FirstEnergy Solutions 10-Q 1 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015
Entity Information [Line Items]
Entity Registrant Name	FIRSTENERGY CORP
Entity Central Index Key	1031296
Document Type	10-Q
Document Period End Date	31-Mar-15
Amendment Flag	FALSE
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding	422,025,870
FES
Entity Information [Line Items]
Entity Registrant Name	FirstEnergy Solutions Corp.
Entity Central Index Key	1407703
Document Type	10-Q
Document Period End Date	31-Mar-15
Amendment Flag	FALSE
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	-19
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding	7

Consolidated_Statements_of_Inc

Consolidated Statements of Income (FirstEnergy Corp.) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
REVENUES:
Electric utilities	$2,800		$2,732
Unregulated businesses	1,097		1,450
Total revenues	3,897	[1]	4,182	[1]
OPERATING EXPENSES:
Fuel	513		617
Purchased power	1,113		1,455
Other operating expenses	1,057		1,182
Provision for depreciation	319		294
Amortization (deferral) of regulatory assets, net	32		-28
General taxes	269		271
Total operating expenses	3,303		3,791
OPERATING INCOME (LOSS)	594		391
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		-7
Investment income	17		22
Interest expense	-279		-265
Capitalized financing costs	34		29
Total other income (expense)	-228		-221
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	366		170
INCOME TAXES (BENEFITS)	144		48
INCOME (LOSS) FROM CONTINUING OPERATIONS	222		122
Discontinued operations (net of income taxes of $69 respectively)	0		86
NET INCOME (LOSS)	$222		$208
EARNINGS PER SHARE OF COMMON STOCK:
Basic - Continuing Operations, in dollars per share	$0.53		$0.29
Basic - Discontinued Operations, in dollars per share	$0		$0.21
Basic - Earnings Available to FirstEnergy Corp., in dollars per share	$0.53		$0.50
Diluted - Continuing Operations, in dollars per share	$0.53		$0.29
Diluted - Discontinued Operations, in dollars per share	$0		$0.20
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share	$0.53		$0.49
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic, in shares	421		419
Diluted, in shares	423		420
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share	$0.72		$0.72
[1]	Includes excise tax collections of $115 million and $117 million in the three months ended March 31, 2015 and 2014.

Consolidated_Statements_of_Inc1

Consolidated Statements of Income (FirstEnergy Corp.) (Parenthetical) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Income Statement [Abstract]
Tax effect of discontinued operations	$0	$69
Excise taxes collected	$115	$117

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (FirstEnergy Corp.) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Statement of Comprehensive Income [Abstract]
NET INCOME	$222	$208
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	-31	-42
Amortized gains (losses) on derivative hedges	1	0
Change in unrealized gain on available-for-sale securities	4	21
Other comprehensive income (loss)	-26	-21
Income tax benefits on other comprehensive loss	-10	-8
Other comprehensive income (loss), net of tax	-16	-13
COMPREHENSIVE INCOME (LOSS)	$206	$195

Consolidated_Balance_Sheets_Fi

Consolidated Balance Sheets (FirstEnergy Corp.) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
CURRENT ASSETS:
Cash and cash equivalents	$90	$85
Receivables-
Customers, net of allowance for uncollectible accounts of $60 in 2015 and $59 in 2014	1,675	1,554
Other, net of allowance for uncollectible accounts of $5 in 2015 and in 2014	201	225
Materials and supplies	762	817
Prepaid taxes	225	128
Derivatives	133	159
Accumulated deferred income taxes	548	518
Collateral	220	230
Other	157	160
Total current assets	4,011	3,876
PROPERTY, PLANT AND EQUIPMENT:
In service	47,992	47,484
Less - Accumulated provision for depreciation	14,508	14,150
Property, plant and equipment in service net of accumulated provision for depreciation	33,484	33,334
Construction work in progress	2,633	2,449
Total net property, plant and equipment	36,117	35,783
INVESTMENTS:
Nuclear plant decommissioning trusts	2,360	2,341
Other	898	881
Total other property and investments	3,258	3,222
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418
Regulatory assets	1,372	1,411
Other	1,345	1,456
Total deferred charges and other assets	9,135	9,285
Total assets	52,521	52,166
CURRENT LIABILITIES:
Currently payable long-term debt	787	804
Short-term borrowings	2,559	1,799
Accounts payable	1,102	1,279
Accrued taxes	503	490
Accrued compensation and benefits	249	329
Derivatives	154	167
Other	908	693
Total current liabilities	6,262	5,561
Common stockholders' equity-
Common stock, $0.10 par value, authorized 490,000,000 shares - 422,025,870 and 421,102,570 shares outstanding as of March 31, 2015 and December 31, 2014, respectively	42	42
Other paid-in capital	9,871	9,847
Accumulated other comprehensive income	230	246
Retained earnings	2,205	2,285
Total common stockholders' equity	12,348	12,420
Noncontrolling interest	2	2
Total equity	12,350	12,422
Long-term debt and other long-term obligations	19,130	19,176
Total capitalization	31,480	31,598
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	7,211	7,057
Retirement benefits	3,817	3,932
Asset retirement obligations	1,390	1,387
Deferred gain on sale and leaseback transaction	816	824
Adverse power contract liability	213	217
Other	1,332	1,590
Total noncurrent liabilities	14,779	15,007
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	$52,521	$52,166

Consolidated_Balance_Sheets_Fi1

Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, except Share data, unless otherwise specified
Common stockholders' equity-
Common stock, par value (in dollars per share)	$0.10	$0.10
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	422,025,870	421,102,570
Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$60	$59
Other [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$5	$5

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (FirstEnergy Corp.) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$222	$208
Adjustments to reconcile net income to net cash from operating activities-
Income from discontinued operations	0	-86
Provision for depreciation	319	294
Amortization (deferral) of regulatory assets, net	32	-28
Nuclear fuel amortization	57	48
Deferred purchased power and other costs	-31	-34
Deferred income taxes and investment tax credits, net	127	181
Deferred costs on sale and leaseback transaction, net	12	13
Amortization of customer intangibles and deferred advertising expense	7	9
Retirement benefits	-4	-20
Pension trust contributions	-143	0
Commodity derivative transactions, net	2	-17
Loss on debt redemptions	0	7
Changes in current assets and liabilities-
Receivables	-97	-168
Materials and supplies	30	12
Prepayments and other current assets	-116	-29
Accounts payable	-177	200
Accrued taxes	-80	-242
Accrued interest	44	46
Accrued compensation and benefits	-80	-118
Other current liabilities	11	2
Cash collateral, net	-15	-461
Other	73	91
Net cash provided from (used for) operating activities	193	-92
New Financing-
Long-term debt	0	1,467
Short-term borrowings, net	760	0
Redemptions and Repayments-
Long-term debt	-48	-489
Short-term borrowings, net	0	-319
Common stock dividend payments	-152	-151
Other	0	-10
Net cash provided from (used for) financing activities	560	498
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	-668	-821
Nuclear fuel	-60	-55
Proceeds from asset sales	10	394
Sales of investment securities held in trusts	371	621
Purchases of investment securities held in trusts	-394	-646
Cash investments	21	28
Asset removal costs	-28	-39
Other	0	3
Net cash provided from (used for) investing activities	-748	-515
Net change in cash and cash equivalents	5	-109
Cash and cash equivalents at beginning of period	85	218
Cash and cash equivalents at end of period	$90	$109

Consolidated_Statements_of_Inc2

Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
NET INCOME	$222		$208
REVENUES:
Electric sales	1,097		1,450
Total revenues	3,897	[1]	4,182	[1]
OPERATING EXPENSES:
Fuel	513		617
Purchased power	1,113		1,455
Other operating expenses	1,057		1,182
Provision for depreciation	319		294
General taxes	269		271
Total operating expenses	3,303		3,791
OPERATING INCOME (LOSS)	594		391
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		-7
Investment income	17		22
Interest expense	-279		-265
Capitalized interest	34		29
Total other income (expense)	-228		-221
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	366		170
INCOME TAXES (BENEFITS)	144		48
INCOME (LOSS) FROM CONTINUING OPERATIONS	222		122
Discontinued operations (net of income taxes of $70 respectively)	0		86
NET INCOME (LOSS)	222		208
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME (LOSS)	222		208
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	-31		-42
Amortized loss (gain) on derivative hedges	1		0
Change in unrealized gain on available-for-sale securities	4		21
Other comprehensive income (loss)	-26		-21
Income taxes (benefits) on other comprehensive income (loss)	-10		-8
Other comprehensive income (loss), net of tax	-16		-13
COMPREHENSIVE INCOME (LOSS)	206		195
FES
NET INCOME	-3		13
REVENUES:
Other	47		40
Total revenues	1,377		1,829
OPERATING EXPENSES:
Fuel	230		319
Other operating expenses	413		452
Provision for depreciation	80		74
General taxes	29		39
Total operating expenses	1,365		1,977
OPERATING INCOME (LOSS)	12		-148
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		-5
Investment income	13		20
Capitalized interest	9		12
Total other income (expense)	-17		-11
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	-5		-159
INCOME TAXES (BENEFITS)	-2		-56
INCOME (LOSS) FROM CONTINUING OPERATIONS	-3		-103
Discontinued operations (net of income taxes of $70 respectively)	0		116
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	-4		-5
Amortized loss (gain) on derivative hedges	-1		-2
Change in unrealized gain on available-for-sale securities	3		19
Other comprehensive income (loss)	-2		12
Income taxes (benefits) on other comprehensive income (loss)	-1		4
Other comprehensive income (loss), net of tax	-1		8
COMPREHENSIVE INCOME (LOSS)	-4		21
FES | Affiliates
REVENUES:
Electric sales	255		349
OPERATING EXPENSES:
Purchased power	70		64
OTHER INCOME (EXPENSE):
Interest expense	-2		-2
FES | Non-Affiliates
REVENUES:
Electric sales	1,075		1,440
OPERATING EXPENSES:
Purchased power	543		1,029
OTHER INCOME (EXPENSE):
Interest expense	($37)		($36)
[1]	Includes excise tax collections of $115 million and $117 million in the three months ended MarchB 31, 2015 and 2014.

Consolidated_Statements_of_Inc3

Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) (Parenthetical) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Tax effect of discontinued operations	$0	$69
FES
Tax effect of discontinued operations	$0	$70

Consolidated_Balance_Sheets_Fi2

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
CURRENT ASSETS:
Cash and cash equivalents	$90	$85
Receivables-
Customers, net of allowance for uncollectible accounts of $15 in 2015 and $18 in 2014	1,675	1,554
Other, net of allowance for uncollectible accounts of $3 in 2015 and 2014	201	225
Materials and supplies	762	817
Derivatives	133	159
Collateral	220	230
Prepayments and other	157	160
Total current assets	4,011	3,876
PROPERTY, PLANT AND EQUIPMENT:
In service	47,992	47,484
Less - Accumulated provision for depreciation	14,508	14,150
Property, plant and equipment in service net of accumulated provision for depreciation	33,484	33,334
Construction work in progress	2,633	2,449
Total net property, plant and equipment	36,117	35,783
INVESTMENTS:
Nuclear plant decommissioning trusts	2,360	2,341
Other	898	881
Total other property and investments	3,258	3,222
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418
Other	1,345	1,456
Total deferred charges and other assets	9,135	9,285
Total assets	52,521	52,166
CURRENT LIABILITIES:
Currently payable long-term debt	787	804
Other	2,559	1,799
Accounts payable-
Accrued taxes	503	490
Derivatives	154	167
Other	908	693
Total current liabilities	6,262	5,561
Common stockholders' equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of March 31, 2015 and December 31, 2014	42	42
Accumulated other comprehensive income	230	246
Retained earnings	2,205	2,285
Total common stockholders' equity	12,348	12,420
Long-term debt and other long-term obligations	19,130	19,176
Total capitalization	31,480	31,598
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	816	824
Accumulated deferred income taxes	7,211	7,057
Retirement benefits	3,817	3,932
Asset retirement obligations	1,390	1,387
Other	1,332	1,590
Total noncurrent liabilities	14,779	15,007
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	52,521	52,166
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2
Receivables-
Customers, net of allowance for uncollectible accounts of $15 in 2015 and $18 in 2014	351	415
Affiliated companies	541	525
Other, net of allowance for uncollectible accounts of $3 in 2015 and 2014	152	107
Notes receivable from affiliated companies	44	0
Materials and supplies	447	492
Derivatives	132	147
Collateral	217	229
Prepayments and other	117	95
Total current assets	2,003	2,012
PROPERTY, PLANT AND EQUIPMENT:
In service	13,706	13,596
Less - Accumulated provision for depreciation	5,331	5,208
Property, plant and equipment in service net of accumulated provision for depreciation	8,375	8,388
Construction work in progress	1,057	1,010
Total net property, plant and equipment	9,432	9,398
INVESTMENTS:
Nuclear plant decommissioning trusts	1,381	1,365
Other	10	10
Total other property and investments	1,391	1,375
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	74	78
Goodwill	23	23
Property taxes	31	41
Unamortized sale and leaseback costs	248	217
Derivatives	67	52
Other	108	114
Total deferred charges and other assets	551	525
Total assets	13,377	13,310
CURRENT LIABILITIES:
Currently payable long-term debt	490	506
Other	284	99
Accounts payable-
Affiliated companies	429	416
Other	156	248
Accrued taxes	85	102
Derivatives	154	166
Other	206	184
Total current liabilities	1,804	1,756
Common stockholders' equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of March 31, 2015 and December 31, 2014	3,594	3,594
Accumulated other comprehensive income	56	57
Retained earnings	1,931	1,934
Total common stockholders' equity	5,581	5,585
Long-term debt and other long-term obligations	2,605	2,608
Total capitalization	8,186	8,193
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	816	824
Accumulated deferred income taxes	548	511
Retirement benefits	327	324
Asset retirement obligations	838	841
Derivatives	28	14
Other	830	847
Total noncurrent liabilities	3,387	3,361
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	13,377	13,310
FES | Affiliated Entity [Member]
CURRENT LIABILITIES:
Affiliated companies	$0	$35

Consolidated_Balance_Sheets_Fi3

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, except Share data, unless otherwise specified
Common stockholders' equity-
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	422,025,870	421,102,570
Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	60	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)	15	18
FES | Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	3	3

Consolidated_Statements_of_Cas1

Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$222	$208
Adjustments to reconcile net income (loss) to net cash from operating activities-
Income from discontinued operations	0	-86
Provision for depreciation	319	294
Nuclear fuel amortization	57	48
Deferred costs on sale and leaseback transaction, net	12	13
Amortization of customer intangibles and deferred advertising expense	7	9
Deferred income taxes and investment tax credits, net	127	181
Commodity derivative transactions, net	2	-17
Loss on debt redemptions	0	7
Changes in current assets and liabilities-
Receivables	-97	-168
Materials and supplies	30	12
Prepayments and other current assets	-116	-29
Accounts payable	-177	200
Accrued taxes	-80	-242
Accrued compensation and benefits	-80	-118
Cash collateral, net	-15	-461
Other	73	91
Net cash provided from (used for) operating activities	193	-92
New financing-
Long-term debt	0	1,467
Short-term borrowings, net	760	0
Redemptions and Repayments-
Long-term debt	-48	-489
Other	0	-10
Net cash provided from (used for) financing activities	560	498
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	-668	-821
Nuclear fuel	-60	-55
Proceeds from asset sales	10	394
Sales of investment securities held in trusts	371	621
Purchases of investment securities held in trusts	-394	-646
Net cash provided from (used for) investing activities	-748	-515
Net change in cash and cash equivalents	5	-109
Cash and cash equivalents at beginning of period	85	218
Cash and cash equivalents at end of period	90	109
FES
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	-3	13
Adjustments to reconcile net income (loss) to net cash from operating activities-
Income from discontinued operations	0	-116
Provision for depreciation	80	74
Nuclear fuel amortization	57	48
Deferred costs on sale and leaseback transaction, net	12	13
Amortization of customer intangibles and deferred advertising expense	7	9
Deferred income taxes and investment tax credits, net	34	48
Investment impairments	6	2
Commodity derivative transactions, net	1	-17
Loss on debt redemptions	0	5
Changes in current assets and liabilities-
Receivables	1	553
Materials and supplies	21	21
Prepayments and other current assets	-18	-48
Accounts payable	-75	-430
Accrued taxes	-24	-49
Accrued compensation and benefits	-9	-19
Cash collateral, net	12	-420
Other	3	1
Net cash provided from (used for) operating activities	105	-312
New financing-
Long-term debt	0	417
Short-term borrowings, net	150	120
Equity contribution from parent	0	500
Redemptions and Repayments-
Long-term debt	-17	-445
Other	-2	-4
Net cash provided from (used for) financing activities	131	588
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	-119	-298
Nuclear fuel	-60	-55
Proceeds from asset sales	0	307
Sales of investment securities held in trusts	189	423
Purchases of investment securities held in trusts	-202	-438
Loans to affiliated companies, net	-44	-215
Net cash provided from (used for) investing activities	-236	-276
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_Pres

Organization and Basis of Presentation	3 Months Ended
	Mar. 31, 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.
	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 March 31, 2015 and 2014, capitalized financing costs on FirstEnergy's Consolidated Statements of Income includes $16 million and $7 million, respectively, of allowance for equity funds used during construction and $18 million and $22 million, respectively, of capitalized interest.
	Certain prior year amounts have been reclassified to conform to the current year presentation.
	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 April 2015, the FASB proposed a deferral of the effective date of the new revenue standard by one year, subject to the FASB's due process requirement. 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_S

Earnings Per Share of Common Stock	3 Months Ended
	Mar. 31, 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 March 31,
	Reconciliation of Basic and Diluted Earnings per Share of Common Stock		2015		2014
	Income from continuing operations		$	222	$	122
	Discontinued operations (Note 13)		—		86
	Net income		$	222	$	208
	Weighted average number of basic shares outstanding		421		419
	Assumed exercise of dilutive stock options and awards(1)		2		1
	Weighted average number of diluted shares outstanding		423		420
	Earnings per share:
	Basic earnings per share:
	Income from continuing operations		$	0.53	$	0.29
	Discontinued operations (Note 13)		—		0.21
	Net earnings per basic share		$	0.53	$	0.5
	Diluted earnings per share:
	Income from continuing operations		$	0.53	$	0.29
	Discontinued operations (Note 13)		—		0.2
	Net earnings per diluted share		$	0.53	$	0.49
	(1)	For the three months ended March 31, 2015 and March 31, 2014, 1 million and 2 million shares, respectively, were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

Pension_and_Other_Postemployme

Pension and Other Postemployment Benefits	3 Months Ended
	Mar. 31, 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 March 31,	2015			2014			2015			2014
		(In millions)
	Service costs	$	48		$	42		$	1		$	2
	Interest costs	96			100			7			10
	Expected return on plan assets	(111		)	(115		)	(8		)	(8		)
	Amortization of prior service costs (credits)	2			2			(33		)	(44		)
	Net periodic costs (credits)	$	35		$	29		$	(33	)	$	(40	)
	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 March 31,	$	4		$	4		$	(5	)	$	(5	)
	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 March 31,	2015			2014			2015			2014
		(In millions)
	FirstEnergy	$	25		$	21		$	(23	)	$	(27	)
	FES	4			4			(4		)	(4		)

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income	3 Months Ended
	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME	ACCUMULATED OTHER COMPREHENSIVE INCOME
	The changes in AOCI, net of tax, in the three months ended March 31, 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 January 1, 2015	$	(37	)	$	25		$	258		$	246
	Other comprehensive income before reclassifications	—			14			—			14
	Amounts reclassified from AOCI	1			(10		)	(31		)	(40		)
	Other comprehensive income (loss)	1			4			(31		)	(26		)
	Income tax (benefits) on other comprehensive income (loss)	—			1			(11		)	(10		)
	Net other comprehensive income (loss)	1			3			(20		)	(16		)
	AOCI Balance as of March 31, 2015	$	(36	)	$	28		$	238		$	230
	AOCI Balance as of January 1, 2014	$	(36	)	$	9		$	311		$	284
	Other comprehensive income before reclassifications	—			35			—			35
	Amounts reclassified from AOCI	—			(14		)	(42		)	(56		)
	Other comprehensive income (loss)	—			21			(42		)	(21		)
	Income tax (benefits) on other comprehensive income (loss)	—			8			(16		)	(8		)
	Net other comprehensive income (loss)	—			13			(26		)	(13		)
	AOCI Balance as of March 31, 2014	$	(36	)	$	22		$	285		$	271
	The following amounts were reclassified from AOCI in the three months ended March 31, 2015 and 2014:
		Three Months Ended March 31,						Affected Line Item in Consolidated Statements of Income
	Reclassifications from AOCI (2)	2015			2014
		(In millions)
	Gains & losses on cash flow hedges
	Commodity contracts	$	(1	)	$	(2	)	Other operating expenses
	Long-term debt	2			2			Interest expense
		1			—			Total before taxes
		—			—			Income taxes
		$	1		$	—		Net of tax
	Unrealized gains on AFS securities
	Realized gains on sales of securities	$	(10	)	$	(14	)	Investment income
		4			5			Income taxes
		$	(6	)	$	(9	)	Net of tax
	Defined benefit pension and OPEB plans
	Prior-service costs	$	(31	)	$	(42	)	(1)
		11			16			Income taxes
		$	(20	)	$	(26	)	Net of tax
	(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details.
	(2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.
	The changes in AOCI, net of tax, in the three months ended March 31, 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 January 1, 2015	$	(7	)	$	21		$	43		$	57
	Other comprehensive income before reclassifications	—			13			—			13
	Amounts reclassified from AOCI	(1		)	(10		)	(4		)	(15		)
	Other comprehensive income (loss)	(1		)	3			(4		)	(2		)
	Income tax (benefits) on other comprehensive loss	—			—			(1		)	(1		)
	Net other comprehensive income (loss)	(1		)	3			(3		)	(1		)
	AOCI Balance as of March 31, 2015	$	(8	)	$	24		$	40		$	56
	AOCI Balance as of January 1, 2014	$	(1	)	$	8		$	47		$	54
	Other comprehensive income before reclassifications	—			33			—			33
	Amounts reclassified from AOCI	(2		)	(14		)	(5		)	(21		)
	Other comprehensive income (loss)	(2		)	19			(5		)	12
	Income tax (benefits) on other comprehensive income (loss)	(1		)	7			(2		)	4
	Net other comprehensive income (loss)	(1		)	12			(3		)	8
	AOCI Balance as of March 31, 2014	$	(2	)	$	20		$	44		$	62
	The following amounts were reclassified from AOCI in the three months ended March 31, 2015 and 2014:
		Three Months Ended March 31,						Affected Line Item in Consolidated Statements of Income (Loss)
	Reclassifications from AOCI (2)	2015			2014
		(In millions)
	Gains & losses on cash flow hedges
	Commodity contracts	$	(1	)	$	(2	)	Other operating expenses
		—			1			Income tax benefits
	$	(1	)	$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(10	)	$	(14	)	Investment income (loss)
	4			5			Income tax benefits
	$	(6	)	$	(9	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(4	)	$	(5	)	(1)
	1			2			Income tax benefits
	$	(3	)	$	(3	)	Net of tax
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details.
(2) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.

Income_Taxes

Income Taxes	3 Months Ended
	Mar. 31, 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 March 31, 2015 and 2014 was 39.3% and 28.2%, respectively. The increase in the effective tax rate is primarily due to the elimination of certain future tax liabilities associated with basis differences as well as the reduction in state deferred tax liabilities resulting from changes in state apportionment factors in the first quarter of 2014.
	FES’ effective tax rate from continuing operations for the three months ended March 31, 2015 and 2014 was 40.0% and 35.2%, respectively. The increase in the effective tax rate quarter over quarter is primarily due to changes in estimated annual permanent items on lower pre-tax losses for the period.
	As of March 31, 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 year 2014 is currently under review by the IRS.

Variable_Interest_Entities

Variable Interest Entities	3 Months Ended
	Mar. 31, 2015
Variable Interest Entities [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES
	FirstEnergy performs qualitative analyses based on powers and benefits 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 trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; wholly-owned limited liability companies of the Ohio Companies created to issue phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets; wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs and special purpose limited liability companies at MP and PE created to issue environmental control bonds that were used to construct environmental control facilities.
	The caption "noncontrolling interest" within the consolidated financial statements is used to reflect the portion of a VIE that FirstEnergy consolidates, but does not own.
	In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into the following categories based on similar risk characteristics and significance.
	Ohio Securitization
	In September 2012, the Ohio Companies formed CEI Funding LLC, OE Funding LLC and TE Funding LLC, respectively, as separate, wholly-owned limited liability SPEs. The phase-in recovery bonds issued by these SPEs are payable only from, and secured by, phase-in recovery property owned by the SPEs (i.e. the right to impose, charge and collect irrevocable non-bypassable usage-based charges payable by retail electric customers in the service territories of the Ohio Companies) and the bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of March 31, 2015 and December 31, 2014, $374 million and $386 million of the phase-in recovery bonds were outstanding, respectively.
	JCP&L Securitization
	The consolidated financial statements of FirstEnergy and JCP&L include the accounts of JCP&L Transition Funding and JCP&L Transition Funding II (wholly owned limited liability companies of JCP&L). In June 2002, JCP&L Transition Funding sold transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consist primarily of bondable transition property. As of March 31, 2015 and December 31, 2014, $159 million and $168 million of the transition bonds were outstanding, respectively.
	MP and PE Environmental Funding Companies
	The consolidated financial statements of FirstEnergy include two bankruptcy remote, special purpose limited liability companies (indirect subsidiaries of MP and PE). 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 March 31, 2015 and December 31, 2014, $441 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 $379 million as of March 31, 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. (See Note 10, Commitments, Guarantees and Contingencies.)
	Trusts
	FirstEnergy's consolidated financial statements include PNBV. FirstEnergy used debt and available funds to purchase the notes issued by PNBV for the purchase of lease obligation bonds. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE.
	PATH-WV
	PATH is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FirstEnergy owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of the portion of the PATH project that was to be constructed by PATH-WV. 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 PATH.
	Power Purchase Agreements
	FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy maintains 16 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 interests 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 March 31, 2015 and 2014 were $31 million and $61 million, 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 March 31, 2015, FirstEnergy's leasehold interest was 3.75% of Perry Unit 1, 93.83% of Bruce Mansfield Unit 1 and 2.60% of Beaver Valley Unit 2.
	On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors' interests in Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), which right to repurchase was assigned to NG. Additionally, on June 24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor equity interests of the remaining non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the end of the lease term. Upon the completion of these transactions, NG will have obtained all of the lessor equity interests at Perry Unit 1 and Beaver Valley Unit 2.
	FES, and other FE subsidiaries are exposed to losses under their applicable sale and leaseback agreements upon the occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions as of March 31, 2015:
		Maximum		Discounted Lease		Net
		Exposure		Payments, net		Exposure
		(In millions)
	FirstEnergy	$	1,321	$	1,053	$	268
	FES	1,235		1,014		221

Fair_Value_Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 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 RTO auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent RTO auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 8, Derivative Instruments, for additional information regarding FirstEnergy's FTRs.
	NUG contracts represent purchase power agreements with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for the current year and next three years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on ICE quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement.
	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 March 31, 2015, from those used as of December 31, 2014. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements.
	Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the three months ended March 31, 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	March 31, 2015																December 31, 2014
		Level 1				Level 2				Level 3				Total				Level 1			Level 2			Level 3			Total
	Assets	(In millions)
	Corporate debt securities	$	—			$	1,262			$	—			$	1,262			$	—		$	1,221		$	—		$	1,221
	Derivative assets - commodity contracts	2				191				—				193				1			171			—			172
	Derivative assets - FTRs	—				—				7				7				—			—			39			39
	Derivative assets - NUG contracts(1)	—				—				2				2				—			—			2			2
	Equity securities(2)	695				—				—				695				592			—			—			592
	Foreign government debt securities	—				85				—				85				—			76			—			76
	U.S. government debt securities	—				185				—				185				—			182			—			182
	U.S. state debt securities	—				244				—				244				—			237			—			237
	Other(3)	48				186				—				234				55			256			—			311
	Total assets	$	745			$	2,153			$	9			$	2,907			$	648		$	2,143		$	41		$	2,832
	Liabilities
	Derivative liabilities - commodity contracts	$	(10	)		$	(167	)		$	—			$	(177	)		$	(26	)	$	(141	)	$	—		$	(167	)
	Derivative liabilities - FTRs	—				—				(5		)		(5		)		—			—			(14		)	(14		)
	Derivative liabilities - NUG contracts(1)	—				—				(150		)		(150		)		—			—			(153		)	(153		)
	Total liabilities	$	(10	)		$	(167	)		$	(155	)		$	(332	)		$	(26	)	$	(141	)	$	(167	)	$	(334	)
	Net assets (liabilities)(4)	$	735			$	1,986			$	(146	)		$	2,575			$	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 $(32) million and $40 million as of March 31, 2015 and December 31, 2014, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
	Rollforward of Level 3 Measurements
	The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2015 and December 31, 2014:
		NUG Contracts(1)												FTRs
		Derivative Assets				Derivative Liabilities				Net				Derivative Assets				Derivative Liabilities			Net
		(In millions)
	January 1, 2014 Balance	$	20			$	(222	)		$	(202	)		$	4			$	(12	)	$	(8	)
	Unrealized gain (loss)	2				(2		)		—				47				(1		)	46
	Purchases	—				—				—				26				(16		)	10
	Settlements	(20		)		71				51				(38		)		15			(23		)
	December 31, 2014 Balance	$	2			$	(153	)		$	(151	)		$	39			$	(14	)	$	25
	Unrealized gain (loss)	1				(10		)		(9		)		4				3			7
	Settlements	(1		)		13				12				(36		)		6			(30		)
	March 31, 2015 Balance	$	2			$	(150	)		$	(148	)		$	7			$	(5	)	$	2
	(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 March 31, 2015:
			Fair Value, Net (In millions)				Valuation		Significant Input		Range		Weighted Average			Units
							Technique
	FTRs		$	2			Model		RTO auction clearing prices		($3.80) to $4.70		$0.90			Dollars/MWH
	NUG Contracts		$	(148	)		Model		Generation		500 to 4,538,000		891,000			MWH
									Regional electricity prices		$46.10 to $69.90		$52.80			Dollars/MWH
	FES
	Recurring Fair Value Measurements	March 31, 2015																December 31, 2014
		Level 1				Level 2				Level 3				Total				Level 1			Level 2			Level 3			Total
	Assets	(In millions)
	Corporate debt securities	$	—			$	690			$	—			$	690			$	—		$	655		$	—		$	655
Derivative assets - commodity contracts	2				191				—				193				1			171			—			172
Derivative assets - FTRs	—				—				6				6				—			—			27			27
Equity securities(1)	469				—				—				469				360			—			—			360
Foreign government debt securities	—				68				—				68				—			57			—			57
U.S. government debt securities	—				35				—				35				—			46			—			46
U.S. state debt securities	—				4				—				4				—			4			—			4
Other(2)	—				124				—				124				—			199			—			199
Total assets	$	471			$	1,112			$	6			$	1,589			$	361		$	1,132		$	27		$	1,520
Liabilities
Derivative liabilities - commodity contracts	$	(10	)		$	(167	)		$	—			$	(177	)		$	(26	)	$	(141	)	$	—		$	(167	)
Derivative liabilities - FTRs	—				—				(5		)		(5		)		—			—			(13		)	(13		)
Total liabilities	$	(10	)		$	(167	)		$	(5	)		$	(182	)		$	(26	)	$	(141	)	$	(13	)	$	(180	)
Net assets (liabilities)(3)	$	461			$	945			$	1			$	1,407			$	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 $(9) million and $44 million as of March 31, 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 March 31, 2015 and December 31, 2014:
		Derivative Asset				Derivative Liability				Net Asset (Liability)
		(In millions)
January 1, 2014 Balance		$	3			$	(11	)		$	(8	)
Unrealized gain (loss)		34				(1		)		33
Purchases		15				(16		)		(1		)
Settlements		(25		)		15				(10		)
December 31, 2014 Balance		$	27			$	(13	)		$	14
Unrealized gain		3				2				5
Settlements		(24		)		6				(18		)
March 31, 2015 Balance		$	6			$	(5	)		$	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 March 31, 2015:
		Fair Value, Net (In millions)				Valuation		Significant Input		Range		Weighted Average		Units
						Technique
FTRs		$	1			Model		RTO auction clearing prices		($3.80) to $4.30		$0.70		Dollars/MWH
INVESTMENTS
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities, AFS securities and notes receivable.
At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy first considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value.
Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES, OE and TE are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of OTTI.
The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries.
AFS Securities
FirstEnergy holds debt and equity securities within its NDT, nuclear fuel disposal and NUG trusts. These trust investments are considered AFS securities, recognized at fair market value. FirstEnergy has no securities held for trading purposes.
The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT, nuclear fuel disposal and NUG trusts as of March 31, 2015 and December 31, 2014:
		March 31, 2015(1)												December 31, 2014(2)
		Cost Basis				Unrealized Gains				Fair Value				Cost Basis				Unrealized Gains			Fair Value
		(In millions)
Debt securities
FirstEnergy		$	1,767			$	43			$	1,810			$	1,724			$	27		$	1,751
FES		812				22				834				788				13			801
Equity securities
FirstEnergy		$	648			$	47			$	695			$	533			$	58		$	591
FES		442				27				469				329				31			360
(1)	Excludes short-term cash investments: FE Consolidated - $98 million; FES - $78 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 months ended March 31, 2015 and 2014 were as follows:
Three Months Ended
March 31, 2015		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and
																		Dividend Income
		(In millions)
FirstEnergy		$	371			$	60			$	(50	)		$	(7	)		$	25
FES		189				38				(28		)		(6		)		14
March 31, 2014		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and Dividend Income
		(In millions)
FirstEnergy		$	621			$	28			$	(16	)		$	(2	)		$	25
FES		423				19				(5		)		(2		)		15
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 March 31, 2015 and December 31, 2014:
		March 31, 2015												December 31, 2014
		Cost Basis				Unrealized Gains				Fair Value				Cost Basis				Unrealized Gains			Fair Value
		(In millions)
Debt Securities
FirstEnergy		$	13			$	4			$	17			$	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 $642 million as of March 31, 2015 and $626 million as of December 31, 2014, are excluded from the amounts reported above.
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations, excluding capital lease obligations and net unamortized premiums and discounts:
	March 31, 2015								December 31, 2014
	Carrying				Fair				Carrying				Fair
	Value				Value				Value				Value
	(In millions)
FirstEnergy	$	19,775			$	21,911			$	19,828			$	21,733
FES	3,080				3,215				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 March 31, 2015 and December 31, 2014.

Derivative_Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS
	FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility 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 would be 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 $9 million and $8 million as of March 31, 2015 and December 31, 2014, respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $2 million is expected to be amortized to income during the next twelve months associated with these non-active derivative instruments.
	FirstEnergy has used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $48 million and $50 million as of March 31, 2015 and December 31, 2014, respectively. Based on current estimates, approximately $9 million will be amortized to interest expense during the next twelve months associated with these non-active derivative instruments.
	Refer to Note 4, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the three months ended March 31, 2015 and 2014.
	As of March 31, 2015 and December 31, 2014, no commodity or interest rate derivatives were designated as cash flow hedges.
	Fair Value Hedges
	FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. As of March 31, 2015 and December 31, 2014, no fixed-for-floating interest rate swap agreements were outstanding.
	Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $29 million and $32 million as of March 31, 2015 and December 31, 2014, respectively. Based on current estimates, approximately $12 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $3 million during the three months ended March 31, 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 March 31, 2015, FirstEnergy’s net asset position under commodity derivative contracts was $16 million, which related to FES positions. Under these commodity derivative contracts, FES posted $71 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 March 31, 2015, an adverse change of 10% in commodity prices would increase net income by approximately $15 million during the next twelve months.
	NUGs
	As of March 31, 2015, FirstEnergy's net liability position under NUG contracts was $148 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 March 31, 2015, FirstEnergy's and FES' net asset position under FTRs was $2 million and $1 million, respectively, and FES posted $5 million of collateral. FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of an RTO that have load serving obligations and through the direct allocation of FTRs from the PJM RTO. The PJM RTO has a rule that allows directly allocated FTRs to be granted to LSEs in zones that have newly entered PJM. For the first two planning years, PJM permits the LSEs to request a direct allocation of FTRs in these new zones at no cost as opposed to receiving ARRs. The directly allocated FTRs differ from traditional FTRs in that the ownership of all or part of the FTRs may shift to another LSE if customers choose to shop with the other LSE.
	The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets and have not been designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price less the obligation due to the RTO, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FES and AE Supply are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s utilities are recorded as regulatory assets or liabilities. Directly allocated FTRs are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance.
	FirstEnergy records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets:
	Derivative Assets									Derivative Liabilities
		Fair Value									Fair Value
		March 31,				December 31,					March 31,			December 31,
		2015				2014					2015			2014
		(In millions)									(In millions)
	Current Assets - Derivatives									Current Liabilities - Derivatives
	Commodity Contracts	$	127			$	121			Commodity Contracts	$	(150	)	$	(154	)
	FTRs	6				38				FTRs	(4		)	(13		)
		133				159					(154		)	(167		)
										Noncurrent Liabilities - Adverse Power Contract Liability
	Deferred Charges and Other Assets - Other									NUGs(1)	(150		)	(153		)
	Commodity Contracts	66				51				Noncurrent Liabilities - Other
	FTRs	1				1				Commodity Contracts	(27		)	(13		)
	NUGs(1)	2				2				FTRs	(1		)	(1		)
		69				54					(178		)	(167		)
	Derivative Assets	$	202			$	213			Derivative Liabilities	$	(332	)	$	(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
	March 31, 2015		Fair Value				Derivative Instruments				Cash Collateral (Received)/Pledged			Net Fair Value
			(In millions)
	Derivative Assets
	Commodity contracts		$	193			$	(156	)		$	—		$	37
	FTRs		7				(5		)		—			2
	NUG contracts		2				—				—			2
			$	202			$	(161	)		$	—		$	41
	Derivative Liabilities
	Commodity contracts		$	(177	)		$	156			$	16		$	(5	)
	FTRs		(5		)		5				—			—
	NUG contracts		(150		)		—				—			(150		)
			$	(332	)		$	161			$	16		$	(155	)
							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 March 31, 2015:
	Purchases			Sales			Net			Units
	(In millions)
Power Contracts	22			42			(20	)		MWH
FTRs	22			—			22			MWH
NUGs	5			—			5			MWH
Natural Gas	32			—			32			mmBTU
The effect of active derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income during the three months ended March 31, 2015 and 2014, are summarized in the following tables:
	Three Months Ended March 31,
	Commodity Contracts				FTRs				Total
	(In millions)
2015
Unrealized Gain (Loss) Recognized in:
Other Operating Expense (1)	$	11			$	(13	)		$	(2	)
Realized Gain (Loss) Reclassified to:
Revenues (2)	$	(1	)		$	37			$	36
Purchased Power Expense (3)	(3		)		—				(3		)
Other Operating Expense (4)	—				(13		)		(13		)
Fuel Expense	(16		)		—				(16		)
(1) Includes $11 million for commodity contracts and ($12) million for FTRs associated with FES.
(2) Represents losses on structured financial contracts. Includes ($1) million for commodity contracts and $36 million for FTRs associated with FES.
(3) Realized losses on financially settled wholesale sales contracts of $22 million were netted in purchased power. Includes ($3) million for commodity contracts associated with FES.
(4) Includes ($13) million for FTRs associated with FES.
	Three Months Ended March 31,
	Commodity Contracts				FTRs				Total
	(In millions)
2014
Unrealized Gain Recognized in:
Other Operating Expense (5)	$	12			$	5			$	17
Realized Gain (Loss) Reclassified to:
Revenues (6)	$	(13	)		$	52			$	39
Purchased Power Expense (7)	436				—				436
Other Operating Expense (8)	—				(7		)		(7		)
Fuel Expense	9				—				9
(5) Includes $12 million for commodity contracts and $5 million for FTRs associated with FES.
(6) Represents losses on structured financial contracts. Includes ($13) million for commodity contracts and $51 million for FTRs associated with FES.
(7) Realized losses on financially settled wholesale sales contracts of $321 million resulting from higher market prices were netted in purchased power. Includes $436 million for commodity contracts associated with FES.
(8) Includes ($7) 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 months ended March 31, 2015 and 2014. Changes in the value of these instruments are deferred for future recovery from (or credit to) customers:
		Three Months Ended March 31,
Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				Regulated FTRs				Total
		(In millions)
Outstanding net asset (liability) as of January 1, 2015		$	(151	)		$	11			$	(140	)
Unrealized gain (loss)		(8		)		1				(7		)
Settlements		11				(11		)		—
Outstanding net asset (liability) as of March 31, 2015		$	(148	)		$	1			$	(147	)
Outstanding net liability as of January 1, 2014		$	(202	)		$	—			$	(202	)
Unrealized gain		27				4				31
Settlements		(10		)		(1		)		(11		)
Outstanding net asset (liability) as of March 31, 2014		$	(185	)		$	3			$	(182	)

Regulatory_Matters

Regulatory Matters	3 Months Ended
	Mar. 31, 2015
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS
	STATE REGULATION
	Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.
	As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates. In addition, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility.
	MARYLAND
	PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS.
	The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption by 10% and reduce electricity demand by 15%, in each case by 2015, and requiring each electric utility to file a plan every three years. PE's current plan, covering the three-year period 2015-2017, was approved by the MDPSC on December 23, 2014. The projected costs of the 2015-2017 plan are approximately $64 million for that three year period. 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 also recommended the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff. In addition, the Staff proposed that the utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC 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 has issued two orders directing the Staff to file an analysis and recommendations, by May 19, 2015, with respect to the proposed 2016-2019 SAIDI and SAIFI standards and any related rule changes which Staff recommended. The orders further set an initial hearing on Staff’s analysis and recommendations for June 4-5, 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.
	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 March 26, 2015, the NJBPU entered a final Order in JCP&L's base rate case proceeding that was initiated in November 2012, directing an annual revenue reduction of approximately $115 million, including recovery of 2011 storm costs. The NJBPU largely approved the ALJ's initial decision with the following adjustments: (i) a decrease in annual base rate revenues of $5 million associated with the NJBPU's recently modified CTA policy that was approved in the Generic CTA proceeding; and (ii) lower carrying charges on the unamortized balance of 2011 storm costs, which resulted in a decrease in annual base rate revenues of approximately $2 million. On the same day, the NJBPU entered a final Order in the generic proceeding established to review JCP&L's major storm events of 2011 and 2012 and approved recovery of 2012 storm costs of $580 million, which resulted in an increase in annual revenues of approximately $81 million, including recovery of certain amounts through base rates and a separate rider to recover the deferred operation and maintenance costs over six years, subject to a carrying charge of 2.52%. JCP&L is also required to file another base rate case no later than April 1, 2017. The overall result of these final Orders is a reduction in JCP&L annual base rate revenues of approximately $34 million, effective April 1, 2015. The NJBPU also directed JCP&L to complete certain studies, including a study related to reliability.
	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. The evidentiary hearing on the ESP IV is now scheduled to commence on June 15, 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. 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, 2015, and provide for the competitive procurement of generation supply for customers that do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. The default service supply is currently provided by wholesale suppliers through a mix of long-term and short-term contracts procured through descending clock auctions, competitive requests for proposals and spot market purchases. On July 24, 2014, the PPUC unanimously approved a settlement of the Pennsylvania Companies' DSPs for the period of June 1, 2015 through May 31, 2017, that provides for quarterly descending clock auctions to procure 3, 12 and 24-month energy contracts, as well as one RFP seeking 2-year contracts to secure 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. The PPUC filed its brief in opposition to the petition, and FirstEnergy’s reply is due on May 5, 2015. Thereafter the court will decide whether to grant the petition and take the case for adjudication on the merits.
	Pursuant to Pennsylvania's EE&C legislation (Act 129 of 2008), the PPUC was charged with reviewing the cost effectiveness of energy efficiency and peak demand reduction programs. The PPUC found the energy efficiency programs to be cost effective and directed all of the electric utilities in Pennsylvania to submit by November 15, 2012, a Phase II EE&C Plan that would be in effect for the period June 1, 2013 through May 31, 2016. The PPUC 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 for the period 2013-2016. Total costs of these plans are expected to be approximately $234 million and recoverable through the Pennsylvania Companies' reconcilable EE&C riders. On March 11, 2015, the PPUC issued a Tentative Order for comment by interested parties proposing requirements and procedures for a Phase III EE&C Plan, including energy efficiency and peak demand programs. On April 27, 2015, the Pennsylvania Companies filed comments addressing various issues included in the Phase III Tentative Order.
	On August 4, 2014, the Pennsylvania Companies each filed tariffs with the PPUC proposing general rate increases associated with their distribution operations. The filings 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 ALJ's 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 will be 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 revised implementation plans regarding certain of the operational topics addressed in the report, including addressing certain reliability matters. The Pennsylvania Companies are developing implementation plans in accordance with the order. The cost of compliance cannot be predicted at this time.
	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. FERC accepted the PJM/MISO and PJM/SERTP filings, subject to refund and further compliance requirements. The PJM/NYISO cross-border project cost allocation filing remains pending before FERC.
	In series of orders in the 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 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. Initial comments on the MISO/PJM MVP issue were filed 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 are due June 22, 2015.
	In addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM approved before ATSI joined PJM could be charged to transmission customers in the ATSI zone. The amount to be paid, and the question of derived benefits, is pending before FERC as a result of the Seventh Circuit's June 25, 2014 order described above under PJM Transmission Rates.
	The outcome of those proceedings that address the remaining open issues related to ATSI's move into PJM cannot be predicted at this time.
	2014 ATSI Formula Rate Filing
	On October 31, 2014, ATSI filed a proposal with FERC to change the structure of its formula rate. The proposed change requested to move from an “historical looking” approach, where transmission rates reflect actual costs for the prior year, to a “forward looking” approach, where transmission rates would be based on the estimated costs for the coming year, with an annual true up. Several parties protested ATSI's filing. On December 31, 2014, FERC issued an order accepting ATSI's filing effective January 1, 2015, as requested, subject to refund and the outcome of hearing and settlement proceedings. Settlement discussions under a FERC-appointed settlement judge are ongoing. FERC also initiated an inquiry pursuant to Section 206 of the FPA into ATSI's ROE and certain other matters, with a refund effective date of January 12, 2015, for any refund resulting from the inquiry.
	California Claims Matters
In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the Ninth Circuit in several pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit had previously remanded one of those proceedings to FERC, which dismissed the claims of the California Parties in May 2011. The California Parties appealed FERC's decision back to the Ninth Circuit. AE Supply joined with other intervenors in the case and filed a brief in support of FERC's dismissal of the case. On April 29, 2015, the Ninth Circuit issued a decision remanding the case to FERC for further proceedings.
In another proceeding, in June 2009, the California Attorney General, on behalf of certain California parties, filed a complaint with FERC against various sellers, including AE Supply, again seeking refunds for transactions in the California energy markets during 2000 and 2001. The above-noted transactions with CDWR are the basis for including AE Supply in this complaint. AE Supply filed a motion to dismiss, which FERC granted. The California Attorney General appealed FERC's dismissal of its complaint to the Ninth Circuit, which has consolidated the case with other pending appeals related to California refund claims, and stayed the proceedings pending further order.
FirstEnergy cannot predict the outcome of either of the above matters or estimate the possible loss or range of loss.
PATH Transmission Project
On August 24, 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia through Virginia and into Maryland which PJM had previously suspended in February 2011. As a result of PJM canceling the project, approximately $62 million and approximately $59 million in costs incurred by PATH-Allegheny and PATH-WV (an equity method investment for FE), respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery. PATH-Allegheny and PATH-WV requested authorization from FERC to recover the costs with a proposed ROE of 10.9% (10.4% base plus 0.5% for RTO membership) from PJM customers over five years. FERC issued an order denying the 0.5% ROE adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to settlement proceedings and hearing if the parties do not agree to a settlement. On March 24, 2014, the FERC Chief ALJ terminated settlement proceedings and appointed an ALJ to preside over the hearing phase of the case, including discovery and additional pleadings leading up to hearing, which subsequently included the parties addressing the application of FERC's Opinion No. 531, discussed below, to the PATH proceeding. The hearing concluded on April 22, 2015, and the parties are preparing post-hearing briefs.
FERC Opinion No. 531
On June 19, 2014, FERC issued Opinion No. 531, in which FERC revised its approach for calculating the discounted cash flow element of FERC’s ROE methodology, and announced a qualitative adjustment to the ROE methodology results. Under the old methodology, FERC used a five-year forecast for the dividend growth variable, whereas going forward the growth variable will consist of two parts: (a) a five-year forecast for dividend growth (2/3 weight); and (b) a long-term dividend growth forecast based on a forecast for the U.S. economy (1/3 weight). Regarding the qualitative adjustment, FERC formerly pegged ROE at the mid-point of the “zone of reasonableness” that came out of the ROE formula, whereas going forward, FERC may rely on record evidence to make qualitative adjustments to the outcome of the ROE methodology in order to reach a level sufficient to attract future investment. On October 16, 2014, FERC issued its Opinion No. 531-A, applying the revised ROE methodology to certain ISO New England Inc. transmission owners. On March 3, 2015, FERC issued Opinion No. 531-B affirming its prior rulings. FirstEnergy is evaluating the potential impact of Opinion No. 531 on the authorized ROE of our FERC-regulated transmission utilities and the cost-of-service wholesale power generation transactions of MP.
MISO Capacity Portability
On June 11, 2012, in response to certain arguments advanced by MISO, FERC issued a Notice of Request for Comments regarding whether existing rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM. FirstEnergy and other parties have submitted filings arguing that MISO's concerns largely are without foundation and suggested that FERC address the remaining concerns in the existing stakeholder process that is described in the PJM/MISO Joint Operating Agreement. FERC has not mandated a solution, and the RTOs and affected parties are working to address the MISO's proposal in stakeholder proceedings. In January 2015, the RTOs and affected parties indicated to FERC that discussions on the various issues are continuing. In a February 24, 2015 order, FERC directed PJM and MISO to provide additional information on their various joint issues surrounding the PJM/MISO seam, including capacity portability, to assist the FERC's understanding of the issues and what, if any, additional steps it should take to improve the efficiency of operations at the PJM/MISO seam. Changes to the criteria and qualifications for participation in the PJM RPM capacity auctions could have a significant impact on the outcome of those auctions, including a negative impact on the prices at which those auctions would clear.
FTR Underfunding Complaint
In PJM, FTRs are a mechanism to hedge congestion and operate as a financial replacement for physical firm transmission service. FTRs are financially-settled instruments that entitle the holder to a stream of revenues based on the hourly congestion price differences across a specific transmission path in the PJM Day-ahead Energy Market. FE also performs bilateral transactions for the purpose of hedging the price differences between the location of supply resources and retail load obligations. Due to certain language in the PJM Tariff, the funds that are set aside to pay FTRs can be diverted to other uses, which may result in “underfunding” of FTR payments. FES and AE Supply continue to evaluate proposals to address issues with FTR allocation and funding.
On February 15, 2013, FES and AE Supply filed a renewed complaint with FERC for the purpose of changing the PJM Tariff to eliminate FTR underfunding. On June 5, 2013, FERC issued its order denying the new complaint. Requests for rehearing, and all subsequent filings in the docket, are pending before FERC. The PJM stakeholders continue to discuss FTR underfunding.
A recent and related issue is the effect that certain financial trades have on congestion. On August 29, 2014, FERC instituted an investigation to address the question of whether the current rules regarding “Up-to Congestion” transactions are just and reasonable. FESC, on behalf of FES and the Utilities, filed comments supporting the investigation, arguing that PJM Tariff changes would decrease the incidence of Up-to Congestion transactions, and funding for FTRs likely would increase. FERC convened a technical conference on January 7, 2015 to discuss application of certain FTR-related rules to Up-to Congestion and virtual transactions and whether PJM’s current uplift allocation for Up-to Congestion and virtual transactions is just and reasonable. FERC action following the technical conference is pending.
PJM Market Reform: 2014 PJM RPM Tariff Amendments
In late 2013 and early 2014, PJM submitted a series of amendments to the PJM Tariff to ensure that resources that clear in the RPM auctions are available as physical resources in the delivery year and that the rules implement comparable obligations for different types of resources. PJM's filings can be grouped into four categories: (i) DR; (ii) imports; (iii) modeling of transmission upgrades in calculating geographic clearing prices; and (iv) arbitrage/capacity replacement. In each of the relevant dockets, FirstEnergy and other parties submitted comments largely supporting PJM's proposed amendments. FERC largely approved the PJM Tariff amendments as proposed by PJM regarding DR, imports, and transmission upgrade modeling. Compliance filings pursuant to and requests for rehearing of certain of these orders are pending before FERC. However, FERC rejected the arbitrage/capacity replacement amendments, directing instead that a technical conference be convened to further examine the issues. The technical conference has yet to be scheduled, but the issue of arbitrage has been raised in other ongoing PJM RPM FERC dockets.
PJM Market Reform: PJM Capacity Performance Proposal and 2015/2016 Reliability Filings
On December 12, 2014, PJM submitted two filings for FERC authorization to implement its proposed “Capacity Performance” reform of the RPM capacity market. PJM proposed to revise the PJM Tariff to, among other things: (i) adopt a modified version of the FERC-approved ISO New England Inc. capacity performance payment structure; (ii) allow no excuses for nonperformance except in certain defined instances; (iii) maintain DR as a supply-side resource; and (iv) impose a Capacity Performance Resource must-offer requirement (units that can perform as a Capacity Performance Resource must offer into the capacity market, except certain defined resources, including DR). PJM also proposed, among other things, to revise the PJM Operating Agreement to provide limits in energy market offers based on specific physical characteristics and to ensure that capacity resources are available when the PJM Region needs them to perform. PJM requested an effective date of April 1, 2015 for these proposed reforms. Numerous parties filed comments on and protests to PJM’s Capacity Performance filings. FESC, on behalf of its affected affiliates, and, as part of a coalition of certain other PJM utilities, filed comments and protests on the proposed reforms. On March 31, 2015, FERC Staff issued a deficiency letter asking for more information and data related to PJM’s proposal. PJM submitted its response to the deficiency letter on April 10, 2015 outlining further changes to the Capacity Performance proposal, and asked for speedy FERC resolution of the proposed tariff amendments. FESC, on behalf of its affected affiliates, and, as part of a coalition, filed responsive comments on April 24, 2015.
On April 7, 2015, PJM filed a request for waiver of the PJM Tariff to allow PJM to delay the 2015 BRA from May 2015 to no later than the week of August 10-14, 2015 to allow FERC to rule on PJM’s Capacity Performance proposal. FERC granted this waiver on April 24, 2015.
FirstEnergy and other PJM market entities also are addressing PJM’s capacity market concerns in other FERC proceedings. On November 20, 2014, FERC issued an order directing each ISO/RTO to file a report with FERC outlining each region’s efforts to ensure fuel security. PJM filed its report on February 18, 2015, advising FERC that PJM’s Capacity Performance proposal will address fuel assurance issues. On March 20, 2015, FESC, on behalf of its affected affiliates and as part of a coalition, filed responsive comments demonstrating that significant improvements were needed for PJM’s Capacity Performance proposal to address fuel assurance issues. The comments are before FERC for review.
PJM Market Reform: PJM RPM Auctions - Calculation of Unit-Specific Offer Caps
The PJM Tariff describes the rules for calculating the “offer cap” for each unit that offers into the RPM auctions. FES disagreed with the PJM Market Monitor's approach for calculating the offer caps and in 2014, FES asked FERC to determine which PJM Tariff interpretation, FES' or the PJM Market Monitor's, was correct. On August 25, 2014, FERC issued a declaratory order agreeing with the FES interpretation of the PJM Tariff language. FERC went on, however, to initiate a new proceeding to examine whether the existing PJM Tariff language is just and reasonable. PJM filed its brief explaining why the existing PJM Tariff language is just and reasonable. Other parties, including FES, submitted responsive briefs. The briefs and related pleadings are pending before FERC.
PJM Market Reform: FERC Order No. 745 - DR
On May 23, 2014, a divided three-judge panel of the U.S. Court of Appeals for the D.C. Circuit issued an opinion vacating FERC Order No. 745, which required that, under certain parameters, DR participating in organized wholesale energy markets be compensated at LMP. The majority concluded that DR is a retail service, and therefore falls under state, and not federal, jurisdiction, and that FERC, therefore, lacks jurisdiction to regulate DR. The majority also found that even if FERC had jurisdiction over DR, Order No. 745 would be arbitrary and capricious because, under its requirements, DR was inappropriately receiving a double payment (LMP plus the savings of foregone energy purchases). Petitions for certiorari and responses thereto are currently pending before the United States Supreme Court. The U.S. Court of Appeals for the D.C. Circuit withheld issuance of its mandate pending the United States Supreme Court's disposition of those petitions.
On May 23, 2014, FESC, on behalf of its affiliates with market-based rate authorization, filed a complaint asking FERC to issue an order requiring the removal of all portions of the PJM Tariff allowing or requiring DR to be included in the PJM capacity market, with a refund effective date of May 23, 2014. FESC also requested that the results of the May 2014 PJM BRA be considered void and legally invalid to the extent that DR cleared that auction because the participation of DR in that auction was unlawful in light of the May 23, 2014 U.S. Court of Appeals for the D.C. Circuit decision discussed above. FESC, on behalf of FES, subsequently filed an amended complaint renewing its request that DR be removed from the May 2014 BRA. Specifically, FESC requested that FERC direct PJM to recalculate the results of the May 2014 BRA by: (i) removing DR from the PJM capacity supply pool; (ii) leaving the offers of actual capacity suppliers unchanged; and then (iii) determining which capacity suppliers clear the auction on the basis of the offers they submitted consistent with the existing PJM Tariff once the unlawful DR resources have been removed. The complaint remains pending before FERC. The timing of FERC action and the outcome of this proceeding cannot be predicted at this time.
On January 14, 2015, PJM filed proposed amendments to the PJM Tariff for the purpose of addressing continued DR participation in the PJM capacity markets. PJM asserted that the decision of the U.S. Court of Appeals for the D.C. Circuit discussed above, which is pending for review before the United States Supreme Court, created uncertainty. PJM proposed that if the United States Supreme Court denies the petitions for certiorari before the May 2015 BRA, PJM would move DR to the load side for purposes of participating in the auction. FESC, on behalf of its affected affiliates and as part of the coalition, protested PJM's proposed PJM Tariff amendments. On March 31, 2015, FERC issued an order rejecting PJM's proposed DR changes as premature.
PJM Market Reform: PJM 2014 Triennial RPM Review
The PJM Tariff obligates PJM to perform a thorough review of its RPM program every three years. On September 25, 2014, PJM filed proposed changes to the PJM Tariff as part of the latest review cycle. Among other adjustments, the filing included: (i) shifting the VRR curve one percentage point to the right, which would increase the amount of capacity supply that is procured in the RPM auctions and the clearing price; and (ii) a change to the index used for calculating the generation plant construction costs of the Net CONE formula for the future years between triennial reviews. On November 28, 2014, FERC accepted the PJM Tariff amendments as proposed, subject to a minor compliance requirement. PJM subsequently submitted the required compliance filing. On December 23, 2014, a coalition including FESC, on behalf of its affected affiliates, requested rehearing of FERC's order. PJM's compliance filing, and the coalition's and others' requests for rehearing, remain pending before FERC.

Commitments_Guarantees_and_Con

Commitments, Guarantees and Contingencies	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS, GUARANTEES AND CONTINGENCIES	COMMITMENTS, GUARANTEES AND CONTINGENCIES
	GUARANTEES AND OTHER ASSURANCES
	FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party.
	As of March 31, 2015, outstanding guarantees and other assurances aggregated approximately $4.0 billion, consisting of parental guarantees ($621 million), subsidiaries' guarantees ($2,338 million), other guarantees ($300 million) and other assurances ($729 million).
	Of this amount, substantially all relates to guarantees of wholly-owned consolidated entities. FES' debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each of FG and NG. Accordingly, present and future holders of indebtedness of FES, FG, and NG would have claims against each of FES, FG and NG, regardless of whether their primary obligor is FES, FG or NG.
	COLLATERAL AND CONTINGENT-RELATED FEATURES
	In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel, and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements.
	Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on FES' power portfolio exposures as of March 31, 2015, FES has posted collateral of $279 million and AE Supply has posted no collateral. The Regulated Distribution segment has posted collateral of $3 million.
	These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required.
	Subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of FE or its subsidiaries. The following table discloses the additional credit contingent contractual obligations that may be required under certain events as of March 31, 2015:
	Collateral Provisions	FES		AE Supply		Utilities		Total
		(In millions)
	Split Rating (One rating agency's rating below investment grade)	$	427	$	6	$	43	$	476
	BB+/Ba1 Credit Ratings	$	465	$	6	$	43	$	514
	Full impact of credit contingent contractual obligations	$	583	$	50	$	78	$	711
	Excluded from the preceding table are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment. As of March 31, 2015, neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES would be required to post $17 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. As of March 31, 2015, the carrying amount of FE's guarantee obligation was $54 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 SO2 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 SO2 emissions in two phases (2015 and 2017), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. 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. MATS was challenged in the U.S. Court of Appeals for the D.C. Circuit by various entities, including FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers, such as Bay Shore Unit 1. On April 15, 2014, MATS was upheld by the U.S. Court of Appeals for the D.C. Circuit, however, the Court refused to decide FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers due to a January 2013 petition for reconsideration still pending but not addressed by EPA. On November 25, 2014, the United States Supreme Court agreed to review MATS, specifically, to determine if EPA should have evaluated the cost of MATS prior to regulating. Depending on the outcome of the United States Supreme Court review 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 $145 million has been spent through March 31, 2015 ($58 million at CES and $87 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 or unresolved aspects of the agreements 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 has commenced litigation alleging FirstEnergy and AE Supply do not have sufficient justification to terminate the agreement. 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 believes the claims are without merit and intends to vigorously defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
	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 CO2 emissions will be reduced 25% below 2005 levels by 2015, exceeding the President’s Climate Action Plan goals both in terms of timing and reduction levels.
	850 mmBTU/hr), and 1,100 lbs. CO2/MWH for other natural gas fired units (≤ 850 mmBTU/hr), and 1,100 lbs. CO2/MWH for fossil fuel fired units which would require partial carbon capture and storage. EPA proposed regulations in June 2014, to reduce CO2 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 CO2 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 CO2 emission limits on modified and reconstructed fossil fuel fired electric generating units. On June 23, 2014, the United States Supreme Court decided that CO2 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 April 16, 2015, the U.S. Court of Appeals for the D.C. Circuit held oral argument to consider challenges to prevent EPA from regulating CO2 emissions from existing fossil fuel fired electric generating units. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future cost of compliance may be substantial." id="sjs-B68">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. CO2/MWH for large natural gas fired units (> 850 mmBTU/hr), and 1,100 lbs. CO2/MWH for other natural gas fired units (≤ 850 mmBTU/hr), and 1,100 lbs. CO2/MWH for fossil fuel fired units which would require partial carbon capture and storage. EPA proposed regulations in June 2014, to reduce CO2 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 CO2 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 CO2 emission limits on modified and reconstructed fossil fuel fired electric generating units. On June 23, 2014, the United States Supreme Court decided that CO2 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 April 16, 2015, the U.S. Court of Appeals for the D.C. Circuit held oral argument to consider challenges to prevent EPA from regulating CO2 emissions from existing fossil fuel fired electric generating units. Depending on the outcome of 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 CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
	Clean Water Act
	Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations.
	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 March 14, 2015, an application for waste permit renewal and reissuance for the Hatfield's Ferry CCR disposal facility, another potential alternative for Bruce Mansfield plant CCR disposal, was published in the Pennsylvania Bulletin commencing a 60-day comment period.
	On October 10, 2013, approximately 61 individuals filed a complaint against FG in the United States District Court for the Northern District of West Virginia seeking damages for alleged property damage, bodily injury and emotional distress related to the LBR CCR Impoundment. The complaints state claims for private nuisance, negligence, negligence per se, reckless conduct and trespass related to alleged groundwater contamination and odors emanating from the Impoundment. FG believes the claims are without merit and intends to vigorously defend itself against the allegations made in the complaints, but, at this time, is unable to predict the outcome of the above matter or estimate the possible loss or range of loss.
	FirstEnergy 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 March 31, 2015 based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $125 million have been accrued through March 31, 2015. Included in the total are accrued liabilities of approximately $85 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 March 31, 2015, FirstEnergy had approximately $2.4 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. The values of FirstEnergy's 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. FES maintains a $155 million FES parental guaranty relating to a shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry. FE and FES have also entered into a total of $23 million in parental guaranties in support of the decommissioning of the spent fuel storage facilities located at the nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guaranties, as appropriate.
	In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. 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 September 29, 2014, the Intervenors filed a petition, accompanied by a request to admit a new contention, to suspend the final licensing decision on Davis-Besse license renewal. These filings argued that the NRC’s Continued Storage Rule failed to make necessary safety findings regarding the technical feasibility of spent fuel disposal and the adequacy of future repository capacity required by the Atomic Energy Act. All other contentions had previously been denied. On February 26, 2015, the NRC Commissioners denied both the suspension request and the request to file new contentions on the Continued Storage Rule. 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 April 22, 2015, one of the Intervenors filed requests to admit a contention on the NRC’s Continued Storage Rule and a motion to reopen the record in the Davis-Besse license renewal proceeding.
	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. On September 2, 2014, the Intervenors in the Davis-Besse license renewal proceeding requested that the ASLB introduce issues based on FENOC's plans to manage the subsurface laminar cracking in the Davis-Besse shield building. On January 15, 2015, the ASLB denied this request. 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 have been notified of the settlement.
	Other Legal Matters
	There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The loss or range of loss in these matters is not expected to be material to FirstEnergy or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 9, Regulatory Matters of the Combined Notes to Consolidated Financial Statements.
	FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Supplemental_Guarantor_Informa

Supplemental Guarantor Information	3 Months Ended
	Mar. 31, 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 months ended March 31, 2015 and 2014, Condensed Consolidating Balance Sheets as of March 31, 2015 and December 31, 2014, and Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 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 March 31, 2015	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	REVENUES	$	1,332		$	493		$	507		$	(955	)	$	1,377
	OPERATING EXPENSES:
	Fuel	—			180			50			—			230
	Purchased power from affiliates	957			—			68			(955		)	70
	Purchased power from non-affiliates	543			—			—			—			543
	Other operating expenses	180			67			154			12			413
	Provision for depreciation	3			30			48			(1		)	80
	General taxes	15			8			6			—			29
	Total operating expenses	1,698			285			326			(944		)	1,365
	OPERATING INCOME (LOSS)	(366		)	208			181			(11		)	12
	OTHER INCOME (EXPENSE):
	Loss on debt redemptions	—			—			—			—			—
	Investment income, including net income from equity investees	241			3			14			(245		)	13
	Interest expense — affiliates	(6		)	(2		)	(1		)	7			(2		)
	Interest expense — other	(13		)	(26		)	(13		)	15			(37		)
	Capitalized interest	—			1			8			—			9
	Total other income (expense)	222			(24		)	8			(223		)	(17		)
	INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS)	(144		)	184			189			(234		)	(5		)
	INCOME TAXES (BENEFITS)	(141		)	67			70			2			(2		)
	NET INCOME (LOSS)	$	(3	)	$	117		$	119		$	(236	)	$	(3	)
	STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
	NET INCOME (LOSS)	$	(3	)	$	117		$	119		$	(236	)	$	(3	)
	OTHER COMPREHENSIVE INCOME (LOSS):
	Pension and OPEB prior service costs	(4		)	(4		)	3			1			(4		)
	Amortized gain on derivative hedges	(1		)	—			—			—			(1		)
	Change in unrealized gain on available-for-sale securities	3			—			—			—			3
	Other comprehensive income (loss)	(2		)	(4		)	3			1			(2		)
	Income taxes (benefits) on other comprehensive loss	(1		)	(1		)	1			—			(1		)
	Other comprehensive income (loss), net of tax	(1		)	(3		)	2			1			(1		)
	COMPREHENSIVE INCOME (LOSS)	$	(4	)	$	114		$	121		$	(235	)	$	(4	)
	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
	(Unaudited)
	For the Three Months Ended March 31, 2014	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	STATEMENTS OF INCOME
	REVENUES	$	1,797		$	315		$	362		$	(645	)	$	1,829
	OPERATING EXPENSES:
	Fuel	—			272			47			—			319
	Purchased power from affiliates	645			—			64			(645		)	64
	Purchased power from non-affiliates	1,025			4			—			—			1,029
	Other operating expenses	228			62			150			12			452
	Provision for depreciation	2			29			43			—			74
	General taxes	21			11			7			—			39
	Total operating expenses	1,921			378			311			(633		)	1,977
	OPERATING INCOME (LOSS)	(124		)	(63		)	51			(12		)	(148		)
	OTHER INCOME (EXPENSE):
	Loss on debt redemption	(3		)	(1		)	(1		)	—			(5		)
	Investment income, including net income from equity investees	104			1			21			(106		)	20
	Interest expense — affiliates	(3		)	(1		)	(1		)	3			(2		)
	Interest expense — other	(14		)	(24		)	(13		)	15			(36		)
	Capitalized interest	—			1			11			—			12
	Total other income (expense)	84			(24		)	17			(88		)	(11		)
	INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	(40		)	(87		)	68			(100		)	(159		)
	INCOME TAXES (BENEFITS)	(52		)	(31		)	26			1			(56		)
	INCOME (LOSS) FROM CONTINUING OPERATIONS	12			(56		)	42			(101		)	(103		)
Discontinued operations (net of income taxes of $70) (Note 13)	—			116			—			—			116
NET INCOME	$	12		$	60		$	42		$	(101	)	$	13
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	12		$	60		$	42		$	(101	)	$	13
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(5		)	(4		)	—			4			(5		)
Amortized gain on derivative hedges	(2		)	—			—			—			(2		)
Change in unrealized gain on available for sale securities	19			—			19			(19		)	19
Other comprehensive income (loss)	12			(4		)	19			(15		)	12
Income taxes (benefits) on other comprehensive income (loss)	4			(2		)	7			(5		)	4
Other comprehensive income (loss), net of tax	8			(2		)	12			(10		)	8
COMPREHENSIVE INCOME	$	20		$	58		$	54		$	(111	)	$	21
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
As of March 31, 2015	FES			FG			NG			Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—		$	2		$	—		$	—		$	2
Receivables-
Customers	351			—			—			—			351
Affiliated companies	507			357			313			(636		)	541
Other	71			2			79			—			152
Notes receivable from affiliated companies	333			1,017			634			(1,940		)	44
Materials and supplies	46			181			220			—			447
Derivatives	132			—			—			—			132
Collateral	217			—			—			—			217
Prepayments and other	83			34			—			—			117
	1,740			1,593			1,246			(2,576		)	2,003
PROPERTY, PLANT AND EQUIPMENT:
In service	134			6,296			7,659			(383		)	13,706
Less — Accumulated provision for depreciation	39			2,085			3,399			(192		)	5,331
	95			4,211			4,260			(191		)	8,375
Construction work in progress	3			162			892			—			1,057
	98			4,373			5,152			(191		)	9,432
INVESTMENTS:
Nuclear plant decommissioning trusts	—			—			1,381			—			1,381
Investment in affiliated companies	6,847			—			—			(6,847		)	—
Other	—			10			—			—			10
	6,847			10			1,381			(6,847		)	1,391
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	344			7			—			(351		)	—
Customer intangibles	74			—			—			—			74
Goodwill	23			—			—			—			23
Property taxes	—			11			20			—			31
Unamortized sale and leaseback costs	—			—			—			248			248
Derivatives	67			—			—			—			67
Other	31			275			6			(204		)	108
	539			293			26			(307		)	551
	$	9,224		$	6,269		$	7,805		$	(9,921	)	$	13,377
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	—		$	166		$	348		$	(24	)	$	490
Short-term borrowings-
Affiliated companies	1,624			316			—			(1,940		)	—
Other	275			9			—			—			284
Accounts payable-
Affiliated companies	652			180			249			(652		)	429
Other	84			72			—			—			156
Accrued taxes	5			43			92			(55		)	85
Derivatives	154			—			—			—			154
Other	44			63			17			82			206
	2,838			849			706			(2,589		)	1,804
CAPITALIZATION:
Total equity	5,581			2,677			4,135			(6,812		)	5,581
Long-term debt and other long-term obligations	695			2,212			859			(1,161		)	2,605
	6,276			4,889			4,994			(7,973		)	8,186
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—			—			—			816			816
Accumulated deferred income taxes	13			—			710			(175		)	548
Asset retirement obligations	—			190			648			—			838
Retirement benefits	36			291			—			—			327
Derivatives	28			—			—			—			28
Other	33			50			747			—			830
	110			531			2,105			641			3,387
	$	9,224		$	6,269		$	7,805		$	(9,921	)	$	13,377
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 Three Months Ended March 31, 2015	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(662	)	$	222		$	545		$	—		$	105
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	674			—			—			(524		)	150
Redemptions and Repayments-
Long-term debt	(17		)	—			—			—			(17		)
Short-term borrowings, net	—			(5		)	(28		)	33			—
Other	—			(2		)	—			—			(2		)
Net cash provided from (used for) financing activities	657			(7		)	(28		)	(491		)	131
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1		)	(36		)	(82		)	—			(119		)
Nuclear fuel	—			—			(60		)	—			(60		)
Sales of investment securities held in trusts	—			—			189			—			189
Purchases of investment securities held in trusts	—			—			(202		)	—			(202		)
Loans to affiliated companies, net	6			(179		)	(362		)	491			(44		)
Net cash provided from (used for) investing activities	5			(215		)	(517		)	491			(236		)
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 Three Months Ended March 31, 2014	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(450	)	$	87		$	51		$	—		$	(312	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			235			182			—			417
Short-term borrowings, net	209			72			—			(161		)	120
Equity contribution from parent	500			—			—			—			500
Redemptions and Repayments-
Long-term debt	—			(248		)	(197		)	—			(445		)
Short-term borrowings, net	—			—			(151		)	151			—
Other	(1		)	(2		)	(1		)	—			(4		)
Net cash provided from (used for) financing activities	708			57			(167		)	(10		)	588
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2		)	(28		)	(268		)	—			(298		)
Nuclear fuel	—			—			(55		)	—			(55		)
Proceeds from asset sales	—			307			—			—			307
Sales of investment securities held in trusts	—			—			423			—			423
Purchases of investment securities held in trusts	—			—			(438		)	—			(438		)
Loans to affiliated companies, net	(254		)	(425		)	454			10			(215		)
Other	(2		)	2			—			—			—
Net cash provided from (used for) investing activities	(258		)	(144		)	116			10			(276		)
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	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION
	FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission, and CES.
	Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does not have separate reportable operating segments.
	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. As part of this, the CES segment eliminated future selling efforts in certain sales channels, such as Mass Market, medium commercial-industrial and select large commercial-industrial (Direct), to focus on a selective mix of retail sales channels, wholesale sales that hedge generation more effectively, and maintain a small open position to take advantage of market upside opportunities resulting from volatility such as that experienced in the first quarter of 2014. Beginning in 2015, CES will target approximately 65 to 75 million MWHs in annual contract sales with a projected target portfolio mix of approximately 10 to 15 million MWHs in Governmental Aggregation sales, 0 to 10 million MWHs of POLR sales, 0 to 20 million MWHs in large commercial and industrial sales (Direct),10 to 20 million MWHs in block wholesale sales, including Structured sales, and 10 to 20 million MWHs of spot wholesale sales. As of March 31, 2015, committed sales for calendar year 2015 and 2016 are 70 million MWH and 45 million MWH, respectively. Support for current customers in the channels to be exited will remain through their respective contract terms.
	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 March 31, 2015, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of which 28% was subject to variable-interest rates, and $1.9 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)
	March 31, 2015
	External revenues	$	2,562		$	238	$	1,175		$	(42	)	$	(36	)	$	3,897
	Internal revenues	—			—		260			—			(260		)	—
	Total revenues	2,562			238		1,435			(42		)	(296		)	3,897
	Depreciation	172			37		96			14			—			319
	Amortization of regulatory assets, net	29			3		—			—			—			32
	Investment income (loss)	13			—		11			3			(10		)	17
	Interest expense	144			39		48			47			1			279
	Income taxes (benefits)	122			42		(4		)	(18		)	2			144
	Income (loss) from continuing operations	208			72		(9		)	(49		)	—			222
	Net income (loss)	208			72		(9		)	(49		)	—			222
	Total assets	28,276			6,731		16,733			781			—			52,521
	Total goodwill	5,092			526		800			—			—			6,418
	Property additions	280			254		126			8			—			668
	March 31, 2014
	External revenues	$	2,550		$	182	$	1,522		$	(35	)	$	(37	)	$	4,182
	Internal revenues	—			—		249			—			(249		)	—
	Total revenues	2,550			182		1,771			(35		)	(286		)	4,182
	Depreciation	162			30		91			11			—			294
	Amortization (Deferral) of regulatory assets, net	(31		)	3		—			—			—			(28		)
	Investment income (loss)	15			—		14			3			(10		)	22
	Interest expense	151			25		46			43			—			265
	Income taxes (benefits)	125			30		(73		)	(26		)	(8		)	48
	Income (loss) from continuing operations	214			51		(124		)	(32		)	13			122
	Discontinued operations, net of tax	—			—		86			—			—			86
	Net income (loss)	214			51		(38		)	(32		)	13			208
	Total assets	27,742			5,584		17,445			457			—			51,228
	Total goodwill	5,092			526		800			—			—			6,418
	Property additions	269			217		318			17			—			821

Discontinued_Operations

Discontinued Operations	3 Months Ended
	Mar. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	DISCONTINUED OPERATIONS
	On February 12, 2014, certain of FirstEnergy's subsidiaries sold eleven hydroelectric power stations to 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 three months ended March 31, 2014, was included in discontinued operations in the Consolidated Statement of Income (Loss). Included in income from discontinued operations in the three months ended March 31, 2014, was a pre-tax gain on the sale of assets of $142 million (FES - $177 million). Revenues for the hydroelectric facilities of $5 million (FES - $5 million) for the three months ended March 31, 2014, was included in discontinued operations in the Consolidated Statement of Income (Loss).

Organization_and_Basis_of_Pres1

Organization and Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 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.
Reclassification Policy	Certain prior year amounts have been reclassified to conform to the current year presentation.
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 April 2015, the FASB proposed a deferral of the effective date of the new revenue standard by one year, subject to the FASB's due process requirement. 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 powers and benefits 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_S1

Earnings Per Share of Common Stock (Tables)	3 Months Ended
	Mar. 31, 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 March 31,
	Reconciliation of Basic and Diluted Earnings per Share of Common Stock		2015		2014
	Income from continuing operations		$	222	$	122
	Discontinued operations (Note 13)		—		86
	Net income		$	222	$	208
	Weighted average number of basic shares outstanding		421		419
	Assumed exercise of dilutive stock options and awards(1)		2		1
	Weighted average number of diluted shares outstanding		423		420
	Earnings per share:
	Basic earnings per share:
	Income from continuing operations		$	0.53	$	0.29
	Discontinued operations (Note 13)		—		0.21
	Net earnings per basic share		$	0.53	$	0.5
	Diluted earnings per share:
	Income from continuing operations		$	0.53	$	0.29
	Discontinued operations (Note 13)		—		0.2
	Net earnings per diluted share		$	0.53	$	0.49
	(1)	For the three months ended March 31, 2015 and March 31, 2014, 1 million and 2 million shares, respectively, were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

Pension_and_Other_Postemployme1

Pension and Other Postemployment Benefits (Tables)	3 Months Ended
	Mar. 31, 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 March 31,	2015			2014			2015			2014
		(In millions)
	Service costs	$	48		$	42		$	1		$	2
	Interest costs	96			100			7			10
	Expected return on plan assets	(111		)	(115		)	(8		)	(8		)
	Amortization of prior service costs (credits)	2			2			(33		)	(44		)
	Net periodic costs (credits)	$	35		$	29		$	(33	)	$	(40	)
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 March 31,	$	4		$	4		$	(5	)	$	(5	)
	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 March 31,	2015			2014			2015			2014
		(In millions)
	FirstEnergy	$	25		$	21		$	(23	)	$	(27	)
	FES	4			4			(4		)	(4		)

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Tables)	3 Months Ended
	Mar. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of Accumulated Other Comprehensive Income	The changes in AOCI, net of tax, in the three months ended March 31, 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 January 1, 2015	$	(37	)	$	25		$	258		$	246
	Other comprehensive income before reclassifications	—			14			—			14
	Amounts reclassified from AOCI	1			(10		)	(31		)	(40		)
	Other comprehensive income (loss)	1			4			(31		)	(26		)
	Income tax (benefits) on other comprehensive income (loss)	—			1			(11		)	(10		)
	Net other comprehensive income (loss)	1			3			(20		)	(16		)
	AOCI Balance as of March 31, 2015	$	(36	)	$	28		$	238		$	230
	AOCI Balance as of January 1, 2014	$	(36	)	$	9		$	311		$	284
	Other comprehensive income before reclassifications	—			35			—			35
	Amounts reclassified from AOCI	—			(14		)	(42		)	(56		)
	Other comprehensive income (loss)	—			21			(42		)	(21		)
	Income tax (benefits) on other comprehensive income (loss)	—			8			(16		)	(8		)
	Net other comprehensive income (loss)	—			13			(26		)	(13		)
	AOCI Balance as of March 31, 2014	$	(36	)	$	22		$	285		$	271
Reclassification out of Accumulated Other Comprehensive Income	The following amounts were reclassified from AOCI in the three months ended March 31, 2015 and 2014:
		Three Months Ended March 31,						Affected Line Item in Consolidated Statements of Income
	Reclassifications from AOCI (2)	2015			2014
		(In millions)
	Gains & losses on cash flow hedges
	Commodity contracts	$	(1	)	$	(2	)	Other operating expenses
	Long-term debt	2			2			Interest expense
		1			—			Total before taxes
		—			—			Income taxes
		$	1		$	—		Net of tax
	Unrealized gains on AFS securities
	Realized gains on sales of securities	$	(10	)	$	(14	)	Investment income
		4			5			Income taxes
		$	(6	)	$	(9	)	Net of tax
	Defined benefit pension and OPEB plans
	Prior-service costs	$	(31	)	$	(42	)	(1)
		11			16			Income taxes
		$	(20	)	$	(26	)	Net of tax
	(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details.
	(2) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.
FES [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of Accumulated Other Comprehensive Income	The changes in AOCI, net of tax, in the three months ended March 31, 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 January 1, 2015	$	(7	)	$	21		$	43		$	57
	Other comprehensive income before reclassifications	—			13			—			13
	Amounts reclassified from AOCI	(1		)	(10		)	(4		)	(15		)
	Other comprehensive income (loss)	(1		)	3			(4		)	(2		)
	Income tax (benefits) on other comprehensive loss	—			—			(1		)	(1		)
	Net other comprehensive income (loss)	(1		)	3			(3		)	(1		)
	AOCI Balance as of March 31, 2015	$	(8	)	$	24		$	40		$	56
	AOCI Balance as of January 1, 2014	$	(1	)	$	8		$	47		$	54
	Other comprehensive income before reclassifications	—			33			—			33
	Amounts reclassified from AOCI	(2		)	(14		)	(5		)	(21		)
	Other comprehensive income (loss)	(2		)	19			(5		)	12
	Income tax (benefits) on other comprehensive income (loss)	(1		)	7			(2		)	4
	Net other comprehensive income (loss)	(1		)	12			(3		)	8
	AOCI Balance as of March 31, 2014	$	(2	)	$	20		$	44		$	62
Reclassification out of Accumulated Other Comprehensive Income	The following amounts were reclassified from AOCI in the three months ended March 31, 2015 and 2014:
		Three Months Ended March 31,						Affected Line Item in Consolidated Statements of Income (Loss)
	Reclassifications from AOCI (2)	2015			2014
		(In millions)
	Gains & losses on cash flow hedges
	Commodity contracts	$	(1	)	$	(2	)	Other operating expenses
		—			1			Income tax benefits
		$	(1	)	$	(1	)	Net of tax
	Unrealized gains on AFS securities
	Realized gains on sales of securities	$	(10	)	$	(14	)	Investment income (loss)
		4			5			Income tax benefits
		$	(6	)	$	(9	)	Net of tax
	Defined benefit pension and OPEB plans
	Prior-service costs	$	(4	)	$	(5	)	(1)
		1			2			Income tax benefits
		$	(3	)	$	(3	)	Net of tax
	(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details.
	(2) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.

Variable_Interest_Entities_Tab

Variable Interest Entities (Tables)	3 Months Ended
	Mar. 31, 2015
Variable Interest Entities [Abstract]
Net exposure to loss based upon the casualty value provisions	The following table discloses each company’s net exposure to loss based upon the casualty value provisions as of March 31, 2015:
		Maximum		Discounted Lease		Net
		Exposure		Payments, net		Exposure
		(In millions)
	FirstEnergy	$	1,321	$	1,053	$	268
	FES	1,235		1,014		221

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value of Financial Instruments [Line Items]
Assets and liabilities measured on recurring basis	The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:
	FirstEnergy
	Recurring Fair Value Measurements	March 31, 2015																December 31, 2014
		Level 1				Level 2				Level 3				Total				Level 1			Level 2			Level 3			Total
	Assets	(In millions)
	Corporate debt securities	$	—			$	1,262			$	—			$	1,262			$	—		$	1,221		$	—		$	1,221
	Derivative assets - commodity contracts	2				191				—				193				1			171			—			172
	Derivative assets - FTRs	—				—				7				7				—			—			39			39
	Derivative assets - NUG contracts(1)	—				—				2				2				—			—			2			2
	Equity securities(2)	695				—				—				695				592			—			—			592
	Foreign government debt securities	—				85				—				85				—			76			—			76
	U.S. government debt securities	—				185				—				185				—			182			—			182
	U.S. state debt securities	—				244				—				244				—			237			—			237
	Other(3)	48				186				—				234				55			256			—			311
	Total assets	$	745			$	2,153			$	9			$	2,907			$	648		$	2,143		$	41		$	2,832
	Liabilities
	Derivative liabilities - commodity contracts	$	(10	)		$	(167	)		$	—			$	(177	)		$	(26	)	$	(141	)	$	—		$	(167	)
	Derivative liabilities - FTRs	—				—				(5		)		(5		)		—			—			(14		)	(14		)
	Derivative liabilities - NUG contracts(1)	—				—				(150		)		(150		)		—			—			(153		)	(153		)
	Total liabilities	$	(10	)		$	(167	)		$	(155	)		$	(332	)		$	(26	)	$	(141	)	$	(167	)	$	(334	)
	Net assets (liabilities)(4)	$	735			$	1,986			$	(146	)		$	2,575			$	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 $(32) million and $40 million as of March 31, 2015 and December 31, 2014, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts	The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2015 and December 31, 2014:
		NUG Contracts(1)												FTRs
		Derivative Assets				Derivative Liabilities				Net				Derivative Assets				Derivative Liabilities			Net
		(In millions)
	January 1, 2014 Balance	$	20			$	(222	)		$	(202	)		$	4			$	(12	)	$	(8	)
	Unrealized gain (loss)	2				(2		)		—				47				(1		)	46
	Purchases	—				—				—				26				(16		)	10
	Settlements	(20		)		71				51				(38		)		15			(23		)
	December 31, 2014 Balance	$	2			$	(153	)		$	(151	)		$	39			$	(14	)	$	25
	Unrealized gain (loss)	1				(10		)		(9		)		4				3			7
	Settlements	(1		)		13				12				(36		)		6			(30		)
	March 31, 2015 Balance	$	2			$	(150	)		$	(148	)		$	7			$	(5	)	$	2
	(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 March 31, 2015:
			Fair Value, Net (In millions)				Valuation		Significant Input		Range		Weighted Average			Units
							Technique
	FTRs		$	2			Model		RTO auction clearing prices		($3.80) to $4.70		$0.90			Dollars/MWH
	NUG Contracts		$	(148	)		Model		Generation		500 to 4,538,000		891,000			MWH
									Regional electricity prices		$46.10 to $69.90		$52.80			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 March 31, 2015 and December 31, 2014:
			March 31, 2015(1)												December 31, 2014(2)
			Cost Basis				Unrealized Gains				Fair Value				Cost Basis				Unrealized Gains			Fair Value
			(In millions)
	Debt securities
	FirstEnergy		$	1,767			$	43			$	1,810			$	1,724			$	27		$	1,751
	FES		812				22				834				788				13			801
	Equity securities
	FirstEnergy		$	648			$	47			$	695			$	533			$	58		$	591
	FES		442				27				469				329				31			360
	(1)	Excludes short-term cash investments: FE Consolidated - $98 million; FES - $78 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 months ended March 31, 2015 and 2014 were as follows:
	Three Months Ended
	March 31, 2015		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and
																			Dividend Income
			(In millions)
	FirstEnergy		$	371			$	60			$	(50	)		$	(7	)		$	25
	FES		189				38				(28		)		(6		)		14
	March 31, 2014		Sale Proceeds				Realized Gains				Realized Losses				OTTI				Interest and Dividend Income
			(In millions)
	FirstEnergy		$	621			$	28			$	(16	)		$	(2	)		$	25
	FES		423				19				(5		)		(2		)		15
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 March 31, 2015 and December 31, 2014:
			March 31, 2015												December 31, 2014
			Cost Basis				Unrealized Gains				Fair Value				Cost Basis				Unrealized Gains			Fair Value
			(In millions)
	Debt Securities
	FirstEnergy		$	13			$	4			$	17			$	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:
		March 31, 2015								December 31, 2014
		Carrying				Fair				Carrying				Fair
		Value				Value				Value				Value
		(In millions)
	FirstEnergy	$	19,775			$	21,911			$	19,828			$	21,733
	FES	3,080				3,215				3,097				3,241
FES
Fair Value of Financial Instruments [Line Items]
Assets and liabilities measured on recurring basis
	FES
	Recurring Fair Value Measurements	March 31, 2015																December 31, 2014
		Level 1				Level 2				Level 3				Total				Level 1			Level 2			Level 3			Total
	Assets	(In millions)
	Corporate debt securities	$	—			$	690			$	—			$	690			$	—		$	655		$	—		$	655
	Derivative assets - commodity contracts	2				191				—				193				1			171			—			172
	Derivative assets - FTRs	—				—				6				6				—			—			27			27
	Equity securities(1)	469				—				—				469				360			—			—			360
	Foreign government debt securities	—				68				—				68				—			57			—			57
	U.S. government debt securities	—				35				—				35				—			46			—			46
	U.S. state debt securities	—				4				—				4				—			4			—			4
	Other(2)	—				124				—				124				—			199			—			199
	Total assets	$	471			$	1,112			$	6			$	1,589			$	361		$	1,132		$	27		$	1,520
	Liabilities
	Derivative liabilities - commodity contracts	$	(10	)		$	(167	)		$	—			$	(177	)		$	(26	)	$	(141	)	$	—		$	(167	)
	Derivative liabilities - FTRs	—				—				(5		)		(5		)		—			—			(13		)	(13		)
	Total liabilities	$	(10	)		$	(167	)		$	(5	)		$	(182	)		$	(26	)	$	(141	)	$	(13	)	$	(180	)
	Net assets (liabilities)(3)	$	461			$	945			$	1			$	1,407			$	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 $(9) million and $44 million as of March 31, 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 March 31, 2015 and December 31, 2014:
			Derivative Asset				Derivative Liability				Net Asset (Liability)
			(In millions)
	January 1, 2014 Balance		$	3			$	(11	)		$	(8	)
	Unrealized gain (loss)		34				(1		)		33
	Purchases		15				(16		)		(1		)
	Settlements		(25		)		15				(10		)
	December 31, 2014 Balance		$	27			$	(13	)		$	14
	Unrealized gain		3				2				5
	Settlements		(24		)		6				(18		)
	March 31, 2015 Balance		$	6			$	(5	)		$	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 March 31, 2015:
			Fair Value, Net (In millions)				Valuation		Significant Input		Range		Weighted Average		Units
							Technique
	FTRs		$	1			Model		RTO auction clearing prices		($3.80) to $4.30		$0.70		Dollars/MWH

Derivative_Instruments_Tables

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair value of derivatives instruments	The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets:
	Derivative Assets									Derivative Liabilities
		Fair Value									Fair Value
		March 31,				December 31,					March 31,			December 31,
		2015				2014					2015			2014
		(In millions)									(In millions)
	Current Assets - Derivatives									Current Liabilities - Derivatives
	Commodity Contracts	$	127			$	121			Commodity Contracts	$	(150	)	$	(154	)
	FTRs	6				38				FTRs	(4		)	(13		)
		133				159					(154		)	(167		)
										Noncurrent Liabilities - Adverse Power Contract Liability
	Deferred Charges and Other Assets - Other									NUGs(1)	(150		)	(153		)
	Commodity Contracts	66				51				Noncurrent Liabilities - Other
	FTRs	1				1				Commodity Contracts	(27		)	(13		)
	NUGs(1)	2				2				FTRs	(1		)	(1		)
		69				54					(178		)	(167		)
	Derivative Assets	$	202			$	213			Derivative Liabilities	$	(332	)	$	(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
	March 31, 2015		Fair Value				Derivative Instruments				Cash Collateral (Received)/Pledged			Net Fair Value
			(In millions)
	Derivative Assets
	Commodity contracts		$	193			$	(156	)		$	—		$	37
	FTRs		7				(5		)		—			2
	NUG contracts		2				—				—			2
			$	202			$	(161	)		$	—		$	41
	Derivative Liabilities
	Commodity contracts		$	(177	)		$	156			$	16		$	(5	)
	FTRs		(5		)		5				—			—
	NUG contracts		(150		)		—				—			(150		)
			$	(332	)		$	161			$	16		$	(155	)
							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 March 31, 2015:
		Purchases			Sales			Net			Units
		(In millions)
	Power Contracts	22			42			(20	)		MWH
	FTRs	22			—			22			MWH
	NUGs	5			—			5			MWH
	Natural Gas	32			—			32			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 months ended March 31, 2015 and 2014, are summarized in the following tables:
		Three Months Ended March 31,
		Commodity Contracts				FTRs				Total
		(In millions)
	2015
	Unrealized Gain (Loss) Recognized in:
	Other Operating Expense (1)	$	11			$	(13	)		$	(2	)
	Realized Gain (Loss) Reclassified to:
	Revenues (2)	$	(1	)		$	37			$	36
	Purchased Power Expense (3)	(3		)		—				(3		)
	Other Operating Expense (4)	—				(13		)		(13		)
	Fuel Expense	(16		)		—				(16		)
	(1) Includes $11 million for commodity contracts and ($12) million for FTRs associated with FES.
	(2) Represents losses on structured financial contracts. Includes ($1) million for commodity contracts and $36 million for FTRs associated with FES.
	(3) Realized losses on financially settled wholesale sales contracts of $22 million were netted in purchased power. Includes ($3) million for commodity contracts associated with FES.
	(4) Includes ($13) million for FTRs associated with FES.
		Three Months Ended March 31,
		Commodity Contracts				FTRs				Total
		(In millions)
	2014
	Unrealized Gain Recognized in:
	Other Operating Expense (5)	$	12			$	5			$	17
	Realized Gain (Loss) Reclassified to:
	Revenues (6)	$	(13	)		$	52			$	39
	Purchased Power Expense (7)	436				—				436
	Other Operating Expense (8)	—				(7		)		(7		)
	Fuel Expense	9				—				9
	(5) Includes $12 million for commodity contracts and $5 million for FTRs associated with FES.
	(6) Represents losses on structured financial contracts. Includes ($13) million for commodity contracts and $51 million for FTRs associated with FES.
	(7) Realized losses on financially settled wholesale sales contracts of $321 million resulting from higher market prices were netted in purchased power. Includes $436 million for commodity contracts associated with FES.
	(8) Includes ($7) 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 months ended March 31, 2015 and 2014. Changes in the value of these instruments are deferred for future recovery from (or credit to) customers:
			Three Months Ended March 31,
	Derivatives Not in a Hedging Relationship with Regulatory Offset		NUGs				Regulated FTRs				Total
			(In millions)
	Outstanding net asset (liability) as of January 1, 2015		$	(151	)		$	11			$	(140	)
	Unrealized gain (loss)		(8		)		1				(7		)
	Settlements		11				(11		)		—
	Outstanding net asset (liability) as of March 31, 2015		$	(148	)		$	1			$	(147	)
	Outstanding net liability as of January 1, 2014		$	(202	)		$	—			$	(202	)
	Unrealized gain		27				4				31
	Settlements		(10		)		(1		)		(11		)
	Outstanding net asset (liability) as of March 31, 2014		$	(185	)		$	3			$	(182	)

Commitments_Guarantees_and_Con1

Commitments, Guarantees and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule of Guarantor Obligations	The following table discloses the additional credit contingent contractual obligations that may be required under certain events as of March 31, 2015:
	Collateral Provisions	FES		AE Supply		Utilities		Total
		(In millions)
	Split Rating (One rating agency's rating below investment grade)	$	427	$	6	$	43	$	476
	BB+/Ba1 Credit Ratings	$	465	$	6	$	43	$	514
	Full impact of credit contingent contractual obligations	$	583	$	50	$	78	$	711

Supplemental_Guarantor_Informa1

Supplemental Guarantor Information (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2015	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	REVENUES	$	1,332		$	493		$	507		$	(955	)	$	1,377
	OPERATING EXPENSES:
	Fuel	—			180			50			—			230
	Purchased power from affiliates	957			—			68			(955		)	70
	Purchased power from non-affiliates	543			—			—			—			543
	Other operating expenses	180			67			154			12			413
	Provision for depreciation	3			30			48			(1		)	80
	General taxes	15			8			6			—			29
	Total operating expenses	1,698			285			326			(944		)	1,365
	OPERATING INCOME (LOSS)	(366		)	208			181			(11		)	12
	OTHER INCOME (EXPENSE):
	Loss on debt redemptions	—			—			—			—			—
	Investment income, including net income from equity investees	241			3			14			(245		)	13
	Interest expense — affiliates	(6		)	(2		)	(1		)	7			(2		)
	Interest expense — other	(13		)	(26		)	(13		)	15			(37		)
	Capitalized interest	—			1			8			—			9
	Total other income (expense)	222			(24		)	8			(223		)	(17		)
	INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS)	(144		)	184			189			(234		)	(5		)
	INCOME TAXES (BENEFITS)	(141		)	67			70			2			(2		)
	NET INCOME (LOSS)	$	(3	)	$	117		$	119		$	(236	)	$	(3	)
	STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
	NET INCOME (LOSS)	$	(3	)	$	117		$	119		$	(236	)	$	(3	)
	OTHER COMPREHENSIVE INCOME (LOSS):
	Pension and OPEB prior service costs	(4		)	(4		)	3			1			(4		)
	Amortized gain on derivative hedges	(1		)	—			—			—			(1		)
	Change in unrealized gain on available-for-sale securities	3			—			—			—			3
	Other comprehensive income (loss)	(2		)	(4		)	3			1			(2		)
	Income taxes (benefits) on other comprehensive loss	(1		)	(1		)	1			—			(1		)
	Other comprehensive income (loss), net of tax	(1		)	(3		)	2			1			(1		)
	COMPREHENSIVE INCOME (LOSS)	$	(4	)	$	114		$	121		$	(235	)	$	(4	)
	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
	(Unaudited)
	For the Three Months Ended March 31, 2014	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	STATEMENTS OF INCOME
	REVENUES	$	1,797		$	315		$	362		$	(645	)	$	1,829
	OPERATING EXPENSES:
	Fuel	—			272			47			—			319
	Purchased power from affiliates	645			—			64			(645		)	64
	Purchased power from non-affiliates	1,025			4			—			—			1,029
	Other operating expenses	228			62			150			12			452
	Provision for depreciation	2			29			43			—			74
	General taxes	21			11			7			—			39
	Total operating expenses	1,921			378			311			(633		)	1,977
	OPERATING INCOME (LOSS)	(124		)	(63		)	51			(12		)	(148		)
	OTHER INCOME (EXPENSE):
	Loss on debt redemption	(3		)	(1		)	(1		)	—			(5		)
	Investment income, including net income from equity investees	104			1			21			(106		)	20
	Interest expense — affiliates	(3		)	(1		)	(1		)	3			(2		)
	Interest expense — other	(14		)	(24		)	(13		)	15			(36		)
	Capitalized interest	—			1			11			—			12
	Total other income (expense)	84			(24		)	17			(88		)	(11		)
	INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	(40		)	(87		)	68			(100		)	(159		)
	INCOME TAXES (BENEFITS)	(52		)	(31		)	26			1			(56		)
	INCOME (LOSS) FROM CONTINUING OPERATIONS	12			(56		)	42			(101		)	(103		)
	Discontinued operations (net of income taxes of $70) (Note 13)	—			116			—			—			116
	NET INCOME	$	12		$	60		$	42		$	(101	)	$	13
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	12		$	60		$	42		$	(101	)	$	13
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(5		)	(4		)	—			4			(5		)
Amortized gain on derivative hedges	(2		)	—			—			—			(2		)
Change in unrealized gain on available for sale securities	19			—			19			(19		)	19
Other comprehensive income (loss)	12			(4		)	19			(15		)	12
Income taxes (benefits) on other comprehensive income (loss)	4			(2		)	7			(5		)	4
Other comprehensive income (loss), net of tax	8			(2		)	12			(10		)	8
COMPREHENSIVE INCOME	$	20		$	58		$	54		$	(111	)	$	21
Condensed Consolidating Balance Sheets	FIRSTENERGY SOLUTIONS CORP.
	CONDENSED CONSOLIDATING BALANCE SHEETS
	(Unaudited)
	As of March 31, 2015	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	ASSETS
	CURRENT ASSETS:
	Cash and cash equivalents	$	—		$	2		$	—		$	—		$	2
	Receivables-
	Customers	351			—			—			—			351
	Affiliated companies	507			357			313			(636		)	541
	Other	71			2			79			—			152
	Notes receivable from affiliated companies	333			1,017			634			(1,940		)	44
	Materials and supplies	46			181			220			—			447
	Derivatives	132			—			—			—			132
	Collateral	217			—			—			—			217
	Prepayments and other	83			34			—			—			117
		1,740			1,593			1,246			(2,576		)	2,003
	PROPERTY, PLANT AND EQUIPMENT:
	In service	134			6,296			7,659			(383		)	13,706
	Less — Accumulated provision for depreciation	39			2,085			3,399			(192		)	5,331
		95			4,211			4,260			(191		)	8,375
	Construction work in progress	3			162			892			—			1,057
		98			4,373			5,152			(191		)	9,432
	INVESTMENTS:
	Nuclear plant decommissioning trusts	—			—			1,381			—			1,381
	Investment in affiliated companies	6,847			—			—			(6,847		)	—
	Other	—			10			—			—			10
		6,847			10			1,381			(6,847		)	1,391
	DEFERRED CHARGES AND OTHER ASSETS:
	Accumulated deferred income tax benefits	344			7			—			(351		)	—
	Customer intangibles	74			—			—			—			74
	Goodwill	23			—			—			—			23
	Property taxes	—			11			20			—			31
	Unamortized sale and leaseback costs	—			—			—			248			248
	Derivatives	67			—			—			—			67
	Other	31			275			6			(204		)	108
		539			293			26			(307		)	551
		$	9,224		$	6,269		$	7,805		$	(9,921	)	$	13,377
	LIABILITIES AND CAPITALIZATION
	CURRENT LIABILITIES:
	Currently payable long-term debt	$	—		$	166		$	348		$	(24	)	$	490
	Short-term borrowings-
	Affiliated companies	1,624			316			—			(1,940		)	—
	Other	275			9			—			—			284
	Accounts payable-
	Affiliated companies	652			180			249			(652		)	429
	Other	84			72			—			—			156
	Accrued taxes	5			43			92			(55		)	85
	Derivatives	154			—			—			—			154
	Other	44			63			17			82			206
		2,838			849			706			(2,589		)	1,804
	CAPITALIZATION:
	Total equity	5,581			2,677			4,135			(6,812		)	5,581
	Long-term debt and other long-term obligations	695			2,212			859			(1,161		)	2,605
		6,276			4,889			4,994			(7,973		)	8,186
	NONCURRENT LIABILITIES:
	Deferred gain on sale and leaseback transaction	—			—			—			816			816
	Accumulated deferred income taxes	13			—			710			(175		)	548
	Asset retirement obligations	—			190			648			—			838
	Retirement benefits	36			291			—			—			327
	Derivatives	28			—			—			—			28
	Other	33			50			747			—			830
		110			531			2,105			641			3,387
	$	9,224		$	6,269		$	7,805		$	(9,921	)	$	13,377
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 Three Months Ended March 31, 2015	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(662	)	$	222		$	545		$	—		$	105
	CASH FLOWS FROM FINANCING ACTIVITIES:
	New Financing-
	Short-term borrowings, net	674			—			—			(524		)	150
	Redemptions and Repayments-
	Long-term debt	(17		)	—			—			—			(17		)
	Short-term borrowings, net	—			(5		)	(28		)	33			—
	Other	—			(2		)	—			—			(2		)
	Net cash provided from (used for) financing activities	657			(7		)	(28		)	(491		)	131
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Property additions	(1		)	(36		)	(82		)	—			(119		)
	Nuclear fuel	—			—			(60		)	—			(60		)
	Sales of investment securities held in trusts	—			—			189			—			189
	Purchases of investment securities held in trusts	—			—			(202		)	—			(202		)
	Loans to affiliated companies, net	6			(179		)	(362		)	491			(44		)
	Net cash provided from (used for) investing activities	5			(215		)	(517		)	491			(236		)
	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 Three Months Ended March 31, 2014	FES			FG			NG			Eliminations			Consolidated
		(In millions)
	NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(450	)	$	87		$	51		$	—		$	(312	)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	New Financing-
	Long-term debt	—			235			182			—			417
	Short-term borrowings, net	209			72			—			(161		)	120
	Equity contribution from parent	500			—			—			—			500
	Redemptions and Repayments-
	Long-term debt	—			(248		)	(197		)	—			(445		)
	Short-term borrowings, net	—			—			(151		)	151			—
	Other	(1		)	(2		)	(1		)	—			(4		)
	Net cash provided from (used for) financing activities	708			57			(167		)	(10		)	588
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Property additions	(2		)	(28		)	(268		)	—			(298		)
	Nuclear fuel	—			—			(55		)	—			(55		)
	Proceeds from asset sales	—			307			—			—			307
	Sales of investment securities held in trusts	—			—			423			—			423
	Purchases of investment securities held in trusts	—			—			(438		)	—			(438		)
	Loans to affiliated companies, net	(254		)	(425		)	454			10			(215		)
	Other	(2		)	2			—			—			—
	Net cash provided from (used for) investing activities	(258		)	(144		)	116			10			(276		)
	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)	3 Months Ended
	Mar. 31, 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)
	March 31, 2015
	External revenues	$	2,562		$	238	$	1,175		$	(42	)	$	(36	)	$	3,897
	Internal revenues	—			—		260			—			(260		)	—
	Total revenues	2,562			238		1,435			(42		)	(296		)	3,897
	Depreciation	172			37		96			14			—			319
	Amortization of regulatory assets, net	29			3		—			—			—			32
	Investment income (loss)	13			—		11			3			(10		)	17
	Interest expense	144			39		48			47			1			279
	Income taxes (benefits)	122			42		(4		)	(18		)	2			144
	Income (loss) from continuing operations	208			72		(9		)	(49		)	—			222
	Net income (loss)	208			72		(9		)	(49		)	—			222
	Total assets	28,276			6,731		16,733			781			—			52,521
	Total goodwill	5,092			526		800			—			—			6,418
	Property additions	280			254		126			8			—			668
	March 31, 2014
	External revenues	$	2,550		$	182	$	1,522		$	(35	)	$	(37	)	$	4,182
	Internal revenues	—			—		249			—			(249		)	—
	Total revenues	2,550			182		1,771			(35		)	(286		)	4,182
	Depreciation	162			30		91			11			—			294
	Amortization (Deferral) of regulatory assets, net	(31		)	3		—			—			—			(28		)
	Investment income (loss)	15			—		14			3			(10		)	22
	Interest expense	151			25		46			43			—			265
	Income taxes (benefits)	125			30		(73		)	(26		)	(8		)	48
	Income (loss) from continuing operations	214			51		(124		)	(32		)	13			122
	Discontinued operations, net of tax	—			—		86			—			—			86
	Net income (loss)	214			51		(38		)	(32		)	13			208
	Total assets	27,742			5,584		17,445			457			—			51,228
	Total goodwill	5,092			526		800			—			—			6,418
	Property additions	269			217		318			17			—			821

Organization_and_Basis_of_Pres2

Organization and Basis of Presentation (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Allowance for Funds Used During Construction Capitalized Cost of Equity	$16	$7
Capitalized interest	$18	$22

Earnings_Per_Share_of_Common_S2

Earnings Per Share of Common Stock (Details) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Earnings Per Share [Abstract]
Income (loss) from continuing operations	$222	$122
Discontinued operations	0	86
NET INCOME (LOSS)	$222	$208
Weighted average number of basic shares outstanding	421	419
Assumed exercise of dilutive stock options and awards	2	1
Weighted average number of diluted shares outstanding	423	420
Basic earnings per share:
Income (loss) from continuing operations, in dollars per share	$0.53	$0.29
Discontinued operations, in dollars per share	$0	$0.21
Basic - Earnings Available to FirstEnergy Corp., in dollars per share	$0.53	$0.50
Diluted earnings per share:
Income (loss) from continuing operations, in dollars per share	$0.53	$0.29
Discontinued operations, in dollars per share	$0	$0.20
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share	$0.53	$0.49
Shares excluded from the calculation of diluted shares outstanding, in shares	1	2

Pension_and_Other_Postemployme2

Pension and Other Postemployment Benefits (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 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	42
Interest costs	96	100
Expected return on plan assets	-111	-115
Amortization of prior service cost (credit)	2	2
Net periodic costs (credits)	35	29
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	1	2
Interest costs	7	10
Expected return on plan assets	-8	-8
Amortization of prior service cost (credit)	-33	-44
Net periodic costs (credits)	-33	-40
FirstEnergy | Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	25	21
FirstEnergy | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	-23	-27
FES | Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)	4	4
Net periodic benefit expense (credit)	4	4
FES | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)	-5	-5
Net periodic benefit expense (credit)	($4)	($4)

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, before Tax	$14	$35
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	40	56
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	246	284
Other comprehensive income (loss)	-26	-21
Income taxes (benefits) on other comprehensive income (loss)	-10	-8
Other comprehensive income (loss), net of tax	-16	-13
AOCI Ending Balance	230	271
FES
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, before Tax	13	33
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	15	21
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	57	54
Other comprehensive income (loss)	-2	12
Income taxes (benefits) on other comprehensive income (loss)	-1	4
Other comprehensive income (loss), net of tax	-1	8
AOCI Ending Balance	56	62
Gains & Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, before Tax	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	-1	0
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	-37	-36
Other comprehensive income (loss)	1	0
Income taxes (benefits) on other comprehensive income (loss)	0	0
Other comprehensive income (loss), net of tax	1	0
AOCI Ending Balance	-36	-36
Gains & Losses on Cash Flow Hedges | FES
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, before Tax	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	1	2
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	-7	-1
Other comprehensive income (loss)	-1	-2
Income taxes (benefits) on other comprehensive income (loss)	0	-1
Other comprehensive income (loss), net of tax	-1	-1
AOCI Ending Balance	-8	-2
Unrealized Gains on AFS Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, before Tax	14	35
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	10	14
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	25	9
Other comprehensive income (loss)	4	21
Income taxes (benefits) on other comprehensive income (loss)	1	8
Other comprehensive income (loss), net of tax	3	13
AOCI Ending Balance	28	22
Unrealized Gains on AFS Securities | FES
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, before Tax	13	33
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	10	14
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	21	8
Other comprehensive income (loss)	3	19
Income taxes (benefits) on other comprehensive income (loss)	0	7
Other comprehensive income (loss), net of tax	3	12
AOCI Ending Balance	24	20
Defined Benefit Pension & OPEB Plans
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, before Tax	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	31	42
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	258	311
Other comprehensive income (loss)	-31	-42
Income taxes (benefits) on other comprehensive income (loss)	-11	-16
Other comprehensive income (loss), net of tax	-20	-26
AOCI Ending Balance	238	285
Defined Benefit Pension & OPEB Plans | FES
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, before Tax	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	4	5
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	43	47
Other comprehensive income (loss)	-4	-5
Income taxes (benefits) on other comprehensive income (loss)	-1	-2
Other comprehensive income (loss), net of tax	-3	-3
AOCI Ending Balance	$40	$44

Accumulated_Other_Comprehensiv3

Accumulated Other Comprehensive Income (Details 1) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	$1,057	$1,182
Interest expense	279	265
Investment income (loss)	-17	-22
Total before taxes	-366	-170
Income taxes (benefits)	144	48
Net of tax	-222	-208
FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	413	452
Investment income (loss)	-13	-20
Total before taxes	5	159
Income taxes (benefits)	-2	-56
Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Total before taxes	1	0
Income taxes (benefits)	0	0
Net of tax	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
Net of tax	-1	-1
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	-1	-2
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	-2
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
Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	-10	-14
Income taxes (benefits)	4	5
Net of tax	-6	-9
Reclassifications from AOCI | Unrealized gains on AFS securities | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	-10	-14
Income taxes (benefits)	4	5
Net of tax	-6	-9
Reclassifications from AOCI | Defined benefit pension and OPEB plans
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	-31	-42
Income taxes (benefits)	11	16
Net of tax	-20	-26
Reclassifications from AOCI | Defined benefit pension and OPEB plans | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	-4	-5
Income taxes (benefits)	1	2
Net of tax	($3)	($3)

Income_Taxes_Details

Income Taxes (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	39.30%	28.20%
Unrecognized tax benefits from lapse of statute of limitations	$10
FES
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	40.00%	35.20%

Variable_Interest_Entities_Det

Variable Interest Entities (Details) (USD $)	Mar. 31, 2015
In Millions, unless otherwise specified
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	$1,321
Discounted Lease Payments, net	1,053
Net Exposure	268
FES
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	1,235
Discounted Lease Payments, net	1,014
Net Exposure	$221

Variable_Interest_Entities_Det1

Variable Interest Entities (Details Textuals) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2011	Dec. 31, 2014	Dec. 31, 2007	Oct. 31, 2012
	entities		T
Variable Interest Entities (Textuals) [Abstract]
Long-term transition bond	$159,000,000			$168,000,000
Long-term pollution control bond	441,000,000			450,000,000
Guarantor obligations	711,000,000
Equity interest by unaffiliated third party in PNBV	3.00%
Number of contracts that may contain variable interest	1
Purchased power	1,113,000,000	1,455,000,000
Perry Power Plant Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary	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%
Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities	16
Phase-In Recovery Bonds
Variable Interest Entities (Textuals) [Abstract]
Long-term debt and other long-term obligations	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					350
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%
Other FE subsidiaries | Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Purchased power	31,000,000	61,000,000
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%
Percentage of high-voltage transmission line project owned by subsidiary of FE on the West Virginia Series	50.00%
Global Holding | FEV
Variable Interest Entities (Textuals) [Abstract]
Equity method investment	379,000,000
Pre-tax charge	24,000,000
Global Holding | Guarantee of senior secured loan facility
Variable Interest Entities (Textuals) [Abstract]
Pre-tax charge	24,000,000
Guarantor obligations	$300,000,000
Signal Peak
Variable Interest Entities (Textuals) [Abstract]
Equity ownership percentage sold			16.70%
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)			2,000,000
Signal Peak | Global Holding | FEV
Variable Interest Entities (Textuals) [Abstract]
Ownership interest	33.33%

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (Recurring, USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Assets
Fair value, assets	$2,907	$2,832
Liabilities
Fair value, liabilities	-332	-334
Net assets (liabilities)	2,575	2,498
FES
Assets
Fair value, assets	1,589	1,520
Liabilities
Fair value, liabilities	-182	-180
Net assets (liabilities)	1,407	1,340
Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	-177	-167
Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	-177	-167
FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	-5	-14
FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	-5	-13
NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	-150	-153
Corporate debt securities
Assets
Fair value, assets	1,262	1,221
Corporate debt securities | FES
Assets
Fair value, assets	690	655
Commodity contracts | Derivative Assets
Assets
Fair value, assets	193	172
Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	193	172
FTRs | Derivative Assets
Assets
Fair value, assets	7	39
FTRs | Derivative Assets | FES
Assets
Fair value, assets	6	27
NUG contracts | Derivative Assets
Assets
Fair value, assets	2	2
Equity securities
Assets
Fair value, assets	695	592
Equity securities | FES
Assets
Fair value, assets	469	360
Foreign government debt securities
Assets
Fair value, assets	85	76
Foreign government debt securities | FES
Assets
Fair value, assets	68	57
U.S. government debt securities
Assets
Fair value, assets	185	182
U.S. government debt securities | FES
Assets
Fair value, assets	35	46
U.S. state debt securities
Assets
Fair value, assets	244	237
U.S. state debt securities | FES
Assets
Fair value, assets	4	4
Other
Assets
Fair value, assets	234	311
Other | FES
Assets
Fair value, assets	124	199
Level 1
Assets
Fair value, assets	745	648
Liabilities
Fair value, liabilities	-10	-26
Net assets (liabilities)	735	622
Level 1 | FES
Assets
Fair value, assets	471	361
Liabilities
Fair value, liabilities	-10	-26
Net assets (liabilities)	461	335
Level 1 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	-10	-26
Level 1 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	-10	-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	2	1
Level 1 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	2	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	695	592
Level 1 | Equity securities | FES
Assets
Fair value, assets	469	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	48	55
Level 1 | Other | FES
Assets
Fair value, assets	0	0
Level 2
Assets
Fair value, assets	2,153	2,143
Liabilities
Fair value, liabilities	-167	-141
Net assets (liabilities)	1,986	2,002
Level 2 | FES
Assets
Fair value, assets	1,112	1,132
Liabilities
Fair value, liabilities	-167	-141
Net assets (liabilities)	945	991
Level 2 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	-167	-141
Level 2 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	-167	-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	1,262	1,221
Level 2 | Corporate debt securities | FES
Assets
Fair value, assets	690	655
Level 2 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	191	171
Level 2 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	191	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	85	76
Level 2 | Foreign government debt securities | FES
Assets
Fair value, assets	68	57
Level 2 | U.S. government debt securities
Assets
Fair value, assets	185	182
Level 2 | U.S. government debt securities | FES
Assets
Fair value, assets	35	46
Level 2 | U.S. state debt securities
Assets
Fair value, assets	244	237
Level 2 | U.S. state debt securities | FES
Assets
Fair value, assets	4	4
Level 2 | Other
Assets
Fair value, assets	186	256
Level 2 | Other | FES
Assets
Fair value, assets	124	199
Level 3
Assets
Fair value, assets	9	41
Liabilities
Fair value, liabilities	-155	-167
Net assets (liabilities)	-146	-126
Level 3 | FES
Assets
Fair value, assets	6	27
Liabilities
Fair value, liabilities	-5	-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	-5	-14
Level 3 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	-5	-13
Level 3 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	-150	-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	7	39
Level 3 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	6	27
Level 3 | NUG contracts | Derivative Assets
Assets
Fair value, assets	2	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_Detail1

Fair Value Measurements (Details 1) (Level 3, USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
NUG contracts
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	$2	$20
Beginning Balance, Derivative Liabilities	-153	-222
Beginning Balance, Net	-151	-202
Unrealized gain (loss), Derivative Assets	1	2
Unrealized gain (loss), Derivative Liabilities	-10	-2
Unrealized gain (loss), Net	-9	0
Purchases, Derivative Assets		0
Purchases, Derivative Liabilities		0
Purchases, Net		0
Settlements, Derivative Assets	-1	-20
Settlements, Derivative Liabilities	13	71
Settlements, Net	12	51
Ending Balance, Derivative Assets	2	2
Ending Balance, Derivative Liabilities	-150	-153
Ending Balance, Net	-148	-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	4	47
Unrealized gain (loss), Derivative Liabilities	3	-1
Unrealized gain (loss), Net	7	46
Purchases, Derivative Assets		26
Purchases, Derivative Liabilities		-16
Purchases, Net		10
Settlements, Derivative Assets	-36	-38
Settlements, Derivative Liabilities	6	15
Settlements, Net	-30	-23
Ending Balance, Derivative Assets	7	39
Ending Balance, Derivative Liabilities	-5	-14
Ending Balance, Net	2	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	3	34
Unrealized gain (loss), Derivative Liabilities	2	-1
Unrealized gain (loss), Net	5	33
Purchases, Derivative Assets		15
Purchases, Derivative Liabilities		-16
Purchases, Net		-1
Settlements, Derivative Assets	-24	-25
Settlements, Derivative Liabilities	6	15
Settlements, Net	-18	-10
Ending Balance, Derivative Assets	6	27
Ending Balance, Derivative Liabilities	-5	-13
Ending Balance, Net	$1	$14

Fair_Value_Measurements_Detail2

Fair Value Measurements (Details 2) (Level 3, USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value	$2	$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	-148	-151	-202
Model | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value	2
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	($148)
Model | Minimum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices	-3.8
Model | Minimum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices	-3.8
Model | Minimum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power	500
Fair Value Inputs, Power, Regional Prices	46.1
Model | Maximum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices	4.7
Model | Maximum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices	4.3
Model | Maximum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power	4,538,000
Fair Value Inputs, Power, Regional Prices	69.9
Model | Weighted Average | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices	0.9
Model | Weighted Average | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices	0.7
Model | Weighted Average | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power	891,000
Fair Value Inputs, Power, Regional Prices	52.8

Fair_Value_Measurements_Detail3

Fair Value Measurements (Details 3) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	$1,767	$1,724
Unrealized Gain	43	27
Fair Value	1,810	1,751
Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	648	533
Unrealized Gains	-47	-58
Fair Value	695	591
FES | Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	812	788
Unrealized Gain	22	13
Fair Value	834	801
FES | Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	442	329
Unrealized Gains	-27	-31
Fair Value	$469	$360

Fair_Value_Measurements_Detail4

Fair Value Measurements (Details 4) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 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	$371	$621
Realized Gains	60	28
Realized Losses	-50	-16
OTTI	-7	-2
Interest and Dividend Income	25	25
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	189	423
Realized Gains	38	19
Realized Losses	-28	-5
OTTI	-6	-2
Interest and Dividend Income	$14	$15

Fair_Value_Measurements_Detail5

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

Fair_Value_Measurements_Detail6

Fair Value Measurements (Details 6) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$19,775	$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	3,080	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	21,911	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	$3,215	$3,241

Fair_Value_Measurements_Detail7

Fair Value Measurements (Details Textuals) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	-32	$40
Cash balance excluded from available for sale securities	98	241
Investments not required to be disclosed	642	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	-9	44
Cash balance excluded from available for sale securities	78	$204

Derivative_Instruments_Details

Derivative Instruments (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Fair value of commodity derivatives
Derivative Assets	$202	$213
Derivative Liabilities	-332	-334
Current Assets
Fair value of commodity derivatives
Derivative Assets	133	159
Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	69	54
Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	-154	-167
Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	-178	-167
Commodity contracts | Current Assets
Fair value of commodity derivatives
Derivative Assets	127	121
Commodity contracts | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	66	51
Commodity contracts | Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	-150	-154
Commodity contracts | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	-27	-13
FTRs | Current Assets
Fair value of commodity derivatives
Derivative Assets	6	38
FTRs | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	1	1
FTRs | Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	-4	-13
FTRs | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	-1	-1
NUGs | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	2	2
NUGs | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	($150)	($153)

Derivative_Instruments_Details1

Derivative Instruments (Details 1) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Derivative Assets
Fair Value	$202	$213
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	-161	-140
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	41	73
Derivative Liabilities
Fair Value	-332	-334
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	161	140
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	16	35
Net Fair Value	-155	-159
Commodity contracts
Derivative Assets
Fair Value	193	172
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	-156	-126
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	37	46
Derivative Liabilities
Fair Value	-177	-167
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	156	126
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	16	35
Net Fair Value	-5	-6
FTRs
Derivative Assets
Fair Value	7	39
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	-5	-14
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	2	25
Derivative Liabilities
Fair Value	-5	-14
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	5	14
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	0	0
NUGs
Derivative Assets
Fair Value	2	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	2	2
Derivative Liabilities
Fair Value	-150	-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	($150)	($153)

Derivative_Instruments_Details2

Derivative Instruments (Details 2)	Mar. 31, 2015
	MWh
Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	22,000,000
Sales (in MWH or mmBTUs)	42,000,000
Net (in MWH or mmBTUs)	-20,000,000
FTRs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	22,000,000
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	22,000,000
NUGs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	5,000,000
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	5,000,000
Natural Gas
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	32,000,000
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	32,000,000

Derivative_Instruments_Details3

Derivative Instruments (Details 3) (Not Designated as Hedging Instrument, USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 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	$36	$39
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	-3	436
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	17
Realized Gain (Loss) Reclassified	-13	-7
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	-16	9
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	-1	-13
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	-3	436
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	12
Realized Gain (Loss) Reclassified	0	0
Commodity contracts | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	-16	9
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	37	52
FTRs | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	0	0
FTRs | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	-13	5
Realized Gain (Loss) Reclassified	-13	-7
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
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	-1	-13
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	-3	436
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	12
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	36	51
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	-12	5
Realized Gain (Loss) Reclassified	-13	-7
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	($22)	($321)

Derivative_Instruments_Details4

Derivative Instruments (Details 5) (Not Designated as Hedging Instrument, USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	($140)	($202)
Unrealized gain (loss)	-7	31
Settlements	0	-11
Outstanding net asset (liability), Ending Balance	-147	-182
NUGs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	-151	-202
Unrealized gain (loss)	-8	27
Settlements	11	-10
Outstanding net asset (liability), Ending Balance	-148	-185
Regulated FTRs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	11	0
Unrealized gain (loss)	1	4
Settlements	-11	-1
Outstanding net asset (liability), Ending Balance	$1	$3

Derivative_Instruments_Details5

Derivative Instruments (Details Textuals) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Unamortized gains or losses associated with designated cash flow hedges	$9,000,000	$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	48,000,000	50,000,000
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	29,000,000	32,000,000
Possible adverse change in quoted market prices of derivative instruments	10.00%
Possible increase net income due to ten percent adverse change in commodity prices	15,000,000
Net asset position	41,000,000	73,000,000
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	16,000,000
Net asset position	37,000,000	46,000,000
NUGs
Derivative [Line Items]
Net liability position	148,000,000
Net asset position	2,000,000	2,000,000
FTRs
Derivative [Line Items]
Net asset position	2,000,000	25,000,000
FES | Commodity contracts
Derivative [Line Items]
Net asset position under commodity derivative contracts	16,000,000
Collateral posted	71,000,000
Additional collateral related to commodity derivatives	6,000,000
FES | FTRs
Derivative [Line Items]
Collateral posted	5,000,000
Net asset position	1,000,000
Cash Flow Hedges
Derivative [Line Items]
Number of forward starting swap agreements accounted for as a cash flow hedge outstanding	0	0
Losses to be amortized to interest expenses during next twelve months	-9,000,000
Number of outstanding commodity or interest rate derivatives		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		0
Number of fixed-for-floating interest rate swap agreements outstanding	0	0
Reclassifications from long-term debt	$3,000,000

Regulatory_Matters_Details

Regulatory Matters (Details) (USD $)

3 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

Mar. 31, 2015

Mar. 31, 2014

Aug. 24, 2012

Mar. 03, 2014

Feb. 27, 2013

Dec. 31, 2009

Mar. 26, 2015

Apr. 01, 2015

Aug. 07, 2013

Dec. 31, 2013

Oct. 10, 2013

Sep. 30, 2013

Dec. 31, 2010

Apr. 09, 2015

Aug. 04, 2014

Feb. 03, 2013

Oct. 31, 2006

Mar. 14, 2013

entities

order

proposals

Proceedings

Regulatory Matters [Line Items]

Amortization (deferral) of regulatory assets, net

$32,000,000

($28,000,000)

Regional enforcement entities

8

FERC

Regulatory Matters [Line Items]

Denied recovery charges of exit fees

78,800,000

FERC | PATH

Regulatory Matters [Line Items]

Proposed return on equity

10.90%

Base return on equity

10.40%

Return on equity granted for regional transmission organization participation

0.50%

Remaining recovery period of regulatory assets

5 years

FERC | PATH-Allegheny

Regulatory Matters [Line Items]

Cost recovery, PP&E reclassified to Regulatory Assets

62,000,000

FERC | Path-WV

Regulatory Matters [Line Items]

Cost recovery, PP&E reclassified to Regulatory Assets

59,000,000

Maryland

Regulatory Matters [Line Items]

Proposed electric consumption reduction percentage

10.00%

Proposed electric demand reduction percentage

15.00%

Expenditures for cost recovery program

64,000,000

Recovery period for expenditures for cost recovery program

5 years

3 years

Number of orders to be filed

2

Expected infrastructure investments

2,700,000,000

Period of expected infrastructure investments

15 years

New Jersey

Regulatory Matters [Line Items]

Number of supply components

2

Number of basic generation services

1

New Jersey | Board Of Public Utilities | Final Order Base Rate Case | JCP&L

Regulatory Matters [Line Items]

Approved increase (decrease)

-115,000,000

New Jersey | Board Of Public Utilities | Final Order Base Rate Case | 2011 Storm Costs | JCP&L

Regulatory Matters [Line Items]

Approved increase (decrease)

-2,000,000

New Jersey | Board Of Public Utilities | Generic CTA Proceedings | JCP&L

Regulatory Matters [Line Items]

Approved increase (decrease)

-5,000,000

New Jersey | Board Of Public Utilities | Major Storm Events | JCP&L

Regulatory Matters [Line Items]

Approved increase (decrease)

81,000,000

Recovery period

6 years

Approved carrying charge (percent)

2.52%

New Jersey | Board Of Public Utilities | Major Storm Events | JCP&L | Subsequent Event

Regulatory Matters [Line Items]

Approved increase (decrease)

-34,000,000

New Jersey | Board Of Public Utilities | Major Storm Events | 2012 Storm Costs | JCP&L

Regulatory Matters [Line Items]

Approved increase (decrease)

580,000,000

Ohio

Regulatory Matters [Line Items]

Generation discount for low income customers

6.00%

Recovery period

5 years

Costs avoided by customers

360,000,000

ESP extension term

2 years

Generation supply auction period, after approval

3 years

Generation supply auction period, before approval

1 year

Term of economic development and assistance plan

3 years

Term of proposed purchase power agreement

15 years

Annual revenue cap for rider

30,000,000

Estimated cost of portfolio plan

250,000,000

Portion of revenue obtained to be received

20.00%

Credit to non-shopping customers

43,400,000

Ohio | Year 2017

Regulatory Matters [Line Items]

Annual increase in energy savings (percent)

1.00%

Ohio | Year 2015

Regulatory Matters [Line Items]

Annual energy savings

2,266,000

Ohio | Year 2016

Regulatory Matters [Line Items]

Annual energy savings

2,288,000

Ohio | Annually Through 2014

Regulatory Matters [Line Items]

Utilities required to additionally reduce peak demand

0.75%

Ohio | Public Utilities Commission Of Ohio

Regulatory Matters [Line Items]

Number of renewable energy auctions

1

Amortization (deferral) of regulatory assets, net

51,000,000

Pennsylvania

Regulatory Matters [Line Items]

Marginal transmission refund period

29 months

Marginal transmission losses

254,000,000

Asset impairment charges

254,000,000

Number of requests for proposal

1

Request for proposal project term

2 years

Pennsylvania | Subsequent Event

Regulatory Matters [Line Items]

Approved settlement additional operating expenses

87,700,000

Pennsylvania | WP

Regulatory Matters [Line Items]

Amount of requested rate increase (decrease)

115,500,000

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 | 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

Pennsylvania | Unfavorable Regulatory Action

Regulatory Matters [Line Items]

Maximum range of possible loss

234,000,000

West Virginia

Regulatory Matters [Line Items]

Amount of requested rate increase (decrease)

292,800,000

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 | Penn

Regulatory Matters [Line Items]

Amount of requested rate increase (decrease)

15,900,000

West Virginia | Public Utility Commission of West Virginia | MP and PE

Regulatory Matters [Line Items]

Deferred storm and property reserve deficiency

46,000,000

Amount of requested rate increase (decrease)

15,000,000

California Claims Matters | FERC

Regulatory Matters [Line Items]

Settlement proposal claims

$190,000,000

Court proceedings from filed claims

1

West Virginia | Public Utility Commission of West Virginia | MP and PE

Regulatory Matters [Line Items]

Recovery period

5 years

Commitments_Guarantees_and_Con2

Commitments, Guarantees and Contingencies (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2015
Guarantor Obligations [Line Items]
Guarantor obligations		$711,000,000
FES
Guarantor Obligations [Line Items]
Guarantor obligations		583,000,000
AE Supply
Guarantor Obligations [Line Items]
Guarantor obligations		50,000,000
Utilities
Guarantor Obligations [Line Items]
Guarantor obligations		78,000,000
Split Rating
Guarantor Obligations [Line Items]
Guarantor obligations		476,000,000
Split Rating | FES
Guarantor Obligations [Line Items]
Guarantor obligations		427,000,000
Split Rating | AE Supply
Guarantor Obligations [Line Items]
Guarantor obligations		6,000,000
Split Rating | Utilities
Guarantor Obligations [Line Items]
Guarantor obligations		43,000,000
Fitch, BB Plus Moody's, Ba1 Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations		514,000,000
Fitch, BB Plus Moody's, Ba1 Credit Rating | FES
Guarantor Obligations [Line Items]
Guarantor obligations		465,000,000
Fitch, BB Plus Moody's, Ba1 Credit Rating | AE Supply
Guarantor Obligations [Line Items]
Guarantor obligations		6,000,000
Fitch, BB Plus Moody's, Ba1 Credit Rating | Utilities
Guarantor Obligations [Line Items]
Guarantor obligations		43,000,000
ICG Litigation
Guarantor Obligations [Line Items]
Gain (Loss) Related to Litigation Settlement	15,000,000
ICG Litigation | AE Supply
Guarantor Obligations [Line Items]
Gain (Loss) Related to Litigation Settlement	12,000,000
ICG Litigation | MP
Guarantor Obligations [Line Items]
Gain (Loss) Related to Litigation Settlement	$3,000,000

Commitments_Guarantees_and_Con3

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

3 Months Ended

0 Months Ended

39 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

Mar. 31, 2015

Mar. 31, 2014

Apr. 19, 2013

Oct. 03, 2013

Mar. 31, 2015

31-May-14

Jul. 31, 2008

Jun. 30, 2014

Oct. 10, 2013

Mar. 14, 2015

Dec. 31, 2011

Dec. 31, 2014

Apr. 30, 2015

Sep. 30, 2013

Jun. 30, 2013

Oct. 31, 2012

Complaints

IndividualsInAComplaint

T

MW

lb

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

$4,000,000,000

$4,000,000,000

New syndicated senior secured term loan facility

711,000,000

711,000,000

Long-term debt

48,000,000

489,000,000

Nuclear plant decommissioning trusts

2,360,000,000

2,360,000,000

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

8

Number of preferred treatment 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

Accrual for environmental loss contingencies

125,000,000

125,000,000

Environmental liabilities former gas facilities

85,000,000

85,000,000

Nuclear Plant Matters

Guarantor Obligations [Line Items]

Nuclear plant decommissioning trusts

2,400,000,000

2,400,000,000

Parental guarantee associated with the funding of decommissioning costs

155,000,000

155,000,000

Parental guarantee

23,000,000

23,000,000

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

20 years

Caa Compliance

Guarantor Obligations [Line Items]

Loss in period

145,000,000

Caa Compliance | Subsequent Event

Guarantor Obligations [Line Items]

Amount of coal-fired plants deactivated

5,429

National Ambient Air Quality Standards

Guarantor Obligations [Line Items]

Capping of SO2 emissions under CSAPR

2,400,000

Capping of NOx emissions under CSAPR

1,200,000

National Ambient Air Quality Standards | CSAPR

Guarantor Obligations [Line Items]

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

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

1,000

Proposed emissions standard other natural gas fired units

1,100

Proposed emissions standard fossil fuel fired units

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

3,000,000

3,000,000

Regulated Distribution | Caa Compliance

Guarantor Obligations [Line Items]

Loss in period

87,000,000

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

58,000,000

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

279,000,000

279,000,000

Potential collateral posted related to net liability positions

17,000,000

17,000,000

New syndicated senior secured term loan facility

583,000,000

583,000,000

Long-term debt

17,000,000

445,000,000

Nuclear plant decommissioning trusts

1,381,000,000

1,381,000,000

1,365,000,000

AE Supply

Guarantor Obligations [Line Items]

New syndicated senior secured term loan facility

50,000,000

50,000,000

AE Supply | ICG Litigation

Guarantor Obligations [Line Items]

Gain contingency, damages denied

12,000,000

Global Holding

Guarantor Obligations [Line Items]

Senior secured term loan facility, term

3 years

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

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%

Signal Peak and Global Rail

Guarantor Obligations [Line Items]

Senior secured term loan facility, term

2 years

FEV | Global Holding

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

54,000,000

54,000,000

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

0

248,000,000

Nuclear plant decommissioning trusts

0

0

0

FGCO | Caa Compliance

Guarantor Obligations [Line Items]

Number of complaints seek enjoin plant

2

Power plants complaints

3

FGCO | Caa Compliance | Claim One

Guarantor Obligations [Line Items]

Number of complaints seek enjoin plant

1

Number of individuals behalf of which complaint filed

21

FGCO | Caa Compliance | Claim Two

Guarantor Obligations [Line Items]

Number of named plaintiffs as class representatives

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

6,000,000

6,000,000

Pending Litigation | Regulation of Waste Disposal | West Virginia

Guarantor Obligations [Line Items]

Number of individuals behalf of which complaint filed

61

Pending Litigation | Regulation of Waste Disposal | Pennsylvania

Guarantor Obligations [Line Items]

Comment period

60 days

FirstEnergy

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

621,000,000

621,000,000

Subsidiaries

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

2,338,000,000

2,338,000,000

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

$729,000,000

$729,000,000

Put Option | FEV | Signal Peak

Guarantor Obligations [Line Items]

Derivative notional amount mass (tons)

2,000,000

Supplemental_Guarantor_Informa2

Supplemental Guarantor Information (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2007
Condensed Financial Statements, Captions [Line Items]
Tax effect of discontinued operations	$0		$69
Consolidating Statements of Income
Revenues	3,897	[1]	4,182	[1]
OPERATING EXPENSES:
Fuel	513		617
Purchased power	1,113		1,455
Other operating expenses	1,057		1,182
Provision for depreciation	319		294
General taxes	269		271
Total operating expenses	3,303		3,791
OPERATING INCOME (LOSS)	594		391
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		-7
Investment income	17		22
Interest expense	-279		-265
Capitalized interest	34		29
Total other income (expense)	-228		-221
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	366		170
INCOME TAXES (BENEFITS)	144		48
INCOME (LOSS) FROM CONTINUING OPERATIONS	222		122
Discontinued operations	0		86
NET INCOME (LOSS)	222		208
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)	222		208
Pension and OPEB prior service costs	-31		-42
Amortized loss (gain) on derivative hedges	1		0
Change in unrealized gain on available-for-sale securities	4		21
Other comprehensive income (loss)	-26		-21
Income taxes (benefits) on other comprehensive income (loss)	-10		-8
Other comprehensive income (loss), net of tax	-16		-13
COMPREHENSIVE INCOME (LOSS)	206		195
FES
Consolidating Statements of Income
Revenues	1,332		1,797
OPERATING EXPENSES:
Fuel	0		0
Other operating expenses	180		228
Provision for depreciation	3		2
General taxes	15		21
Total operating expenses	1,698		1,921
OPERATING INCOME (LOSS)	-366		-124
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		-3
Investment income	241		104
Capitalized interest	0		0
Total other income (expense)	222		84
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	-144		-40
INCOME TAXES (BENEFITS)	-141		-52
INCOME (LOSS) FROM CONTINUING OPERATIONS			12
Discontinued operations			0
NET INCOME (LOSS)	-3		12
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)	-3		12
Pension and OPEB prior service costs	-4		-5
Amortized loss (gain) on derivative hedges	-1		-2
Change in unrealized gain on available-for-sale securities	3		19
Other comprehensive income (loss)	-2		12
Income taxes (benefits) on other comprehensive income (loss)	-1		4
Other comprehensive income (loss), net of tax	-1		8
COMPREHENSIVE INCOME (LOSS)	-4		20
FES | Affiliates
OPERATING EXPENSES:
Purchased power	957		645
OTHER INCOME (EXPENSE):
Interest expense	-6		-3
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power	543		1,025
OTHER INCOME (EXPENSE):
Interest expense	-13		-14
FGCO
Condensed Financial Statements, Captions [Line Items]
Tax effect of discontinued operations	0		70
Consolidating Statements of Income
Revenues	493		315
OPERATING EXPENSES:
Fuel	180		272
Other operating expenses	67		62
Provision for depreciation	30		29
General taxes	8		11
Total operating expenses	285		378
OPERATING INCOME (LOSS)	208		-63
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		-1
Investment income	3		1
Capitalized interest	1		1
Total other income (expense)	-24		-24
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	184		-87
INCOME TAXES (BENEFITS)	67		-31
INCOME (LOSS) FROM CONTINUING OPERATIONS			-56
Discontinued operations			116
NET INCOME (LOSS)	117		60
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)	117		60
Pension and OPEB prior service costs	-4		-4
Amortized loss (gain) on derivative hedges	0		0
Change in unrealized gain on available-for-sale securities	0		0
Other comprehensive income (loss)	-4		-4
Income taxes (benefits) on other comprehensive income (loss)	-1		-2
Other comprehensive income (loss), net of tax	-3		-2
COMPREHENSIVE INCOME (LOSS)	114		58
FGCO | Affiliates
OPERATING EXPENSES:
Purchased power	0		0
OTHER INCOME (EXPENSE):
Interest expense	-2		-1
FGCO | Non-Affiliates
OPERATING EXPENSES:
Purchased power	0		4
OTHER INCOME (EXPENSE):
Interest expense	-26		-24
Nuclear Generation Corp
Consolidating Statements of Income
Revenues	507		362
OPERATING EXPENSES:
Fuel	50		47
Other operating expenses	154		150
Provision for depreciation	48		43
General taxes	6		7
Total operating expenses	326		311
OPERATING INCOME (LOSS)	181		51
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		-1
Investment income	14		21
Capitalized interest	8		11
Total other income (expense)	8		17
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	189		68
INCOME TAXES (BENEFITS)	70		26
INCOME (LOSS) FROM CONTINUING OPERATIONS			42
Discontinued operations			0
NET INCOME (LOSS)	119		42
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)	119		42
Pension and OPEB prior service costs	3		0
Amortized loss (gain) on derivative hedges	0		0
Change in unrealized gain on available-for-sale securities	0		19
Other comprehensive income (loss)	3		19
Income taxes (benefits) on other comprehensive income (loss)	1		7
Other comprehensive income (loss), net of tax	2		12
COMPREHENSIVE INCOME (LOSS)	121		54
Nuclear Generation Corp | Affiliates
OPERATING EXPENSES:
Purchased power	68		64
OTHER INCOME (EXPENSE):
Interest expense	-1		-1
Nuclear Generation Corp | Non-Affiliates
OPERATING EXPENSES:
Purchased power	0		0
OTHER INCOME (EXPENSE):
Interest expense	-13		-13
Eliminations
Consolidating Statements of Income
Revenues	-955		-645
OPERATING EXPENSES:
Fuel	0		0
Other operating expenses	12		12
Provision for depreciation	-1		0
General taxes	0		0
Total operating expenses	-944		-633
OPERATING INCOME (LOSS)	-11		-12
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		0
Investment income	-245		-106
Capitalized interest	0		0
Total other income (expense)	-223		-88
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	-234		-100
INCOME TAXES (BENEFITS)	2		1
INCOME (LOSS) FROM CONTINUING OPERATIONS			-101
Discontinued operations			0
NET INCOME (LOSS)	-236		-101
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)	-236		-101
Pension and OPEB prior service costs	1		4
Amortized loss (gain) on derivative hedges	0		0
Change in unrealized gain on available-for-sale securities	0		-19
Other comprehensive income (loss)	1		-15
Income taxes (benefits) on other comprehensive income (loss)	0		-5
Other comprehensive income (loss), net of tax	1		-10
COMPREHENSIVE INCOME (LOSS)	-235		-111
Eliminations | Affiliates
OPERATING EXPENSES:
Purchased power	-955		-645
OTHER INCOME (EXPENSE):
Interest expense	7		3
Eliminations | Non-Affiliates
OPERATING EXPENSES:
Purchased power	0		0
OTHER INCOME (EXPENSE):
Interest expense	15		15
FES
Condensed Financial Statements, Captions [Line Items]
Tax effect of discontinued operations	0		70
Consolidating Statements of Income
Revenues	1,377		1,829
OPERATING EXPENSES:
Fuel	230		319
Other operating expenses	413		452
Provision for depreciation	80		74
General taxes	29		39
Total operating expenses	1,365		1,977
OPERATING INCOME (LOSS)	12		-148
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		-5
Investment income	13		20
Capitalized interest	9		12
Total other income (expense)	-17		-11
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS)	-5		-159
INCOME TAXES (BENEFITS)	-2		-56
INCOME (LOSS) FROM CONTINUING OPERATIONS	-3		-103
Discontinued operations	0		116
NET INCOME (LOSS)	-3		13
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)	-3		13
Pension and OPEB prior service costs	-4		-5
Amortized loss (gain) on derivative hedges	-1		-2
Change in unrealized gain on available-for-sale securities	3		19
Other comprehensive income (loss)	-2		12
Income taxes (benefits) on other comprehensive income (loss)	-1		4
Other comprehensive income (loss), net of tax	-1		8
COMPREHENSIVE INCOME (LOSS)	-4		21
FES | Affiliates
OPERATING EXPENSES:
Purchased power	70		64
OTHER INCOME (EXPENSE):
Interest expense	-2		-2
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power	543		1,029
OTHER INCOME (EXPENSE):
Interest expense	($37)		($36)
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 $115 million and $117 million in the three months ended MarchB 31, 2015 and 2014.

Supplemental_Guarantor_Informa3

Supplemental Guarantor Information (Details 1) (USD $)	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
CURRENT ASSETS:
Cash and cash equivalents	$90	$85	$109	$218
Receivables-
Customers	1,675	1,554
Other Receivables	201	225
Materials and supplies	762	817
Derivatives	133	159
Collateral	220	230
Prepayments and other	157	160
Total current assets	4,011	3,876
PROPERTY, PLANT AND EQUIPMENT:
In service	47,992	47,484
Less - Accumulated provision for depreciation	14,508	14,150
Property, plant and equipment in service net of accumulated provision for depreciation	33,484	33,334
Construction work in progress	2,633	2,449
Total net property, plant and equipment	36,117	35,783
INVESTMENTS:
Nuclear plant decommissioning trusts	2,360	2,341
Other	898	881
Total other property and investments	3,258	3,222
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418	6,418
Other	1,345	1,456
Total deferred charges and other assets	9,135	9,285
Total assets	52,521	52,166	51,228
CURRENT LIABILITIES:
Currently payable long-term debt	787	804
Other	2,559	1,799
Accounts payable-
Accrued taxes	503	490
Derivatives	154	167
Other	908	693
Total current liabilities	6,262	5,561
CAPITALIZATION:
Total common stockholders' equity	12,348	12,420
Long-term debt and other long-term obligations	19,130	19,176
Total capitalization	31,480	31,598
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	816	824
Accumulated deferred income taxes	7,211	7,057
Asset retirement obligations	1,390	1,387
Retirement benefits	3,817	3,932
Other	1,332	1,590
Total noncurrent liabilities	14,779	15,007
Total liabilities and capitalization	52,521	52,166
FES
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	351	415
Affiliated companies	507	484
Other Receivables	71	66
Notes receivable from affiliated companies	333	339
Materials and supplies	46	67
Derivatives	132	147
Collateral	217	229
Prepayments and other	83	56
Total current assets	1,740	1,803
PROPERTY, PLANT AND EQUIPMENT:
In service	134	133
Less - Accumulated provision for depreciation	39	36
Property, plant and equipment in service net of accumulated provision for depreciation	95	97
Construction work in progress	3	3
Total net property, plant and equipment	98	100
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	6,847	6,607
Other	0	0
Total other property and investments	6,847	6,607
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	344	276
Customer intangibles	74	78
Goodwill	23	23
Property taxes	0	0
Unamortized sale and leaseback costs	0	0
Derivatives	67	52
Other	31	34
Total deferred charges and other assets	539	463
Total assets	9,224	8,973
CURRENT LIABILITIES:
Currently payable long-term debt	0	18
Other	275	90
Accounts payable-
Affiliated companies	652	1,068
Other	84	46
Accrued taxes	5	2
Derivatives	154	166
Other	44	72
Total current liabilities	2,838	2,597
CAPITALIZATION:
Total common stockholders' equity	5,581	5,585
Long-term debt and other long-term obligations	695	695
Total capitalization	6,276	6,280
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	13	13
Asset retirement obligations	0	0
Retirement benefits	36	36
Derivatives	28	14
Other	33	33
Total noncurrent liabilities	110	96
Total liabilities and capitalization	9,224	8,973
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	1,624	1,135
FGCO
CURRENT ASSETS:
Cash and cash equivalents	2	2	2	2
Receivables-
Customers	0	0
Affiliated companies	357	487
Other Receivables	2	21
Notes receivable from affiliated companies	1,017	838
Materials and supplies	181	202
Derivatives	0	0
Collateral	0	0
Prepayments and other	34	41
Total current assets	1,593	1,591
PROPERTY, PLANT AND EQUIPMENT:
In service	6,296	6,217
Less - Accumulated provision for depreciation	2,085	2,058
Property, plant and equipment in service net of accumulated provision for depreciation	4,211	4,159
Construction work in progress	162	206
Total net property, plant and equipment	4,373	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	7	76
Customer intangibles	0	0
Goodwill	0	0
Property taxes	11	14
Unamortized sale and leaseback costs	0	0
Derivatives	0	0
Other	275	277
Total deferred charges and other assets	293	367
Total assets	6,269	6,333
CURRENT LIABILITIES:
Currently payable long-term debt	166	164
Other	9	9
Accounts payable-
Affiliated companies	180	197
Other	72	202
Accrued taxes	43	62
Derivatives	0	0
Other	63	56
Total current liabilities	849	1,011
CAPITALIZATION:
Total common stockholders' equity	2,677	2,561
Long-term debt and other long-term obligations	2,212	2,215
Total capitalization	4,889	4,776
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	0	0
Asset retirement obligations	190	189
Retirement benefits	291	288
Derivatives	0	0
Other	50	69
Total noncurrent liabilities	531	546
Total liabilities and capitalization	6,269	6,333
FGCO | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	316	321
Nuclear Generation Corp
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	313	674
Other Receivables	79	20
Notes receivable from affiliated companies	634	272
Materials and supplies	220	223
Derivatives	0	0
Collateral	0	0
Prepayments and other	0	0
Total current assets	1,246	1,189
PROPERTY, PLANT AND EQUIPMENT:
In service	7,659	7,628
Less - Accumulated provision for depreciation	3,399	3,305
Property, plant and equipment in service net of accumulated provision for depreciation	4,260	4,323
Construction work in progress	892	801
Total net property, plant and equipment	5,152	5,124
INVESTMENTS:
Nuclear plant decommissioning trusts	1,381	1,365
Investment in affiliated companies	0	0
Other	0	0
Total other property and investments	1,381	1,365
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	0	0
Goodwill	0	0
Property taxes	20	27
Unamortized sale and leaseback costs	0	0
Derivatives	0	0
Other	6	7
Total deferred charges and other assets	26	34
Total assets	7,805	7,712
CURRENT LIABILITIES:
Currently payable long-term debt	348	348
Other	0	0
Accounts payable-
Affiliated companies	249	219
Other	0	0
Accrued taxes	92	161
Derivatives	0	0
Other	17	9
Total current liabilities	706	765
CAPITALIZATION:
Total common stockholders' equity	4,135	4,014
Long-term debt and other long-term obligations	859	859
Total capitalization	4,994	4,873
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	710	678
Asset retirement obligations	648	652
Retirement benefits	0	0
Derivatives	0	0
Other	747	744
Total noncurrent liabilities	2,105	2,074
Total liabilities and capitalization	7,805	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	-636	-1,120
Other Receivables	0	0
Notes receivable from affiliated companies	-1,940	-1,449
Materials and supplies	0	0
Derivatives	0	0
Collateral	0	0
Prepayments and other	0	-2
Total current assets	-2,576	-2,571
PROPERTY, PLANT AND EQUIPMENT:
In service	-383	-382
Less - Accumulated provision for depreciation	-192	-191
Property, plant and equipment in service net of accumulated provision for depreciation	-191	-191
Construction work in progress	0	0
Total net property, plant and equipment	-191	-191
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	-6,847	-6,607
Other	0	0
Total other property and investments	-6,847	-6,607
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	-351	-352
Customer intangibles	0	0
Goodwill	0	0
Property taxes	0	0
Unamortized sale and leaseback costs	248	217
Derivatives	0	0
Other	-204	-204
Total deferred charges and other assets	-307	-339
Total assets	-9,921	-9,708
CURRENT LIABILITIES:
Currently payable long-term debt	-24	-24
Other	0	0
Accounts payable-
Affiliated companies	-652	-1,068
Other	0	0
Accrued taxes	-55	-123
Derivatives	0	0
Other	82	47
Total current liabilities	-2,589	-2,617
CAPITALIZATION:
Total common stockholders' equity	-6,812	-6,575
Long-term debt and other long-term obligations	-1,161	-1,161
Total capitalization	-7,973	-7,736
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	816	824
Accumulated deferred income taxes	-175	-180
Asset retirement obligations	0	0
Retirement benefits	0	0
Derivatives	0	0
Other	0	1
Total noncurrent liabilities	641	645
Total liabilities and capitalization	-9,921	-9,708
Eliminations | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	-1,940	-1,449
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2	2	2
Receivables-
Customers	351	415
Affiliated companies	541	525
Other Receivables	152	107
Notes receivable from affiliated companies	44	0
Materials and supplies	447	492
Derivatives	132	147
Collateral	217	229
Prepayments and other	117	95
Total current assets	2,003	2,012
PROPERTY, PLANT AND EQUIPMENT:
In service	13,706	13,596
Less - Accumulated provision for depreciation	5,331	5,208
Property, plant and equipment in service net of accumulated provision for depreciation	8,375	8,388
Construction work in progress	1,057	1,010
Total net property, plant and equipment	9,432	9,398
INVESTMENTS:
Nuclear plant decommissioning trusts	1,381	1,365
Investment in affiliated companies	0	0
Other	10	10
Total other property and investments	1,391	1,375
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	74	78
Goodwill	23	23
Property taxes	31	41
Unamortized sale and leaseback costs	248	217
Derivatives	67	52
Other	108	114
Total deferred charges and other assets	551	525
Total assets	13,377	13,310
CURRENT LIABILITIES:
Currently payable long-term debt	490	506
Other	284	99
Accounts payable-
Affiliated companies	429	416
Other	156	248
Accrued taxes	85	102
Derivatives	154	166
Other	206	184
Total current liabilities	1,804	1,756
CAPITALIZATION:
Total common stockholders' equity	5,581	5,585
Long-term debt and other long-term obligations	2,605	2,608
Total capitalization	8,186	8,193
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	816	824
Accumulated deferred income taxes	548	511
Asset retirement obligations	838	841
Retirement benefits	327	324
Derivatives	28	14
Other	830	847
Total noncurrent liabilities	3,387	3,361
Total liabilities and capitalization	13,377	13,310
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	$0	$35

Supplemental_Guarantor_Informa4

Supplemental Guarantor Information (Details 2) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from (used for) operating activities	$193	($92)
New Financing-
Long-term debt	0	1,467
Short-term borrowings, net	760	0
Redemptions and Repayments-
Long-term debt	-48	-489
Short-term borrowings, net	0	-319
Other	0	-10
Net cash provided from (used for) financing activities	560	498
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	-668	-821
Nuclear fuel	-60	-55
Proceeds from asset sales	10	394
Sales of investment securities held in trusts	371	621
Purchases of investment securities held in trusts	-394	-646
Other	0	3
Net cash provided from (used for) investing activities	-748	-515
Net change in cash and cash equivalents	5	-109
Cash and cash equivalents at beginning of period	85	218
Cash and cash equivalents at end of period	90	109
FES
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from (used for) operating activities	-662	-450
New Financing-
Long-term debt		0
Short-term borrowings, net	674	209
Equity contribution from parent		500
Redemptions and Repayments-
Long-term debt	-17	0
Short-term borrowings, net	0	0
Other		-1
Net cash provided from (used for) financing activities	657	708
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	-1	-2
Nuclear fuel	0	0
Proceeds from asset sales		0
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Loans to affiliated companies, net	6	-254
Other		-2
Net cash provided from (used for) investing activities	5	-258
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
FGCO
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from (used for) operating activities	222	87
New Financing-
Long-term debt		235
Short-term borrowings, net	0	72
Equity contribution from parent		0
Redemptions and Repayments-
Long-term debt	0	-248
Short-term borrowings, net	-5	0
Other	-2	-2
Net cash provided from (used for) financing activities	-7	57
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	-36	-28
Nuclear fuel	0	0
Proceeds from asset sales		307
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Loans to affiliated companies, net	-179	-425
Other		2
Net cash provided from (used for) investing activities	-215	-144
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
Nuclear Generation Corp
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from (used for) operating activities	545	51
New Financing-
Long-term debt		182
Short-term borrowings, net	0	0
Equity contribution from parent		0
Redemptions and Repayments-
Long-term debt	0	-197
Short-term borrowings, net	-28	-151
Other		-1
Net cash provided from (used for) financing activities	-28	-167
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	-82	-268
Nuclear fuel	-60	-55
Proceeds from asset sales		0
Sales of investment securities held in trusts	189	423
Purchases of investment securities held in trusts	-202	-438
Loans to affiliated companies, net	-362	454
Other		0
Net cash provided from (used for) investing activities	-517	116
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
Eliminations
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from (used for) operating activities	0	0
New Financing-
Long-term debt		0
Short-term borrowings, net	-524	-161
Equity contribution from parent		0
Redemptions and Repayments-
Long-term debt	0	0
Short-term borrowings, net	33	151
Other		0
Net cash provided from (used for) financing activities	-491	-10
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	0	0
Nuclear fuel	0	0
Proceeds from asset sales		0
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Loans to affiliated companies, net	491	10
Other		0
Net cash provided from (used for) investing activities	491	10
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
FES
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from (used for) operating activities	105	-312
New Financing-
Long-term debt	0	417
Short-term borrowings, net	150	120
Equity contribution from parent	0	500
Redemptions and Repayments-
Long-term debt	-17	-445
Short-term borrowings, net	0	0
Other	-2	-4
Net cash provided from (used for) financing activities	131	588
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	-119	-298
Nuclear fuel	-60	-55
Proceeds from asset sales	0	307
Sales of investment securities held in trusts	189	423
Purchases of investment securities held in trusts	-202	-438
Loans to affiliated companies, net	-44	-215
Other		0
Net cash provided from (used for) investing activities	-236	-276
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

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2014
Segment Financial Information
Revenues	$3,897		$4,182
Revenues	3,897	[1]	4,182	[1]
Depreciation	319		294
Amortization (deferral) of regulatory assets, net	32		-28
Investment income (loss)	17		22
Interest expense	279		265
Income taxes (benefits)	144		48
Income (loss) from continuing operations	222		122
Discontinued operations	0		86
NET INCOME (LOSS)	222		208
Total assets	52,521		51,228		52,166
Goodwill	6,418		6,418		6,418
Property additions	668		821
Intersegment Eliminations
Segment Financial Information
Revenues	0		0
Regulated Distribution
Segment Financial Information
Revenues	2,562		2,550
Revenues	2,562		2,550
Depreciation	172		162
Amortization (deferral) of regulatory assets, net	29		-31
Investment income (loss)	13		15
Interest expense	144		151
Income taxes (benefits)	122		125
Income (loss) from continuing operations	208		214
Discontinued operations			0
NET INCOME (LOSS)	208		214
Total assets	28,276		27,742
Goodwill	5,092		5,092
Property additions	280		269
Regulated Distribution | Intersegment Eliminations
Segment Financial Information
Revenues	0		0
Regulated Transmission
Segment Financial Information
Revenues	238		182
Revenues	238		182
Depreciation	37		30
Amortization (deferral) of regulatory assets, net	3		3
Investment income (loss)	0		0
Interest expense	39		25
Income taxes (benefits)	42		30
Income (loss) from continuing operations	72		51
Discontinued operations			0
NET INCOME (LOSS)	72		51
Total assets	6,731		5,584
Goodwill	526		526
Property additions	254		217
Regulated Transmission | Intersegment Eliminations
Segment Financial Information
Revenues	0		0
Competitive Energy Services
Segment Financial Information
Revenues	1,175		1,522
Revenues	1,435		1,771
Depreciation	96		91
Amortization (deferral) of regulatory assets, net	0		0
Investment income (loss)	11		14
Interest expense	48		46
Income taxes (benefits)	-4		-73
Income (loss) from continuing operations	-9		-124
Discontinued operations			86
NET INCOME (LOSS)	-9		-38
Total assets	16,733		17,445
Goodwill	800		800
Property additions	126		318
Competitive Energy Services | Intersegment Eliminations
Segment Financial Information
Revenues	260		249
Other/Corporate
Segment Financial Information
Revenues	-42		-35
Revenues	-42		-35
Depreciation	14		11
Amortization (deferral) of regulatory assets, net	0		0
Investment income (loss)	3		3
Interest expense	47		43
Income taxes (benefits)	-18		-26
Income (loss) from continuing operations	-49		-32
Discontinued operations			0
NET INCOME (LOSS)	-49		-32
Total assets	781		457
Goodwill	0		0
Property additions	8		17
Other/Corporate | Intersegment Eliminations
Segment Financial Information
Revenues	0		0
Reconciling Adjustments
Segment Financial Information
Revenues	-36		-37
Revenues	-296		-286
Depreciation	0		0
Amortization (deferral) of regulatory assets, net	0		0
Investment income (loss)	-10		-10
Interest expense	1		0
Income taxes (benefits)	2		-8
Income (loss) from continuing operations	0		13
Discontinued operations			0
NET INCOME (LOSS)	0		13
Total assets	0		0
Goodwill	0		0
Property additions	0		0
Reconciling Adjustments | Intersegment Eliminations
Segment Financial Information
Revenues	($260)		($249)
[1]	Includes excise tax collections of $115 million and $117 million in the three months ended MarchB 31, 2015 and 2014.

Segment_Information_Details_Te

Segment Information (Details Textuals) (USD $)	3 Months Ended
	Mar. 31, 2015
	Customers
	Companies
	MW
	sqmi
Regulated Distribution
Segment Reporting Information [Line Items]
Number of existing utility operating companies	10
Number of customers served by utility operating companies	6,000,000
Number of square miles in service area	65,000
Megawatts of net demonstrated capacity of competitive segment	3,790
Competitive Energy Services
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment	13,169
Competitive Energy Services | Committed Sales
Segment Reporting Information [Line Items]
Committed sales in 2015	70,000,000
Committed sales in 2016	45,000,000
Competitive Energy Services | Minimum
Segment Reporting Information [Line Items]
Targeted sales portfolio	65,000,000
Competitive Energy Services | Maximum
Segment Reporting Information [Line Items]
Targeted sales portfolio	75,000,000
Competitive Energy Services | Governmental Aggregation | Minimum
Segment Reporting Information [Line Items]
Targeted sales portfolio	10,000,000
Competitive Energy Services | Governmental Aggregation | Maximum
Segment Reporting Information [Line Items]
Targeted sales portfolio	15,000,000
Competitive Energy Services | POLR | Minimum
Segment Reporting Information [Line Items]
Targeted sales portfolio	0
Competitive Energy Services | POLR | Maximum
Segment Reporting Information [Line Items]
Targeted sales portfolio	10,000,000
Competitive Energy Services | Large Commercial and Industrial | Minimum
Segment Reporting Information [Line Items]
Targeted sales portfolio	0
Competitive Energy Services | Large Commercial and Industrial | Maximum
Segment Reporting Information [Line Items]
Targeted sales portfolio	20,000,000
Competitive Energy Services | Block Wholesale | Minimum
Segment Reporting Information [Line Items]
Targeted sales portfolio	10,000,000
Competitive Energy Services | Block Wholesale | Maximum
Segment Reporting Information [Line Items]
Targeted sales portfolio	20,000,000
Competitive Energy Services | Spot Wholesale | Minimum
Segment Reporting Information [Line Items]
Targeted sales portfolio	10,000,000
Competitive Energy Services | Spot Wholesale | Maximum
Segment Reporting Information [Line Items]
Targeted sales portfolio	20,000,000
Other/Corporate
Segment Reporting Information [Line Items]
Long-term debt and other long-term obligations	4,200,000,000
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	1,900,000,000

Discontinued_Operations_Detail

Discontinued Operations (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Feb. 12, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales	$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	0	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