FirstEnergy (FE) 10-Q 30 Jul 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - Jun. 30, 2015 - shares	Total
Entity Information [Line Items]
Entity Registrant Name	FIRSTENERGY CORP
Entity Central Index Key	1,031,296
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding	422,453,361
FES
Entity Information [Line Items]
Entity Registrant Name	FirstEnergy Solutions Corp.
Entity Central Index Key	1,407,703
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
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 Inco

Consolidated Statements of Income (FirstEnergy Corp.) - USD ($) shares in Millions, $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
REVENUES:
Electric utilities		$ 2,508	$ 2,256	$ 5,308	$ 4,988
Unregulated businesses		957	1,240	2,054	2,690
Total revenues	[1]	3,465	3,496	7,362	7,678
OPERATING EXPENSES:
Fuel		383	550	896	1,167
Purchased power		989	1,083	2,102	2,538
Other operating expenses		916	1,021	1,973	2,203
Provision for depreciation		322	302	641	596
Amortization (deferral) of regulatory assets, net		59	20	91	(8)
General taxes		242	228	511	499
Total operating expenses		2,911	3,204	6,214	6,995
OPERATING INCOME (LOSS)		554	292	1,148	683
OTHER INCOME (EXPENSE):
Loss on debt redemptions		0	(1)	0	(8)
Investment income		(3)	29	14	51
Interest expense		(282)	(262)	(561)	(527)
Capitalized financing costs		33	32	67	61
Total other income (expense)		(252)	(202)	(480)	(423)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)		302	90	668	260
INCOME TAXES (BENEFITS)		115	26	259	74
INCOME (LOSS) FROM CONTINUING OPERATIONS		187	64	409	186
Discontinued operations (net of income taxes of $69 respectively)		0	0	0	86
NET INCOME (LOSS)		$ 187	$ 64	$ 409	$ 272
EARNINGS PER SHARE OF COMMON STOCK:
Basic - Continuing Operations, in dollars per share		$ 0.44	$ 0.16	$ 0.97	$ 0.45
Basic - Discontinued Operations, in dollars per share		0	0	0	0.20
Basic - Net Earnings per Basic Share to FirstEnergy Corp., in dollars per share		0.44	0.16	0.97	0.65
Diluted - Continuing Operations, in dollars per share		0.44	0.15	0.97	0.45
Diluted - Discontinued Operations, in dollars per share		0	0	0	0.20
Diluted - Net Earnings per Diluted Share Available to FirstEnergy Corp., in dollars per share		$ 0.44	$ 0.15	$ 0.97	$ 0.65
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic, in shares		422	420	422	419
Diluted, in shares		423	421	423	420
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share		$ 0	$ 0	$ 0.72	$ 0.72
[1]	Includes excise tax collections of $96 million and $99 million the three months ended June 30, 2015 and 2014, respectively, and $211 million and $216 million in the six months ended June 30, 2015 and 2014, respectively.

Consolidated Statements of Inc3

Consolidated Statements of Income (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Income Statement [Abstract]
Tax effect of discontinued operations				$ 69
Excise taxes collected	$ 96	$ 99	$ 211	$ 216

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (FirstEnergy Corp.) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Statement of Comprehensive Income [Abstract]
NET INCOME (LOSS)	$ 187	$ 64	$ 409	$ 272
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(32)	(42)	(63)	(84)
Amortized (gains) losses on derivative hedges	1	(1)	2	(1)
Change in unrealized gain on available-for-sale securities	(14)	30	(10)	51
Other comprehensive income (loss)	(45)	(13)	(71)	(34)
Income tax benefits on other comprehensive loss	(17)	(6)	(27)	(14)
Other comprehensive income (loss), net of tax	(28)	(7)	(44)	(20)
COMPREHENSIVE INCOME (LOSS)	$ 159	$ 57	$ 365	$ 252

Consolidated Balance Sheets (Fi

Consolidated Balance Sheets (FirstEnergy Corp.) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 94	$ 85
Receivables-
Customers, net of allowance for uncollectible accounts of $62 in 2015 and $59 in 2014	1,590	1,554
Other, net of allowance for uncollectible accounts of $5 in 2015 and 2014	181	225
Materials and supplies	792	817
Prepaid taxes	235	128
Derivatives	171	159
Accumulated deferred income taxes	743	518
Collateral	141	230
Other	166	160
Total current assets	4,113	3,876
PROPERTY, PLANT AND EQUIPMENT:
In service	48,862	47,484
Less - Accumulated provision for depreciation	14,728	14,150
Property, plant and equipment in service net of accumulated provision for depreciation	34,134	33,334
Construction work in progress	2,282	2,449
Total net property, plant and equipment	36,416	35,783
INVESTMENTS:
Nuclear plant decommissioning trusts	2,348	2,341
Other	886	881
Total other property and investments	3,234	3,222
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418
Regulatory assets	1,523	1,411
Other	1,301	1,456
Total deferred charges and other assets	9,242	9,285
Total assets	53,005	52,166
CURRENT LIABILITIES:
Currently payable long-term debt	1,292	804
Short-term borrowings	2,908	1,799
Accounts payable	1,034	1,279
Accrued taxes	467	490
Accrued compensation and benefits	323	329
Derivatives	160	167
Other	605	693
Total current liabilities	6,789	5,561
Common stockholders' equity-
Common stock, $0.10 par value, authorized 490,000,000 shares - 422,453,361 and 421,102,570 shares outstanding as of June 30, 2015 and December 31, 2014, respectively	42	42
Other paid-in capital	9,895	9,847
Accumulated other comprehensive income	202	246
Retained earnings	2,391	2,285
Total common stockholders' equity	12,530	12,420
Noncontrolling interest	1	2
Total equity	12,531	12,422
Long-term debt and other long-term obligations	18,570	19,176
Total capitalization	31,101	31,598
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	7,485	7,057
Retirement benefits	3,836	3,932
Asset retirement obligations	1,411	1,387
Deferred gain on sale and leaseback transaction	807	824
Adverse power contract liability	203	217
Other	1,373	1,590
Total noncurrent liabilities	$ 15,115	$ 15,007
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	$ 53,005	$ 52,166

Consolidated Balance Sheets (F6

Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Common stockholders' equity-
Common stock, par value (in dollars per share)	$ 0.1	$ 0.1
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	422,453,361	421,102,570
Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 62	$ 59
Other [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 5	$ 5

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (FirstEnergy Corp.) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$ 409	$ 272
Adjustments to reconcile net income to net cash from operating activities-
Income from discontinued operations	0	(86)
Provision for depreciation	641	596
Amortization (deferral) of regulatory assets, net	91	(8)
Nuclear fuel amortization	106	98
Amortization of debt related costs	20	28
Deferred purchased power and other costs	(45)	(47)
Deferred income taxes and investment tax credits, net	219	159
Investment impairments	24	3
Deferred costs on sale and leaseback transaction, net	24	24
Amortization of customer intangibles and deferred advertising expense	11	39
Retirement benefits	(16)	(42)
Pension trust contributions	(143)	0
Commodity derivative transactions, net	(7)	40
Loss on debt redemptions	0	8
Lease payments on sale and leaseback transaction	(102)	(100)
Impairment of long lived assets	16	0
Changes in current assets and liabilities-
Receivables	8	(44)
Materials and supplies	0	(50)
Prepayments and other current assets	(116)	(20)
Accounts payable	(245)	103
Accrued taxes	(23)	(159)
Accrued compensation and benefits	12	(70)
Other current liabilities	2	26
Cash collateral, net	38	(127)
Other	66	(21)
Net cash provided from operating activities	990	622
New Financing-
Long-term debt	200	3,137
Short-term borrowings, net	1,109	0
Redemptions and Repayments-
Long-term debt	(292)	(925)
Short-term borrowings, net	0	(1,081)
Common stock dividend payments	(303)	(302)
Other	(2)	(24)
Net cash provided from (used for) financing activities	712	805
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,486)	(1,809)
Nuclear fuel	(97)	(58)
Proceeds from asset sales	10	394
Sales of investment securities held in trusts	819	1,164
Purchases of investment securities held in trusts	(881)	(1,221)
Asset removal costs	(67)	(47)
Other	9	8
Net cash provided from (used for) investing activities	(1,693)	(1,569)
Net change in cash and cash equivalents	9	(142)
Cash and cash equivalents at beginning of period	85	218
Cash and cash equivalents at end of period	$ 94	$ 76

Consolidated Statements of Inc8

Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
REVENUES:
Electric sales		$ 957	$ 1,240	$ 2,054	$ 2,690
Total revenues	[1]	3,465	3,496	7,362	7,678
OPERATING EXPENSES:
Fuel		383	550	896	1,167
Purchased power		989	1,083	2,102	2,538
Other operating expenses		916	1,021	1,973	2,203
Provision for depreciation		322	302	641	596
General taxes		242	228	511	499
Total operating expenses		2,911	3,204	6,214	6,995
OPERATING INCOME (LOSS)		554	292	1,148	683
OTHER INCOME (EXPENSE):
Loss on debt redemptions		0	(1)	0	(8)
Investment income		(3)	29	14	51
Interest expense		(282)	(262)	(561)	(527)
Capitalized interest		33	32	67	61
Total other income (expense)		(252)	(202)	(480)	(423)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)		302	90	668	260
INCOME TAXES (BENEFITS)		115	26	259	74
INCOME (LOSS) FROM CONTINUING OPERATIONS		187	64	409	186
Discontinued operations (net of income taxes of $70 respectively)		0	0	0	86
NET INCOME (LOSS)		187	64	409	272
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME (LOSS)		187	64	409	272
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(32)	(42)	(63)	(84)
Amortized gains on derivative hedges		1	(1)	2	(1)
Change in unrealized gain on available-for-sale securities		(14)	30	(10)	51
Other comprehensive income (loss)		(45)	(13)	(71)	(34)
Income taxes (benefits) on other comprehensive income (loss)		(17)	(6)	(27)	(14)
Other comprehensive income (loss), net of tax		(28)	(7)	(44)	(20)
COMPREHENSIVE INCOME (LOSS)		159	57	365	252
FES
REVENUES:
Other		48	42	95	82
Total revenues		1,119	1,452	2,496	3,281
OPERATING EXPENSES:
Fuel		191	334	421	653
Other operating expenses		353	468	766	920
Provision for depreciation		81	79	161	153
General taxes		25	29	54	68
Total operating expenses		1,119	1,603	2,484	3,580
OPERATING INCOME (LOSS)		0	(151)	12	(299)
OTHER INCOME (EXPENSE):
Loss on debt redemptions		0	0	0	(5)
Investment income		1	24	14	44
Miscellaneous income		4	4	4	4
Capitalized interest		9	8	18	20
Total other income (expense)		(25)	(3)	(42)	(14)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)		(25)	(154)	(30)	(313)
INCOME TAXES (BENEFITS)		(4)	(67)	(6)	(123)
INCOME (LOSS) FROM CONTINUING OPERATIONS		(21)	(87)	(24)	(190)
Discontinued operations (net of income taxes of $70 respectively)		0	0	0	116
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME (LOSS)		(21)	(87)	(24)	(74)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(4)	(5)	(8)	(10)
Amortized gains on derivative hedges		(1)	(3)	(2)	(5)
Change in unrealized gain on available-for-sale securities		(12)	25	(9)	44
Other comprehensive income (loss)		(17)	17	(19)	29
Income taxes (benefits) on other comprehensive income (loss)		(6)	7	(7)	11
Other comprehensive income (loss), net of tax		(11)	10	(12)	18
COMPREHENSIVE INCOME (LOSS)		(32)	(77)	(36)	(56)
FES | Affiliates
REVENUES:
Electric sales		157	176	412	525
OPERATING EXPENSES:
Purchased power		77	75	147	139
OTHER INCOME (EXPENSE):
Interest expense		(2)	(2)	(4)	(4)
FES | Non-Affiliates
REVENUES:
Electric sales		914	1,234	1,989	2,674
OPERATING EXPENSES:
Purchased power		392	618	935	1,647
OTHER INCOME (EXPENSE):
Interest expense		$ (37)	$ (37)	$ (74)	$ (73)
[1]	Includes excise tax collections of $96 million and $99 million the three months ended June 30, 2015 and 2014, respectively, and $211 million and $216 million in the six months ended June 30, 2015 and 2014, respectively.

Consolidated Statements of Inc9

Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) (Parenthetical) $ in Millions	6 Months Ended
	Jun. 30, 2014USD ($)
Tax effect of discontinued operations	$ 69
FES
Tax effect of discontinued operations	$ 70

Consolidated Balance Sheets (10

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 94	$ 85
Receivables-
Customers, net of allowance for uncollectible accounts of $16 in 2015 and $18 in 2014	1,590	1,554
Other, net of allowance for uncollectible accounts of $3 in 2015 and 2014	181	225
Materials and supplies	792	817
Derivatives	171	159
Collateral	141	230
Prepayments and other	166	160
Total current assets	4,113	3,876
PROPERTY, PLANT AND EQUIPMENT:
In service	48,862	47,484
Less - Accumulated provision for depreciation	14,728	14,150
Property, plant and equipment in service net of accumulated provision for depreciation	34,134	33,334
Construction work in progress	2,282	2,449
Total net property, plant and equipment	36,416	35,783
INVESTMENTS:
Nuclear plant decommissioning trusts	2,348	2,341
Other	886	881
Total other property and investments	3,234	3,222
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418
Other	1,301	1,456
Total deferred charges and other assets	9,242	9,285
Total assets	53,005	52,166
CURRENT LIABILITIES:
Currently payable long-term debt	1,292	804
Other	2,908	1,799
Accounts payable-
Accrued taxes	467	490
Derivatives	160	167
Other	605	693
Total current liabilities	6,789	5,561
Common stockholders' equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of June 30, 2015 and December 31, 2014	42	42
Accumulated other comprehensive income	202	246
Retained earnings	2,391	2,285
Total common stockholders' equity	12,530	12,420
Long-term debt and other long-term obligations	18,570	19,176
Total capitalization	31,101	31,598
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	807	824
Accumulated deferred income taxes	7,485	7,057
Retirement benefits	3,836	3,932
Asset retirement obligations	1,411	1,387
Other	1,373	1,590
Total noncurrent liabilities	$ 15,115	$ 15,007
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	$ 53,005	$ 52,166
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2
Receivables-
Customers, net of allowance for uncollectible accounts of $16 in 2015 and $18 in 2014	325	415
Affiliated companies	403	525
Other, net of allowance for uncollectible accounts of $3 in 2015 and 2014	57	107
Notes receivable from affiliated companies	13	0
Materials and supplies	476	492
Derivatives	158	147
Collateral	140	229
Prepayments and other	139	95
Total current assets	1,713	2,012
PROPERTY, PLANT AND EQUIPMENT:
In service	13,978	13,596
Less - Accumulated provision for depreciation	5,431	5,208
Property, plant and equipment in service net of accumulated provision for depreciation	8,547	8,388
Construction work in progress	917	1,010
Total net property, plant and equipment	9,464	9,398
INVESTMENTS:
Nuclear plant decommissioning trusts	1,365	1,365
Other	10	10
Total other property and investments	1,375	1,375
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	70	78
Goodwill	23	23
Property taxes	19	41
Unamortized sale and leaseback costs	266	217
Derivatives	104	52
Other	117	114
Total deferred charges and other assets	599	525
Total assets	13,151	13,310
CURRENT LIABILITIES:
Currently payable long-term debt	683	506
Other	258	99
Accounts payable-
Affiliated companies	297	416
Other	117	248
Accrued taxes	79	102
Derivatives	158	166
Other	163	184
Total current liabilities	1,755	1,756
Common stockholders' equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of June 30, 2015 and December 31, 2014	3,599	3,594
Accumulated other comprehensive income	45	57
Retained earnings	1,910	1,934
Total common stockholders' equity	5,554	5,585
Long-term debt and other long-term obligations	2,359	2,608
Total capitalization	7,913	8,193
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	807	824
Accumulated deferred income taxes	588	511
Retirement benefits	331	324
Asset retirement obligations	850	841
Derivatives	74	14
Other	833	847
Total noncurrent liabilities	$ 3,483	$ 3,361
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	$ 13,151	$ 13,310
FES | Affiliated Entity [Member]
CURRENT LIABILITIES:
Affiliated companies	$ 0	$ 35

Consolidated Balance Sheets (11

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions, None in scaling factor is -9223372036854775296	Jun. 30, 2015	Dec. 31, 2014
Common stockholders' equity-
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	422,453,361	421,102,570
Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 62	$ 59
Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 5	$ 5
FES
Common stockholders' equity-
Common stock, no par value
Common stock, shares authorized	750	750
Common stock, shares outstanding	7	7
FES | Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 16	$ 18
FES | Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 3	$ 3

Consolidated Statements of Ca12

Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$ 409	$ 272
Adjustments to reconcile net income (loss) to net cash from operating activities-
Income from discontinued operations	0	(86)
Provision for depreciation	641	596
Nuclear fuel amortization	106	98
Deferred costs on sale and leaseback transaction, net	24	24
Amortization of customer intangibles and deferred advertising expense	11	39
Deferred income taxes and investment tax credits, net	219	159
Investment impairments	24	3
Commodity derivative transactions, net	(7)	40
Lease payments on sale and leaseback transaction	(102)	(100)
Loss on debt redemptions	0	8
Impairment of long lived assets	16	0
Changes in current assets and liabilities-
Receivables	8	(44)
Materials and supplies	0	(50)
Prepayments and other current assets	(116)	(20)
Accounts payable	(245)	103
Accrued taxes	(23)	(159)
Accrued compensation and benefits	12	(70)
Other current liabilities	2	26
Cash collateral, net	38	(127)
Other	66	(21)
Net cash provided from operating activities	990	622
New financing-
Long-term debt	200	3,137
Short-term borrowings, net	1,109	0
Redemptions and Repayments-
Long-term debt	(292)	(925)
Short-term borrowings, net	0	1,081
Other	(2)	(24)
Net cash provided from (used for) financing activities	712	805
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,486)	(1,809)
Nuclear fuel	(97)	(58)
Proceeds from asset sales	10	394
Sales of investment securities held in trusts	819	1,164
Purchases of investment securities held in trusts	(881)	(1,221)
Other	9	8
Net cash provided from (used for) investing activities	(1,693)	(1,569)
Net change in cash and cash equivalents	9	(142)
Cash and cash equivalents at beginning of period	85	218
Cash and cash equivalents at end of period	94	76
FES
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	(24)	(74)
Adjustments to reconcile net income (loss) to net cash from operating activities-
Income from discontinued operations	0	(116)
Provision for depreciation	161	153
Nuclear fuel amortization	106	98
Deferred costs on sale and leaseback transaction, net	24	24
Amortization of customer intangibles and deferred advertising expense	11	39
Deferred income taxes and investment tax credits, net	50	(23)
Investment impairments	22	3
Commodity derivative transactions, net	(7)	40
Lease payments on sale and leaseback transaction	(102)	(100)
Loss on debt redemptions	0	5
Impairment of long lived assets	16	0
Changes in current assets and liabilities-
Receivables	277	550
Materials and supplies	(9)	(18)
Prepayments and other current assets	(9)	5
Accounts payable	(259)	(339)
Accrued taxes	(23)	(57)
Accrued compensation and benefits	1	(7)
Other current liabilities	17	5
Cash collateral, net	89	(117)
Other	2	12
Net cash provided from operating activities	343	83
New financing-
Long-term debt	0	637
Short-term borrowings, net	124	0
Equity contribution from parent	0	500
Redemptions and Repayments-
Long-term debt	(69)	(664)
Short-term borrowings, net	0	127
Other	(2)	(10)
Net cash provided from (used for) financing activities	53	336
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(264)	(477)
Nuclear fuel	(97)	(57)
Proceeds from asset sales	3	307
Sales of investment securities held in trusts	376	707
Purchases of investment securities held in trusts	(404)	(736)
Loans to affiliated companies, net	(13)	(168)
Other	3	5
Net cash provided from (used for) investing activities	(396)	(419)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	2	2
Cash and cash equivalents at end of period	$ 2	$ 2

Organization and Basis of Prese

Organization and Basis of Presentation	6 Months Ended
	Jun. 30, 2015
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. FE’s principal business is the holding, directly or indirectly, of all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, FES and its principal subsidiaries (FG and NG), AE Supply, MP, PE, WP, FET and its principal subsidiaries (ATSI and TrAIL), and AESC. In addition, FE holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., GPU Nuclear, Inc., and AE Ventures, Inc. FirstEnergy and its subsidiaries are principally involved in the generation, transmission, and distribution of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving six million customers in the Midwest and Mid-Atlantic regions. Its generation subsidiaries control nearly 17,000 MW of capacity from a diverse mix of non-emitting nuclear, scrubbed coal, natural gas, hydroelectric and other renewables. FirstEnergy’s transmission operations include approximately 24,000 miles of lines and three regional transmission operation centers. 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, 2014 . 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 necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued. FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. 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, 2015 and 2014, capitalized financing costs on FirstEnergy's Consolidated Statements of Income includes $14 million of allowance for equity funds used during construction for both periods and $19 million and $18 million , respectively, of capitalized interest. For the six months ended June 30, 2015 and 2014, capitalized financing costs on FirstEnergy's Consolidated Statements of Income includes $30 million and $21 million , respectively, of allowance for equity funds used during construction, and $37 million and $40 million , respectively, of capitalized interest. During the second quarter of 2015, FES recognized an impairment of $16 million associated with certain transportation equipment. The charge is classified as a component of Other operating expenses in the Consolidated Statement of Income. New Accounting Pronouncements In May 2014, the FASB issued "Revenue from Contracts with Customers", requiring entities to recognize revenue by applying a five-step model in accordance with the core principle to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue recognition are expanded. This standard is currently 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. In July 2015, the FASB voted to proceed with a one-year deferral of the revenue recognition standard for all entities, with early adoption as of the original effective date permitted. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In February 2015, the FASB issued, "Consolidations: Amendments to the Consolidation Analysis", which amends current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate whether an entity should be consolidated. This standard is effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. A reporting entity must apply the amendments using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments retrospectively. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In April 2015, the FASB issued, "Simplifying the Presentation of Debt Issuance Costs", which requires debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. The guidance is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Upon adoption, an entity must apply the new guidance retrospectively to all prior periods presented in the financial statements. FirstEnergy does not expect this amendment to have a material effect on its financial statements.

Earnings Per Share of Common St

Earnings Per Share of Common Stock	6 Months Ended
	Jun. 30, 2015
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 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 per Share of Common Stock 2015 2014 2015 2014 Income from continuing operations $ 187 $ 64 $ 409 $ 186 Discontinued operations (Note 13) — — — 86 Net income $ 187 $ 64 $ 409 $ 272 Weighted average number of basic shares outstanding 422 420 422 419 Assumed exercise of dilutive stock options and awards (1) 1 1 1 1 Weighted average number of diluted shares outstanding 423 421 423 420 Earnings per share: Basic earnings per share: Income from continuing operations $ 0.44 $ 0.16 $ 0.97 $ 0.45 Discontinued operations (Note 13) — — — 0.20 Net earnings per basic share $ 0.44 $ 0.16 $ 0.97 $ 0.65 Diluted earnings per share: Income from continuing operations $ 0.44 $ 0.15 $ 0.97 $ 0.45 Discontinued operations (Note 13) — — — 0.20 Net earnings per diluted share $ 0.44 $ 0.15 $ 0.97 $ 0.65 (1) For both the three months ended June 30, 2015 and June 30, 2014 , one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the six months ended June 30, 2015 and June 30, 2014 , one million and two million shares, respectively, were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

Pension and Other Postemploymen

Pension and Other Postemployment Benefits	6 Months Ended
	Jun. 30, 2015
Compensation and Retirement Disclosure [Abstract]
PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS	PENSION AND OTHER POSTEMPLOYMENT BENEFITS In March 2015, FirstEnergy contributed $143 million to its qualified pension plan. The components of the consolidated net periodic cost (credits) for pension and OPEB (including amounts capitalized) were as follows: Components of Net Periodic Benefit Costs (Credits) Pension OPEB For the Three Months Ended June 30, 2015 2014 2015 2014 (In millions) Service costs $ 48 $ 41 $ 1 $ 2 Interest costs 96 101 7 10 Expected return on plan assets (111 ) (115 ) (8 ) (8 ) Amortization of prior service costs (credits) 2 2 (34 ) (44 ) Net periodic costs (credits) $ 35 $ 29 $ (34 ) $ (40 ) Components of Net Periodic Benefit Costs (Credits) Pensions OPEB For the Six Months Ended June 30, 2015 2014 2015 2014 (In millions) Service costs $ 96 $ 83 $ 2 $ 4 Interest costs 192 201 14 20 Expected return on plan assets (222 ) (230 ) (16 ) (16 ) Amortization of prior service costs (credits) 4 4 (67 ) (88 ) Net periodic costs (credits) $ 70 $ 58 $ (67 ) $ (80 ) FES' share of the net periodic pension and OPEB costs (credits) were as follows: Pension OPEB 2015 2014 2015 2014 (In millions) For the Three Months Ended June 30, $ 4 $ 4 $ (5 ) $ (5 ) For the Six Months Ended June 30, 8 8 (10 ) (10 ) Pension and OPEB obligations are allocated to FE's subsidiaries, including FES, employing the plan participants. The net periodic pension and OPEB costs (credits) (net of amounts capitalized) recognized in earnings by FE and FES were as follows: Net Periodic Benefit Expense (Credit) Pension OPEB For the Three Months Ended June 30, 2015 2014 2015 2014 (In millions) FirstEnergy $ 24 $ 21 $ (22 ) $ (27 ) FES 4 4 (4 ) (5 ) Net Periodic Benefit Expense (Credit) Pensions OPEB For the Six Months Ended June 30, 2015 2014 2015 2014 (In millions) FirstEnergy $ 49 $ 42 $ (45 ) $ (54 ) FES 8 8 (8 ) (9 )

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	6 Months Ended
	Jun. 30, 2015
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, 2015 and 2014 , for FirstEnergy 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, 2015 $ (36 ) $ 28 $ 238 $ 230 Other comprehensive loss before reclassifications — (7 ) — (7 ) Amounts reclassified from AOCI 1 (7 ) (32 ) (38 ) Other comprehensive income (loss) 1 (14 ) (32 ) (45 ) Income tax (benefits) on other comprehensive income (loss) 1 (5 ) (13 ) (17 ) Net other comprehensive loss — (9 ) (19 ) (28 ) AOCI Balance as of June 30, 2015 $ (36 ) $ 19 $ 219 $ 202 AOCI Balance as of April 1, 2014 $ (36 ) $ 22 $ 285 $ 271 Other comprehensive income before reclassifications — 49 — 49 Amounts reclassified from AOCI (1 ) (19 ) (42 ) (62 ) Other comprehensive income (loss) (1 ) 30 (42 ) (13 ) Income tax (benefits) on other comprehensive income (loss) (1 ) 11 (16 ) (6 ) Net other comprehensive income (loss) — 19 (26 ) (7 ) AOCI Balance as of June 30, 2014 $ (36 ) $ 41 $ 259 $ 264 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, 2015 $ (37 ) $ 25 $ 258 $ 246 Other comprehensive income before reclassifications — 7 — 7 Amounts reclassified from AOCI 2 (17 ) (63 ) (78 ) Other comprehensive income (loss) 2 (10 ) (63 ) (71 ) Income tax (benefits) on other comprehensive income (loss) 1 (4 ) (24 ) (27 ) Net other comprehensive income (loss) 1 (6 ) (39 ) (44 ) AOCI Balance as of June 30, 2015 $ (36 ) $ 19 $ 219 $ 202 AOCI Balance as of January 1, 2014 $ (36 ) $ 9 $ 311 $ 284 Other comprehensive income before reclassifications — 84 — 84 Amounts reclassified from AOCI (1 ) (33 ) (84 ) (118 ) Other comprehensive income (loss) (1 ) 51 (84 ) (34 ) Income tax (benefits) on other comprehensive income (loss) (1 ) 19 (32 ) (14 ) Net other comprehensive income (loss) — 32 (52 ) (20 ) AOCI Balance as of June 30, 2014 $ (36 ) $ 41 $ 259 $ 264 The following amounts were reclassified from AOCI for FirstEnergy in the three and six months ended June 30, 2015 and 2014 : Three Months Ended June 30, Six Months Ended June 30 Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (2) 2015 2014 2015 2014 (In millions) Gains & losses on cash flow hedges Commodity contracts $ (1 ) $ (3 ) $ (2 ) $ (5 ) Other operating expenses Long-term debt 2 2 4 4 Interest expense 1 (1 ) 2 (1 ) Total before taxes (1 ) 1 (1 ) 1 Income taxes $ — $ — $ 1 $ — Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (7 ) $ (19 ) $ (17 ) $ (33 ) Investment income (loss) 2 7 6 12 Income taxes $ (5 ) $ (12 ) $ (11 ) $ (21 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (32 ) $ (42 ) $ (63 ) $ (84 ) (1) 13 16 24 32 Income taxes $ (19 ) $ (26 ) $ (39 ) $ (52 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI. The changes in AOCI, net of tax, in the three and six months ended June 30, 2015 and 2014 , for FES are shown in the following tables: 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, 2015 $ (8 ) $ 24 $ 40 $ 56 Other comprehensive loss before reclassifications — (7 ) — (7 ) Amounts reclassified from AOCI (1 ) (5 ) (4 ) (10 ) Other comprehensive loss (1 ) (12 ) (4 ) (17 ) Income tax benefits on other comprehensive loss — (4 ) (2 ) (6 ) Net other comprehensive loss (1 ) (8 ) (2 ) (11 ) AOCI Balance as of June 30, 2015 $ (9 ) $ 16 $ 38 $ 45 AOCI Balance as of April 1, 2014 $ (2 ) $ 20 $ 44 $ 62 Other comprehensive income before reclassifications — 43 — 43 Amounts reclassified from AOCI (3 ) (18 ) (5 ) (26 ) Other comprehensive income (loss) (3 ) 25 (5 ) 17 Income tax (benefits) on other comprehensive income (loss) — 9 (2 ) 7 Net other comprehensive income (loss) (3 ) 16 (3 ) 10 AOCI Balance as of June 30, 2014 $ (5 ) $ 36 $ 41 $ 72 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, 2015 $ (7 ) $ 21 $ 43 $ 57 Other comprehensive income before reclassifications — 6 — 6 Amounts reclassified from AOCI (2 ) (15 ) (8 ) (25 ) Other comprehensive loss (2 ) (9 ) (8 ) (19 ) Income tax benefits on other comprehensive loss — (4 ) (3 ) (7 ) Net other comprehensive loss (2 ) (5 ) (5 ) (12 ) AOCI Balance as of June 30, 2015 $ (9 ) $ 16 $ 38 $ 45 AOCI Balance as of January 1, 2014 $ (1 ) $ 8 $ 47 $ 54 Other comprehensive income before reclassifications — 76 — 76 Amounts reclassified from AOCI (5 ) (32 ) (10 ) (47 ) Other comprehensive income (loss) (5 ) 44 (10 ) 29 Income tax (benefits) on other comprehensive income (loss) (1 ) 16 (4 ) 11 Net other comprehensive income (loss) (4 ) 28 (6 ) 18 AOCI Balance as of June 30, 2014 $ (5 ) $ 36 $ 41 $ 72 The following amounts were reclassified from AOCI for FES in the three and six months ended June 30, 2015 and 2014 : Three Months Ended June 30, Six Months Ended June 30, Affected Line Item in Consolidated Statements of Operations Reclassifications from AOCI (2) 2015 2014 2015 2014 (In millions) Gains & losses on cash flow hedges Commodity contracts $ (1 ) $ (3 ) $ (2 ) $ (5 ) Other operating expenses — 1 — 2 Income tax benefits $ (1 ) $ (2 ) $ (2 ) $ (3 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (5 ) $ (18 ) $ (15 ) $ (32 ) Investment income 2 6 6 11 Income tax benefits $ (3 ) $ (12 ) $ (9 ) $ (21 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (4 ) $ (5 ) $ (8 ) $ (10 ) (1) 2 2 3 4 Income tax benefits $ (2 ) $ (3 ) $ (5 ) $ (6 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Operations from AOCI.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2015
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES FirstEnergy’s and FES’ interim effective tax rates reflect the estimated annual effective tax rates for 2015 and 2014 . These tax rates are affected by estimated annual permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period, but are not consistent from period to period. FirstEnergy’s effective tax rate from continuing operations for the three months ended June 30, 2015 and 2014 was 38.1% and 28.9% , respectively. The increase in the effective tax rate is primarily due to an increase in uncertain tax benefits recognized in the second quarter of 2015 and a reduction in state deferred tax liabilities recognized in the second quarter of 2014 resulting from changes in state apportionment factors. FirstEnergy's effective tax rate from continuing operations for the six months ended June 30, 2015 and 2014 was 38.8% and 28.5% , respectively. The increase in the effective tax rate for the six month period ending June 30, 2015 is primarily due to a reduction in state deferred tax liabilities resulting from changes in state apportionment factors as well as the elimination of certain future tax liabilities associated with basis differences recognized in the first six months of 2014 and an increase in uncertain tax benefits recognized in 2015. FES’ effective tax rate from continuing operations for the three months ended June 30, 2015 and 2014 was 16.0% and 43.5% , respectively. FES' effective tax rate from continuing operations for the six months ended June 30, 2015 and 2014 was 20.0% and 39.3% , respectively. For both periods, the decrease in the effective tax rate on pre-tax losses is primarily due to a reduction in state deferred tax liabilities recognized in the second quarter of 2014 resulting from changes in state apportionment factors and an increase in uncertain tax benefits recognized in the second quarter of 2015. As of June 30, 2015 , it is reasonably possible that approximately $10 million of unrecognized tax benefits may be resolved within the next twelve months as a result of the statute of limitations expiring, all of which would affect FirstEnergy's effective tax rate. In January 2015, the IRS completed its examination of the 2013 federal income tax return and issued a Revenue Agent Report. For tax year 2013 there was no material impact to FirstEnergy's effective tax rate associated with this examination. Tax years 2014 and 2015 are currently under review by the IRS.

Variable Interest Entities

Variable Interest Entities	6 Months Ended
	Jun. 30, 2015
Variable Interest Entities [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest gives FirstEnergy a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both power and benefits, such that an entity has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. VIEs included in FirstEnergy’s consolidated financial statements are: the PNBV capital trust created to refinance debt originally issued in connection with sale and leaseback transactions (PNBV trust); wholly-owned limited liability companies of the Ohio Companies created to issue phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets (Ohio Securitization); wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs (JCP&L Securitization) and special purpose limited liability companies at MP and PE created to issue environmental control bonds that were used to construct environmental control facilities (MP and PE Environmental Funding Companies). The caption "noncontrolling interest" within the consolidated financial statements is used to reflect the portion of a VIE that FirstEnergy consolidates, but does not own. In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into the following categories based on similar risk characteristics and significance. PNBV Trust 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. Ohio Securitization In September 2012, the Ohio Companies formed CEI Funding LLC, OE Funding LLC and TE Funding LLC as separate, wholly-owned limited liability SPEs. The phase-in recovery bonds issued by these SPEs are payable only from, and secured by, phase-in recovery property owned by the SPEs and the bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445,000 that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of June 30, 2015 and December 31, 2014 , $374 million and $386 million of the phase-in recovery bonds were outstanding, respectively. JCP&L Securitization In June 2002, JCP&L Transition Funding sold transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consist primarily of bondable transition property. As of June 30, 2015 and December 31, 2014 , $150 million and $168 million of the transition bonds were outstanding, respectively. MP and PE Environmental Funding Companies The entities issued bonds of which the proceeds were used to construct environmental control facilities. The special purpose limited liability companies own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's and PE's West Virginia service territories. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. The right to collect environmental control charges is not included as an asset on FirstEnergy's consolidated balance sheets. Creditors of FirstEnergy, other than the special purpose limited liability companies, have no recourse to any assets or revenues of the special purpose limited liability companies. As of June 30, 2015 and December 31, 2014 , $440 million and $450 million of the environmental control bonds were outstanding, respectively. 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 with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture's economic performance. FEV's ownership interest is subject to the equity method of accounting. FEV's equity method investment in Global Holding was $372 million as of June 30, 2015 . Previously, FEV held a 50% equity ownership in Global Holding, of which a 16.7% interest was sold in 2011. In conjunction with the 2011 sale, a subsidiary of Global Holding was given the right to put up to 2 million tons annually from the Signal Peak underground mine to FG through 2024. Such subsidiary did not exercise their right under the put for 2014. During the first quarter of 2015, such Global Holding subsidiary eliminated its right under the put in exchange for FirstEnergy extending its guarantee under Global Holding's $300 million senior secured term loan facility through 2020, resulting in a pre-tax charge of $24 million in the first quarter of 2015. (See Note 10, Commitments, Guarantees and Contingencies.) PATH-WV PATH is a 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. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting. 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 the PATH project. Power Purchase Agreements FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy maintains 15 long-term power purchase agreements with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that for all but one of these NUG entities, it does not have a variable interest in the entities or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities. Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contracts that may contain a variable interest during the three months ended June 30, 2015 and 2014 were $27 million and $40 million , respectively, and $58 million and $102 million during the six months ended June 30, 2015 and 2014 , 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. As of June 30, 2015, FirstEnergy's leasehold interest was 3.75% of Perry Unit 1, 93.83% of Bruce Mansfield Unit 1 and 2.60% of Beaver Valley Unit 2. On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors' interests in Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), which right to repurchase was assigned to NG. Additionally, on June 24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor equity interests of the remaining non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the end of the lease term. Upon the completion of these transactions, NG will have obtained all of the lessor equity interests at Perry Unit 1 and Beaver Valley Unit 2. FES and other FE subsidiaries are exposed to losses under their applicable sale and leaseback agreements upon the occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions as of June 30, 2015 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy $ 1,231 $ 958 $ 273 FES 1,151 929 222

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2015
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 PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. 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. 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, 2015 , from those used as of December 31, 2014 . The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements. Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the six months ended June 30, 2015 . 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, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,292 $ — $ 1,292 $ — $ 1,221 $ — $ 1,221 Derivative assets - commodity contracts 1 251 — 252 1 171 — 172 Derivative assets - FTRs — — 23 23 — — 39 39 Derivative assets - NUG contracts (1) — — 1 1 — — 2 2 Equity securities (2) 697 — — 697 592 — — 592 Foreign government debt securities — 81 — 81 — 76 — 76 U.S. government debt securities — 178 — 178 — 182 — 182 U.S. state debt securities — 241 — 241 — 237 — 237 Other (3) 90 128 — 218 55 256 — 311 Total assets $ 788 $ 2,171 $ 24 $ 2,983 $ 648 $ 2,143 $ 41 $ 2,832 Liabilities Derivative liabilities - commodity contracts $ (7 ) $ (214 ) $ — $ (221 ) $ (26 ) $ (141 ) $ — $ (167 ) Derivative liabilities - FTRs — — (13 ) (13 ) — — (14 ) (14 ) Derivative liabilities - NUG contracts (1) — — (141 ) (141 ) — — (153 ) (153 ) Total liabilities $ (7 ) $ (214 ) $ (154 ) $ (375 ) $ (26 ) $ (141 ) $ (167 ) $ (334 ) Net assets (liabilities) (4) $ 781 $ 1,957 $ (130 ) $ 2,608 $ 622 $ 2,002 $ (126 ) $ 2,498 (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (3) Primarily consists of short-term cash investments. (4) Excludes $(6) million and $40 million as of June 30, 2015 and December 31, 2014 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. Rollforward of Level 3 Measurements The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended June 30, 2015 and December 31, 2014 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2014 Balance $ 20 $ (222 ) $ (202 ) $ 4 $ (12 ) $ (8 ) Unrealized gain (loss) 2 (2 ) — 47 (1 ) 46 Purchases — — — 26 (16 ) 10 Settlements (20 ) 71 51 (38 ) 15 (23 ) December 31, 2014 Balance $ 2 $ (153 ) $ (151 ) $ 39 $ (14 ) $ 25 Unrealized gain (loss) 1 (17 ) (16 ) 5 3 8 Purchases — — — 22 (11 ) 11 Settlements (2 ) 29 27 (43 ) 9 (34 ) June 30, 2015 Balance $ 1 $ (141 ) $ (140 ) $ 23 $ (13 ) $ 10 (1) Changes in the fair value of NUG contracts are generally subject to regulatory accounting treatment and do not impact earnings. Level 3 Quantitative Information The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended June 30, 2015 : Fair Value, Net (In millions) Valuation Technique Significant Input Range Weighted Average Units FTRs $ 10 Model RTO auction clearing prices ($5.10) to $9.20 $1.40 Dollars/MWH NUG Contracts $ (140 ) Model Generation 500 to 4,317,000 833,000 MWH Regional electricity prices $44.00 to $68.90 $51.00 Dollars/MWH FES Recurring Fair Value Measurements June 30, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 701 $ — $ 701 $ — $ 655 $ — $ 655 Derivative assets - commodity contracts 1 251 — 252 1 171 — 172 Derivative assets - FTRs — — 10 10 — — 27 27 Equity securities (1) 481 — — 481 360 — — 360 Foreign government debt securities — 64 — 64 — 57 — 57 U.S. government debt securities — 27 — 27 — 46 — 46 U.S. state debt securities — 4 — 4 — 4 — 4 Other (2) — 87 — 87 — 199 — 199 Total assets $ 482 $ 1,134 $ 10 $ 1,626 $ 361 $ 1,132 $ 27 $ 1,520 Liabilities Derivative liabilities - commodity contracts $ (7 ) $ (214 ) $ — $ (221 ) $ (26 ) $ (141 ) $ — $ (167 ) Derivative liabilities - FTRs — — (11 ) (11 ) — — (13 ) (13 ) Total liabilities $ (7 ) $ (214 ) $ (11 ) $ (232 ) $ (26 ) $ (141 ) $ (13 ) $ (180 ) Net assets (liabilities) (3) $ 475 $ 920 $ (1 ) $ 1,394 $ 335 $ 991 $ 14 $ 1,340 (1) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (2) Primarily consists of short-term cash investments. (3) Excludes $1 million and $44 million as of June 30, 2015 and December 31, 2014 , 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, 2015 and December 31, 2014 : Derivative Asset Derivative Liability Net Asset (Liability) (In millions) January 1, 2014 Balance $ 3 $ (11 ) $ (8 ) Unrealized gain (loss) 34 (1 ) 33 Purchases 15 (16 ) (1 ) Settlements (25 ) 15 (10 ) December 31, 2014 Balance $ 27 $ (13 ) $ 14 Unrealized gain 4 3 7 Purchases 9 (10 ) (1 ) Settlements (30 ) 9 (21 ) June 30, 2015 Balance $ 10 $ (11 ) $ (1 ) 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, 2015 : Fair Value, Net (In millions) Valuation Technique Significant Input Range Weighted Average Units FTRs $ (1 ) Model RTO auction clearing prices ($5.10) to $9.20 $1.00 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 receivables. 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, 2015 and December 31, 2014 : June 30, 2015 (1) December 31, 2014 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,808 $ 25 $ 1,833 $ 1,724 $ 27 $ 1,751 FES 824 13 837 788 13 801 Equity securities FirstEnergy $ 664 $ 33 $ 697 $ 533 $ 58 $ 591 FES 462 19 481 329 31 360 (1) Excludes short-term cash investments: FE Consolidated - $58 million ; FES - $47 million . (2) Excludes short-term cash investments: FE Consolidated - $241 million ; FES - $204 million . Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three and six months ended June 30, 2015 and 2014 were as follows: Three Months Ended June 30, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 448 $ 42 $ (39 ) $ (17 ) $ 25 FES 187 32 (27 ) (16 ) 15 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 Six Months Ended June 30, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 819 $ 102 $ (89 ) $ (24 ) $ 50 FES 376 70 (55 ) (22 ) 29 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 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, 2015 and December 31, 2014 : June 30, 2015 December 31, 2014 Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt Securities FirstEnergy $ 10 $ 2 $ 12 $ 13 $ 4 $ 17 The held-to-maturity debt securities contractually mature by June 30, 2017. 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, 2015 and $626 million as of December 31, 2014 , are excluded from the amounts reported above. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations, excluding capital lease obligations and net unamortized premiums and discounts: June 30, 2015 December 31, 2014 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 19,728 $ 21,195 $ 19,828 $ 21,733 FES 3,028 3,146 3,097 3,241 The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy. 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, 2015 and December 31, 2014 .

Derivative Instruments

Derivative Instruments	6 Months Ended
	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility 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) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in net income on a mark-to-market basis, unless otherwise noted. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance. FirstEnergy has contractual derivative agreements through 2020 . Cash Flow Hedges FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating commodity prices and interest rates. Total pre-tax net unamortized losses included in AOCI associated with instruments previously designated as cash flow hedges totaled $10 million and $8 million as of June 30, 2015 and December 31, 2014 , respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $2 million of net unamortized losses is expected to be amortized to income during the next twelve months. FirstEnergy has used forward starting interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were designated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $46 million and $50 million as of June 30, 2015 and December 31, 2014 , respectively. Based on current estimates, approximately $9 million of these unamortized losses is expected to be amortized to interest expense during the next twelve months. Refer to Note 4, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the three and six months ended June 30, 2015 and 2014 . As of June 30, 2015 and December 31, 2014 , no commodity or interest rate derivatives were designated as cash flow hedges. Fair Value Hedges FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. As of June 30, 2015 and December 31, 2014 , no fixed-for-floating interest rate swap agreements were outstanding. Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $26 million and $32 million as of June 30, 2015 and December 31, 2014 , respectively. During the next twelve months, approximately $12 million of the unamortized gains is expected to be amortized to interest expense. Amortization of unamortized gains included in long-term debt totaled approximately $3 million during the three months ended June 30, 2015 and 2014 and $6 million during the six months ended June 30, 2015 and 2014 . 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, 2015 , FirstEnergy’s net asset position under commodity derivative contracts was $31 million , which related to FES positions. Under these commodity derivative contracts, FES posted $60 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $6 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, 2015 , an adverse change of 10% in commodity prices would increase net income by approximately $25 million during the next twelve months. NUGs As of June 30, 2015 , FirstEnergy's net liability position under NUG contracts was $140 million , representing contracts held at JCP&L, ME and PN. NUG contracts represent purchased power agreements with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. Changes in the fair value of NUG contracts are subject to regulatory accounting treatment and do not impact earnings. FTRs As of June 30, 2015 , FirstEnergy's and FES' FTR position was a $10 million net asset and a $1 million net liability, respectively, and FES posted $6 million of collateral. FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of PJM that have load serving obligations and through the direct allocation of FTRs from PJM. PJM has a rule that allows directly allocated FTRs to be granted to LSEs in zones that have newly entered PJM. For the first two planning years, PJM permits the LSEs to request a direct allocation of FTRs in these new zones at no cost as opposed to receiving ARRs. The directly allocated FTRs differ from traditional FTRs in that the ownership of all or part of the FTRs may shift to another LSE if customers choose to shop with the other LSE. The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets and have not been designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price less the obligation due to PJM, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FES and AE Supply are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s utilities are recorded as regulatory assets or liabilities. Directly allocated FTRs are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance. FirstEnergy records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets: Derivative Assets Derivative Liabilities Fair Value Fair Value June 30, December 31, June 30, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 149 $ 121 Commodity Contracts $ (148 ) $ (154 ) FTRs 22 38 FTRs (12 ) (13 ) 171 159 (160 ) (167 ) Noncurrent Liabilities - Adverse Power Contract Liability Deferred Charges and Other Assets - Other NUGs (1) (141 ) (153 ) Commodity Contracts 103 51 Noncurrent Liabilities - Other FTRs 1 1 Commodity Contracts (73 ) (13 ) NUGs (1) 1 2 FTRs (1 ) (1 ) 105 54 (215 ) (167 ) Derivative Assets $ 276 $ 213 Derivative Liabilities $ (375 ) $ (334 ) (1) NUG contracts are subject to regulatory accounting treatment. Changes in fair value do not impact earnings. 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, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 252 $ (202 ) $ — $ 50 FTRs 23 (13 ) — 10 NUG contracts 1 — — 1 $ 276 $ (215 ) $ — $ 61 Derivative Liabilities Commodity contracts $ (221 ) $ 202 $ 11 $ (8 ) FTRs (13 ) 13 — — NUG contracts (141 ) — — (141 ) $ (375 ) $ 215 $ 11 $ (149 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2014 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 172 $ (126 ) $ — $ 46 FTRs 39 (14 ) — 25 NUG contracts 2 — — 2 $ 213 $ (140 ) $ — $ 73 Derivative Liabilities Commodity contracts $ (167 ) $ 126 $ 35 $ (6 ) FTRs (14 ) 14 — — NUG contracts (153 ) — — (153 ) $ (334 ) $ 140 $ 35 $ (159 ) The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of June 30, 2015 : Purchases Sales Net Units (In millions) Power Contracts 23 54 (31 ) MWH FTRs 54 — 54 MWH NUGs 5 — 5 MWH Natural Gas 39 1 38 mmBTU The effect of active derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income during the three and six months ended June 30, 2015 and 2014 , are summarized in the following tables: Three Months Ended June 30, Commodity Contracts FTRs Interest Rate Swaps Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense (1) $ 11 $ (2 ) $ — $ 9 Realized Gain (Loss) Reclassified to: Revenues (2) $ 8 $ 8 $ — $ 16 Purchased Power Expense (3) (25 ) — — (25 ) Other Operating Expense (4) — (13 ) — (13 ) Fuel Expense (5 ) — — (5 ) (1) Includes $11 million for commodity contracts and ($2) million for FTRs associated with FES. (2) Includes $8 million for commodity contacts and $8 million for FTRs associated with FES. (3) Includes ($25) million for commodity contracts associated with FES. (4) Includes ($13) million for FTRs associated with FES. Three Months Ended June 30, Commodity Contracts FTRs Interest Rate Swaps Total (In millions) 2014 Unrealized Gain (Loss) Recognized in: Other Operating Expense (5) $ (70 ) $ 13 $ — $ (57 ) Realized Gain (Loss) Reclassified to: Revenues (6) $ 2 $ (1 ) $ — $ 1 Purchased Power Expense (7) 22 — — 22 Other Operating Expense (8) — (10 ) — (10 ) Fuel Expense 2 — — 2 Interest Expense — — 6 6 (5) Includes ($70) million for commodity contracts and $13 million for FTRs associated with FES. (6) Represents losses on structured financial contracts. Includes $2 million for commodity contracts and ($1) million for FTRs associated with FES. (7) 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. (8) Includes ($9) million for FTRs associated with FES. Six Months Ended June 30, Commodity Contracts FTRs Interest Rate Swaps Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense (1) $ 22 $ (15 ) $ — $ 7 Realized Gain (Loss) Reclassified to: Revenues (2) $ 7 $ 45 $ — $ 52 Purchased Power Expense (3) (28 ) — — (28 ) Other Operating Expense (4) — (26 ) — (26 ) Fuel Expense (21 ) — — (21 ) (1) Includes $22 million for commodity contracts and ($14) million for FTRs associated with FES. (2) Includes $7 million for commodity contracts and $44 million for FTRs associated with FES. (3) Includes ($28) million for commodity contracts associated with FES. (4) Includes ($26) million for FTRs associated with FES. Six Months Ended June 30, Commodity Contracts FTRs Interest Rate Swaps Total (In millions) 2014 Unrealized Gain (Loss) Recognized in: Other Operating Expense (5) $ (58 ) $ 18 $ — $ (40 ) Realized Gain (Loss) Reclassified to: Revenues (6) $ (11 ) $ 51 $ — $ 40 Purchased Power Expense (7) 458 — — 458 Other Operating Expense (8) — (17 ) — (17 ) Fuel Expense 11 — — 11 Interest Expense — — 6 6 (5) Includes ($58) million for commodity contracts and $18 million for FTRs associated with FES. (6) Represents losses on structured financial contracts. Includes ($11) million for commodity contracts and $50 million for FTRs 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 ($16) million for FTRs associated with FES. The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during the three and six months ended June 30, 2015 and 2014 . Changes in the value of these instruments are deferred for future recovery from (or credit to) customers: Three Months Ended June 30, Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of April 1, 2015 $ (148 ) $ 1 $ (147 ) Unrealized loss (8 ) — (8 ) Purchases — 12 12 Settlements 16 (1 ) 15 Outstanding net asset (liability) as of June 30, 2015 $ (140 ) $ 12 $ (128 ) Outstanding net asset (liability) as of April 1, 2014 $ (185 ) $ 3 $ (182 ) Unrealized loss (2 ) — (2 ) Purchases — 11 11 Settlements 18 (4 ) 14 Outstanding net asset (liability) as of June 30, 2014 $ (169 ) $ 10 $ (159 ) Six Months Ended June 30, Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of January 1, 2015 $ (151 ) $ 11 $ (140 ) Unrealized gain (loss) (16 ) 1 (15 ) Purchases — 12 12 Settlements 27 (12 ) 15 Outstanding net asset (liability) as of June 30, 2015 $ (140 ) $ 12 $ (128 ) Outstanding net liability as of January 1, 2014 $ (202 ) $ — $ (202 ) Unrealized gain 25 4 29 Purchases — 11 11 Settlements 8 (5 ) 3 Outstanding net asset (liability) as of June 30, 2014 $ (169 ) $ 10 $ (159 )

Regulatory Matters

Regulatory Matters	6 Months Ended
	Jun. 30, 2015
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS STATE REGULATION Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates. In addition, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility. MARYLAND PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS. The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption by 10% and reduce electricity demand by 15% , in each case by 2015, and requiring each electric utility to file a plan every three years. PE's current plan, covering the three-year period 2015-2017, was approved by the MDPSC on December 23, 2014. The projected costs of the 2015-2017 plan are approximately $64 million for that three year period, of which $9 million was incurred through June 2015. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2016 and beyond, beginning with the goal of 0.2% for 2016 and ramping up thereafter to reach 2% . PE continues to recover program costs subject to a five -year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date such recovery has not been sought or obtained by PE. On February 27, 2013, the MDPSC issued an order (the February 27 Order) requiring the Maryland electric utilities to submit analyses, relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations. The order further required the Staff of the MDPSC to report on possible performance-based rate structures and to propose additional rules relating to feeder performance standards, outage communication and reporting, and sharing of special needs customer information. PE's responsive filings discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 27 Order, and projected that it would require approximately $2.7 billion in infrastructure investments over 15 years to attempt to achieve the quickest level of response for the largest storm projected in the February 27 Order. On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting. The Staff of the MDPSC also recommended the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that the utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not yet issued a ruling on any of those matters. On March 3, 2014, pursuant to the MDPSC's regulations, PE filed its recommendations for SAIDI and SAIFI standards to apply during the period 2016-2019. The MDPSC directed the Staff of the MDPSC to file an analysis and recommendations with respect to the proposed 2016-2019 SAIDI and SAIFI standards and any related rule changes which the Staff of the MDPSC recommended. The Staff of the MDPSC made its filing on July 10, 2015, and recommended that PE be required to improve its SAIDI results by approximately 20% by 2019. The MDPSC has set an initial hearing on the Staff of the MDPSC's analysis and recommendations for September 1-2, 2015. On April 1, 2015, PE filed its annual report on its performance relative to various service reliability standards set forth in the MDPSC’s regulations. The MDPSC has scheduled a hearing on the reports filed by PE and the other electric utilities in Maryland for August 24, 2015. NEW JERSEY JCP&L currently provides BGS for retail customers who do not choose a third party EGS and for customers of third party EGSs that fail to provide the contracted service. The supply for BGS is comprised of two components, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers. The second BGS component provides a fixed price service and is intended for smaller commercial and residential customers. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. On March 26, 2015, the NJBPU entered final orders which together provide an overall reduction in JCP&L's annual revenues of approximately $34 million , effective April 1, 2015. The final order in JCP&L's base rate case proceeding filed in November 2012 directed an annual base rate revenue reduction of approximately $115 million , including recovery of 2011 storm costs and the application of the NJBPU's modified CTA policy approved in the generic CTA proceeding referred to below. Additionally, the final order in the generic proceeding established to review JCP&L's major storm events of 2011 and 2012 approved the recovery of 2012 storm costs of $580 million resulting in an increase in annual revenues of approximately $81 million . JCP&L is required to file another base rate case no later than April 1, 2017. The NJBPU also directed that certain studies be completed, including a study related to reliability. On July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such study, which will include operational and financial components and is expected to take approximately one year to complete. In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases (Generic CTA proceeding), the NJBPU stated that it would continue to apply its current CTA policy in base rate cases, subject to incorporating the following modifications: 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. On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the Generic CTA proceeding to the New Jersey Superior Court and JCP&L has filed to participate as a respondent in that proceeding, which remains pending. On June 19, 2015, JCP&L, along with PN, ME, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction. 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; • Continues collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; • Continuing to provide economic development and assistance to low-income customers for the two -year plan period at levels established in the prior ESP; • A 6% generation rate discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); • 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 FERC proceedings; • Securing generation supply for a longer period of time by conducting an auction for a three -year period rather than a one -year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility customers who do not switch to a competitive generation supplier; and • Extending the recovery period for costs associated with purchasing RECs mandated by SB221, Ohio's renewable energy and energy efficiency standard, through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the entire ESP period. Notices of appeal of the Ohio Companies' ESP 3 plan to the Supreme Court of Ohio were filed by the Northeast Ohio Public Energy Council and the ELPC. The 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 initially requested a decision by the PUCO by April 8, 2015. The Ohio Companies filed a partial Stipulation and Recommendation on December 22, 2014, a Supplemental Stipulation and Recommendation on May 28, 2015, and a Second Supplemental Stipulation and Recommendation on June 4, 2015. The evidentiary hearing on the ESP IV is now scheduled to commence on August 31, 2015. The material terms of the proposed plan as filed include: • Continuing a base distribution rate freeze through May 31, 2019; • Continuing collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; • 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 FERC proceedings; and • General updates to electric service regulations and tariffs to reflect regulatory orders, administrative rule changes, and current practices. Under Ohio's energy efficiency standards (SB221 and SB310), and based on the Ohio Companies' amended energy efficiency plans, the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of 2,266 GWHs in 2015 and 2,288 GWHs in 2016, and then begin to increase by 1% each year in 2017, subject to the outcome of a legislative study committee. The Ohio Companies are also required to retain the 2014 peak demand reduction level for 2015 and 2016 and then increase the benchmark by an additional 0.75% thereafter through 2020, subject to the outcome of a legislative study committee. On March 20, 2013, the PUCO approved the three-year energy efficiency portfolio plans for 2013-2015, estimated to cost the Ohio Companies approximately $250 million over the three-year period, which is expected to be recovered in rates. Actual costs may be lower for a number of reasons including the approval of the amended portfolio plan under SB310. On July 17, 2013, the PUCO modified the plan to authorize the Ohio Companies to receive 20% of any revenues obtained from offering energy efficiency and DR reserves into the PJM auction. The PUCO also confirmed that the Ohio Companies can recover PJM costs and applicable penalties associated with PJM auctions, including the costs of purchasing replacement capacity from PJM incremental auctions, to the extent that such costs or penalties are prudently incurred. ELPC and OCC filed applications for rehearing, which were granted for the sole purpose of further consideration of the issue. On September 24, 2014, the Ohio Companies filed an amendment to their portfolio plan as contemplated by SB310, seeking to suspend certain programs for the 2015-2016 period in order to better align the plan with the new benchmarks under SB310. On November 20, 2014, the PUCO approved the Ohio Companies' amended portfolio plan. Several applications for rehearing were filed, and the PUCO granted those applications for further consideration of the matters specified in those applications. On September 16, 2013, the Ohio Companies filed with the Supreme Court of Ohio a notice of appeal of the PUCO's July 17, 2013 Entry on Rehearing related to energy efficiency, alternative energy, and long-term forecast rules stating that the rules issued by the PUCO are inconsistent with, and are not supported by, statutory authority. On October 23, 2013, the PUCO filed a motion to dismiss the appeal, which is still pending. The matter has not been scheduled for oral argument. Ohio law requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage amount through 2026, subject to the outcome of a legislative study committee, except 2015 and 2016 that remain at the 2014 level. The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements. In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs. The PUCO issued an Opinion and Order on August 7, 2013 approving the Ohio Companies' acquisition process and their purchases of RECs to meet statutory mandates in all instances except for part of the purchases arising from one auction and directing the Ohio Companies to credit non-shopping customers in the amount of $43.4 million , plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent. 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, following the denial of their application for rehearing, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted. On February 18, 2014, the OCC and the ELPC also filed appeals of the PUCO's order. The Ohio Companies timely filed their merit brief with the Supreme Court of Ohio and the briefing process has concluded. The matter is not yet scheduled for oral argument. On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges. The matter remains pending. PENNSYLVANIA The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2017, and provide for the competitive procurement of generation supply for customers that do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. The default service supply is currently provided by wholesale suppliers through a mix of long-term and short-term contracts procured through spot market purchases, quarterly descending clock auctions for 3, 12- and 24-month energy contracts, and one RFP seeking 2-year contracts to serve SRECs for ME, PN, and Penn. 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 29 -months concluding in the second quarter of 2013. 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. The United States District Court for the Eastern District of Pennsylvania granted the PPUC's motion to dismiss the complaint filed by ME and PN 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. 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. On appeal, in a split decision, two judges of a three-judge panel of the Third Circuit affirmed the U.S. District Court's dismissal of the complaint, agreeing that ME and PN had litigated the issue in the state proceedings and thus were precluded from subsequent litigation in federal court. ME and PN timely filed for rehearing and rehearing en banc; the Third Circuit rejected that rehearing request. ME and PN filed a Petition for Certiorari with the United States Supreme Court on February 12, 2015, and that Court denied the Petition on May 26, 2015. Pursuant to Pennsylvania's EE&C legislation (Act 129 of 2008), the PPUC was charged with reviewing the cost effectiveness of all Pennsylvania EDC's energy efficiency and peak demand reduction programs. In 2012, the PPUC found the energy efficiency programs to be cost effective and directed all of the EDCs 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. At that time, the PPUC deferred ruling on the need to create peak demand reduction targets and did not include a peak demand reduction requirement in the Phase II plans. On March 14, 2013, the PPUC adopted a settlement among the Pennsylvania Companies and interested parties and approved the Pennsylvania Companies' Phase II EE&C Plans. Total costs of these plans are expected to be approximately $234 million and recoverable through the Pennsylvania Companies' reconcilable EE&C riders. On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at 1.8% for ME, 1.7% for Penn, 1.8% for WP, and 0% for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at 4.0% for ME, 3.9% for PN, 3.3% for Penn, and 2.6% for WP. EDCs are permitted to recover costs for implementing Phase III EE&C plans. On August 4, 2014, the Pennsylvania Companies each filed tariffs with the PPUC proposing general rate increases associated with their distribution operations. The filings requested 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. On February 3, 2015, each of the Pennsylvania Companies filed a Joint Petition for Settlement seeking PPUC approval of the agreements reached in each proceeding which, among other things, provided for an increase in annual revenues of $292.8 million ( $89.3 million for ME, $90.8 million for PN, $15.9 million for Penn and $96.8 million for WP). The sole issue reserved for briefing was with respect to the scope and pricing of the Companies' proposed LED offerings. Recommended Decisions were issued by the ALJs recommending approval of the settlements and implementation of the Pennsylvania Companies' LED lighting offerings as proposed in their original filings. On April 9, 2015, the PPUC adopted the ALJs' Recommended Decisions and approved the settlements. The settlements will result in $87.7 million of additional annual operating expenses, including costs associated with service reliability enhancements to the distribution system, amortization of deferred storm costs and the remaining net book value of legacy meters, assistance for providing service to low-income customers, and the creation of a storm reserve for each utility. Additionally, the settlements include commitments to meet certain wait times for call centers and service reliability standards. The new rates were effective May 3, 2015. On July 16, 2013, the PPUC's Bureau of Audits initiated a focused management and operations audit of the Pennsylvania Companies as required every eight years by statute. The PPUC issued a report on its findings and recommendations on February 12, 2015, at which time the Pennsylvania Companies' associated implementation plan was also made public. In an order issued on March 30, 2015, the Pennsylvania Companies were directed to develop and file by May 29, 2015 revised implementation plans regarding certain of the operational topics addressed in the report, including addressing certain reliability matters. On May 19, 2015, the PPUC granted a forty-five day extension for the filing of revised implementation plans with respect to certain of the matters raised in its March 30, 2015 Order. On May 29, 2015 and July 13, 2015, the Pennsylvania Companies filed their revised implementation plan. The cost of compliance is currently expected to range from approximately $200 million to $230 million . On June 19, 2015, ME and PN, along with JCP&L, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction. WEST VIRGINIA MP and PE currently operate under a Joint Stipulation and Agreement of Settlement approved by the WVPSC on February 3, 2015, that provides for: a $15 million increase in base rate revenues effective February 25, 2015; the implementation of a Vegetation Management Surcharge to recover all costs related to both new and existing vegetation maintenance programs; authority to establish a regulatory asset for MATS investments placed into service in 2016 and 2017; authority to defer, amortize and recover over a 5 -year period approximately $46 million of storm restoration costs; and elimination of the Temporary Transaction Surcharge for costs associated with MP's acquisition of the Harrison plant in October 2013 and movement of those costs into base rates. MP and PE's current ENEC rates went into effect on February 25, 2015, in accordance with a settlement approved by the WVPSC on January 29, 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, NG, ATSI and TrAIL. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC. FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy's part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows. FERC MATTERS PJM Transmission Rates PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities. While FirstEnergy and other parties advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM. This question has been the subject of extensive litigation before FERC and the appellate courts, including most recently before the Seventh Circuit. On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines. The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole. The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings. Settlement discussions under a FERC-appointed settlement judge are ongoing. The PJM transmission owners, including FirstEnergy, submitted filings to FERC setting forth the cost allocation method for projects that cross the borders between the PJM Region and: (1) the NYISO region; (2) the MISO region; and (3) the FERC-jurisdictional members of the SERTP region. These filings propose to allocate the costs of these interregional transmission projects based on the costs of projects that otherwise would have been constructed separately in each region, or, in the case of MISO, indicate 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. As of May 14, 2015, FERC has accepted the PJM/NYISO, PJM/MISO and PJM/SERTP filings, subject to further compliance requirements. FERC’s acceptance of the PJM/SERTP filing is also subject to refund and the SERTP region participants’ related Order No. 1000 interregional compliance proceedings. In a series of orders in certain Order No. 1000 dockets, FERC asserted that the PJM transmission owners do not hold an incumbent “right of first refusal” to construct, own and operate transmission projects within their respective footprints that are approved as part of PJM’s RTEP process. FirstEnergy and other PJM transmission owners have appealed these rulings, and the question of whether FirstEnergy and the PJM transmission owners have a "right of first refusal" is now pending before the U.S. Court of Appeals for the D.C. Circuit in an appeal of FERC's order approving PJM's Order No.1000 compliance filing. The outcome of the remaining pending 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. While many of the matters involved with the move have been resolved, FERC denied recovery under ATSI's transmission rate for certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation charges totaling approximately $78.8 million until such time as ATSI submits a cost/benefit analysis demonstrating net benefits to customers from the move. FERC rejected a proposed settlement agreement to resolve the exit fee and transmission cost allocation issues, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. FirstEnergy's request for rehearing of FERC's order remains pending. 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 before FERC and certain United States appellate courts. 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. On a related issue, FirstEnergy joined certain other PJM transmission owners in a protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region. On January 22, 2015, FERC issued an order establishing a paper hearing on remand from the Seventh Circuit of the issue of whether any limitation on "export pricing" for sales of energy from MISO into PJM is justified in light of applicable FERC precedent. On April 22, 2015, certain PJM transmission owners, including FirstEnergy, filed an initial brief asserting that FERC’s prior ruling rejecting MISO’s proposed MVP export charge on transactions into PJM was correct and should be re-affirmed on remand. Reply comments were filed June 22, 2015. The matter is now before FERC for consideration. In addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission pro

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS, GUARANTEES AND CONTINGENCIES	850 mmBTU/hr), and 1,100 lbs. CO 2 /MWH for other natural gas fired units (≤ 850 mmBTU/hr), and 1,100 lbs. CO 2 /MWH for fossil fuel fired units which would require partial carbon capture and storage. EPA proposed regulations in June 2014, to reduce CO 2 emissions from existing fossil fuel fired electric generating units that would require each state to develop SIPs by June 30, 2016, to meet EPA’s state specific CO 2 emission rate goals. EPA’s proposal allows states to request a 1-year extension for SIPs (June 30, 2017) or a 2-year extension for multi-state SIPs (June 30, 2018). EPA also proposed separate regulations imposing additional CO 2 emission limits on modified and reconstructed fossil fuel fired electric generating units. On June 23, 2014, the United States Supreme Court decided that CO 2 or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by EPA to install GHG control technologies. On June 9, 2015, the U.S. Court of Appeals for the D.C. Circuit denied challenges to prevent EPA from regulating CO 2 emissions from existing fossil fuel fired electric generating units because EPA's proposed Clean Power Plant is not final agency action and therefore not ripe for review. Depending on the outcome of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be substantial. At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. In advance of the December 2015 United Nations Framework Convention on Climate Change meetings in Paris, the Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide greenhouse gas emissions by 26 to 28 percent below 2005 levels by 2025. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO 2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO 2 emitting gas-fired and nuclear generators. Clean Water Act Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from the plant's cooling water intake system. Depending on the results of such studies and any final action taken by the states based on those studies, the future costs of compliance with these standards may require material capital expenditures. The EPA proposed updates to the waste water effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423) in April 2013. 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 United States District Court and the treatment obligations are proposed to phase-in as permits are renewed on a 5 -year cycle from 2017 to 2022. Depending on the content of the EPA's final rule and any final action taken by the states, 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 the appeal or estimate the possible loss or range of loss. FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the 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, as amended, and the Toxic Substances Control Act. Certain coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. Depending on how the final rules are ultimately implemented, the future costs of compliance with such CCR regulations may require material capital expenditures. The PA DEP filed a 2012 complaint against FG in the United States District Court for the Western District of Pennsylvania with claims under the RCRA and Pennsylvania's Solid Waste Management Act regarding the LBR CCR Impoundment and simultaneously proposed a consent decree between PA DEP and FG to resolve those claims. On December 14, 2012, a modified consent decree 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. PA DEP issued a 2014 permit requiring FE to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FE to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCRs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The Bruce Mansfield plant is pursuing several options for its CCRs following December 31, 2016. A June 28, 2013 complaint filed by Citizens Coal Counsel and other NGOs in the United States District Court for the Western District of Pennsylvania, against the owner and operator of a reclamation mine in LaBelle, Pennsylvania that is one possible alternative, 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. To date, no complaint has been filed. On May 22, 2015, PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility, another potential alternative for Bruce Mansfield plant CCR disposal. On July 6, 2015, Sierra Club filed a Notice of Appeal with the Pennsylvania Environmental Hearing Board challenging the renewal and reissuance of the permit for the Hatfield’s Ferry CCB disposal facility. FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of June 30, 2015 based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $134 million have been accrued through June 30, 2015 . Included in the total are accrued liabilities of approximately $93 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, 2015 , FirstEnergy had approximately $2.3 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. The values of FirstEnergy's NDTs fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs. FE and FES have also entered into a total of $24.5 million in parental 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. An NRC ASLB granted an opportunity for a hearing on the Davis-Besse license renewal application to a group of Intervenors, subject to the admissibility of contentions. On March 10, 2015, the ASLB issued an Order that terminated its jurisdiction and closed the record in the Davis-Besse license renewal proceeding. On June 9, 2015, the NRC Commissioners denied an intervenor's filed requests to reopen the record and admit a contention on the NRC’s Continued Storage Rule. As part of routine inspections of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. These inspections revealed that the cracking condition had 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. In a May 28, 2015, Inspection Report regarding the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation for FENOC’s failure to request and obtain a license amendment for its method of evaluating the significance of the shield building cracking. The NRC also concluded that the shield building remained capable of performing its design safety functions despite the identified laminar cracking and that this issue was of very low safety significance. The NRC continues to evaluate FENOC's analysis of the shield building. 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 FirstEnergy'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 for failure to supply coal required by a long term CSA. A jury trial, appeal and other proceedings followed. On April 6, 2015, and in lieu of further appeals and litigation process, the parties agreed to a full and final settlement of all remaining claims and on April 7, 2015, ICG paid the $15 million settlement amount in full of which $12 million was allocated to AE Supply and $3 million to MP. The trial and appellate courts were notified of the settlement and the cases were discontinued by the parties. 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." id="sjs-B4">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, 2015 , FirstEnergy's outstanding guarantees and other assurances aggregated approximately $3.9 billion , consisting of parental guarantees ( $599 million ), subsidiaries' guarantees ( $2.2 billion ), other guarantees ( $300 million ) and other assurances ( $717 million ). Of this aggregate amount, substantially all relates to guarantees of wholly-owned consolidated entities of FirstEnergy. FES' debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each of FG and NG. Accordingly, present and future holders of indebtedness of FES, FG and NG would have claims against each of FES, FG and NG, regardless of whether their primary obligor is FES, FG or NG. COLLATERAL AND CONTINGENT-RELATED FEATURES In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel, and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on FES' power portfolio exposures as of June 30, 2015 , FES has posted collateral, including LOC, of $214 million . The Regulated Distribution segment has posted collateral of $1 million . These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. Subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of FE or its subsidiaries. The following table discloses the additional credit contingent contractual obligations that may be required under certain events as of June 30, 2015 : Collateral Provisions FES AE Supply Utilities Total (In millions) Split Rating (One rating agency's rating below investment grade) $ 410 $ 6 $ 50 $ 466 BB+/Ba1 Credit Ratings $ 447 $ 6 $ 50 $ 503 Full impact of credit contingent contractual obligations $ 492 $ 16 $ 50 $ 558 Excluded from the preceding table are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment. As of June 30, 2015 , neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES would be required to post $13 million with affiliated parties. OTHER COMMITMENTS AND CONTINGENCIES FirstEnergy is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding borrowed $300 million . The facility, which was originally entered into in October 2012 with a $350 million borrowing that was subsequently paid down to the current $300 million , was amended and extended in the first quarter of 2015 as further discussed below. In addition to FirstEnergy, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several guaranties of the obligations of Global Holding under the facility. In connection with the facility, 69.99% of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral. During the first quarter of 2015, a subsidiary of Global Holding eliminated its right to put 2 million tons annually through 2024 from the Signal Peak mine to FG in exchange for FirstEnergy extending its guarantee under Global Holding's $300 million senior secured term loan facility through 2020, resulting in a pre-tax charge of $24 million . See Note 6, Variable Interest Entities, for additional information regarding FEV's investment in Global Holding . ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Clean Air Act FirstEnergy complies with SO 2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls, generating more electricity from lower or non-emitting plants and/or using emission allowances. CSAPR requires reductions of NOx and SO 2 emissions in two phases (2015 and 2017), ultimately capping SO 2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions. Depending on how the EPA and the states implement the CSAPR, the future cost of compliance may be substantial and changes to FirstEnergy's and FES' operations may result. MATS imposes emission limits for mercury, PM, and HCL for all existing and new fossil fuel fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. On December 28, 2012, the WVDEP granted a conditional extension through April 16, 2016 for MATS compliance at the Fort Martin, Harrison and Pleasants plants. On March 20, 2013, the PA DEP granted an extension through April 16, 2016 for MATS compliance at the Hatfield's Ferry and Bruce Mansfield plants. On February 5, 2015, the OEPA granted an extension through April 16, 2016 for MATS compliance at the Bay Shore and Sammis plants. Nearly all spending for MATS compliance at Bay Shore and Sammis has been completed through 2014. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On June 29, 2015, the United States Supreme Court reversed a D.C. Circuit decision that upheld MATS, rejecting EPA’s regulatory approach that costs are not relevant to the decision of whether or not to regulate power plant emissions under Section 112 of the Clean Air Act and remanded the case back to the D.C. Circuit for further proceedings. Subject to the outcome of further proceedings before the D.C. Circuit and how the MATS are ultimately implemented, FirstEnergy's total capital cost for compliance (over the 2012 to 2018 time period) is currently expected to be approximately $370 million (CES segment of $178 million and Regulated Distribution segment of $192 million ), of which $167 million has been spent through June 30, 2015 ( $62 million at CES and $105 million at Regulated Distribution). Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 were deactivated in April 2015, which completes the deactivation of 5,429 MW of coal-fired plants since 2012. FirstEnergy and FES have various long-term coal supply and transportation agreements, some of which run through 2025 and certain of which are related to deactivated coal-fired plants. FirstEnergy and FES have asserted force majeure defenses for delivery shortfalls under certain agreements, and are in discussion with the applicable counterparties. If FirstEnergy and FES fail to reach a resolution with the applicable counterparties for the agreements associated with the deactivated plants and it were ultimately determined that, contrary to their belief, the force majeure provisions or other defenses, do not excuse or otherwise mitigate the delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. If that were to occur, FirstEnergy and FES are unable to estimate the loss or range of loss. As to a specific coal supply agreement, FirstEnergy and AE Supply have asserted termination rights effective in 2015. In response to notification of the termination, the coal supplier commenced litigation alleging FirstEnergy and AE Supply do not have sufficient justification to terminate the agreement. FirstEnergy and AE Supply have filed an answer denying any liability related to the termination. There are 6 million tons remaining under the contract for delivery. At this time, FirstEnergy cannot estimate the loss or range of loss regarding the on-going litigation with respect to this agreement. In September 2007, AE received an NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia. The EPA's NOV alleges equipment replacements during maintenance outages triggered the pre-construction permitting requirements under the NSR and PSD programs. On June 29, 2012, January 31, 2013, and March 27, 2013, EPA issued CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. On December 12, 2014, EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009. FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the possible loss or range of loss. In July 2008, three complaints representing multiple plaintiffs were filed against FG in the United States 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 has entered into a confidential settlement to resolve these claims for an immaterial amount. Climate Change There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation. A June 2013, Presidential Climate Action Plan outlined goals to: (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 CO 2 emissions will be reduced 25% below 2005 levels by 2015, exceeding the President’s Climate Action Plan goals both in terms of timing and reduction levels. EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act” in December 2009, concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. EPA proposed a new source performance standard in September 2013, which would not apply to any existing, modified, or reconstructed fossil fuel fired generating units, of 1,000 lbs. CO 2 /MWH for large natural gas fired units (> 850 mmBTU/hr), and 1,100 lbs. CO 2 /MWH for other natural gas fired units (≤ 850 mmBTU/hr), and 1,100 lbs. CO 2 /MWH for fossil fuel fired units which would require partial carbon capture and storage. EPA proposed regulations in June 2014, to reduce CO 2 emissions from existing fossil fuel fired electric generating units that would require each state to develop SIPs by June 30, 2016, to meet EPA’s state specific CO 2 emission rate goals. EPA’s proposal allows states to request a 1-year extension for SIPs (June 30, 2017) or a 2-year extension for multi-state SIPs (June 30, 2018). EPA also proposed separate regulations imposing additional CO 2 emission limits on modified and reconstructed fossil fuel fired electric generating units. On June 23, 2014, the United States Supreme Court decided that CO 2 or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by EPA to install GHG control technologies. On June 9, 2015, the U.S. Court of Appeals for the D.C. Circuit denied challenges to prevent EPA from regulating CO 2 emissions from existing fossil fuel fired electric generating units because EPA's proposed Clean Power Plant is not final agency action and therefore not ripe for review. Depending on the outcome of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be substantial. At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. In advance of the December 2015 United Nations Framework Convention on Climate Change meetings in Paris, the Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide greenhouse gas emissions by 26 to 28 percent below 2005 levels by 2025. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO 2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO 2 emitting gas-fired and nuclear generators. Clean Water Act Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from the plant's cooling water intake system. Depending on the results of such studies and any final action taken by the states based on those studies, the future costs of compliance with these standards may require material capital expenditures. The EPA proposed updates to the waste water effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423) in April 2013. 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 United States District Court and the treatment obligations are proposed to phase-in as permits are renewed on a 5 -year cycle from 2017 to 2022. Depending on the content of the EPA's final rule and any final action taken by the states, 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 the appeal or estimate the possible loss or range of loss. FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the 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, as amended, and the Toxic Substances Control Act. Certain coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. Depending on how the final rules are ultimately implemented, the future costs of compliance with such CCR regulations may require material capital expenditures. The PA DEP filed a 2012 complaint against FG in the United States District Court for the Western District of Pennsylvania with claims under the RCRA and Pennsylvania's Solid Waste Management Act regarding the LBR CCR Impoundment and simultaneously proposed a consent decree between PA DEP and FG to resolve those claims. On December 14, 2012, a modified consent decree 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. PA DEP issued a 2014 permit requiring FE to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FE to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCRs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The Bruce Mansfield plant is pursuing several options for its CCRs following December 31, 2016. A June 28, 2013 complaint filed by Citizens Coal Counsel and other NGOs in the United States District Court for the Western District of Pennsylvania, against the owner and operator of a reclamation mine in LaBelle, Pennsylvania that is one possible alternative, 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. To date, no complaint has been filed. On May 22, 2015, PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility, another potential alternative for Bruce Mansfield plant CCR disposal. On July 6, 2015, Sierra Club filed a Notice of Appeal with the Pennsylvania Environmental Hearing Board challenging the renewal and reissuance of the permit for the Hatfield’s Ferry CCB disposal facility. FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of June 30, 2015 based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $134 million have been accrued through June 30, 2015 . Included in the total are accrued liabilities of approximately $93 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, 2015 , FirstEnergy had approximately $2.3 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. The values of FirstEnergy's NDTs fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs. FE and FES have also entered into a total of $24.5 million in parental 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. An NRC ASLB granted an opportunity for a hearing on the Davis-Besse license renewal application to a group of Intervenors, subject to the admissibility of contentions. On March 10, 2015, the ASLB issued an Order that terminated its jurisdiction and closed the record in the Davis-Besse license renewal proceeding. On June 9, 2015, the NRC Commissioners denied an intervenor's filed requests to reopen the record and admit a contention on the NRC’s Continued Storage Rule. As part of routine inspections of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. These inspections revealed that the cracking condition had 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. In a May 28, 2015, Inspection Report regarding the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation for FENOC’s failure to request and obtain a license amendment for its method of evaluating the significance of the shield building cracking. The NRC also concluded that the shield building remained capable of performing its design safety functions despite the identified laminar cracking and that this issue was of very low safety significance. The NRC continues to evaluate FENOC's analysis of the shield building. 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 FirstEnergy'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 for failure to supply coal required by a long term CSA. A jury trial, appeal and other proceedings followed. On April 6, 2015, and in lieu of further appeals and litigation process, the parties agreed to a full and final settlement of all remaining claims and on April 7, 2015, ICG paid the $15 million settlement amount in full of which $12 million was allocated to AE Supply and $3 million to MP. The trial and appellate courts were notified of the settlement and the cases were discontinued by the parties. 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 Informat

Supplemental Guarantor Information	6 Months Ended
	Jun. 30, 2015
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 (Loss) and Comprehensive Income (Loss) for the three and six months ended June 30, 2015 and 2014 , Condensed Consolidating Balance Sheets as of June 30, 2015 and December 31, 2014 , and Condensed Consolidating Statements of Cash Flows for the six months ended June 30, 2015 and 2014 , 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, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 1,074 $ 346 $ 456 $ (757 ) $ 1,119 OPERATING EXPENSES: Fuel — 150 41 — 191 Purchased power from affiliates 768 — 66 (757 ) 77 Purchased power from non-affiliates 392 — — — 392 Other operating expenses 102 75 164 12 353 Provision for depreciation 2 32 47 — 81 General taxes 11 7 7 — 25 Total operating expenses 1,275 264 325 (745 ) 1,119 OPERATING INCOME (LOSS) (201 ) 82 131 (12 ) — OTHER INCOME (EXPENSE): Investment income, including net income from equity investees 119 5 3 (126 ) 1 Miscellaneous income 1 3 — — 4 Interest expense — affiliates (7 ) (2 ) (1 ) 8 (2 ) Interest expense — other (13 ) (26 ) (12 ) 14 (37 ) Capitalized interest — 2 7 — 9 Total other income (expense) 100 (18 ) (3 ) (104 ) (25 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (101 ) 64 128 (116 ) (25 ) INCOME TAXES (BENEFITS) (80 ) 28 47 1 (4 ) NET INCOME (LOSS) $ (21 ) $ 36 $ 81 $ (117 ) $ (21 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (21 ) $ 36 $ 81 $ (117 ) $ (21 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (4 ) (4 ) — 4 (4 ) Amortized gain on derivative hedges (1 ) — — — (1 ) Change in unrealized gain on available-for-sale securities (12 ) — (12 ) 12 (12 ) Other comprehensive loss (17 ) (4 ) (12 ) 16 (17 ) Income tax benefits on other comprehensive loss (6 ) (2 ) (4 ) 6 (6 ) Other comprehensive loss, net of tax (11 ) (2 ) (8 ) 10 (11 ) COMPREHENSIVE INCOME (LOSS) $ (32 ) $ 34 $ 73 $ (107 ) $ (32 ) FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) (Unaudited) For the Six Months Ended June 30, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 2,406 $ 839 $ 963 $ (1,712 ) $ 2,496 OPERATING EXPENSES: Fuel — 330 91 — 421 Purchased power from affiliates 1,725 — 134 (1,712 ) 147 Purchased power from non-affiliates 935 — — — 935 Other operating expenses 282 142 318 24 766 Provision for depreciation 5 62 95 (1 ) 161 General taxes 26 15 13 — 54 Total operating expenses 2,973 549 651 (1,689 ) 2,484 OPERATING INCOME (LOSS) (567 ) 290 312 (23 ) 12 OTHER INCOME (EXPENSE): Loss on debt redemptions — — — — — Investment income, including net income from equity investees 360 8 17 (371 ) 14 Miscellaneous income 1 3 — — 4 Interest expense — affiliates (13 ) (4 ) (2 ) 15 (4 ) Interest expense — other (26 ) (52 ) (25 ) 29 (74 ) Capitalized interest — 3 15 — 18 Total other income (expense) 322 (42 ) 5 (327 ) (42 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) (245 ) 248 317 (350 ) (30 ) INCOME TAXES (BENEFITS) (221 ) 95 117 3 (6 ) INCOME (LOSS) FROM CONTINUING OPERATIONS (24 ) 153 200 (353 ) (24 ) Discontinued operations (Note 13) — — — — — NET INCOME (LOSS) $ (24 ) $ 153 $ 200 $ (353 ) $ (24 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (24 ) $ 153 $ 200 $ (353 ) $ (24 ) OTHER COMPREHENSIVE INCOME (LOSS): Pensions and OPEB prior service costs (8 ) (8 ) — 8 (8 ) Amortized gain on derivative hedges (2 ) — — — (2 ) Change in unrealized gain on available-for-sale securities (9 ) — (9 ) 9 (9 ) Other comprehensive loss (19 ) (8 ) (9 ) 17 (19 ) Income tax benefits on other comprehensive loss (7 ) (3 ) (3 ) 6 (7 ) Other comprehensive loss, net of tax (12 ) (5 ) (6 ) 11 (12 ) COMPREHENSIVE INCOME (LOSS) $ (36 ) $ 148 $ 194 $ (342 ) $ (36 ) 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): Investment income, including net income from equity investees 2 2 23 (3 ) 24 Miscellaneous income 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) BEFORE INCOME TAXES (BENEFITS) (225 ) 80 145 (154 ) (154 ) INCOME TAXES (BENEFITS) (137 ) 23 45 2 (67 ) 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): Pension 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, including net income from equity investees 3 3 44 (6 ) 44 Miscellaneous income 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 BALANCE SHEETS (Unaudited) As of June 30, 2015 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 325 — — — 325 Affiliated companies 340 287 301 (525 ) 403 Other 45 2 10 — 57 Notes receivable from affiliated companies 394 1,072 580 (2,033 ) 13 Materials and supplies 54 201 221 — 476 Derivatives 158 — — — 158 Collateral 140 — — — 140 Prepayments and other 80 59 — — 139 1,536 1,623 1,112 (2,558 ) 1,713 PROPERTY, PLANT AND EQUIPMENT: In service 90 6,351 7,919 (382 ) 13,978 Less — Accumulated provision for depreciation 34 2,107 3,483 (193 ) 5,431 56 4,244 4,436 (189 ) 8,547 Construction work in progress 3 157 757 — 917 59 4,401 5,193 (189 ) 9,464 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,365 — 1,365 Investment in affiliated companies 6,957 — — (6,957 ) — Other — 10 — — 10 6,957 10 1,365 (6,957 ) 1,375 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 322 — — (322 ) — Customer intangibles 70 — — — 70 Goodwill 23 — — — 23 Property taxes — 7 12 — 19 Unamortized sale and leaseback costs — — — 266 266 Derivatives 104 — — — 104 Other 51 321 11 (266 ) 117 570 328 23 (322 ) 599 $ 9,122 $ 6,362 $ 7,693 $ (10,026 ) $ 13,151 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 167 $ 541 $ (25 ) $ 683 Short-term borrowings- Affiliated companies 1,649 384 — (2,033 ) — Other 250 8 — — 258 Accounts payable- Affiliated companies 581 133 164 (581 ) 297 Other 24 93 — — 117 Accrued taxes 3 41 50 (15 ) 79 Derivatives 155 3 — — 158 Other 66 54 9 34 163 2,728 883 764 (2,620 ) 1,755 CAPITALIZATION: Total equity 5,554 2,712 4,208 (6,920 ) 5,554 Long-term debt and other long-term obligations 695 2,199 614 (1,149 ) 2,359 6,249 4,911 4,822 (8,069 ) 7,913 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 807 807 Accumulated deferred income taxes 7 29 696 (144 ) 588 Asset retirement obligations — 191 659 — 850 Retirement benefits 36 295 — — 331 Derivatives 69 5 — — 74 Other 33 48 752 — 833 145 568 2,107 663 3,483 $ 9,122 $ 6,362 $ 7,693 $ (10,026 ) $ 13,151 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS (Unaudited) As of December 31, 2014 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 415 — — — 415 Affiliated companies 484 487 674 (1,120 ) 525 Other 66 21 20 — 107 Notes receivable from affiliated companies 339 838 272 (1,449 ) — Materials and supplies 67 202 223 — 492 Derivatives 147 — — — 147 Collateral 229 — — — 229 Prepayments and other 56 41 — (2 ) 95 1,803 1,591 1,189 (2,571 ) 2,012 PROPERTY, PLANT AND EQUIPMENT: In service 133 6,217 7,628 (382 ) 13,596 Less — Accumulated provision for depreciation 36 2,058 3,305 (191 ) 5,208 97 4,159 4,323 (191 ) 8,388 Construction work in progress 3 206 801 — 1,010 100 4,365 5,124 (191 ) 9,398 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,365 — 1,365 Investment in affiliated companies 6,607 — — (6,607 ) — Other — 10 — — 10 6,607 10 1,365 (6,607 ) 1,375 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 276 76 — (352 ) — Customer intangibles 78 — — — 78 Goodwill 23 — — — 23 Property taxes — 14 27 — 41 Unamortized sale and leaseback costs — — — 217 217 Derivatives 52 — — — 52 Other 34 277 7 (204 ) 114 463 367 34 (339 ) 525 $ 8,973 $ 6,333 $ 7,712 $ (9,708 ) $ 13,310 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ 18 $ 164 $ 348 $ (24 ) $ 506 Short-term borrowings- Affiliated companies 1,135 321 28 (1,449 ) 35 Other 90 9 — — 99 Accounts payable- Affiliated companies 1,068 197 219 (1,068 ) 416 Other 46 202 — — 248 Accrued taxes 2 62 161 (123 ) 102 Derivatives 166 — — — 166 Other 72 56 9 47 184 2,597 1,011 765 (2,617 ) 1,756 CAPITALIZATION: Total equity 5,585 2,561 4,014 (6,575 ) 5,585 Long-term debt and other long-term obligations 695 2,215 859 (1,161 ) 2,608 6,280 4,776 4,873 (7,736 ) 8,193 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 824 824 Accumulated deferred income taxes 13 — 678 (180 ) 511 Asset retirement obligations — 189 652 — 841 Retirement benefits 36 288 — — 324 Derivatives 14 — — — 14 Other 33 69 744 1 847 96 546 2,074 645 3,361 $ 8,973 $ 6,333 $ 7,712 $ (9,708 ) $ 13,310 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited) For the Six Months Ended June 30, 2015 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (600 ) $ 275 $ 680 $ (12 ) $ 343 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 674 62 — (612 ) 124 Redemptions and Repayments- Long-term debt (17 ) (12 ) (52 ) 12 (69 ) Short-term borrowings, net — — (28 ) 28 — Other — (2 ) — — (2 ) Net cash provided from (used for) financing activities 657 48 (80 ) (572 ) 53 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (2 ) (95 ) (167 ) — (264 ) Nuclear fuel — — (97 ) — (97 ) Proceeds from asset sales — 3 — — 3 Sales of investment securities held in trusts — — 376 — 376 Purchases of investment securities held in trusts — — (404 ) — (404 ) Loans to affiliated companies, net (55 ) (234 ) (308 ) 584 (13 ) Other — 3 — — 3 Net cash used for investing activities (57 ) (323 ) (600 ) 584 (396 ) 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, 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

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission, and CES. Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does not have separate reportable operating segments. The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes regulated electric generation facilities located primarily in West Virginia, Virginia and New Jersey that MP and JCP&L, respectively, own or contractually control. The segment's results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs. This business segment currently controls 3,790 MWs of generation capacity. The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, and certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP) 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 primarily from transmission services provided pursuant to the PJM Tariff to LSEs. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities. The CES segment, through FES and AE Supply, primarily supplies electricity to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. This business segment currently controls 13,169 MWs of capacity. The CES segment’s net income is primarily derived from electric generation sales less the related costs of electricity generation, including fuel, purchased power and net transmission (including congestion) and ancillary costs and capacity costs charged by PJM to deliver energy to the segment’s customers. In 2014, the CES segment began reducing its exposure to weather-sensitive loads, 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. Corporate support and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment and interest expense on stand-alone holding company debt and corporate income taxes are categorized as Corporate/Other for reportable business segment purposes. As of June 30, 2015, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of which 28% was subject to variable-interest rates, and $1.9 billion was borrowed by FE under its revolving credit facility. Reconciling adjustments for the elimination of inter-segment transactions are shown separately in the accompanying table. Segment Financial Information Three Months Ended Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Reconciling Adjustments Consolidated (In millions) June 30, 2015 External revenues $ 2,239 $ 269 $ 1,034 $ (42 ) $ (35 ) $ 3,465 Internal revenues — — 162 — (162 ) — Total revenues 2,239 269 1,196 (42 ) (197 ) 3,465 Depreciation 170 38 99 15 — 322 Amortization of regulatory assets, net 57 2 — — — 59 Investment income (loss) 12 — (7 ) 2 (10 ) (3 ) Interest expense 146 40 48 49 (1 ) 282 Income taxes (benefits) 91 52 (7 ) (19 ) (2 ) 115 Net income (loss) 156 89 (12 ) (46 ) — 187 Total assets 28,353 7,055 16,711 886 — 53,005 Total goodwill 5,092 526 800 — — 6,418 Property additions 312 297 191 18 — 818 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 164 30 96 12 — 302 Amortization of regulatory assets, net 16 3 — — 1 20 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 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 Six Months Ended June 30, 2015 External revenues $ 4,801 $ 507 $ 2,209 $ (84 ) $ (71 ) $ 7,362 Internal revenues — — 422 — (422 ) — Total revenues 4,801 507 2,631 (84 ) (493 ) 7,362 Depreciation 342 75 195 29 — 641 Amortization of regulatory assets, net 86 5 — — — 91 Investment income 25 — 4 5 (20 ) 14 Interest expense 290 79 96 96 — 561 Income taxes (benefits) 213 94 (11 ) (37 ) — 259 Income (loss) from continuing operations 364 161 (21 ) (95 ) — 409 Discontinued operations, net of tax — — — — — — Net income (loss) 364 161 (21 ) (95 ) — 409 Property additions 592 551 317 26 — 1,486 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 326 60 187 23 — 596 Amortization of regulatory assets, net (15 ) 6 — — 1 (8 ) 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

Discontinued Operations

Discontinued Operations	6 Months Ended
	Jun. 30, 2015
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	DISCONTINUED OPERATIONS On February 12, 2014, certain of FirstEnergy's subsidiaries sold eleven hydroelectric power stations to a subsidiary of LS Power for approximately $394 million (FES - $307 million ). The carrying value of the assets sold was $235 million (FES - $122 million ), including goodwill of $29 million (FES - $1 million ). Pre-tax income for the hydroelectric facilities of $155 million (FES - $186 million ) for the six months ended June 30, 2014 , was included in discontinued operations in the Consolidated Statement of Income. 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 , were included in discontinued operations in the Consolidated Statement of Income.

Organization and Basis of Pre26

Organization and Basis of Presentation (Policies)	6 Months Ended
	Jun. 30, 2015
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 necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued.
Consolidation 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.
New Accounting Pronouncements	New Accounting Pronouncements In May 2014, the FASB issued "Revenue from Contracts with Customers", requiring entities to recognize revenue by applying a five-step model in accordance with the core principle to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue recognition are expanded. This standard is currently 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. In July 2015, the FASB voted to proceed with a one-year deferral of the revenue recognition standard for all entities, with early adoption as of the original effective date permitted. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In February 2015, the FASB issued, "Consolidations: Amendments to the Consolidation Analysis", which amends current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate whether an entity should be consolidated. This standard is effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. A reporting entity must apply the amendments using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments retrospectively. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In April 2015, the FASB issued, "Simplifying the Presentation of Debt Issuance Costs", which requires debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. The guidance is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Upon adoption, an entity must apply the new guidance retrospectively to all prior periods presented in the financial statements. FirstEnergy does not expect this amendment to have a material effect on its financial statements.
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 based on control and economics 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 power and benefits, such that an entity has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary.
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 27

Earnings Per Share of Common Stock (Tables)	6 Months Ended
	Jun. 30, 2015
Earnings Per Share [Abstract]
Reconciliation of basic and diluted earnings per share	The following table reconciles basic and diluted earnings 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 per Share of Common Stock 2015 2014 2015 2014 Income from continuing operations $ 187 $ 64 $ 409 $ 186 Discontinued operations (Note 13) — — — 86 Net income $ 187 $ 64 $ 409 $ 272 Weighted average number of basic shares outstanding 422 420 422 419 Assumed exercise of dilutive stock options and awards (1) 1 1 1 1 Weighted average number of diluted shares outstanding 423 421 423 420 Earnings per share: Basic earnings per share: Income from continuing operations $ 0.44 $ 0.16 $ 0.97 $ 0.45 Discontinued operations (Note 13) — — — 0.20 Net earnings per basic share $ 0.44 $ 0.16 $ 0.97 $ 0.65 Diluted earnings per share: Income from continuing operations $ 0.44 $ 0.15 $ 0.97 $ 0.45 Discontinued operations (Note 13) — — — 0.20 Net earnings per diluted share $ 0.44 $ 0.15 $ 0.97 $ 0.65 (1) For both the three months ended June 30, 2015 and June 30, 2014 , one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

Pension and Other Postemploym28

Pension and Other Postemployment Benefits (Tables)	6 Months Ended
	Jun. 30, 2015
Compensation and Retirement Disclosure [Abstract]
Components of Net Periodic Benefit Costs	The components of the consolidated net periodic cost (credits) for pension and OPEB (including amounts capitalized) were as follows: Components of Net Periodic Benefit Costs (Credits) Pension OPEB For the Three Months Ended June 30, 2015 2014 2015 2014 (In millions) Service costs $ 48 $ 41 $ 1 $ 2 Interest costs 96 101 7 10 Expected return on plan assets (111 ) (115 ) (8 ) (8 ) Amortization of prior service costs (credits) 2 2 (34 ) (44 ) Net periodic costs (credits) $ 35 $ 29 $ (34 ) $ (40 ) Components of Net Periodic Benefit Costs (Credits) Pensions OPEB For the Six Months Ended June 30, 2015 2014 2015 2014 (In millions) Service costs $ 96 $ 83 $ 2 $ 4 Interest costs 192 201 14 20 Expected return on plan assets (222 ) (230 ) (16 ) (16 ) Amortization of prior service costs (credits) 4 4 (67 ) (88 ) Net periodic costs (credits) $ 70 $ 58 $ (67 ) $ (80 )
Net Periodic Pension and OPEB Costs	FES' share of the net periodic pension and OPEB costs (credits) were as follows: Pension OPEB 2015 2014 2015 2014 (In millions) For the Three Months Ended June 30, $ 4 $ 4 $ (5 ) $ (5 ) For the Six Months Ended June 30, 8 8 (10 ) (10 ) Pension and OPEB obligations are allocated to FE's subsidiaries, including FES, employing the plan participants. The net periodic pension and OPEB costs (credits) (net of amounts capitalized) recognized in earnings by FE and FES were as follows: Net Periodic Benefit Expense (Credit) Pension OPEB For the Three Months Ended June 30, 2015 2014 2015 2014 (In millions) FirstEnergy $ 24 $ 21 $ (22 ) $ (27 ) FES 4 4 (4 ) (5 ) Net Periodic Benefit Expense (Credit) Pensions OPEB For the Six Months Ended June 30, 2015 2014 2015 2014 (In millions) FirstEnergy $ 49 $ 42 $ (45 ) $ (54 ) FES 8 8 (8 ) (9 )

Accumulated Other Comprehensi29

Accumulated Other Comprehensive Income (Tables)	6 Months Ended
	Jun. 30, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of Accumulated Other Comprehensive Income	The changes in AOCI, net of tax, in the three and six months ended June 30, 2015 and 2014 , for FirstEnergy 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, 2015 $ (36 ) $ 28 $ 238 $ 230 Other comprehensive loss before reclassifications — (7 ) — (7 ) Amounts reclassified from AOCI 1 (7 ) (32 ) (38 ) Other comprehensive income (loss) 1 (14 ) (32 ) (45 ) Income tax (benefits) on other comprehensive income (loss) 1 (5 ) (13 ) (17 ) Net other comprehensive loss — (9 ) (19 ) (28 ) AOCI Balance as of June 30, 2015 $ (36 ) $ 19 $ 219 $ 202 AOCI Balance as of April 1, 2014 $ (36 ) $ 22 $ 285 $ 271 Other comprehensive income before reclassifications — 49 — 49 Amounts reclassified from AOCI (1 ) (19 ) (42 ) (62 ) Other comprehensive income (loss) (1 ) 30 (42 ) (13 ) Income tax (benefits) on other comprehensive income (loss) (1 ) 11 (16 ) (6 ) Net other comprehensive income (loss) — 19 (26 ) (7 ) AOCI Balance as of June 30, 2014 $ (36 ) $ 41 $ 259 $ 264 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, 2015 $ (37 ) $ 25 $ 258 $ 246 Other comprehensive income before reclassifications — 7 — 7 Amounts reclassified from AOCI 2 (17 ) (63 ) (78 ) Other comprehensive income (loss) 2 (10 ) (63 ) (71 ) Income tax (benefits) on other comprehensive income (loss) 1 (4 ) (24 ) (27 ) Net other comprehensive income (loss) 1 (6 ) (39 ) (44 ) AOCI Balance as of June 30, 2015 $ (36 ) $ 19 $ 219 $ 202 AOCI Balance as of January 1, 2014 $ (36 ) $ 9 $ 311 $ 284 Other comprehensive income before reclassifications — 84 — 84 Amounts reclassified from AOCI (1 ) (33 ) (84 ) (118 ) Other comprehensive income (loss) (1 ) 51 (84 ) (34 ) Income tax (benefits) on other comprehensive income (loss) (1 ) 19 (32 ) (14 ) Net other comprehensive income (loss) — 32 (52 ) (20 ) AOCI Balance as of June 30, 2014 $ (36 ) $ 41 $ 259 $ 264
Reclassification out of Accumulated Other Comprehensive Income	The following amounts were reclassified from AOCI for FirstEnergy in the three and six months ended June 30, 2015 and 2014 : Three Months Ended June 30, Six Months Ended June 30 Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (2) 2015 2014 2015 2014 (In millions) Gains & losses on cash flow hedges Commodity contracts $ (1 ) $ (3 ) $ (2 ) $ (5 ) Other operating expenses Long-term debt 2 2 4 4 Interest expense 1 (1 ) 2 (1 ) Total before taxes (1 ) 1 (1 ) 1 Income taxes $ — $ — $ 1 $ — Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (7 ) $ (19 ) $ (17 ) $ (33 ) Investment income (loss) 2 7 6 12 Income taxes $ (5 ) $ (12 ) $ (11 ) $ (21 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (32 ) $ (42 ) $ (63 ) $ (84 ) (1) 13 16 24 32 Income taxes $ (19 ) $ (26 ) $ (39 ) $ (52 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI.
FES
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of Accumulated Other Comprehensive Income	The changes in AOCI, net of tax, in the three and six months ended June 30, 2015 and 2014 , for FES are shown in the following tables: 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, 2015 $ (8 ) $ 24 $ 40 $ 56 Other comprehensive loss before reclassifications — (7 ) — (7 ) Amounts reclassified from AOCI (1 ) (5 ) (4 ) (10 ) Other comprehensive loss (1 ) (12 ) (4 ) (17 ) Income tax benefits on other comprehensive loss — (4 ) (2 ) (6 ) Net other comprehensive loss (1 ) (8 ) (2 ) (11 ) AOCI Balance as of June 30, 2015 $ (9 ) $ 16 $ 38 $ 45 AOCI Balance as of April 1, 2014 $ (2 ) $ 20 $ 44 $ 62 Other comprehensive income before reclassifications — 43 — 43 Amounts reclassified from AOCI (3 ) (18 ) (5 ) (26 ) Other comprehensive income (loss) (3 ) 25 (5 ) 17 Income tax (benefits) on other comprehensive income (loss) — 9 (2 ) 7 Net other comprehensive income (loss) (3 ) 16 (3 ) 10 AOCI Balance as of June 30, 2014 $ (5 ) $ 36 $ 41 $ 72 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, 2015 $ (7 ) $ 21 $ 43 $ 57 Other comprehensive income before reclassifications — 6 — 6 Amounts reclassified from AOCI (2 ) (15 ) (8 ) (25 ) Other comprehensive loss (2 ) (9 ) (8 ) (19 ) Income tax benefits on other comprehensive loss — (4 ) (3 ) (7 ) Net other comprehensive loss (2 ) (5 ) (5 ) (12 ) AOCI Balance as of June 30, 2015 $ (9 ) $ 16 $ 38 $ 45 AOCI Balance as of January 1, 2014 $ (1 ) $ 8 $ 47 $ 54 Other comprehensive income before reclassifications — 76 — 76 Amounts reclassified from AOCI (5 ) (32 ) (10 ) (47 ) Other comprehensive income (loss) (5 ) 44 (10 ) 29 Income tax (benefits) on other comprehensive income (loss) (1 ) 16 (4 ) 11 Net other comprehensive income (loss) (4 ) 28 (6 ) 18 AOCI Balance as of June 30, 2014 $ (5 ) $ 36 $ 41 $ 72
Reclassification out of Accumulated Other Comprehensive Income	The following amounts were reclassified from AOCI for FES in the three and six months ended June 30, 2015 and 2014 : Three Months Ended June 30, Six Months Ended June 30, Affected Line Item in Consolidated Statements of Operations Reclassifications from AOCI (2) 2015 2014 2015 2014 (In millions) Gains & losses on cash flow hedges Commodity contracts $ (1 ) $ (3 ) $ (2 ) $ (5 ) Other operating expenses — 1 — 2 Income tax benefits $ (1 ) $ (2 ) $ (2 ) $ (3 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (5 ) $ (18 ) $ (15 ) $ (32 ) Investment income 2 6 6 11 Income tax benefits $ (3 ) $ (12 ) $ (9 ) $ (21 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (4 ) $ (5 ) $ (8 ) $ (10 ) (1) 2 2 3 4 Income tax benefits $ (2 ) $ (3 ) $ (5 ) $ (6 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Operations from AOCI.

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	6 Months Ended
	Jun. 30, 2015
Variable Interest Entities [Abstract]
Net exposure to loss based upon the casualty value provisions	The following table discloses each company’s net exposure to loss based upon the casualty value provisions as of June 30, 2015 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy $ 1,231 $ 958 $ 273 FES 1,151 929 222

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value of Financial Instruments [Line Items]
Assets and liabilities measured on recurring basis	The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: FirstEnergy Recurring Fair Value Measurements June 30, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,292 $ — $ 1,292 $ — $ 1,221 $ — $ 1,221 Derivative assets - commodity contracts 1 251 — 252 1 171 — 172 Derivative assets - FTRs — — 23 23 — — 39 39 Derivative assets - NUG contracts (1) — — 1 1 — — 2 2 Equity securities (2) 697 — — 697 592 — — 592 Foreign government debt securities — 81 — 81 — 76 — 76 U.S. government debt securities — 178 — 178 — 182 — 182 U.S. state debt securities — 241 — 241 — 237 — 237 Other (3) 90 128 — 218 55 256 — 311 Total assets $ 788 $ 2,171 $ 24 $ 2,983 $ 648 $ 2,143 $ 41 $ 2,832 Liabilities Derivative liabilities - commodity contracts $ (7 ) $ (214 ) $ — $ (221 ) $ (26 ) $ (141 ) $ — $ (167 ) Derivative liabilities - FTRs — — (13 ) (13 ) — — (14 ) (14 ) Derivative liabilities - NUG contracts (1) — — (141 ) (141 ) — — (153 ) (153 ) Total liabilities $ (7 ) $ (214 ) $ (154 ) $ (375 ) $ (26 ) $ (141 ) $ (167 ) $ (334 ) Net assets (liabilities) (4) $ 781 $ 1,957 $ (130 ) $ 2,608 $ 622 $ 2,002 $ (126 ) $ 2,498 (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (3) Primarily consists of short-term cash investments. (4) Excludes $(6) million and $40 million as of June 30, 2015 and December 31, 2014 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts	The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended June 30, 2015 and December 31, 2014 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2014 Balance $ 20 $ (222 ) $ (202 ) $ 4 $ (12 ) $ (8 ) Unrealized gain (loss) 2 (2 ) — 47 (1 ) 46 Purchases — — — 26 (16 ) 10 Settlements (20 ) 71 51 (38 ) 15 (23 ) December 31, 2014 Balance $ 2 $ (153 ) $ (151 ) $ 39 $ (14 ) $ 25 Unrealized gain (loss) 1 (17 ) (16 ) 5 3 8 Purchases — — — 22 (11 ) 11 Settlements (2 ) 29 27 (43 ) 9 (34 ) June 30, 2015 Balance $ 1 $ (141 ) $ (140 ) $ 23 $ (13 ) $ 10 (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, 2015 : Fair Value, Net (In millions) Valuation Technique Significant Input Range Weighted Average Units FTRs $ 10 Model RTO auction clearing prices ($5.10) to $9.20 $1.40 Dollars/MWH NUG Contracts $ (140 ) Model Generation 500 to 4,317,000 833,000 MWH Regional electricity prices $44.00 to $68.90 $51.00 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, 2015 and December 31, 2014 : June 30, 2015 (1) December 31, 2014 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,808 $ 25 $ 1,833 $ 1,724 $ 27 $ 1,751 FES 824 13 837 788 13 801 Equity securities FirstEnergy $ 664 $ 33 $ 697 $ 533 $ 58 $ 591 FES 462 19 481 329 31 360 (1) Excludes short-term cash investments: FE Consolidated - $58 million ; FES - $47 million . (2) Excludes short-term cash investments: FE Consolidated - $241 million ; FES - $204 million .
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income	Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three and six months ended June 30, 2015 and 2014 were as follows: Three Months Ended June 30, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 448 $ 42 $ (39 ) $ (17 ) $ 25 FES 187 32 (27 ) (16 ) 15 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 Six Months Ended June 30, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 819 $ 102 $ (89 ) $ (24 ) $ 50 FES 376 70 (55 ) (22 ) 29 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
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, 2015 and December 31, 2014 : June 30, 2015 December 31, 2014 Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt Securities FirstEnergy $ 10 $ 2 $ 12 $ 13 $ 4 $ 17
Fair value and related carrying amounts of long-term debt and other long-term obligations	The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations, excluding capital lease obligations and net unamortized premiums and discounts: June 30, 2015 December 31, 2014 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 19,728 $ 21,195 $ 19,828 $ 21,733 FES 3,028 3,146 3,097 3,241
FES
Fair Value of Financial Instruments [Line Items]
Assets and liabilities measured on recurring basis	FES Recurring Fair Value Measurements June 30, 2015 December 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 701 $ — $ 701 $ — $ 655 $ — $ 655 Derivative assets - commodity contracts 1 251 — 252 1 171 — 172 Derivative assets - FTRs — — 10 10 — — 27 27 Equity securities (1) 481 — — 481 360 — — 360 Foreign government debt securities — 64 — 64 — 57 — 57 U.S. government debt securities — 27 — 27 — 46 — 46 U.S. state debt securities — 4 — 4 — 4 — 4 Other (2) — 87 — 87 — 199 — 199 Total assets $ 482 $ 1,134 $ 10 $ 1,626 $ 361 $ 1,132 $ 27 $ 1,520 Liabilities Derivative liabilities - commodity contracts $ (7 ) $ (214 ) $ — $ (221 ) $ (26 ) $ (141 ) $ — $ (167 ) Derivative liabilities - FTRs — — (11 ) (11 ) — — (13 ) (13 ) Total liabilities $ (7 ) $ (214 ) $ (11 ) $ (232 ) $ (26 ) $ (141 ) $ (13 ) $ (180 ) Net assets (liabilities) (3) $ 475 $ 920 $ (1 ) $ 1,394 $ 335 $ 991 $ 14 $ 1,340 (1) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (2) Primarily consists of short-term cash investments. (3) Excludes $1 million and $44 million as of June 30, 2015 and December 31, 2014 , 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, 2015 and December 31, 2014 : Derivative Asset Derivative Liability Net Asset (Liability) (In millions) January 1, 2014 Balance $ 3 $ (11 ) $ (8 ) Unrealized gain (loss) 34 (1 ) 33 Purchases 15 (16 ) (1 ) Settlements (25 ) 15 (10 ) December 31, 2014 Balance $ 27 $ (13 ) $ 14 Unrealized gain 4 3 7 Purchases 9 (10 ) (1 ) Settlements (30 ) 9 (21 ) June 30, 2015 Balance $ 10 $ (11 ) $ (1 )
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, 2015 : Fair Value, Net (In millions) Valuation Technique Significant Input Range Weighted Average Units FTRs $ (1 ) Model RTO auction clearing prices ($5.10) to $9.20 $1.00 Dollars/MWH

Derivative Instruments (Tables)

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair value of derivatives instruments	The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets: Derivative Assets Derivative Liabilities Fair Value Fair Value June 30, December 31, June 30, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 149 $ 121 Commodity Contracts $ (148 ) $ (154 ) FTRs 22 38 FTRs (12 ) (13 ) 171 159 (160 ) (167 ) Noncurrent Liabilities - Adverse Power Contract Liability Deferred Charges and Other Assets - Other NUGs (1) (141 ) (153 ) Commodity Contracts 103 51 Noncurrent Liabilities - Other FTRs 1 1 Commodity Contracts (73 ) (13 ) NUGs (1) 1 2 FTRs (1 ) (1 ) 105 54 (215 ) (167 ) Derivative Assets $ 276 $ 213 Derivative Liabilities $ (375 ) $ (334 )
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, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 252 $ (202 ) $ — $ 50 FTRs 23 (13 ) — 10 NUG contracts 1 — — 1 $ 276 $ (215 ) $ — $ 61 Derivative Liabilities Commodity contracts $ (221 ) $ 202 $ 11 $ (8 ) FTRs (13 ) 13 — — NUG contracts (141 ) — — (141 ) $ (375 ) $ 215 $ 11 $ (149 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2014 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 172 $ (126 ) $ — $ 46 FTRs 39 (14 ) — 25 NUG contracts 2 — — 2 $ 213 $ (140 ) $ — $ 73 Derivative Liabilities Commodity contracts $ (167 ) $ 126 $ 35 $ (6 ) FTRs (14 ) 14 — — NUG contracts (153 ) — — (153 ) $ (334 ) $ 140 $ 35 $ (159 )
Volume of First Energy's outstanding derivative transactions	The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of June 30, 2015 : Purchases Sales Net Units (In millions) Power Contracts 23 54 (31 ) MWH FTRs 54 — 54 MWH NUGs 5 — 5 MWH Natural Gas 39 1 38 mmBTU
Effect of derivative instruments on statements of income and comprehensive income	The effect of active derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income during the three and six months ended June 30, 2015 and 2014 , are summarized in the following tables: Three Months Ended June 30, Commodity Contracts FTRs Interest Rate Swaps Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense (1) $ 11 $ (2 ) $ — $ 9 Realized Gain (Loss) Reclassified to: Revenues (2) $ 8 $ 8 $ — $ 16 Purchased Power Expense (3) (25 ) — — (25 ) Other Operating Expense (4) — (13 ) — (13 ) Fuel Expense (5 ) — — (5 ) (1) Includes $11 million for commodity contracts and ($2) million for FTRs associated with FES. (2) Includes $8 million for commodity contacts and $8 million for FTRs associated with FES. (3) Includes ($25) million for commodity contracts associated with FES. (4) Includes ($13) million for FTRs associated with FES. Three Months Ended June 30, Commodity Contracts FTRs Interest Rate Swaps Total (In millions) 2014 Unrealized Gain (Loss) Recognized in: Other Operating Expense (5) $ (70 ) $ 13 $ — $ (57 ) Realized Gain (Loss) Reclassified to: Revenues (6) $ 2 $ (1 ) $ — $ 1 Purchased Power Expense (7) 22 — — 22 Other Operating Expense (8) — (10 ) — (10 ) Fuel Expense 2 — — 2 Interest Expense — — 6 6 (5) Includes ($70) million for commodity contracts and $13 million for FTRs associated with FES. (6) Represents losses on structured financial contracts. Includes $2 million for commodity contracts and ($1) million for FTRs associated with FES. (7) 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. (8) Includes ($9) million for FTRs associated with FES. Six Months Ended June 30, Commodity Contracts FTRs Interest Rate Swaps Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense (1) $ 22 $ (15 ) $ — $ 7 Realized Gain (Loss) Reclassified to: Revenues (2) $ 7 $ 45 $ — $ 52 Purchased Power Expense (3) (28 ) — — (28 ) Other Operating Expense (4) — (26 ) — (26 ) Fuel Expense (21 ) — — (21 ) (1) Includes $22 million for commodity contracts and ($14) million for FTRs associated with FES. (2) Includes $7 million for commodity contracts and $44 million for FTRs associated with FES. (3) Includes ($28) million for commodity contracts associated with FES. (4) Includes ($26) million for FTRs associated with FES. Six Months Ended June 30, Commodity Contracts FTRs Interest Rate Swaps Total (In millions) 2014 Unrealized Gain (Loss) Recognized in: Other Operating Expense (5) $ (58 ) $ 18 $ — $ (40 ) Realized Gain (Loss) Reclassified to: Revenues (6) $ (11 ) $ 51 $ — $ 40 Purchased Power Expense (7) 458 — — 458 Other Operating Expense (8) — (17 ) — (17 ) Fuel Expense 11 — — 11 Interest Expense — — 6 6 (5) Includes ($58) million for commodity contracts and $18 million for FTRs associated with FES. (6) Represents losses on structured financial contracts. Includes ($11) million for commodity contracts and $50 million for FTRs 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 ($16) million for FTRs associated with FES.
Reconciliation of changes in the fair value of certain contracts that are deferred	The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during the three and six months ended June 30, 2015 and 2014 . Changes in the value of these instruments are deferred for future recovery from (or credit to) customers: Three Months Ended June 30, Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of April 1, 2015 $ (148 ) $ 1 $ (147 ) Unrealized loss (8 ) — (8 ) Purchases — 12 12 Settlements 16 (1 ) 15 Outstanding net asset (liability) as of June 30, 2015 $ (140 ) $ 12 $ (128 ) Outstanding net asset (liability) as of April 1, 2014 $ (185 ) $ 3 $ (182 ) Unrealized loss (2 ) — (2 ) Purchases — 11 11 Settlements 18 (4 ) 14 Outstanding net asset (liability) as of June 30, 2014 $ (169 ) $ 10 $ (159 ) Six Months Ended June 30, Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of January 1, 2015 $ (151 ) $ 11 $ (140 ) Unrealized gain (loss) (16 ) 1 (15 ) Purchases — 12 12 Settlements 27 (12 ) 15 Outstanding net asset (liability) as of June 30, 2015 $ (140 ) $ 12 $ (128 ) Outstanding net liability as of January 1, 2014 $ (202 ) $ — $ (202 ) Unrealized gain 25 4 29 Purchases — 11 11 Settlements 8 (5 ) 3 Outstanding net asset (liability) as of June 30, 2014 $ (169 ) $ 10 $ (159 )

Commitments, Guarantees and C33

Commitments, Guarantees and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule of Guarantor Obligations	The following table discloses the additional credit contingent contractual obligations that may be required under certain events as of June 30, 2015 : Collateral Provisions FES AE Supply Utilities Total (In millions) Split Rating (One rating agency's rating below investment grade) $ 410 $ 6 $ 50 $ 466 BB+/Ba1 Credit Ratings $ 447 $ 6 $ 50 $ 503 Full impact of credit contingent contractual obligations $ 492 $ 16 $ 50 $ 558

Supplemental Guarantor Inform34

Supplemental Guarantor Information (Tables)	6 Months Ended
	Jun. 30, 2015
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, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 1,074 $ 346 $ 456 $ (757 ) $ 1,119 OPERATING EXPENSES: Fuel — 150 41 — 191 Purchased power from affiliates 768 — 66 (757 ) 77 Purchased power from non-affiliates 392 — — — 392 Other operating expenses 102 75 164 12 353 Provision for depreciation 2 32 47 — 81 General taxes 11 7 7 — 25 Total operating expenses 1,275 264 325 (745 ) 1,119 OPERATING INCOME (LOSS) (201 ) 82 131 (12 ) — OTHER INCOME (EXPENSE): Investment income, including net income from equity investees 119 5 3 (126 ) 1 Miscellaneous income 1 3 — — 4 Interest expense — affiliates (7 ) (2 ) (1 ) 8 (2 ) Interest expense — other (13 ) (26 ) (12 ) 14 (37 ) Capitalized interest — 2 7 — 9 Total other income (expense) 100 (18 ) (3 ) (104 ) (25 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (101 ) 64 128 (116 ) (25 ) INCOME TAXES (BENEFITS) (80 ) 28 47 1 (4 ) NET INCOME (LOSS) $ (21 ) $ 36 $ 81 $ (117 ) $ (21 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (21 ) $ 36 $ 81 $ (117 ) $ (21 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (4 ) (4 ) — 4 (4 ) Amortized gain on derivative hedges (1 ) — — — (1 ) Change in unrealized gain on available-for-sale securities (12 ) — (12 ) 12 (12 ) Other comprehensive loss (17 ) (4 ) (12 ) 16 (17 ) Income tax benefits on other comprehensive loss (6 ) (2 ) (4 ) 6 (6 ) Other comprehensive loss, net of tax (11 ) (2 ) (8 ) 10 (11 ) COMPREHENSIVE INCOME (LOSS) $ (32 ) $ 34 $ 73 $ (107 ) $ (32 ) FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) (Unaudited) For the Six Months Ended June 30, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 2,406 $ 839 $ 963 $ (1,712 ) $ 2,496 OPERATING EXPENSES: Fuel — 330 91 — 421 Purchased power from affiliates 1,725 — 134 (1,712 ) 147 Purchased power from non-affiliates 935 — — — 935 Other operating expenses 282 142 318 24 766 Provision for depreciation 5 62 95 (1 ) 161 General taxes 26 15 13 — 54 Total operating expenses 2,973 549 651 (1,689 ) 2,484 OPERATING INCOME (LOSS) (567 ) 290 312 (23 ) 12 OTHER INCOME (EXPENSE): Loss on debt redemptions — — — — — Investment income, including net income from equity investees 360 8 17 (371 ) 14 Miscellaneous income 1 3 — — 4 Interest expense — affiliates (13 ) (4 ) (2 ) 15 (4 ) Interest expense — other (26 ) (52 ) (25 ) 29 (74 ) Capitalized interest — 3 15 — 18 Total other income (expense) 322 (42 ) 5 (327 ) (42 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) (245 ) 248 317 (350 ) (30 ) INCOME TAXES (BENEFITS) (221 ) 95 117 3 (6 ) INCOME (LOSS) FROM CONTINUING OPERATIONS (24 ) 153 200 (353 ) (24 ) Discontinued operations (Note 13) — — — — — NET INCOME (LOSS) $ (24 ) $ 153 $ 200 $ (353 ) $ (24 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (24 ) $ 153 $ 200 $ (353 ) $ (24 ) OTHER COMPREHENSIVE INCOME (LOSS): Pensions and OPEB prior service costs (8 ) (8 ) — 8 (8 ) Amortized gain on derivative hedges (2 ) — — — (2 ) Change in unrealized gain on available-for-sale securities (9 ) — (9 ) 9 (9 ) Other comprehensive loss (19 ) (8 ) (9 ) 17 (19 ) Income tax benefits on other comprehensive loss (7 ) (3 ) (3 ) 6 (7 ) Other comprehensive loss, net of tax (12 ) (5 ) (6 ) 11 (12 ) COMPREHENSIVE INCOME (LOSS) $ (36 ) $ 148 $ 194 $ (342 ) $ (36 ) 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): Investment income, including net income from equity investees 2 2 23 (3 ) 24 Miscellaneous income 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) BEFORE INCOME TAXES (BENEFITS) (225 ) 80 145 (154 ) (154 ) INCOME TAXES (BENEFITS) (137 ) 23 45 2 (67 ) 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): Pension 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, including net income from equity investees 3 3 44 (6 ) 44 Miscellaneous income 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 )
Condensed Consolidating Balance Sheets	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS (Unaudited) As of June 30, 2015 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 325 — — — 325 Affiliated companies 340 287 301 (525 ) 403 Other 45 2 10 — 57 Notes receivable from affiliated companies 394 1,072 580 (2,033 ) 13 Materials and supplies 54 201 221 — 476 Derivatives 158 — — — 158 Collateral 140 — — — 140 Prepayments and other 80 59 — — 139 1,536 1,623 1,112 (2,558 ) 1,713 PROPERTY, PLANT AND EQUIPMENT: In service 90 6,351 7,919 (382 ) 13,978 Less — Accumulated provision for depreciation 34 2,107 3,483 (193 ) 5,431 56 4,244 4,436 (189 ) 8,547 Construction work in progress 3 157 757 — 917 59 4,401 5,193 (189 ) 9,464 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,365 — 1,365 Investment in affiliated companies 6,957 — — (6,957 ) — Other — 10 — — 10 6,957 10 1,365 (6,957 ) 1,375 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 322 — — (322 ) — Customer intangibles 70 — — — 70 Goodwill 23 — — — 23 Property taxes — 7 12 — 19 Unamortized sale and leaseback costs — — — 266 266 Derivatives 104 — — — 104 Other 51 321 11 (266 ) 117 570 328 23 (322 ) 599 $ 9,122 $ 6,362 $ 7,693 $ (10,026 ) $ 13,151 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 167 $ 541 $ (25 ) $ 683 Short-term borrowings- Affiliated companies 1,649 384 — (2,033 ) — Other 250 8 — — 258 Accounts payable- Affiliated companies 581 133 164 (581 ) 297 Other 24 93 — — 117 Accrued taxes 3 41 50 (15 ) 79 Derivatives 155 3 — — 158 Other 66 54 9 34 163 2,728 883 764 (2,620 ) 1,755 CAPITALIZATION: Total equity 5,554 2,712 4,208 (6,920 ) 5,554 Long-term debt and other long-term obligations 695 2,199 614 (1,149 ) 2,359 6,249 4,911 4,822 (8,069 ) 7,913 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 807 807 Accumulated deferred income taxes 7 29 696 (144 ) 588 Asset retirement obligations — 191 659 — 850 Retirement benefits 36 295 — — 331 Derivatives 69 5 — — 74 Other 33 48 752 — 833 145 568 2,107 663 3,483 $ 9,122 $ 6,362 $ 7,693 $ (10,026 ) $ 13,151 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS (Unaudited) As of December 31, 2014 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 415 — — — 415 Affiliated companies 484 487 674 (1,120 ) 525 Other 66 21 20 — 107 Notes receivable from affiliated companies 339 838 272 (1,449 ) — Materials and supplies 67 202 223 — 492 Derivatives 147 — — — 147 Collateral 229 — — — 229 Prepayments and other 56 41 — (2 ) 95 1,803 1,591 1,189 (2,571 ) 2,012 PROPERTY, PLANT AND EQUIPMENT: In service 133 6,217 7,628 (382 ) 13,596 Less — Accumulated provision for depreciation 36 2,058 3,305 (191 ) 5,208 97 4,159 4,323 (191 ) 8,388 Construction work in progress 3 206 801 — 1,010 100 4,365 5,124 (191 ) 9,398 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,365 — 1,365 Investment in affiliated companies 6,607 — — (6,607 ) — Other — 10 — — 10 6,607 10 1,365 (6,607 ) 1,375 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 276 76 — (352 ) — Customer intangibles 78 — — — 78 Goodwill 23 — — — 23 Property taxes — 14 27 — 41 Unamortized sale and leaseback costs — — — 217 217 Derivatives 52 — — — 52 Other 34 277 7 (204 ) 114 463 367 34 (339 ) 525 $ 8,973 $ 6,333 $ 7,712 $ (9,708 ) $ 13,310 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ 18 $ 164 $ 348 $ (24 ) $ 506 Short-term borrowings- Affiliated companies 1,135 321 28 (1,449 ) 35 Other 90 9 — — 99 Accounts payable- Affiliated companies 1,068 197 219 (1,068 ) 416 Other 46 202 — — 248 Accrued taxes 2 62 161 (123 ) 102 Derivatives 166 — — — 166 Other 72 56 9 47 184 2,597 1,011 765 (2,617 ) 1,756 CAPITALIZATION: Total equity 5,585 2,561 4,014 (6,575 ) 5,585 Long-term debt and other long-term obligations 695 2,215 859 (1,161 ) 2,608 6,280 4,776 4,873 (7,736 ) 8,193 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 824 824 Accumulated deferred income taxes 13 — 678 (180 ) 511 Asset retirement obligations — 189 652 — 841 Retirement benefits 36 288 — — 324 Derivatives 14 — — — 14 Other 33 69 744 1 847 96 546 2,074 645 3,361 $ 8,973 $ 6,333 $ 7,712 $ (9,708 ) $ 13,310
Condensed Consolidating Statements of Cash Flows	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited) For the Six Months Ended June 30, 2015 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (600 ) $ 275 $ 680 $ (12 ) $ 343 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 674 62 — (612 ) 124 Redemptions and Repayments- Long-term debt (17 ) (12 ) (52 ) 12 (69 ) Short-term borrowings, net — — (28 ) 28 — Other — (2 ) — — (2 ) Net cash provided from (used for) financing activities 657 48 (80 ) (572 ) 53 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (2 ) (95 ) (167 ) — (264 ) Nuclear fuel — — (97 ) — (97 ) Proceeds from asset sales — 3 — — 3 Sales of investment securities held in trusts — — 376 — 376 Purchases of investment securities held in trusts — — (404 ) — (404 ) Loans to affiliated companies, net (55 ) (234 ) (308 ) 584 (13 ) Other — 3 — — 3 Net cash used for investing activities (57 ) (323 ) (600 ) 584 (396 ) 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, 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

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Segment Financial Information	Segment Financial Information Three Months Ended Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Reconciling Adjustments Consolidated (In millions) June 30, 2015 External revenues $ 2,239 $ 269 $ 1,034 $ (42 ) $ (35 ) $ 3,465 Internal revenues — — 162 — (162 ) — Total revenues 2,239 269 1,196 (42 ) (197 ) 3,465 Depreciation 170 38 99 15 — 322 Amortization of regulatory assets, net 57 2 — — — 59 Investment income (loss) 12 — (7 ) 2 (10 ) (3 ) Interest expense 146 40 48 49 (1 ) 282 Income taxes (benefits) 91 52 (7 ) (19 ) (2 ) 115 Net income (loss) 156 89 (12 ) (46 ) — 187 Total assets 28,353 7,055 16,711 886 — 53,005 Total goodwill 5,092 526 800 — — 6,418 Property additions 312 297 191 18 — 818 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 164 30 96 12 — 302 Amortization of regulatory assets, net 16 3 — — 1 20 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 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 Six Months Ended June 30, 2015 External revenues $ 4,801 $ 507 $ 2,209 $ (84 ) $ (71 ) $ 7,362 Internal revenues — — 422 — (422 ) — Total revenues 4,801 507 2,631 (84 ) (493 ) 7,362 Depreciation 342 75 195 29 — 641 Amortization of regulatory assets, net 86 5 — — — 91 Investment income 25 — 4 5 (20 ) 14 Interest expense 290 79 96 96 — 561 Income taxes (benefits) 213 94 (11 ) (37 ) — 259 Income (loss) from continuing operations 364 161 (21 ) (95 ) — 409 Discontinued operations, net of tax — — — — — — Net income (loss) 364 161 (21 ) (95 ) — 409 Property additions 592 551 317 26 — 1,486 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 326 60 187 23 — 596 Amortization of regulatory assets, net (15 ) 6 — — 1 (8 ) 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

Organization and Basis of Pre36

Organization and Basis of Presentation (Details Textuals) mi in Thousands, MW in Thousands, customer in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)transmission_center	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)customertransmission_centercompanymiMW	Jun. 30, 2014USD ($)
Property, Plant and Equipment [Line Items]
Aggregate amount of capacity | MW			17
Length of transmission lines | mi			24
Number of regional transmission centers | transmission_center	3		3
Impairment of long lived assets			$ 16	$ 0
Capitalized cost of equity	$ 19	$ 18	30	21
Capitalized interest	14	$ 14	37	40
FES
Property, Plant and Equipment [Line Items]
Impairment of long lived assets			$ 16	$ 0
FES | Other Operating Expense | Transportation Equipment
Property, Plant and Equipment [Line Items]
Impairment of long lived assets	$ 16
Regulated Distribution
Property, Plant and Equipment [Line Items]
Number of existing utility operating companies | company			10
Number of customers served by utility operating companies | customer			6

Earnings Per Share of Common 37

Earnings Per Share of Common Stock (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Earnings Per Share [Abstract]
Income (loss) from continuing operations	$ 187	$ 64	$ 409	$ 186
Discontinued operations	0	0	0	86
NET INCOME (LOSS)	$ 187	$ 64	$ 409	$ 272
Weighted average number of basic shares outstanding	422	420	422	419
Assumed exercise of dilutive stock options and awards	1	1	1	1
Weighted average number of diluted shares outstanding	423	421	423	420
Basic earnings per share:
Income (loss) from continuing operations, in dollars per share	$ 0.44	$ 0.16	$ 0.97	$ 0.45
Discontinued operations, in dollars per share	0	0	0	0.20
Basic - Net Earnings per Basic Share to FirstEnergy Corp., in dollars per share	0.44	0.16	0.97	0.65
Diluted earnings per share:
Income (loss) from continuing operations, in dollars per share	0.44	0.15	0.97	0.45
Discontinued operations, in dollars per share	0	0	0	0.20
Diluted - Net Earnings per Diluted Share Available to FirstEnergy Corp., in dollars per share	$ 0.44	$ 0.15	$ 0.97	$ 0.65
Shares excluded from the calculation of diluted shares outstanding, in shares	1	1	1	2

Pension and Other Postemploym38

Pension and Other Postemployment Benefits (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension contributions			$ 143	$ 0
Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	$ 48	$ 41	96	83
Interest costs	96	101	192	201
Expected return on plan assets	(111)	(115)	(222)	(230)
Amortization of prior service cost (credit)	2	2	4	4
Net periodic costs (credits)	35	29	70	58
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	1	2	2	4
Interest costs	7	10	14	20
Expected return on plan assets	(8)	(8)	(16)	(16)
Amortization of prior service cost (credit)	(34)	(44)	(67)	(88)
Net periodic costs (credits)	(34)	(40)	(67)	(80)
FirstEnergy | Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	24	21	49	42
FirstEnergy | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	(22)	(27)	(45)	(54)
FES | Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)	4	4	8	8
Net periodic benefit expense (credit)	4	4	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)	$ (4)	$ (5)	$ (8)	$ (9)

Accumulated Other Comprehensi39

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	$ 230	$ 271	$ 246	$ 284
Other comprehensive income (loss) before reclassifications	(7)	49	7	84
Amounts reclassified from AOCI	(38)	(62)	(78)	(118)
Other comprehensive income (loss)	(45)	(13)	(71)	(34)
Income taxes (benefits) on other comprehensive income (loss)	(17)	(6)	(27)	(14)
Other comprehensive income (loss), net of tax	(28)	(7)	(44)	(20)
AOCI Ending Balance	202	264	202	264
FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	56	62	57	54
Other comprehensive income (loss) before reclassifications	(7)	43	6	76
Amounts reclassified from AOCI	(10)	(26)	(25)	(47)
Other comprehensive income (loss)	(17)	17	(19)	29
Income taxes (benefits) on other comprehensive income (loss)	(6)	7	(7)	11
Other comprehensive income (loss), net of tax	(11)	10	(12)	18
AOCI Ending Balance	45	72	45	72
Gains & Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(36)	(36)	(37)	(36)
Other comprehensive income (loss) before reclassifications	0	0	0	0
Amounts reclassified from AOCI	1	(1)	2	(1)
Other comprehensive income (loss)	1	(1)	2	(1)
Income taxes (benefits) on other comprehensive income (loss)	1	(1)	1	(1)
Other comprehensive income (loss), net of tax	0	0	1	0
AOCI Ending Balance	(36)	(36)	(36)	(36)
Gains & Losses on Cash Flow Hedges | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(8)	(2)	(7)	(1)
Other comprehensive income (loss) before reclassifications	0	0	0	0
Amounts reclassified from AOCI	(1)	(3)	(2)	(5)
Other comprehensive income (loss)	(1)	(3)	(2)	(5)
Income taxes (benefits) on other comprehensive income (loss)	0	0	0	(1)
Other comprehensive income (loss), net of tax	(1)	(3)	(2)	(4)
AOCI Ending Balance	(9)	(5)	(9)	(5)
Unrealized Gains on AFS Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	28	22	25	9
Other comprehensive income (loss) before reclassifications	(7)	49	7	84
Amounts reclassified from AOCI	(7)	(19)	(17)	(33)
Other comprehensive income (loss)	(14)	30	(10)	51
Income taxes (benefits) on other comprehensive income (loss)	(5)	11	(4)	19
Other comprehensive income (loss), net of tax	(9)	19	(6)	32
AOCI Ending Balance	19	41	19	41
Unrealized Gains on AFS Securities | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	24	20	21	8
Other comprehensive income (loss) before reclassifications	(7)	43	6	76
Amounts reclassified from AOCI	(5)	(18)	(15)	(32)
Other comprehensive income (loss)	(12)	25	(9)	44
Income taxes (benefits) on other comprehensive income (loss)	(4)	9	(4)	16
Other comprehensive income (loss), net of tax	(8)	16	(5)	28
AOCI Ending Balance	16	36	16	36
Defined Benefit Pension & OPEB Plans
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	238	285	258	311
Other comprehensive income (loss) before reclassifications	0	0	0	0
Amounts reclassified from AOCI	(32)	(42)	(63)	(84)
Other comprehensive income (loss)	(32)	(42)	(63)	(84)
Income taxes (benefits) on other comprehensive income (loss)	(13)	(16)	(24)	(32)
Other comprehensive income (loss), net of tax	(19)	(26)	(39)	(52)
AOCI Ending Balance	219	259	219	259
Defined Benefit Pension & OPEB Plans | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	40	44	43	47
Other comprehensive income (loss) before reclassifications	0	0	0	0
Amounts reclassified from AOCI	(4)	(5)	(8)	(10)
Other comprehensive income (loss)	(4)	(5)	(8)	(10)
Income taxes (benefits) on other comprehensive income (loss)	(2)	(2)	(3)	(4)
Other comprehensive income (loss), net of tax	(2)	(3)	(5)	(6)
AOCI Ending Balance	$ 38	$ 41	$ 38	$ 41

Accumulated Other Comprehensi40

Accumulated Other Comprehensive Income (Details 1) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	$ 916	$ 1,021	$ 1,973	$ 2,203
Interest expense	282	262	561	527
Investment income (loss)	3	(29)	(14)	(51)
Total before taxes	(302)	(90)	(668)	(260)
Income taxes (benefits)	115	26	259	74
Net of tax	(187)	(64)	(409)	(272)
FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	353	468	766	920
Investment income (loss)	(1)	(24)	(14)	(44)
Total before taxes	25	154	30	313
Income taxes (benefits)	(4)	(67)	(6)	(123)
Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Total before taxes	1	(1)	2	(1)
Income taxes (benefits)	(1)	1	(1)	1
Net of tax	0	0	1	0
Reclassifications from AOCI | Gains & losses on cash flow hedges | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Income taxes (benefits)	0	1	0	2
Net of tax	(1)	(2)	(2)	(3)
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	(1)	(3)	(2)	(5)
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	(1)	(3)	(2)	(5)
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	2	2	4	4
Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(7)	(19)	(17)	(33)
Income taxes (benefits)	2	7	6	12
Net of tax	(5)	(12)	(11)	(21)
Reclassifications from AOCI | Unrealized gains on AFS securities | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(5)	(18)	(15)	(32)
Income taxes (benefits)	2	6	6	11
Net of tax	(3)	(12)	(9)	(21)
Reclassifications from AOCI | Defined benefit pension and OPEB plans
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(32)	(42)	(63)	(84)
Income taxes (benefits)	13	16	24	32
Net of tax	(19)	(26)	(39)	(52)
Reclassifications from AOCI | Defined benefit pension and OPEB plans | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(4)	(5)	(8)	(10)
Income taxes (benefits)	2	2	3	4
Net of tax	$ (2)	$ (3)	$ (5)	$ (6)

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	38.10%	28.90%	38.80%	28.50%
Unrecognized tax benefits from lapse of statute of limitations			$ 10
FES
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	16.00%	43.50%	20.00%	39.30%

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	Jun. 30, 2015USD ($)
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	$ 1,231
Discounted Lease Payments, net	958
Net Exposure	273
FES
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	1,151
Discounted Lease Payments, net	929
Net Exposure	$ 222

Variable Interest Entities (D43

Variable Interest Entities (Details Textuals)	3 Months Ended			6 Months Ended		12 Months Ended
	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)agreemententities	Jun. 30, 2014USD ($)	Dec. 31, 2011T	Dec. 31, 2014USD ($)	Oct. 31, 2012USD ($)
Variable Interest Entities (Textuals) [Abstract]
Long-term transition bond	$ 150,000,000			$ 150,000,000			$ 168,000,000
Long-term pollution control bond	440,000,000			440,000,000			450,000,000
Guarantor obligations	558,000,000			$ 558,000,000
Equity interest by unaffiliated third party in PNBV				3.00%
Number of contracts that may contain variable interest | entities				1
Purchased power	$ 989,000,000		$ 1,083,000,000	$ 2,102,000,000	$ 2,538,000,000
Perry Power Plant Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary	3.75%			3.75%
Bruce Mansfield Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary	93.83%			93.83%
Beaver Valley Unit 2
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary	2.60%			2.60%
Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities | agreement				15
Phase-In Recovery Bonds
Variable Interest Entities (Textuals) [Abstract]
Long-term debt and other long-term obligations	$ 374,000,000			$ 374,000,000			$ 386,000,000
Ohio Funding Companies
Variable Interest Entities (Textuals) [Abstract]
Annual servicing fees				445,000
Global Holding | Senior Loans | Senior Secured Term Loan
Variable Interest Entities (Textuals) [Abstract]
Guarantor obligations	$ 300,000,000			$ 300,000,000				$ 350,000,000
OE
Variable Interest Entities (Textuals) [Abstract]
Equity interest by OES Ventures in PNBV				3.00%
Other FE subsidiaries
Variable Interest Entities (Textuals) [Abstract]
Ownership interest	0.00%			0.00%
Other FE subsidiaries | Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Purchased power	$ 27,000,000		$ 40,000,000	$ 58,000,000	$ 102,000,000
Path-WV
Variable Interest Entities (Textuals) [Abstract]
Percentage of high-voltage transmission line project owned by subsidiary of FE on the Allegheny Series	100.00%			100.00%
Percentage of high-voltage transmission line project owned by subsidiary of FE on the West Virginia Series	50.00%			50.00%
Global Holding | FEV
Variable Interest Entities (Textuals) [Abstract]
Equity method investment	$ 372,000,000			$ 372,000,000
Pre-tax charge				$ 24,000,000
Global Holding | Guarantee of senior secured loan facility
Variable Interest Entities (Textuals) [Abstract]
Guarantor obligations		$ 300,000,000
Pre-tax charge		$ 24,000,000
Signal Peak
Variable Interest Entities (Textuals) [Abstract]
Equity ownership percentage sold						17.00%
Signal Peak | FEV
Variable Interest Entities (Textuals) [Abstract]
Equity ownership percentage						50.00%
Signal Peak | FEV | Put Option
Variable Interest Entities (Textuals) [Abstract]
Derivative notional amount mass (tons) | T						2,000,000
Signal Peak | Global Holding | FEV
Variable Interest Entities (Textuals) [Abstract]
Ownership interest	33.33%			33.33%

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Recurring - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Assets
Fair value, assets	$ 2,983	$ 2,832
Liabilities
Fair value, liabilities	(375)	(334)
Net assets (liabilities)	2,608	2,498
FES
Assets
Fair value, assets	1,626	1,520
Liabilities
Fair value, liabilities	(232)	(180)
Net assets (liabilities)	1,394	1,340
Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(221)	(167)
Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(221)	(167)
FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(13)	(14)
FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(11)	(13)
NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(141)	(153)
Corporate debt securities
Assets
Fair value, assets	1,292	1,221
Corporate debt securities | FES
Assets
Fair value, assets	701	655
Commodity contracts | Derivative Assets
Assets
Fair value, assets	252	172
Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	252	172
FTRs | Derivative Assets
Assets
Fair value, assets	23	39
FTRs | Derivative Assets | FES
Assets
Fair value, assets	10	27
NUG contracts | Derivative Assets
Assets
Fair value, assets	1	2
Equity securities
Assets
Fair value, assets	697	592
Equity securities | FES
Assets
Fair value, assets	481	360
Foreign government debt securities
Assets
Fair value, assets	81	76
Foreign government debt securities | FES
Assets
Fair value, assets	64	57
U.S. government debt securities
Assets
Fair value, assets	178	182
U.S. government debt securities | FES
Assets
Fair value, assets	27	46
U.S. state debt securities
Assets
Fair value, assets	241	237
U.S. state debt securities | FES
Assets
Fair value, assets	4	4
Other
Assets
Fair value, assets	218	311
Other | FES
Assets
Fair value, assets	87	199
Level 1
Assets
Fair value, assets	788	648
Liabilities
Fair value, liabilities	(7)	(26)
Net assets (liabilities)	781	622
Level 1 | FES
Assets
Fair value, assets	482	361
Liabilities
Fair value, liabilities	(7)	(26)
Net assets (liabilities)	475	335
Level 1 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(7)	(26)
Level 1 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(7)	(26)
Level 1 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 1 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 1 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 1 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 1 | Corporate debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	1	1
Level 1 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	1	1
Level 1 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 1 | NUG contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | Equity securities
Assets
Fair value, assets	697	592
Level 1 | Equity securities | FES
Assets
Fair value, assets	481	360
Level 1 | Foreign government debt securities
Assets
Fair value, assets	0	0
Level 1 | Foreign government debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | U.S. government debt securities
Assets
Fair value, assets	0	0
Level 1 | U.S. government debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | U.S. state debt securities
Assets
Fair value, assets	0	0
Level 1 | U.S. state debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | Other
Assets
Fair value, assets	90	55
Level 1 | Other | FES
Assets
Fair value, assets	0	0
Level 2
Assets
Fair value, assets	2,171	2,143
Liabilities
Fair value, liabilities	(214)	(141)
Net assets (liabilities)	1,957	2,002
Level 2 | FES
Assets
Fair value, assets	1,134	1,132
Liabilities
Fair value, liabilities	(214)	(141)
Net assets (liabilities)	920	991
Level 2 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(214)	(141)
Level 2 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(214)	(141)
Level 2 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 2 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2 | Corporate debt securities
Assets
Fair value, assets	1,292	1,221
Level 2 | Corporate debt securities | FES
Assets
Fair value, assets	701	655
Level 2 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	251	171
Level 2 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	251	171
Level 2 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 2 | NUG contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | Equity securities
Assets
Fair value, assets	0	0
Level 2 | Equity securities | FES
Assets
Fair value, assets	0	0
Level 2 | Foreign government debt securities
Assets
Fair value, assets	81	76
Level 2 | Foreign government debt securities | FES
Assets
Fair value, assets	64	57
Level 2 | U.S. government debt securities
Assets
Fair value, assets	178	182
Level 2 | U.S. government debt securities | FES
Assets
Fair value, assets	27	46
Level 2 | U.S. state debt securities
Assets
Fair value, assets	241	237
Level 2 | U.S. state debt securities | FES
Assets
Fair value, assets	4	4
Level 2 | Other
Assets
Fair value, assets	128	256
Level 2 | Other | FES
Assets
Fair value, assets	87	199
Level 3
Assets
Fair value, assets	24	41
Liabilities
Fair value, liabilities	(154)	(167)
Net assets (liabilities)	(130)	(126)
Level 3 | FES
Assets
Fair value, assets	10	27
Liabilities
Fair value, liabilities	(11)	(13)
Net assets (liabilities)	(1)	14
Level 3 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 3 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 3 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(13)	(14)
Level 3 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(11)	(13)
Level 3 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(141)	(153)
Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 3 | Corporate debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 3 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 3 | FTRs | Derivative Assets
Assets
Fair value, assets	23	39
Level 3 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	10	27
Level 3 | NUG contracts | Derivative Assets
Assets
Fair value, assets	1	2
Level 3 | Equity securities
Assets
Fair value, assets	0	0
Level 3 | Equity securities | FES
Assets
Fair value, assets	0	0
Level 3 | Foreign government debt securities
Assets
Fair value, assets	0	0
Level 3 | Foreign government debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | U.S. government debt securities
Assets
Fair value, assets	0	0
Level 3 | U.S. government debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | U.S. state debt securities
Assets
Fair value, assets	0	0
Level 3 | U.S. state debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | Other
Assets
Fair value, assets	0	0
Level 3 | Other | FES
Assets
Fair value, assets	$ 0	$ 0

Fair Value Measurements (Deta45

Fair Value Measurements (Details 1) - Level 3 - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
NUG contracts
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	$ 2	$ 20
Beginning Balance, Derivative Liabilities	(153)	(222)
Beginning Balance, Net	(151)	(202)
Unrealized gain (loss), Derivative Assets	1	2
Unrealized gain (loss), Derivative Liabilities	(17)	(2)
Unrealized gain (loss), Net	(16)	0
Purchases, Derivative Assets	0	0
Purchases, Derivative Liabilities	0	0
Purchases, Net	0	0
Settlements, Derivative Assets	(2)	(20)
Settlements, Derivative Liabilities	29	71
Settlements, Net	27	51
Ending Balance, Derivative Assets	1	2
Ending Balance, Derivative Liabilities	(141)	(153)
Ending Balance, Net	(140)	(151)
FTRs
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	39	4
Beginning Balance, Derivative Liabilities	(14)	(12)
Beginning Balance, Net	25	(8)
Unrealized gain (loss), Derivative Assets	5	47
Unrealized gain (loss), Derivative Liabilities	3	(1)
Unrealized gain (loss), Net	8	46
Purchases, Derivative Assets	22	26
Purchases, Derivative Liabilities	(11)	(16)
Purchases, Net	11	10
Settlements, Derivative Assets	(43)	(38)
Settlements, Derivative Liabilities	9	15
Settlements, Net	(34)	(23)
Ending Balance, Derivative Assets	23	39
Ending Balance, Derivative Liabilities	(13)	(14)
Ending Balance, Net	10	25
FTRs | FES
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	27	3
Beginning Balance, Derivative Liabilities	(13)	(11)
Beginning Balance, Net	14	(8)
Unrealized gain (loss), Derivative Assets	4	34
Unrealized gain (loss), Derivative Liabilities	3	(1)
Unrealized gain (loss), Net	7	33
Purchases, Derivative Assets	9	15
Purchases, Derivative Liabilities	(10)	(16)
Purchases, Net	(1)	(1)
Settlements, Derivative Assets	(30)	(25)
Settlements, Derivative Liabilities	9	15
Settlements, Net	(21)	(10)
Ending Balance, Derivative Assets	10	27
Ending Balance, Derivative Liabilities	(11)	(13)
Ending Balance, Net	$ (1)	$ 14

Fair Value Measurements (Deta46

Fair Value Measurements (Details 2) - Level 3 $ in Millions	6 Months Ended
	Jun. 30, 2015USD ($)MWh$ / MWh	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ 10	$ 25	$ (8)
FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(1)	14	(8)
NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(140)	$ (151)	$ (202)
Model | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	10
Model | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(1)
Model | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ (140)
Model | Minimum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	(5.10)
Model | Minimum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	(5.10)
Model | Minimum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	500
Fair Value Inputs, Power, Regional Prices (in $/MWH)	44
Model | Maximum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	9.20
Model | Maximum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	9.20
Model | Maximum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	4,317,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	68.90
Model | Weighted Average | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	1.40
Model | Weighted Average | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	1
Model | Weighted Average | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	833,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	51

Fair Value Measurements (Deta47

Fair Value Measurements (Details 3) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	$ 1,808	$ 1,724
Unrealized Gain	25	27
Fair Value	1,833	1,751
Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	664	533
Unrealized Gains	(33)	(58)
Fair Value	697	591
FES | Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	824	788
Unrealized Gain	13	13
Fair Value	837	801
FES | Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	462	329
Unrealized Gains	(19)	(31)
Fair Value	$ 481	$ 360

Fair Value Measurements (Deta48

Fair Value Measurements (Details 4) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
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	$ 448	$ 543	$ 819	$ 1,164
Realized Gains	42	35	102	63
Realized Losses	(39)	(15)	(89)	(31)
OTTI	(17)	(1)	(24)	(3)
Interest and Dividend Income	25	24	50	49
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	187	284	376	707
Realized Gains	32	30	70	49
Realized Losses	(27)	(12)	(55)	(17)
OTTI	(16)	(1)	(22)	(3)
Interest and Dividend Income	$ 15	$ 14	$ 29	$ 29

Fair Value Measurements (Deta49

Fair Value Measurements (Details 5) - Debt Securities - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities
Cost Basis	$ 10	$ 13
Unrecognized Gains	2	4
Fair Value	$ 12	$ 17

Fair Value Measurements (Deta50

Fair Value Measurements (Details 6) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$ 19,728	$ 19,828
Carrying Value | FES
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	3,028	3,097
Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	21,195	21,733
Fair Value | FES
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$ 3,146	$ 3,241

Fair Value Measurements (Deta51

Fair Value Measurements (Details Textuals) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	$ (6)	$ 40
Cash balance excluded from available for sale securities	58	241
Investments not required to be disclosed	$ 636	626
NUG contracts
Fair Value of Financial Instruments [Line Items]
Period of future observable data to determine contract price	3 years
FES
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	$ 1	44
Cash balance excluded from available for sale securities	$ 47	$ 204

Derivative Instruments (Details

Derivative Instruments (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Fair value of commodity derivatives
Derivative Assets	$ 276	$ 213
Derivative Liabilities	(375)	(334)
Current Assets
Fair value of commodity derivatives
Derivative Assets	171	159
Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	105	54
Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(160)	(167)
Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(215)	(167)
Commodity contracts | Current Assets
Fair value of commodity derivatives
Derivative Assets	149	121
Commodity contracts | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	103	51
Commodity contracts | Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(148)	(154)
Commodity contracts | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(73)	(13)
FTRs | Current Assets
Fair value of commodity derivatives
Derivative Assets	22	38
FTRs | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	1	1
FTRs | Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(12)	(13)
FTRs | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(1)	(1)
NUGs | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	1	2
NUGs | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	$ (141)	$ (153)

Derivative Instruments (Detai53

Derivative Instruments (Details 1) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Derivative Assets
Fair Value	$ 276	$ 213
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(215)	(140)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	61	73
Derivative Liabilities
Fair Value	(375)	(334)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	215	140
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	11	35
Net Fair Value	(149)	(159)
Commodity contracts
Derivative Assets
Fair Value	252	172
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(202)	(126)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	50	46
Derivative Liabilities
Fair Value	(221)	(167)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	202	126
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	11	35
Net Fair Value	(8)	(6)
FTRs
Derivative Assets
Fair Value	23	39
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(13)	(14)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	10	25
Derivative Liabilities
Fair Value	(13)	(14)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	13	14
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	0	0
NUGs
Derivative Assets
Fair Value	1	2
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	0	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	1	2
Derivative Liabilities
Fair Value	(141)	(153)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	0	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	$ (141)	$ (153)

Derivative Instruments (Detai54

Derivative Instruments (Details 2) - Jun. 30, 2015 MWh in Millions, MMBTU in Millions	MMBTUMWh
Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	23
Sales (in MWH or mmBTUs)	54
Net (in MWH or mmBTUs)	(31)
FTRs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	54
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	54
NUGs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	5
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	5
Natural Gas
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs) | MMBTU	39
Sales (in MWH or mmBTUs) | MMBTU	1
Net (in MWH or mmBTUs) | MMBTU	38

Derivative Instruments (Detai55

Derivative Instruments (Details 3) - Not Designated as Hedging Instrument - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
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	$ (16)	$ (1)	$ (52)	$ (40)
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	25	(22)	28	(458)
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	9	(57)	7	(40)
Realized Gain (Loss) Reclassified	13	10	26	17
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	5	(2)	21	(11)
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	(8)	(2)	(7)	11
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	25	(22)	28	(458)
Commodity contracts | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	11	(70)	22	(58)
Realized Gain (Loss) Reclassified	0	0	0	0
Commodity contracts | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	5	(2)	21	(11)
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		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	(8)	1	(45)	(51)
FTRs | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	0	0	0	0
FTRs | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	(2)	13	(15)	18
Realized Gain (Loss) Reclassified	13	10	26	17
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		0
Interest Rate Swaps | 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	0	0	0
Interest Rate Swaps | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	0	0	0	0
Interest Rate Swaps | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	0	0	0	0
Realized Gain (Loss) Reclassified	0	0	0	0
Interest Rate Swaps | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	0	0	0	0
Interest Rate Swaps | Interest Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified		(6)		(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	(8)	(2)	(7)	11
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	25	(22)	28	(458)
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	11	(70)	22	(58)
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	(8)	1	(44)	(50)
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	(2)	13	(14)	18
Realized Gain (Loss) Reclassified	$ 13	9	$ 26	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

Derivative Instruments (Detai56

Derivative Instruments (Details 5) - Not Designated as Hedging Instrument - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	$ (147)	$ (182)	$ (140)	$ (202)
Unrealized gain (loss)	(8)	(2)	(15)	29
Purchases	12	11	12	11
Settlements	15	14	15	3
Outstanding net asset (liability), Ending Balance	(128)	(159)	(128)	(159)
NUGs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(148)	(185)	(151)	(202)
Unrealized gain (loss)	(8)	(2)	(16)	25
Purchases	0	0	0	0
Settlements	16	18	27	8
Outstanding net asset (liability), Ending Balance	(140)	(169)	(140)	(169)
Regulated FTRs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	1	3	11	0
Unrealized gain (loss)	0	0	1	4
Purchases	12	11	12	11
Settlements	(1)	(4)	(12)	(5)
Outstanding net asset (liability), Ending Balance	$ 12	$ 10	$ 12	$ 10

Derivative Instruments (Detai57

Derivative Instruments (Details Textuals)	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)agreement	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)agreement	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)agreement
Derivative [Line Items]
Unamortized gains or losses associated with designated cash flow hedges	$ 10,000,000		$ 10,000,000		$ 8,000,000
Gain (loss) on cash flow hedge expected to be reclassified to earnings in next twelve months			2,000,000
Unamortized gains or losses associated with prior interest rate hedges	46,000,000		46,000,000		50,000,000
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	$ 26,000,000		$ 26,000,000		32,000,000
Possible adverse change in quoted market prices of derivative instruments	10.00%		10.00%
Possible increase net income due to ten percent adverse change in commodity prices			$ (25,000,000)
Net asset position	$ 61,000,000		61,000,000		73,000,000
Net liability	(149,000,000)		$ (149,000,000)		(159,000,000)
Period in which LSEs may request direct allocation of FTRs			2 years
Direct allocation of FTRs, cost			$ 0
Commodity contracts
Derivative [Line Items]
Net asset position under commodity derivative contracts	31,000,000		31,000,000
Net asset position	50,000,000		50,000,000		46,000,000
Net liability	(8,000,000)		(8,000,000)		(6,000,000)
NUGs
Derivative [Line Items]
Liability position	140,000,000		140,000,000
Net asset position	1,000,000		1,000,000		2,000,000
Net liability	(141,000,000)		(141,000,000)		(153,000,000)
FTRs
Derivative [Line Items]
Net asset position	10,000,000		10,000,000		25,000,000
Net liability	0		0		$ 0
FES | Commodity contracts
Derivative [Line Items]
Collateral posted	60,000,000		60,000,000
Additional collateral related to commodity derivatives	6,000,000		6,000,000
FES | FTRs
Derivative [Line Items]
Collateral posted	6,000,000		6,000,000
Net liability	$ (1,000,000)		$ (1,000,000)
Cash Flow Hedges
Derivative [Line Items]
Number of forward starting swap agreements accounted for as a cash flow hedge outstanding | agreement	0		0		0
Losses to be amortized to interest expenses during next twelve months			$ (9,000,000)
Number of outstanding commodity or interest rate derivatives | agreement					0
Fair Value Hedging
Derivative [Line Items]
Losses to be amortized to interest expenses during next twelve months			$ 12,000,000
Number of outstanding commodity or interest rate derivatives | agreement	0		0		0
Number of fixed-for-floating interest rate swap agreements outstanding | agreement	0		0		0
Reclassifications from long-term debt	$ 3,000,000	$ 3,000,000	$ 6,000,000	$ 6,000,000

Regulatory Matters - Maryland a

Regulatory Matters - Maryland and New Jersey (Details) $ in Millions	Jul. 16, 2015	Jul. 10, 2015	Apr. 01, 2015USD ($)	Mar. 26, 2015USD ($)	Feb. 27, 2013USD ($)	Jun. 30, 2015USD ($)componentbgs	Dec. 31, 2009
Maryland
Regulatory Matters [Line Items]
Proposed electric consumption reduction percentage						10.00%
Proposed electric demand reduction percentage						15.00%
Expenditures for cost recovery program						$ 64
Expenditures for cost recovery program incurred						$ 9
Recovery period for expenditures for cost recovery program						5 years	3 years
Expected infrastructure investments					$ 2,700
Period of expected infrastructure investments					15 years
New Jersey
Regulatory Matters [Line Items]
Number of supply components | component						2
Number of basic generation services | bgs						1
JCP&L | Board Of Public Utilities | Major Storm Events | New Jersey
Regulatory Matters [Line Items]
Approved increase (decrease)			$ (34)	$ 81
JCP&L | Board Of Public Utilities | Final order base rate case | New Jersey
Regulatory Matters [Line Items]
Approved increase (decrease)				(115)
Subsequent Event | Maryland
Regulatory Matters [Line Items]
Incremental energy savings goal next 12 months (percent)	0.20%
Incremental energy savings goal thereafter (percent)	2.00%
Recommended reduction in average outage duration (percent)		20.00%
2012 Storm Costs | JCP&L | Board Of Public Utilities | Major Storm Events | New Jersey
Regulatory Matters [Line Items]
Approved increase (decrease)				$ 580

Regulatory Matters - Ohio (Deta

Regulatory Matters - Ohio (Details) MWh in Thousands, $ in Millions	Aug. 07, 2013USD ($)auctions	Mar. 20, 2013	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Dec. 31, 2013USD ($)	Jun. 30, 2015USD ($)MWh	Jun. 30, 2014USD ($)
Regulatory Matters [Line Items]
Amortization (deferral) of regulatory assets, net			$ 59	$ 20		$ 91	$ (8)
Ohio
Regulatory Matters [Line Items]
ESP extension term						2 years
Generation discount for low income customers (percent)						6.00%
Recovery period						5 years
Costs avoided by customers						$ 360
Generation supply auction period, after approval						3 years
Generation supply auction period, before approval						1 year
Term of proposed purchase power agreement						15 years
Annual revenue cap for rider			30			$ 30
Estimated cost of portfolio plan			$ 250			$ 250
Portion of revenue obtained to be received						20.00%
Credit to non-shopping customers	$ 43.4
Term of economic development and assistance plan						3 years
Energy efficient portfolio plan term		3 years
Annually Through 2014 | Ohio
Regulatory Matters [Line Items]
Utilities required to additionally reduce peak demand						0.75%
Year 2015 | Ohio
Regulatory Matters [Line Items]
Annual energy savings (in GWH) | MWh						2,266
Year 2016 | Ohio
Regulatory Matters [Line Items]
Annual energy savings (in GWH) | MWh						2,288
Year 2017 | Ohio
Regulatory Matters [Line Items]
Annual increase in energy savings (percent)						1.00%
PUCO | Ohio
Regulatory Matters [Line Items]
Number of renewable energy auctions | auctions	1
Amortization (deferral) of regulatory assets, net					$ 51

Regulatory Matters - Pennsylvan

Regulatory Matters - Pennsylvania and West Virginia (Details)	Jun. 19, 2015	May. 19, 2015	Apr. 09, 2015USD ($)	Aug. 04, 2014USD ($)	Oct. 10, 2013proposal	Feb. 03, 2013USD ($)	Sep. 30, 2013USD ($)judge	Jun. 30, 2015USD ($)	Dec. 31, 2010USD ($)	Jul. 13, 2015USD ($)	Mar. 14, 2013USD ($)
Pennsylvania
Regulatory Matters [Line Items]
Marginal transmission refund period								29 months
Marginal transmission losses									$ 254,000,000
Impairment of long lived assets							$ 254,000,000
Number of judges that ruled in favor of hearing | judge							2
Approved settlement additional operating expenses			$ 87,700,000
Number of requests for proposal | proposal					1
Request for proposal project term					2 years
Pennsylvania | Unfavorable Regulatory Action
Regulatory Matters [Line Items]
Maximum range of possible loss											$ 234,000,000
Revised implementation plan granted extension period		45 days
Pennsylvania | Unfavorable Regulatory Action | Subsequent Event
Regulatory Matters [Line Items]
Maximum range of possible loss										$ 230,000,000
Loss contingency range of possible loss										$ 200,000,000
Pennsylvania | ME
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)				$ 151,900,000
Pennsylvania | PN
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)				119,800,000
Pennsylvania | Penn
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)				28,500,000
Pennsylvania | WP
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)				$ 115,500,000
Pennsylvania | PPUC | ME
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)	1.80%
Energy consumption reduction targets proposed return on equity (percent)	4.00%
Pennsylvania | PPUC | PN
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)	0.00%
Energy consumption reduction targets proposed return on equity (percent)	3.90%
Pennsylvania | PPUC | Penn
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)	1.70%
Energy consumption reduction targets proposed return on equity (percent)	3.30%
Pennsylvania | PPUC | WP
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)	1.80%
Energy consumption reduction targets proposed return on equity (percent)	2.60%
Pennsylvania | Three month period
Regulatory Matters [Line Items]
Term of energy contract					3 months
Pennsylvania | Twelve month period
Regulatory Matters [Line Items]
Term of energy contract					12 months
Pennsylvania | Twenty-Four Month Period
Regulatory Matters [Line Items]
Term of energy contract					24 months
West Virginia
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)						$ 292,800,000
West Virginia | Penn
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)						15,900,000
West Virginia | WP
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)						96,800,000
West Virginia | Met-Ed
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)						89,300,000
West Virginia | Penelec
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)						$ 90,800,000
West Virginia | Public Utility Commission of West Virginia | MP and PE
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)								$ 15,000,000
Recovery period								5 years
Deferred storm and property reserve deficiency								$ 46,000,000

Regulatory Matters - Reliabilit

Regulatory Matters - Reliability Matters and FERC (Details) $ in Millions	Jan. 01, 2016	Sep. 24, 2014	Aug. 24, 2012USD ($)	Oct. 31, 2006proceeding	Dec. 31, 2015	Jun. 30, 2015USD ($)entitiessubsidiary
Regulatory Matters [Line Items]
Regional enforcement entities | entities						8
Requested increase to VRR curve (percent)		1.00%
FERC
Regulatory Matters [Line Items]
Denied recovery charges of exit fees						$ 78.8
FERC | California Claims Matters
Regulatory Matters [Line Items]
Settlement proposal claims						$ 190
Court proceedings from filed claims | proceeding				1
FERC | ATSI
Regulatory Matters [Line Items]
Public Utilities, Requested Return on Equity, Percentage						12.38%
FERC | PATH-Allegheny
Regulatory Matters [Line Items]
Cost recovery, PP&E reclassified to Regulatory Assets			$ 62
FERC | Path-WV
Regulatory Matters [Line Items]
Cost recovery, PP&E reclassified to Regulatory Assets			$ 59
FERC | PATH
Regulatory Matters [Line Items]
Public Utilities, Requested Return on Equity, Percentage			10.40%
Proposed return on equity			10.90%
Return on equity granted for regional transmission organization participation			0.50%
Remaining recovery period of regulatory assets			5 years
FERC | FET
Regulatory Matters [Line Items]
Number of stand-alone transmission subsidiaries | subsidiary						2
FERC | Scenario, Forecast | ATSI
Regulatory Matters [Line Items]
Public Utilities, Requested Return on Equity, Percentage	10.38%				11.06%

Commitments, Guarantees and C62

Commitments, Guarantees and Contingencies (Details) - USD ($) $ in Millions	3 Months Ended
	Jun. 30, 2014	Jun. 30, 2015
Guarantor Obligations [Line Items]
Guarantor obligations		$ 558
FES
Guarantor Obligations [Line Items]
Guarantor obligations		492
AE Supply
Guarantor Obligations [Line Items]
Guarantor obligations		16
Utilities
Guarantor Obligations [Line Items]
Guarantor obligations		50
Split Rating
Guarantor Obligations [Line Items]
Guarantor obligations		466
Split Rating | FES
Guarantor Obligations [Line Items]
Guarantor obligations		410
Split Rating | AE Supply
Guarantor Obligations [Line Items]
Guarantor obligations		6
Split Rating | Utilities
Guarantor Obligations [Line Items]
Guarantor obligations		50
Fitch, BB Plus Moody's, Ba1 Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations		503
Fitch, BB Plus Moody's, Ba1 Credit Rating | FES
Guarantor Obligations [Line Items]
Guarantor obligations		447
Fitch, BB Plus Moody's, Ba1 Credit Rating | AE Supply
Guarantor Obligations [Line Items]
Guarantor obligations		6
Fitch, BB Plus Moody's, Ba1 Credit Rating | Utilities
Guarantor Obligations [Line Items]
Guarantor obligations		$ 50
ICG Litigation
Guarantor Obligations [Line Items]
Gain (loss) related to litigation settlement	$ 15
ICG Litigation | AE Supply
Guarantor Obligations [Line Items]
Gain (loss) related to litigation settlement	12
ICG Litigation | MP
Guarantor Obligations [Line Items]
Gain (loss) related to litigation settlement	$ 3

Commitments, Guarantees and C63

Commitments, Guarantees and Contingencies (Details Textuals) - Geographical [Domain]

Apr. 19, 2013options

Jun. 30, 2014

May. 31, 2014

Jul. 31, 2008ComplaintsIndividualsInAComplaintplaintiff

Jun. 30, 2015USD ($)T

Jun. 30, 2014USD ($)

Jun. 30, 2015USD ($)phasesT

Jun. 30, 2014USD ($)

Dec. 31, 2011T

Mar. 31, 2015USD ($)

Apr. 30, 2015MW

Dec. 31, 2014USD ($)

Sep. 30, 2013lb

Jun. 30, 2013

Oct. 31, 2012USD ($)

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

$ 3,900,000,000

$ 3,900,000,000

New syndicated senior secured term loan facility

558,000,000

558,000,000

Long-term debt

292,000,000

$ 925,000,000

Nuclear plant decommissioning trusts

2,348,000,000

2,348,000,000

$ 2,341,000,000

ICG Litigation

Guarantor Obligations [Line Items]

Gain contingency, damages denied

$ 15,000,000

Clean Water Act

Guarantor Obligations [Line Items]

Number of treatment options | options

8

Number of preferred treatment options | options

4

Waste water discharge permit renewal cycle

5 years

Regulation of Waste Disposal

Guarantor Obligations [Line Items]

Civil penalties

$ 800,000

Bond closure and post closure period

45 years

Period to complete closure

12 years

Accrual for environmental loss contingencies

134,000,000

$ 134,000,000

Environmental liabilities former gas facilities

93,000,000

93,000,000

Nuclear Plant Matters

Guarantor Obligations [Line Items]

Nuclear plant decommissioning trusts

2,300,000,000

2,300,000,000

Parental guarantee

24,500,000

$ 24,500,000

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

20 years

Caa Compliance

Guarantor Obligations [Line Items]

Loss in period

$ 167,000,000

Amount of coal-fired plants deactivated | MW

5,429

National Ambient Air Quality Standards

Guarantor Obligations [Line Items]

Capping of SO2 emissions under CSAPR | T

2,400,000

Capping of NOx emissions under CSAPR | T

1,200,000

National Ambient Air Quality Standards | CSAPR

Guarantor Obligations [Line Items]

Number of phases under the EPA’s CAIR for reductions of Sulfur Dioxide and Mono-Nitrogen Oxides | phases

2

Hazardous Air Pollutant Emissions

Guarantor Obligations [Line Items]

Potential cost of compliance, MATS

370,000,000

$ 370,000,000

Climate Change

Guarantor Obligations [Line Items]

Percent reduction in GHG emissions between 2005 and 2012

10.00%

Proposed emissions standard of large natural gas fired units | lb

1,000

Proposed emissions standard other natural gas fired units | lb

1,100

Proposed emissions standard fossil fuel fired units | lb

1,100

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

12.00%

Climate Change | Year 2016

Guarantor Obligations [Line Items]

Anticipated reduction in CO2 emissions (percent)

25.00%

Climate Change | Year 2020

Guarantor Obligations [Line Items]

Proposed reduction in power plants carbon pollution (percent)

17.00%

Regulated Distribution

Guarantor Obligations [Line Items]

Company posted collateral related to net liability positions

1,000,000

1,000,000

Regulated Distribution | Caa Compliance

Guarantor Obligations [Line Items]

Loss in period

105,000,000

Regulated Distribution | Hazardous Air Pollutant Emissions

Guarantor Obligations [Line Items]

Potential cost of compliance, MATS

192,000,000

192,000,000

Competitive Energy Services | Caa Compliance

Guarantor Obligations [Line Items]

Loss in period

$ 62,000,000

Competitive Energy Services | Hazardous Air Pollutant Emissions

Guarantor Obligations [Line Items]

Potential cost of compliance, MATS

178,000,000

178,000,000

FES

Guarantor Obligations [Line Items]

Company posted collateral related to net liability positions

214,000,000

214,000,000

Potential collateral posted related to net liability positions

13,000,000

13,000,000

New syndicated senior secured term loan facility

492,000,000

492,000,000

Long-term debt

69,000,000

664,000,000

Nuclear plant decommissioning trusts

1,365,000,000

1,365,000,000

1,365,000,000

AE Supply

Guarantor Obligations [Line Items]

New syndicated senior secured term loan facility

16,000,000

16,000,000

AE Supply | ICG Litigation

Guarantor Obligations [Line Items]

Gain contingency, damages denied

12,000,000

Global Holding | Senior Secured Term Loan | Senior Loans

Guarantor Obligations [Line Items]

New syndicated senior secured term loan facility

$ 300,000,000

$ 300,000,000

$ 350,000,000

Global Holding | Senior Secured Term Loan | Senior Loans | Signal Peak, Global Rail and Affiliates

Guarantor Obligations [Line Items]

Investment ownership percentage

69.99%

69.99%

FEV | Global Holding

Guarantor Obligations [Line Items]

Loss in period

$ 24,000,000

FEV | Senior Secured Term Loan | Senior Loans | Signal Peak | Global Holding

Guarantor Obligations [Line Items]

Investment ownership percentage

33.33%

33.33%

WMB Marketing Ventures, LLC | Senior Secured Term Loan | Senior Loans | Signal Peak | Global Holding

Guarantor Obligations [Line Items]

Investment ownership percentage

33.33%

33.33%

FGCO

Guarantor Obligations [Line Items]

Long-term debt

$ 12,000,000

$ 258,000,000

Nuclear plant decommissioning trusts

$ 0

0

$ 0

FGCO | Caa Compliance

Guarantor Obligations [Line Items]

Number of complaints seek enjoin plant | Complaints

2

Power plants complaints | Complaints

3

FGCO | Caa Compliance | Claim One

Guarantor Obligations [Line Items]

Number of complaints seek enjoin plant | Complaints

1

Number of individuals behalf of which complaint filed | IndividualsInAComplaint

21

FGCO | Caa Compliance | Claim Two

Guarantor Obligations [Line Items]

Number of named plaintiffs as class representatives | plaintiff

8

MP | ICG Litigation

Guarantor Obligations [Line Items]

Gain contingency, damages denied

$ 3,000,000

State and Local Agencies | Hazardous Air Pollutant Emissions

Guarantor Obligations [Line Items]

Potential MATS extension period

1 year

Environmental Protection Agency | Hazardous Air Pollutant Emissions

Guarantor Obligations [Line Items]

Potential MATS extension period

1 year

Minimum | Clean Water Act

Guarantor Obligations [Line Items]

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

150,000,000

Minimum | State and Local Agencies | Climate Change

Guarantor Obligations [Line Items]

Potential MATS extension period

1 year

Maximum | Clean Water Act

Guarantor Obligations [Line Items]

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

$ 300,000,000

Maximum | State and Local Agencies | Climate Change

Guarantor Obligations [Line Items]

Potential MATS extension period

2 years

Transportation Commitment | Caa Compliance

Guarantor Obligations [Line Items]

Amount remaining under contract | T

6,000,000

6,000,000

FirstEnergy

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

$ 599,000,000

$ 599,000,000

Subsidiaries

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

2,245,000,000

2,245,000,000

Guarantee Type, Other

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

300,000,000

300,000,000

Other Assurances

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

$ 717,000,000

$ 717,000,000

Put Option | FEV | Signal Peak

Guarantor Obligations [Line Items]

Derivative notional amount mass (tons) | T

2,000,000

Supplemental Guarantor Inform64

Supplemental Guarantor Information (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Condensed Financial Statements, Captions [Line Items]
Tax effect of discontinued operations					$ 69
Consolidating Statements of Income
Revenues	[1]	$ 3,465	$ 3,496	$ 7,362	7,678
OPERATING EXPENSES:
Fuel		383	550	896	1,167
Purchased power		989	1,083	2,102	2,538
Other operating expenses		916	1,021	1,973	2,203
Provision for depreciation		322	302	641	596
General taxes		242	228	511	499
Total operating expenses		2,911	3,204	6,214	6,995
OPERATING INCOME (LOSS)		554	292	1,148	683
OTHER INCOME (EXPENSE):
Loss on debt redemptions		0	(1)	0	(8)
Investment income		(3)	29	14	51
Interest expense		(282)	(262)	(561)	(527)
Capitalized interest		33	32	67	61
Total other income (expense)		(252)	(202)	(480)	(423)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)		302	90	668	260
INCOME TAXES (BENEFITS)		115	26	259	74
INCOME (LOSS) FROM CONTINUING OPERATIONS		187	64	409	186
Discontinued operations		0	0	0	86
NET INCOME (LOSS)		187	64	409	272
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		187	64	409	272
Pension and OPEB prior service costs		(32)	(42)	(63)	(84)
Amortized gains on derivative hedges		1	(1)	2	(1)
Change in unrealized gain on available-for-sale securities		(14)	30	(10)	51
Other comprehensive income (loss)		(45)	(13)	(71)	(34)
Income taxes (benefits) on other comprehensive income (loss)		(17)	(6)	(27)	(14)
Other comprehensive income (loss), net of tax		(28)	(7)	(44)	(20)
COMPREHENSIVE INCOME (LOSS)		159	57	365	252
FES
Consolidating Statements of Income
Revenues		1,074	1,412	2,406	3,209
OPERATING EXPENSES:
Fuel		0	0	0	0
Other operating expenses		102	242	282	470
Provision for depreciation		2	2	5	4
General taxes		11	18	26	39
Total operating expenses		1,275	1,782	2,973	3,703
OPERATING INCOME (LOSS)		(201)	(370)	(567)	(494)
OTHER INCOME (EXPENSE):
Loss on debt redemptions				0	(3)
Investment income		119	2	360	3
Miscellaneous income		1	159	1	262
Capitalized interest		0	0	0	0
Total other income (expense)		100	145	322	229
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)		(101)	(225)	(245)	(265)
INCOME TAXES (BENEFITS)		(80)	(137)	(221)	(189)
INCOME (LOSS) FROM CONTINUING OPERATIONS				(24)	(76)
Discontinued operations				0	0
NET INCOME (LOSS)		(21)	(88)	(24)	(76)
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		(21)	(88)	(24)	(76)
Pension and OPEB prior service costs		(4)	(5)	(8)	(10)
Amortized gains on derivative hedges		(1)	(3)	(2)	(5)
Change in unrealized gain on available-for-sale securities		(12)	25	(9)	44
Other comprehensive income (loss)		(17)	17	(19)	29
Income taxes (benefits) on other comprehensive income (loss)		(6)	7	(7)	11
Other comprehensive income (loss), net of tax		(11)	10	(12)	18
COMPREHENSIVE INCOME (LOSS)		(32)	(78)	(36)	(58)
FES | Affiliates
OPERATING EXPENSES:
Purchased power		768	902	1,725	1,547
OTHER INCOME (EXPENSE):
Interest expense		(7)	(2)	(13)	(5)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power		392	618	935	1,643
OTHER INCOME (EXPENSE):
Interest expense		(13)	(14)	(26)	(28)
FGCO
Condensed Financial Statements, Captions [Line Items]
Tax effect of discontinued operations				0	70
Consolidating Statements of Income
Revenues		346	505	839	820
OPERATING EXPENSES:
Fuel		150	288	330	560
Other operating expenses		75	79	142	141
Provision for depreciation		32	30	62	59
General taxes		7	6	15	17
Total operating expenses		264	403	549	781
OPERATING INCOME (LOSS)		82	102	290	39
OTHER INCOME (EXPENSE):
Loss on debt redemptions				0	(1)
Investment income		5	2	8	3
Miscellaneous income		3	3	3	3
Capitalized interest		2	0	3	1
Total other income (expense)		(18)	(22)	(42)	(46)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)		64	80	248	(7)
INCOME TAXES (BENEFITS)		28	23	95	(8)
INCOME (LOSS) FROM CONTINUING OPERATIONS				153	1
Discontinued operations				0	116
NET INCOME (LOSS)		36	57	153	117
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		36	57	153	117
Pension and OPEB prior service costs		(4)	(5)	(8)	(9)
Amortized gains on derivative hedges		0	0	0	0
Change in unrealized gain on available-for-sale securities		0	0	0	0
Other comprehensive income (loss)		(4)	(5)	(8)	(9)
Income taxes (benefits) on other comprehensive income (loss)		(2)	(1)	(3)	(3)
Other comprehensive income (loss), net of tax		(2)	(4)	(5)	(6)
COMPREHENSIVE INCOME (LOSS)		34	53	148	111
FGCO | Affiliates
OPERATING EXPENSES:
Purchased power		0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense		(2)	(2)	(4)	(3)
FGCO | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0	0	4
OTHER INCOME (EXPENSE):
Interest expense		(26)	(25)	(52)	(49)
Nuclear Generation Corp
Consolidating Statements of Income
Revenues		456	437	963	799
OPERATING EXPENSES:
Fuel		41	46	91	93
Other operating expenses		164	135	318	285
Provision for depreciation		47	48	95	91
General taxes		7	5	13	12
Total operating expenses		325	309	651	620
OPERATING INCOME (LOSS)		131	128	312	179
OTHER INCOME (EXPENSE):
Loss on debt redemptions				0	(1)
Investment income		3	23	17	44
Miscellaneous income		0	0	0	0
Capitalized interest		7	8	15	19
Total other income (expense)		(3)	17	5	34
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)		128	145	317	213
INCOME TAXES (BENEFITS)		47	45	117	71
INCOME (LOSS) FROM CONTINUING OPERATIONS				200	142
Discontinued operations				0	0
NET INCOME (LOSS)		81	100	200	142
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		81	100	200	142
Pension and OPEB prior service costs		0	0	0	0
Amortized gains on derivative hedges		0	0	0	0
Change in unrealized gain on available-for-sale securities		(12)	25	(9)	44
Other comprehensive income (loss)		(12)	25	(9)	44
Income taxes (benefits) on other comprehensive income (loss)		(4)	9	(3)	16
Other comprehensive income (loss), net of tax		(8)	16	(6)	28
COMPREHENSIVE INCOME (LOSS)		73	116	194	170
Nuclear Generation Corp | Affiliates
OPERATING EXPENSES:
Purchased power		66	75	134	139
OTHER INCOME (EXPENSE):
Interest expense		(1)	(1)	(2)	(2)
Nuclear Generation Corp | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense		(12)	(13)	(25)	(26)
Eliminations
Consolidating Statements of Income
Revenues		(757)	(902)	(1,712)	(1,547)
OPERATING EXPENSES:
Fuel		0	0	0	0
Other operating expenses		12	12	24	24
Provision for depreciation		0	(1)	(1)	(1)
General taxes		0	0	0	0
Total operating expenses		(745)	(891)	(1,689)	(1,524)
OPERATING INCOME (LOSS)		(12)	(11)	(23)	(23)
OTHER INCOME (EXPENSE):
Loss on debt redemptions				0	0
Investment income		(126)	(3)	(371)	(6)
Miscellaneous income		0	(158)	0	(261)
Capitalized interest		0	0	0	0
Total other income (expense)		(104)	(143)	(327)	(231)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)		(116)	(154)	(350)	(254)
INCOME TAXES (BENEFITS)		1	2	3	3
INCOME (LOSS) FROM CONTINUING OPERATIONS				(353)	(257)
Discontinued operations				0	0
NET INCOME (LOSS)		(117)	(156)	(353)	(257)
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		(117)	(156)	(353)	(257)
Pension and OPEB prior service costs		4	5	8	9
Amortized gains on derivative hedges		0	0	0	0
Change in unrealized gain on available-for-sale securities		12	(25)	9	(44)
Other comprehensive income (loss)		16	(20)	17	(35)
Income taxes (benefits) on other comprehensive income (loss)		6	(8)	6	(13)
Other comprehensive income (loss), net of tax		10	(12)	11	(22)
COMPREHENSIVE INCOME (LOSS)		(107)	(168)	(342)	(279)
Eliminations | Affiliates
OPERATING EXPENSES:
Purchased power		(757)	(902)	(1,712)	(1,547)
OTHER INCOME (EXPENSE):
Interest expense		8	3	15	6
Eliminations | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense		14	15	29	30
FES
Condensed Financial Statements, Captions [Line Items]
Tax effect of discontinued operations					70
Consolidating Statements of Income
Revenues		1,119	1,452	2,496	3,281
OPERATING EXPENSES:
Fuel		191	334	421	653
Other operating expenses		353	468	766	920
Provision for depreciation		81	79	161	153
General taxes		25	29	54	68
Total operating expenses		1,119	1,603	2,484	3,580
OPERATING INCOME (LOSS)		0	(151)	12	(299)
OTHER INCOME (EXPENSE):
Loss on debt redemptions		0	0	0	(5)
Investment income		1	24	14	44
Miscellaneous income		4	4	4	4
Capitalized interest		9	8	18	20
Total other income (expense)		(25)	(3)	(42)	(14)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)		(25)	(154)	(30)	(313)
INCOME TAXES (BENEFITS)		(4)	(67)	(6)	(123)
INCOME (LOSS) FROM CONTINUING OPERATIONS		(21)	(87)	(24)	(190)
Discontinued operations		0	0	0	116
NET INCOME (LOSS)		(21)	(87)	(24)	(74)
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		(21)	(87)	(24)	(74)
Pension and OPEB prior service costs		(4)	(5)	(8)	(10)
Amortized gains on derivative hedges		(1)	(3)	(2)	(5)
Change in unrealized gain on available-for-sale securities		(12)	25	(9)	44
Other comprehensive income (loss)		(17)	17	(19)	29
Income taxes (benefits) on other comprehensive income (loss)		(6)	7	(7)	11
Other comprehensive income (loss), net of tax		(11)	10	(12)	18
COMPREHENSIVE INCOME (LOSS)		(32)	(77)	(36)	(56)
FES | Affiliates
OPERATING EXPENSES:
Purchased power		77	75	147	139
OTHER INCOME (EXPENSE):
Interest expense		(2)	(2)	(4)	(4)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power		392	618	935	1,647
OTHER INCOME (EXPENSE):
Interest expense		$ (37)	$ (37)	$ (74)	$ (73)
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 $96 million and $99 million the three months ended June 30, 2015 and 2014, respectively, and $211 million and $216 million in the six months ended June 30, 2015 and 2014, respectively.

Supplemental Guarantor Inform65

Supplemental Guarantor Information (Details 1) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013
CURRENT ASSETS:
Cash and cash equivalents	$ 94	$ 85	$ 76	$ 218
Receivables-
Customers	1,590	1,554
Other	181	225
Materials and supplies	792	817
Derivatives	171	159
Collateral	141	230
Prepayments and other	166	160
Total current assets	4,113	3,876
PROPERTY, PLANT AND EQUIPMENT:
In service	48,862	47,484
Less - Accumulated provision for depreciation	14,728	14,150
Property, plant and equipment in service net of accumulated provision for depreciation	34,134	33,334
Construction work in progress	2,282	2,449
Total net property, plant and equipment	36,416	35,783
INVESTMENTS:
Nuclear plant decommissioning trusts	2,348	2,341
Other	886	881
Total other property and investments	3,234	3,222
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418	6,418
Other	1,301	1,456
Total deferred charges and other assets	9,242	9,285
Total assets	53,005	52,166	51,388
CURRENT LIABILITIES:
Currently payable long-term debt	1,292	804
Other	2,908	1,799
Accounts payable-
Accrued taxes	467	490
Derivatives	160	167
Other	605	693
Total current liabilities	6,789	5,561
CAPITALIZATION:
Total common stockholders' equity	12,530	12,420
Long-term debt and other long-term obligations	18,570	19,176
Total capitalization	31,101	31,598
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	807	824
Accumulated deferred income taxes	7,485	7,057
Asset retirement obligations	1,411	1,387
Retirement benefits	3,836	3,932
Other	1,373	1,590
Total noncurrent liabilities	15,115	15,007
Total liabilities and capitalization	53,005	52,166
FES
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	325	415
Affiliated companies	340	484
Other	45	66
Notes receivable from affiliated companies	394	339
Materials and supplies	54	67
Derivatives	158	147
Collateral	140	229
Prepayments and other	80	56
Total current assets	1,536	1,803
PROPERTY, PLANT AND EQUIPMENT:
In service	90	133
Less - Accumulated provision for depreciation	34	36
Property, plant and equipment in service net of accumulated provision for depreciation	56	97
Construction work in progress	3	3
Total net property, plant and equipment	59	100
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	6,957	6,607
Other	0	0
Total other property and investments	6,957	6,607
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	322	276
Customer intangibles	70	78
Goodwill	23	23
Property taxes	0	0
Unamortized sale and leaseback costs	0	0
Derivatives	104	52
Other	51	34
Total deferred charges and other assets	570	463
Total assets	9,122	8,973
CURRENT LIABILITIES:
Currently payable long-term debt	0	18
Other	250	90
Accounts payable-
Affiliated companies	581	1,068
Other	24	46
Accrued taxes	3	2
Derivatives	155	166
Other	66	72
Total current liabilities	2,728	2,597
CAPITALIZATION:
Total common stockholders' equity	5,554	5,585
Long-term debt and other long-term obligations	695	695
Total capitalization	6,249	6,280
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	7	13
Asset retirement obligations	0	0
Retirement benefits	36	36
Derivatives	69	14
Other	33	33
Total noncurrent liabilities	145	96
Total liabilities and capitalization	9,122	8,973
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	1,649	1,135
FGCO
CURRENT ASSETS:
Cash and cash equivalents	2	2	2	2
Receivables-
Customers	0	0
Affiliated companies	287	487
Other	2	21
Notes receivable from affiliated companies	1,072	838
Materials and supplies	201	202
Derivatives	0	0
Collateral	0	0
Prepayments and other	59	41
Total current assets	1,623	1,591
PROPERTY, PLANT AND EQUIPMENT:
In service	6,351	6,217
Less - Accumulated provision for depreciation	2,107	2,058
Property, plant and equipment in service net of accumulated provision for depreciation	4,244	4,159
Construction work in progress	157	206
Total net property, plant and equipment	4,401	4,365
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	0	0
Other	10	10
Total other property and investments	10	10
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	76
Customer intangibles	0	0
Goodwill	0	0
Property taxes	7	14
Unamortized sale and leaseback costs	0	0
Derivatives	0	0
Other	321	277
Total deferred charges and other assets	328	367
Total assets	6,362	6,333
CURRENT LIABILITIES:
Currently payable long-term debt	167	164
Other	8	9
Accounts payable-
Affiliated companies	133	197
Other	93	202
Accrued taxes	41	62
Derivatives	3	0
Other	54	56
Total current liabilities	883	1,011
CAPITALIZATION:
Total common stockholders' equity	2,712	2,561
Long-term debt and other long-term obligations	2,199	2,215
Total capitalization	4,911	4,776
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	29	0
Asset retirement obligations	191	189
Retirement benefits	295	288
Derivatives	5	0
Other	48	69
Total noncurrent liabilities	568	546
Total liabilities and capitalization	6,362	6,333
FGCO | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	384	321
Nuclear Generation Corp
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	301	674
Other	10	20
Notes receivable from affiliated companies	580	272
Materials and supplies	221	223
Derivatives	0	0
Collateral	0	0
Prepayments and other	0	0
Total current assets	1,112	1,189
PROPERTY, PLANT AND EQUIPMENT:
In service	7,919	7,628
Less - Accumulated provision for depreciation	3,483	3,305
Property, plant and equipment in service net of accumulated provision for depreciation	4,436	4,323
Construction work in progress	757	801
Total net property, plant and equipment	5,193	5,124
INVESTMENTS:
Nuclear plant decommissioning trusts	1,365	1,365
Investment in affiliated companies	0	0
Other	0	0
Total other property and investments	1,365	1,365
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	0	0
Goodwill	0	0
Property taxes	12	27
Unamortized sale and leaseback costs	0	0
Derivatives	0	0
Other	11	7
Total deferred charges and other assets	23	34
Total assets	7,693	7,712
CURRENT LIABILITIES:
Currently payable long-term debt	541	348
Other	0	0
Accounts payable-
Affiliated companies	164	219
Other	0	0
Accrued taxes	50	161
Derivatives	0	0
Other	9	9
Total current liabilities	764	765
CAPITALIZATION:
Total common stockholders' equity	4,208	4,014
Long-term debt and other long-term obligations	614	859
Total capitalization	4,822	4,873
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	696	678
Asset retirement obligations	659	652
Retirement benefits	0	0
Derivatives	0	0
Other	752	744
Total noncurrent liabilities	2,107	2,074
Total liabilities and capitalization	7,693	7,712
Nuclear Generation Corp | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	0	28
Eliminations
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	(525)	(1,120)
Other	0	0
Notes receivable from affiliated companies	(2,033)	(1,449)
Materials and supplies	0	0
Derivatives	0	0
Collateral	0	0
Prepayments and other	0	(2)
Total current assets	(2,558)	(2,571)
PROPERTY, PLANT AND EQUIPMENT:
In service	(382)	(382)
Less - Accumulated provision for depreciation	(193)	(191)
Property, plant and equipment in service net of accumulated provision for depreciation	(189)	(191)
Construction work in progress	0	0
Total net property, plant and equipment	(189)	(191)
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	(6,957)	(6,607)
Other	0	0
Total other property and investments	(6,957)	(6,607)
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	(322)	(352)
Customer intangibles	0	0
Goodwill	0	0
Property taxes	0	0
Unamortized sale and leaseback costs	266	217
Derivatives	0	0
Other	(266)	(204)
Total deferred charges and other assets	(322)	(339)
Total assets	(10,026)	(9,708)
CURRENT LIABILITIES:
Currently payable long-term debt	(25)	(24)
Other	0	0
Accounts payable-
Affiliated companies	(581)	(1,068)
Other	0	0
Accrued taxes	(15)	(123)
Derivatives	0	0
Other	34	47
Total current liabilities	(2,620)	(2,617)
CAPITALIZATION:
Total common stockholders' equity	(6,920)	(6,575)
Long-term debt and other long-term obligations	(1,149)	(1,161)
Total capitalization	(8,069)	(7,736)
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	807	824
Accumulated deferred income taxes	(144)	(180)
Asset retirement obligations	0	0
Retirement benefits	0	0
Derivatives	0	0
Other	0	1
Total noncurrent liabilities	663	645
Total liabilities and capitalization	(10,026)	(9,708)
Eliminations | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	(2,033)	(1,449)
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2	$ 2	$ 2
Receivables-
Customers	325	415
Affiliated companies	403	525
Other	57	107
Notes receivable from affiliated companies	13	0
Materials and supplies	476	492
Derivatives	158	147
Collateral	140	229
Prepayments and other	139	95
Total current assets	1,713	2,012
PROPERTY, PLANT AND EQUIPMENT:
In service	13,978	13,596
Less - Accumulated provision for depreciation	5,431	5,208
Property, plant and equipment in service net of accumulated provision for depreciation	8,547	8,388
Construction work in progress	917	1,010
Total net property, plant and equipment	9,464	9,398
INVESTMENTS:
Nuclear plant decommissioning trusts	1,365	1,365
Investment in affiliated companies	0	0
Other	10	10
Total other property and investments	1,375	1,375
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	70	78
Goodwill	23	23
Property taxes	19	41
Unamortized sale and leaseback costs	266	217
Derivatives	104	52
Other	117	114
Total deferred charges and other assets	599	525
Total assets	13,151	13,310
CURRENT LIABILITIES:
Currently payable long-term debt	683	506
Other	258	99
Accounts payable-
Affiliated companies	297	416
Other	117	248
Accrued taxes	79	102
Derivatives	158	166
Other	163	184
Total current liabilities	1,755	1,756
CAPITALIZATION:
Total common stockholders' equity	5,554	5,585
Long-term debt and other long-term obligations	2,359	2,608
Total capitalization	7,913	8,193
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	807	824
Accumulated deferred income taxes	588	511
Asset retirement obligations	850	841
Retirement benefits	331	324
Derivatives	74	14
Other	833	847
Total noncurrent liabilities	3,483	3,361
Total liabilities and capitalization	13,151	13,310
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	$ 0	$ 35

Supplemental Guarantor Inform66

Supplemental Guarantor Information (Details 2) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2015	Jun. 30, 2014
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities				$ 990	$ 622
New Financing-
Long-term debt				200	3,137
Short-term borrowings, net				1,109	0
Redemptions and Repayments-
Long-term debt				(292)	(925)
Short-term borrowings, net				0	(1,081)
Other				(2)	(24)
Net cash provided from (used for) financing activities				712	805
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	$ (818)	$ (988)		(1,486)	(1,809)
Nuclear fuel				(97)	(58)
Proceeds from asset sales			$ 394	10	394
Sales of investment securities held in trusts				819	1,164
Purchases of investment securities held in trusts				(881)	(1,221)
Other				9	8
Net cash provided from (used for) investing activities				(1,693)	(1,569)
Net change in cash and cash equivalents				9	(142)
Cash and cash equivalents at beginning of period			218	85	218
Cash and cash equivalents at end of period	94	76		94	76
FES
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities				(600)	(202)
New Financing-
Long-term debt					0
Short-term borrowings, net				674	0
Equity contribution from parent					500
Redemptions and Repayments-
Long-term debt				(17)	(1)
Short-term borrowings, net				0	(74)
Other					(1)
Net cash provided from (used for) financing activities				657	424
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions				(2)	(4)
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				(55)	(218)
Other				0	0
Net cash provided from (used for) investing activities				(57)	(222)
Net change in cash and cash equivalents				0	0
Cash and cash equivalents at beginning of period			0	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				275	147
New Financing-
Long-term debt					291
Short-term borrowings, net				62	172
Equity contribution from parent					0
Redemptions and Repayments-
Long-term debt				(12)	(258)
Short-term borrowings, net				0	0
Other				(2)	(8)
Net cash provided from (used for) financing activities				48	197
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions				(95)	(74)
Nuclear fuel				0	0
Proceeds from asset sales				3	307
Sales of investment securities held in trusts				0	0
Purchases of investment securities held in trusts				0	0
Loans to affiliated companies, net				(234)	(581)
Other				3	4
Net cash provided from (used for) investing activities				(323)	(344)
Net change in cash and cash equivalents				0	0
Cash and cash equivalents at beginning of period			2	2	2
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				680	149
New Financing-
Long-term debt					346
Short-term borrowings, net				0	0
Equity contribution from parent					0
Redemptions and Repayments-
Long-term debt				(52)	(416)
Short-term borrowings, net				(28)	(151)
Other					(1)
Net cash provided from (used for) financing activities				(80)	(222)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions				(167)	(399)
Nuclear fuel				(97)	(57)
Proceeds from asset sales				0	0
Sales of investment securities held in trusts				376	707
Purchases of investment securities held in trusts				(404)	(736)
Loans to affiliated companies, net				(308)	558
Other				0	0
Net cash provided from (used for) investing activities				(600)	73
Net change in cash and cash equivalents				0	0
Cash and cash equivalents at beginning of period			0	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				(12)	(11)
New Financing-
Long-term debt					0
Short-term borrowings, net				(612)	(172)
Equity contribution from parent					0
Redemptions and Repayments-
Long-term debt				12	11
Short-term borrowings, net				28	98
Other					0
Net cash provided from (used for) financing activities				(572)	(63)
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				584	73
Other				0	1
Net cash provided from (used for) investing activities				584	74
Net change in cash and cash equivalents				0	0
Cash and cash equivalents at beginning of period			0	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				343	83
New Financing-
Long-term debt				0	637
Short-term borrowings, net				124	0
Equity contribution from parent				0	500
Redemptions and Repayments-
Long-term debt				(69)	(664)
Short-term borrowings, net				0	(127)
Other				(2)	(10)
Net cash provided from (used for) financing activities				53	336
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions				(264)	(477)
Nuclear fuel				(97)	(57)
Proceeds from asset sales			307	3	307
Sales of investment securities held in trusts				376	707
Purchases of investment securities held in trusts				(404)	(736)
Loans to affiliated companies, net				(13)	(168)
Other				3	5
Net cash provided from (used for) investing activities				(396)	(419)
Net change in cash and cash equivalents				0	0
Cash and cash equivalents at beginning of period			$ 2	2	2
Cash and cash equivalents at end of period	$ 2	$ 2		$ 2	$ 2

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Segment Financial Information
Revenues		$ 3,465	$ 3,496	$ 7,362	$ 7,678
Revenues	[1]	3,465	3,496	7,362	7,678
Depreciation		322	302	641	596
Amortization (deferral) of regulatory assets, net		59	20	91	(8)
Investment income (loss)		(3)	29	14	51
Interest expense		282	262	561	527
Income taxes (benefits)		115	26	259	74
Income (loss) from continuing operations		187	64	409	186
Discontinued operations		0	0	0	86
NET INCOME (LOSS)		187	64	409	272
Total assets		53,005	51,388	53,005	51,388	$ 52,166
Goodwill		6,418	6,418	6,418	6,418	$ 6,418
Property additions		818	988	1,486	1,809
Intersegment Eliminations
Segment Financial Information
Revenues		0	0	0	0
Regulated Distribution
Segment Financial Information
Revenues		2,239	2,065	4,801	4,615
Revenues		2,239	2,065	4,801	4,615
Depreciation		170	164	342	326
Amortization (deferral) of regulatory assets, net		57	16	86	(15)
Investment income (loss)		12	15	25	30
Interest expense		146	147	290	298
Income taxes (benefits)		91	77	213	202
Income (loss) from continuing operations				364	372
Discontinued operations				0	0
NET INCOME (LOSS)		156	158	364	372
Total assets		28,353	27,901	28,353	27,901
Goodwill		5,092	5,092	5,092	5,092
Property additions		312	340	592	609
Regulated Distribution | Intersegment Eliminations
Segment Financial Information
Revenues		0	0	0	0
Regulated Transmission
Segment Financial Information
Revenues		269	191	507	373
Revenues		269	191	507	373
Depreciation		38	30	75	60
Amortization (deferral) of regulatory assets, net		2	3	5	6
Investment income (loss)		0	0	0	0
Interest expense		40	30	79	55
Income taxes (benefits)		52	32	94	62
Income (loss) from continuing operations				161	114
Discontinued operations				0	0
NET INCOME (LOSS)		89	63	161	114
Total assets		7,055	5,840	7,055	5,840
Goodwill		526	526	526	526
Property additions		297	384	551	601
Regulated Transmission | Intersegment Eliminations
Segment Financial Information
Revenues		0	0	0	0
Competitive Energy Services
Segment Financial Information
Revenues		1,034	1,311	2,209	2,833
Revenues		1,196	1,493	2,631	3,264
Depreciation		99	96	195	187
Amortization (deferral) of regulatory assets, net		0	0	0	0
Investment income (loss)		(7)	21	4	35
Interest expense		48	48	96	94
Income taxes (benefits)		(7)	(65)	(11)	(138)
Income (loss) from continuing operations				(21)	(243)
Discontinued operations				0	86
NET INCOME (LOSS)		(12)	(119)	(21)	(157)
Total assets		16,711	17,137	16,711	17,137
Goodwill		800	800	800	800
Property additions		191	240	317	558
Competitive Energy Services | Intersegment Eliminations
Segment Financial Information
Revenues		162	182	422	431
Other/Corporate
Segment Financial Information
Revenues		(42)	(31)	(84)	(71)
Revenues		(42)	(31)	(84)	(71)
Depreciation		15	12	29	23
Amortization (deferral) of regulatory assets, net		0	0	0	0
Investment income (loss)		2	2	5	5
Interest expense		49	30	96	73
Income taxes (benefits)		(19)	(30)	(37)	(56)
Income (loss) from continuing operations				(95)	(58)
Discontinued operations				0	0
NET INCOME (LOSS)		(46)	(26)	(95)	(58)
Total assets		886	510	886	510
Goodwill		0	0	0	0
Property additions		18	24	26	41
Other/Corporate | Intersegment Eliminations
Segment Financial Information
Revenues		0	0	0	0
Reconciling Adjustments
Segment Financial Information
Revenues		(35)	(40)	(71)	(72)
Revenues		(197)	(222)	(493)	(503)
Depreciation		0	0	0	0
Amortization (deferral) of regulatory assets, net		0	1	0	1
Investment income (loss)		(10)	(9)	(20)	(19)
Interest expense		(1)	7	0	7
Income taxes (benefits)		(2)	12	0	4
Income (loss) from continuing operations				0	1
Discontinued operations				0	0
NET INCOME (LOSS)		0	(12)	0	1
Total assets		0	0	0	0
Goodwill		0	0	0	0
Property additions		0	0	0	0
Reconciling Adjustments | Intersegment Eliminations
Segment Financial Information
Revenues		$ (162)	$ (182)	$ (422)	$ (431)
[1]	Includes excise tax collections of $96 million and $99 million the three months ended June 30, 2015 and 2014, respectively, and $211 million and $216 million in the six months ended June 30, 2015 and 2014, respectively.

Segment Information (Details Te

Segment Information (Details Textuals) - Jun. 30, 2015 mi² in Thousands, customer in Millions, $ in Billions	USD ($)mi²customercompanyMW
Regulated Distribution
Segment Reporting Information [Line Items]
Number of existing utility operating companies | company	10
Number of customers served by utility operating companies | customer	6
Number of square miles in service area | mi²	65
Megawatts of net demonstrated capacity of competitive segment | MW	3,790
Competitive Energy Services
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment | MW	13,169
Other/Corporate
Segment Reporting Information [Line Items]
Long-term debt and other long-term obligations	$ 4.2
Long-term debt percentage bearing variable interest (percent)	28.00%
FirstEnergy | Revolving Credit Facility | Other/Corporate
Segment Reporting Information [Line Items]
Long-term line of credit	$ 1.9

Discontinued Operations (Detail

Discontinued Operations (Details) $ in Millions	Feb. 12, 2014USD ($)hydroelectric_power_station	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of hydroelectric power stations sold | hydroelectric_power_station	11
Proceeds from asset sales			$ 394	$ 10	$ 394
Carrying value of assets sold	$ 235
Discontinued operations, goodwill	29
Pre-tax income from discontinued operation					155
Pre-tax gain on sale of assets					142
Revenues from discontinued operations					5
FES
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales			$ 307	$ 3	307
Carrying value of assets sold	122
Discontinued operations, goodwill	$ 1
Pre-tax income from discontinued operation					$ 186
Pre-tax gain on sale of assets		$ 177
Revenues from discontinued operations		$ 5