10		)	(39		)
OTHER INCOME (EXPENSE):
Loss on debt redemption	(32		)	—			—			—			(32		)
Investment income	1			—			(14		)	(5		)	(18		)
Miscellaneous income, including net income from equity investees	171			3			—			(168		)	6
Interest expense — affiliates	(5		)	(1		)	(3		)	4			(5		)
Interest expense — other	(12		)	(27		)	(14		)	14			(39		)
Capitalized interest	1			—			9			—			10
Total other income (expense)	124			(25		)	(22		)	(155		)	(78		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	(221		)	132			137			(165		)	(117		)
INCOME TAXES (BENEFITS)	(150		)	53			52			3			(42		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	(71		)	79			85			(168		)	(75		)
Discontinued operations (net of income taxes of $1) (Note 13)	—			4			—			—			4
NET INCOME (LOSS)	$	(71	)	$	83		$	85		$	(168	)	$	(71	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(71	)	$	83		$	85		$	(168	)	$	(71	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(5		)	—			5			(5		)
Amortized gain on derivative hedges	(1		)	—			—			—			(1		)
Change in unrealized gain on available for sale securities	(8		)	—			(8		)	8			(8		)
Other comprehensive income (loss)	(14		)	(5		)	(8		)	13			(14		)
Income tax benefits on other comprehensive income (loss)	(5		)	(2		)	(4		)	6			(5		)
Other comprehensive income (loss), net of tax	(9		)	(3		)	(4		)	7			(9		)
COMPREHENSIVE INCOME (LOSS)	$	(80	)	$	80		$	81		$	(161	)	$	(80	)
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)
For the Six Months Ended June 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME (LOSS)
REVENUES	$	2,921		$	1,084		$	897		$	(1,926	)	$	2,976
OPERATING EXPENSES:
Fuel	—			533			99			—			632
Purchased power from affiliates	2,063			—			132			(1,926		)	269
Purchased power from non-affiliates	1,029			2			—			—			1,031
Other operating expenses	337			143			262			24			766
Pensions and OPEB mark-to-market adjustments	—			—			—			—			—
Provision for depreciation	3			63			88			(3		)	151
General taxes	39			19			13			—			71
Total operating expenses	3,471			760			594			(1,905		)	2,920
OPERATING INCOME (LOSS)	(550		)	324			303			(21		)	56
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(103		)	—			—			—			(103		)
Investment income	2			—			4			(7		)	(1		)
Miscellaneous income, including net income from equity investees	363			4			—			(359		)	8
Interest expense — affiliates	(7		)	(2		)	(4		)	7			(6		)
Interest expense — other	(37		)	(55		)	(29		)	30			(91		)
Capitalized interest	1			—			18			—			19
Total other income (expense)	219			(53		)	(11		)	(329		)	(174		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	(331		)	271			292			(350		)	(118		)
INCOME TAXES (BENEFITS)	(262		)	104			110			6			(42		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	(69		)	167			182			(356		)	(76		)
Discontinued operations (net of income taxes of $3) Note (13)	—			7			—			—			7
NET INCOME (LOSS)	$	(69	)	$	174		$	182		$	(356	)	$	(69	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(69	)	$	174		$	182		$	(356	)	$	(69	)
OTHER COMPREHENSIVE INCOME:
Pensions and OPEB prior service costs	(11		)	(10		)	—			10			(11		)
Amortized gain on derivative hedges	(2		)	—			—			—			(2		)
Change in unrealized gain on available-for-sale securities	(3		)	—			(3		)	3			(3		)
Other comprehensive loss	(16		)	(10		)	(3		)	13			(16		)
Income tax benefits on other comprehensive loss	(6		)	(4		)	(2		)	6			(6		)
Other comprehensive loss, net of tax	(10		)	(6		)	(1		)	7			(10		)
COMPREHENSIVE INCOME (LOSS)	$	(79	)	$	168		$	181		$	(349	)	$	(79	)
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of June 30, 2014	FES			FG			NG			Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—		$	2		$	—		$	—		$	2
Receivables-
Customers	534			—			—			—			534
Affiliated companies	437			380			350			(692		)	475
Other	70			19			8			—			97
Notes receivable from affiliated companies	421			605			125			(983		)	168
Materials and supplies	71			179			216			—			466
Derivatives	238			—			—			—			238
Collateral	256			—			—			—			256
Prepayments and other	59			66			—			—			125
	2,086			1,251			699			(1,675		)	2,361
PROPERTY, PLANT AND EQUIPMENT:
In service	127			6,156			7,722			(383		)	13,622
Less — Accumulated provision for depreciation	32			2,005			3,121			(190		)	4,968
	95			4,151			4,601			(193		)	8,654
Construction work in progress	6			161			515			—			682
	101			4,312			5,116			(193		)	9,336
INVESTMENTS:
Nuclear plant decommissioning trusts	—			—			1,379			—			1,379
Investment in affiliated companies	6,060			—			—			(6,060		)	—
Other	—			11			—			—			11
	6,060			11			1,379			(6,060		)	1,390
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	184			58			—			(242		)	—
Customer intangibles	86			—			—			—			86
Goodwill	23			—			—			—			23
Property taxes	—			7			12			—			19
Unamortized sale and leaseback costs	—			—			—			215			215
Derivatives	57			—			—			—			57
Other	47			279			1			(215		)	112
	397			344			13			(242		)	512
	$	8,644		$	5,918		$	7,207		$	(8,170	)	$	13,599
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1		$	120		$	193		$	(23	)	$	291
Short-term borrowings-
Affiliated companies	603			379			—			(982		)	—
Other	300			8			—			—			308
Accounts payable-
Affiliated companies	611			222			198			(610		)	421
Other	110			149			—			—			259
Accrued taxes	182			26			19			(129		)	98
Derivatives	200			—			—			—			200
Other	86			53			11			33			183
	2,093			957			421			(1,711		)	1,760
CAPITALIZATION:
Total equity	5,731			2,398			3,662			(6,032		)	5,759
Long-term debt and other long-term obligations	712			2,133			1,049			(1,173		)	2,721
	6,443			4,531			4,711			(7,205		)	8,480
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—			—			—			841			841
Accumulated deferred income taxes	15			—			826			(95		)	746
Asset retirement obligations	—			188			856			—			1,044
Retirement benefits	23			171			—			(1		)	193
Derivatives	43			—			—			—			43
Other	27			71			393			1			492
	108			430			2,075			746			3,359
	$	8,644		$	5,918		$	7,207		$	(8,170	)	$	13,599
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
Collateral	136			—			—			—			136
Prepayments and other	52			50			7			—			109
	2,161			1,033			1,147			(1,825		)	2,516
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	—			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	81			228			18			(155		)	172
	252			374			44			(118		)	552
	$	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 STATEMENTS OF CASH FLOWS
(Unaudited)
For the Six Months Ended June 30, 2014	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(202	)	$	147		$	149		$	(11	)	$	83
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			291			346			—			637
Short-term borrowings, net	—			172			—			(172		)	—
Equity contribution from parent	500			—			—			—			500
Redemptions and Repayments-
Long-term debt	(1		)	(258		)	(416		)	11			(664		)
Short-term borrowings, net	(74		)	—			(151		)	98			(127		)
Other	(1		)	(8		)	(1		)	—			(10		)
Net cash provided from (used for) financing activities	424			197			(222		)	(63		)	336
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(4		)	(74		)	(399		)	—			(477		)
Nuclear fuel	—			—			(57		)	—			(57		)
Proceeds from asset sales	—			307			—			—			307
Sales of investment securities held in trusts	—			—			707			—			707
Purchases of investment securities held in trusts	—			—			(736		)	—			(736		)
Loans to affiliated companies, net	(218		)	(581		)	558			73			(168		)
Other	—			4			—			1			5
Net cash provided from (used for) investing activities	(222		)	(344		)	73			74			(419		)
Net change in cash and cash equivalents	—			—			—			—			—
Cash and cash equivalents at beginning of period	—			2			—			—			2
Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
For the Six Months Ended June 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(687	)	$	390		$	308		$	(11	)	$	—
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	240			112			—			(352		)	—
Equity contribution from parent	1,500			—			—			—			1,500
Redemptions and Repayments-
Long-term debt	(770		)	(352		)	(68		)	11			(1,179		)
Tender premiums	(67		)	—			—			—			(67		)
Other	(2		)	(3		)	—			—			(5		)
Net cash provided from (used for) financing activities	901			(243		)	(68		)	(341		)	249
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(7		)	(163		)	(180		)	—			(350		)
Nuclear fuel	—			—			(50		)	—			(50		)
Proceeds from asset sales	—			19			—			—			19
Sales of investment securities held in trusts	—			—			487			—			487
Purchases of investment securities held in trusts	—			—			(515		)	—			(515		)
Loans to affiliated companies, net	(207		)	(7		)	18			352			156
Other	—			3			—			—			3
Net cash used for investing activities	(214		)	(148		)	(240		)	352			(250		)
Net change in cash and cash equivalents	—			(1		)	—			—			(1		)
Cash and cash equivalents at beginning of period	—			3			—			—			3
Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2

Segment_Information

Segment Information	6 Months Ended
	Jun. 30, 2014
Segment Reporting [Abstract]	'
SEGMENT INFORMATION	'
	SEGMENT INFORMATION
	FirstEnergy continues to have three reportable operating segments - Regulated Distribution, Regulated Transmission and Competitive Energy Services. The external reporting is consistent with the internal financial reporting used by FirstEnergy’s Chief Executive Officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources.
	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 3,790 MWs of generation capacity.
	The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, and certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP) 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. 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 Competitive Energy Services segment is taking action to reduce its exposure to weather-sensitive loads, including maintaining competitive generation in excess of committed sales, eliminating load obligations that do not adequately cover risk premiums, pursuing more certain revenue streams, and modifying its hedging strategy to optimize risk management and market upside opportunities. As part of this, the Competitive Energy Services segment has eliminated future selling efforts in certain sales channels, such as mass market, medium commercial-industrial and select large commercial-industrial, to focus on a selective mix of retail sales channels, wholesale sales that hedge generation more effectively, and maintain a small open position to take advantage of market upside opportunities resulting from volatility as was experienced in the first quarter of 2014. Going forward, the Competitive Energy Services segment expects to target a sales portfolio of approximately 10 to 15 million MWHs in Governmental Aggregation sales, 0 to 10 million MWHs of POLR sales, 0 to 20 million MWHs in large commercial and industrial sales, 10 to 20 million MWHs in block wholesale sales and 10 to 20 million MWHs of spot wholesale sales. As a result of these changes, the Competitive Energy Services segment incurred certain pre-tax charges in the second quarter of 2014 including an impairment of deferred advertising costs, specifically resulting from the elimination of selling efforts as discussed above, of approximately $22 million and severance related expenses of $7 million. Support for current customers in the channels to be exited will remain through their respective contract terms.
	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
	Three Months Ended	Regulated Distribution		Regulated Transmission		Competitive Energy Services			Other/Corporate			Reconciling Adjustments			Consolidated
		(In millions)
	June 30, 2014
	External revenues	$	2,065	$	191	$	1,311		$	(31	)	$	(40	)	$	3,496
	Internal revenues	—		—		182			—			(182		)	—
	Total revenues	2,065		191		1,493			(31		)	(222		)	3,496
	Depreciation, amortization and deferrals	180		33		96			13			—			322
	Investment income (loss)	15		—		21			2			(9		)	29
	Interest expense	147		30		48			30			7			262
	Income taxes (benefits)	77		32		(65		)	(30		)	12			26
	Income (loss) from continuing operations	158		63		(119		)	(26		)	(12		)	64
	Net income (loss)	158		63		(119		)	(26		)	(12		)	64
	Total assets	27,901		5,840		17,137			510			—			51,388
	Total goodwill	5,092		526		800			—			—			6,418
	Property additions	340		384		240			24			—			988
	June 30, 2013
	External revenues	$	2,038	$	179	$	1,368		$	(31	)	$	(47	)	$	3,507
	Internal revenues	—		—		176			—			(176		)	—
	Total revenues	2,038		179		1,544			(31		)	(223		)	3,507
	Depreciation, amortization and deferrals	220		31		112			9			—			372
	Investment income (loss)	9		—		(16		)	2			(10		)	(15		)
	Interest expense	135		22		61			38			—			256
	Income taxes (benefits)	108		30		(212		)	8			4			(62		)
	Income (loss) from continuing operations	179		51		(343		)	(52		)	(3		)	(168		)
	Net income (loss)	179		51		(339		)	(52		)	(3		)	(164		)
	Total assets	26,936		4,797		17,910			514			—			50,157
	Total goodwill	5,025		526		896			—			—			6,447
	Property additions	283		97		185			21			—			586
	Six Months Ended
	June 30, 2014
	External revenues	$	4,615	$	373	$	2,833		$	(71	)	$	(72	)	$	7,678
	Internal revenues	—		—		431			—			(431		)	—
	Total revenues	4,615		373		3,264			(71		)	(503		)	7,678
	Depreciation, amortization and deferrals	311		66		187			24			—			588
	Investment income	30		—		35			5			(19		)	51
	Interest expense	298		55		94			73			7			527
	Income taxes (benefits)	202		62		(138		)	(56		)	4			74
	Income (loss) from continuing operations	372		114		(243		)	(58		)	1			186
	Discontinued operations, net of tax	—		—		86			—			—			86
	Net income (loss)	372		114		(157		)	(58		)	1			272
	Property additions	609		601		558			41			—			1,809
	June 30, 2013
	External revenues	$	4,247	$	355	$	2,782		$	(58	)	$	(99	)	$	7,227
	Internal revenues	—		—		392			—			(392		)	—
	Total revenues	4,247		355		3,174			(58		)	(491		)	7,227
	Depreciation, amortization and deferrals	422		60		222			20			—			724
	Investment income (loss)	27		—		(6		)	3			(21		)	3
	Interest expense	270		45		134			65			—			514
	Income taxes (benefits)	234		61		(236		)	(11		)	4			52
	Income (loss) from continuing operations	389		102		(385		)	(82		)	—			24
	Discontinued operations, net of tax	—		—		8			—			—			8
	Net income (loss)	389		102		(377		)	(82		)	—			32
	Property additions	719		186		468			39			—			1,412

Discontinued_Operations

Discontinued Operations	6 Months Ended
	Jun. 30, 2014
Discontinued Operations and Disposal Groups [Abstract]	'
Discontinued Operations	'
	DISCONTINUED OPERATIONS
	On September 4, 2013, certain of FirstEnergy 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 $394 million (FES - $307 million). The carrying value of the assets sold was $235 million (FES - $122 million), including goodwill of $29 million (FES - $1 million) which was allocated to the hydroelectric plants to be sold.
	Pre-tax income for the hydroelectric facilities of $155 million (FES - $186 million) for the six months ended June 30, 2014, and $8 million and $14 million (FES - $5 million and $10 million) for the three and six months ended June 30, 2013, respectively, were included in discontinued operations in the Consolidated Statement of Income (Loss). Included in income from discontinued operations in the six months ended June 30, 2014, was a pre-tax gain on the sale of assets of $142 million (FES - $177 million). Revenues for the hydroelectric facilities of $5 million (FES - $5 million) for the six months ended June 30, 2014 and $7 million and $13 million (FES - $6 million and $12 million) for the three and six months ended June 30, 2013, respectively, were included in discontinued operations in the Consolidated Statement of Income (Loss).

Impairment_of_Longlived_Assets

Impairment of Long-lived Assets	6 Months Ended
	Jun. 30, 2014
Restructuring and Related Activities [Abstract]	'
Impairment Of Long-Lived Assets	'
	IMPAIRMENT OF LONG-LIVED ASSETS
	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.

Organization_and_Basis_of_Pres1

Organization and Basis of Presentation (Policies)	6 Months Ended
	Jun. 30, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Basis of Accounting	'
	FirstEnergy follows GAAP and complies with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The accompanying interim financial statements are unaudited, but reflect all adjustments, consisting of normal recurring adjustments, that, in the opinion of management, are necessary for a fair statement of the financial statements. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued.
Consolidation Policy	'
	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. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 6, 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.
Reclassification Policy	'
	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 the sale of hydro assets discussed in additional detail in Note 13, Discontinued Operations.
New Accounting Pronouncements	'
	New Accounting Pronouncements
	In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, requiring entities to recognize revenue by applying a five-step model in accordance with the core principle to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, ASU No. 2014-09 specifies the accounting for costs to obtain or fulfill a contract with a customer and expands disclosure requirements for revenue recognition. This standard is effective for fiscal years beginning after December 15, 2016, with no early adoption permitted, and shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.
Earnings Per Share	'
	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.
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.
Investment Policy	'
	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.

Earnings_Per_Share_of_Common_S1

Earnings Per Share of Common Stock (Tables)	6 Months Ended
	Jun. 30, 2014
Earnings Per Share [Abstract]	'
Reconciliation of basic and diluted earnings per share	'
	The following table reconciles basic and diluted earnings (loss) per share of common stock:
	(In millions, except per share amounts)		Three Months Ended June 30					Six Months Ended June 30
	Reconciliation of Basic and Diluted Earnings (Loss) per Share of Common Stock		2014		2013			2014		2013
	Income (loss) from continuing operations		$	64	$	(168	)	$	186	$	24
	Discontinued operations (Note 13)		—		4			86		8
	Net income (loss)		$	64	$	(164	)	$	272	$	32
	Weighted average number of basic shares outstanding		420		418			419		418
	Assumed exercise of dilutive stock options and awards(1)		1		—			1		1
	Weighted average number of diluted shares outstanding		421		418			420		419
	Earnings (loss) per share:
	Basic earnings per share:
	Income (loss) from continuing operations		$	0.16	$	(0.40	)	$	0.45	$	0.06
	Discontinued operations (Note 13)		—		0.01			0.2		0.02
	Net earnings (loss) per basic share		$	0.16	$	(0.39	)	$	0.65	$	0.08
	Diluted earnings (loss) per share:
	Income (loss) from continuing operations		$	0.15	$	(0.40	)	$	0.45	$	0.06
	Discontinued operations (Note 13)		—		0.01			0.2		0.02
	Net earnings (loss) per diluted share		$	0.15	$	(0.39	)	$	0.65	$	0.08
	(1)	For the three months ended June 30, 2014 and June 30, 2013, 1 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the six months ended June 30, 2014, 2 million shares were excluded from the calculation of diluted shares outstanding. The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect was not significant for the six months ended June 30, 2013.

Pension_and_Other_Postemployme1

Pension and Other Postemployment Benefits (Tables)	6 Months Ended
	Jun. 30, 2014
Compensation and Retirement Disclosure [Abstract]	'
Components of Net Periodic Benefit Costs	'
	The components of the consolidated net periodic cost (credits) for pensions and OPEB (including amounts capitalized) were as follows:
	Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
	For the Three Months Ended June 30,	2014			2013			2014			2013
		(In millions)
	Service costs	$	41		$	49		$	2		$	3
	Interest costs	101			93			10			9
	Expected return on plan assets	(115		)	(125		)	(8		)	(8		)
	Amortization of prior service costs (credits)	2			3			(44		)	(58		)
	Net periodic costs (credits)	$	29		$	20		$	(40	)	$	(54	)
	Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
	For the Six Months Ended June 30,	2014			2013			2014			2013
		(In millions)
	Service costs	$	83		$	98		$	4		$	6
	Interest costs	201			186			20			18
	Expected return on plan assets	(230		)	(250		)	(16		)	(16		)
	Amortization of prior service costs (credits)	4			6			(88		)	(107		)
	Net periodic costs (credits)	$	58		$	40		$	(80	)	$	(99	)
Net Periodic Pension and OPEB Costs	'
	FES' share of the net periodic pensions and OPEB costs (credits) were as follows:
		Pensions						OPEB
		2014			2013			2014			2013
		(In millions)
	For the Three Months Ended June 30,	$	4		$	5		$	(5	)	$	(5	)
	For the Six Months Ended June 30,	$	8		$	10		$	(10	)	$	(10	)
	Pension and OPEB obligations are allocated to FE's subsidiaries employing the plan participants. The net periodic pension and OPEB costs (net of amounts capitalized) recognized in earnings by FE and FES were as follows:
	Net Periodic Benefit Expense (Credit)	Pensions						OPEB
	For the Three Months Ended June 30,	2014			2013			2014			2013
		(In millions)
	FirstEnergy	$	21		$	14		$	(27	)	$	(34	)
	FES	4			5			(5		)	(5		)
	Net Periodic Benefit Expense (Credit)	Pensions						OPEB
	For the Six Months Ended June 30,	2014			2013			2014			2013
		(In millions)
	FirstEnergy	$	42		$	25		$	(54	)	$	(64	)
	FES	8			8			(9		)	(8		)

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Tables)	6 Months Ended
	Jun. 30, 2014
Statement of Comprehensive Income [Abstract]	'
Schedule of Accumulated Other Comprehensive Income	'
	The changes in AOCI, net of tax, in the three and six months ended June 30, 2014 and 2013, 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 as of April 1, 2014	$	(36	)	$	22		$	285		$	271
	Other comprehensive income before reclassifications	1			31			—			32
	Amounts reclassified from AOCI	(1		)	(12		)	(26		)	(39		)
	Net other comprehensive income (loss)	—			19			(26		)	(7		)
	AOCI Balance as of June 30, 2014	$	(36	)	$	41		$	259		$	264
	AOCI Balance as of April 1, 2013	$	(37	)	$	18		$	380		$	361
	Other comprehensive loss before reclassifications	—			(1		)	—			(1		)
	Amounts reclassified from AOCI	—			(4		)	(33		)	(37		)
	Net other comprehensive loss	—			(5		)	(33		)	(38		)
	AOCI Balance as of June 30, 2013	$	(37	)	$	13		$	347		$	323
	FES
		Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
		(In millions)
	AOCI Balance as of April 1, 2014	$	(2	)	$	20		$	44		$	62
	Other comprehensive income (loss) before reclassifications	(1		)	28			—			27
	Amounts reclassified from AOCI	(2		)	(12		)	(3		)	(17		)
	Net other comprehensive income (loss)	(3		)	16			(3		)	10
	AOCI Balance as of June 30, 2014	$	(5	)	$	36		$	41		$	72
	AOCI Balance as of April 1, 2013	$	2		$	17		$	52		$	71
	Other comprehensive loss before reclassifications	—			(1		)	—			(1		)
	Amounts reclassified from AOCI	(1		)	(4		)	(3		)	(8		)
	Net other comprehensive loss	(1		)	(5		)	(3		)	(9		)
	AOCI Balance as of June 30, 2013	$	1		$	12		$	49		$	62
	FirstEnergy
		Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
		(In millions)
	AOCI Balance as of January 1, 2014	$	(36	)	$	9		$	311		$	284
	Other comprehensive income before reclassifications	1			53			—			54
	Amounts reclassified from AOCI	(1		)	(21		)	(52		)	(74		)
	Net other comprehensive income (loss)	—			32			(52		)	(20		)
	AOCI Balance as of June 30, 2014	$	(36	)	$	41		$	259		$	264
	AOCI Balance as of January 1, 2013	$	(38	)	$	15		$	408		$	385
	Other comprehensive income before reclassifications	—			14			—			14
	Amounts reclassified from AOCI	1			(16		)	(61		)	(76		)
	Net other comprehensive income (loss)	1			(2		)	(61		)	(62		)
	AOCI Balance as of June 30, 2013	$	(37	)	$	13		$	347		$	323
	FES
		Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
		(In millions)
	AOCI Balance as of January 1, 2014	$	(1	)	$	8		$	47		$	54
	Other comprehensive income (loss) before reclassifications	(1		)	49			—			48
	Amounts reclassified from AOCI	(3		)	(21		)	(6		)	(30		)
	Net other comprehensive income (loss)	(4		)	28			(6		)	18
	AOCI Balance as of June 30, 2014	$	(5	)	$	36		$	41		$	72
	AOCI Balance as of January 1, 2013	$	3		$	13		$	56		$	72
	Other comprehensive income before reclassifications	—			13			—			13
	Amounts reclassified from AOCI	(2		)	(14		)	(7		)	(23		)
	Net other comprehensive loss	(2		)	(1		)	(7		)	(10		)
	AOCI Balance as of June 30, 2013	$	1		$	12		$	49		$	62
Reclassification out of Accumulated Other Comprehensive Income	'
	The following amounts were reclassified from AOCI in the three months ended June 30, 2014 and 2013:
	FE	Three Months Ended June 30						Affected Line Item in Consolidated Statements of Income (Loss)
	Reclassifications from AOCI (b)	2014			2013
		(In millions)
	Gains & losses on cash flow hedges
	Commodity contracts	$	(3	)	$	(1	)	Other operating expenses
	Long-term debt	2			2			Interest expense
		(1		)	1			Total before taxes
		—			(1		)	Income taxes (benefits)
		$	(1	)	$	—		Net of tax
	Unrealized gains on AFS securities
	Realized gains on sales of securities	$	(19	)	$	(6	)	Investment income (loss)
		7			2			Income taxes (benefits)
		$	(12	)	$	(4	)	Net of tax
	Defined benefit pension and OPEB plans
	Prior-service costs	$	(42	)	$	(55	)	(a)
		16			22			Income taxes (benefits)
		$	(26	)	$	(33	)	Net of tax
	(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
	(b) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.
	FES	Three Months Ended June 30						Affected Line Item in Consolidated Statements of Operations
	Reclassifications from AOCI (b)	2014			2013
		(In millions)
	Gains & losses on cash flow hedges
	Commodity contracts	$	(3	)	$	(1	)	Other operating expenses
		1			—			Income tax benefits
		$	(2	)	$	(1	)	Net of tax
	Unrealized gains on AFS securities
	Realized gains on sales of securities	$	(18	)	$	(6	)	Investment income (loss)
		6			2			Income tax benefits
		$	(12	)	$	(4	)	Net of tax
	Defined benefit pension and OPEB plans
	Prior-service costs	$	(5	)	$	(5	)	(a)
		2			2			Income tax benefits
		$	(3	)	$	(3	)	Net of tax
	(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
	(b) Parenthesis represent credits to the Consolidated Statements of Operations from AOCI.
	The following amounts were reclassified from AOCI in the six months ended June 30, 2014 and 2013:
	FE	Six Months Ended June 30						Affected Line Item in Consolidated Statements of Income (Loss)
	Reclassifications from AOCI (b)	2014			2013
		(In millions)
	Gains & losses on cash flow hedges
	Commodity contracts	$	(5	)	$	(4	)	Other operating expenses
	Long-term debt	4			6			Interest expense
		(1		)	2			Total before taxes
		—			(1		)	Income taxes (benefits)
		$	(1	)	$	1		Net of tax
	Unrealized gains on AFS securities
	Realized gains on sales of securities	$	(33	)	$	(25	)	Investment income (loss)
		12			9			Income taxes (benefits)
		$	(21	)	$	(16	)	Net of tax
	Defined benefit pension and OPEB plans
	Prior-service costs	$	(84	)	$	(101	)	(a)
		32			40			Income taxes (benefits)
		$	(52	)	$	(61	)	Net of tax
	(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
	(b) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.
	FES	Six Months Ended June 30						Affected Line Item in Consolidated Statements of Operations
	Reclassifications from AOCI (b)	2014			2013
		(In millions)
	Gains & losses on cash flow hedges
	Commodity contracts	$	(5	)	$	(4	)	Other operating expenses
	Long-term debt	—			2			Interest expense
	(5		)	(2		)	Total before taxes
	2			—			Income tax benefits
	$	(3	)	$	(2	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(32	)	$	(22	)	Investment income (loss)
	11			8			Income tax benefits
	$	(21	)	$	(14	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(10	)	$	(11	)	(a)
	4			4			Income taxes benefits
	$	(6	)	$	(7	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Operations from AOCI.

Variable_Interest_Entities_Tab

Variable Interest Entities (Tables)	6 Months Ended
	Jun. 30, 2014
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 June 30, 2014:
		Maximum		Discounted Lease		Net
		Exposure		Payments, net(1)		Exposure
		(In millions)
	FES	$	1,212	$	1,000	$	212
	Other FE subsidiaries	701		393		308
	(1)The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.0 billion.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2014
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	June 30, 2014																December 31, 2013
		Level 1				Level 2				Level 3				Total				Level 1			Level 2			Level 3			Total
	Assets	(In millions)
	Corporate debt securities	$	—			$	1,194			$	—			$	1,194			$	—		$	1,365		$	—		$	1,365
	Derivative assets - commodity contracts	7				262				—				269				7			208			—			215
	Derivative assets - FTRs	—				—				37				37				—			—			4			4
	Derivative assets - NUG contracts(1)	—				—				2				2				—			—			20			20
	Equity securities(2)	700				—				—				700				317			—			—			317
	Foreign government debt securities	—				80				—				80				—			109			—			109
	U.S. government debt securities	—				172				—				172				—			165			—			165
	U.S. state debt securities	—				242				—				242				—			228			—			228
	Other(3)	95				272				—				367				187			255			—			442
	Total assets	$	802			$	2,222			$	39			$	3,063			$	511		$	2,330		$	24		$	2,865
	Liabilities
	Derivative liabilities - commodity contracts	$	(16	)		$	(212	)		$	—			$	(228	)		$	(13	)	$	(100	)	$	—		$	(113	)
	Derivative liabilities - FTRs	—				—				(16		)		(16		)		—			—			(12		)	(12		)
	Derivative liabilities - NUG contracts(1)	—				—				(171		)		(171		)		—			—			(222		)	(222		)
	Total liabilities	$	(16	)		$	(212	)		$	(187	)		$	(415	)		$	(13	)	$	(100	)	$	(234	)	$	(347	)
	Net assets (liabilities)(4)	$	786			$	2,010			$	(148	)		$	2,648			$	498		$	2,230		$	(210	)	$	2,518
	(1)	NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
	(2)	NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.
	(3)	Primarily consists of short-term cash investments.
	(4)	Excludes $(36) million and $10 million as of June 30, 2014 and December 31, 2013, 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 June 30, 2014 and December 31, 2013:
		NUG Contracts(1)												LCAPP Contracts										FTRs
		Derivative Assets				Derivative Liabilities				Net				Derivative Assets				Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
		(In millions)
	January 1, 2013 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	)
	Unrealized gain	1				26				27				—				—			—			19			6			25
	Purchases	—				—				—				—				—			—			26			(17		)	9
	Settlements	(19		)		25				6				—				—			—			(12		)	7			(5		)
	June 30, 2014 Balance	$	2			$	(171	)		$	(169	)		$	—			$	—		$	—		$	37		$	(16	)	$	21
	(1)	Changes in the fair value of NUG contracts are generally subject to regulatory accounting treatment and do not impact earnings.
Quantitative information for level 3 valuation	'
	The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended June 30, 2014:
			Fair Value, Net (In millions)				Valuation		Significant Input		Range		Weighted Average			Units
							Technique
	FTRs		$	21			Model		RTO auction clearing prices		($6.70) to $8.00		$1.10			Dollars/MWH
	NUG Contracts		$	(169	)		Model		Generation		600 to 5,202,000		955,000			MWH
									Electricity regional prices		$49.30 to $59.00		$54.10			Dollars/MWH
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities	'
	The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT, nuclear fuel disposal and NUG trusts as of June 30, 2014 and December 31, 2013:
			June 30, 2014(1)												December 31, 2013(2)
			Cost Basis				Unrealized Gains				Fair Value				Cost Basis				Unrealized Gains			Fair Value
			(In millions)
	Debt securities
	FirstEnergy		$	1,715			$	51			$	1,766			$	1,881			$	33		$	1,914
	FES		805				24				829				918				17			935
	Equity securities
	FirstEnergy		$	617			$	83			$	700			$	308			$	9		$	317
	FES		411				48				459				207				—			207
	(1)	Excludes short-term cash investments: FE Consolidated - $139 million; FES - $91 million.
	(2)	Excludes short-term cash investments: FE Consolidated - $204 million; FES - $135 million.
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income	'
	Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three months and six months ended June 30, 2014 and 2013 were as follows:
	Three Months Ended
	June 30, 2014		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and
																			Dividend Income
			(In millions)
	FirstEnergy		$	543			$	35			$	(15	)		$	(1	)		$	24
	FES		284				30				(12		)		(1		)		14
	June 30, 2013		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and Dividend Income
			(In millions)
	FirstEnergy		$	638			$	16			$	(11	)		$	(46	)		$	22
	FES		235				13				(8		)		(38		)		15
	Six Months Ended
	June 30, 2014		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and
																			Dividend Income
			(In millions)
	FirstEnergy		$	1,164			$	63			$	(31	)		$	(3	)		$	49
	FES		707				49				(17		)		(3		)		29
	June 30, 2013		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and Dividend Income
			(In millions)
	FirstEnergy		$	1,177			$	40			$	(16	)		$	(53	)		$	48
	FES		487				33				(11		)		(45		)		28
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities	'
	The following table provides the amortized cost basis, unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of June 30, 2014 and December 31, 2013:
			June 30, 2014												December 31, 2013
			Cost Basis				Unrealized Gains				Fair Value				Cost Basis				Unrealized Gains			Fair Value
			(In millions)
	Debt Securities
	FirstEnergy		$	19			$	8			$	27			$	33			$	2		$	35
Fair value and related carrying amounts of long-term debt and other long-term obligations	'
	The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations, excluding capital lease obligations and net unamortized premiums and discounts:
		June 30, 2014								December 31, 2013
		Carrying				Fair				Carrying				Fair
		Value				Value				Value				Value
		(In millions)
	FirstEnergy	$	19,258			$	20,816			$	17,049			$	17,957
	FES	2,993				3,136				3,001				3,073
FES	'
Fair Value of Financial Instruments [Line Items]	'
Assets and liabilities measured on recurring basis	'
	FES
	Recurring Fair Value Measurements	June 30, 2014																December 31, 2013
		Level 1				Level 2				Level 3				Total				Level 1			Level 2			Level 3			Total
	Assets	(In millions)
	Corporate debt securities	$	—			$	651			$	—			$	651			$	—		$	792		$	—		$	792
	Derivative assets - commodity contracts	7				262				—				269				7			208			—			215
	Derivative assets - FTRs	—				—				26				26				—			—			3			3
	Equity securities(1)	459				—				—				459				207			—			—			207
	Foreign government debt securities	—				57				—				57				—			65			—			65
	U.S. government debt securities	—				30				—				30				—			27			—			27
	U.S. state debt securities	—				9				—				9				—			—			—			—
	Other(2)	—				198				—				198				—			176			—			176
	Total assets	$	466			$	1,207			$	26			$	1,699			$	214		$	1,268		$	3		$	1,485
	Liabilities
	Derivative liabilities - commodity contracts	$	(15	)		$	(212	)		$	—			$	(227	)		$	(13	)	$	(100	)	$	—		$	(113	)
	Derivative liabilities - FTRs	—				—				(16		)		(16		)		—			—			(11		)	(11		)
	Total liabilities	$	(15	)		$	(212	)		$	(16	)		$	(243	)		$	(13	)	$	(100	)	$	(11	)	$	(124	)
	Net assets (liabilities)(3)	$	451			$	995			$	10			$	1,456			$	201		$	1,168		$	(8	)	$	1,361
	(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 $(25) million and $9 million as of June 30, 2014 and December 31, 2013, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts	'
	The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the periods ended June 30, 2014 and December 31, 2013:
			Derivative Asset FTRs				Derivative Liability FTRs				Net FTRs
			(In millions)
	January 1, 2013 Balance		$	6			$	(6	)		$	—
	Unrealized loss		—				(2		)		(2		)
	Purchases		5				(12		)		(7		)
	Settlements		(8		)		9				1
	December 31, 2013 Balance		$	3			$	(11	)		$	(8	)
	Unrealized gain		15				5				20
	Purchases		15				(17		)		(2		)
	Settlements		(7		)		7				—
	June 30, 2014 Balance		$	26			$	(16	)		$	10
Quantitative information for level 3 valuation	'
	The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended June 30, 2014:
			Fair Value, Net (In millions)				Valuation		Significant Input		Range		Weighted Average		Units
							Technique
	FTRs		$	10			Model		RTO auction clearing prices		($6.70) to $8.00		$0.90		Dollars/MWH

Derivative_Instruments_Tables

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2014
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
		June 30,				December 31,					June 30,				December 31,
		2014				2013					2014				2013
		(In millions)									(In millions)
	Current Assets - Derivatives									Current Liabilities - Derivatives
	Commodity Contracts	$	213			$	162			Commodity Contracts	$	(186	)		$	(102	)
	FTRs	36				4				FTRs	(15		)		(9		)
		249				166					(201		)		(111		)
										Noncurrent Liabilities - Adverse Power Contract Liability
	Deferred Charges and Other Assets - Other									NUGs	(171		)		(222		)
	Commodity Contracts	56				53				Noncurrent Liabilities - Other
	FTRs	1				—				Commodity Contracts	(42		)		(11		)
	NUGs	2				20				FTRs	(1		)		(3		)
		59				73					(214		)		(236		)
	Derivative Assets	$	308			$	239			Derivative Liabilities	$	(415	)		$	(347	)
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
	June 30, 2014		Fair Value				Derivative Instruments				Cash Collateral (Received)/Pledged				Net Fair Value
			(In millions)
	Derivative Assets
	Commodity contracts		$	269			$	(183	)		$	—			$	86
	FTRs		37				(16		)		—				21
	NUG contracts		2				(1		)		—				1
			$	308			$	(200	)		$	—			$	108
	Derivative Liabilities
	Commodity contracts		$	(228	)		$	183			$	13			$	(32	)
	FTRs		(16		)		16				—				—
	NUG contracts		(171		)		1				—				(170		)
			$	(415	)		$	200			$	13			$	(202	)
							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	)
Volume of First Energy's outstanding derivative transactions	'
	The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of June 30, 2014:
		Purchases			Sales			Net			Units
		(In millions)
	Power Contracts	33			35			(2	)		MWH
	FTRs	82			—			82			MWH
	NUGs	7			—			7			MWH
	Natural Gas	60			3			57			mmBTU
Effect of derivative instruments on statements of income and comprehensive income	'
	The effect of derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income (Loss) during the three months ended June 30, 2014 and 2013, are summarized in the following tables:
		Three Months Ended June 30
		Commodity Contracts				FTRs				Interest Rate Swaps				Total
		(In millions)
	2014
	Unrealized Gain (Loss) Recognized in:
	Other Operating Expense (1)	$	(70	)		$	13			$	—			$	(57	)
	Realized Gain (Loss) Reclassified to:
	Revenues (2)	$	2			$	(1	)		$	—			$	1
	Purchased Power Expense (3)	22				—				—				22
	Other Operating Expense (4)	—				(10		)		—				(10		)
	Fuel Expense	2				—				—				2
	Interest Expense	—				—				6				6
	(1) Includes ($70) million for commodity contracts and $13 million for FTRs associated with FES.
	(2) Represents losses on structured financial contracts. Includes $2 million for commodity contracts and ($1) million for FTRs associated with FES.
	(3) Realized losses on financially settled wholesale sales contracts of $16 million resulting from higher market prices were netted in purchased power. Includes $22 million for commodity contracts associated with FES.
	(4) Includes ($9) million for FTRs associated with FES.
		Three Months Ended June 30
		Commodity Contracts				FTRs				Interest Rate Swaps				Total
		(In millions)
	2013
	Unrealized Loss Recognized in:
	Other Operating Expense (5)	$	(10	)		$	(1	)		$	—			$	(11	)
	Realized Gain (Loss) Reclassified to:
	Revenues (6)	$	6			$	5			$	—			$	11
	Purchased Power Expense (7)	(2		)		—				—				(2		)
	Other Operating Expense (8)	—				(9		)		—				(9		)
	Fuel Expense	2				—				—				2
	(5) Includes ($10) million for commodity contracts and ($1) million for FTRs associated with FES.
	(6) Includes $5 million for commodity contracts and $5 million for FTRs associated with FES.
	(7) Includes ($2) million for commodity contracts associated with FES.
	(8) Includes ($8) million for FTRs associated with FES.
		Six Months Ended June 30
		Commodity				FTRs				Interest Rate Swaps				Total
		Contracts
		(In millions)
	2014
	Unrealized Gain (Loss) Recognized in:
	Other Operating Expense(1)	$	(58	)		$	18			$	—			$	(40	)
	Realized Gain (Loss) Reclassified to:
	Revenues(2)	$	(11	)		$	51			$	—			$	40
	Purchased Power Expense(3)	458				—				—				458
	Other Operating Expense(4)	—				(17		)		—				(17		)
	Fuel Expense	11				—				—				11
	Interest Expense	—				—				6				6
	(1) Includes ($58) million for commodity contracts and $18 million for FTRs associated with FES.
	(2) Represents losses on structured financial contracts. Includes ($11) million for commodity contracts and $50 million for FTRs associated with FES.
	(3) Realized losses on financially settled wholesale sales contracts of $337 million resulting from higher market prices were netted in purchased power. Includes $458 million for commodity contracts associated with FES.
	(4) Includes ($16) million for FTRs associated with FES.
		Six Months Ended June 30
		Commodity				FTRs				Interest Rate Swaps				Total
		Contracts
		(In millions)
	2013
	Unrealized Loss Recognized in:
	Other Operating Expense(5)	$	(15	)		$	(2	)		$	—			$	(17	)
	Realized Gain (Loss) Reclassified to:
	Revenues(6)	$	16			$	12			$	—			$	28
	Purchased Power Expense(7)	(13		)		—				—				(13		)
	Other Operating Expense(8)	—				(18		)		—				(18		)
	Fuel Expense	2				—				—				2
	(5) Includes ($15) million for commodity contracts and ($2) million for FTRs associated with FES.
	(6) Includes $15 million for commodity contracts and $11 million for FTRs associated with FES.
(7) Includes ($13) million for commodity contracts associated with FES.
(8) Includes ($16) million for FTRs associated with FES.
Derivative instruments subject to regulatory accounting	'
	The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during the three months and six months ended June 30, 2014 and 2013, are summarized in the following tables:
			Three Months Ended June 30
	Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				LCAPP(1)				Regulated FTRs				Total
			(In millions)
	2014
	Unrealized Gain (Loss) on Derivative Instrument		$	(2	)		$	—			$	11			$	9
	Realized Gain (Loss) on Derivative Instrument		18				—				(4		)		14
	2013
	Unrealized Loss on Derivative Instrument		$	(38	)		$	(12	)		$	—			$	(50	)
	Realized Gain on Derivative Instrument		20				—				1				21
			Six Months Ended June 30
	Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				LCAPP(1)				Regulated FTRs				Total
			(In millions)
	2014
	Unrealized Gain on Derivative Instrument		$	25			$	—			$	15			$	40
	Realized Gain (Loss) on Derivative Instrument		8				—				(5		)		3
	2013
	Unrealized Loss on Derivative Instrument		$	(20	)		$	(14	)		$	—			$	(34	)
	Realized Gain on Derivative Instrument		43				—				—				43
	(1)	During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.
Reconciliation of changes in the fair value of certain contracts that are deferred	'
	The following tables provide a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or credit to) customers during the three months and six months ended June 30, 2014 and 2013:
			Three Months Ended June 30
	Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				LCAPP(1)				Regulated FTRs				Total
			(In millions)
	Outstanding net liability as of April 1, 2014		$	(185	)		$	—			$	3			$	(182	)
	Additions/Change in value of existing contracts		(2		)		—				11				9
	Settled contracts		18				—				(4		)		14
	Outstanding net liability as of June 30, 2014		$	(169	)		$	—			$	10			$	(159	)
	Outstanding net liability as of April 1, 2013		$	(213	)		$	(146	)		$	(1	)		$	(360	)
	Additions/Change in value of existing contracts		(38		)		(12		)		—				(50		)
	Settled contracts		20				—				1				21
	Outstanding net liability as of June 30, 2013		$	(231	)		$	(158	)		$	—			$	(389	)
			Six Months Ended June 30
	Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				LCAPP(1)				Regulated FTRs				Total
			(In millions)
	Outstanding net liability as of January 1, 2014		$	(202	)		$	—			$	—			$	(202	)
	Additions/Change in value of existing contracts		25				—				15				40
	Settled contracts		8				—				(5		)		3
	Outstanding net liability as of June 30, 2014		$	(169	)		$	—			$	10			$	(159	)
	Outstanding net liability as of January 1, 2013		$	(254	)		$	(144	)		$	—			$	(398	)
	Additions/Change in value of existing contracts		(20		)		(14		)		—				(34		)
	Settled contracts		43				—				—				43
	Outstanding net liability as of June 30, 2013		$	(231	)		$	(158	)		$	—			$	(389	)
	(1)	During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.

Commitments_Guarantees_and_Con1

Commitments, Guarantees and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Schedule of Guarantor Obligations	'
	The following table discloses the additional credit contingent contractual obligations as of June 30, 2014:
	Collateral Provisions	FES		AE Supply		Utilities		Total
		(In millions)
	Split Rating (One rating agency's rating below investment grade)	$	517	$	6	$	53	$	576
	BB+/Ba1 Credit Ratings	$	560	$	6	$	53	$	619
	Full impact of credit contingent contractual obligations	$	825	$	71	$	89	$	985

Supplemental_Guarantor_Informa1

Supplemental Guarantor Information (Tables)	6 Months Ended
	Jun. 30, 2014
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 Three Months Ended June 30, 2014	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	STATEMENTS OF INCOME (LOSS)
	REVENUES	$	1,412		$	505		$	437		$	(902	)	$	1,452
	OPERATING EXPENSES:
	Fuel	—			288			46			—			334
	Purchased power from affiliates	902			—			75			(902		)	75
	Purchased power from non-affiliates	618			—			—			—			618
	Other operating expenses	242			79			135			12			468
	Provision for depreciation	2			30			48			(1		)	79
	General taxes	18			6			5			—			29
	Total operating expenses	1,782			403			309			(891		)	1,603
	OPERATING INCOME (LOSS)	(370		)	102			128			(11		)	(151		)
	OTHER INCOME (EXPENSE):
	Loss on debt redemptions	—			—			—			—			—
	Investment income	2			2			23			(3		)	24
	Miscellaneous income, including net income from equity investees	159			3			—			(158		)	4
	Interest expense — affiliates	(2		)	(2		)	(1		)	3			(2		)
	Interest expense — other	(14		)	(25		)	(13		)	15			(37		)
	Capitalized interest	—			—			8			—			8
	Total other income (expense)	145			(22		)	17			(143		)	(3		)
	INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	(225		)	80			145			(154		)	(154		)
	INCOME TAXES (BENEFITS)	(137		)	23			45			2			(67		)
	INCOME (LOSS) FROM CONTINUING OPERATIONS	(88		)	57			100			(156		)	(87		)
	Discontinued operations (Note 13)	—			—			—			—			—
	NET INCOME (LOSS)	$	(88	)	$	57		$	100		$	(156	)	$	(87	)
	STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
	NET INCOME (LOSS)	$	(88	)	$	57		$	100		$	(156	)	$	(87	)
	OTHER COMPREHENSIVE INCOME (LOSS):
	Pensions and OPEB prior service costs	(5		)	(5		)	—			5			(5		)
	Amortized gain on derivative hedges	(3		)	—			—			—			(3		)
	Change in unrealized gain on available-for-sale securities	25			—			25			(25		)	25
	Other comprehensive income (loss)	17			(5		)	25			(20		)	17
	Income taxes (benefits) on other comprehensive income (loss)	7			(1		)	9			(8		)	7
	Other comprehensive income (loss), net of tax	10			(4		)	16			(12		)	10
	COMPREHENSIVE INCOME (LOSS)	$	(78	)	$	53		$	116		$	(168	)	$	(77	)
	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
	(Unaudited)
	For the Six Months Ended June 30, 2014	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	STATEMENTS OF INCOME (LOSS)
	REVENUES	$	3,209		$	820		$	799		$	(1,547	)	$	3,281
	OPERATING EXPENSES:
	Fuel	—			560			93			—			653
	Purchased power from affiliates	1,547			—			139			(1,547		)	139
	Purchased power from non-affiliates	1,643			4			—			—			1,647
	Other operating expenses	470			141			285			24			920
	Provision for depreciation	4			59			91			(1		)	153
	General taxes	39			17			12			—			68
	Total operating expenses	3,703			781			620			(1,524		)	3,580
	OPERATING INCOME (LOSS)	(494		)	39			179			(23		)	(299		)
	OTHER INCOME (EXPENSE):
	Loss on debt redemptions	(3		)	(1		)	(1		)	—			(5		)
	Investment income	3			3			44			(6		)	44
	Miscellaneous income, including net income from equity investees	262			3			—			(261		)	4
	Interest expense — affiliates	(5		)	(3		)	(2		)	6			(4		)
	Interest expense — other	(28		)	(49		)	(26		)	30			(73		)
	Capitalized interest	—			1			19			—			20
	Total other income (expense)	229			(46		)	34			(231		)	(14		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	(265		)	(7		)	213			(254		)	(313		)
INCOME TAXES (BENEFITS)	(189		)	(8		)	71			3			(123		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	(76		)	1			142			(257		)	(190		)
Discontinued operations (net of income taxes of $70) (Note 13)	—			116			—			—			116
NET INCOME (LOSS)	$	(76	)	$	117		$	142		$	(257	)	$	(74	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(76	)	$	117		$	142		$	(257	)	$	(74	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(10		)	(9		)	—			9			(10		)
Amortized gain on derivative hedges	(5		)	—			—			—			(5		)
Change in unrealized gain on available-for-sale securities	44			—			44			(44		)	44
Other comprehensive income (loss)	29			(9		)	44			(35		)	29
Income taxes (benefits) on other comprehensive income (loss)	11			(3		)	16			(13		)	11
Other comprehensive income (loss), net of tax	18			(6		)	28			(22		)	18
COMPREHENSIVE INCOME (LOSS)	$	(58	)	$	111		$	170		$	(279	)	$	(56	)
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)
For the Three Months Ended June 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME (LOSS)
REVENUES	$	1,425		$	553		$	457		$	(983	)	$	1,452
OPERATING EXPENSES:
Fuel	—			286			46			—			332
Purchased power from affiliates	1,050			—			70			(983		)	137
Purchased power from non-affiliates	524			1			—			—			525
Other operating expenses	175			69			131			12			387
Provision for depreciation	2			32			44			(2		)	76
General taxes	19			8			7			—			34
Total operating expenses	1,770			396			298			(973		)	1,491
OPERATING INCOME (LOSS)	(345		)	157			159			(10		)	(39		)
OTHER INCOME (EXPENSE):
Loss on debt redemption	(32		)	—			—			—			(32		)
Investment income	1			—			(14		)	(5		)	(18		)
Miscellaneous income, including net income from equity investees	171			3			—			(168		)	6
Interest expense — affiliates	(5		)	(1		)	(3		)	4			(5		)
Interest expense — other	(12		)	(27		)	(14		)	14			(39		)
Capitalized interest	1			—			9			—			10
Total other income (expense)	124			(25		)	(22		)	(155		)	(78		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	(221		)	132			137			(165		)	(117		)
INCOME TAXES (BENEFITS)	(150		)	53			52			3			(42		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	(71		)	79			85			(168		)	(75		)
Discontinued operations (net of income taxes of $1) (Note 13)	—			4			—			—			4
NET INCOME (LOSS)	$	(71	)	$	83		$	85		$	(168	)	$	(71	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(71	)	$	83		$	85		$	(168	)	$	(71	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(5		)	—			5			(5		)
Amortized gain on derivative hedges	(1		)	—			—			—			(1		)
Change in unrealized gain on available for sale securities	(8		)	—			(8		)	8			(8		)
Other comprehensive income (loss)	(14		)	(5		)	(8		)	13			(14		)
Income tax benefits on other comprehensive income (loss)	(5		)	(2		)	(4		)	6			(5		)
Other comprehensive income (loss), net of tax	(9		)	(3		)	(4		)	7			(9		)
COMPREHENSIVE INCOME (LOSS)	$	(80	)	$	80		$	81		$	(161	)	$	(80	)
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)
For the Six Months Ended June 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME (LOSS)
REVENUES	$	2,921		$	1,084		$	897		$	(1,926	)	$	2,976
OPERATING EXPENSES:
Fuel	—			533			99			—			632
Purchased power from affiliates	2,063			—			132			(1,926		)	269
Purchased power from non-affiliates	1,029			2			—			—			1,031
Other operating expenses	337			143			262			24			766
Pensions and OPEB mark-to-market adjustments	—			—			—			—			—
Provision for depreciation	3			63			88			(3		)	151
General taxes	39			19			13			—			71
Total operating expenses	3,471			760			594			(1,905		)	2,920
OPERATING INCOME (LOSS)	(550		)	324			303			(21		)	56
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(103		)	—			—			—			(103		)
Investment income	2			—			4			(7		)	(1		)
Miscellaneous income, including net income from equity investees	363			4			—			(359		)	8
Interest expense — affiliates	(7		)	(2		)	(4		)	7			(6		)
Interest expense — other	(37		)	(55		)	(29		)	30			(91		)
Capitalized interest	1			—			18			—			19
Total other income (expense)	219			(53		)	(11		)	(329		)	(174		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	(331		)	271			292			(350		)	(118		)
INCOME TAXES (BENEFITS)	(262		)	104			110			6			(42		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	(69		)	167			182			(356		)	(76		)
Discontinued operations (net of income taxes of $3) Note (13)	—			7			—			—			7
NET INCOME (LOSS)	$	(69	)	$	174		$	182		$	(356	)	$	(69	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(69	)	$	174		$	182		$	(356	)	$	(69	)
OTHER COMPREHENSIVE INCOME:
Pensions and OPEB prior service costs	(11		)	(10		)	—			10			(11		)
Amortized gain on derivative hedges	(2		)	—			—			—			(2		)
Change in unrealized gain on available-for-sale securities	(3		)	—			(3		)	3			(3		)
Other comprehensive loss	(16		)	(10		)	(3		)	13			(16		)
Income tax benefits on other comprehensive loss	(6		)	(4		)	(2		)	6			(6		)
Other comprehensive loss, net of tax	(10		)	(6		)	(1		)	7			(10		)
COMPREHENSIVE INCOME (LOSS)	$	(79	)	$	168		$	181		$	(349	)	$	(79	)
Condensed Consolidating Balance Sheets	'
	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING BALANCE SHEETS
	(Unaudited)
	As of June 30, 2014	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	ASSETS
	CURRENT ASSETS:
	Cash and cash equivalents	$	—		$	2		$	—		$	—		$	2
	Receivables-
	Customers	534			—			—			—			534
	Affiliated companies	437			380			350			(692		)	475
	Other	70			19			8			—			97
	Notes receivable from affiliated companies	421			605			125			(983		)	168
	Materials and supplies	71			179			216			—			466
	Derivatives	238			—			—			—			238
	Collateral	256			—			—			—			256
	Prepayments and other	59			66			—			—			125
		2,086			1,251			699			(1,675		)	2,361
	PROPERTY, PLANT AND EQUIPMENT:
	In service	127			6,156			7,722			(383		)	13,622
	Less — Accumulated provision for depreciation	32			2,005			3,121			(190		)	4,968
		95			4,151			4,601			(193		)	8,654
	Construction work in progress	6			161			515			—			682
		101			4,312			5,116			(193		)	9,336
	INVESTMENTS:
	Nuclear plant decommissioning trusts	—			—			1,379			—			1,379
	Investment in affiliated companies	6,060			—			—			(6,060		)	—
	Other	—			11			—			—			11
		6,060			11			1,379			(6,060		)	1,390
	DEFERRED CHARGES AND OTHER ASSETS:
	Accumulated deferred income tax benefits	184			58			—			(242		)	—
	Customer intangibles	86			—			—			—			86
	Goodwill	23			—			—			—			23
	Property taxes	—			7			12			—			19
	Unamortized sale and leaseback costs	—			—			—			215			215
	Derivatives	57			—			—			—			57
	Other	47			279			1			(215		)	112
		397			344			13			(242		)	512
		$	8,644		$	5,918		$	7,207		$	(8,170	)	$	13,599
	LIABILITIES AND CAPITALIZATION
	CURRENT LIABILITIES:
	Currently payable long-term debt	$	1		$	120		$	193		$	(23	)	$	291
	Short-term borrowings-
	Affiliated companies	603			379			—			(982		)	—
	Other	300			8			—			—			308
	Accounts payable-
	Affiliated companies	611			222			198			(610		)	421
	Other	110			149			—			—			259
	Accrued taxes	182			26			19			(129		)	98
	Derivatives	200			—			—			—			200
	Other	86			53			11			33			183
		2,093			957			421			(1,711		)	1,760
	CAPITALIZATION:
	Total equity	5,731			2,398			3,662			(6,032		)	5,759
	Long-term debt and other long-term obligations	712			2,133			1,049			(1,173		)	2,721
		6,443			4,531			4,711			(7,205		)	8,480
	NONCURRENT LIABILITIES:
	Deferred gain on sale and leaseback transaction	—			—			—			841			841
	Accumulated deferred income taxes	15			—			826			(95		)	746
	Asset retirement obligations	—			188			856			—			1,044
	Retirement benefits	23			171			—			(1		)	193
	Derivatives	43			—			—			—			43
	Other	27			71			393			1			492
	108			430			2,075			746			3,359
	$	8,644		$	5,918		$	7,207		$	(8,170	)	$	13,599
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
Collateral	136			—			—			—			136
Prepayments and other	52			50			7			—			109
	2,161			1,033			1,147			(1,825		)	2,516
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	—			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	81			228			18			(155		)	172
	252			374			44			(118		)	552
	$	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
Condensed Consolidating Statements of Cash Flows	'
	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	(Unaudited)
	For the Six Months Ended June 30, 2014	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(202	)	$	147		$	149		$	(11	)	$	83
	CASH FLOWS FROM FINANCING ACTIVITIES:
	New Financing-
	Long-term debt	—			291			346			—			637
	Short-term borrowings, net	—			172			—			(172		)	—
	Equity contribution from parent	500			—			—			—			500
	Redemptions and Repayments-
	Long-term debt	(1		)	(258		)	(416		)	11			(664		)
	Short-term borrowings, net	(74		)	—			(151		)	98			(127		)
	Other	(1		)	(8		)	(1		)	—			(10		)
	Net cash provided from (used for) financing activities	424			197			(222		)	(63		)	336
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Property additions	(4		)	(74		)	(399		)	—			(477		)
	Nuclear fuel	—			—			(57		)	—			(57		)
	Proceeds from asset sales	—			307			—			—			307
	Sales of investment securities held in trusts	—			—			707			—			707
	Purchases of investment securities held in trusts	—			—			(736		)	—			(736		)
	Loans to affiliated companies, net	(218		)	(581		)	558			73			(168		)
	Other	—			4			—			1			5
	Net cash provided from (used for) investing activities	(222		)	(344		)	73			74			(419		)
	Net change in cash and cash equivalents	—			—			—			—			—
	Cash and cash equivalents at beginning of period	—			2			—			—			2
	Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2
	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	(Unaudited)
	For the Six Months Ended June 30, 2013	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(687	)	$	390		$	308		$	(11	)	$	—
	CASH FLOWS FROM FINANCING ACTIVITIES:
	New Financing-
	Short-term borrowings, net	240			112			—			(352		)	—
	Equity contribution from parent	1,500			—			—			—			1,500
	Redemptions and Repayments-
	Long-term debt	(770		)	(352		)	(68		)	11			(1,179		)
	Tender premiums	(67		)	—			—			—			(67		)
	Other	(2		)	(3		)	—			—			(5		)
	Net cash provided from (used for) financing activities	901			(243		)	(68		)	(341		)	249
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Property additions	(7		)	(163		)	(180		)	—			(350		)
	Nuclear fuel	—			—			(50		)	—			(50		)
	Proceeds from asset sales	—			19			—			—			19
	Sales of investment securities held in trusts	—			—			487			—			487
	Purchases of investment securities held in trusts	—			—			(515		)	—			(515		)
	Loans to affiliated companies, net	(207		)	(7		)	18			352			156
	Other	—			3			—			—			3
	Net cash used for investing activities	(214		)	(148		)	(240		)	352			(250		)
	Net change in cash and cash equivalents	—			(1		)	—			—			(1		)
	Cash and cash equivalents at beginning of period	—			3			—			—			3
	Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2

Segment_Information_Tables

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2014
Segment Reporting [Abstract]	'
Segment Financial Information	'
	Segment Financial Information
	Three Months Ended	Regulated Distribution		Regulated Transmission		Competitive Energy Services			Other/Corporate			Reconciling Adjustments			Consolidated
		(In millions)
	June 30, 2014
	External revenues	$	2,065	$	191	$	1,311		$	(31	)	$	(40	)	$	3,496
	Internal revenues	—		—		182			—			(182		)	—
	Total revenues	2,065		191		1,493			(31		)	(222		)	3,496
	Depreciation, amortization and deferrals	180		33		96			13			—			322
	Investment income (loss)	15		—		21			2			(9		)	29
	Interest expense	147		30		48			30			7			262
	Income taxes (benefits)	77		32		(65		)	(30		)	12			26
	Income (loss) from continuing operations	158		63		(119		)	(26		)	(12		)	64
	Net income (loss)	158		63		(119		)	(26		)	(12		)	64
	Total assets	27,901		5,840		17,137			510			—			51,388
	Total goodwill	5,092		526		800			—			—			6,418
	Property additions	340		384		240			24			—			988
	June 30, 2013
	External revenues	$	2,038	$	179	$	1,368		$	(31	)	$	(47	)	$	3,507
	Internal revenues	—		—		176			—			(176		)	—
	Total revenues	2,038		179		1,544			(31		)	(223		)	3,507
	Depreciation, amortization and deferrals	220		31		112			9			—			372
	Investment income (loss)	9		—		(16		)	2			(10		)	(15		)
	Interest expense	135		22		61			38			—			256
	Income taxes (benefits)	108		30		(212		)	8			4			(62		)
	Income (loss) from continuing operations	179		51		(343		)	(52		)	(3		)	(168		)
	Net income (loss)	179		51		(339		)	(52		)	(3		)	(164		)
	Total assets	26,936		4,797		17,910			514			—			50,157
	Total goodwill	5,025		526		896			—			—			6,447
	Property additions	283		97		185			21			—			586
	Six Months Ended
	June 30, 2014
	External revenues	$	4,615	$	373	$	2,833		$	(71	)	$	(72	)	$	7,678
	Internal revenues	—		—		431			—			(431		)	—
	Total revenues	4,615		373		3,264			(71		)	(503		)	7,678
	Depreciation, amortization and deferrals	311		66		187			24			—			588
	Investment income	30		—		35			5			(19		)	51
	Interest expense	298		55		94			73			7			527
	Income taxes (benefits)	202		62		(138		)	(56		)	4			74
	Income (loss) from continuing operations	372		114		(243		)	(58		)	1			186
	Discontinued operations, net of tax	—		—		86			—			—			86
	Net income (loss)	372		114		(157		)	(58		)	1			272
	Property additions	609		601		558			41			—			1,809
	June 30, 2013
	External revenues	$	4,247	$	355	$	2,782		$	(58	)	$	(99	)	$	7,227
	Internal revenues	—		—		392			—			(392		)	—
	Total revenues	4,247		355		3,174			(58		)	(491		)	7,227
	Depreciation, amortization and deferrals	422		60		222			20			—			724
	Investment income (loss)	27		—		(6		)	3			(21		)	3
	Interest expense	270		45		134			65			—			514
	Income taxes (benefits)	234		61		(236		)	(11		)	4			52
	Income (loss) from continuing operations	389		102		(385		)	(82		)	—			24
	Discontinued operations, net of tax	—		—		8			—			—			8
	Net income (loss)	389		102		(377		)	(82		)	—			32
	Property additions	719		186		468			39			—			1,412

Impairment_of_Longlived_Assets1

Impairment of Long-lived Assets (Tables)	6 Months Ended
	Jun. 30, 2014
Restructuring and Related Activities [Abstract]	'
Generating units to be deactivated	'
	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

Organization_and_Basis_of_Pres2

Organization and Basis of Presentation Organization and Basis of Presentation (Details) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'	'	'	'
Capitalized financing costs	$14	$4	$21	$7
Capitalized interest	$18	$19	$40	$34

Earnings_Per_Share_of_Common_S2

Earnings Per Share of Common Stock (Details) (USD $)	3 Months Ended				6 Months Ended
In Millions, except Per Share data, unless otherwise specified	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Earnings Per Share [Abstract]	'		'		'		'
Income (loss) from continuing operations	$64		($168)		$186		$24
Discontinued operations (Note 13)	0		4		86		8
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$64		($164)		$272		$32
Weighted average number of basic shares outstanding	420		418		419		418
Assumed exercise of dilutive stock options and awards	1	[1]	0	[1]	1	[1]	1	[1]
Weighted average number of diluted shares outstanding	421		418		420		419
Basic earnings per share:	'		'		'		'
Income (loss) from continuing operations, in dollars per share	$0.16		($0.40)		$0.45		$0.06
Discontinued operations (Note 13), in dollars per share	$0		$0.01		$0.20		$0.02
Basic - Earnings Available to FirstEnergy Corp., in dollars per share	$0.16		($0.39)		$0.65		$0.08
Diluted earnings per share:	'		'		'		'
Income (loss) from continuing operations, in dollars per share	$0.15		($0.40)		$0.45		$0.06
Discontinued operations (Note 13), in dollars per share	$0		$0.01		$0.20		$0.02
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share	$0.15		($0.39)		$0.65		$0.08
Shares excluded from the calculation of diluted shares outstanding, in shares	1		1		2		0
[1]	For the three months ended JuneB 30, 2014 and June 30, 2013, 1 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the six months ended June 30, 2014, 2 million shares were excluded from the calculation of diluted shares outstanding. The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect was not significant for the six months ended JuneB 30, 2013.

Pension_and_Other_Postemployme2

Pension and Other Postemployment Benefits (Details) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Pensions	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Service costs	$41	$49	$83	$98
Interest costs	101	93	201	186
Expected return on plan assets	-115	-125	-230	-250
Amortization of prior service cost (credit)	2	3	4	6
Net periodic costs (credits)	29	20	58	40
OPEB	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Service costs	2	3	4	6
Interest costs	10	9	20	18
Expected return on plan assets	-8	-8	-16	-16
Amortization of prior service cost (credit)	-44	-58	-88	-107
Net periodic costs (credits)	-40	-54	-80	-99
FirstEnergy | Pensions	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Net periodic benefit expense (credit)	21	14	42	25
FirstEnergy | OPEB	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Net periodic benefit expense (credit)	-27	-34	-54	-64
FES | Pensions	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Net periodic costs (credits)	4	5	8	10
Net periodic benefit expense (credit)	4	5	8	8
FES | OPEB	'	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'
Net periodic costs (credits)	-5	-5	-10	-10
Net periodic benefit expense (credit)	($5)	($5)	($9)	($8)

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Details) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'
AOCI Beginning Balance	$271	$361	$284	$385
Other comprehensive income (loss) before reclassifications	32	-1	54	14
Amounts reclassified from AOCI	-39	-37	-74	-76
Other comprehensive income (loss), net of tax	-7	-38	-20	-62
AOCI Ending Balance	264	323	264	323
FES	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'
AOCI Beginning Balance	62	71	54	72
Other comprehensive income (loss) before reclassifications	27	-1	48	13
Amounts reclassified from AOCI	-17	-8	-30	-23
Other comprehensive income (loss), net of tax	10	-9	18	-10
AOCI Ending Balance	72	62	72	62
Gains & Losses on Cash Flow Hedges	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'
AOCI Beginning Balance	-36	-37	-36	-38
Other comprehensive income (loss) before reclassifications	1	0	1	0
Amounts reclassified from AOCI	-1	0	-1	1
Other comprehensive income (loss), net of tax	0	0	0	1
AOCI Ending Balance	-36	-37	-36	-37
Gains & Losses on Cash Flow Hedges | FES	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'
AOCI Beginning Balance	-2	2	-1	3
Other comprehensive income (loss) before reclassifications	-1	0	-1	0
Amounts reclassified from AOCI	-2	-1	-3	-2
Other comprehensive income (loss), net of tax	-3	-1	-4	-2
AOCI Ending Balance	-5	1	-5	1
Unrealized Gains on AFS Securities	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'
AOCI Beginning Balance	22	18	9	15
Other comprehensive income (loss) before reclassifications	31	-1	53	14
Amounts reclassified from AOCI	-12	-4	-21	-16
Other comprehensive income (loss), net of tax	19	-5	32	-2
AOCI Ending Balance	41	13	41	13
Unrealized Gains on AFS Securities | FES	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'
AOCI Beginning Balance	20	17	8	13
Other comprehensive income (loss) before reclassifications	28	-1	49	13
Amounts reclassified from AOCI	-12	-4	-21	-14
Other comprehensive income (loss), net of tax	16	-5	28	-1
AOCI Ending Balance	36	12	36	12
Defined Benefit Pension & OPEB Plans	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'
AOCI Beginning Balance	285	380	311	408
Other comprehensive income (loss) before reclassifications	0	0	0	0
Amounts reclassified from AOCI	-26	-33	-52	-61
Other comprehensive income (loss), net of tax	-26	-33	-52	-61
AOCI Ending Balance	259	347	259	347
Defined Benefit Pension & OPEB Plans | FES	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'
AOCI Beginning Balance	44	52	47	56
Other comprehensive income (loss) before reclassifications	0	0	0	0
Amounts reclassified from AOCI	-3	-3	-6	-7
Other comprehensive income (loss), net of tax	-3	-3	-6	-7
AOCI Ending Balance	$41	$49	$41	$49

Accumulated_Other_Comprehensiv3

Accumulated Other Comprehensive Income (Details 1) (USD $)	3 Months Ended				6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Other operating expenses	$1,021		$886		$2,203		$1,768
Interest expense	262		256		527		514
Investment income (loss)	-29		15		-51		-3
Total before taxes	-90		230		-260		-76
Income taxes (benefits)	26		-62		74		52
Net of tax	-64		164		-272		-32
Loss on debt redemptions	1		24		8		141
FES	'		'		'		'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Other operating expenses	468		387		920		766
Investment income (loss)	-24		18		-44		1
Total before taxes	154		117		313		118
Income taxes (benefits)	-67		-42		-123		-42
Net of tax	87		71		74		69
Loss on debt redemptions	0		32		5		103
Reclassifications from AOCI | Gains & losses on cash flow hedges	'		'		'		'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Total before taxes	-1	[1]	1	[1]	-1	[1]	2	[1]
Income taxes (benefits)	0	[1]	-1	[1]	0	[1]	-1	[1]
Net of tax	-1	[1]	0	[1]	-1	[1]	1	[1]
Reclassifications from AOCI | Gains & losses on cash flow hedges | FES	'		'		'		'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Interest expense	'		'		0	[1]	2
Total before taxes	'		'		-5	[1]	-2
Income taxes (benefits)	1	[1]	0	[1]	2		0
Net of tax	-2	[1]	-1	[1]	-3		-2
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts	'		'		'		'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Other operating expenses	-3	[1]	-1	[1]	-5	[1]	-4	[1]
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts | FES	'		'		'		'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Other operating expenses	-3	[1]	-1	[1]	-5	[1]	-4	[1]
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt	'		'		'		'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Interest expense	2	[1]	2	[1]	4	[1]	6	[1]
Reclassifications from AOCI | Unrealized gains on AFS securities	'		'		'		'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Investment income (loss)	-19	[1]	-6	[1]	-33	[1]	-25	[1]
Income taxes (benefits)	7	[1]	2	[1]	12	[1]	9	[1]
Net of tax	-12	[1]	-4	[1]	-21	[1]	-16	[1]
Reclassifications from AOCI | Unrealized gains on AFS securities | FES	'		'		'		'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Investment income (loss)	-18	[1]	-6	[1]	-32	[1]	-22	[1]
Income taxes (benefits)	6	[1]	2	[1]	11	[1]	8	[1]
Net of tax	-12	[1]	-4	[1]	-21	[1]	-14	[1]
Reclassifications from AOCI | Defined benefit pension and OPEB plans	'		'		'		'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Prior-service costs	-42	[1],[2]	-55	[1],[2]	-84	[1],[2]	-101	[1],[2]
Income taxes (benefits)	16	[1]	22	[1]	32	[1]	40	[1]
Net of tax	-26	[1]	-33	[1]	-52	[1]	-61	[1]
Reclassifications from AOCI | Defined benefit pension and OPEB plans | FES	'		'		'		'
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Prior-service costs	-5	[1],[2]	-5	[1],[2]	-10	[1],[2]	-11	[1],[2]
Income taxes (benefits)	2	[1]	2	[1]	4	[1]	4	[1]
Net of tax	($3)	[1]	($3)	[1]	($6)	[1]	($7)	[1]
[1]	Parenthesis represent credits to the Consolidated Statements of Income from AOCI.
[2]	These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.

Income_Taxes_Details

Income Taxes (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Income Taxes (Textuals) [Abstract]	'	'	'	'
Effective tax rate	28.90%	27.00%	28.50%	68.40%
FES	'	'	'	'
Income Taxes (Textuals) [Abstract]	'	'	'	'
Effective tax rate	43.50%	35.90%	39.30%	35.60%

Variable_Interest_Entities_Det

Variable Interest Entities (Details) (USD $)	Jun. 30, 2014
In Millions, unless otherwise specified
FES	'
Net exposure to loss based upon the casualty value provisions	'
Maximum Exposure	$1,212
Discounted Lease Payments, net	1,000	[1]
Net Exposure	212
Other FE subsidiaries	'
Net exposure to loss based upon the casualty value provisions	'
Maximum Exposure	701
Discounted Lease Payments, net	393	[1]
Net Exposure	$308
[1]	The net present value of FirstEnergybs consolidated sale and leaseback operating lease commitments is $1.0 billion.

Variable_Interest_Entities_Det1

Variable Interest Entities (Details Textuals) (USD $)

3 Months Ended

6 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Mar. 31, 2013

Feb. 12, 2014

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

entities

Beaver Valley Unit 2

Perry Power Plant Unit 1

Bruce Mansfield Unit 1

Power Purchase Agreements

OE

Other FE subsidiaries

Other FE subsidiaries

Other FE subsidiaries

Other FE subsidiaries

Other FE subsidiaries

FGCO

Nuclear Generation Corp

Nuclear Generation Corp

Path-WV

Signal Peak

agreements

Power Purchase Agreements

Power Purchase Agreements

Power Purchase Agreements

Power Purchase Agreements

Bruce Mansfield Plant

Beaver Valley Unit 2

Beaver Valley Unit 2

Global Holding

FEV

Variable Interest Entities (Textuals) [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ownership interest

'

'

'

'

'

'

'

'

'

0.00%

'

'

'

'

'

'

'

'

33.33%

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

'

'

'

'

'

'

'

19

'

'

'

'

'

'

'

'

'

'

'

Number of contracts that may contain variable interest

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchased power

$1,083,000,000

$866,000,000

$2,538,000,000

$1,812,000,000

'

'

'

'

'

'

$40,000,000

$41,000,000

$102,000,000

$90,000,000

'

'

'

'

'

Purchase of lessor equity interests in sale and leaseback, value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

221,000,000

94,000,000

23,000,000

'

'

Percentage of undivided interest of non guarantor subsidiary

'

'

'

'

2.60%

8.11%

93.83%

'

'

'

'

'

'

'

'

'

'

'

'

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

$1,000,000,000

'

$1,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (Recurring, USD $)	Jun. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Assets	'		'
Fair value, assets	$3,063		$2,865
Liabilities	'		'
Fair value, liabilities	-415		-347
Net assets (liabilities)	2,648	[1]	2,518	[1]
FES	'		'
Assets	'		'
Fair value, assets	1,699		1,485
Liabilities	'		'
Fair value, liabilities	-243		-124
Net assets (liabilities)	1,456	[2]	1,361	[2]
Commodity contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	-228		-113
Commodity contracts | Derivative Liabilities | FES	'		'
Liabilities	'		'
Fair value, liabilities	-227		-113
FTRs | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	-16		-12
FTRs | Derivative Liabilities | FES	'		'
Liabilities	'		'
Fair value, liabilities	-16		-11
NUG contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	-171	[3]	-222	[3]
Corporate debt securities	'		'
Assets	'		'
Fair value, assets	1,194		1,365
Corporate debt securities | FES	'		'
Assets	'		'
Fair value, assets	651		792
Commodity contracts | Derivative Assets	'		'
Assets	'		'
Fair value, assets	269		215
Commodity contracts | Derivative Assets | FES	'		'
Assets	'		'
Fair value, assets	269		215
FTRs | Derivative Assets	'		'
Assets	'		'
Fair value, assets	37		4
FTRs | Derivative Assets | FES	'		'
Assets	'		'
Fair value, assets	26		3
NUG contracts | Derivative Assets	'		'
Assets	'		'
Fair value, assets	2	[3]	20	[3]
Equity securities	'		'
Assets	'		'
Fair value, assets	700	[4]	317	[4]
Equity securities | FES	'		'
Assets	'		'
Fair value, assets	459	[4]	207	[4]
Foreign government debt securities	'		'
Assets	'		'
Fair value, assets	80		109
Foreign government debt securities | FES	'		'
Assets	'		'
Fair value, assets	57		65
U.S. government debt securities	'		'
Assets	'		'
Fair value, assets	172		165
U.S. government debt securities | FES	'		'
Assets	'		'
Fair value, assets	30		27
U.S. state debt securities	'		'
Assets	'		'
Fair value, assets	242		228
U.S. state debt securities | FES	'		'
Assets	'		'
Fair value, assets	9		0
Other	'		'
Assets	'		'
Fair value, assets	367	[5]	442	[5]
Other | FES	'		'
Assets	'		'
Fair value, assets	198	[5]	176	[5]
Level 1	'		'
Assets	'		'
Fair value, assets	802		511
Liabilities	'		'
Fair value, liabilities	-16		-13
Net assets (liabilities)	786	[1]	498	[1]
Level 1 | FES	'		'
Assets	'		'
Fair value, assets	466		214
Liabilities	'		'
Fair value, liabilities	-15		-13
Net assets (liabilities)	451	[2]	201	[2]
Level 1 | Commodity contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	-16		-13
Level 1 | Commodity contracts | Derivative Liabilities | FES	'		'
Liabilities	'		'
Fair value, liabilities	-15		-13
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 | 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		7
Level 1 | Commodity contracts | Derivative Assets | FES	'		'
Assets	'		'
Fair value, assets	7		7
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	700	[4]	317	[4]
Level 1 | Equity securities | FES	'		'
Assets	'		'
Fair value, assets	459	[4]	207	[4]
Level 1 | Foreign government debt securities	'		'
Assets	'		'
Fair value, assets	0		0
Level 1 | Foreign government debt securities | FES	'		'
Assets	'		'
Fair value, assets	0		0
Level 1 | U.S. government debt securities	'		'
Assets	'		'
Fair value, assets	0		0
Level 1 | U.S. government debt securities | FES	'		'
Assets	'		'
Fair value, assets	0		0
Level 1 | U.S. state debt securities	'		'
Assets	'		'
Fair value, assets	0		0
Level 1 | U.S. state debt securities | FES	'		'
Assets	'		'
Fair value, assets	0		0
Level 1 | Other	'		'
Assets	'		'
Fair value, assets	95	[5]	187	[5]
Level 1 | Other | FES	'		'
Assets	'		'
Fair value, assets	0	[5]	0	[5]
Level 2	'		'
Assets	'		'
Fair value, assets	2,222		2,330
Liabilities	'		'
Fair value, liabilities	-212		-100
Net assets (liabilities)	2,010	[1]	2,230	[1]
Level 2 | FES	'		'
Assets	'		'
Fair value, assets	1,207		1,268
Liabilities	'		'
Fair value, liabilities	-212		-100
Net assets (liabilities)	995	[2]	1,168	[2]
Level 2 | Commodity contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	-212		-100
Level 2 | Commodity contracts | Derivative Liabilities | FES	'		'
Liabilities	'		'
Fair value, liabilities	-212		-100
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 | Corporate debt securities	'		'
Assets	'		'
Fair value, assets	1,194		1,365
Level 2 | Corporate debt securities | FES	'		'
Assets	'		'
Fair value, assets	651		792
Level 2 | Commodity contracts | Derivative Assets	'		'
Assets	'		'
Fair value, assets	262		208
Level 2 | Commodity contracts | Derivative Assets | FES	'		'
Assets	'		'
Fair value, assets	262		208
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	[4]	0	[4]
Level 2 | Foreign government debt securities	'		'
Assets	'		'
Fair value, assets	80		109
Level 2 | Foreign government debt securities | FES	'		'
Assets	'		'
Fair value, assets	57		65
Level 2 | U.S. government debt securities	'		'
Assets	'		'
Fair value, assets	172		165
Level 2 | U.S. government debt securities | FES	'		'
Assets	'		'
Fair value, assets	30		27
Level 2 | U.S. state debt securities	'		'
Assets	'		'
Fair value, assets	242		228
Level 2 | U.S. state debt securities | FES	'		'
Assets	'		'
Fair value, assets	9		0
Level 2 | Other	'		'
Assets	'		'
Fair value, assets	272	[5]	255	[5]
Level 2 | Other | FES	'		'
Assets	'		'
Fair value, assets	198	[5]	176	[5]
Level 3	'		'
Assets	'		'
Fair value, assets	39		24
Liabilities	'		'
Fair value, liabilities	-187		-234
Net assets (liabilities)	-148	[1]	-210	[1]
Level 3 | FES	'		'
Assets	'		'
Fair value, assets	26		3
Liabilities	'		'
Fair value, liabilities	-16		-11
Net assets (liabilities)	10	[2]	-8	[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	-16		-12
Level 3 | FTRs | Derivative Liabilities | FES	'		'
Liabilities	'		'
Fair value, liabilities	-16		-11
Level 3 | NUG contracts | Derivative Liabilities	'		'
Liabilities	'		'
Fair value, liabilities	-171	[3]	-222	[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	37		4
Level 3 | FTRs | Derivative Assets | FES	'		'
Assets	'		'
Fair value, assets	26		3
Level 3 | NUG contracts | Derivative Assets	'		'
Assets	'		'
Fair value, assets	2	[3]	20	[3]
Level 3 | Equity securities	'		'
Assets	'		'
Fair value, assets	0	[4]	0	[4]
Level 3 | Equity securities | FES	'		'
Assets	'		'
Fair value, assets	0	[4]	0	[4]
Level 3 | Foreign government debt securities	'		'
Assets	'		'
Fair value, assets	0		0
Level 3 | Foreign government debt securities | FES	'		'
Assets	'		'
Fair value, assets	0		0
Level 3 | U.S. government debt securities	'		'
Assets	'		'
Fair value, assets	0		0
Level 3 | U.S. government debt securities | FES	'		'
Assets	'		'
Fair value, assets	0		0
Level 3 | U.S. state debt securities	'		'
Assets	'		'
Fair value, assets	0		0
Level 3 | U.S. state debt securities | FES	'		'
Assets	'		'
Fair value, assets	0		0
Level 3 | Other	'		'
Assets	'		'
Fair value, assets	0	[5]	0	[5]
Level 3 | Other | FES	'		'
Assets	'		'
Fair value, assets	$0	[5]	$0	[5]
[1]	Excludes $(36) million and $10 million as of JuneB 30, 2014 and DecemberB 31, 2013, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
[2]	Excludes $(25) million and $9 million as of JuneB 30, 2014 and DecemberB 31, 2013, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
[3]	NUG 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]	Primarily consists of short-term cash investments.

Fair_Value_Measurements_Detail1

Fair Value Measurements (Details 1) (Level 3, USD $)	6 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014		Dec. 31, 2013
Non Utility Generation Contract	'		'
Reconciliation of changes in the fair value of NUG contracts	'		'
Beginning Balance, Derivative Assets	$20	[1]	$36	[1]
Beginning Balance, Derivative Liabilities	-222	[1]	-290	[1]
Beginning Balance, Net	-202	[1]	-254	[1]
Unrealized gain (loss), Derivative Assets	1	[1]	-8	[1]
Unrealized gain (loss), Derivative Liabilities	26	[1]	-17	[1]
Unrealized gain (loss), Net	27	[1]	-25	[1]
Purchases, Derivative Assets	0	[1]	0	[1]
Purchases, Derivative Liabilities	0	[1]	0	[1]
Purchases, Net	0	[1]	0	[1]
Terminations, Derivative Assets	'		0	[1],[2]
Terminations, Derivative Liability	'		0	[1],[2]
Terminations, Net	'		0	[1],[2]
Settlements, Derivative Assets	-19	[1]	-8	[1]
Settlements, Derivative Liabilities	25	[1]	85	[1]
Settlements, Net	6	[1]	77	[1]
Ending Balance, Derivative Assets	2	[1]	20	[1]
Ending Balance, Derivative Liabilities	-171	[1]	-222	[1]
Ending Balance, Net	-169	[1]	-202	[1]
LCAPP Contracts	'		'
Reconciliation of changes in the fair value of NUG contracts	'		'
Beginning Balance, Derivative Assets	0	[1]	0	[1]
Beginning Balance, Derivative Liabilities	0	[1]	-144	[1]
Beginning Balance, Net	0	[1]	-144	[1]
Unrealized gain (loss), Derivative Assets	0	[1]	0	[1]
Unrealized gain (loss), Derivative Liabilities	0	[1]	-22	[1]
Unrealized gain (loss), Net	0	[1]	-22	[1]
Purchases, Derivative Assets	0	[1]	0	[1]
Purchases, Derivative Liabilities	0	[1]	0	[1]
Purchases, Net	0	[1]	0	[1]
Terminations, Derivative Assets	'		0	[1],[2]
Terminations, Derivative Liability	'		166	[1],[2]
Terminations, Net	'		166	[1],[2]
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]	0	[1]
Ending Balance, Net	0	[1]	0	[1]
FTRs	'		'
Reconciliation of changes in the fair value of NUG contracts	'		'
Beginning Balance, Derivative Assets	4		8
Beginning Balance, Derivative Liabilities	-12		-9
Beginning Balance, Net	-8		-1
Unrealized gain (loss), Derivative Assets	19		3
Unrealized gain (loss), Derivative Liabilities	6		1
Unrealized gain (loss), Net	25		4
Purchases, Derivative Assets	26		6
Purchases, Derivative Liabilities	-17		-15
Purchases, Net	9		-9
Terminations, Derivative Assets	'		0	[2]
Terminations, Derivative Liability	'		0	[2]
Terminations, Net	'		0	[2]
Settlements, Derivative Assets	-12		-13
Settlements, Derivative Liabilities	7		11
Settlements, Net	-5		-2
Ending Balance, Derivative Assets	37		4
Ending Balance, Derivative Liabilities	-16		-12
Ending Balance, Net	21		-8
FTRs | FES	'		'
Reconciliation of changes in the fair value of NUG contracts	'		'
Beginning Balance, Derivative Assets	3		6
Beginning Balance, Derivative Liabilities	-11		-6
Beginning Balance, Net	-8		0
Unrealized gain (loss), Derivative Assets	15		0
Unrealized gain (loss), Derivative Liabilities	5		-2
Unrealized gain (loss), Net	20		-2
Purchases, Derivative Assets	15		5
Purchases, Derivative Liabilities	-17		-12
Purchases, Net	-2		-7
Settlements, Derivative Assets	-7		-8
Settlements, Derivative Liabilities	7		9
Settlements, Net	0		1
Ending Balance, Derivative Assets	26		3
Ending Balance, Derivative Liabilities	-16		-11
Ending Balance, Net	$10		($8)
[1]	Changes in the fair value of NUG contracts are generally subject to regulatory accounting treatment and do not impact earnings.
[2]	See Note 8, Derivative Instruments

Fair_Value_Measurements_Detail2

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

Jun. 30, 2014

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2014

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2014

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2014

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

In Millions, unless otherwise specified

FTRs

FTRs

FTRs

FTRs

FTRs

FTRs

Non Utility Generation Contract

Non Utility Generation Contract

Non Utility Generation Contract

LCAPP Contracts

LCAPP Contracts

LCAPP Contracts

Model

Model

Model

Model

Model

Model

Model

Model

Model

Model

Model

Model

FES

FES

FES

FTRs

FTRs

Non Utility Generation Contract

Minimum

Minimum

Minimum

Maximum

Maximum

Maximum

Weighted Average

Weighted Average

Weighted Average

FES

FTRs

FTRs

Non Utility Generation Contract

FTRs

FTRs

Non Utility Generation Contract

FTRs

FTRs

Non Utility Generation Contract

FES

MWh

FES

MWh

FES

MWh

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair Value

$21

($8)

($1)

$10

($8)

$0

($169)

[1]

($202)

[1]

($254)

[1]

$0

[1]

$0

[1]

($144)

[1]

$21

$10

($169)

'

'

'

'

'

'

'

'

'

Fair Value Inputs, RTO Auction Clearing Prices

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-6.7

-6.7

'

8

8

'

1.1

0.9

'

Fair Value Inputs, Power

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600

'

'

5,202,000

'

'

955,000

Fair Value Inputs, Power, Regional Prices

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

49.3

'

'

59

'

'

54.1

[1]

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

Fair_Value_Measurements_Detail3

Fair Value Measurements (Details 3) (USD $)	Jun. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Debt Securities	'		'
Schedule of Available-for-sale Securities [Line Items]	'		'
Cost Basis	$1,715	[1]	$1,881	[2]
Unrealized Gain	51	[1]	33	[2]
Fair Value	1,766	[1]	1,914	[2]
Equity securities	'		'
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities	'		'
Cost Basis	617	[1]	308	[2]
Unrealized Gains	83	[1]	9	[2]
Fair Value	700	[1]	317	[2]
FES | Debt Securities	'		'
Schedule of Available-for-sale Securities [Line Items]	'		'
Cost Basis	805	[1]	918	[2]
Unrealized Gain	24	[1]	17	[2]
Fair Value	829	[1]	935	[2]
FES | Equity securities	'		'
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities	'		'
Cost Basis	411	[1]	207	[2]
Unrealized Gains	48	[1]	0	[2]
Fair Value	$459	[1]	$207	[2]
[1]	Excludes short-term cash investments: FE Consolidated - $139 million; FES - $91 million
[2]	Excludes short-term cash investments: FE Consolidated - $204 million; FES - $135 million

Fair_Value_Measurements_Detail4

Fair Value Measurements (Details 4) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income	'	'	'	'
Sales Proceeds	$543	$638	$1,164	$1,177
Realized Gains	35	16	63	40
Realized Losses	-15	-11	-31	-16
OTTI	-1	-46	-3	-53
Interest and Dividend Income	24	22	49	48
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	284	235	707	487
Realized Gains	30	13	49	33
Realized Losses	-12	-8	-17	-11
OTTI	-1	-38	-3	-45
Interest and Dividend Income	$14	$15	$29	$28

Fair_Value_Measurements_Detail5

Fair Value Measurements (Details 5) (Debt Securities, USD $)	Jun. 30, 2014	Dec. 31, 2013
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	$19	$33
Unrecognized Gains	8	2
Fair Value	$27	$35

Fair_Value_Measurements_Detail6

Fair Value Measurements (Details 6) (USD $)	Jun. 30, 2014	Dec. 31, 2013
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	$19,258	$17,049
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	20,816	17,957
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	2,993	3,001
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	$3,136	$3,073

Fair_Value_Measurements_Detail7

Fair Value Measurements (Details Textuals) (USD $)

3 Months Ended

6 Months Ended

0 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

6 Months Ended

3 Months Ended

3 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Mar. 31, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Mar. 29, 2014

Jun. 30, 2014

Mar. 29, 2014

Mar. 31, 2014

Jun. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Apr. 02, 2014

Jun. 30, 2014

Apr. 02, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 11, 2014

Mar. 31, 2014

Mar. 31, 2014

19-May-14

19-May-14

Jun. 11, 2014

Jun. 11, 2014

Revolving Credit Facility

NUG contracts

FirstEnergy

FE

FES

FES

FES

FES

FES

FES

FES and AE Supply

FET

ATSI

ATSI

TrAIL

TrAIL

PCRB

PCRB

PCRB

PCRB

PCRB

PCRB

PCRB

Variable Rate Term Loan Due 2019

PRCB Put Date June 3, 2019

PRCB Put Date June 3, 2019

PRCB Put Date June 3, 2019

PCRB Put Date December 3, 2018

4.35% Senior notes due 2024

5.45% Senior Notes Due 2044

4 % Senior Notes Due 2025

4.15% Senior Notes Due 2025

credit_facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

FG

FG

NG

NG

PN

ME

ME

Term Loan

PCRB

PCRB

PCRB

PCRB

FET

FET

ME

PN

FirstEnergy

FG and NG

FG and NG

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

($36,000,000)

'

($36,000,000)

'

$10,000,000

'

'

'

'

($25,000,000)

'

($25,000,000)

'

$9,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash balance excluded from available for sale securities

139,000,000

'

139,000,000

'

204,000,000

'

'

'

'

91,000,000

'

91,000,000

'

135,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Investments not required to be disclosed

636,000,000

'

636,000,000

'

636,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of credit facilities extended

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (decrease) of maximum borrowing capacity

'

'

'

'

'

'

'

1,000,000,000

1,000,000,000

'

'

'

'

'

'

-1,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Maximum Borrowing Capacity

'

'

'

'

'

'

'

3,500,000,000

3,500,000,000

'

'

'

'

'

'

1,500,000,000

1,000,000,000

500,000,000

100,000,000

400,000,000

200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss on debt redemptions

1,000,000

24,000,000

8,000,000

141,000,000

'

'

'

5,000,000

'

0

32,000,000

5,000,000

103,000,000

'

3,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt instrument, face amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

57,000,000

164,000,000

'

'

'

'

1,000,000,000

'

'

182,000,000

235,000,000

600,000,000

400,000,000

250,000,000

200,000,000

Stated interest rate percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.50%

4.15%

4.00%

3.75%

4.35%

5.45%

4.00%

'

Face amount of debt repurchased

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

197,000,000

'

'

16,000,000

45,000,000

'

29,000,000

'

'

'

'

'

'

'

'

'

Maturities of Subordinated Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$50,000,000

'

'

'

'

$150,000,000

'

'

'

'

'

'

'

'

'

'

Derivative_Instruments_Details

Derivative Instruments (Details) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair value of commodity derivatives	'	'
Derivative Assets	$308	$239
Derivative Liabilities	-415	-347
Current Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	249	166
Noncurrent Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	59	73
Current Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	-201	-111
Noncurrent Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	-214	-236
Commodity contracts | Current Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	213	162
Commodity contracts | Noncurrent Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	56	53
Commodity contracts | Current Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	-186	-102
Commodity contracts | Noncurrent Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	-42	-11
FTRs | Current Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	36	4
FTRs | Noncurrent Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	1	0
FTRs | Current Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	-15	-9
FTRs | Noncurrent Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	-1	-3
NUGs | Noncurrent Assets	'	'
Fair value of commodity derivatives	'	'
Derivative Assets	2	20
NUGs | Noncurrent Liabilities	'	'
Fair value of commodity derivatives	'	'
Derivative Liabilities	($171)	($222)

Derivative_Instruments_Details1

Derivative Instruments (Details 1) (USD $)	Jun. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative Assets	'	'
Fair Value	$308	$239
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	-200	-110
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	-9
Net Fair Value	108	120
Derivative Liabilities	'	'
Fair Value	-415	-347
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	200	110
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	13	12
Net Fair Value	-202	-225
Commodity contracts	'	'
Derivative Assets	'	'
Fair Value	269	215
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	-183	-106
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	-9
Net Fair Value	86	100
Derivative Liabilities	'	'
Fair Value	-228	-113
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	183	106
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	13	7
Net Fair Value	-32	0
FTRs	'	'
Derivative Assets	'	'
Fair Value	37	4
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	-16	-4
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	21	0
Derivative Liabilities	'	'
Fair Value	-16	-12
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	16	4
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	5
Net Fair Value	0	-3
NUGs	'	'
Derivative Assets	'	'
Fair Value	2	20
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	-1	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	1	20
Derivative Liabilities	'	'
Fair Value	-171	-222
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	1	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	($170)	($222)

Derivative_Instruments_Details2

Derivative Instruments (Details 2)	Jun. 30, 2014
	MWh
Power Contracts	'
Volume of First Energy's outstanding derivative transactions	'
Purchases (in MWH or mmBTUs)	33,000,000
Sales (in MWH or mmBTUs)	35,000,000
Net (in MWH or mmBTUs)	-2,000,000
FTRs	'
Volume of First Energy's outstanding derivative transactions	'
Purchases (in MWH or mmBTUs)	82,000,000
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	82,000,000
NUGs	'
Volume of First Energy's outstanding derivative transactions	'
Purchases (in MWH or mmBTUs)	7,000,000
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	7,000,000
Natural Gas	'
Volume of First Energy's outstanding derivative transactions	'
Purchases (in MWH or mmBTUs)	60,000,000
Sales (in MWH or mmBTUs)	3,000,000
Net (in MWH or mmBTUs)	57,000,000

Derivative_Instruments_Details3

Derivative Instruments (Details 3) (Not Designated as Hedging Instrument, USD $)	3 Months Ended				6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Revenue	'		'		'		'
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	($1)	[1]	($11)	[2]	($40)	[3]	($28)	[4]
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	-22	[5]	2	[6]	-458	[7]	13	[8]
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	-57	[9]	-11	[10]	-40	[11]	-17	[12]
Realized Gain (Loss) Reclassified	10	[13]	9	[14]	17	[15]	18	[15]
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		-2		-11		-2
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		'		-6		'
Commodity contracts | Revenue	'		'		'		'
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	[1]	-6	[2]	11	[3]	-16	[4]
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	-22	[5]	2	[6]	-458	[7]	13	[8]
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	-70	[9]	-10	[10]	-58	[11]	-15	[12]
Realized Gain (Loss) Reclassified	0	[13]	0	[14]	0	[15]	0	[15]
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		-2		-11		-2
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 | Revenue	'		'		'		'
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	1	[1]	-5	[2]	-51	[3]	-12	[4]
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	[5]	0	[6]	0	[7]	0	[8]
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	13	[9]	-1	[10]	18	[11]	-2	[12]
Realized Gain (Loss) Reclassified	10	[13]	9	[14]	17	[15]	18	[15]
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		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 Swap | Revenue	'		'		'		'
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	[1]	0	[2]	0	[3]	0	[4]
Interest Rate Swap | 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	[5]	0	[6]	0	[7]	0	[8]
Interest Rate Swap | 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	[9]	0	[10]	0	[11]	0	[12]
Realized Gain (Loss) Reclassified	0	[13]	0	[14]	0	[15]	0	[15]
Interest Rate Swap | 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		0		0
Interest Rate Swap | 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		'		-6		'
FES | Commodity contracts | Revenue	'		'		'		'
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		11		-15
FES | Commodity contracts | Purchase Power Expense	'		'		'		'
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships	'		'		'		'
Realized Gain (Loss) Reclassified	-22		2		-458		13
FES | Commodity contracts | Other Operating Expense	'		'		'		'
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships	'		'		'		'
Unrealized Gain (Loss) Recognized	-70		-10		-58		-15
FES | FTRs | Revenue	'		'		'		'
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	1		-5		-50		-11
FES | FTRs | Other Operating Expense	'		'		'		'
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships	'		'		'		'
Unrealized Gain (Loss) Recognized	13		-1		18		-2
Realized Gain (Loss) Reclassified	9		8		16		16
FES | Wholesale Sales Contract | 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	$16		'		$337		'
[1]	Represents losses on structured financial contracts. Includes $2 million for commodity contracts and ($1) million for FTRs associated with FES.
[2]	Includes $5 million for commodity contracts and $5 million for FTRs associated with FES.
[3]	Represents losses on structured financial contracts. Includes ($11) million for commodity contracts and $50 million for FTRs associated with FES.
[4]	Includes $15 million for commodity contracts and $11 million for FTRs associated with FES.
[5]	Realized losses on financially settled wholesale sales contracts of $16 million resulting from higher market prices were netted in purchased power. Includes $22 million for commodity contracts associated with FES.
[6]	Includes ($2) million for commodity contracts associated with FES.
[7]	Realized losses on financially settled wholesale sales contracts of $337 million resulting from higher market prices were netted in purchased power. Includes $458 million for commodity contracts associated with FES.
[8]	Includes ($13) million for commodity contracts associated with FES.
[9]	Includes ($70) million for commodity contracts and $13 million for FTRs associated with FES.
[10]	Includes ($10) million for commodity contracts and ($1) million for FTRs associated with FES.
[11]	Includes ($58) million for commodity contracts and $18 million for FTRs associated with FES.
[12]	Includes ($15) million for commodity contracts and ($2) million for FTRs associated with FES.
[13]	Includes ($9) million for FTRs associated with FES.
[14]	Includes ($8) million for FTRs associated with FES.
[15]	Includes ($16) million for FTRs associated with FES.

Derivative_Instruments_Details4

Derivative Instruments (Details 4) (Not Designated as Hedging Instrument, Subject to Regulatory Accounting, Excluded from Earnings, USD $)	3 Months Ended				6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Derivative [Line Items]	'		'		'		'
Unrealized Gain (Loss) on Derivative Instrument	$9		($50)		$40		($34)
Realized Gain (Loss) on Derivative Instrument	14		21		3		43
NUGs	'		'		'		'
Derivative [Line Items]	'		'		'		'
Unrealized Gain (Loss) on Derivative Instrument	-2		-38		25		-20
Realized Gain (Loss) on Derivative Instrument	18		20		8		43
LCAPP	'		'		'		'
Derivative [Line Items]	'		'		'		'
Unrealized Gain (Loss) on Derivative Instrument	0	[1]	-12	[1]	0	[1]	-14	[1]
Realized Gain (Loss) on Derivative Instrument	0	[1]	0	[1]	0	[1]	0	[1]
Regulated FTRs	'		'		'		'
Derivative [Line Items]	'		'		'		'
Unrealized Gain (Loss) on Derivative Instrument	11		0		15		0
Realized Gain (Loss) on Derivative Instrument	($4)		$1		($5)		$0
[1]	During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.

Derivative_Instruments_Details5

Derivative Instruments (Details 5) (Not Designated as Hedging Instrument, USD $)	3 Months Ended				6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Outstanding net asset (liability) [Roll Forward]	'		'		'		'
Outstanding net asset (liability), Beginning Balance	($182)		($360)		($202)		($398)
Additions/Change in value of existing contracts	9		-50		40		-34
Settled contracts	14		21		3		43
Outstanding net asset (liability), Ending Balance	-159		-389		-159		-389
NUGs	'		'		'		'
Outstanding net asset (liability) [Roll Forward]	'		'		'		'
Outstanding net asset (liability), Beginning Balance	-185		-213		-202		-254
Additions/Change in value of existing contracts	-2		-38		25		-20
Settled contracts	18		20		8		43
Outstanding net asset (liability), Ending Balance	-169		-231		-169		-231
LCAPP	'		'		'		'
Outstanding net asset (liability) [Roll Forward]	'		'		'		'
Outstanding net asset (liability), Beginning Balance	0	[1]	-146	[1]	0	[1]	-144	[1]
Additions/Change in value of existing contracts	0	[1]	-12	[1]	0	[1]	-14	[1]
Settled contracts	0	[1]	0	[1]	0	[1]	0	[1]
Outstanding net asset (liability), Ending Balance	0	[1]	-158	[1]	0	[1]	-158	[1]
Regulated FTRs	'		'		'		'
Outstanding net asset (liability) [Roll Forward]	'		'		'		'
Outstanding net asset (liability), Beginning Balance	3		-1		0		0
Additions/Change in value of existing contracts	11		0		15		0
Settled contracts	-4		1		-5		0
Outstanding net asset (liability), Ending Balance	$10		$0		$10		$0
[1]	During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.

Derivative_Instruments_Details6

Derivative Instruments (Details Textuals) (USD $)

3 Months Ended

6 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

Jun. 30, 2014

Jun. 30, 2014

Jun. 10, 2014

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Oct. 22, 2013

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Commodity contracts

NUGs

FTRs

FES

FES

JCP&L

JCP&L

Cash Flow Hedges

Cash Flow Hedges

Fair Value Hedging

Fair Value Hedging

Fair Value Hedging

Fair Value Hedging

Fair Value Hedging

Commodity contracts

FTRs

contracts

appeal

agreements

agreements

agreements

agreements

agreements

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unamortized gains or losses associated with designated cash flow hedges

($3,000,000)

($3,000,000)

'

$2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

7,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

0

0

'

'

'

'

'

Unamortized gains or losses associated with prior interest rate hedges

54,000,000

54,000,000

'

59,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Losses to be amortized to interest expenses during next twelve months

'

'

'

'

'

'

'

'

'

'

'

9,000,000

'

'

'

12,000,000

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

0

'

0

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

38,000,000

38,000,000

'

44,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reclassifications from long-term debt

'

'

'

'

'

'

'

'

'

'

'

'

'

3,000,000

5,000,000

6,000,000

11,000,000

'

Number of outstanding commodity or interest rate derivatives

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

0

'

0

Net asset position under commodity derivative contracts

'

'

'

'

41,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Collateral posted

'

'

'

'

'

'

'

62,000,000

5,000,000

'

'

'

'

'

'

'

'

'

Additional collateral related to commodity derivatives

'

'

'

'

'

'

'

41,000,000

'

'

'

'

'

'

'

'

'

'

Possible adverse change in quoted market prices of derivative instruments

10.00%

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Possible decrease net income due to ten percent adverse change in commodity prices

'

24,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, Notional Amount

'

'

500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, Average Fixed Interest Rate

'

'

3.21%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments

6,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Liability position

'

'

'

'

'

169,000,000

21,000,000

'

10,000,000

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory_Matters_Details

Regulatory Matters (Details) (USD $)

3 Months Ended

6 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

0 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

6 Months Ended

0 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

1 Months Ended

3 Months Ended

6 Months Ended

0 Months Ended

3 Months Ended

1 Months Ended

6 Months Ended

0 Months Ended

3 Months Ended

0 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Apr. 30, 2007

Dec. 31, 2013

Jun. 30, 2014

Jan. 21, 2010

31-May-13

Dec. 07, 2012

Jun. 30, 2014

Aug. 24, 2012

Jun. 30, 2014

Aug. 24, 2012

Aug. 24, 2012

Sep. 28, 2012

Jun. 30, 2014

Sep. 03, 2013

Dec. 22, 2011

Jun. 30, 2014

Aug. 31, 2011

Oct. 06, 2009

Jun. 14, 2013

Jun. 30, 2014

Feb. 22, 2013

Nov. 30, 2012

Jun. 14, 2013

Aug. 07, 2013

Mar. 31, 2014

Jun. 30, 2014

Dec. 31, 2009

Dec. 12, 2012

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Oct. 10, 2013

Sep. 30, 2013

Jun. 30, 2014

Dec. 31, 2010

Dec. 12, 2013

Dec. 02, 2013

Feb. 15, 2013

Jan. 16, 2013

31-May-11

Apr. 29, 2011

Aug. 04, 2014

Jun. 30, 2014

Aug. 04, 2014

Aug. 04, 2014

Aug. 04, 2014

Jun. 30, 2014

Oct. 10, 2013

Oct. 10, 2013

Oct. 10, 2013

Oct. 10, 2013

Jun. 30, 2014

Dec. 31, 2013

Feb. 06, 2013

Apr. 21, 2014

Apr. 21, 2014

Mar. 06, 2014

Apr. 30, 2010

Jun. 30, 2014

Jun. 30, 2014

Oct. 22, 2012

Jun. 13, 2014

Apr. 30, 2014

Jun. 30, 2014

Oct. 31, 2006

Jun. 30, 2014

Jan. 27, 2014

Dec. 31, 2013

Aug. 07, 2013

Jan. 27, 2014

Feb. 24, 2014

entities

FERC

FERC

FERC

FERC

FERC

FERC

FERC

FERC

FERC

FERC

FERC

FERC

FERC

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

Pennsylvania

Pennsylvania

Pennsylvania

Pennsylvania

Pennsylvania

Pennsylvania

Pennsylvania

Pennsylvania

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

West Virginia

West Virginia

California Claims Matters

California Claims Matters

Division Of Rate Counsel

Public Utilities Commission Of Ohio

Public Utilities Commission Of Ohio

Board Of Public Utilities

Board Of Public Utilities

kv

issues

MOPR Reform

MOPR Reform

PJM

PATH

PATH

PATH-Allegheny

Path-WV

Path-WV

FES and AE Supply

bgs

JCP&L

plan

questions

Year 2012

Year 2013

Year 2014

Annually Through 2014

Annually Through 2017 through 2020

proposals

issues

smart_meter

workgroup

issues

questions

WP

Pennsylvania Companies

ME

PN

Pennsylvania Power Company [Member]

Year 2013

Three Month Period

Twelve Month Period

Twenty-Four Month Period

Forty-Eight Month Period

Unfavorable Regulatory Action

Unfavorable Regulatory Action

Unfavorable Regulatory Action

Unfavorable Regulatory Action

Unfavorable Regulatory Action

Unfavorable Regulatory Action

hearing

MP and PE

MP and PE

MP and PE

FERC

FERC

NEW JERSEY

OHIO

OHIO

NEW JERSEY

NEW JERSEY

exemption

kv

challenge

FTR Underfunding Complaint

component

MWh

MWh

MWh

comment

Party

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

WP

Pennsylvania Companies

Pennsylvania Companies

Proceedings

JCP&L

auctions

JCP&L

JCP&L

Minimum

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Recovery of Deferred Costs, Allowed Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

736,000,000

Public Utilities, Requested Recovery of Deferred Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

744,000,000

Public Utilities, Requested Recovery Costs, Disallowed Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8,000,000

'

Public Utilities, Renewable Energy Auctions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

Amortization (deferral) of regulatory assets, net

20,000,000

72,000,000

-8,000,000

131,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

51,000,000

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Revenue Recovery Request

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

112,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Generation discount for low income customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recovery Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Costs avoided by customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

360,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

ESP Extension Term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Generation supply auction period, after approval

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Generation supply auction period, before approval

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual energy savings

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,200,000

1,705,000

2,237,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (decrease) in annual energy savings

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

408,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Utilities required to reduce peak demand

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Utilities required to additionally reduce peak demand

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.75%

0.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual revenue cap for rider

30,000,000

'

30,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

0

473,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

254,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Loss in Period

1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum reduction in Utilities reduce energy consumption

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

'

'

'

'

'

3.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum reduction in Utilities peak demand

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum range of possible loss

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20,000,000

'

234,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of parties not settled

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of issues not settled

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Increase (Decrease), Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14.70%

'

'

'

9.30%

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,500,000

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Surcharge, Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

48,000,000

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Increase (Decrease), Total Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

152,000,000

'

'

'

'

'

'

'

Energy Contract, Term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 months

'12 months

'24 months

'48 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Requests For Proposal

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Request for Proposal, Project Term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Damages Sought, Value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,400,000

'

5,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period to File Amendment to the Deployment Plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'30 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expedited Procedural Schedule to Rule on Filing

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'90 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period to Respond to Complaint

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'20 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Range of Possible Loss, Minimum

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Increase (Decrease), Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

115,500,000

'

151,900,000

119,800,000

28,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

96,000,000

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Auctioned Energy Price

'

'

'

'

'

'

'

'

59

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$94,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Compliance Filing, Hybrid Methodology, Postage Stamp Cost Allocation

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regional Enforcement Entities

'

'

8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Requirement to File Update with FERC Showing Market-Based Rate Authority Requirements Met, Period

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitments_Guarantees_and_Con2

Commitments, Guarantees and Contingencies (Details) (USD $)	Jun. 30, 2014
In Millions, unless otherwise specified
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	$985
Split Rating (One rating agency's rating below investment grade)	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	576
BB Plus/BA1 Credit Ratings	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	619
FES	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	825
FES | Split Rating (One rating agency's rating below investment grade)	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	517
FES | BB Plus/BA1 Credit Ratings	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	560
AE Supply	'
Guarantor Obligations [Line Items]	'
Maximum exposure under collateral provisions	71
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	89
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 $)

6 Months Ended

6 Months Ended

3 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

6 Months Ended

6 Months Ended

6 Months Ended

6 Months Ended

6 Months Ended

3 Months Ended

3 Months Ended

6 Months Ended

6 Months Ended

1 Months Ended

3 Months Ended

6 Months Ended

6 Months Ended

6 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Jan. 31, 2009

Jun. 30, 2014

Jun. 30, 2013

Jun. 10, 2014

Apr. 19, 2013

Jun. 30, 2014

Apr. 19, 2013

Apr. 30, 2009

Apr. 03, 2014

Oct. 03, 2013

Mar. 28, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jul. 14, 2014

Jun. 30, 2014

Jun. 30, 2013

Apr. 13, 2012

Jan. 02, 2011

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jul. 14, 2014

Jul. 14, 2014

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Jul. 31, 2008

Jul. 31, 2008

Jul. 31, 2008

Aug. 13, 2012

2-May-11

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Apr. 13, 2012

Jun. 30, 2014

Apr. 13, 2012

Jun. 30, 2014

Jul. 01, 2014

Dec. 31, 2013

Oct. 10, 2013

Dec. 05, 2013

Dec. 05, 2013

West Virginia

ICG Litigation

Clean Water Act

Clean Water Act

Clean Water Act

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

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

Climate Change

Climate Change

Climate Change

Senior Secured Term Loan

Regulated Distribution

Regulated Distribution

Competitive Energy Services

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

AE Supply and MP

AE Supply and MP

Parental Guarantees

Subsidiaries' Guarantees

Other Guarantees

State and Local Agencies

Environmental Protection Agency

Minimum

Minimum

Maximum

Maximum

Transportation Commitment

Transportation Commitment

Little Blue Run

Pending Litigation

Pending Litigation

Settled Litigation

options

aspect_of_opinion

deficiency

options

ElectricGenerationUnits

T

CAIR

CSAPR

Subsequent Event

celsius

lb

T

Year 2016

Year 2020

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

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

Regulation of Waste Disposal

Regulation of Waste Disposal

Regulation of Waste Disposal

Regulation of Waste Disposal

CoalFiredPlants

phases

phases

Increase in funding

Subsequent Event

Subsequent Event

Senior Loans

Senior Loans

Senior Loans

Senior Loans

Senior Loans

Complaints

Claim One

Claim Two

contracts

Subsequent Event

West Virginia

Pennsylvania

Pennsylvania

Signal Peak, Global Rail and Affiliates

Signal Peak

Signal Peak

IndividualsInAComplaint

plaintiff

IndividualsInAComplaint

IndividualsInAComplaint

IndividualsInAComplaint

Global Holding

Global Holding

Complaints

Guarantor Obligations [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding guarantees and other assurances aggregated

$4,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$717,000,000

$2,460,000,000

$855,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Company posted collateral related to net liability positions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,000,000

'

'

274,000,000

'

'

4,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Potential collateral posted related to net liability positions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

105,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

New syndicated senior secured term loan facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

350,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayments of Long-term Debt

925,000,000

1,968,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

664,000,000

1,179,000,000

'

'

'

'

'

'

'

350,000,000

'

'

258,000,000

352,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior secured term loan facility, term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Investment ownership percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

69.99%

'

'

33.33%

33.33%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of individuals behalf of which complaint filed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

21

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

61

26

16

Number of named plaintiffs as class representatives

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Jointly owned utility plant, proportionate ownership share

'

'

'

16.67%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reduction in air emissions and compliance

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25.00%

'

40.00%

'

'

'

'

'

'

Number of treatment options

'

'

'

'

'

'

'

'

'

8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of preferred treatment options

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

370,000,000

'

'

'

'

'

'

'

'

'

192,000,000

178,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Settlement Agreement, Consideration

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

67,000,000

'

'

'

'

Percent reduction in GHG Emissions Between 2005 And 2012

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Anticipated Reduction in CO2 Emissions (Percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

17.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proposed emissions standard of large natural gas fired units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

TMDL Limit Development Period

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitment, Proposed Regulation, Comment Period

'

'

'

'

'

'

'45 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period of time to implement plan

'

'

'

'

'6 months

'

'

'

'

'

'

'

'9 years

'15 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Bond Closure and Post Closure Period

'

'

'

'

'

'

'

'

'

'

'

'

'45 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset Retirement Obligation, Period Increase (Decrease)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

163,000,000

'

'

'

Permit to Provide Bonding for Closure and Post-Closure Activities

'

'

'

'

'

'

'

'

'

'

'

'45 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period to Complete Closure

'

'

'

'

'

'

'

'

'

'

'

'12 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accrual for Environmental Loss Contingencies

'

'

'

'

'

'

'

'

'

'

'

'

'

'

130,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Environmental Liabilities Former Gas Facilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

82,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Decommissioning Fund Investments

2,364,000,000

'

2,201,000,000

'

'

'

'

'

'

'

'

'

'

'

'

2,400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,379,000,000

'

1,276,000,000

'

'

'

'

'

'

'

'

'

0

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Parental guarantee associated with the funding of decommissioning costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

155,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Parental Guarantee Associated With Funding Of Decommissioning Costs, Additions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Claims Settled Number

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

Gain contingency, damages denied

'

'

'

'

'

$15,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Supplemental_Guarantor_Informa2

Supplemental Guarantor Information (Details) (USD $)	3 Months Ended				6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Condensed Financial Statements, Captions [Line Items]	'		'		'		'
Discontinued Operation, Tax Effect of Discontinued Operation	$0		$4		$69		$6
Consolidating Statements of Income	'		'		'		'
Revenues	3,496	[1]	3,507	[1]	7,678	[1]	7,227	[1]
OPERATING EXPENSES:	'		'		'		'
Fuel	550		628		1,167		1,258
Purchased power	1,083		866		2,538		1,812
Other operating expenses	1,021		886		2,203		1,768
Provision for depreciation	302		300		596		593
General taxes	228		240		499		505
Total operating expenses	3,204		3,465		6,995		6,540
OPERATING INCOME (LOSS)	292		42		683		687
OTHER INCOME (EXPENSE):	'		'		'		'
Loss on debt redemptions	-1		-24		-8		-141
Investment income	29		-15		51		3
Interest expense	-262		-256		-527		-514
Capitalized interest	32		23		61		41
Total other income (expense)	-202		-272		-423		-611
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	90		-230		260		76
INCOME TAXES (BENEFITS)	26		-62		74		52
INCOME (LOSS) FROM CONTINUING OPERATIONS	64		-168		186		24
Discontinued operations (Note 13)	0		4		86		8
NET INCOME (LOSS)	64		-164		272		32
OTHER COMPREHENSIVE INCOME (LOSS):	'		'		'		'
NET INCOME	64		-164		272		32
Pension and OPEB prior service costs	-42		-55		-84		-101
Amortized loss (gain) on derivative hedges	-1		1		-1		2
Change in unrealized gain on available-for-sale securities	30		-8		51		-3
Other comprehensive income (loss)	-13		-62		-34		-102
Income taxes (benefits) on other comprehensive income (loss)	-6		-24		-14		-40
Other comprehensive income (loss), net of tax	-7		-38		-20		-62
COMPREHENSIVE INCOME (LOSS)	57		-202		252		-30
FES	'		'		'		'
Consolidating Statements of Income	'		'		'		'
Revenues	1,412		1,425		3,209		2,921
OPERATING EXPENSES:	'		'		'		'
Fuel	0		0		0		0
Other operating expenses	242		175		470		337
Provision for depreciation	2		2		4		3
General taxes	18		19		39		39
Total operating expenses	1,782		1,770		3,703		3,471
OPERATING INCOME (LOSS)	-370		-345		-494		-550
OTHER INCOME (EXPENSE):	'		'		'		'
Loss on debt redemptions	0		-32		-3		-103
Investment income	2		1		3		2
Miscellaneous income, including net income from equity investees	159		171		262		363
Capitalized interest	0		1		0		1
Total other income (expense)	145		124		229		219
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	-225		-221		-265		-331
INCOME TAXES (BENEFITS)	-137		-150		-189		-262
INCOME (LOSS) FROM CONTINUING OPERATIONS	-88		-71		-76		-69
Discontinued operations (Note 13)	0		0		0		0
NET INCOME (LOSS)	-88		-71		-76		-69
OTHER COMPREHENSIVE INCOME (LOSS):	'		'		'		'
NET INCOME	-88		-71		-76		-69
Pension and OPEB prior service costs	-5		-5		-10		-11
Amortized loss (gain) on derivative hedges	-3		-1		-5		-2
Change in unrealized gain on available-for-sale securities	25		-8		44		-3
Other comprehensive income (loss)	17		-14		29		-16
Income taxes (benefits) on other comprehensive income (loss)	7		-5		11		-6
Other comprehensive income (loss), net of tax	10		-9		18		-10
COMPREHENSIVE INCOME (LOSS)	-78		-80		-58		-79
Pensions and OPEB mark-to-market adjustment	'		'		'		0
FES | Affiliates	'		'		'		'
OPERATING EXPENSES:	'		'		'		'
Purchased power	902		1,050		1,547		2,063
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense	-2		-5		-5		-7
FES | Non-Affiliates	'		'		'		'
OPERATING EXPENSES:	'		'		'		'
Purchased power	618		524		1,643		1,029
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense	-14		-12		-28		-37
FGCO	'		'		'		'
Condensed Financial Statements, Captions [Line Items]	'		'		'		'
Discontinued Operation, Tax Effect of Discontinued Operation	0		1		70		3
Consolidating Statements of Income	'		'		'		'
Revenues	505		553		820		1,084
OPERATING EXPENSES:	'		'		'		'
Fuel	288		286		560		533
Other operating expenses	79		69		141		143
Provision for depreciation	30		32		59		63
General taxes	6		8		17		19
Total operating expenses	403		396		781		760
OPERATING INCOME (LOSS)	102		157		39		324
OTHER INCOME (EXPENSE):	'		'		'		'
Loss on debt redemptions	0		0		-1		0
Investment income	2		0		3		0
Miscellaneous income, including net income from equity investees	3		3		3		4
Capitalized interest	0		0		1		0
Total other income (expense)	-22		-25		-46		-53
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	80		132		-7		271
INCOME TAXES (BENEFITS)	23		53		-8		104
INCOME (LOSS) FROM CONTINUING OPERATIONS	57		79		1		167
Discontinued operations (Note 13)	0		4		116		7
NET INCOME (LOSS)	57		83		117		174
OTHER COMPREHENSIVE INCOME (LOSS):	'		'		'		'
NET INCOME	57		83		117		174
Pension and OPEB prior service costs	-5		-5		-9		-10
Amortized loss (gain) on derivative hedges	0		0		0		0
Change in unrealized gain on available-for-sale securities	0		0		0		0
Other comprehensive income (loss)	-5		-5		-9		-10
Income taxes (benefits) on other comprehensive income (loss)	-1		-2		-3		-4
Other comprehensive income (loss), net of tax	-4		-3		-6		-6
COMPREHENSIVE INCOME (LOSS)	53		80		111		168
Pensions and OPEB mark-to-market adjustment	'		'		'		0
FGCO | Affiliates	'		'		'		'
OPERATING EXPENSES:	'		'		'		'
Purchased power	0		0		0		0
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense	-2		-1		-3		-2
FGCO | Non-Affiliates	'		'		'		'
OPERATING EXPENSES:	'		'		'		'
Purchased power	0		1		4		2
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense	-25		-27		-49		-55
Nuclear Generation Corp	'		'		'		'
Consolidating Statements of Income	'		'		'		'
Revenues	437		457		799		897
OPERATING EXPENSES:	'		'		'		'
Fuel	46		46		93		99
Other operating expenses	135		131		285		262
Provision for depreciation	48		44		91		88
General taxes	5		7		12		13
Total operating expenses	309		298		620		594
OPERATING INCOME (LOSS)	128		159		179		303
OTHER INCOME (EXPENSE):	'		'		'		'
Loss on debt redemptions	0		0		-1		0
Investment income	23		-14		44		4
Miscellaneous income, including net income from equity investees	0		0		0		0
Capitalized interest	8		9		19		18
Total other income (expense)	17		-22		34		-11
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	145		137		213		292
INCOME TAXES (BENEFITS)	45		52		71		110
INCOME (LOSS) FROM CONTINUING OPERATIONS	100		85		142		182
Discontinued operations (Note 13)	0		0		0		0
NET INCOME (LOSS)	100		85		142		182
OTHER COMPREHENSIVE INCOME (LOSS):	'		'		'		'
NET INCOME	100		85		142		182
Pension and OPEB prior service costs	0		0		0		0
Amortized loss (gain) on derivative hedges	0		0		0		0
Change in unrealized gain on available-for-sale securities	25		-8		44		-3
Other comprehensive income (loss)	25		-8		44		-3
Income taxes (benefits) on other comprehensive income (loss)	9		-4		16		-2
Other comprehensive income (loss), net of tax	16		-4		28		-1
COMPREHENSIVE INCOME (LOSS)	116		81		170		181
Pensions and OPEB mark-to-market adjustment	'		'		'		0
Nuclear Generation Corp | Affiliates	'		'		'		'
OPERATING EXPENSES:	'		'		'		'
Purchased power	75		70		139		132
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense	-1		-3		-2		-4
Nuclear Generation Corp | Non-Affiliates	'		'		'		'
OPERATING EXPENSES:	'		'		'		'
Purchased power	0		0		0		0
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense	-13		-14		-26		-29
Eliminations	'		'		'		'
Consolidating Statements of Income	'		'		'		'
Revenues	-902		-983		-1,547		-1,926
OPERATING EXPENSES:	'		'		'		'
Fuel	0		0		0		0
Other operating expenses	12		12		24		24
Provision for depreciation	-1		-2		-1		-3
General taxes	0		0		0		0
Total operating expenses	-891		-973		-1,524		-1,905
OPERATING INCOME (LOSS)	-11		-10		-23		-21
OTHER INCOME (EXPENSE):	'		'		'		'
Loss on debt redemptions	0		0		0		0
Investment income	-3		-5		-6		-7
Miscellaneous income, including net income from equity investees	-158		-168		-261		-359
Capitalized interest	0		0		0		0
Total other income (expense)	-143		-155		-231		-329
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	-154		-165		-254		-350
INCOME TAXES (BENEFITS)	2		3		3		6
INCOME (LOSS) FROM CONTINUING OPERATIONS	-156		-168		-257		-356
Discontinued operations (Note 13)	0		0		0		0
NET INCOME (LOSS)	-156		-168		-257		-356
OTHER COMPREHENSIVE INCOME (LOSS):	'		'		'		'
NET INCOME	-156		-168		-257		-356
Pension and OPEB prior service costs	5		5		9		10
Amortized loss (gain) on derivative hedges	0		0		0		0
Change in unrealized gain on available-for-sale securities	-25		8		-44		3
Other comprehensive income (loss)	-20		13		-35		13
Income taxes (benefits) on other comprehensive income (loss)	-8		6		-13		6
Other comprehensive income (loss), net of tax	-12		7		-22		7
COMPREHENSIVE INCOME (LOSS)	-168		-161		-279		-349
Pensions and OPEB mark-to-market adjustment	'		'		'		0
Eliminations | Affiliates	'		'		'		'
OPERATING EXPENSES:	'		'		'		'
Purchased power	-902		-983		-1,547		-1,926
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense	3		4		6		7
Eliminations | Non-Affiliates	'		'		'		'
OPERATING EXPENSES:	'		'		'		'
Purchased power	0		0		0		0
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense	15		14		30		30
FES	'		'		'		'
Condensed Financial Statements, Captions [Line Items]	'		'		'		'
Discontinued Operation, Tax Effect of Discontinued Operation	0		1		70		3
Consolidating Statements of Income	'		'		'		'
Revenues	1,452		1,452		3,281		2,976
OPERATING EXPENSES:	'		'		'		'
Fuel	334		332		653		632
Other operating expenses	468		387		920		766
Provision for depreciation	79		76		153		151
General taxes	29		34		68		71
Total operating expenses	1,603		1,491		3,580		2,920
OPERATING INCOME (LOSS)	-151		-39		-299		56
OTHER INCOME (EXPENSE):	'		'		'		'
Loss on debt redemptions	0		-32		-5		-103
Investment income	24		-18		44		-1
Miscellaneous income, including net income from equity investees	4		6		4		8
Capitalized interest	8		10		20		19
Total other income (expense)	-3		-78		-14		-174
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	-154		-117		-313		-118
INCOME TAXES (BENEFITS)	-67		-42		-123		-42
INCOME (LOSS) FROM CONTINUING OPERATIONS	-87		-75		-190		-76
Discontinued operations (Note 13)	0		4		116		7
NET INCOME (LOSS)	-87		-71		-74		-69
OTHER COMPREHENSIVE INCOME (LOSS):	'		'		'		'
NET INCOME	-87		-71		-74		-69
Pension and OPEB prior service costs	-5		-5		-10		-11
Amortized loss (gain) on derivative hedges	-3		-1		-5		-2
Change in unrealized gain on available-for-sale securities	25		-8		44		-3
Other comprehensive income (loss)	17		-14		29		-16
Income taxes (benefits) on other comprehensive income (loss)	7		-5		11		-6
Other comprehensive income (loss), net of tax	10		-9		18		-10
COMPREHENSIVE INCOME (LOSS)	-77		-80		-56		-79
Pensions and OPEB mark-to-market adjustment	'		'		'		0
FES | Affiliates	'		'		'		'
OPERATING EXPENSES:	'		'		'		'
Purchased power	75		137		139		269
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense	-2		-5		-4		-6
FES | Non-Affiliates	'		'		'		'
OPERATING EXPENSES:	'		'		'		'
Purchased power	618		525		1,647		1,031
OTHER INCOME (EXPENSE):	'		'		'		'
Interest expense	($37)		($39)		($73)		($91)
Bruce Mansfield Unit 1	'		'		'		'
Condensed Financial Statements, Captions [Line Items]	'		'		'		'
Percentage of undivided interest of non guarantor subsidiary	93.83%		'		93.83%		'
[1]	Includes excise tax collections of $99 million and $107 million in the three months ended JuneB 30, 2014 and 2013, respectively, and $216 million and $229 million in the six months ended JuneB 30, 2014 and 2013, respectively.

Supplemental_Guarantor_Informa3

Supplemental Guarantor Information (Details 1) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	$76	$218	$71	$172
Receivables-	'	'	'	'
Customers	1,731	1,720	'	'
Other Receivables	231	198	'	'
Materials and supplies, at average cost	802	752	'	'
Derivatives	249	166	'	'
Collateral	266	155	'	'
Prepayments and other	205	212	'	'
Total current assets	4,183	4,013	'	'
PROPERTY, PLANT AND EQUIPMENT:	'	'	'	'
In service	46,133	44,228	'	'
Less - Accumulated provision for depreciation	13,797	13,280	'	'
Property, plant and equipment in service net of accumulated provision for depreciation	32,336	30,948	'	'
Construction work in progress	2,180	2,304	'	'
Total net property, plant and equipment	34,516	33,252	'	'
INVESTMENTS:	'	'	'	'
Nuclear plant decommissioning trusts	2,364	2,201	'	'
Other	896	903	'	'
Total other property and investments	3,260	3,104	'	'
ASSETS HELD FOR SALE	0	235	'	'
DEFERRED CHARGES AND OTHER ASSETS:	'	'	'	'
Goodwill	6,418	6,418	6,447	'
Other	1,279	1,548	'	'
Total deferred charges and other assets	9,429	9,820	'	'
Total assets	51,388	50,424	50,157	'
CURRENT LIABILITIES:	'	'	'	'
Currently payable long-term debt	1,016	1,415	'	'
Other	2,323	3,404	'	'
Accounts payable-	'	'	'	'
Accrued taxes	397	485	'	'
Derivatives	201	111	'	'
Other	612	621	'	'
Total current liabilities	6,173	7,637	'	'
CAPITALIZATION:	'	'	'	'
Total common stockholders' equity	12,683	12,692	'	'
Long-term debt and other long-term obligations	18,415	15,831	'	'
Total capitalization	31,100	28,526	'	'
NONCURRENT LIABILITIES:	'	'	'	'
Deferred gain on sale and leaseback transaction	841	858	'	'
Accumulated deferred income taxes	7,081	6,968	'	'
Asset retirement obligations	1,730	1,678	'	'
Retirement benefits	2,732	2,689	'	'
Other	1,494	1,778	'	'
Total noncurrent liabilities	14,115	14,261	'	'
Total liabilities and capitalization	51,388	50,424	'	'
FES	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	0	0	0	0
Receivables-	'	'	'	'
Customers	534	539	'	'
Affiliated companies	437	938	'	'
Other Receivables	70	52	'	'
Notes receivable from affiliated companies	421	203	'	'
Materials and supplies, at average cost	71	76	'	'
Derivatives	238	165	'	'
Collateral	256	136	'	'
Prepayments and other	59	52	'	'
Total current assets	2,086	2,161	'	'
PROPERTY, PLANT AND EQUIPMENT:	'	'	'	'
In service	127	104	'	'
Less - Accumulated provision for depreciation	32	28	'	'
Property, plant and equipment in service net of accumulated provision for depreciation	95	76	'	'
Construction work in progress	6	23	'	'
Total net property, plant and equipment	101	99	'	'
INVESTMENTS:	'	'	'	'
Nuclear plant decommissioning trusts	0	0	'	'
Investment in affiliated companies	6,060	5,801	'	'
Other	0	0	'	'
Total other property and investments	6,060	5,801	'	'
ASSETS HELD FOR SALE	'	0	'	'
DEFERRED CHARGES AND OTHER ASSETS:	'	'	'	'
Accumulated deferred income tax benefits	184	0	'	'
Customer intangibles	86	95	'	'
Goodwill	23	23	'	'
Property taxes	0	0	'	'
Unamortized sale and leaseback costs	0	0	'	'
Derivatives	57	53	'	'
Other	47	81	'	'
Total deferred charges and other assets	397	252	'	'
Total assets	8,644	8,313	'	'
CURRENT LIABILITIES:	'	'	'	'
Currently payable long-term debt	1	1	'	'
Other	300	0	'	'
Accounts payable-	'	'	'	'
Affiliated companies	611	741	'	'
Other	110	94	'	'
Accrued taxes	182	204	'	'
Derivatives	200	110	'	'
Other	86	70	'	'
Total current liabilities	2,093	2,197	'	'
CAPITALIZATION:	'	'	'	'
Total common stockholders' equity	5,731	5,312	'	'
Long-term debt and other long-term obligations	712	712	'	'
Total capitalization	6,443	6,024	'	'
NONCURRENT LIABILITIES:	'	'	'	'
Deferred gain on sale and leaseback transaction	0	0	'	'
Accumulated deferred income taxes	15	32	'	'
Asset retirement obligations	0	0	'	'
Retirement benefits	23	22	'	'
Derivatives	43	14	'	'
Other	27	24	'	'
Total noncurrent liabilities	108	92	'	'
Total liabilities and capitalization	8,644	8,313	'	'
FES | Affiliates	'	'	'	'
CURRENT LIABILITIES:	'	'	'	'
Short-term borrowings	603	977	'	'
FGCO	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	2	2	2	3
Receivables-	'	'	'	'
Customers	0	0	'	'
Affiliated companies	380	787	'	'
Other Receivables	19	12	'	'
Notes receivable from affiliated companies	605	23	'	'
Materials and supplies, at average cost	179	159	'	'
Derivatives	0	0	'	'
Collateral	0	0	'	'
Prepayments and other	66	50	'	'
Total current assets	1,251	1,033	'	'
PROPERTY, PLANT AND EQUIPMENT:	'	'	'	'
In service	6,156	6,105	'	'
Less - Accumulated provision for depreciation	2,005	1,953	'	'
Property, plant and equipment in service net of accumulated provision for depreciation	4,151	4,152	'	'
Construction work in progress	161	148	'	'
Total net property, plant and equipment	4,312	4,300	'	'
INVESTMENTS:	'	'	'	'
Nuclear plant decommissioning trusts	0	0	'	'
Investment in affiliated companies	0	0	'	'
Other	11	11	'	'
Total other property and investments	11	11	'	'
ASSETS HELD FOR SALE	'	122	'	'
DEFERRED CHARGES AND OTHER ASSETS:	'	'	'	'
Accumulated deferred income tax benefits	58	131	'	'
Customer intangibles	0	0	'	'
Goodwill	0	0	'	'
Property taxes	7	15	'	'
Unamortized sale and leaseback costs	0	0	'	'
Derivatives	0	0	'	'
Other	279	228	'	'
Total deferred charges and other assets	344	374	'	'
Total assets	5,918	5,840	'	'
CURRENT LIABILITIES:	'	'	'	'
Currently payable long-term debt	120	367	'	'
Other	8	4	'	'
Accounts payable-	'	'	'	'
Affiliated companies	222	400	'	'
Other	149	196	'	'
Accrued taxes	26	23	'	'
Derivatives	0	0	'	'
Other	53	63	'	'
Total current liabilities	957	1,265	'	'
CAPITALIZATION:	'	'	'	'
Total common stockholders' equity	2,398	2,283	'	'
Long-term debt and other long-term obligations	2,133	1,860	'	'
Total capitalization	4,531	4,143	'	'
NONCURRENT LIABILITIES:	'	'	'	'
Deferred gain on sale and leaseback transaction	0	0	'	'
Accumulated deferred income taxes	0	0	'	'
Asset retirement obligations	188	187	'	'
Retirement benefits	171	163	'	'
Derivatives	0	0	'	'
Other	71	82	'	'
Total noncurrent liabilities	430	432	'	'
Total liabilities and capitalization	5,918	5,840	'	'
FGCO | Affiliates	'	'	'	'
CURRENT LIABILITIES:	'	'	'	'
Short-term borrowings	379	212	'	'
Nuclear Generation Corp	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	0	0	0	0
Receivables-	'	'	'	'
Customers	0	0	'	'
Affiliated companies	350	227	'	'
Other Receivables	8	17	'	'
Notes receivable from affiliated companies	125	683	'	'
Materials and supplies, at average cost	216	213	'	'
Derivatives	0	0	'	'
Collateral	0	0	'	'
Prepayments and other	0	7	'	'
Total current assets	699	1,147	'	'
PROPERTY, PLANT AND EQUIPMENT:	'	'	'	'
In service	7,722	6,645	'	'
Less - Accumulated provision for depreciation	3,121	2,962	'	'
Property, plant and equipment in service net of accumulated provision for depreciation	4,601	3,683	'	'
Construction work in progress	515	1,137	'	'
Total net property, plant and equipment	5,116	4,820	'	'
INVESTMENTS:	'	'	'	'
Nuclear plant decommissioning trusts	1,379	1,276	'	'
Investment in affiliated companies	0	0	'	'
Other	0	0	'	'
Total other property and investments	1,379	1,276	'	'
ASSETS HELD FOR SALE	'	0	'	'
DEFERRED CHARGES AND OTHER ASSETS:	'	'	'	'
Accumulated deferred income tax benefits	0	0	'	'
Customer intangibles	0	0	'	'
Goodwill	0	0	'	'
Property taxes	12	26	'	'
Unamortized sale and leaseback costs	0	0	'	'
Derivatives	0	0	'	'
Other	1	18	'	'
Total deferred charges and other assets	13	44	'	'
Total assets	7,207	7,287	'	'
CURRENT LIABILITIES:	'	'	'	'
Currently payable long-term debt	193	547	'	'
Other	0	0	'	'
Accounts payable-	'	'	'	'
Affiliated companies	198	362	'	'
Other	0	0	'	'
Accrued taxes	19	23	'	'
Derivatives	0	0	'	'
Other	11	18	'	'
Total current liabilities	421	1,101	'	'
CAPITALIZATION:	'	'	'	'
Total common stockholders' equity	3,662	3,493	'	'
Long-term debt and other long-term obligations	1,049	742	'	'
Total capitalization	4,711	4,235	'	'
NONCURRENT LIABILITIES:	'	'	'	'
Deferred gain on sale and leaseback transaction	0	0	'	'
Accumulated deferred income taxes	826	736	'	'
Asset retirement obligations	856	828	'	'
Retirement benefits	0	0	'	'
Derivatives	0	0	'	'
Other	393	387	'	'
Total noncurrent liabilities	2,075	1,951	'	'
Total liabilities and capitalization	7,207	7,287	'	'
Nuclear Generation Corp | Affiliates	'	'	'	'
CURRENT LIABILITIES:	'	'	'	'
Short-term borrowings	0	151	'	'
Eliminations	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	0	0	0	0
Receivables-	'	'	'	'
Customers	0	0	'	'
Affiliated companies	-692	-916	'	'
Other Receivables	0	0	'	'
Notes receivable from affiliated companies	-983	-909	'	'
Materials and supplies, at average cost	0	0	'	'
Derivatives	0	0	'	'
Collateral	0	0	'	'
Prepayments and other	0	0	'	'
Total current assets	-1,675	-1,825	'	'
PROPERTY, PLANT AND EQUIPMENT:	'	'	'	'
In service	-383	-382	'	'
Less - Accumulated provision for depreciation	-190	-188	'	'
Property, plant and equipment in service net of accumulated provision for depreciation	-193	-194	'	'
Construction work in progress	0	0	'	'
Total net property, plant and equipment	-193	-194	'	'
INVESTMENTS:	'	'	'	'
Nuclear plant decommissioning trusts	0	0	'	'
Investment in affiliated companies	-6,060	-5,801	'	'
Other	0	0	'	'
Total other property and investments	-6,060	-5,801	'	'
ASSETS HELD FOR SALE	'	0	'	'
DEFERRED CHARGES AND OTHER ASSETS:	'	'	'	'
Accumulated deferred income tax benefits	-242	-131	'	'
Customer intangibles	0	0	'	'
Goodwill	0	0	'	'
Property taxes	0	0	'	'
Unamortized sale and leaseback costs	215	168	'	'
Derivatives	0	0	'	'
Other	-215	-155	'	'
Total deferred charges and other assets	-242	-118	'	'
Total assets	-8,170	-7,938	'	'
CURRENT LIABILITIES:	'	'	'	'
Currently payable long-term debt	-23	-23	'	'
Other	0	0	'	'
Accounts payable-	'	'	'	'
Affiliated companies	-610	-738	'	'
Other	0	0	'	'
Accrued taxes	-129	-184	'	'
Derivatives	0	0	'	'
Other	33	46	'	'
Total current liabilities	-1,711	-1,808	'	'
CAPITALIZATION:	'	'	'	'
Total common stockholders' equity	-6,032	-5,776	'	'
Long-term debt and other long-term obligations	-1,173	-1,184	'	'
Total capitalization	-7,205	-6,960	'	'
NONCURRENT LIABILITIES:	'	'	'	'
Deferred gain on sale and leaseback transaction	841	858	'	'
Accumulated deferred income taxes	-95	-27	'	'
Asset retirement obligations	0	0	'	'
Retirement benefits	-1	0	'	'
Derivatives	0	0	'	'
Other	1	-1	'	'
Total noncurrent liabilities	746	830	'	'
Total liabilities and capitalization	-8,170	-7,938	'	'
Eliminations | Affiliates	'	'	'	'
CURRENT LIABILITIES:	'	'	'	'
Short-term borrowings	-982	-909	'	'
FES	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	2	2	2	3
Receivables-	'	'	'	'
Customers	534	539	'	'
Affiliated companies	475	1,036	'	'
Other Receivables	97	81	'	'
Notes receivable from affiliated companies	168	0	'	'
Materials and supplies, at average cost	466	448	'	'
Derivatives	238	165	'	'
Collateral	256	136	'	'
Prepayments and other	125	109	'	'
Total current assets	2,361	2,516	'	'
PROPERTY, PLANT AND EQUIPMENT:	'	'	'	'
In service	13,622	12,472	'	'
Less - Accumulated provision for depreciation	4,968	4,755	'	'
Property, plant and equipment in service net of accumulated provision for depreciation	8,654	7,717	'	'
Construction work in progress	682	1,308	'	'
Total net property, plant and equipment	9,336	9,025	'	'
INVESTMENTS:	'	'	'	'
Nuclear plant decommissioning trusts	1,379	1,276	'	'
Investment in affiliated companies	0	0	'	'
Other	11	11	'	'
Total other property and investments	1,390	1,287	'	'
ASSETS HELD FOR SALE	0	122	'	'
DEFERRED CHARGES AND OTHER ASSETS:	'	'	'	'
Accumulated deferred income tax benefits	0	0	'	'
Customer intangibles	86	95	'	'
Goodwill	23	23	'	'
Property taxes	19	41	'	'
Unamortized sale and leaseback costs	215	168	'	'
Derivatives	57	53	'	'
Other	112	172	'	'
Total deferred charges and other assets	512	552	'	'
Total assets	13,599	13,502	'	'
CURRENT LIABILITIES:	'	'	'	'
Currently payable long-term debt	291	892	'	'
Other	308	4	'	'
Accounts payable-	'	'	'	'
Affiliated companies	421	765	'	'
Other	259	290	'	'
Accrued taxes	98	66	'	'
Derivatives	200	110	'	'
Other	183	197	'	'
Total current liabilities	1,760	2,755	'	'
CAPITALIZATION:	'	'	'	'
Total common stockholders' equity	5,759	5,312	'	'
Long-term debt and other long-term obligations	2,721	2,130	'	'
Total capitalization	8,480	7,442	'	'
NONCURRENT LIABILITIES:	'	'	'	'
Deferred gain on sale and leaseback transaction	841	858	'	'
Accumulated deferred income taxes	746	741	'	'
Asset retirement obligations	1,044	1,015	'	'
Retirement benefits	193	185	'	'
Derivatives	43	14	'	'
Other	492	492	'	'
Total noncurrent liabilities	3,359	3,305	'	'
Total liabilities and capitalization	13,599	13,502	'	'
FES | Affiliates	'	'	'	'
CURRENT LIABILITIES:	'	'	'	'
Short-term borrowings	$0	$431	'	'

Supplemental_Guarantor_Informa4

Supplemental Guarantor Information (Details 2) (USD $)	0 Months Ended	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Feb. 12, 2014	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Consolidated Statements of Cash Flows [Abstract]	'	'	'	'	'
Net cash provided from operating activities	'	'	'	$622	$493
New Financing-	'	'	'	'	'
Long-term debt	'	'	'	3,137	2,245
Short-term borrowings, net	'	'	'	0	1,285
Redemptions and Repayments-	'	'	'	'	'
Long-term debt	'	'	'	-925	-1,968
Short-term borrowings, net	'	'	'	-1,081	0
Tender premiums	'	'	'	0	-110
Other	'	'	'	-24	-16
Net cash provided from financing activities	'	'	'	805	976
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'	'	'
Property additions	'	-988	-586	-1,809	-1,412
Nuclear fuel	'	'	'	-58	-50
Proceeds from asset sales	394	'	'	394	0
Sales of investment securities held in trusts	'	'	'	1,164	1,177
Purchases of investment securities held in trusts	'	'	'	-1,221	-1,173
Other	'	'	'	8	-1
Net cash used for investing activities	'	'	'	-1,569	-1,570
Net change in cash and cash equivalents	'	'	'	-142	-101
Cash and cash equivalents at beginning of period	'	'	'	218	172
Cash and cash equivalents at end of period	'	76	71	76	71
FES	'	'	'	'	'
Consolidated Statements of Cash Flows [Abstract]	'	'	'	'	'
Net cash provided from operating activities	'	'	'	-202	-687
New Financing-	'	'	'	'	'
Long-term debt	'	'	'	0	'
Short-term borrowings, net	'	'	'	0	240
Equity contribution from parent	'	'	'	500	1,500
Redemptions and Repayments-	'	'	'	'	'
Long-term debt	'	'	'	-1	-770
Short-term borrowings, net	'	'	'	-74	'
Tender premiums	'	'	'	'	-67
Other	'	'	'	-1	-2
Net cash provided from financing activities	'	'	'	424	901
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'	'	'
Property additions	'	'	'	-4	-7
Nuclear fuel	'	'	'	0	0
Proceeds from asset sales	'	'	'	0	0
Sales of investment securities held in trusts	'	'	'	0	0
Purchases of investment securities held in trusts	'	'	'	0	0
Loans to affiliated companies, net	'	'	'	-218	-207
Other	'	'	'	0	0
Net cash used for investing activities	'	'	'	-222	-214
Net change in cash and cash equivalents	'	'	'	0	0
Cash and cash equivalents at beginning of period	'	'	'	0	0
Cash and cash equivalents at end of period	'	0	0	0	0
FGCO	'	'	'	'	'
Consolidated Statements of Cash Flows [Abstract]	'	'	'	'	'
Net cash provided from operating activities	'	'	'	147	390
New Financing-	'	'	'	'	'
Long-term debt	'	'	'	291	'
Short-term borrowings, net	'	'	'	172	112
Equity contribution from parent	'	'	'	0	0
Redemptions and Repayments-	'	'	'	'	'
Long-term debt	'	'	'	-258	-352
Short-term borrowings, net	'	'	'	0	'
Tender premiums	'	'	'	'	0
Other	'	'	'	-8	-3
Net cash provided from financing activities	'	'	'	197	-243
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'	'	'
Property additions	'	'	'	-74	-163
Nuclear fuel	'	'	'	0	0
Proceeds from asset sales	'	'	'	307	19
Sales of investment securities held in trusts	'	'	'	0	0
Purchases of investment securities held in trusts	'	'	'	0	0
Loans to affiliated companies, net	'	'	'	-581	-7
Other	'	'	'	4	3
Net cash used for investing activities	'	'	'	-344	-148
Net change in cash and cash equivalents	'	'	'	0	-1
Cash and cash equivalents at beginning of period	'	'	'	2	3
Cash and cash equivalents at end of period	'	2	2	2	2
Nuclear Generation Corp	'	'	'	'	'
Consolidated Statements of Cash Flows [Abstract]	'	'	'	'	'
Net cash provided from operating activities	'	'	'	149	308
New Financing-	'	'	'	'	'
Long-term debt	'	'	'	346	'
Short-term borrowings, net	'	'	'	0	0
Equity contribution from parent	'	'	'	0	0
Redemptions and Repayments-	'	'	'	'	'
Long-term debt	'	'	'	-416	-68
Short-term borrowings, net	'	'	'	-151	'
Tender premiums	'	'	'	'	0
Other	'	'	'	-1	0
Net cash provided from financing activities	'	'	'	-222	-68
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'	'	'
Property additions	'	'	'	-399	-180
Nuclear fuel	'	'	'	-57	-50
Proceeds from asset sales	'	'	'	0	0
Sales of investment securities held in trusts	'	'	'	707	487
Purchases of investment securities held in trusts	'	'	'	-736	-515
Loans to affiliated companies, net	'	'	'	558	18
Other	'	'	'	0	0
Net cash used for investing activities	'	'	'	73	-240
Net change in cash and cash equivalents	'	'	'	0	0
Cash and cash equivalents at beginning of period	'	'	'	0	0
Cash and cash equivalents at end of period	'	0	0	0	0
Eliminations	'	'	'	'	'
Consolidated Statements of Cash Flows [Abstract]	'	'	'	'	'
Net cash provided from operating activities	'	'	'	-11	-11
New Financing-	'	'	'	'	'
Long-term debt	'	'	'	0	'
Short-term borrowings, net	'	'	'	-172	-352
Equity contribution from parent	'	'	'	0	0
Redemptions and Repayments-	'	'	'	'	'
Long-term debt	'	'	'	11	11
Short-term borrowings, net	'	'	'	98	'
Tender premiums	'	'	'	'	0
Other	'	'	'	'	0
Net cash provided from financing activities	'	'	'	-63	-341
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'	'	'
Property additions	'	'	'	0	0
Nuclear fuel	'	'	'	0	0
Proceeds from asset sales	'	'	'	0	0
Sales of investment securities held in trusts	'	'	'	0	0
Purchases of investment securities held in trusts	'	'	'	0	0
Loans to affiliated companies, net	'	'	'	73	352
Other	'	'	'	1	0
Net cash used for investing activities	'	'	'	74	352
Net change in cash and cash equivalents	'	'	'	0	0
Cash and cash equivalents at beginning of period	'	'	'	0	0
Cash and cash equivalents at end of period	'	0	0	0	0
FES	'	'	'	'	'
Consolidated Statements of Cash Flows [Abstract]	'	'	'	'	'
Net cash provided from operating activities	'	'	'	83	0
New Financing-	'	'	'	'	'
Long-term debt	'	'	'	637	0
Short-term borrowings, net	'	'	'	0	0
Equity contribution from parent	'	'	'	500	1,500
Redemptions and Repayments-	'	'	'	'	'
Long-term debt	'	'	'	-664	-1,179
Short-term borrowings, net	'	'	'	-127	0
Tender premiums	'	'	'	0	-67
Other	'	'	'	-10	-5
Net cash provided from financing activities	'	'	'	336	249
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'	'	'
Property additions	'	'	'	-477	-350
Nuclear fuel	'	'	'	-57	-50
Proceeds from asset sales	307	'	'	307	19
Sales of investment securities held in trusts	'	'	'	707	487
Purchases of investment securities held in trusts	'	'	'	-736	-515
Loans to affiliated companies, net	'	'	'	-168	156
Other	'	'	'	5	3
Net cash used for investing activities	'	'	'	-419	-250
Net change in cash and cash equivalents	'	'	'	0	-1
Cash and cash equivalents at beginning of period	'	'	'	2	3
Cash and cash equivalents at end of period	'	$2	$2	$2	$2

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended				6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013		Dec. 31, 2013
Segment Financial Information	'		'		'		'		'
Revenues	$3,496		$3,507		$7,678		$7,227		'
Revenues	3,496	[1]	3,507	[1]	7,678	[1]	7,227	[1]	'
Depreciation, amortization and deferrals	322		372		588		724		'
Investment income (loss)	29		-15		51		3		'
Interest expense	262		256		527		514		'
Income taxes (benefits)	26		-62		74		52		'
Income (loss) from continuing operations	64		-168		186		24		'
Discontinued operations (Note 13)	0		4		86		8		'
NET INCOME (LOSS)	64		-164		272		32		'
Total assets	51,388		50,157		51,388		50,157		50,424
Total goodwill	6,418		6,447		6,418		6,447		6,418
Property additions	988		586		1,809		1,412		'
Intersegment Eliminations [Member]	'		'		'		'		'
Segment Financial Information	'		'		'		'		'
Revenues	0		0		0		0		'
Operating Segments [Member]	'		'		'		'		'
Segment Financial Information	'		'		'		'		'
Revenues	3,496		3,507		'		'		'
Regulated Distribution	'		'		'		'		'
Segment Financial Information	'		'		'		'		'
Revenues	2,065		2,038		4,615		4,247		'
Revenues	2,065		2,038		4,615		4,247		'
Depreciation, amortization and deferrals	180		220		311		422		'
Investment income (loss)	15		9		30		27		'
Interest expense	147		135		298		270		'
Income taxes (benefits)	77		108		202		234		'
Income (loss) from continuing operations	158		179		372		389		'
Discontinued operations (Note 13)	'		'		0		0		'
NET INCOME (LOSS)	158		179		372		389		'
Total assets	27,901		26,936		27,901		26,936		'
Total goodwill	5,092		5,025		5,092		5,025		'
Property additions	340		283		609		719		'
Regulated Distribution | Intersegment Eliminations [Member]	'		'		'		'		'
Segment Financial Information	'		'		'		'		'
Revenues	0		0		0		0		'
Regulated Transmission	'		'		'		'		'
Segment Financial Information	'		'		'		'		'
Revenues	191		179		373		355		'
Revenues	191		179		373		355		'
Depreciation, amortization and deferrals	33		31		66		60		'
Investment income (loss)	0		0		0		0		'
Interest expense	30		22		55		45		'
Income taxes (benefits)	32		30		62		61		'
Income (loss) from continuing operations	63		51		114		102		'
Discontinued operations (Note 13)	'		'		0		0		'
NET INCOME (LOSS)	63		51		114		102		'
Total assets	5,840		4,797		5,840		4,797		'
Total goodwill	526		526		526		526		'
Property additions	384		97		601		186		'
Regulated Transmission | Intersegment Eliminations [Member]	'		'		'		'		'
Segment Financial Information	'		'		'		'		'
Revenues	0		0		0		0		'
Competitive Energy Services	'		'		'		'		'
Segment Financial Information	'		'		'		'		'
Revenues	1,311		1,368		2,833		2,782		'
Revenues	1,493		1,544		3,264		3,174		'
Depreciation, amortization and deferrals	96		112		187		222		'
Investment income (loss)	21		-16		35		-6		'
Interest expense	48		61		94		134		'
Income taxes (benefits)	-65		-212		-138		-236		'
Income (loss) from continuing operations	-119		-343		-243		-385		'
Discontinued operations (Note 13)	'		'		86		8		'
NET INCOME (LOSS)	-119		-339		-157		-377		'
Total assets	17,137		17,910		17,137		17,910		'
Total goodwill	800		896		800		896		'
Property additions	240		185		558		468		'
Competitive Energy Services | Intersegment Eliminations [Member]	'		'		'		'		'
Segment Financial Information	'		'		'		'		'
Revenues	182		176		431		392		'
Other/Corporate	'		'		'		'		'
Segment Financial Information	'		'		'		'		'
Revenues	-31		-31		-71		-58		'
Revenues	-31		-31		-71		-58		'
Depreciation, amortization and deferrals	13		9		24		20		'
Investment income (loss)	2		2		5		3		'
Interest expense	30		38		73		65		'
Income taxes (benefits)	-30		8		-56		-11		'
Income (loss) from continuing operations	-26		-52		-58		-82		'
Discontinued operations (Note 13)	'		'		0		0		'
NET INCOME (LOSS)	-26		-52		-58		-82		'
Total assets	510		514		510		514		'
Total goodwill	0		0		0		0		'
Property additions	24		21		41		39		'
Other/Corporate | Intersegment Eliminations [Member]	'		'		'		'		'
Segment Financial Information	'		'		'		'		'
Revenues	0		0		0		0		'
Reconciling Adjustments	'		'		'		'		'
Segment Financial Information	'		'		'		'		'
Revenues	-40		-47		-72		-99		'
Revenues	-222		-223		-503		-491		'
Depreciation, amortization and deferrals	0		0		0		0		'
Investment income (loss)	-9		-10		-19		-21		'
Interest expense	7		0		7		0		'
Income taxes (benefits)	12		4		4		4		'
Income (loss) from continuing operations	-12		-3		1		0		'
Discontinued operations (Note 13)	'		'		0		0		'
NET INCOME (LOSS)	-12		-3		1		0		'
Total assets	0		0		0		0		'
Total goodwill	0		0		0		0		'
Property additions	0		0		0		0		'
Reconciling Adjustments | Intersegment Eliminations [Member]	'		'		'		'		'
Segment Financial Information	'		'		'		'		'
Revenues	($182)		($176)		($431)		($392)		'
[1]	Includes excise tax collections of $99 million and $107 million in the three months ended JuneB 30, 2014 and 2013, respectively, and $216 million and $229 million in the six months ended JuneB 30, 2014 and 2013, respectively.

Segment_Information_Details_Te

Segment Information (Details Textuals) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
			Segments
Segment Reporting Information [Line Items]	'	'	'	'
Number of reportable operating segments	'	'	3	'
Severance Costs	$7	'	'	'
Impairments of long-lived assets	'	473	0	473
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	'	65,000	'
Megawatts of net demonstrated capacity of competitive segment	3,790	'	3,790	'
Competitive Energy Services	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Megawatts of net demonstrated capacity of competitive segment	14,000	'	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	'	885	'
Deferred Advertising Costs	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Impairments of long-lived assets	$22	'	'	'
Minimum | Competitive Energy Services | Governmental Aggregation	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Segment Reporting, Targeted Sales Portfolio	10,000,000	'	10,000,000	'
Minimum | Competitive Energy Services | POLR	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Segment Reporting, Targeted Sales Portfolio	0	'	0	'
Minimum | Competitive Energy Services | Large Commercial and Industrial	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Segment Reporting, Targeted Sales Portfolio	0	'	0	'
Minimum | Competitive Energy Services | Block Wholesale	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Segment Reporting, Targeted Sales Portfolio	10,000,000	'	10,000,000	'
Minimum | Competitive Energy Services | Spot Wholesale	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Segment Reporting, Targeted Sales Portfolio	10,000,000	'	10,000,000	'
Maximum | Competitive Energy Services | Governmental Aggregation	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Segment Reporting, Targeted Sales Portfolio	15,000,000	'	15,000,000	'
Maximum | Competitive Energy Services | POLR	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Segment Reporting, Targeted Sales Portfolio	10,000,000	'	10,000,000	'
Maximum | Competitive Energy Services | Large Commercial and Industrial	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Segment Reporting, Targeted Sales Portfolio	20,000,000	'	20,000,000	'
Maximum | Competitive Energy Services | Block Wholesale	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Segment Reporting, Targeted Sales Portfolio	20,000,000	'	20,000,000	'
Maximum | Competitive Energy Services | Spot Wholesale	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Segment Reporting, Targeted Sales Portfolio	20,000,000	'	20,000,000	'

Discontinued_Operations_Detail

Discontinued Operations (Details) (USD $)	0 Months Ended	3 Months Ended	6 Months Ended			0 Months Ended	3 Months Ended	6 Months Ended
In Millions, unless otherwise specified	Feb. 12, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Feb. 12, 2014	Feb. 12, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Feb. 12, 2014	Sep. 04, 2013
						FES	FES	FES	FES	FES	Pennsylvania, Virginia and West Virginia
											hydroelectric_power_station
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Application to sell hydroelectric power stations	'	'	'	'	'	'	'	'	'	'	11
Proceeds from asset sales	$394	'	$394	$0	'	$307	'	$307	$19	'	'
Carrying value of assets sold	'	'	'	'	235	'	'	'	'	122	'
Discontinued operations, goodwill	'	'	'	'	29	'	'	'	'	1	'
Pre-tax income from discontinued operation	'	8	155	14	'	'	5	186	10	'	'
Pre-tax gain on sale of assets	'	'	142	'	'	'	'	177	'	'	'
Revenues from discontinued operations	'	$7	'	$13	'	'	$6	$5	$12	'	'

Impairment_of_Longlived_Assets2

Impairment of Long-lived Assets (Details) (USD $)	3 Months Ended	6 Months Ended		3 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2013	Jul. 08, 2013	Jul. 08, 2013
				Inventories	Hatfield's Ferry, Units 1-3 [Member]	Mitchell, Units 2-3 [Member]
					MW	MW
Schedule of Generating Plant Retirements [Line Items]	'	'	'	'	'	'
Megawatt capacity of plants expected to be closed	'	'	'	'	1,710	370
Impairments of long-lived assets	$473	$0	$473	$13	'	'