FirstEnergy (FE) 10-Q 4 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	9 Months Ended
	Sep. 30, 2016shares
Entity Information [Line Items]
Entity Registrant Name	FIRSTENERGY CORP
Entity Central Index Key	1,031,296
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding	425,743,282
FES
Entity Information [Line Items]
Entity Registrant Name	FirstEnergy Solutions Corp.
Entity Central Index Key	1,407,703
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding	7

Consolidated Statements of Inco

Consolidated Statements of Income (Loss) (FirstEnergy Corp.) - USD ($) shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
REVENUES:
Regulated Distribution		$ 2,702	$ 2,624	$ 7,423	$ 7,425
Regulated Transmission		285	248	824	755
Unregulated businesses		930	1,251	2,940	3,305
Total revenues	[1]	3,917	4,123	11,187	11,485
OPERATING EXPENSES:
Fuel		450	482	1,269	1,378
Purchased power		979	1,209	2,992	3,311
Other operating expenses		953	842	2,835	2,799
Provision for depreciation		311	328	974	969
Amortization of regulatory assets, net		98	110	222	201
General taxes		265	236	786	747
Impairment of assets (Note 2)		0	8	1,447	24
Total operating expenses		3,056	3,215	10,525	9,429
OPERATING INCOME		861	908	662	2,056
OTHER INCOME (EXPENSE):
Investment income (loss)		28	(28)	75	(14)
Interest expense		(286)	(285)	(863)	(846)
Capitalized financing costs		28	26	79	93
Total other expense		(230)	(287)	(709)	(767)
INCOME (LOSS) BEFORE INCOME TAXES		631	621	(47)	1,289
INCOME TAXES		251	226	334	485
NET INCOME (LOSS)		$ 380	$ 395	$ (381)	$ 804
EARNINGS (LOSSES) PER SHARE OF COMMON STOCK:
Basic, in dollars per share		$ 0.89	$ 0.94	$ (0.90)	$ 1.91
Diluted, in dollars per share		$ 0.89	$ 0.93	$ (0.90)	$ 1.90
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic, in shares		425	423	425	422
Diluted, in shares		427	424	425	423
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share		$ 0.72	$ 0.72	$ 1.44	$ 1.44
Excise taxes collected		$ 111	$ 109	$ 310	$ 320
[1]	Includes excise tax collections of $111 million and $109 million in the three months ended September 30, 2016 and 2015, respectively, and $310 million and $320 million in the nine months ended September 30, 2016 and 2015, respectively.

Consolidated Statements of Inc3

Consolidated Statements of Income (Loss) (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Statement [Abstract]
Excise taxes collected	$ 111	$ 109	$ 310	$ 320

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) (FirstEnergy Corp.) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 380	$ 395	$ (381)	$ 804
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(18)	(31)	(54)	(94)
Amortized (gains) losses on derivative hedges	2	2	6	4
Change in unrealized gains on available-for-sale securities	4	(11)	67	(21)
Other comprehensive income (loss)	(12)	(40)	19	(111)
Income taxes (benefits) on other comprehensive income (loss)	(5)	(15)	6	(42)
Other comprehensive income (loss), net of tax	(7)	(25)	13	(69)
COMPREHENSIVE INCOME (LOSS)	$ 373	$ 370	$ (368)	$ 735

Consolidated Balance Sheets (Fi

Consolidated Balance Sheets (FirstEnergy Corp.) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 551	$ 131
Receivables-
Customers, net of allowance for uncollectible accounts of $61 in 2016 and $69 in 2015	1,470	1,415
Other, net of allowance for uncollectible accounts of $3 in 2016 and $5 in 2015	159	180
Materials and supplies	699	785
Prepaid taxes	204	135
Derivatives	152	157
Collateral	89	70
Other	156	167
Total current assets	3,480	3,040
PROPERTY, PLANT AND EQUIPMENT:
In service	50,889	49,952
Less - Accumulated provision for depreciation	15,450	15,160
Property, plant and equipment in service net of accumulated provision for depreciation	35,439	34,792
Construction work in progress	2,394	2,422
Total net property, plant and equipment	37,833	37,214
INVESTMENTS:
Nuclear plant decommissioning trusts	2,502	2,282
Other	533	506
Total other property and investments	3,035	2,788
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill (Note 2)	5,618	6,418
Regulatory assets	1,088	1,348
Other	907	1,286
Total deferred charges and other assets	7,613	9,052
Total assets	51,961	52,094
CURRENT LIABILITIES:
Currently payable long-term debt	1,216	1,166
Short-term borrowings	2,975	1,708
Accounts payable	944	1,075
Accrued taxes	537	519
Accrued compensation and benefits	365	334
Derivatives	91	106
Other	915	694
Total current liabilities	7,043	5,602
Common stockholders' equity-
Common stock, $0.10 par value, authorized 490,000,000 shares - 425,743,282 and 423,560,397 shares outstanding as of September 30, 2016 and December 31, 2015, respectively	43	42
Other paid-in capital	10,012	9,952
Accumulated other comprehensive income	184	171
Retained earnings	1,264	2,256
Total common stockholders' equity	11,503	12,421
Noncontrolling interest	0	1
Total equity	11,503	12,422
Long-term debt and other long-term obligations	18,532	19,099
Total capitalization	30,035	31,521
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	7,136	6,773
Retirement benefits	4,080	4,245
Asset retirement obligations	1,459	1,410
Deferred gain on sale and leaseback transaction	765	791
Adverse power contract liability	174	197
Other	1,269	1,555
Total noncurrent liabilities	14,883	14,971
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 12)
Total liabilities and capitalization	$ 51,961	$ 52,094

Consolidated Balance Sheets (F6

Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Common stockholders' equity-
Common stock, par value (in dollars per share)	$ 0.1	$ 0.1
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	425,743,282	423,560,397
Customer
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 61	$ 69
Other
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 3	$ 5

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (FirstEnergy Corp.) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (381)	$ 804
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets and customer intangible asset amortization	1,440	1,383
Deferred purchased power and other costs	(34)	(73)
Deferred income taxes and investment tax credits, net	318	428
Impairment of assets (Note 2)	1,447	24
Investment impairments	13	70
Deferred costs on sale leaseback transaction, net	36	37
Retirement benefits, net of payments	45	(18)
Pension trust contributions	(297)	(143)
Commodity derivative transactions, net (Note 9)	(10)	(64)
Lease payments on sale and leaseback transaction	(94)	(102)
Changes in current assets and liabilities-
Receivables	(34)	7
Materials and supplies	45	32
Prepayments and other current assets	(28)	(43)
Accounts payable	(17)	(285)
Accrued taxes	(81)	(68)
Accrued interest	36	37
Accrued compensation and benefits	2	16
Other current liabilities	17	26
Cash collateral, net	25	59
Other	132	190
Net cash provided from operating activities	2,580	2,317
New Financing-
Long-term debt	521	1,084
Short-term borrowings, net	1,275	134
Redemptions and Repayments-
Long-term debt	(1,017)	(781)
Common stock dividend payments	(458)	(455)
Other	(5)	(11)
Net cash provided from (used for) financing activities	316	(29)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2,156)	(2,025)
Nuclear fuel	(195)	(101)
Sales of investment securities held in trusts	1,361	1,126
Purchases of investment securities held in trusts	(1,437)	(1,213)
Asset removal costs	(101)	(111)
Other	52	37
Net cash used for investing activities	(2,476)	(2,287)
Net change in cash and cash equivalents	420	1
Cash and cash equivalents at beginning of period	131	85
Cash and cash equivalents at end of period	$ 551	$ 86

Consolidated Statements of Inc8

Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) (FirstEnergy Solutions Corp.) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
REVENUES:
Electric sales		$ 930	$ 1,251	$ 2,940	$ 3,305
Total revenues	[1]	3,917	4,123	11,187	11,485
OPERATING EXPENSES:
Fuel		450	482	1,269	1,378
Purchased power		979	1,209	2,992	3,311
Other operating expenses		953	842	2,835	2,799
Provision for depreciation		311	328	974	969
General taxes		265	236	786	747
Impairment of assets (Note 2)		0	8	1,447	24
Total operating expenses		3,056	3,215	10,525	9,429
OPERATING INCOME		861	908	662	2,056
OTHER INCOME (EXPENSE):
Investment income (loss)		28	(28)	75	(14)
Interest expense		(286)	(285)	(863)	(846)
Capitalized financing costs		28	26	79	93
Total other expense		(230)	(287)	(709)	(767)
INCOME (LOSS) BEFORE INCOME TAXES		631	621	(47)	1,289
INCOME TAXES		251	226	334	485
NET INCOME (LOSS)		380	395	(381)	804
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)		380	395	(381)	804
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(18)	(31)	(54)	(94)
Amortized losses (gains) on derivative hedges		2	2	6	4
Change in unrealized gains on available-for-sale securities		4	(11)	67	(21)
Other comprehensive income (loss)		(12)	(40)	19	(111)
Income taxes (benefits) on other comprehensive income (loss)		(5)	(15)	6	(42)
Other comprehensive income (loss), net of tax		(7)	(25)	13	(69)
COMPREHENSIVE INCOME (LOSS)		373	370	(368)	735
FES
REVENUES:
Other		37	46	124	141
Total revenues		1,100	1,338	3,401	3,834
OPERATING EXPENSES:
Fuel		202	245	595	666
Other operating expenses		316	246	925	996
Provision for depreciation		83	79	250	240
General taxes		21	24	66	78
Impairment of assets (Note 2)		0	0	540	16
Total operating expenses		999	1,098	3,645	3,582
OPERATING INCOME		101	240	(244)	252
OTHER INCOME (EXPENSE):
Investment income (loss)		24	(21)	56	(7)
Miscellaneous income		1	1	4	5
Capitalized financing costs		9	8	27	26
Total other expense		(5)	(50)	(28)	(92)
INCOME (LOSS) BEFORE INCOME TAXES		96	190	(272)	160
INCOME TAXES		56	70	(5)	64
NET INCOME (LOSS)		40	120	(267)	96
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)		40	120	(267)	96
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(3)	(4)	(10)	(12)
Amortized losses (gains) on derivative hedges		1	0	0	(2)
Change in unrealized gains on available-for-sale securities		5	(11)	61	(20)
Other comprehensive income (loss)		3	(15)	51	(34)
Income taxes (benefits) on other comprehensive income (loss)		1	(6)	20	(13)
Other comprehensive income (loss), net of tax		2	(9)	31	(21)
COMPREHENSIVE INCOME (LOSS)		42	111	(236)	75
FES | Affiliates
REVENUES:
Electric sales		111	135	360	547
OPERATING EXPENSES:
Purchased power		191	103	440	250
OTHER INCOME (EXPENSE):
Interest expense		(3)	(2)	(6)	(6)
FES | Non-Affiliates
REVENUES:
Electric sales		952	1,157	2,917	3,146
OPERATING EXPENSES:
Purchased power		186	401	829	1,336
OTHER INCOME (EXPENSE):
Interest expense		$ (36)	$ (36)	$ (109)	$ (110)
[1]	Includes excise tax collections of $111 million and $109 million in the three months ended September 30, 2016 and 2015, respectively, and $310 million and $320 million in the nine months ended September 30, 2016 and 2015, respectively.

Consolidated Balance Sheets (F9

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 551	$ 131
Receivables-
Customers, net of allowance for uncollectible accounts of $6 in 2016 and $8 in 2015	1,470	1,415
Other, net of allowance for uncollectible accounts of $3 in 2016 and 2015	159	180
Materials and supplies	699	785
Derivatives	152	157
Collateral	89	70
Prepayments and other	156	167
Total current assets	3,480	3,040
PROPERTY, PLANT AND EQUIPMENT:
In service	50,889	49,952
Less - Accumulated provision for depreciation	15,450	15,160
Property, plant and equipment in service net of accumulated provision for depreciation	35,439	34,792
Construction work in progress	2,394	2,422
Total net property, plant and equipment	37,833	37,214
INVESTMENTS:
Nuclear plant decommissioning trusts	2,502	2,282
Other	533	506
Total other property and investments	3,035	2,788
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill (Note 2)	5,618	6,418
Other	907	1,286
Total deferred charges and other assets	7,613	9,052
Total assets	51,961	52,094
CURRENT LIABILITIES:
Currently payable long-term debt	1,216	1,166
Other	2,975	1,708
Accounts payable-
Accrued taxes	537	519
Derivatives	91	106
Other	915	694
Total current liabilities	7,043	5,602
Common stockholders' equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of September 30, 2016 and December 31, 2015	43	42
Accumulated other comprehensive income	184	171
Retained earnings	1,264	2,256
Total common stockholders' equity	11,503	12,421
Long-term debt and other long-term obligations	18,532	19,099
Total capitalization	30,035	31,521
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	765	791
Accumulated deferred income taxes	7,136	6,773
Retirement benefits	4,080	4,245
Asset retirement obligations	1,459	1,410
Other	1,269	1,555
Total noncurrent liabilities	14,883	14,971
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 12)
Total liabilities and capitalization	51,961	52,094
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2
Receivables-
Customers, net of allowance for uncollectible accounts of $6 in 2016 and $8 in 2015	225	275
Affiliated companies	482	451
Other, net of allowance for uncollectible accounts of $3 in 2016 and 2015	55	59
Notes receivable from affiliated companies	26	11
Materials and supplies	403	470
Derivatives	146	154
Collateral	85	70
Prepayments and other	72	66
Total current assets	1,496	1,558
PROPERTY, PLANT AND EQUIPMENT:
In service	14,100	14,311
Less - Accumulated provision for depreciation	5,822	5,765
Property, plant and equipment in service net of accumulated provision for depreciation	8,278	8,546
Construction work in progress	1,048	1,157
Total net property, plant and equipment	9,326	9,703
INVESTMENTS:
Nuclear plant decommissioning trusts	1,542	1,327
Other	10	10
Total other property and investments	1,552	1,337
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	11	61
Goodwill (Note 2)	0	23
Property taxes	10	40
Derivatives	98	79
Other	374	367
Total deferred charges and other assets	493	570
Total assets	12,867	13,168
CURRENT LIABILITIES:
Currently payable long-term debt	182	512
Other	0	8
Accounts payable-
Affiliated companies	393	542
Other	89	139
Accrued taxes	72	76
Derivatives	89	104
Other	182	181
Total current liabilities	1,108	1,562
Common stockholders' equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of September 30, 2016 and December 31, 2015	3,653	3,613
Accumulated other comprehensive income	77	46
Retained earnings	1,679	1,946
Total common stockholders' equity	5,409	5,605
Long-term debt and other long-term obligations	2,815	2,510
Total capitalization	8,224	8,115
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	765	791
Accumulated deferred income taxes	734	600
Retirement benefits	219	332
Asset retirement obligations	887	831
Derivatives	50	38
Other	880	899
Total noncurrent liabilities	3,535	3,491
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 12)
Total liabilities and capitalization	12,867	13,168
FES | Affiliated Companies
CURRENT LIABILITIES:
Affiliated companies	$ 101	$ 0

Consolidated Balance Sheets (10

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Common stockholders' equity-
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	425,743,282	423,560,397
Customer
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 61	$ 69
Other Receivables
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 3	$ 5
FES
Common stockholders' equity-
Common stock, shares authorized	750	750
Common stock, shares outstanding	7	7
FES | Customer
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 6	$ 8
FES | Other Receivables
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 3	$ 3

Consolidated Statements of Ca11

Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (381)	$ 804
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets and customer intangible asset amortization	1,440	1,383
Deferred costs on sale and leaseback transaction, net	(36)	(37)
Deferred income taxes and investment tax credits, net	318	428
Investment impairments	13	70
Pension trust contributions	(297)	(143)
Commodity derivative transactions, net (Note 9)	(10)	(64)
Lease payments on sale and leaseback transaction	(94)	(102)
Impairment of assets (Note 2)	1,447	24
Changes in current assets and liabilities-
Receivables	(34)	7
Materials and supplies	45	32
Accounts payable	(17)	(285)
Accrued taxes	(81)	(68)
Accrued compensation and benefits	2	16
Other current liabilities	17	26
Cash collateral, net	25	59
Other	132	190
Net cash provided from operating activities	2,580	2,317
New financing-
Long-term debt	521	1,084
Short-term borrowings, net	1,275	134
Redemptions and Repayments-
Long-term debt	(1,017)	(781)
Other	(5)	(11)
Net cash provided from (used for) financing activities	316	(29)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2,156)	(2,025)
Nuclear fuel	(195)	(101)
Sales of investment securities held in trusts	1,361	1,126
Purchases of investment securities held in trusts	(1,437)	(1,213)
Other	52	37
Net cash used for investing activities	(2,476)	(2,287)
Net change in cash and cash equivalents	420	1
Cash and cash equivalents at beginning of period	131	85
Cash and cash equivalents at end of period	551	86
FES
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	(267)	96
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets and customer intangible asset amortization	463	422
Deferred costs on sale and leaseback transaction, net	(36)	(37)
Deferred income taxes and investment tax credits, net	90	139
Investment impairments	12	63
Pension trust contributions	(138)	0
Commodity derivative transactions, net (Note 9)	(10)	(65)
Lease payments on sale and leaseback transaction	(94)	(102)
Impairment of assets (Note 2)	540	16
Changes in current assets and liabilities-
Receivables	19	171
Materials and supplies	25	(1)
Accounts payable	(69)	(241)
Accrued taxes	(6)	(28)
Accrued compensation and benefits	0	2
Other current liabilities	13	24
Cash collateral, net	6	107
Other	(16)	(4)
Net cash provided from operating activities	604	636
New financing-
Long-term debt	471	339
Short-term borrowings, net	101	0
Redemptions and Repayments-
Long-term debt	(503)	(382)
Short-term borrowings, net	0	109
Other	(7)	(5)
Net cash provided from (used for) financing activities	62	(157)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(432)	(341)
Nuclear fuel	(195)	(101)
Sales of investment securities held in trusts	576	503
Purchases of investment securities held in trusts	(619)	(546)
Cash investments	10	(10)
Loans to affiliated companies, net	(15)	0
Other	9	16
Net cash used for investing activities	(666)	(479)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	2	2
Cash and cash equivalents at end of period	$ 2	$ 2

Organization and Basis of Prese

Organization and Basis of Presentation	9 Months Ended
	Sep. 30, 2016
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 Allegheny Ventures, Inc. FE and its subsidiaries are principally involved in the generation, transmission, and distribution of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving six million customers in the Midwest and Mid-Atlantic regions. Its regulated and unregulated generation subsidiaries control nearly 17,000 MW of capacity from a diverse mix of non-emitting nuclear, scrubbed coal, natural gas, hydroelectric and other renewables. FirstEnergy’s transmission operations include approximately 24,000 miles of lines and two regional transmission operation centers. 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, 2015 . These Notes to the Consolidated Financial Statements are combined for FirstEnergy and FES. 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 as appropriate. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 7, Variable Interest Entities). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, 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 of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). For the three months ended September 30, 2016 and 2015 , capitalized financing costs on FirstEnergy's Consolidated Statements of Income (Loss) include $11 million and $10 million , respectively, of allowance for equity funds used during construction and $17 million and $16 million , respectively, of capitalized interest. For the nine months ended September 30, 2016 and 2015 , capitalized financing costs on FirstEnergy's Consolidated Statements of Income (Loss) include $28 million and $40 million , respectively, of allowance for equity funds used during construction and $51 million and $53 million , respectively, of capitalized interest. During the third quarter of 2016, a reduction to depreciation of $21 million ( $19 million prior to January 1, 2016) was recorded that related to prior periods. The out-of-period adjustment related to the utilization of an accelerated useful life for a component of a certain power station. Management has determined this adjustment is not material to the current period or any prior periods. Strategic Review of Competitive Operations FirstEnergy’s strategy is to be a fully regulated utility focusing on stable and predictable earnings and cash flow from its regulated business units. In order to execute on this strategy, FirstEnergy has begun a strategic review of its competitive operations focused on the sale of gas and hydroelectric units as well as exploring all alternatives for the remaining generation assets at FES and AE Supply. These include, but are not limited to, legislative efforts to convert generation from competitive operations to a regulated or regulated-like construct such as a regulatory restructuring in Ohio, offering generation into any process designed to address MP's generation shortfall included in its IRP, and/or a solution for nuclear generation that recognize their environmental benefits. Management anticipates that the viability of these alternatives will be determined in the near term with a target to implement these strategic options within the next 12 to 18 months and could result in material asset impairments. Based on current market forwards, CES, including FES, expects to have more than sufficient cash flow from operations in 2017 and 2018 to fund anticipated capital expenditures with no equity contributions from FirstEnergy. However, in addition to exposure to market price volatility and operational risks, CES, including FES, faces significant financial risks that could impact its anticipated cash flow and liquidity, including, but not limited to, the following: • Requests to post additional collateral or accelerated payments of up to $355 million resulting from current credit ratings at FES, including Moody's downgrade of the Senior Unsecured debt rating for FES to Caa1 as well as S&P's downgrade of the Senior Unsecured debt rating at FES to B, both of which occurred on November 4, 2016. • Adverse outcomes in the previously disclosed disputes regarding long-term coal transportation contracts. • The inability to extend or refinance debt maturities at CES, including at FES subsidiaries, in 2017 and 2018 of $130 million and $515 million , respectively. A significant collateral call or the inability to refinance 2017 debt maturities at FES subsidiaries is expected to be addressed by FES through a combination of cash on hand, additional capital expenditure reductions, asset sales, and/or borrowings under the unregulated money pool. However, adverse outcomes in the coal transportation contracts disputes, the inability to refinance 2018 debt maturities, or lack of viable alternative strategies could cause FES to take one or more of the following actions: (i) restructuring of debt and other financial obligations, (ii) additional borrowings under the unregulated money pool, (iii) further asset sales or plant deactivations, and/or (iv) seek protection under bankruptcy laws. In the event FES seeks such protection, FENOC may similarly seek protection under bankruptcy laws. Material asset impairments resulting from the sale or deactivation of generation assets or from a determination by management of its intent to exit competitive generation assets before the end of their estimated useful life resulting from the inability to implement alternative strategies discussed above, adverse judgments or a FES bankruptcy filing could result in an event of default under various agreements related to the indebtedness of FE. Although management expects to successfully resolve any FE defaults through waivers or other actions on acceptable terms and conditions, the failure to do so would have a material and adverse impact on FirstEnergy’s financial condition, and FirstEnergy cannot provide any assurance that it will be able to successfully resolve any such defaults on satisfactory terms. New Accounting Pronouncements In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers". Subsequent accounting standards updates have been issued which amend and/or clarify the application of ASU 2014-09. The core principle of the new guidance is that an entity recognizes revenue 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. More detailed disclosures will also be required to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For public business entities, the new revenue recognition guidance will be effective for annual and interim reporting periods beginning after December 15, 2017. Earlier adoption is permitted for annual and interim reporting periods beginning after December 15, 2016. The standards shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting these standards. In February 2015, the FASB issued ASU 2015-02, "Consolidations: Amendments to the Consolidation Analysis", which amends current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate whether an entity should be consolidated. 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's adoption of ASU 2015-02, on January 1, 2016, did not result in a change in the consolidation of VIEs by FE or its subsidiaries. In April 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs", which requires debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. I n addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements", which allows debt issuance costs related to line of credit arrangements to be presented as an asset and amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit. FirstEnergy adopted ASU 2015-15 and ASU 2015-03 beginning January 1, 2016. As of December 31, 2015, FirstEnergy and FES reclassified $93 million and $17 million of debt issuance costs included in Deferred charges and other assets to Long-term debt and Other long-term obligations. FirstEnergy has elected to continue presenting debt issuance costs relating to its revolving credit facilities as an asset. In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities . The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption for certain provisions can be elected for all financial statements of fiscal years and interim periods that have not yet been issued or that have not yet been made available for issuance. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted . Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment . FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In March of 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", which simplifies several aspects of the accounting for employee share-based payment. The new guidance will require all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also will not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted for fiscal years beginning after December 15, 2018. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments". The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted for all entities. FirstEnergy does not expect this ASU to have a material effect on its financial statements. In October 2016, the FASB issued ASU 2016-16, " Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory." ASU 2016-16 eliminates the exception for all intra-entity sales of assets other than inventory, which allows companies to defer the tax effects of intra-entity asset transfers. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the intra-entity transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted and the modified retrospective approach will be required for transition to the new guidance, with a cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. Additionally, during 2016, the FASB issued the following ASUs: • ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships,” • ASU 2016-06, “Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging Issues Task Force)," • ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting," and • ASU 2016-17, “Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control.” FirstEnergy does not expect these ASUs to have a material effect on its financial statements.

Asset Impairments

Asset Impairments	9 Months Ended
	Sep. 30, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Asset Impairments	ASSET IMPAIRMENTS Plant Impairments FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, an impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. FirstEnergy utilizes the income approach, based upon discounted cash flows to estimate fair value. On July 19, 2016, FirstEnergy and FES committed to exit operations of the Bay Shore Unit 1 generating station ( 136 MW) by October 1, 2020, through either sale or deactivation and to deactivate Units 1-4 of the W. H. Sammis generating station ( 720 MW) by May 31, 2020. As a result, FirstEnergy recorded a non-cash pre-tax impairment charge of $647 million ( $517 million - FES) in the second quarter of 2016, which is included in Impairment of assets on the Consolidated Statement of Income (Loss) and included within the results of the CES segment. PJM has approved the W.H Sammis Units 1-4 and Bay Shore Unit 1 deactivations pending review by the Independent Market Monitor. In addition, FirstEnergy and FES recorded termination and settlement costs on fuel contracts of approximately $58 million (pre-tax) in the second quarter of 2016 resulting from plant retirements and deactivations. During the first nine months of 2015, FirstEnergy and FES recognized impairment charges of $24 million and $16 million , respectively, associated with certain transportation equipment and facilities. In order to conform to current year presentation, the charge was reclassified from Other operating expenses in the Consolidated Statement of Income (Loss) to Impairment of assets. Goodwill In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated Transmission, and CES. The following table presents the changes in the carrying value of goodwill for the nine months ended September 30, 2016 : Goodwill Regulated Distribution Regulated Transmission Competitive Energy Services Consolidated (In millions) Balance as of December 31, 2015 $ 5,092 $ 526 $ 800 $ 6,418 Impairment — — (800 ) (800 ) Balance as of September 30, 2016 $ 5,092 $ 526 $ — $ 5,618 FirstEnergy tests goodwill for impairment annually as of July 31 and considers more frequent testing if indicators of potential impairment arise. As a result of low capacity prices associated with the 2019/2020 PJM Base Residual Auction in May 2016, as well as its annual update to its fundamental long-term capacity and energy price forecast, FirstEnergy determined that an interim impairment analysis of the CES reporting unit’s goodwill was necessary during the second quarter of 2016. Consistent with FirstEnergy’s annual goodwill impairment test, a discounted cash flow analysis was used to determine the fair value of the CES reporting unit for purposes of step one of the interim goodwill impairment test. Key assumptions incorporated into the CES discounted cash flow analysis requiring significant management judgment included the following: • Future Energy and Capacity Prices: Observable market information for near-term forward power prices, PJM auction results for near term capacity pricing, and a longer-term fundamental pricing model for energy and capacity that considered the impact of key factors such as load growth, plant retirements, carbon and other environmental regulations, and natural gas pipeline construction, as well as coal and natural gas pricing. • Retail Sales and Margin: CES' current retail targeted portfolio to estimate future retail sales volume as well as historical financial results to estimate retail margins. • Operating and Capital Costs: Estimated future operating and capital costs, including the estimated impact on costs of pending carbon and other environmental regulations, as well as costs associated with capacity performance reforms in the PJM market. • Discount Rate: A discount rate of 9.50% , based on selected comparable companies' capital structure, return on debt and return on equity. • Terminal Value: A terminal value of 7.0x earnings before interest, taxes, depreciation and amortization based on consideration of peer group data and analyst consensus expectations. Based on the impairment analysis, FirstEnergy determined that the carrying value of goodwill exceeded its fair value and recognized a non-cash pre-tax impairment charge of $800 million ( $23 million - FES) in the second quarter of 2016, which is included within the caption Impairment of assets in the Consolidated Statement of Income (Loss). As of July 31, 2016, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial performance. It was determined that the fair value of these reporting units were, more likely than not, greater than their carrying value and a quantitative analysis was not necessary. Termination of Customer Contract During the third quarter of 2016, FES recorded a pre-tax charge of $32 million associated with the termination of a customer contract, which is included in Other operating expenses in the Consolidated Statement of Income (Loss).

Earnings Per Share Of Common St

Earnings Per Share Of Common Stock	9 Months Ended
	Sep. 30, 2016
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) For the Three Months Ended September 30 For the Nine Months Ended September 30 Reconciliation of Basic and Diluted Earnings per Share of Common Stock 2016 2015 2016 2015 Net income (loss) $ 380 $ 395 $ (381 ) $ 804 Weighted average number of basic shares outstanding 425 423 425 422 Assumed exercise of dilutive stock options and awards (1) 2 1 — 1 Weighted average number of diluted shares outstanding 427 424 425 423 Basic earnings (losses) per share of common stock $ 0.89 $ 0.94 $ (0.90 ) $ 1.91 Diluted earnings (losses) per share of common stock $ 0.89 $ 0.93 $ (0.90 ) $ 1.90 (1) For the nine months ended September 30, 2016 , three million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive as a result of the net loss for the period. For the three months ended September 30, 2016 and 2015, and for the nine months ended September 30, 2015, one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

Pension and Other Postemploymen

Pension and Other Postemployment Benefits	9 Months Ended
	Sep. 30, 2016
Compensation and Retirement Disclosure [Abstract]
PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS	PENSION AND OTHER POSTEMPLOYMENT BENEFITS Through October 2016, FirstEnergy satisfied its minimum required funding obligations to its qualified pension plan for the year with contributions of $382 million ($85 million in October 2016), including $138 million at FES. Depending on, among other things, market conditions, FirstEnergy expects to make additional contributions to its qualified pension plan in 2016 of up to $500 million of equity to address its funding obligations for future years. 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 September 30 2016 2015 2016 2015 (In millions) Service costs $ 48 $ 49 $ 2 $ 2 Interest costs 99 96 7 7 Expected return on plan assets (100 ) (111 ) (7 ) (9 ) Amortization of prior service costs (credits) 2 2 (20 ) (33 ) Net periodic costs (credits) $ 49 $ 36 $ (18 ) $ (33 ) Components of Net Periodic Benefit Costs (Credits) Pension OPEB For the Nine Months Ended September 30 2016 2015 2016 2015 (In millions) Service costs $ 144 $ 145 $ 4 $ 4 Interest costs 298 288 22 21 Expected return on plan assets (297 ) (333 ) (23 ) (25 ) Amortization of prior service costs (credits) 6 6 (60 ) (100 ) Net periodic costs (credits) $ 151 $ 106 $ (57 ) $ (100 ) FES' share of the net periodic pension and OPEB costs (credits) were as follows: Pension OPEB 2016 2015 2016 2015 (In millions) For the Three Months Ended September 30 $ 6 $ 4 $ (4 ) $ (5 ) For the Nine Months Ended September 30 18 12 (12 ) (15 ) 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 FirstEnergy and FES were as follows: Net Periodic Benefit Expense (Credit) Pension OPEB For the Three Months Ended September 30 2016 2015 2016 2015 (In millions) FirstEnergy $ 35 $ 25 $ (11 ) $ (21 ) FES 5 4 (4 ) (4 ) Net Periodic Benefit Expense (Credit) Pension OPEB For the Nine Months Ended September 30 2016 2015 2016 2015 (In millions) FirstEnergy $ 107 $ 74 $ (41 ) $ (66 ) FES 17 12 (12 ) (12 )

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	9 Months Ended
	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME	ACCUMULATED OTHER COMPREHENSIVE INCOME The changes in AOCI, net of tax, in the three and nine months ended September 30, 2016 and 2015 , for FirstEnergy are included 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 July 1, 2016 $ (31 ) $ 58 $ 164 $ 191 Other comprehensive income before reclassifications — 21 — 21 Amounts reclassified from AOCI 2 (17 ) (18 ) (33 ) Other comprehensive income (loss) 2 4 (18 ) (12 ) Income taxes (benefits) on other comprehensive income (loss) — 2 (7 ) (5 ) Other comprehensive income (loss), net of tax 2 2 (11 ) (7 ) AOCI Balance as of September 30, 2016 $ (29 ) $ 60 $ 153 $ 184 AOCI Balance as of July 1, 2015 $ (36 ) $ 19 $ 219 $ 202 Other comprehensive loss before reclassifications — (8 ) — (8 ) Amounts reclassified from AOCI 2 (3 ) (31 ) (32 ) Other comprehensive income (loss) 2 (11 ) (31 ) (40 ) Income taxes (benefits) on other comprehensive income (loss) 1 (4 ) (12 ) (15 ) Other comprehensive income (loss), net of tax 1 (7 ) (19 ) (25 ) AOCI Balance as of September 30, 2015 $ (35 ) $ 12 $ 200 $ 177 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, 2016 $ (33 ) $ 18 $ 186 $ 171 Other comprehensive income before reclassifications — 109 — 109 Amounts reclassified from AOCI 6 (42 ) (54 ) (90 ) Other comprehensive income (loss) 6 67 (54 ) 19 Income taxes (benefits) on other comprehensive income (loss) 2 25 (21 ) 6 Other comprehensive income (loss), net of tax 4 42 (33 ) 13 AOCI Balance as of September 30, 2016 $ (29 ) $ 60 $ 153 $ 184 AOCI Balance as of January 1, 2015 $ (37 ) $ 25 $ 258 $ 246 Other comprehensive loss before reclassifications — (1 ) — (1 ) Amounts reclassified from AOCI 4 (20 ) (94 ) (110 ) Other comprehensive income (loss) 4 (21 ) (94 ) (111 ) Income taxes (benefits) on other comprehensive income (loss) 2 (8 ) (36 ) (42 ) Other comprehensive income (loss), net of tax 2 (13 ) (58 ) (69 ) AOCI Balance as of September 30, 2015 $ (35 ) $ 12 $ 200 $ 177 The following amounts were reclassified from AOCI for FirstEnergy in the three and nine months ended September 30, 2016 and 2015 : For the Three Months Ended September 30 For the Nine Months Ended September 30 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2016 2015 2016 2015 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ — $ — $ (2 ) Other operating expenses Long-term debt 2 2 6 6 Interest expense 2 2 6 4 Total before taxes — (1 ) (2 ) (2 ) Income taxes $ 2 $ 1 $ 4 $ 2 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (17 ) $ (3 ) $ (42 ) $ (20 ) Investment income (loss) 7 1 16 7 Income taxes $ (10 ) $ (2 ) $ (26 ) $ (13 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (18 ) $ (31 ) $ (54 ) $ (94 ) (1) 7 12 21 36 Income taxes $ (11 ) $ (19 ) $ (33 ) $ (58 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 4, Pension and Other Postemployment Benefits for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. The changes in AOCI, net of tax, in the three and nine months ended September 30, 2016 and 2015 , for FES are included 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 July 1, 2016 $ (10 ) $ 50 $ 35 $ 75 Other comprehensive income before reclassifications — 22 — 22 Amounts reclassified from AOCI 1 (17 ) (3 ) (19 ) Other comprehensive income (loss) 1 5 (3 ) 3 Income taxes (benefits) on other comprehensive income (loss) — 2 (1 ) 1 Other comprehensive income (loss), net of tax 1 3 (2 ) 2 AOCI Balance as of September 30, 2016 $ (9 ) $ 53 $ 33 $ 77 AOCI Balance as of July 1, 2015 $ (9 ) $ 16 $ 38 $ 45 Other comprehensive loss before reclassifications — (7 ) — (7 ) Amounts reclassified from AOCI — (4 ) (4 ) (8 ) Other comprehensive loss — (11 ) (4 ) (15 ) Income tax benefits on other comprehensive loss — (5 ) (1 ) (6 ) Other comprehensive loss, net of tax — (6 ) (3 ) (9 ) AOCI Balance as of September 30, 2015 $ (9 ) $ 10 $ 35 $ 36 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, 2016 $ (9 ) $ 16 $ 39 $ 46 Other comprehensive income before reclassifications — 102 — 102 Amounts reclassified from AOCI — (41 ) (10 ) (51 ) Other comprehensive income (loss) — 61 (10 ) 51 Income taxes (benefits) on other comprehensive income (loss) — 24 (4 ) 20 Other comprehensive income (loss), net of tax — 37 (6 ) 31 AOCI Balance as of September 30, 2016 $ (9 ) $ 53 $ 33 $ 77 AOCI Balance as of January 1, 2015 $ (7 ) $ 21 $ 43 $ 57 Other comprehensive loss before reclassifications — (1 ) — (1 ) Amounts reclassified from AOCI (2 ) (19 ) (12 ) (33 ) Other comprehensive loss (2 ) (20 ) (12 ) (34 ) Income tax benefits on other comprehensive loss — (9 ) (4 ) (13 ) Other comprehensive loss, net of tax (2 ) (11 ) (8 ) (21 ) AOCI Balance as of September 30, 2015 $ (9 ) $ 10 $ 35 $ 36 The following amounts were reclassified from AOCI for FES in the three and nine months ended September 30, 2016 and 2015 : For the Three Months Ended September 30 For the Nine Months Ended September 30 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2016 2015 2016 2015 (In millions) Gains & losses on cash flow hedges Commodity contracts $ 1 $ — $ — $ (2 ) Other operating expenses — — — — Income taxes $ 1 $ — $ — $ (2 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (17 ) $ (3 ) $ (41 ) $ (18 ) Investment income (loss) 6 1 15 7 Income taxes $ (11 ) $ (2 ) $ (26 ) $ (11 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (3 ) $ (4 ) $ (10 ) $ (12 ) (1) 1 1 4 4 Income taxes $ (2 ) $ (3 ) $ (6 ) $ (8 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 4, Pension and Other Postemployment Benefits for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Operations from AOCI.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES FirstEnergy’s and FES’ interim effective tax rates reflect the estimated annual effective tax rates for 2016 and 2015 . 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 for the three months ended September 30, 2016 and 2015 was 39.8% and 36.4% , respectively. Changes in FirstEnergy’s effective tax rate for the nine months ended September 30, 2016 as compared to the same period of 2015 , resulted from the second quarter of 2016 impairment of $800 million of goodwill (as described in Note 2), of which $433 million is non-deductible for tax purposes. Additionally, $159 million of valuation allowances were recorded in the second quarter of 2016 against state and local NOL carryforwards that management believes, more likely than not, will not be realized based primarily on projected taxable income reflecting updates to FirstEnergy's annual long-term fundamental pricing model for energy and capacity, as well as certain statutory limitations on the utilization of state and local NOL carryforwards. FES’ effective tax rate for the three months ended September 30, 2016 and 2015 was 58.3% and 36.8% , respectively. The increase in the effective tax rate is primarily due to the impact of estimated annual permanent items on forecasted lower pre-tax income for the period. FES’ effective tax rate for the nine months ended September 30, 2016 and 2015 was 1.8% and 40.0% , respectively. The change in the effective tax rate primarily resulted from $65 million of valuation allowances recorded against state and local NOL carryforwards that management believes, more likely than not, will not be realized as described above. Additionally, FES recorded an impairment of goodwill (as described in Note 2) in the second quarter of 2016, of which $23 million is non-deductible for tax purposes. In March 2016, FirstEnergy recorded unrecognized tax benefits of $69 million primarily related to protective refund claims filed with the Commonwealth of Pennsylvania as a result of a recent ruling by the Commonwealth Court finding that the state’s NOL carryover limitation violated the uniformity clause and was unconstitutional. The Commonwealth of Pennsylvania has appealed this ruling to the Pennsylvania Supreme Court. As of September 30, 2016 , it is reasonably possible that approximately $54 million of unrecognized tax benefits may be resolved within the next twelve months as a result of the statute of limitations expiring and expected resolution with respect to certain claims, of which approximately $15 million would affect FirstEnergy's effective tax rate. In February 2016, the IRS completed its examination of FirstEnergy’s 2014 federal income tax return and issued a full acceptance letter with no adjustments.

Variable Interest Entities

Variable Interest Entities	9 Months Ended
	Sep. 30, 2016
Variable Interest Entities [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has; (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. The caption "noncontrolling interest" within the consolidated financial statements is used to reflect the portion of a VIE that FirstEnergy consolidates, but does not own. In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance. Consolidated VIEs VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements): • PNBV Trust - PNBV , a business trust established by OE in 1996, issued certain beneficial interests and notes to fund the acquisition of a portion of the bonds issued by certain owner trusts in connection with the sale and leaseback in 1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. The beneficial ownership of PNBV includes a 3% interest by unaffiliated third parties. • Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly-owned limited liability companies (SPEs) which issued phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase-in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of September 30, 2016 and December 31, 2015 , $339 million and $362 million of the phase-in recovery bonds were outstanding, respectively. • JCP&L Securitization - In June 2002, JCP&L Transition Funding sold transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consist primarily of bondable transition property. As of September 30, 2016 and December 31, 2015 , $97 million and $128 million of the transition bonds were outstanding, respectively. • MP and PE Environmental Funding Companies - The entities issued bonds, the proceeds of which were used to construct environmental control facilities. The special purpose limited liability companies own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's and PE's West Virginia service territories. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the special purpose limited liability companies, have no recourse to any assets or revenues of the special purpose limited liability companies. As of September 30, 2016 and December 31, 2015 , $407 million and $429 million of the environmental control bonds were outstanding, respectively. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of the following VIEs: • Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture's economic performance. FEV's ownership interest is subject to the equity method of accounting. As discussed in Note 12, Commitments, Guarantees and Contingencies, FE is the guarantor under Global Holding's $300 million term loan facility. Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to be obligated under the provisions of its guarantee, resulting in consolidation of Global Holding by FE. • PATH WV - PATH is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting. • Purchase Power Agreements - FirstEnergy evaluated its PPAs 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 14 long-term PPAs with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that for all but one of these NUG entities, it does not have a variable interest 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 September 30, 2016 and 2015 were $22 million and $29 million , respectively, and $78 million and $86 million during the nine months ended September 30, 2016 and 2015 , respectively. • Sale and Leaseback Transactions - OE and FES have obligations that are not included on their Consolidated Balance Sheets related to the Beaver Valley Unit 2 and 2007 Bruce Mansfield Unit 1 sale and leaseback arrangements, respectively, which are satisfied through operating lease payments. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the arrangements. As of September 30, 2016, FirstEnergy's leasehold interest was 2.60% of Beaver Valley Unit 2 and FES' leasehold interest was 93.83% of Bruce Mansfield Unit 1. 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. Upon the completion of this transaction, NG will have obtained all of the lessor equity interests at Beaver Valley Unit 2. Therefore, upon the expiration of the Beaver Valley Unit 2 leases, NG will be the sole owner of Beaver Valley Unit 2 and entitled to 100% of the unit's output. On May 23, 2016, NG completed the purchase of the 3.75% lessor equity interests of the remaining non-affiliated leasehold interest in Perry Unit 1 for $50 million . In addition, the Perry Unit 1 leases expired in accordance with their terms on May 30, 2016, resulting in NG being the sole owner of Perry Unit 1 and entitled to 100% of the unit's output. Thereafter, OE transferred its NDT assets and related ARO to NG associated with Perry Unit 1. See Note 10, Asset Retirement Obligations, for additional information. 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 September 30, 2016 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy $ 1,137 $ 895 $ 242 FES 1,110 887 223

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS RECURRING FAIR VALUE MEASUREMENTS Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows: Level 1 - Quoted prices for identical instruments in active market Level 2 - Quoted prices for similar instruments in active market - Quoted prices for identical or similar instruments in markets that are not active - Model-derived valuations for which all significant inputs are observable market data Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 - Valuation inputs are unobservable and significant to the fair value measurement FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast, which has been reviewed and approved by FirstEnergy's Risk Policy Committee, are used to measure fair value. A more detailed description of FirstEnergy's valuation process for FTRs and NUGs follows: FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 9, Derivative Instruments, for additional information regarding FirstEnergy's FTRs. NUG contracts represent PPAs 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 September 30, 2016 , from those used as of December 31, 2015 . 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 nine months ended September 30, 2016 . 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 September 30, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,242 $ — $ 1,242 $ — $ 1,245 $ — $ 1,245 Derivative assets - commodity contracts 7 230 — 237 4 224 — 228 Derivative assets - FTRs — — 13 13 — — 8 8 Derivative assets - NUG contracts (1) — — — — — — 1 1 Equity securities (2) 908 — — 908 576 — — 576 Foreign government debt securities — 77 — 77 — 75 — 75 U.S. government debt securities — 173 — 173 — 180 — 180 U.S. state debt securities — 255 — 255 — 246 — 246 Other (3) 551 126 — 677 105 212 — 317 Total assets $ 1,466 $ 2,103 $ 13 $ 3,582 $ 685 $ 2,182 $ 9 $ 2,876 Liabilities Derivative liabilities - commodity contracts $ (12 ) $ (122 ) $ — $ (134 ) $ (9 ) $ (122 ) $ — $ (131 ) Derivative liabilities - FTRs — — (7 ) (7 ) — — (13 ) (13 ) Derivative liabilities - NUG contracts (1) — — (118 ) (118 ) — — (137 ) (137 ) Total liabilities $ (12 ) $ (122 ) $ (125 ) $ (259 ) $ (9 ) $ (122 ) $ (150 ) $ (281 ) Net assets (liabilities) (4) $ 1,454 $ 1,981 $ (112 ) $ 3,323 $ 676 $ 2,060 $ (141 ) $ 2,595 (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 $(8) million and $7 million as of September 30, 2016 and December 31, 2015 , 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 September 30, 2016 and December 31, 2015 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2015 Balance $ 2 $ (153 ) $ (151 ) $ 39 $ (14 ) $ 25 Unrealized gain (loss) 2 (49 ) (47 ) (5 ) (7 ) (12 ) Purchases — — — 22 (11 ) 11 Settlements (3 ) 65 62 (48 ) 19 (29 ) December 31, 2015 Balance $ 1 $ (137 ) $ (136 ) $ 8 $ (13 ) $ (5 ) Unrealized gain (loss) — (17 ) (17 ) (8 ) 1 (7 ) Purchases — — — 17 (8 ) 9 Settlements (1 ) 36 35 (4 ) 13 9 September 30, 2016 Balance $ — $ (118 ) $ (118 ) $ 13 $ (7 ) $ 6 (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings. Level 3 Quantitative Information The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended September 30, 2016 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 6 Model RTO auction clearing prices $(2.20) to $7.60 $1.00 Dollars/MWH NUG Contracts $ (118 ) Model Generation 400 to 3,207,000 661,000 MWH Regional electricity prices $30.90 to $35.30 $32.10 Dollars/MWH FES Recurring Fair Value Measurements September 30, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 714 $ — $ 714 $ — $ 678 $ — $ 678 Derivative assets - commodity contracts 7 230 — 237 4 224 — 228 Derivative assets - FTRs — — 7 7 — — 5 5 Equity securities (1) 624 — — 624 378 — — 378 Foreign government debt securities — 59 — 59 — 59 — 59 U.S. government debt securities — 53 — 53 — 23 — 23 U.S. state debt securities — 4 — 4 — 4 — 4 Other (2) 2 87 — 89 — 184 — 184 Total assets $ 633 $ 1,147 $ 7 $ 1,787 $ 382 $ 1,172 $ 5 $ 1,559 Liabilities Derivative liabilities - commodity contracts $ (12 ) $ (122 ) $ — $ (134 ) $ (9 ) $ (122 ) $ — $ (131 ) Derivative liabilities - FTRs — — (5 ) (5 ) — — (11 ) (11 ) Total liabilities $ (12 ) $ (122 ) $ (5 ) $ (139 ) $ (9 ) $ (122 ) $ (11 ) $ (142 ) Net assets (liabilities) (3) $ 621 $ 1,025 $ 2 $ 1,648 $ 373 $ 1,050 $ (6 ) $ 1,417 (1) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (2) Primarily consists of short-term cash investments. (3) Excludes $1 million as of September 30, 2016 and December 31, 2015 , 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 September 30, 2016 and December 31, 2015 : Derivative Asset Derivative Liability Net Asset (Liability) (In millions) January 1, 2015 Balance $ 27 $ (13 ) $ 14 Unrealized gain (loss) 2 (5 ) (3 ) Purchases 9 (10 ) (1 ) Settlements (33 ) 17 (16 ) December 31, 2015 Balance $ 5 $ (11 ) $ (6 ) Unrealized gain (loss) (7 ) 1 (6 ) Purchases 10 (5 ) 5 Settlements (1 ) 10 9 September 30, 2016 Balance $ 7 $ (5 ) $ 2 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 September 30, 2016 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 2 Model RTO auction clearing prices ($2.20) to $7.60 $0.70 Dollars/MWH INVESTMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and AFS securities. At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value. Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES, OE and TE are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of OTTI. The NDTs of JCP&L, ME and PN are subject to regulatory accounting with unrealized gains and losses offset against regulatory assets. The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries. AFS Securities FirstEnergy holds debt and equity securities within its NDT and nuclear fuel disposal 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 and nuclear fuel disposal trusts as of September 30, 2016 and December 31, 2015 : September 30, 2016 (1) December 31, 2015 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,728 $ 69 $ 1,797 $ 1,778 $ 16 $ 1,794 FES 834 45 879 801 9 810 Equity securities FirstEnergy $ 816 $ 92 $ 908 $ 542 $ 34 $ 576 FES 561 63 624 354 24 378 (1) Excludes short-term cash investments: FirstEnergy - $50 million ; FES - $39 million . (2) Excludes short-term cash investments: FirstEnergy - $157 million ; FES - $139 million . Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three and nine months ended September 30, 2016 and 2015 were as follows: For the Three Months Ended September 30, 2016 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 337 $ 36 $ (15 ) $ (3 ) $ 27 FES 135 23 (6 ) (3 ) 16 September 30, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 307 $ 33 $ (32 ) $ (46 ) $ 25 FES 127 28 (24 ) (41 ) 14 For the Nine Months Ended September 30, 2016 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 1,361 $ 131 $ (88 ) $ (13 ) $ 75 FES 576 90 (49 ) (12 ) 42 September 30, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 1,126 $ 135 $ (121 ) $ (70 ) $ 75 FES 503 98 (79 ) (63 ) 43 Held-To-Maturity Securities Unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of September 30, 2016 and December 31, 2015 are immaterial to FirstEnergy. Investments in employee benefit trusts and equity method investments totaling $276 million as of September 30, 2016 and $255 million as of December 31, 2015 , 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 debt issuance costs, premiums and discounts: September 30, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 19,745 $ 21,465 $ 20,244 $ 21,519 FES 3,003 2,662 3,027 3,121 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 September 30, 2016 and December 31, 2015 .

Derivative Instruments

Derivative Instruments	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance. FirstEnergy has contractual derivative agreements through 2020 . Cash Flow Hedges FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating commodity prices and interest rates. Total pre-tax net unamortized losses included in AOCI associated with instruments previously designated as cash flow hedges totaled $11 million as of September 30, 2016 and December 31, 2015 . Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Less than $1 million of net unamortized losses is expected to be amortized to income during the next twelve months. FirstEnergy has used forward starting interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were designated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $35 million and $42 million as of September 30, 2016 and December 31, 2015 , respectively. Based on current estimates, approximately $8 million of these unamortized losses are expected to be amortized to interest expense during the next twelve months. Refer to Note 5, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the three and nine months ended September 30, 2016 and 2015 . As of September 30, 2016 and December 31, 2015 , 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 September 30, 2016 and December 31, 2015 , 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 $12 million and $20 million as of September 30, 2016 and December 31, 2015 , respectively. During the next twelve months, approximately $8 million of unamortized gains are expected to be amortized to interest expense. Amortization of unamortized gains included in long-term debt totaled approximately $2 million during the three months ended September 30, 2016 and $3 million during the three months ended September 30, 2015 . Amortization of unamortized gains included in long-term debt totaled approximately $8 million during the nine months ended September 30, 2016 and $9 million during the nine months ended September 30, 2015 . Commodity Derivatives FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances where the hedging relationship does not qualify for hedge accounting. Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas primarily for use in FirstEnergy’s combustion turbine units. Derivative instruments are not used in quantities greater than forecasted needs. As of September 30, 2016 , FirstEnergy’s net asset position under commodity derivative contracts was $103 million , which related to FES positions. Under these commodity derivative contracts, FES posted $9 million of collateral and received $22 million of collateral. Based on commodity derivative contracts held as of September 30, 2016 , an increase in commodity prices of 10% would decrease net income by approximately $37 million during the next twelve months. NUGs As of September 30, 2016 , FirstEnergy's net liability position under NUG contracts was $118 million , representing contracts held at JCP&L, ME and PN. Changes in the fair value of NUG contracts are subject to regulatory accounting treatment and do not impact earnings. FTRs As of September 30, 2016 , FirstEnergy's and FES' net asset associated with FTRs was $6 million and $2 million , respectively, and FES posted $7 million of collateral. FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of PJM that have load serving obligations. The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets and have not been designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price less the obligation due to PJM, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FES and AE Supply are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by the 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 September 30, December 31, September 30, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 139 $ 150 Commodity Contracts $ (84 ) $ (94 ) FTRs 13 7 FTRs (7 ) (12 ) 152 157 (91 ) (106 ) Deferred Charges and Other Assets - Other Noncurrent Liabilities - Adverse Power Contract Liability NUGs (1) (118 ) (137 ) Commodity Contracts 98 78 Noncurrent Liabilities - Other FTRs — 1 Commodity Contracts (50 ) (37 ) NUGs (1) — 1 FTRs — (1 ) 98 80 (168 ) (175 ) Derivative Assets $ 250 $ 237 Derivative Liabilities $ (259 ) $ (281 ) (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings. FirstEnergy enters into contracts with counterparties that allow for the offsetting of derivative assets and derivative liabilities under netting arrangements with the same counterparty. Certain of these contracts contain margining provisions that require the use of collateral to mitigate credit exposure between FirstEnergy and these counterparties. In situations where collateral is pledged to mitigate exposures related to derivative and non-derivative instruments with the same counterparty, FirstEnergy allocates the collateral based on the percentage of the net fair value of derivative instruments to the total fair value of the combined derivative and non-derivative instruments. The following tables summarize the fair value of derivative assets and derivative liabilities on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet September 30, 2016 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 237 $ (120 ) $ (22 ) $ 95 FTRs 13 (7 ) — 6 NUG contracts — — — — $ 250 $ (127 ) $ (22 ) $ 101 Derivative Liabilities Commodity contracts $ (134 ) $ 120 $ 8 $ (6 ) FTRs (7 ) 7 — — NUG contracts (118 ) — — (118 ) $ (259 ) $ 127 $ 8 $ (124 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 228 $ (125 ) $ — $ 103 FTRs 8 (8 ) — — NUG contracts 1 — — 1 $ 237 $ (133 ) $ — $ 104 Derivative Liabilities Commodity contracts $ (131 ) $ 125 $ 3 $ (3 ) FTRs (13 ) 8 5 — NUG contracts (137 ) — — (137 ) $ (281 ) $ 133 $ 8 $ (140 ) The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of September 30, 2016 : Purchases Sales Net Units (In millions) Power Contracts 9 49 (40 ) MWH FTRs 42 — 42 MWH NUGs 3 — 3 MWH Natural Gas 49 — 49 mmBTU The effect of active derivative instruments not in a hedging relationship on the Consolidated Statements of Income (Loss) during the three months and nine months ended September 30, 2016 and 2015 , are summarized in the following tables: For the Three Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain (Loss) Recognized in: Other Operating Expense (1) $ 19 $ (3 ) $ 16 Realized Gain (Loss) Reclassified to: Revenues (1) $ 32 $ 1 $ 33 Purchased Power Expense (1) (22 ) — (22 ) Other Operating Expense (1) — (6 ) (6 ) Fuel Expense (2 ) — (2 ) (1) All amounts are associated with FES. For the Three Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense (2) $ 59 $ (2 ) $ 57 Realized Gain (Loss) Reclassified to: Revenues (2) $ 41 $ 2 $ 43 Purchased Power Expense (2) (50 ) — (50 ) Other Operating Expense (2) — (11 ) (11 ) Fuel Expense (5 ) — (5 ) (2) All amounts are associated with FES. For the Nine Months Ended September 30 Commodity Contracts FTRs Total 2016 (In millions) Unrealized Gain Recognized in: Other Operating Expense (1) $ 2 $ 8 $ 10 Realized Gain (Loss) Reclassified to: Revenues (1) $ 162 $ 5 $ 167 Purchased Power Expense (1) (105 ) — (105 ) Other Operating Expense (1) — (28 ) (28 ) Fuel Expense (9 ) — (9 ) (1) All amounts are associated with FES. For the Nine Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense (2) $ 81 $ (17 ) $ 64 Realized Gain (Loss) Reclassified to: Revenues (3) $ 48 $ 48 $ 96 Purchased Power Expense (4) (78 ) — (78 ) Other Operating Expense (5) — (38 ) (38 ) Fuel Expense (26 ) — (26 ) (2) Includes $81 million for commodity contracts and $(16) million for FTRs associated with FES. (3) Includes $48 million for commodity contracts and $46 million for FTRs associated with FES. (4) All amounts are associated with FES. (5) Includes $(37) million for FTRs associated with FES. The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during the three and nine months ended September 30, 2016 and 2015 . Changes in the value of these instruments are deferred for future recovery from (or credit to) customers: For the Three Months Ended September 30 Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of July 1, 2016 $ (124 ) $ 4 $ (120 ) Unrealized loss (6 ) — (6 ) Settlements 12 — 12 Outstanding net asset (liability) as of September 30, 2016 $ (118 ) $ 4 $ (114 ) Outstanding net asset (liability) as of July 1, 2015 $ (140 ) $ 12 $ (128 ) Unrealized loss (20 ) (4 ) (24 ) Settlements 17 (3 ) 14 Outstanding net asset (liability) as of September 30, 2015 $ (143 ) $ 5 $ (138 ) For the Nine Months Ended September 30 Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of January 1, 2016 $ (136 ) $ 1 $ (135 ) Unrealized loss (17 ) (1 ) (18 ) Purchases — 4 4 Settlements 35 — 35 Outstanding net asset (liability) as of September 30, 2016 $ (118 ) $ 4 $ (114 ) Outstanding net asset (liability) as of January 1, 2015 $ (151 ) $ 11 $ (140 ) Unrealized loss (36 ) (3 ) (39 ) Purchases — 12 12 Settlements 44 (15 ) 29 Outstanding net asset (liability) as of September 30, 2015 $ (143 ) $ 5 $ (138 )

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS FirstEnergy has recognized applicable legal obligations for AROs and their associated cost primarily for nuclear power plant decommissioning, reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks, wastewater treatment lagoons and transformers containing PCBs. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation. The ARO liabilities for FES primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities, which are approximately $701 million , as of September 30, 2016. FES uses an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs. FirstEnergy and FES maintain NDTs that are legally restricted for purposes of settling the nuclear decommissioning ARO. The fair values of the decommissioning trust assets as of September 30, 2016 and December 31, 2015 were as follows: 2016 2015 (In millions) FirstEnergy $ 2,502 $ 2,282 FES $ 1,542 $ 1,327 The following table summarizes the changes to the ARO balances during 2016 : ARO Reconciliation FirstEnergy FES (In millions) Balance, December 31, 2015 $ 1,410 $ 831 Liabilities settled (25 ) (17 ) Liabilities incurred 4 32 Accretion 70 41 Balance, September 30, 2016 $ 1,459 $ 887 During the second quarter of 2016, in connection with NG purchasing the lessor equity interests of the remaining non-affiliated leasehold interests from an owner participant in Perry Unit 1, OE transferred the ARO (included within the FES liabilities incurred above) and related NDT assets associated with the leasehold interest to NG with the difference of $28 million credited to the common stock of FES. As of June 30, 2016, NG owns 100% of Perry Unit 1. Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although none are currently expected, any changes in timing and closure plan requirements in the future could materially and adversely impact FirstEnergy's and FES' AROs .

Regulatory Matters

Regulatory Matters	9 Months Ended
	Sep. 30, 2016
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 and demand and requiring each electric utility to file a plan every three years. PE's current plan, covering the three-year period 2015-2017, was approved by the MDPSC on December 23, 2014. The costs of the 2015-2017 plan are expected to be approximately $68 million , of which $38 million was incurred through September 30, 2016. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the level of savings achieved under PE's current plan for 2016, and ramping up 0.2% per year thereafter to reach 2% . PE continues to recover program costs subject to a five -year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE. On February 27, 2013, the MDPSC issued an order (the February 27 Order) requiring the Maryland electric utilities to submit analyses relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations. The order further required the Staff of the MDPSC to report on possible performance-based rate structures and to propose additional rules relating to feeder performance standards, outage communication and reporting, and sharing of special needs customer information. PE's responsive filings discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 27 Order, and projected that it would require approximately $2.7 billion in infrastructure investments over 15 years to attempt to achieve the quickest level of response for the largest storm projected in the February 27 Order. On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting. The Staff of the MDPSC also recommended the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that the utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not yet issued a ruling on any of those matters. 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. Pursuant to the NJBPU's March 26, 2015 final order in JCP&L's 2012 rate case proceeding directing that certain studies be completed, on July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which include operational and financial components. The independent consultant conducting the review issued a final report on July 27, 2016, recognizing that JCP&L is meeting the NJBPU requirements and making various operational and financial recommendations. The NJBPU issued an Order on August 24, 2016, that accepted the independent consultant’s final report and directed JCP&L, the Division of Rate Counsel, and other interested parties to address the recommendations. In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases (Generic CTA proceeding), the NJBPU stated that it would continue to apply its current CTA policy in base rate cases, subject to incorporating the following modifications: (i) calculating savings using a five -year look back from the beginning of the test year; (ii) allocating savings with 75% retained by the company and 25% allocated to rate payers; and (iii) excluding transmission assets of electric distribution companies in the savings calculation. On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the Generic CTA proceeding to the New Jersey Superior Court and JCP&L has filed to participate as a respondent in that proceeding. Briefing has been completed. The oral argument was held on October 25, 2016. On April 28, 2016, JCP&L filed tariffs with the NJBPU proposing a general rate increase associated with its distribution operations that seeks to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses. The filing requested approval to increase annual operating revenues by approximately $142.1 million based upon a hybrid test year for the twelve months ending June 30, 2016. On July 13, 2016, this matter was submitted to the Office of Administrative Law for hearing and the issuance of an Initial Decision. On September 30, 2016, JCP&L filed an update to its filing, which includes actual data for the twelve months ended June 30, 2016, requesting an increase to annual operating revenues by approximately $146.6 million . On October 19, 2016, an order was received approving the agreed upon procedural schedule. Hearings are scheduled to occur in January 2017 through March 2017. On November 2, 2016, JCP&L achieved a settlement-in-principle with all the intervening parties providing for an annual $80 million distribution revenue increase, which will take effect on January 1, 2017, subject to finalization, execution and NJBPU approval of a Stipulation of Settlement. On June 19, 2015, JCP&L, along with PN, ME, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. The procedural schedule was suspended while the NJBPU considered a motion on a legal issue regarding whether MAIT can be designated as a "public utility" in New Jersey. On February 24, 2016, the NJBPU issued an Order concluding that MAIT does not satisfy the “electricity distribution” element necessary for “public utility” status because MAIT would not own any electric distribution assets in New Jersey. On April 22, 2016, JCP&L and MAIT filed a supplemental petition and testimony seeking to include certain JCP&L distributions assets in the transfer to satisfy the "electricity distribution" element necessary for "public utility" status in accordance with the NJBPU’s February 24, 2016 order. In order to allow MAIT to file its formula transmission rate with an effective date of January 1, 2017, on September 8, 2016, JCP&L and MAIT submitted a letter to the NJBPU to withdraw their petition to transfer JCP&L assets into MAIT. The NJBPU administratively closed the matter on September 30, 2016. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction. OHIO On August 4, 2014, the Ohio Companies filed an application with the PUCO seeking approval of their ESP IV entitled Powering Ohio's Progress . ESP IV included a proposed Rider RRS, which would flow through to customers either charges or credits representing the net result of the price paid to FES through an eight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, against the revenues received from selling such output into the PJM markets. The Ohio Companies entered into stipulations which modified ESP IV and which included PUCO Staff as a signatory party, in addition to other signatories. On March 31, 2016, the PUCO issued an Opinion and Order adopting and approving the Ohio Companies’ stipulated ESP IV with modifications. FES and the Ohio Companies entered into the ESP IV PPA on April 1, 2016. On January 27, 2016, certain parties filed a complaint with FERC against FES and the Ohio Companies requesting FERC review the ESP IV PPA under Section 205 of the FPA. On April 27, 2016, FERC issued an order granting the complaint, prohibiting any transactions under the ESP IV PPA pending future authorization by FERC, and directing FES to submit the ESP IV PPA for FERC review if the parties desired to transact under the agreement. FES and the Ohio Companies did not file the ESP IV PPA for FERC review but rather agreed to suspend the ESP IV PPA. FES and the Ohio Companies subsequently advised FERC of this course of action. On April 29, 2016 and May 2, 2016, several parties, including the Ohio Companies, filed applications for rehearing on the Ohio Companies’ ESP IV with the PUCO. The Ohio Companies’ Application for Rehearing included a modified Rider RRS proposal but did not include a FERC-jurisdictional PPA. The PUCO accepted the applications for rehearing for further consideration and provided parties an opportunity to comment on the Ohio Companies’ Application for Rehearing and file an alternative proposal. PUCO Staff recommended that the PUCO deny the Ohio Companies’ modified Rider RRS proposal and recommended a new Rider DMR providing for the collection of $204 million annually (grossed up for income taxes) for three years with a possible extension for an additional two years. The Ohio Companies recommended that the PUCO approve the proposed modified Rider RRS and that a properly designed Rider DMR would be valued at $558 million annually for 8 years , and include an additional amount that recognizes the value of the economic impact of FirstEnergy maintaining its headquarters in Ohio. Several parties subsequently filed protests and comments with FERC alleging, among other things, that the modified Rider RRS constitutes a "virtual PPA". The filings and FirstEnergy’s responses thereto are pending before FERC. On September 6, 2016, while the applications for rehearing were still pending before the PUCO, the OCC and NOAC filed a notice of appeal with the Ohio Supreme Court appealing various PUCO and Attorney Examiner Entries on the parties’ applications for rehearing. On September 16, 2016, the Ohio Companies intervened and filed a motion to dismiss the appeal. The appeal remains pending before the Ohio Supreme Court. On October 12, 2016, the PUCO issued an opinion and order ruling on the parties’ applications for rehearing and further modified ESP IV. The PUCO order denied the Ohio Companies’ modified Rider RRS proposal, and instead approved a Rider DMR proposed by PUCO Staff, with modifications. As a result of the stipulations, the PUCO’s March 31, 2016 Opinion and Order and the PUCO’s October 12, 2016 order, the material terms of ESP IV include: • An eight -year term (June 1, 2016 - May 31, 2024). • The Rider DMR which provides for the Ohio Companies to collect $132.5 million annually for three years , with the possibility of a two-year extension. The Rider DMR will be grossed up for taxes, resulting in an approved amount of approximately $204 million annually. Revenues from the Rider DMR will be excluded from the significantly excessive earnings test for the initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension. • Three conditions for continued recovery under the Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO. • No restrictions on the Ohio Companies’ use of funds collected under the Rider DMR. However, the PUCO directed the PUCO Staff to periodically review how the Ohio Companies and FE use the funds to ensure the funds are used, directly or indirectly, in support of grid modernization. Uses of funds to indirectly support grid modernization could include, e.g., reducing outstanding pension obligations or reducing debt. • Continuation of a base distribution rate freeze through May 31, 2024. • Continuation of the supply of power to non-shopping customers at a market-based price set through an auction process. • Continuation of Rider DCR with increased revenue caps of approximately $30 million per year from June 1, 2016 through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024 that supports continued investment related to the distribution system for the benefit of customers. • Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs. • Continuation of 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 . • Potential procurement of 100 MW of new Ohio wind or solar resources subject to a demonstrated need to procure new renewable energy resources as part of a strategy to further diversify Ohio's energy portfolio. • An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential customers. • An agreement to file a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016). • A goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045. • A contribution of $3 million per year ( $24 million over the eight -year term) to fund energy conservation programs, economic development and job retention in the Ohio Companies service territory. • Contributions of $2.4 million per year ( $19 million over the eight -year term) to fund a fuel-fund in each of the Ohio Companies service territories to assist low-income customers. • A contribution of $1 million per year ( $8 million over the eight -year term) to establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio. Finally, on March 21, 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in the PJM capacity markets by state-subsidized generation, in particular alleged price suppression that could result from the ESP IV PPA and other similar agreements. The complaint requested that FERC direct PJM to initiate a stakeholder process to develop a long-term MOPR reform for existing resources that receive out-of-market revenue. This proceeding remains pending before FERC. Under Ohio's energy efficiency standards (SB221 and SB310), and based on the Ohio Companies' amended energy efficiency plans, the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of 2,266 GWHs in 2015 and 2,288 GWHs in 2016, and then begin to increase by 1% each year in 2017, subject to legislative amendments to the energy efficiency standards discussed below. The Ohio Companies are also required to retain the 2014 peak demand reduction level for 2015 and 2016 and then increase the benchmark by an additional 0.75% thereafter through 2020, subject to legislative amendments to the peak demand reduction standards discussed below. On September 30, 2015, the Energy Mandates Study Committee issued its report related to energy efficiency and renewable energy mandates, recommending that the current level of mandates remain in place indefinitely. The report also recommended: (i) an expedited process for review of utility proposed energy efficiency plans; (ii) ensuring maximum credit for all of Ohio's Energy Initiatives; (iii) a switch from energy mandates to energy incentives; and (iv) a declaration be made that the General Assembly may determine the energy policy of the state. Legislation was introduced to address issues raised in the Energy Mandates Study Committee report, namely SB320 and HB554. SB320 proposes to freeze energy efficiency and renewable energy requirements for an additional four years at 2014 levels, as well as addressing net metering issues. HB554 proposes to freeze energy efficiency and renewable energy requirements through 2027 at 2014 levels. On September 24, 2014, the Ohio Companies filed an amendment to their energy efficiency 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 and the matter remains pending before the PUCO. On April 15, 2016, the Ohio Companies filed an application for approval of their three-year energy efficiency portfolio plans for the period from January 1, 2017 through December 31, 2019. The plans as proposed comply with benchmarks contemplated by SB310 and provisions of the ESP IV, and include a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities. The Ohio Companies anticipate the cost of the plans will be approximately $323 million over the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. The hearing is scheduled for November 21-23, 2016. 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 was denied. On August 9, 2016, upon a Joint Application for Dismissal filed by the Ohio Companies, PUCO and the ELPC, the Ohio Supreme Court dismissed the appeal. Ohio law requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage amount through 2026, subject to legislative amendments discussed above, except 2015 and 2016 that remain at the 2014 level. The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements. In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs. The PUCO issued an Opinion and Order on August 7, 2013, approving the Ohio Companies' acquisition process and their purchases of RECs to meet statutory mandates in all instances except for certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of $43.4 million , plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent. On December 24, 2013, following the denial of their application for rehearing, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted. On February 18, 2014, the OCC and the ELPC also filed appeals of the PUCO's order. The Ohio Companies timely filed their merit brief with the Supreme Court of Ohio and the briefing process has concluded. The matter is not yet scheduled for oral argument. On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers. On January 13, 2016, the PUCO granted reconsideration for further consideration of the matters specified in the applications for rehearing. PENNSYLVANIA The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2017, and provide for the competitive procurement of generation supply for customers that do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. The default service supply is currently provided by wholesale suppliers through a mix of long-term and short-term contracts procured through spot market purchases, quarterly descending clock auctions for 3-, 12- and 24-month energy contracts, and one RFP seeking 2-year contracts to serve SRECs for ME, PN and Penn. Following the expiration of the current DSPs, the Pennsylvania Companies will operate under new DSPs for the June 1, 2017 through May 31, 2019 delivery period, which would provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Under the programs, the supply would be provided by wholesale suppliers through a mix of 12 and 24-month energy contracts, as well as one RFP for 2-year SREC contracts for ME, PN and Penn. In addition, the plan includes modifications to the Pennsylvania Companies’ existing POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges. Pursuant to Pennsylvania's EE&C legislation (Act 129 of 2008) and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies' Phase II EE&C Plans were effective through May 31, 2016. Total Phase II costs of these plans were expected to be approximately $175 million and recoverable through the Pennsylvania Companies' reconcilable EE&C riders. On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at 1.8% for ME, 1.7% for Penn, 1.8% for WP, and 0% for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at 4.0% for ME, 3.9% for PN, 3.3% for Penn, and 2.6% for WP. The Pennsylvania Companies' Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, are designed to achieve the targets established in the PPUC's Phase III Final Implementation Order without recovery to implement the EE&C plans. Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. Pennsylvania EDCs must file LTIIPs outlining infrastructure improvement plans for PPUC review and approval prior to approval of a DSIC. On October 19, 2015, each of the Pennsylvania Companies filed LTIIPs with the PPUC for infrastructure improvement over the five -year period of 2016 to 2020 for the following costs: WP $88.34 million ; PN $56.74 million ; Penn $56.35 million ; and ME $43.44 million . On February 11, 2016, the PPUC approved the Pennsylvania Companies' LTIIPs. On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery associated with the capital projects approved in the LTIIPs. On June 9, 2016, the PPUC approved the Pennsylvania Companies’ DSIC riders to be effective July 1, 2016, subject to hearings and refund or reallocation among customers. On April 28, 2016, each of the Pennsylvania Companies filed tariffs with the PPUC proposing general rate increases associated with their distribution operations that will benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements. The filings request approval to increase annual operating revenues by approximately $140.2 million at ME, $158.8 million at PN, $42.0 million at Penn, and $98.2 million at WP, based upon fully projected future test years for the twelve months ending December 31, 2017 at each of the Pennsylvania Companies. As a result of the enactment of Act 40 of 2016 that terminated the practice of making a CTA when calculating a utility’s federal income taxes for ratemaking purposes, the Pennsylvania Companies submitted supplemental testimony on July 7, 2016, that quantified the value of the elimination of the CTA and outlined their plan for investing 50 percent of that amount in rate base eligible equipment as required by the new law. Formal settlement agreements for each of the Pennsylvania Companies were filed on October 14, 2016, which provide increases in annual operating revenues of approximately $96 million at ME, $100 million at PN, $29 million at Penn, and $66 million at WP, and are subject to PPUC approval. One item related to the calculation of DSIC rates was reserved for briefing, with briefs filed by two parties. The proposed new rates are expected to take effect in January 2017 pending regulatory approval, which is expected no later than January 26, 2017. On June 19, 2015, ME and PN, along with JCP&L, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. On March 4, 2016, a Joint Petition for Full Settlement was submitted to the PPUC for consideration and approval. On April 18, 2016, the ALJs issued an Initial Decision approving the Joint Petition for Full Settlement without modifications. On July 21, 2016, the PPUC adopted a Motion approving the Joint Petition for Full Settlement with minor modifications. On August 24, 2016, the PPUC issued a Final Order approving the Joint Settlement consistent with the July 21, 2016 Motion. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction. WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP's and PE's ENEC rate is updated annually. MP and PE filed with the WVPSC on March 31, 2016 their Phase II energy efficiency program proposal for approval. MP and PE are proposing three energy efficiency programs to meet their Phase II requirement of energy efficiency reductions of 0.5% of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, as agreed to by MP and PE, and approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of Harrison Power Station to MP. The costs for the program are expected to be $10.4 million and will be eligible for recovery through the existing energy efficiency rider which is reviewed in the fuel (ENEC) case each year. A unanimous settlement was reached by the parties on all issues and presented to the WVPSC on August 18, 2016. An order approving the settlement in full without modification was issued by the WVPSC on September 23, 2016. Under the order, the programs may begin as of the date of such order, but no later than January 1, 2017. The Staff of the WVPSC and the Consumer Advocate Division filed a Show Cause petition on August 5, 2016, requesting the WVPSC order MP and PE to file and implement RFPs for all future capacity and energy requirements above 100 MWs and that they comply with an RFP settlement provision from the Harrison asset acquisition. MP and PE filed a timely response to the petition arguing for dismissal on September 7, 2016. On October 17, 2016, the WVPSC denied the petition filed by the Staff of the WVPSC and the Consumer Advocate Division and dismissed the case. On August 16, 2016, MP and PE filed their annual ENEC case proposing an approximate $65 million annual increase in rates effective January 1, 2017, which is a 4.7% overall increase over existing rates. The $65 million increase is comprised of $119 million under-recovered balance as of June 30, 2016, and a projected $54 million over-recovery for the 2017 rate effective period. A hearing has been set for November 9 and 10, 2016 with an order expected to be issued in the fourth quarter of 2016. On August 22, 2016, MP and PE filed an application for approval of a modernization and improvement plan for coal-fired boilers at electric power plants and cost-recovery surcharge proposing an approximate $6.9 million annual increase in rates proposed to be effective May 1, 2017, which is a 0.5% overall increase over existing rates. The filing is in response to recent legislation by the West Virginia Legislature session permitting accelerated recovery of costs related to modernizing and improving coal-fired boilers, including costs related to meeting environmental requirements and reducing emissions. The filing was supplemented on September 28, 2016, to add two additional projects, resulting in an approximate $7.4 million annual increase in rates. The Staff of the WVPSC has filed a motion to dismiss the case arguing the new statute was not meant to recover these types of projects, but the WVPSC has set the case for hearing for February 21-23, 2017. On December 30, 2015, MP filed an IRP identifying a capacity shortfall starting in 2016 and exceeding 700 MW by 2020 and 850 MW by 2027. On June 3, 2016, the WVPSC accepted the IRP finding that IRPs are informational and that it must not approve or disapprove the IRP. MP Plans to issue a RFP to address its generation shortfall identified in the IRP by the end of the year. RELIABILITY MATTERS Federally-enforceable mandatory reliability standards apply

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	9 Months Ended
	Sep. 30, 2016
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 September 30, 2016 , FirstEnergy's outstanding guarantees and other assurances aggregated approximately $3.4 billion , consisting of parental guarantees ( $584 million ), subsidiaries' guarantees ( $2.0 billion ), other guarantees ( $300 million ) and other assurances ( $504 million ). Of this aggregate amount, substantially all relates to guarantees of wholly-owned consolidated entities of FirstEnergy. FES' debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each of FG and NG. Accordingly, present and future holders of indebtedness of FES, FG and NG would have claims against each of FES, FG and NG, regardless of whether their primary obligor is FES, FG or NG. COLLATERAL AND CONTINGENT-RELATED FEATURES In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel, and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on FES' power portfolio exposures as of September 30, 2016 , FES has posted collateral of $193 million and AE Supply has posted collateral of $4 million . These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. As a result of the downgrades by Moody's and S&P on July 29, 2016 and August 1, 2016, CES posted additional collateral of $53 million. Additionally, on November 4, 2016, Moody's and S&P further downgraded FES. Given the downgrades, CES has further potential collateral posting obligations totaling $81 million for which counterparties have not exercised their right to require CES to post collateral. Subsequent to the occurrence of a senior unsecured credit rating downgrade below S&P's and Moody's current ratings, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of FirstEnergy. The following table discloses the additional credit contingent contractual obligations that may be required under certain events as of November 4, 2016 : Potential Collateral Obligations CES Regulated Total (in millions) Contractual Obligations for Additional Collateral At Current Credit Rating $ 81 $ — $ 81 Upon Further Downgrade — 48 48 Upon Material Adverse Event 10 — 10 Surety Bonds (Collateralized Amount) 264 96 360 Total Exposure from Contractual Obligations $ 355 $ 144 $ 499 Excluded from the preceding table are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment. As of September 30, 2016 , neither FES nor AE Supply had any collateral posted with their affiliates. OTHER COMMITMENTS AND CONTINGENCIES FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding borrowed $300 million . In addition to FE, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, 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. ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Clean Air Act FirstEnergy complies with SO 2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls, generating more electricity from lower or non-emitting plants and/or using emission allowances. CSAPR requires reductions of NOx and SO 2 emissions in two phases (2015 and 2017), ultimately capping SO 2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions. The U.S. Court of Appeals for the D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO 2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding EPA’s regulatory approach under CSAPR, but questioning whether EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Depending on how the EPA and the states implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's and FES' operations may result. EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015. EPA stated the vast majority of U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and state rules and programs but EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017. States will then have roughly three years to develop implementation plans to attain the new 2015 ozone NAAQS. Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be material and changes to FirstEnergy’s and FES’ operations may result. In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility's NOx emissions significantly contribute to Delaware's inability to attain the ozone NAAQS. The petition seeks a short term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. On September 27, 2016, EPA extended the time frame for acting on the CAA Section 126 petition by six months to April 7, 2017. FirstEnergy is unable to predict the outcome of this matter or estimate the loss or range of loss. 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. FirstEnergy's total capital cost for compliance (over the 2012 to 2018 time period) is currently expected to be approximately $345 million (CES segment of $168 million and Regulated Distribution segment of $177 million ), of which $267 million has been spent through September 30, 2016 ( $117 million at CES and $150 million at Regulated Distribution). On August 3, 2015, FG, a subsidiary of FES, submitted to the AAA office in New York, N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure event that excuses FG’s performance under its coal transportation contract with these parties. Specifically, the dispute arises from a contract for the transportation by BNSF and CSX of a minimum of 3.5 million tons of coal annually through 2025 to certain coal-fired power plants owned by FG that are located in Ohio. As a result of and in compliance with MATS, all plants covered by this contract were deactivated by April 16, 2015. In January 2012, FG notified BNSF and CSX that MATS constituted a force majeure event under the contract that excused FG’s further performance. Separately, on August 4, 2015, BNSF and CSX submitted to the AAA office in Washington, D.C., a demand for arbitration and statement of claim against FG alleging that FG breached the contract and that FG’s declaration of a force majeure under the contract is not valid and seeking damages under the contract through 2025. On May 31, 2016, the parties agreed to a stipulation that if FG’s force majeure defense is determined to be wholly or partially invalid, liquidated damages are the sole remedy available to BNSF and CSX. The arbitration panel has determined to consolidate the claims with a liability hearing scheduled to begin on November 28, 2016, and, if necessary, a damages hearing scheduled to begin on May 8, 2017. The decision on liability is expected to be issued within sixty days from the end of the liability hearing proceedings, which are scheduled to conclude February 24, 2017. FirstEnergy and FES continue to believe that MATS constitutes a force majeure event under the contract as it relates to the deactivated plants and that FG’s performance under the contract is therefore excused. FG intends to vigorously assert its position in the arbitration proceedings. If, however, the arbitration panel rules in favor of BNSF and CSX, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. Refer to the Strategic Review of Competitive Operations section of Note 1, Organization and Basis of Presentation, for possible actions that may be taken by FES in the event of an adverse outcome, including, without limitation, seeking protection under the bankruptcy laws. FirstEnergy and FES are unable to estimate the loss or range of loss. FG is also a party to another coal transportation contract covering the delivery of 2.5 million tons annually through 2025, a portion of which is to be delivered to another coal-fired plant owned by FG that was deactivated as a result of MATS. FG has asserted a defense of force majeure in response to delivery shortfalls to such plant under this contract as well. If FG fails to reach a resolution with the applicable counterparties to the contract, and if it were ultimately determined that, contrary to FirstEnergy’s and FES’ belief, the force majeure provisions of that contract do not excuse the delivery shortfalls to the deactivated plant, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. FirstEnergy and FES are unable to estimate the loss or range of loss. As to both coal transportation agreements referenced above, FG paid approximately $70 million in the aggregate in liquidated damages to settle delivery shortfalls in 2014 related to its deactivated plants, which approximated full liquidated damages under the agreements for such year related to the plant deactivations. Liquidated damages for the period 2015-2025 remain in dispute. As to a specific coal supply agreement, AE Supply has asserted termination rights effective in 2015. In response to notification of the termination, the coal supplier commenced litigation alleging AE Supply does not have sufficient justification to terminate the agreement. AE Supply has filed an answer denying any liability related to the termination. This matter is currently in the discovery phase of litigation and no trial date has been established. There are approximately 5.5 million tons remaining under the contract for delivery. At this time, AE Supply 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, March 27, 2013 and October 18, 2017, EPA issued CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. On December 12, 2014, EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009. FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss. Climate Change FirstEnergy has established a goal to reduce CO 2 emissions by 90% below 2005 levels by 2045. 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. The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act” in December 2009, concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. The EPA released its final regulations in August 2015 (which have been stayed by the U.S. Supreme Court), to reduce CO 2 emissions from existing fossil fuel fired electric generating units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO 2 emission rate goals. The EPA’s CPP allows states to request a two -year extension to finalize SIPs by September 6, 2018. If states fail to develop SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions trading rules which states can also adopt in their SIPs. The EPA also finalized separate regulations imposing CO 2 emission limits for new, modified, and reconstructed fossil fuel fired electric generating units. On June 23, 2014, the United States Supreme Court decided that CO 2 or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies. Numerous states and private parties filed appeals and motions to stay the CPP with the U.S. Court of Appeals for the D.C. Circuit in October 2015. On January 21, 2015, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court . Depending on the outcome of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material. At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide greenhouse gas emissions by 26 to 28 percent below 2005 levels by 2025 and joined in adopting the agreement reached on December 12, 2015 at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement was ratified by the requisite number of countries (i.e. at least 55 countries representing at least 55% of global GHG emissions) in October 2016 and its non-binding obligations to limit global warming to well below two degrees Celsius are effective on November 4, 2016. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. The CO 2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO 2 emitting gas-fired and nuclear generators. Clean Water Act Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from the plant's cooling water intake system. Depending on the results of such studies and any final action taken by the states based on those studies, the future capital costs of compliance with these standards may be substantial. On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations will phase-in as permits are renewed on a five -year cycle from 2018 to 2023. The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's and FES' operations may result. In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the effluent limits that were effective immediately under the terms of the NPDES permit. MP appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require an initial capital investment ranging from $150 million to $300 million in order to install technology to meet the TDS and sulfate limits, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of the appeal or estimate the possible loss or range of loss. FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the loss or range of loss. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although none are currently expected, any changes in timing and closure plan requirements in the future could materially and adversely impact FirstEnergy's and FES' AROs . Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRs by December 31, 2016 and FG to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FG to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCRs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The Bruce Mansfield plant is pursuing several options for disposal of CCRs following December 31, 2016 and expects beneficial reuse and disposal options will be sufficient for the ongoing operation of the plant. On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR. On July 6, 2015 and October 22, 2015, the Sierra Club filed Notices of Appeal with the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility. FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of September 30, 2016 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 $121 million have been accrued through September 30, 2016 . Included in the total are accrued liabilities of approximately $89 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FirstEnergy or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time. OTHER LEGAL PROCEEDINGS Nuclear Plant Matters Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of September 30, 2016 , FirstEnergy had approximately $2.5 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. The values of FirstEnergy's NDTs fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs. FE and FES have also entered into a total of $24.5 million in parental guarantees in support of the decommissioning of the spent fuel storage facilities located at the nuclear facilities. However, as FES no longer maintains investment grade credit ratings from either S&P or Moody’s, NG plans to fund a supplemental trust in lieu of a parental guarantee that would be required to support the decommissioning of the spent fuel storage facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantees, as appropriate. In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years. On December 8, 2015, the NRC renewed the operating license for Davis-Besse, which is now authorized to continue operation through April 22, 2037. Prior to that decision, the NRC Commissioners denied an intervenor's request to reopen the record and admit a contention on the NRC’s Continued Storage Rule. On August 6, 2015, this intervenor sought review of the NRC Commissioners' decision before the U.S. Court of Appeals for the DC Circuit. FENOC intervened in that proceeding. On September 21, 2016, the U.S. Court of Appeals for the DC Circuit granted the intervenor’s unopposed motion and dismissed this case. As part of routine inspections of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. These inspections revealed that the cracking condition had propagated a small amount in select areas. FENOC's analysis confirms that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions. In a May 28, 2015, Inspection Report regarding the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation for FENOC’s failure to request and obtain a license amendment for its method of evaluating the significance of the shield building cracking. The NRC also concluded that the shield building remained capable of performing its design safety functions despite the identified laminar cracking and that this issue was of very low safety significance. FENOC plans to submit a license amendment application to the NRC related to the laminar cracking in 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. 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 11, Regulatory Matters of the Combined Notes to Consolidated Financial Statements. FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Supplemental Guarantor Informat

Supplemental Guarantor Information	9 Months Ended
	Sep. 30, 2016
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. FG's parent company 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 FG or its parent company, but the notes are secured by, among other things, each lessor trust's undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES' lease guaranty. This transaction is classified as an operating lease for FES and FirstEnergy and as a financing lease for FG. The Condensed Consolidating Statements of Income (Loss) and Comprehensive Income (Loss) for the three and nine months ended September 30, 2016 and 2015 , Condensed Consolidating Balance Sheets as of September 30, 2016 and December 31, 2015 , and Condensed Consolidating Statements of Cash Flows for the nine months ended September 30, 2016 and 2015 , for the parent and guarantor and non-guarantor subsidiaries are presented below. These statements are provided as FG's parent company 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 the parent company using the equity method. Results of operations for FG and NG are, therefore, reflected in their parent company's investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction. FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Three Months Ended September 30, 2016 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 1,065 $ 494 $ 400 $ (859 ) $ 1,100 OPERATING EXPENSES: Fuel — 149 53 — 202 Purchased power from affiliates 1,011 — 39 (859 ) 191 Purchased power from non-affiliates 186 — — — 186 Other operating expenses 95 61 149 11 316 Provision for depreciation 4 28 51 — 83 General taxes 8 7 6 — 21 Total operating expenses 1,304 245 298 (848 ) 999 OPERATING INCOME (LOSS) (239 ) 249 102 (11 ) 101 OTHER INCOME (EXPENSE): Investment income, including net income from equity investees 224 8 28 (236 ) 24 Miscellaneous income — 1 — — 1 Interest expense — affiliates (13 ) (3 ) (2 ) 15 (3 ) Interest expense — other (14 ) (27 ) (9 ) 14 (36 ) Capitalized interest — 3 6 — 9 Total other income (expense) 197 (18 ) 23 (207 ) (5 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (42 ) 231 125 (218 ) 96 INCOME TAXES (BENEFITS) (82 ) 87 49 2 56 NET INCOME $ 40 $ 144 $ 76 $ (220 ) $ 40 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 40 $ 144 $ 76 $ (220 ) $ 40 OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (3 ) (3 ) — 3 (3 ) Amortized gains on derivative hedges 1 — — — 1 Change in unrealized gains on available-for-sale securities 5 — 5 (5 ) 5 Other comprehensive income (loss) 3 (3 ) 5 (2 ) 3 Income taxes (benefits) on other comprehensive income (loss) 1 (1 ) 2 (1 ) 1 Other comprehensive income (loss), net of tax 2 (2 ) 3 (1 ) 2 COMPREHENSIVE INCOME $ 42 $ 142 $ 79 $ (221 ) $ 42 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Nine Months Ended September 30, 2016 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 3,281 $ 1,309 $ 1,404 $ (2,593 ) $ 3,401 OPERATING EXPENSES: Fuel — 449 146 — 595 Purchased power from affiliates 2,888 — 145 (2,593 ) 440 Purchased power from non-affiliates 829 — — — 829 Other operating expenses 218 220 450 37 925 Provision for depreciation 10 91 151 (2 ) 250 General taxes 23 23 20 — 66 Impairment of assets 23 517 — — 540 Total operating expenses 3,991 1,300 912 (2,558 ) 3,645 OPERATING INCOME (LOSS) (710 ) 9 492 (35 ) (244 ) OTHER INCOME (EXPENSE): Investment income, including net income (loss) from equity investees 310 21 67 (342 ) 56 Miscellaneous income 3 1 — — 4 Interest expense — affiliates (34 ) (7 ) (4 ) 39 (6 ) Interest expense — other (40 ) (79 ) (33 ) 43 (109 ) Capitalized interest — 7 20 — 27 Total other income (expense) 239 (57 ) 50 (260 ) (28 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (471 ) (48 ) 542 (295 ) (272 ) INCOME TAXES (BENEFITS) (204 ) (1 ) 196 4 (5 ) NET INCOME (LOSS) $ (267 ) $ (47 ) $ 346 $ (299 ) $ (267 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (267 ) $ (47 ) $ 346 $ (299 ) $ (267 ) OTHER COMPREHENSIVE INCOME (LOSS): Pensions and OPEB prior service costs (10 ) (10 ) — 10 (10 ) Amortized gains on derivative hedges — — — — — Change in unrealized gains on available-for-sale securities 61 — 60 (60 ) 61 Other comprehensive income (loss) 51 (10 ) 60 (50 ) 51 Income taxes (benefits) on other comprehensive income (loss) 20 (4 ) 23 (19 ) 20 Other comprehensive income (loss), net of tax 31 (6 ) 37 (31 ) 31 COMPREHENSIVE INCOME (LOSS) $ (236 ) $ (53 ) $ 383 $ (330 ) $ (236 ) FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Three Months Ended September 30, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 1,293 $ 420 $ 531 $ (906 ) $ 1,338 OPERATING EXPENSES: Fuel — 193 52 — 245 Purchased power from affiliates 932 — 77 (906 ) 103 Purchased power from non-affiliates 401 — — — 401 Other operating expenses 34 66 134 12 246 Provision for depreciation 3 30 47 (1 ) 79 General taxes 10 8 6 — 24 Total operating expenses 1,380 297 316 (895 ) 1,098 OPERATING INCOME (LOSS) (87 ) 123 215 (11 ) 240 OTHER INCOME (EXPENSE): Investment income (loss), including net income from equity investees 191 4 (18 ) (198 ) (21 ) Miscellaneous income — 1 — — 1 Interest expense — affiliates (8 ) (2 ) (1 ) 9 (2 ) Interest expense — other (13 ) (26 ) (12 ) 15 (36 ) Capitalized interest — 1 7 — 8 Total other income (expense) 170 (22 ) (24 ) (174 ) (50 ) INCOME BEFORE INCOME TAXES (BENEFITS) 83 101 191 (185 ) 190 INCOME TAXES (BENEFITS) (37 ) 36 70 1 70 NET INCOME $ 120 $ 65 $ 121 $ (186 ) $ 120 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 120 $ 65 $ 121 $ (186 ) $ 120 OTHER COMPREHENSIVE LOSS: Pension and OPEB prior service costs (4 ) (3 ) — 3 (4 ) Amortized gains on derivative hedges — — — — — Change in unrealized gains on available for sale securities (11 ) — (11 ) 11 (11 ) Other comprehensive loss (15 ) (3 ) (11 ) 14 (15 ) Income tax benefits on other comprehensive loss (6 ) (1 ) (4 ) 5 (6 ) Other comprehensive loss, net of tax (9 ) (2 ) (7 ) 9 (9 ) COMPREHENSIVE INCOME $ 111 $ 63 $ 114 $ (177 ) $ 111 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Nine Months Ended September 30, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 3,699 $ 1,259 $ 1,494 $ (2,618 ) $ 3,834 OPERATING EXPENSES: Fuel — 523 143 — 666 Purchased power from affiliates 2,657 — 211 (2,618 ) 250 Purchased power from non-affiliates 1,336 — — — 1,336 Other operating expenses 300 208 452 36 996 Provision for depreciation 8 92 142 (2 ) 240 General taxes 36 23 19 — 78 Impairment of assets 16 — — — 16 Total operating expenses 4,353 846 967 (2,584 ) 3,582 OPERATING INCOME (LOSS) (654 ) 413 527 (34 ) 252 OTHER INCOME (EXPENSE): Investment income (loss), including net income from equity investees 551 12 (1 ) (569 ) (7 ) Miscellaneous income 1 4 — — 5 Interest expense — affiliates (21 ) (6 ) (3 ) 24 (6 ) Interest expense — other (39 ) (78 ) (37 ) 44 (110 ) Capitalized interest — 4 22 — 26 Total other income (expense) 492 (64 ) (19 ) (501 ) (92 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (162 ) 349 508 (535 ) 160 INCOME TAXES (BENEFITS) (258 ) 131 187 4 64 NET INCOME $ 96 $ 218 $ 321 $ (539 ) $ 96 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 96 $ 218 $ 321 $ (539 ) $ 96 OTHER COMPREHENSIVE LOSS Pension and OPEB prior service costs (12 ) (11 ) — 11 (12 ) Amortized gains on derivative hedges (2 ) — — — (2 ) Change in unrealized gains on available-for-sale securities (20 ) — (20 ) 20 (20 ) Other comprehensive loss (34 ) (11 ) (20 ) 31 (34 ) Income tax benefits on other comprehensive loss (13 ) (4 ) (7 ) 11 (13 ) Other comprehensive loss, net of tax (21 ) (7 ) (13 ) 20 (21 ) COMPREHENSIVE INCOME $ 75 $ 211 $ 308 $ (519 ) $ 75 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of September 30, 2016 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 225 — — — 225 Affiliated companies 356 351 267 (492 ) 482 Other 21 4 30 — 55 Notes receivable from affiliated companies 494 1,501 1,133 (3,102 ) 26 Materials and supplies 38 153 212 — 403 Derivatives 146 — — — 146 Collateral 85 — — — 85 Prepayments and other 57 14 1 — 72 1,422 2,025 1,643 (3,594 ) 1,496 PROPERTY, PLANT AND EQUIPMENT: In service 121 5,683 8,674 (378 ) 14,100 Less — Accumulated provision for depreciation 49 1,915 4,050 (192 ) 5,822 72 3,768 4,624 (186 ) 8,278 Construction work in progress 3 287 758 — 1,048 75 4,055 5,382 (186 ) 9,326 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,542 — 1,542 Investment in affiliated companies 7,826 — — (7,826 ) — Other — 10 — — 10 7,826 10 1,542 (7,826 ) 1,552 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 279 27 — (306 ) — Customer intangibles 11 — — — 11 Property taxes — 3 7 — 10 Derivatives 98 — — — 98 Other 29 333 — 12 374 417 363 7 (294 ) 493 $ 9,740 $ 6,453 $ 8,574 $ (11,900 ) $ 12,867 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 199 $ 8 $ (25 ) $ 182 Short-term borrowings- Affiliated companies 2,723 480 — (3,102 ) 101 Accounts payable- Affiliated companies 597 165 180 (549 ) 393 Other 18 71 — — 89 Accrued taxes 31 28 51 (38 ) 72 Derivatives 88 1 — — 89 Other 66 71 12 33 182 3,523 1,015 251 (3,681 ) 1,108 CAPITALIZATION: Total equity 5,409 2,897 4,893 (7,790 ) 5,409 Long-term debt and other long-term obligations 691 2,108 1,120 (1,104 ) 2,815 6,100 5,005 6,013 (8,894 ) 8,224 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 765 765 Accumulated deferred income taxes 7 — 817 (90 ) 734 Retirement benefits 25 194 — — 219 Asset retirement obligations — 186 701 — 887 Derivatives 45 5 — — 50 Other 40 48 792 — 880 117 433 2,310 675 3,535 $ 9,740 $ 6,453 $ 8,574 $ (11,900 ) $ 12,867 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2015 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 275 — — — 275 Affiliated companies 433 403 461 (846 ) 451 Other 36 4 19 — 59 Notes receivable from affiliated companies 406 1,210 805 (2,410 ) 11 Materials and supplies 53 204 213 — 470 Derivatives 154 — — — 154 Collateral 70 — — — 70 Prepayments and other 48 18 — — 66 1,475 1,841 1,498 (3,256 ) 1,558 PROPERTY, PLANT AND EQUIPMENT: In service 93 6,367 8,233 (382 ) 14,311 Less — Accumulated provision for depreciation 40 2,144 3,775 (194 ) 5,765 53 4,223 4,458 (188 ) 8,546 Construction work in progress 30 249 878 — 1,157 83 4,472 5,336 (188 ) 9,703 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,327 — 1,327 Investment in affiliated companies 7,452 — — (7,452 ) — Other — 10 — — 10 7,452 10 1,327 (7,452 ) 1,337 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 300 16 — (316 ) — Customer intangibles 61 — — — 61 Goodwill 23 — — — 23 Property taxes — 12 28 — 40 Derivatives 79 — — — 79 Other 29 312 14 12 367 492 340 42 (304 ) 570 $ 9,502 $ 6,663 $ 8,203 $ (11,200 ) $ 13,168 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 229 $ 308 $ (25 ) $ 512 Short-term borrowings- Affiliated companies 2,021 389 — (2,410 ) — Other — 8 — — 8 Accounts payable- Affiliated companies 884 146 368 (856 ) 542 Other 21 118 — — 139 Accrued taxes 7 93 62 (86 ) 76 Derivatives 103 1 — — 104 Other 66 61 9 45 181 3,102 1,045 747 (3,332 ) 1,562 CAPITALIZATION: Total equity 5,605 2,944 4,476 (7,420 ) 5,605 Long-term debt and other long-term obligations 690 2,116 840 (1,136 ) 2,510 6,295 5,060 5,316 (8,556 ) 8,115 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 791 791 Accumulated deferred income taxes 6 — 697 (103 ) 600 Retirement benefits 27 305 — — 332 Asset retirement obligations — 191 640 — 831 Derivatives 37 1 — — 38 Other 35 61 803 — 899 105 558 2,140 688 3,491 $ 9,502 $ 6,663 $ 8,203 $ (11,200 ) $ 13,168 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Nine Months Ended September 30, 2016 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (605 ) $ 401 $ 820 $ (12 ) $ 604 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 186 285 — 471 Short-term borrowings, net 701 92 — (692 ) 101 Redemptions and Repayments- Long-term debt — (211 ) (304 ) 12 (503 ) Other — (5 ) (2 ) — (7 ) Net cash provided from (used for) financing activities 701 62 (21 ) (680 ) 62 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (28 ) (171 ) (233 ) — (432 ) Nuclear fuel — — (195 ) — (195 ) Sales of investment securities held in trusts — — 576 — 576 Purchases of investment securities held in trusts — — (619 ) — (619 ) Cash investments 10 — — — 10 Loans to affiliated companies, net (87 ) (292 ) (328 ) 692 (15 ) Other 9 — — — 9 Net cash used for investing activities (96 ) (463 ) (799 ) 692 (666 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Nine Months Ended September 30, 2015 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (624 ) $ 405 $ 867 $ (12 ) $ 636 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 43 296 — 339 Short-term borrowings, net 689 51 — (740 ) — Redemptions and Repayments- Long-term debt (17 ) (55 ) (322 ) 12 (382 ) Short-term borrowings, net — — (27 ) (82 ) (109 ) Other — (4 ) (1 ) — (5 ) Net cash provided from (used for) financing activities 672 35 (54 ) (810 ) (157 ) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (3 ) (144 ) (194 ) — (341 ) Nuclear fuel — — (101 ) — (101 ) Sales of investment securities held in trusts — — 503 — 503 Purchases of investment securities held in trusts — — (546 ) — (546 ) Loans to affiliated companies, net (45 ) (302 ) (475 ) 822 — Cash Investments (10 ) — — — (10 ) Other 10 6 — — 16 Net cash used for investing activities (48 ) (440 ) (813 ) 822 (479 ) 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	9 Months Ended
	Sep. 30, 2016
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 controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment's results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs. The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, and certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP). This segment also includes the regulatory asset associated with the abandoned PATH project. The segment's revenues are primarily derived from forward-looking rates at ATSI and TrAIL, as well as fixed rates at certain of FirstEnergy’s utilities. Both the forward-looking and fixed rates recover costs and provide a return on transmission capital investment. Under the forward-looking rates, each of ATSI's and TrAIL’s revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to annual true-up based on actual costs. Except for the recovery of the PATH abandoned project regulatory asset, the segment's revenues are primarily from transmission services provided to LSEs pursuant to the PJM Tariff. 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. As of September 30, 2016, this business segment controlled 13,162 MWs of electric generating 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, as well as other operating and maintenance costs, including costs incurred by FENOC. Corporate support and other businesses that do not constitute an operating segment, interest expense on stand-alone holding company debt and corporate income taxes are categorized as Corporate/Other for reportable business segment purposes. Additionally, reconciling adjustments for the elimination of inter-segment transactions are included in Corporate/Other. As of September 30, 2016, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of which 28% was subject to variable-interest rates, and $2.7 billion was borrowed by FE under its revolving credit facility. Segment Financial Information For the Three Months Ended Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Reconciling Adjustments Consolidated (In millions) September 30, 2016 External revenues $ 2,702 $ 285 $ 998 $ — $ (68 ) $ 3,917 Internal revenues — — 117 — (117 ) — Total revenues 2,702 285 1,115 — (185 ) 3,917 Depreciation 171 45 79 16 — 311 Amortization of regulatory assets, net 98 — — — — 98 Investment income 13 — 23 2 (10 ) 28 Interest expense 139 43 48 56 — 286 Income taxes (benefits) 167 45 49 (11 ) 1 251 Net income (loss) 283 78 86 (67 ) — 380 Total assets 28,276 8,034 15,165 486 — 51,961 Total goodwill 5,092 526 — — — 5,618 Property additions 303 246 110 5 — 664 September 30, 2015 External revenues $ 2,624 $ 248 $ 1,327 $ — $ (76 ) $ 4,123 Internal revenues — — 141 — (141 ) — Total revenues 2,624 248 1,468 — (217 ) 4,123 Depreciation 174 41 98 15 — 328 Amortization of regulatory assets, net 110 — — — — 110 Impairment of assets 8 — — — — 8 Investment income (loss) 8 — (19 ) (6 ) (11 ) (28 ) Interest expense 149 40 48 48 — 285 Income taxes (benefits) 137 41 84 (39 ) 3 226 Net income (loss) 234 70 145 (54 ) — 395 Total assets 27,883 6,988 16,229 830 — 51,930 Total goodwill 5,092 526 800 — — 6,418 Property additions 292 149 83 15 — 539 For the Nine Months Ended September 30, 2016 External revenues $ 7,423 $ 824 $ 3,158 $ — $ (218 ) $ 11,187 Internal revenues — — 377 — (377 ) — Total revenues 7,423 824 3,535 — (595 ) 11,187 Depreciation 510 132 284 48 — 974 Amortization of regulatory assets, net 218 4 — — — 222 Impairment of assets (Note 2) — — 1,447 — — 1,447 Investment income 37 — 56 13 (31 ) 75 Interest expense 431 128 143 161 — 863 Income taxes (benefits) 349 130 (96 ) (51 ) 2 334 Net income (loss) 594 223 (1,029 ) (169 ) — (381 ) Property additions 878 755 492 31 — 2,156 September 30, 2015 External revenues $ 7,425 $ 755 $ 3,536 $ — $ (231 ) $ 11,485 Internal revenues — — 563 — (563 ) — Total revenues 7,425 755 4,099 — (794 ) 11,485 Depreciation 516 116 293 44 — 969 Amortization of regulatory assets, net 196 5 — — — 201 Impairment of assets 8 — 16 — — 24 Investment income (loss) 33 — (7 ) (9 ) (31 ) (14 ) Interest expense 439 119 144 144 — 846 Income taxes (benefits) 350 135 76 (84 ) 8 485 Net income (loss) 598 231 129 (154 ) — 804 Property additions 884 700 400 41 — 2,025

Organization and Basis of Pre26

Organization and Basis of Presentation (Policies)	9 Months Ended
	Sep. 30, 2016
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 as appropriate. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 7, Variable Interest Entities). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, 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 of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss).
New Accounting Pronouncements	New Accounting Pronouncements In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers". Subsequent accounting standards updates have been issued which amend and/or clarify the application of ASU 2014-09. The core principle of the new guidance is that an entity recognizes revenue 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. More detailed disclosures will also be required to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For public business entities, the new revenue recognition guidance will be effective for annual and interim reporting periods beginning after December 15, 2017. Earlier adoption is permitted for annual and interim reporting periods beginning after December 15, 2016. The standards shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting these standards. In February 2015, the FASB issued ASU 2015-02, "Consolidations: Amendments to the Consolidation Analysis", which amends current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate whether an entity should be consolidated. 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's adoption of ASU 2015-02, on January 1, 2016, did not result in a change in the consolidation of VIEs by FE or its subsidiaries. In April 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs", which requires debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. I n addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements", which allows debt issuance costs related to line of credit arrangements to be presented as an asset and amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit. FirstEnergy adopted ASU 2015-15 and ASU 2015-03 beginning January 1, 2016. As of December 31, 2015, FirstEnergy and FES reclassified $93 million and $17 million of debt issuance costs included in Deferred charges and other assets to Long-term debt and Other long-term obligations. FirstEnergy has elected to continue presenting debt issuance costs relating to its revolving credit facilities as an asset. In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities . The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption for certain provisions can be elected for all financial statements of fiscal years and interim periods that have not yet been issued or that have not yet been made available for issuance. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted . Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment . FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In March of 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", which simplifies several aspects of the accounting for employee share-based payment. The new guidance will require all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also will not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted for fiscal years beginning after December 15, 2018. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments". The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted for all entities. FirstEnergy does not expect this ASU to have a material effect on its financial statements. In October 2016, the FASB issued ASU 2016-16, " Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory." ASU 2016-16 eliminates the exception for all intra-entity sales of assets other than inventory, which allows companies to defer the tax effects of intra-entity asset transfers. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the intra-entity transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted and the modified retrospective approach will be required for transition to the new guidance, with a cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. Additionally, during 2016, the FASB issued the following ASUs: • ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships,” • ASU 2016-06, “Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging Issues Task Force)," • ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting," and • ASU 2016-17, “Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control.” FirstEnergy does not expect these ASUs to have a material effect on its financial statements.
Asset Impairment Policy	FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, an impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. FirstEnergy utilizes the income approach, based upon discounted cash flows to estimate fair value.
Earnings Per Share	Basic earnings per share of common stock are computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised.
Variable Interest Entities	FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has; (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. The caption "noncontrolling interest" within the consolidated financial statements is used to reflect the portion of a VIE that FirstEnergy consolidates, but does not own.
Investment Policy	All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and AFS securities. At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy 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.
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.
Derivatives Instruments Policy	FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance.

Asset Impairments (Tables)

Asset Impairments (Tables)	9 Months Ended
	Sep. 30, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill by Segment	The following table presents the changes in the carrying value of goodwill for the nine months ended September 30, 2016 : Goodwill Regulated Distribution Regulated Transmission Competitive Energy Services Consolidated (In millions) Balance as of December 31, 2015 $ 5,092 $ 526 $ 800 $ 6,418 Impairment — — (800 ) (800 ) Balance as of September 30, 2016 $ 5,092 $ 526 $ — $ 5,618

Earnings Per Share Of Common 28

Earnings Per Share Of Common Stock (Tables)	9 Months Ended
	Sep. 30, 2016
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) For the Three Months Ended September 30 For the Nine Months Ended September 30 Reconciliation of Basic and Diluted Earnings per Share of Common Stock 2016 2015 2016 2015 Net income (loss) $ 380 $ 395 $ (381 ) $ 804 Weighted average number of basic shares outstanding 425 423 425 422 Assumed exercise of dilutive stock options and awards (1) 2 1 — 1 Weighted average number of diluted shares outstanding 427 424 425 423 Basic earnings (losses) per share of common stock $ 0.89 $ 0.94 $ (0.90 ) $ 1.91 Diluted earnings (losses) per share of common stock $ 0.89 $ 0.93 $ (0.90 ) $ 1.90 (1) For the nine months ended September 30, 2016 , three million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive as a result of the net loss for the period. For the three months ended September 30, 2016 and 2015, and for the nine months ended September 30, 2015, one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

Pension and Other Postemploym29

Pension and Other Postemployment Benefits (Tables)	9 Months Ended
	Sep. 30, 2016
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 September 30 2016 2015 2016 2015 (In millions) Service costs $ 48 $ 49 $ 2 $ 2 Interest costs 99 96 7 7 Expected return on plan assets (100 ) (111 ) (7 ) (9 ) Amortization of prior service costs (credits) 2 2 (20 ) (33 ) Net periodic costs (credits) $ 49 $ 36 $ (18 ) $ (33 ) Components of Net Periodic Benefit Costs (Credits) Pension OPEB For the Nine Months Ended September 30 2016 2015 2016 2015 (In millions) Service costs $ 144 $ 145 $ 4 $ 4 Interest costs 298 288 22 21 Expected return on plan assets (297 ) (333 ) (23 ) (25 ) Amortization of prior service costs (credits) 6 6 (60 ) (100 ) Net periodic costs (credits) $ 151 $ 106 $ (57 ) $ (100 )
Net Periodic Pension and OPEB Costs	FES' share of the net periodic pension and OPEB costs (credits) were as follows: Pension OPEB 2016 2015 2016 2015 (In millions) For the Three Months Ended September 30 $ 6 $ 4 $ (4 ) $ (5 ) For the Nine Months Ended September 30 18 12 (12 ) (15 ) 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 FirstEnergy and FES were as follows: Net Periodic Benefit Expense (Credit) Pension OPEB For the Three Months Ended September 30 2016 2015 2016 2015 (In millions) FirstEnergy $ 35 $ 25 $ (11 ) $ (21 ) FES 5 4 (4 ) (4 ) Net Periodic Benefit Expense (Credit) Pension OPEB For the Nine Months Ended September 30 2016 2015 2016 2015 (In millions) FirstEnergy $ 107 $ 74 $ (41 ) $ (66 ) FES 17 12 (12 ) (12 )

Accumulated Other Comprehensi30

Accumulated Other Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of Accumulated Other Comprehensive Income	The changes in AOCI, net of tax, in the three and nine months ended September 30, 2016 and 2015 , for FirstEnergy are included 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 July 1, 2016 $ (31 ) $ 58 $ 164 $ 191 Other comprehensive income before reclassifications — 21 — 21 Amounts reclassified from AOCI 2 (17 ) (18 ) (33 ) Other comprehensive income (loss) 2 4 (18 ) (12 ) Income taxes (benefits) on other comprehensive income (loss) — 2 (7 ) (5 ) Other comprehensive income (loss), net of tax 2 2 (11 ) (7 ) AOCI Balance as of September 30, 2016 $ (29 ) $ 60 $ 153 $ 184 AOCI Balance as of July 1, 2015 $ (36 ) $ 19 $ 219 $ 202 Other comprehensive loss before reclassifications — (8 ) — (8 ) Amounts reclassified from AOCI 2 (3 ) (31 ) (32 ) Other comprehensive income (loss) 2 (11 ) (31 ) (40 ) Income taxes (benefits) on other comprehensive income (loss) 1 (4 ) (12 ) (15 ) Other comprehensive income (loss), net of tax 1 (7 ) (19 ) (25 ) AOCI Balance as of September 30, 2015 $ (35 ) $ 12 $ 200 $ 177 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, 2016 $ (33 ) $ 18 $ 186 $ 171 Other comprehensive income before reclassifications — 109 — 109 Amounts reclassified from AOCI 6 (42 ) (54 ) (90 ) Other comprehensive income (loss) 6 67 (54 ) 19 Income taxes (benefits) on other comprehensive income (loss) 2 25 (21 ) 6 Other comprehensive income (loss), net of tax 4 42 (33 ) 13 AOCI Balance as of September 30, 2016 $ (29 ) $ 60 $ 153 $ 184 AOCI Balance as of January 1, 2015 $ (37 ) $ 25 $ 258 $ 246 Other comprehensive loss before reclassifications — (1 ) — (1 ) Amounts reclassified from AOCI 4 (20 ) (94 ) (110 ) Other comprehensive income (loss) 4 (21 ) (94 ) (111 ) Income taxes (benefits) on other comprehensive income (loss) 2 (8 ) (36 ) (42 ) Other comprehensive income (loss), net of tax 2 (13 ) (58 ) (69 ) AOCI Balance as of September 30, 2015 $ (35 ) $ 12 $ 200 $ 177
Reclassification out of Accumulated Other Comprehensive Income	The following amounts were reclassified from AOCI for FirstEnergy in the three and nine months ended September 30, 2016 and 2015 : For the Three Months Ended September 30 For the Nine Months Ended September 30 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2016 2015 2016 2015 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ — $ — $ (2 ) Other operating expenses Long-term debt 2 2 6 6 Interest expense 2 2 6 4 Total before taxes — (1 ) (2 ) (2 ) Income taxes $ 2 $ 1 $ 4 $ 2 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (17 ) $ (3 ) $ (42 ) $ (20 ) Investment income (loss) 7 1 16 7 Income taxes $ (10 ) $ (2 ) $ (26 ) $ (13 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (18 ) $ (31 ) $ (54 ) $ (94 ) (1) 7 12 21 36 Income taxes $ (11 ) $ (19 ) $ (33 ) $ (58 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 4, Pension and Other Postemployment Benefits for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.
FES
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of Accumulated Other Comprehensive Income	The changes in AOCI, net of tax, in the three and nine months ended September 30, 2016 and 2015 , for FES are included 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 July 1, 2016 $ (10 ) $ 50 $ 35 $ 75 Other comprehensive income before reclassifications — 22 — 22 Amounts reclassified from AOCI 1 (17 ) (3 ) (19 ) Other comprehensive income (loss) 1 5 (3 ) 3 Income taxes (benefits) on other comprehensive income (loss) — 2 (1 ) 1 Other comprehensive income (loss), net of tax 1 3 (2 ) 2 AOCI Balance as of September 30, 2016 $ (9 ) $ 53 $ 33 $ 77 AOCI Balance as of July 1, 2015 $ (9 ) $ 16 $ 38 $ 45 Other comprehensive loss before reclassifications — (7 ) — (7 ) Amounts reclassified from AOCI — (4 ) (4 ) (8 ) Other comprehensive loss — (11 ) (4 ) (15 ) Income tax benefits on other comprehensive loss — (5 ) (1 ) (6 ) Other comprehensive loss, net of tax — (6 ) (3 ) (9 ) AOCI Balance as of September 30, 2015 $ (9 ) $ 10 $ 35 $ 36 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, 2016 $ (9 ) $ 16 $ 39 $ 46 Other comprehensive income before reclassifications — 102 — 102 Amounts reclassified from AOCI — (41 ) (10 ) (51 ) Other comprehensive income (loss) — 61 (10 ) 51 Income taxes (benefits) on other comprehensive income (loss) — 24 (4 ) 20 Other comprehensive income (loss), net of tax — 37 (6 ) 31 AOCI Balance as of September 30, 2016 $ (9 ) $ 53 $ 33 $ 77 AOCI Balance as of January 1, 2015 $ (7 ) $ 21 $ 43 $ 57 Other comprehensive loss before reclassifications — (1 ) — (1 ) Amounts reclassified from AOCI (2 ) (19 ) (12 ) (33 ) Other comprehensive loss (2 ) (20 ) (12 ) (34 ) Income tax benefits on other comprehensive loss — (9 ) (4 ) (13 ) Other comprehensive loss, net of tax (2 ) (11 ) (8 ) (21 ) AOCI Balance as of September 30, 2015 $ (9 ) $ 10 $ 35 $ 36
Reclassification out of Accumulated Other Comprehensive Income	The following amounts were reclassified from AOCI for FES in the three and nine months ended September 30, 2016 and 2015 : For the Three Months Ended September 30 For the Nine Months Ended September 30 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2016 2015 2016 2015 (In millions) Gains & losses on cash flow hedges Commodity contracts $ 1 $ — $ — $ (2 ) Other operating expenses — — — — Income taxes $ 1 $ — $ — $ (2 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (17 ) $ (3 ) $ (41 ) $ (18 ) Investment income (loss) 6 1 15 7 Income taxes $ (11 ) $ (2 ) $ (26 ) $ (11 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (3 ) $ (4 ) $ (10 ) $ (12 ) (1) 1 1 4 4 Income taxes $ (2 ) $ (3 ) $ (6 ) $ (8 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 4, Pension and Other Postemployment Benefits for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Operations from AOCI.

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	9 Months Ended
	Sep. 30, 2016
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 September 30, 2016 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy $ 1,137 $ 895 $ 242 FES 1,110 887 223

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2016
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 September 30, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,242 $ — $ 1,242 $ — $ 1,245 $ — $ 1,245 Derivative assets - commodity contracts 7 230 — 237 4 224 — 228 Derivative assets - FTRs — — 13 13 — — 8 8 Derivative assets - NUG contracts (1) — — — — — — 1 1 Equity securities (2) 908 — — 908 576 — — 576 Foreign government debt securities — 77 — 77 — 75 — 75 U.S. government debt securities — 173 — 173 — 180 — 180 U.S. state debt securities — 255 — 255 — 246 — 246 Other (3) 551 126 — 677 105 212 — 317 Total assets $ 1,466 $ 2,103 $ 13 $ 3,582 $ 685 $ 2,182 $ 9 $ 2,876 Liabilities Derivative liabilities - commodity contracts $ (12 ) $ (122 ) $ — $ (134 ) $ (9 ) $ (122 ) $ — $ (131 ) Derivative liabilities - FTRs — — (7 ) (7 ) — — (13 ) (13 ) Derivative liabilities - NUG contracts (1) — — (118 ) (118 ) — — (137 ) (137 ) Total liabilities $ (12 ) $ (122 ) $ (125 ) $ (259 ) $ (9 ) $ (122 ) $ (150 ) $ (281 ) Net assets (liabilities) (4) $ 1,454 $ 1,981 $ (112 ) $ 3,323 $ 676 $ 2,060 $ (141 ) $ 2,595 (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 $(8) million and $7 million as of September 30, 2016 and December 31, 2015 , 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 September 30, 2016 and December 31, 2015 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2015 Balance $ 2 $ (153 ) $ (151 ) $ 39 $ (14 ) $ 25 Unrealized gain (loss) 2 (49 ) (47 ) (5 ) (7 ) (12 ) Purchases — — — 22 (11 ) 11 Settlements (3 ) 65 62 (48 ) 19 (29 ) December 31, 2015 Balance $ 1 $ (137 ) $ (136 ) $ 8 $ (13 ) $ (5 ) Unrealized gain (loss) — (17 ) (17 ) (8 ) 1 (7 ) Purchases — — — 17 (8 ) 9 Settlements (1 ) 36 35 (4 ) 13 9 September 30, 2016 Balance $ — $ (118 ) $ (118 ) $ 13 $ (7 ) $ 6 (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
Quantitative information for level 3 valuation	The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended September 30, 2016 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 6 Model RTO auction clearing prices $(2.20) to $7.60 $1.00 Dollars/MWH NUG Contracts $ (118 ) Model Generation 400 to 3,207,000 661,000 MWH Regional electricity prices $30.90 to $35.30 $32.10 Dollars/MWH
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities	The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT and nuclear fuel disposal trusts as of September 30, 2016 and December 31, 2015 : September 30, 2016 (1) December 31, 2015 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,728 $ 69 $ 1,797 $ 1,778 $ 16 $ 1,794 FES 834 45 879 801 9 810 Equity securities FirstEnergy $ 816 $ 92 $ 908 $ 542 $ 34 $ 576 FES 561 63 624 354 24 378 (1) Excludes short-term cash investments: FirstEnergy - $50 million ; FES - $39 million . (2) Excludes short-term cash investments: FirstEnergy - $157 million ; FES - $139 million .
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income	Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three and nine months ended September 30, 2016 and 2015 were as follows: For the Three Months Ended September 30, 2016 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 337 $ 36 $ (15 ) $ (3 ) $ 27 FES 135 23 (6 ) (3 ) 16 September 30, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 307 $ 33 $ (32 ) $ (46 ) $ 25 FES 127 28 (24 ) (41 ) 14 For the Nine Months Ended September 30, 2016 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 1,361 $ 131 $ (88 ) $ (13 ) $ 75 FES 576 90 (49 ) (12 ) 42 September 30, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 1,126 $ 135 $ (121 ) $ (70 ) $ 75 FES 503 98 (79 ) (63 ) 43
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 debt issuance costs, premiums and discounts: September 30, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 19,745 $ 21,465 $ 20,244 $ 21,519 FES 3,003 2,662 3,027 3,121
FES
Fair Value of Financial Instruments [Line Items]
Assets and liabilities measured on recurring basis	FES Recurring Fair Value Measurements September 30, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 714 $ — $ 714 $ — $ 678 $ — $ 678 Derivative assets - commodity contracts 7 230 — 237 4 224 — 228 Derivative assets - FTRs — — 7 7 — — 5 5 Equity securities (1) 624 — — 624 378 — — 378 Foreign government debt securities — 59 — 59 — 59 — 59 U.S. government debt securities — 53 — 53 — 23 — 23 U.S. state debt securities — 4 — 4 — 4 — 4 Other (2) 2 87 — 89 — 184 — 184 Total assets $ 633 $ 1,147 $ 7 $ 1,787 $ 382 $ 1,172 $ 5 $ 1,559 Liabilities Derivative liabilities - commodity contracts $ (12 ) $ (122 ) $ — $ (134 ) $ (9 ) $ (122 ) $ — $ (131 ) Derivative liabilities - FTRs — — (5 ) (5 ) — — (11 ) (11 ) Total liabilities $ (12 ) $ (122 ) $ (5 ) $ (139 ) $ (9 ) $ (122 ) $ (11 ) $ (142 ) Net assets (liabilities) (3) $ 621 $ 1,025 $ 2 $ 1,648 $ 373 $ 1,050 $ (6 ) $ 1,417 (1) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (2) Primarily consists of short-term cash investments. (3) Excludes $1 million as of September 30, 2016 and December 31, 2015 , 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 September 30, 2016 and December 31, 2015 : Derivative Asset Derivative Liability Net Asset (Liability) (In millions) January 1, 2015 Balance $ 27 $ (13 ) $ 14 Unrealized gain (loss) 2 (5 ) (3 ) Purchases 9 (10 ) (1 ) Settlements (33 ) 17 (16 ) December 31, 2015 Balance $ 5 $ (11 ) $ (6 ) Unrealized gain (loss) (7 ) 1 (6 ) Purchases 10 (5 ) 5 Settlements (1 ) 10 9 September 30, 2016 Balance $ 7 $ (5 ) $ 2
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 September 30, 2016 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 2 Model RTO auction clearing prices ($2.20) to $7.60 $0.70 Dollars/MWH

Derivative Instruments (Tables)

Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2016
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 September 30, December 31, September 30, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 139 $ 150 Commodity Contracts $ (84 ) $ (94 ) FTRs 13 7 FTRs (7 ) (12 ) 152 157 (91 ) (106 ) Deferred Charges and Other Assets - Other Noncurrent Liabilities - Adverse Power Contract Liability NUGs (1) (118 ) (137 ) Commodity Contracts 98 78 Noncurrent Liabilities - Other FTRs — 1 Commodity Contracts (50 ) (37 ) NUGs (1) — 1 FTRs — (1 ) 98 80 (168 ) (175 ) Derivative Assets $ 250 $ 237 Derivative Liabilities $ (259 ) $ (281 ) (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
Offsetting assets and liabilities	The following tables summarize the fair value of derivative assets and derivative liabilities on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet September 30, 2016 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 237 $ (120 ) $ (22 ) $ 95 FTRs 13 (7 ) — 6 NUG contracts — — — — $ 250 $ (127 ) $ (22 ) $ 101 Derivative Liabilities Commodity contracts $ (134 ) $ 120 $ 8 $ (6 ) FTRs (7 ) 7 — — NUG contracts (118 ) — — (118 ) $ (259 ) $ 127 $ 8 $ (124 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 228 $ (125 ) $ — $ 103 FTRs 8 (8 ) — — NUG contracts 1 — — 1 $ 237 $ (133 ) $ — $ 104 Derivative Liabilities Commodity contracts $ (131 ) $ 125 $ 3 $ (3 ) FTRs (13 ) 8 5 — NUG contracts (137 ) — — (137 ) $ (281 ) $ 133 $ 8 $ (140 )
Volume of First Energy's outstanding derivative transactions	The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of September 30, 2016 : Purchases Sales Net Units (In millions) Power Contracts 9 49 (40 ) MWH FTRs 42 — 42 MWH NUGs 3 — 3 MWH Natural Gas 49 — 49 mmBTU
Effect of derivative instruments on statements of income and comprehensive income	The effect of active derivative instruments not in a hedging relationship on the Consolidated Statements of Income (Loss) during the three months and nine months ended September 30, 2016 and 2015 , are summarized in the following tables: For the Three Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain (Loss) Recognized in: Other Operating Expense (1) $ 19 $ (3 ) $ 16 Realized Gain (Loss) Reclassified to: Revenues (1) $ 32 $ 1 $ 33 Purchased Power Expense (1) (22 ) — (22 ) Other Operating Expense (1) — (6 ) (6 ) Fuel Expense (2 ) — (2 ) (1) All amounts are associated with FES. For the Three Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense (2) $ 59 $ (2 ) $ 57 Realized Gain (Loss) Reclassified to: Revenues (2) $ 41 $ 2 $ 43 Purchased Power Expense (2) (50 ) — (50 ) Other Operating Expense (2) — (11 ) (11 ) Fuel Expense (5 ) — (5 ) (2) All amounts are associated with FES. For the Nine Months Ended September 30 Commodity Contracts FTRs Total 2016 (In millions) Unrealized Gain Recognized in: Other Operating Expense (1) $ 2 $ 8 $ 10 Realized Gain (Loss) Reclassified to: Revenues (1) $ 162 $ 5 $ 167 Purchased Power Expense (1) (105 ) — (105 ) Other Operating Expense (1) — (28 ) (28 ) Fuel Expense (9 ) — (9 ) (1) All amounts are associated with FES. For the Nine Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense (2) $ 81 $ (17 ) $ 64 Realized Gain (Loss) Reclassified to: Revenues (3) $ 48 $ 48 $ 96 Purchased Power Expense (4) (78 ) — (78 ) Other Operating Expense (5) — (38 ) (38 ) Fuel Expense (26 ) — (26 ) (2) Includes $81 million for commodity contracts and $(16) million for FTRs associated with FES. (3) Includes $48 million for commodity contracts and $46 million for FTRs associated with FES. (4) All amounts are associated with FES. (5) Includes $(37) million for FTRs associated with FES.
Reconciliation of changes in the fair value of certain contracts that are deferred	The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during the three and nine months ended September 30, 2016 and 2015 . Changes in the value of these instruments are deferred for future recovery from (or credit to) customers: For the Three Months Ended September 30 Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of July 1, 2016 $ (124 ) $ 4 $ (120 ) Unrealized loss (6 ) — (6 ) Settlements 12 — 12 Outstanding net asset (liability) as of September 30, 2016 $ (118 ) $ 4 $ (114 ) Outstanding net asset (liability) as of July 1, 2015 $ (140 ) $ 12 $ (128 ) Unrealized loss (20 ) (4 ) (24 ) Settlements 17 (3 ) 14 Outstanding net asset (liability) as of September 30, 2015 $ (143 ) $ 5 $ (138 ) For the Nine Months Ended September 30 Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of January 1, 2016 $ (136 ) $ 1 $ (135 ) Unrealized loss (17 ) (1 ) (18 ) Purchases — 4 4 Settlements 35 — 35 Outstanding net asset (liability) as of September 30, 2016 $ (118 ) $ 4 $ (114 ) Outstanding net asset (liability) as of January 1, 2015 $ (151 ) $ 11 $ (140 ) Unrealized loss (36 ) (3 ) (39 ) Purchases — 12 12 Settlements 44 (15 ) 29 Outstanding net asset (liability) as of September 30, 2015 $ (143 ) $ 5 $ (138 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation [Abstract]
Fair Values of the Decommissioning Trust Assets	FirstEnergy and FES maintain NDTs that are legally restricted for purposes of settling the nuclear decommissioning ARO. The fair values of the decommissioning trust assets as of September 30, 2016 and December 31, 2015 were as follows: 2016 2015 (In millions) FirstEnergy $ 2,502 $ 2,282 FES $ 1,542 $ 1,327
Changes to ARO Balances	The following table summarizes the changes to the ARO balances during 2016 : ARO Reconciliation FirstEnergy FES (In millions) Balance, December 31, 2015 $ 1,410 $ 831 Liabilities settled (25 ) (17 ) Liabilities incurred 4 32 Accretion 70 41 Balance, September 30, 2016 $ 1,459 $ 887

Commitments, Guarantees and C35

Commitments, Guarantees and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2016
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 November 4, 2016 : Potential Collateral Obligations CES Regulated Total (in millions) Contractual Obligations for Additional Collateral At Current Credit Rating $ 81 $ — $ 81 Upon Further Downgrade — 48 48 Upon Material Adverse Event 10 — 10 Surety Bonds (Collateralized Amount) 264 96 360 Total Exposure from Contractual Obligations $ 355 $ 144 $ 499

Supplemental Guarantor Inform36

Supplemental Guarantor Information (Tables)	9 Months Ended
	Sep. 30, 2016
Supplemental Guarantor Information [Abstract]
Condensed Consolidating Statements of Operations and Comprehensive Income (Loss)	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Three Months Ended September 30, 2016 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 1,065 $ 494 $ 400 $ (859 ) $ 1,100 OPERATING EXPENSES: Fuel — 149 53 — 202 Purchased power from affiliates 1,011 — 39 (859 ) 191 Purchased power from non-affiliates 186 — — — 186 Other operating expenses 95 61 149 11 316 Provision for depreciation 4 28 51 — 83 General taxes 8 7 6 — 21 Total operating expenses 1,304 245 298 (848 ) 999 OPERATING INCOME (LOSS) (239 ) 249 102 (11 ) 101 OTHER INCOME (EXPENSE): Investment income, including net income from equity investees 224 8 28 (236 ) 24 Miscellaneous income — 1 — — 1 Interest expense — affiliates (13 ) (3 ) (2 ) 15 (3 ) Interest expense — other (14 ) (27 ) (9 ) 14 (36 ) Capitalized interest — 3 6 — 9 Total other income (expense) 197 (18 ) 23 (207 ) (5 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (42 ) 231 125 (218 ) 96 INCOME TAXES (BENEFITS) (82 ) 87 49 2 56 NET INCOME $ 40 $ 144 $ 76 $ (220 ) $ 40 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 40 $ 144 $ 76 $ (220 ) $ 40 OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (3 ) (3 ) — 3 (3 ) Amortized gains on derivative hedges 1 — — — 1 Change in unrealized gains on available-for-sale securities 5 — 5 (5 ) 5 Other comprehensive income (loss) 3 (3 ) 5 (2 ) 3 Income taxes (benefits) on other comprehensive income (loss) 1 (1 ) 2 (1 ) 1 Other comprehensive income (loss), net of tax 2 (2 ) 3 (1 ) 2 COMPREHENSIVE INCOME $ 42 $ 142 $ 79 $ (221 ) $ 42 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Nine Months Ended September 30, 2016 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 3,281 $ 1,309 $ 1,404 $ (2,593 ) $ 3,401 OPERATING EXPENSES: Fuel — 449 146 — 595 Purchased power from affiliates 2,888 — 145 (2,593 ) 440 Purchased power from non-affiliates 829 — — — 829 Other operating expenses 218 220 450 37 925 Provision for depreciation 10 91 151 (2 ) 250 General taxes 23 23 20 — 66 Impairment of assets 23 517 — — 540 Total operating expenses 3,991 1,300 912 (2,558 ) 3,645 OPERATING INCOME (LOSS) (710 ) 9 492 (35 ) (244 ) OTHER INCOME (EXPENSE): Investment income, including net income (loss) from equity investees 310 21 67 (342 ) 56 Miscellaneous income 3 1 — — 4 Interest expense — affiliates (34 ) (7 ) (4 ) 39 (6 ) Interest expense — other (40 ) (79 ) (33 ) 43 (109 ) Capitalized interest — 7 20 — 27 Total other income (expense) 239 (57 ) 50 (260 ) (28 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (471 ) (48 ) 542 (295 ) (272 ) INCOME TAXES (BENEFITS) (204 ) (1 ) 196 4 (5 ) NET INCOME (LOSS) $ (267 ) $ (47 ) $ 346 $ (299 ) $ (267 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (267 ) $ (47 ) $ 346 $ (299 ) $ (267 ) OTHER COMPREHENSIVE INCOME (LOSS): Pensions and OPEB prior service costs (10 ) (10 ) — 10 (10 ) Amortized gains on derivative hedges — — — — — Change in unrealized gains on available-for-sale securities 61 — 60 (60 ) 61 Other comprehensive income (loss) 51 (10 ) 60 (50 ) 51 Income taxes (benefits) on other comprehensive income (loss) 20 (4 ) 23 (19 ) 20 Other comprehensive income (loss), net of tax 31 (6 ) 37 (31 ) 31 COMPREHENSIVE INCOME (LOSS) $ (236 ) $ (53 ) $ 383 $ (330 ) $ (236 ) FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Three Months Ended September 30, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 1,293 $ 420 $ 531 $ (906 ) $ 1,338 OPERATING EXPENSES: Fuel — 193 52 — 245 Purchased power from affiliates 932 — 77 (906 ) 103 Purchased power from non-affiliates 401 — — — 401 Other operating expenses 34 66 134 12 246 Provision for depreciation 3 30 47 (1 ) 79 General taxes 10 8 6 — 24 Total operating expenses 1,380 297 316 (895 ) 1,098 OPERATING INCOME (LOSS) (87 ) 123 215 (11 ) 240 OTHER INCOME (EXPENSE): Investment income (loss), including net income from equity investees 191 4 (18 ) (198 ) (21 ) Miscellaneous income — 1 — — 1 Interest expense — affiliates (8 ) (2 ) (1 ) 9 (2 ) Interest expense — other (13 ) (26 ) (12 ) 15 (36 ) Capitalized interest — 1 7 — 8 Total other income (expense) 170 (22 ) (24 ) (174 ) (50 ) INCOME BEFORE INCOME TAXES (BENEFITS) 83 101 191 (185 ) 190 INCOME TAXES (BENEFITS) (37 ) 36 70 1 70 NET INCOME $ 120 $ 65 $ 121 $ (186 ) $ 120 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 120 $ 65 $ 121 $ (186 ) $ 120 OTHER COMPREHENSIVE LOSS: Pension and OPEB prior service costs (4 ) (3 ) — 3 (4 ) Amortized gains on derivative hedges — — — — — Change in unrealized gains on available for sale securities (11 ) — (11 ) 11 (11 ) Other comprehensive loss (15 ) (3 ) (11 ) 14 (15 ) Income tax benefits on other comprehensive loss (6 ) (1 ) (4 ) 5 (6 ) Other comprehensive loss, net of tax (9 ) (2 ) (7 ) 9 (9 ) COMPREHENSIVE INCOME $ 111 $ 63 $ 114 $ (177 ) $ 111 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Nine Months Ended September 30, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 3,699 $ 1,259 $ 1,494 $ (2,618 ) $ 3,834 OPERATING EXPENSES: Fuel — 523 143 — 666 Purchased power from affiliates 2,657 — 211 (2,618 ) 250 Purchased power from non-affiliates 1,336 — — — 1,336 Other operating expenses 300 208 452 36 996 Provision for depreciation 8 92 142 (2 ) 240 General taxes 36 23 19 — 78 Impairment of assets 16 — — — 16 Total operating expenses 4,353 846 967 (2,584 ) 3,582 OPERATING INCOME (LOSS) (654 ) 413 527 (34 ) 252 OTHER INCOME (EXPENSE): Investment income (loss), including net income from equity investees 551 12 (1 ) (569 ) (7 ) Miscellaneous income 1 4 — — 5 Interest expense — affiliates (21 ) (6 ) (3 ) 24 (6 ) Interest expense — other (39 ) (78 ) (37 ) 44 (110 ) Capitalized interest — 4 22 — 26 Total other income (expense) 492 (64 ) (19 ) (501 ) (92 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (162 ) 349 508 (535 ) 160 INCOME TAXES (BENEFITS) (258 ) 131 187 4 64 NET INCOME $ 96 $ 218 $ 321 $ (539 ) $ 96 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 96 $ 218 $ 321 $ (539 ) $ 96 OTHER COMPREHENSIVE LOSS Pension and OPEB prior service costs (12 ) (11 ) — 11 (12 ) Amortized gains on derivative hedges (2 ) — — — (2 ) Change in unrealized gains on available-for-sale securities (20 ) — (20 ) 20 (20 ) Other comprehensive loss (34 ) (11 ) (20 ) 31 (34 ) Income tax benefits on other comprehensive loss (13 ) (4 ) (7 ) 11 (13 ) Other comprehensive loss, net of tax (21 ) (7 ) (13 ) 20 (21 ) COMPREHENSIVE INCOME $ 75 $ 211 $ 308 $ (519 ) $ 75
Condensed Consolidating Balance Sheets	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of September 30, 2016 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 225 — — — 225 Affiliated companies 356 351 267 (492 ) 482 Other 21 4 30 — 55 Notes receivable from affiliated companies 494 1,501 1,133 (3,102 ) 26 Materials and supplies 38 153 212 — 403 Derivatives 146 — — — 146 Collateral 85 — — — 85 Prepayments and other 57 14 1 — 72 1,422 2,025 1,643 (3,594 ) 1,496 PROPERTY, PLANT AND EQUIPMENT: In service 121 5,683 8,674 (378 ) 14,100 Less — Accumulated provision for depreciation 49 1,915 4,050 (192 ) 5,822 72 3,768 4,624 (186 ) 8,278 Construction work in progress 3 287 758 — 1,048 75 4,055 5,382 (186 ) 9,326 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,542 — 1,542 Investment in affiliated companies 7,826 — — (7,826 ) — Other — 10 — — 10 7,826 10 1,542 (7,826 ) 1,552 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 279 27 — (306 ) — Customer intangibles 11 — — — 11 Property taxes — 3 7 — 10 Derivatives 98 — — — 98 Other 29 333 — 12 374 417 363 7 (294 ) 493 $ 9,740 $ 6,453 $ 8,574 $ (11,900 ) $ 12,867 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 199 $ 8 $ (25 ) $ 182 Short-term borrowings- Affiliated companies 2,723 480 — (3,102 ) 101 Accounts payable- Affiliated companies 597 165 180 (549 ) 393 Other 18 71 — — 89 Accrued taxes 31 28 51 (38 ) 72 Derivatives 88 1 — — 89 Other 66 71 12 33 182 3,523 1,015 251 (3,681 ) 1,108 CAPITALIZATION: Total equity 5,409 2,897 4,893 (7,790 ) 5,409 Long-term debt and other long-term obligations 691 2,108 1,120 (1,104 ) 2,815 6,100 5,005 6,013 (8,894 ) 8,224 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 765 765 Accumulated deferred income taxes 7 — 817 (90 ) 734 Retirement benefits 25 194 — — 219 Asset retirement obligations — 186 701 — 887 Derivatives 45 5 — — 50 Other 40 48 792 — 880 117 433 2,310 675 3,535 $ 9,740 $ 6,453 $ 8,574 $ (11,900 ) $ 12,867 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2015 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 275 — — — 275 Affiliated companies 433 403 461 (846 ) 451 Other 36 4 19 — 59 Notes receivable from affiliated companies 406 1,210 805 (2,410 ) 11 Materials and supplies 53 204 213 — 470 Derivatives 154 — — — 154 Collateral 70 — — — 70 Prepayments and other 48 18 — — 66 1,475 1,841 1,498 (3,256 ) 1,558 PROPERTY, PLANT AND EQUIPMENT: In service 93 6,367 8,233 (382 ) 14,311 Less — Accumulated provision for depreciation 40 2,144 3,775 (194 ) 5,765 53 4,223 4,458 (188 ) 8,546 Construction work in progress 30 249 878 — 1,157 83 4,472 5,336 (188 ) 9,703 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,327 — 1,327 Investment in affiliated companies 7,452 — — (7,452 ) — Other — 10 — — 10 7,452 10 1,327 (7,452 ) 1,337 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 300 16 — (316 ) — Customer intangibles 61 — — — 61 Goodwill 23 — — — 23 Property taxes — 12 28 — 40 Derivatives 79 — — — 79 Other 29 312 14 12 367 492 340 42 (304 ) 570 $ 9,502 $ 6,663 $ 8,203 $ (11,200 ) $ 13,168 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 229 $ 308 $ (25 ) $ 512 Short-term borrowings- Affiliated companies 2,021 389 — (2,410 ) — Other — 8 — — 8 Accounts payable- Affiliated companies 884 146 368 (856 ) 542 Other 21 118 — — 139 Accrued taxes 7 93 62 (86 ) 76 Derivatives 103 1 — — 104 Other 66 61 9 45 181 3,102 1,045 747 (3,332 ) 1,562 CAPITALIZATION: Total equity 5,605 2,944 4,476 (7,420 ) 5,605 Long-term debt and other long-term obligations 690 2,116 840 (1,136 ) 2,510 6,295 5,060 5,316 (8,556 ) 8,115 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 791 791 Accumulated deferred income taxes 6 — 697 (103 ) 600 Retirement benefits 27 305 — — 332 Asset retirement obligations — 191 640 — 831 Derivatives 37 1 — — 38 Other 35 61 803 — 899 105 558 2,140 688 3,491 $ 9,502 $ 6,663 $ 8,203 $ (11,200 ) $ 13,168
Condensed Consolidating Statements of Cash Flows	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Nine Months Ended September 30, 2016 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (605 ) $ 401 $ 820 $ (12 ) $ 604 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 186 285 — 471 Short-term borrowings, net 701 92 — (692 ) 101 Redemptions and Repayments- Long-term debt — (211 ) (304 ) 12 (503 ) Other — (5 ) (2 ) — (7 ) Net cash provided from (used for) financing activities 701 62 (21 ) (680 ) 62 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (28 ) (171 ) (233 ) — (432 ) Nuclear fuel — — (195 ) — (195 ) Sales of investment securities held in trusts — — 576 — 576 Purchases of investment securities held in trusts — — (619 ) — (619 ) Cash investments 10 — — — 10 Loans to affiliated companies, net (87 ) (292 ) (328 ) 692 (15 ) Other 9 — — — 9 Net cash used for investing activities (96 ) (463 ) (799 ) 692 (666 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Nine Months Ended September 30, 2015 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (624 ) $ 405 $ 867 $ (12 ) $ 636 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 43 296 — 339 Short-term borrowings, net 689 51 — (740 ) — Redemptions and Repayments- Long-term debt (17 ) (55 ) (322 ) 12 (382 ) Short-term borrowings, net — — (27 ) (82 ) (109 ) Other — (4 ) (1 ) — (5 ) Net cash provided from (used for) financing activities 672 35 (54 ) (810 ) (157 ) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (3 ) (144 ) (194 ) — (341 ) Nuclear fuel — — (101 ) — (101 ) Sales of investment securities held in trusts — — 503 — 503 Purchases of investment securities held in trusts — — (546 ) — (546 ) Loans to affiliated companies, net (45 ) (302 ) (475 ) 822 — Cash Investments (10 ) — — — (10 ) Other 10 6 — — 16 Net cash used for investing activities (48 ) (440 ) (813 ) 822 (479 ) 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)	9 Months Ended
	Sep. 30, 2016
Segment Reporting [Abstract]
Segment Financial Information	Segment Financial Information For the Three Months Ended Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Reconciling Adjustments Consolidated (In millions) September 30, 2016 External revenues $ 2,702 $ 285 $ 998 $ — $ (68 ) $ 3,917 Internal revenues — — 117 — (117 ) — Total revenues 2,702 285 1,115 — (185 ) 3,917 Depreciation 171 45 79 16 — 311 Amortization of regulatory assets, net 98 — — — — 98 Investment income 13 — 23 2 (10 ) 28 Interest expense 139 43 48 56 — 286 Income taxes (benefits) 167 45 49 (11 ) 1 251 Net income (loss) 283 78 86 (67 ) — 380 Total assets 28,276 8,034 15,165 486 — 51,961 Total goodwill 5,092 526 — — — 5,618 Property additions 303 246 110 5 — 664 September 30, 2015 External revenues $ 2,624 $ 248 $ 1,327 $ — $ (76 ) $ 4,123 Internal revenues — — 141 — (141 ) — Total revenues 2,624 248 1,468 — (217 ) 4,123 Depreciation 174 41 98 15 — 328 Amortization of regulatory assets, net 110 — — — — 110 Impairment of assets 8 — — — — 8 Investment income (loss) 8 — (19 ) (6 ) (11 ) (28 ) Interest expense 149 40 48 48 — 285 Income taxes (benefits) 137 41 84 (39 ) 3 226 Net income (loss) 234 70 145 (54 ) — 395 Total assets 27,883 6,988 16,229 830 — 51,930 Total goodwill 5,092 526 800 — — 6,418 Property additions 292 149 83 15 — 539 For the Nine Months Ended September 30, 2016 External revenues $ 7,423 $ 824 $ 3,158 $ — $ (218 ) $ 11,187 Internal revenues — — 377 — (377 ) — Total revenues 7,423 824 3,535 — (595 ) 11,187 Depreciation 510 132 284 48 — 974 Amortization of regulatory assets, net 218 4 — — — 222 Impairment of assets (Note 2) — — 1,447 — — 1,447 Investment income 37 — 56 13 (31 ) 75 Interest expense 431 128 143 161 — 863 Income taxes (benefits) 349 130 (96 ) (51 ) 2 334 Net income (loss) 594 223 (1,029 ) (169 ) — (381 ) Property additions 878 755 492 31 — 2,156 September 30, 2015 External revenues $ 7,425 $ 755 $ 3,536 $ — $ (231 ) $ 11,485 Internal revenues — — 563 — (563 ) — Total revenues 7,425 755 4,099 — (794 ) 11,485 Depreciation 516 116 293 44 — 969 Amortization of regulatory assets, net 196 5 — — — 201 Impairment of assets 8 — 16 — — 24 Investment income (loss) 33 — (7 ) (9 ) (31 ) (14 ) Interest expense 439 119 144 144 — 846 Income taxes (benefits) 350 135 76 (84 ) 8 485 Net income (loss) 598 231 129 (154 ) — 804 Property additions 884 700 400 41 — 2,025

Organization and Basis of Pre38

Organization and Basis of Presentation (Details Textuals) mi in Thousands, MW in Thousands, customer in Millions, $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016USD ($)transmission_center	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)customertransmission_centercompanymiMW	Sep. 30, 2015USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2015USD ($)	Nov. 04, 2016USD ($)
Property, Plant and Equipment [Line Items]
Aggregate amount of capacity | MW			17
Length of transmission lines | mi			24
Number of regional transmission centers | transmission_center	2		2
Capitalized cost of equity	$ 11	$ 10	$ 28	$ 40
Capitalized interest	17	$ 16	$ 51	$ 53
Utilization of Accelerated Useful Life
Property, Plant and Equipment [Line Items]
Reduction to depreciation	$ 21						$ 19
Accounting Standards Update 2015-03 | Deferred Charges and Other Assets
Property, Plant and Equipment [Line Items]
Debt issuance costs							(93)
Accounting Standards Update 2015-03 | Long-Term Debt and Other Long-Term Obligations
Property, Plant and Equipment [Line Items]
Debt issuance costs							93
Regulated Distribution
Property, Plant and Equipment [Line Items]
Number of existing utility operating companies | company			10
Number of customers served by utility operating companies | customer			6
FES | Accounting Standards Update 2015-03 | Deferred Charges and Other Assets
Property, Plant and Equipment [Line Items]
Debt issuance costs							(17)
FES | Accounting Standards Update 2015-03 | Long-Term Debt and Other Long-Term Obligations
Property, Plant and Equipment [Line Items]
Debt issuance costs							$ 17
FES | CES
Property, Plant and Equipment [Line Items]
Additional collateral posted or accelerated payments								$ 355
Scenario, Forecast | FES | CES
Property, Plant and Equipment [Line Items]
Inability to extend or refinance debt					$ 515	$ 130
Minimum
Property, Plant and Equipment [Line Items]
Strategic review of competitive operations period			12 months
Maximum
Property, Plant and Equipment [Line Items]
Strategic review of competitive operations period			18 months

Asset Impairments (Details 1)

Asset Impairments (Details 1) $ in Millions	Jul. 19, 2016MW	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of assets (Note 2)		$ 0		$ 8	$ 1,447	$ 24
Impairment			$ 800		800
Loss on termination of contract		32
Contract Termination
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Restructuring charges			58
Competitive Energy Services
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of assets			647
Impairment					$ 800
Competitive Energy Services | Income Approach Valuation Technique | Goodwill
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate (percent)					9.50%
Terminal value of EBITDA					7
FES
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of assets (Note 2)		$ 0		$ 0	$ 540	$ 16
Impairment			23
FES | Competitive Energy Services
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of assets			$ 517
Bay Shore Unit 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Plant capacity (in MW's) | MW	136
Sammis Power Plant Units 1-4
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Plant capacity (in MW's) | MW	720

Asset Impairments (Details 2)

Asset Impairments (Details 2) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Jun. 30, 2016	Sep. 30, 2016
Goodwill [Roll Forward]
Beginning balance		$ 6,418
Impairment	$ (800)	(800)
Ending balance		5,618
Regulated Distribution
Goodwill [Roll Forward]
Beginning balance		5,092
Impairment		0
Ending balance		5,092
Regulated Transmission
Goodwill [Roll Forward]
Beginning balance		526
Impairment		0
Ending balance		526
Competitive Energy Services
Goodwill [Roll Forward]
Beginning balance		800
Impairment		(800)
Ending balance		$ 0

Earnings Per Share Of Common 41

Earnings Per Share Of Common Stock (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Share [Abstract]
Net income (loss)	$ 380	$ 395	$ (381)	$ 804
Weighted average number of basic shares outstanding	425	423	425	422
Assumed exercise of dilutive stock options and awards (in shares)	2	1	0	1
Weighted average number of diluted shares outstanding	427	424	425	423
Basic earnings (losses) per share of common stock (in dollars per share)	$ 0.89	$ 0.94	$ (0.90)	$ 1.91
Diluted earnings (losses) per share of common stock (in dollars per share)	$ 0.89	$ 0.93	$ (0.90)	$ 1.90
Shares excluded from the calculation of diluted shares outstanding, in shares	1	1	3	1

Pension and Other Postemploym42

Pension and Other Postemployment Benefits (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended		10 Months Ended
	Oct. 28, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Oct. 28, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension trust contribution				$ 297	$ 143
Estimated future contributions in current fiscal year				500
Subsequent Event
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Minimum required funding obligations						$ 382
Pension trust contribution	$ 85
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs		$ 48	$ 49	144	145
Interest costs		99	96	298	288
Expected return on plan assets		(100)	(111)	(297)	(333)
Amortization of prior service costs (credits)		2	2	6	6
Net periodic costs (credits)		49	36	151	106
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs		2	2	4	4
Interest costs		7	7	22	21
Expected return on plan assets		(7)	(9)	(23)	(25)
Amortization of prior service costs (credits)		(20)	(33)	(60)	(100)
Net periodic costs (credits)		(18)	(33)	(57)	(100)
FirstEnergy | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)		35	25	107	74
FirstEnergy | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)		(11)	(21)	(41)	(66)
FES
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension trust contribution				138	0
FES | Subsequent Event
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension trust contribution						$ 138
FES | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)		6	4	18	12
Net periodic benefit expense (credit)		5	4	17	12
FES | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)		(4)	(5)	(12)	(15)
Net periodic benefit expense (credit)		$ (4)	$ (4)	$ (12)	$ (12)

Accumulated Other Comprehensi43

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	$ 191	$ 202	$ 171	$ 246
Other comprehensive income (loss) before reclassifications	21	(8)	109	(1)
Amounts reclassified from AOCI	(33)	(32)	(90)	(110)
Other comprehensive income (loss)	(12)	(40)	19	(111)
Income taxes (benefits) on other comprehensive income (loss)	(5)	(15)	6	(42)
Other comprehensive income (loss), net of tax	(7)	(25)	13	(69)
AOCI Ending Balance	184	177	184	177
FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	75	45	46	57
Other comprehensive income (loss) before reclassifications	22	(7)	102	(1)
Amounts reclassified from AOCI	(19)	(8)	(51)	(33)
Other comprehensive income (loss)	3	(15)	51	(34)
Income taxes (benefits) on other comprehensive income (loss)	1	(6)	20	(13)
Other comprehensive income (loss), net of tax	2	(9)	31	(21)
AOCI Ending Balance	77	36	77	36
Gains & Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(31)	(36)	(33)	(37)
Other comprehensive income (loss) before reclassifications	0	0	0	0
Amounts reclassified from AOCI	2	2	6	4
Other comprehensive income (loss)	2	2	6	4
Income taxes (benefits) on other comprehensive income (loss)	0	1	2	2
Other comprehensive income (loss), net of tax	2	1	4	2
AOCI Ending Balance	(29)	(35)	(29)	(35)
Gains & Losses on Cash Flow Hedges | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(10)	(9)	(9)	(7)
Other comprehensive income (loss) before reclassifications	0	0	0	0
Amounts reclassified from AOCI	1	0	0	(2)
Other comprehensive income (loss)	1	0	0	(2)
Income taxes (benefits) on other comprehensive income (loss)	0	0	0	0
Other comprehensive income (loss), net of tax	1	0	0	(2)
AOCI Ending Balance	(9)	(9)	(9)	(9)
Unrealized Gains on AFS Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	58	19	18	25
Other comprehensive income (loss) before reclassifications	21	(8)	109	(1)
Amounts reclassified from AOCI	(17)	(3)	(42)	(20)
Other comprehensive income (loss)	4	(11)	67	(21)
Income taxes (benefits) on other comprehensive income (loss)	2	(4)	25	(8)
Other comprehensive income (loss), net of tax	2	(7)	42	(13)
AOCI Ending Balance	60	12	60	12
Unrealized Gains on AFS Securities | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	50	16	16	21
Other comprehensive income (loss) before reclassifications	22	(7)	102	(1)
Amounts reclassified from AOCI	(17)	(4)	(41)	(19)
Other comprehensive income (loss)	5	(11)	61	(20)
Income taxes (benefits) on other comprehensive income (loss)	2	(5)	24	(9)
Other comprehensive income (loss), net of tax	3	(6)	37	(11)
AOCI Ending Balance	53	10	53	10
Defined Benefit Pension & OPEB Plans
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	164	219	186	258
Other comprehensive income (loss) before reclassifications	0	0	0	0
Amounts reclassified from AOCI	(18)	(31)	(54)	(94)
Other comprehensive income (loss)	(18)	(31)	(54)	(94)
Income taxes (benefits) on other comprehensive income (loss)	(7)	(12)	(21)	(36)
Other comprehensive income (loss), net of tax	(11)	(19)	(33)	(58)
AOCI Ending Balance	153	200	153	200
Defined Benefit Pension & OPEB Plans | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	35	38	39	43
Other comprehensive income (loss) before reclassifications	0	0	0	0
Amounts reclassified from AOCI	(3)	(4)	(10)	(12)
Other comprehensive income (loss)	(3)	(4)	(10)	(12)
Income taxes (benefits) on other comprehensive income (loss)	(1)	(1)	(4)	(4)
Other comprehensive income (loss), net of tax	(2)	(3)	(6)	(8)
AOCI Ending Balance	$ 33	$ 35	$ 33	$ 35

Accumulated Other Comprehensi44

Accumulated Other Comprehensive Income (Details 1) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	$ (953)	$ (842)	$ (2,835)	$ (2,799)
Interest expense	(286)	(285)	(863)	(846)
INCOME (LOSS) BEFORE INCOME TAXES	631	621	(47)	1,289
Income taxes	(251)	(226)	(334)	(485)
FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	(316)	(246)	(925)	(996)
INCOME (LOSS) BEFORE INCOME TAXES	96	190	(272)	160
Income taxes	(56)	(70)	5	(64)
Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
INCOME (LOSS) BEFORE INCOME TAXES	2	2	6	4
Income taxes	0	(1)	(2)	(2)
Net of tax	2	1	4	2
Reclassifications from AOCI | Gains & losses on cash flow hedges | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Income taxes	0	0	0	0
Net of tax	1	0	0	(2)
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	0	0	0	(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	0	0	(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	6	6
Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(17)	(3)	(42)	(20)
Income taxes	7	1	16	7
Net of tax	(10)	(2)	(26)	(13)
Reclassifications from AOCI | Unrealized gains on AFS securities | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(17)	(3)	(41)	(18)
Income taxes	6	1	15	7
Net of tax	(11)	(2)	(26)	(11)
Reclassifications from AOCI | Defined benefit pension and OPEB plans
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(18)	(31)	(54)	(94)
Income taxes	7	12	21	36
Net of tax	(11)	(19)	(33)	(58)
Reclassifications from AOCI | Defined benefit pension and OPEB plans | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(3)	(4)	(10)	(12)
Income taxes	1	1	4	4
Net of tax	$ (2)	$ (3)	$ (6)	$ (8)

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended			9 Months Ended
	Mar. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)		39.80%		36.40%
Impairment			$ 800		$ 800
Non-deductible expense from impairment of goodwill			433
Unrecognized tax benefits from lapse of statute of limitations					54
Unrecognized tax benefits that would impact effective tax rate		$ 15			$ 15
FES
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)		58.30%		36.80%	1.80%	40.00%
Impairment			23
Non-deductible expense from impairment of goodwill					$ 23
State and Local Jurisdiction
Income Taxes (Textuals) [Abstract]
Valuation allowance			$ 159
Increase resulting from settlements with taxing authorities	$ 69
State and Local Jurisdiction | FES
Income Taxes (Textuals) [Abstract]
Valuation allowance		$ 65			$ 65

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	Sep. 30, 2016USD ($)
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	$ 1,137
Discounted Lease Payments, net	895
Net Exposure	242
FES
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	1,110
Discounted Lease Payments, net	887
Net Exposure	$ 223

Variable Interest Entities (D47

Variable Interest Entities (Details Textuals)	May 23, 2016USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)agreemententity	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)	Jun. 24, 2014
Variable Interest Entities (Textuals) [Abstract]
Equity interest by unaffiliated third party in PNBV (percent)				3.00%
Long-term transition bond		$ 97,000,000		$ 97,000,000		$ 128,000,000
Long-term pollution control bond		407,000,000		407,000,000		429,000,000
Guarantor obligations		499,000,000		$ 499,000,000
Number of contracts that may contain variable interest | entity				1
Purchased power		$ 979,000,000	$ 1,209,000,000	$ 2,992,000,000	$ 3,311,000,000
Beaver Valley Unit 2
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary		2.60%		2.60%
Bruce Mansfield Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary		93.83%		93.83%
Perry Power Plant Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary	3.75%
Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Ownership interest		0.00%		0.00%
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities | agreement				14
Phase In Recovery Bonds
Variable Interest Entities (Textuals) [Abstract]
Long-term debt and other long-term obligations		$ 339,000,000		$ 339,000,000		$ 362,000,000
Ohio Funding Companies
Variable Interest Entities (Textuals) [Abstract]
Annual servicing fees				$ 445,000
Other FE subsidiaries
Variable Interest Entities (Textuals) [Abstract]
Ownership interest		0.00%		0.00%
Other FE subsidiaries | Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Purchased power		$ 22,000,000	$ 29,000,000	$ 78,000,000	$ 86,000,000
NG | Beaver Valley Unit 2
Variable Interest Entities (Textuals) [Abstract]
Percentage of high-voltage transmission line project owned by subsidiary of FE on the Allegheny Series							100.00%
NG | Perry Power Plant Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage of high-voltage transmission line project owned by subsidiary of FE on the Allegheny Series	100.00%
Payments to acquire additional interest	$ 50,000,000
Path-WV
Variable Interest Entities (Textuals) [Abstract]
Percentage of high-voltage transmission line project owned by subsidiary of FE on the Allegheny Series		100.00%		100.00%
Percentage of high-voltage transmission line project owned by subsidiary of FE on the West Virginia Series		50.00%		50.00%
Global Holding | Guarantee of senior secured loan facility
Variable Interest Entities (Textuals) [Abstract]
Guarantor obligations		$ 300,000,000		$ 300,000,000
Signal Peak | Global Holding | FEV
Variable Interest Entities (Textuals) [Abstract]
Ownership interest		33.33%		33.33%

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Recurring - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Assets
Fair value, assets	$ 3,582	$ 2,876
Liabilities
Fair value, liabilities	(259)	(281)
Net assets (liabilities)	3,323	2,595
FES
Assets
Fair value, assets	1,787	1,559
Liabilities
Fair value, liabilities	(139)	(142)
Net assets (liabilities)	1,648	1,417
Derivative liabilities - commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(134)	(131)
Derivative liabilities - commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(134)	(131)
Derivative liabilities - FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(7)	(13)
Derivative liabilities - FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(5)	(11)
Derivative liabilities - NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(118)	(137)
Corporate debt securities
Assets
Fair value, assets	1,242	1,245
Corporate debt securities | FES
Assets
Fair value, assets	714	678
Derivative liabilities - commodity contracts | Derivative Assets
Assets
Fair value, assets	237	228
Derivative liabilities - commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	237	228
Derivative liabilities - FTRs | Derivative Assets
Assets
Fair value, assets	13	8
Derivative liabilities - FTRs | Derivative Assets | FES
Assets
Fair value, assets	7	5
Derivative liabilities - NUG contracts | Derivative Assets
Assets
Fair value, assets	0	1
Equity securities
Assets
Fair value, assets	908	576
Equity securities | FES
Assets
Fair value, assets	624	378
Foreign government debt securities
Assets
Fair value, assets	77	75
Foreign government debt securities | FES
Assets
Fair value, assets	59	59
U.S. government debt securities
Assets
Fair value, assets	173	180
U.S. government debt securities | FES
Assets
Fair value, assets	53	23
U.S. state debt securities
Assets
Fair value, assets	255	246
U.S. state debt securities | FES
Assets
Fair value, assets	4	4
Other
Assets
Fair value, assets	677	317
Other | FES
Assets
Fair value, assets	89	184
Level 1
Assets
Fair value, assets	1,466	685
Liabilities
Fair value, liabilities	(12)	(9)
Net assets (liabilities)	1,454	676
Level 1 | FES
Assets
Fair value, assets	633	382
Liabilities
Fair value, liabilities	(12)	(9)
Net assets (liabilities)	621	373
Level 1 | Derivative liabilities - commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(12)	(9)
Level 1 | Derivative liabilities - commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(12)	(9)
Level 1 | Derivative liabilities - FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 1 | Derivative liabilities - FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 1 | Derivative liabilities - 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 | Derivative liabilities - commodity contracts | Derivative Assets
Assets
Fair value, assets	7	4
Level 1 | Derivative liabilities - commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	7	4
Level 1 | Derivative liabilities - FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | Derivative liabilities - FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 1 | Derivative liabilities - NUG contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | Equity securities
Assets
Fair value, assets	908	576
Level 1 | Equity securities | FES
Assets
Fair value, assets	624	378
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	551	105
Level 1 | Other | FES
Assets
Fair value, assets	2	0
Level 2
Assets
Fair value, assets	2,103	2,182
Liabilities
Fair value, liabilities	(122)	(122)
Net assets (liabilities)	1,981	2,060
Level 2 | FES
Assets
Fair value, assets	1,147	1,172
Liabilities
Fair value, liabilities	(122)	(122)
Net assets (liabilities)	1,025	1,050
Level 2 | Derivative liabilities - commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(122)	(122)
Level 2 | Derivative liabilities - commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(122)	(122)
Level 2 | Derivative liabilities - FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2 | Derivative liabilities - FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 2 | Derivative liabilities - NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2 | Corporate debt securities
Assets
Fair value, assets	1,242	1,245
Level 2 | Corporate debt securities | FES
Assets
Fair value, assets	714	678
Level 2 | Derivative liabilities - commodity contracts | Derivative Assets
Assets
Fair value, assets	230	224
Level 2 | Derivative liabilities - commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	230	224
Level 2 | Derivative liabilities - FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | Derivative liabilities - FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 2 | Derivative liabilities - 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	77	75
Level 2 | Foreign government debt securities | FES
Assets
Fair value, assets	59	59
Level 2 | U.S. government debt securities
Assets
Fair value, assets	173	180
Level 2 | U.S. government debt securities | FES
Assets
Fair value, assets	53	23
Level 2 | U.S. state debt securities
Assets
Fair value, assets	255	246
Level 2 | U.S. state debt securities | FES
Assets
Fair value, assets	4	4
Level 2 | Other
Assets
Fair value, assets	126	212
Level 2 | Other | FES
Assets
Fair value, assets	87	184
Level 3
Assets
Fair value, assets	13	9
Liabilities
Fair value, liabilities	(125)	(150)
Net assets (liabilities)	(112)	(141)
Level 3 | FES
Assets
Fair value, assets	7	5
Liabilities
Fair value, liabilities	(5)	(11)
Net assets (liabilities)	2	(6)
Level 3 | Derivative liabilities - commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 3 | Derivative liabilities - commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 3 | Derivative liabilities - FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(7)	(13)
Level 3 | Derivative liabilities - FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(5)	(11)
Level 3 | Derivative liabilities - NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(118)	(137)
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 | Derivative liabilities - commodity contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 3 | Derivative liabilities - commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 3 | Derivative liabilities - FTRs | Derivative Assets
Assets
Fair value, assets	13	8
Level 3 | Derivative liabilities - FTRs | Derivative Assets | FES
Assets
Fair value, assets	7	5
Level 3 | Derivative liabilities - NUG contracts | Derivative Assets
Assets
Fair value, assets	0	1
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 (Deta49

Fair Value Measurements (Details 1) - Level 3 - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
NUG contracts
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	$ 1	$ 2
Beginning Balance, Derivative Liabilities	(137)	(153)
Beginning Balance, Net	(136)	(151)
Unrealized gain (loss), Derivative Assets	0	2
Unrealized gain (loss), Derivative Liabilities	(17)	(49)
Unrealized gain (loss), Net	(17)	(47)
Purchases, Derivative Assets	0	0
Purchases, Derivative Liabilities	0	0
Purchases, Net	0	0
Settlements, Derivative Assets	(1)	(3)
Settlements, Derivative Liabilities	36	65
Settlements, Net	35	62
Ending Balance, Derivative Assets	0	1
Ending Balance, Derivative Liabilities	(118)	(137)
Ending Balance, Net	(118)	(136)
FTRs
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	8	39
Beginning Balance, Derivative Liabilities	(13)	(14)
Beginning Balance, Net	(5)	25
Unrealized gain (loss), Derivative Assets	(8)	(5)
Unrealized gain (loss), Derivative Liabilities	1	(7)
Unrealized gain (loss), Net	(7)	(12)
Purchases, Derivative Assets	17	22
Purchases, Derivative Liabilities	(8)	(11)
Purchases, Net	9	11
Settlements, Derivative Assets	(4)	(48)
Settlements, Derivative Liabilities	13	19
Settlements, Net	9	(29)
Ending Balance, Derivative Assets	13	8
Ending Balance, Derivative Liabilities	(7)	(13)
Ending Balance, Net	6	(5)
FTRs | FES
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	5	27
Beginning Balance, Derivative Liabilities	(11)	(13)
Beginning Balance, Net	(6)	14
Unrealized gain (loss), Derivative Assets	(7)	2
Unrealized gain (loss), Derivative Liabilities	1	(5)
Unrealized gain (loss), Net	(6)	(3)
Purchases, Derivative Assets	10	9
Purchases, Derivative Liabilities	(5)	(10)
Purchases, Net	5	(1)
Settlements, Derivative Assets	(1)	(33)
Settlements, Derivative Liabilities	10	17
Settlements, Net	9	(16)
Ending Balance, Derivative Assets	7	5
Ending Balance, Derivative Liabilities	(5)	(11)
Ending Balance, Net	$ 2	$ (6)

Fair Value Measurements (Deta50

Fair Value Measurements (Details 2) - Level 3 $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)MWh$ / MWh	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ 6	$ (5)	$ 25
FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	2	(6)	14
NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(118)	$ (136)	$ (151)
Model | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	6
Model | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	2
Model | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ (118)
Model | Minimum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	(2.20)
Model | Minimum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	(2.20)
Model | Minimum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	400
Fair Value Inputs, Power, Regional Prices (in $/MWH)	30.90
Model | Maximum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	7.60
Model | Maximum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	7.60
Model | Maximum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	3,207,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	35.30
Model | Weighted Average | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	1
Model | Weighted Average | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	0.70
Model | Weighted Average | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	661,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	32.10

Fair Value Measurements (Deta51

Fair Value Measurements (Details 3) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	$ 1,728	$ 1,778
Unrealized Gain	69	16
Fair Value	1,797	1,794
Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	816	542
Unrealized Gains	92	34
Fair Value	908	576
FES | Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	834	801
Unrealized Gain	45	9
Fair Value	879	810
FES | Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	561	354
Unrealized Gains	63	24
Fair Value	$ 624	$ 378

Fair Value Measurements (Deta52

Fair Value Measurements (Details 4) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
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	$ 337	$ 307	$ 1,361	$ 1,126
Realized Gains	36	33	131	135
Realized Losses	(15)	(32)	(88)	(121)
OTTI	(3)	(46)	(13)	(70)
Interest and Dividend Income	27	25	75	75
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	135	127	576	503
Realized Gains	23	28	90	98
Realized Losses	(6)	(24)	(49)	(79)
OTTI	(3)	(41)	(12)	(63)
Interest and Dividend Income	$ 16	$ 14	$ 42	$ 43

Fair Value Measurements (Deta53

Fair Value Measurements (Details 5) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
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	$ 19,745	$ 20,244
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	3,003	3,027
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	21,465	21,519
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	$ 2,662	$ 3,121

Fair Value Measurements (Deta54

Fair Value Measurements (Details Textuals) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Fair Value of Financial Instruments [Line Items]
Investment excludes receivables, payables and accrued income	$ (8)	$ 7
Cash balance excluded from available for sale securities	50	157
Investments not required to be disclosed	$ 276	255
NUG contracts
Fair Value of Financial Instruments [Line Items]
Period of future observable data to determine contract price	3 years
FES
Fair Value of Financial Instruments [Line Items]
Investment excludes receivables, payables and accrued income	$ 1	1
Cash balance excluded from available for sale securities	$ 39	$ 139

Derivative Instruments (Details

Derivative Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Fair value of derivatives instruments
Derivative Assets	$ 250	$ 237
Derivative Liabilities	(259)	(281)
Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	152	157
Deferred Charges and Other Assets - Other
Fair value of derivatives instruments
Derivative Assets	98	80
Current Liabilities - Derivatives
Fair value of derivatives instruments
Derivative Liabilities	(91)	(106)
Noncurrent Liabilities
Fair value of derivatives instruments
Derivative Liabilities	(168)	(175)
Commodity contracts | Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	139	150
Commodity contracts | Deferred Charges and Other Assets - Other
Fair value of derivatives instruments
Derivative Assets	98	78
Commodity contracts | Current Liabilities - Derivatives
Fair value of derivatives instruments
Derivative Liabilities	(84)	(94)
Commodity contracts | Noncurrent Liabilities
Fair value of derivatives instruments
Derivative Liabilities	(50)	(37)
FTRs | Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	13	7
FTRs | Deferred Charges and Other Assets - Other
Fair value of derivatives instruments
Derivative Assets	0	1
FTRs | Current Liabilities - Derivatives
Fair value of derivatives instruments
Derivative Liabilities	(7)	(12)
FTRs | Noncurrent Liabilities
Fair value of derivatives instruments
Derivative Liabilities	0	(1)
NUGs | Deferred Charges and Other Assets - Other
Fair value of derivatives instruments
Derivative Assets	0	1
NUGs | Noncurrent Liabilities
Fair value of derivatives instruments
Derivative Liabilities	$ (118)	$ (137)

Derivative Instruments (Detai56

Derivative Instruments (Details 1) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Derivative Assets
Fair Value	$ 250	$ 237
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(127)	(133)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	(22)	0
Net Fair Value	101	104
Derivative Liabilities
Fair Value	(259)	(281)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	127	133
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	8	8
Net Fair Value	(124)	(140)
Commodity contracts
Derivative Assets
Fair Value	237	228
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(120)	(125)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	(22)	0
Net Fair Value	95	103
Derivative Liabilities
Fair Value	(134)	(131)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	120	125
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	8	3
Net Fair Value	(6)	(3)
FTRs
Derivative Assets
Fair Value	13	8
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(7)	(8)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	6	0
Derivative Liabilities
Fair Value	(7)	(13)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	7	8
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	5
Net Fair Value	0	0
NUGs
Derivative Assets
Fair Value	0	1
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	0	1
Derivative Liabilities
Fair Value	(118)	(137)
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	$ (118)	$ (137)

Derivative Instruments (Detai57

Derivative Instruments (Details 2) MWh in Millions, MMBTU in Millions	Sep. 30, 2016MWhMMBTU
Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	9
Sales (in MWH or mmBTUs)	49
Net (in MWH or mmBTUs)	(40)
FTRs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	42
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	42
NUGs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	3
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	3
Natural Gas
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs) | MMBTU	49
Sales (in MWH or mmBTUs) | MMBTU	0
Net (in MWH or mmBTUs) | MMBTU	49

Derivative Instruments (Detai58

Derivative Instruments (Details 3) - Not Designated as Hedging Instrument - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	$ 33	$ 43	$ 167	$ 96
Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	(22)	(50)	(105)	(78)
Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Unrealized Gain (Loss) Recognized	16	57	10	64
Realized Gain (Loss) Reclassified	(6)	(11)	(28)	(38)
Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	(2)	(5)	(9)	(26)
Commodity contracts | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	32	41	162	48
Commodity contracts | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	(22)	(50)	(105)	(78)
Commodity contracts | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Unrealized Gain (Loss) Recognized	19	59	2	81
Realized Gain (Loss) Reclassified	0	0	0	0
Commodity contracts | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	(2)	(5)	(9)	(26)
FTRs | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	1	2	5	48
FTRs | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	0	0	0	0
FTRs | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Unrealized Gain (Loss) Recognized	(3)	(2)	8	(17)
Realized Gain (Loss) Reclassified	(6)	(11)	(28)	(38)
FTRs | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	0	0	0	0
FES | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	33	43	167
FES | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	(22)	(50)	(105)	(78)
FES | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Unrealized Gain (Loss) Recognized	16	57	10
Realized Gain (Loss) Reclassified	(6)	(11)	(28)
FES | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	(2)	(5)	(9)
FES | Commodity contracts | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	32	41	162	48
FES | Commodity contracts | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	(22)	(50)	(105)	(78)
FES | Commodity contracts | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Unrealized Gain (Loss) Recognized	19	59	2	81
Realized Gain (Loss) Reclassified	0	0	0
FES | Commodity contracts | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	(2)	(5)	(9)
FES | FTRs | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	1	2	5	46
FES | FTRs | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	0	0	0	0
FES | FTRs | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Unrealized Gain (Loss) Recognized	(3)	(2)	8	(16)
Realized Gain (Loss) Reclassified	(6)	(11)	(28)	$ (37)
FES | FTRs | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	$ 0	$ 0	$ 0

Derivative Instruments (Detai59

Derivative Instruments (Details 4) - Not Designated as Hedging Instrument - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	$ (120)	$ (128)	$ (135)	$ (140)
Unrealized loss	(6)	(24)	(18)	(39)
Purchases			4	12
Settlements	12	14	35	29
Outstanding net asset (liability), Ending Balance	(114)	(138)	(114)	(138)
NUGs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(124)	(140)	(136)	(151)
Unrealized loss	(6)	(20)	(17)	(36)
Purchases			0	0
Settlements	12	17	35	44
Outstanding net asset (liability), Ending Balance	(118)	(143)	(118)	(143)
Regulated FTRs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	4	12	1	11
Unrealized loss	0	(4)	(1)	(3)
Purchases			4	12
Settlements	0	(3)	0	(15)
Outstanding net asset (liability), Ending Balance	$ 4	$ 5	$ 4	$ 5

Derivative Instruments (Detai60

Derivative Instruments (Details Textuals) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016USD ($)agreement	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)agreement	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)
Derivative [Line Items]
Unamortized gains or losses associated with designated cash flow hedges	$ 11		$ 11		$ 11
Collateral received	$ 22		$ 22		0
Possible adverse change in quoted market prices of derivative instruments	10.00%		10.00%
Possible increase (decrease) net income due to ten percent adverse change in commodity prices			$ (37)
Cash Flow Hedges
Derivative [Line Items]
Less than 1 million dollar loss on cash flow hedge expected to be reclassified to earnings in next twelve months			1
Unamortized gains or losses associated with prior interest rate hedges	$ 35		35		42
Gains (losses) to be amortized to interest expenses during next twelve months			(8)
Fair Value Hedging
Derivative [Line Items]
Gains (losses) to be amortized to interest expenses during next twelve months			$ 8
Number of fixed-for-floating interest rate swap agreements outstanding | agreement	0		0
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	$ 12		$ 12		20
Reclassifications from long-term debt	2	$ 3	8	$ 9
Commodity contracts
Derivative [Line Items]
Net asset position under commodity derivative contracts	103		103
Collateral received	22		22		0
Commodity contracts | FES
Derivative [Line Items]
Collateral posted	9		9
Collateral received	22		22
NUGs
Derivative [Line Items]
Collateral received	0		0		0
Liability position	118		118
FTRs
Derivative [Line Items]
Net asset position under commodity derivative contracts	6		6
Collateral received	0		0		$ 0
FTRs | FES
Derivative [Line Items]
Net asset position under commodity derivative contracts	2		2
Collateral posted	$ 7		$ 7

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	Jun. 30, 2016	Sep. 30, 2016	Dec. 31, 2015
Asset Retirement Obligations [Line Items]
Fair value of decommissioning trust assets		$ 2,502	$ 2,282
Changes to the asset retirement obligations
Beginning Balance		1,410
Liabilities settled		(25)
Liabilities incurred		4
Accretion		70
Ending Balance		1,459
FES
Asset Retirement Obligations [Line Items]
Fair value of decommissioning trust assets		1,542	$ 1,327
Changes to the asset retirement obligations
Beginning Balance		831
Liabilities settled		(17)
Liabilities incurred		32
Accretion		41
Ending Balance		887
FES | Beaver Valley, Davis-Besse and Perry Power Plants
Changes to the asset retirement obligations
Ending Balance		701
NG | Perry Power Plant Unit 1
Changes to the asset retirement obligations
ARO transferred		$ 28
Ownership percentage	100.00%

Regulatory Matters - Maryland a

Regulatory Matters - Maryland and New Jersey (Details) $ in Millions	Nov. 02, 2016USD ($)	Apr. 28, 2016USD ($)	Jul. 16, 2015	Feb. 27, 2013USD ($)	Sep. 30, 2016USD ($)componentbgs	Dec. 31, 2017USD ($)
Maryland
Regulatory Matters [Line Items]
Expenditures for cost recovery program incurred					$ 38
Incremental energy savings goal next 12 months (percent)			0.20%
Incremental energy savings goal thereafter (percent)			2.00%
Recovery period for expenditures for cost recovery program			5 years		3 years
Expected infrastructure investments				$ 2,700
Period of expected infrastructure investments				15 years
New Jersey
Regulatory Matters [Line Items]
Number of supply components | component					2
Number of basic generation services | bgs					1
JCP&L | NJBPU | New Jersey
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)		$ 142.1			$ 146.6
Scenario, Forecast | Maryland
Regulatory Matters [Line Items]
Expenditures for cost recovery program						$ 68
Subsequent Event | JCP&L | NJBPU | New Jersey
Regulatory Matters [Line Items]
Approved amount of annual increase	$ 80

Regulatory Matters - Ohio (Deta

Regulatory Matters - Ohio (Details) MWh in Thousands, $ in Millions	Oct. 12, 2016USD ($)conditionMW	Aug. 04, 2016	Jul. 25, 2016USD ($)	Jun. 29, 2016USD ($)	Apr. 15, 2016USD ($)	Aug. 07, 2013USD ($)auction	Mar. 20, 2013	Sep. 30, 2016MWh
Regulatory Matters [Line Items]
Proposed goal to reduce CO2 pollution (percent)								90.00%
Ohio
Regulatory Matters [Line Items]
Energy efficient portfolio plan term							3 years
Credit to non-shopping customers						$ 43.4
Ohio | Year 2015
Regulatory Matters [Line Items]
Annual energy savings (in GWH) | MWh								2,266
Ohio | Year 2016
Regulatory Matters [Line Items]
Annual energy savings (in GWH) | MWh								2,288
Ohio | Year 2017
Regulatory Matters [Line Items]
Annual increase in energy savings (percent)								1.00%
Ohio | Annually Through 2020
Regulatory Matters [Line Items]
Utilities required to additionally reduce peak demand								0.75%
Ohio | PUCO
Regulatory Matters [Line Items]
Number of renewable energy auctions | auction						1
Approved period to limit average customer bill								2 years
Ohio | PUCO | Subsequent Event
Regulatory Matters [Line Items]
Term of proposed purchase power agreement	8 years
Recovery period	5 years
Costs avoided by customers	$ 360
Proposed goal to reduce CO2 pollution (percent)	90.00%
Ohio | PUCO | Wind or Solar Power | Subsequent Event
Regulatory Matters [Line Items]
Proposed potential plant acquisition (MW) | MW	100
Ohio | Ohio Companies | PUCO
Regulatory Matters [Line Items]
Expenditures for cost recovery program					$ 323
Ohio | Retail Rate Stability Rider | FES
Regulatory Matters [Line Items]
Term of proposed purchase power agreement		8 years
Ohio | Delivery Capital Recovery Rider | PUCO | Subsequent Event
Regulatory Matters [Line Items]
Annual revenue cap for rider	$ 30
Annual revenue cap for rider for years three through six	20
Annual revenue cap for rider for years six through eight	15
Ohio | Distribution Modernization Rider
Regulatory Matters [Line Items]
Annual revenue cap for rider				$ 131
Recovery period				3 years
Amount of rider valuation			$ 558
Period of rider valuation			8 years
Ohio | Distribution Modernization Rider | PUCO
Regulatory Matters [Line Items]
Possible extension period				2 years
Ohio | Distribution Modernization Rider | PUCO | Subsequent Event
Regulatory Matters [Line Items]
Annual revenue cap for rider	$ 132.5
Recovery period	3 years
Possible extension period	2 years
Public Utilities, Annual Revenue Cap for Rider, Approved Amount	$ 204
Public Utilities, Excessive Earnings Test Cost Recovery, Exclusion Period	3 years
Public Utilities, Excessive Earnings Test Cost Recovery, Exclusion Period, Renewal Period	2 years
Public Utilities, Annual Revenue Cap for Rider, Number of Conditions | condition	3
Ohio | Customary Advisory Council | PUCO | Subsequent Event
Regulatory Matters [Line Items]
Term of proposed purchase power agreement	8 years
Annual contribution amount	$ 1
Contribution amount	$ 8
Ohio | Energy Conservation, Economic Development and Job Retention | Ohio Companies | PUCO | Subsequent Event
Regulatory Matters [Line Items]
Term of proposed purchase power agreement	8 years
Annual contribution amount	$ 3
Contribution amount	$ 24
Ohio | Fuel-Fund | Ohio Companies | PUCO | Subsequent Event
Regulatory Matters [Line Items]
Term of proposed purchase power agreement	8 years
Annual contribution amount	$ 2.4
Contribution amount	$ 19

Regulatory Matters - Pennsylvan

Regulatory Matters - Pennsylvania and West Virginia (Details) $ in Thousands

Oct. 14, 2016USD ($)itembrief

Sep. 28, 2016USD ($)

Aug. 22, 2016USD ($)

Aug. 16, 2016USD ($)

Aug. 05, 2016MW

Jul. 07, 2016

Apr. 28, 2016USD ($)

Oct. 19, 2015USD ($)

Jun. 19, 2015

Oct. 10, 2013proposal

Jun. 30, 2016USD ($)

Sep. 30, 2016USD ($)program

Dec. 31, 2017USD ($)

Dec. 31, 2027MW

Dec. 31, 2020MW

Pennsylvania

Regulatory Matters [Line Items]

Number of requests for proposal | proposal

1

Request for proposal project term

2 years

Pennsylvania | Unfavorable Regulatory Action

Regulatory Matters [Line Items]

Maximum range of possible loss

$ 175,000

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 | PPUC

Regulatory Matters [Line Items]

LTIIP recovery period

5 years

Pennsylvania | Pennsylvania Companies

Regulatory Matters [Line Items]

Requested reinvestment of CTA (percent)

50.00%

Pennsylvania | Pennsylvania Companies | Subsequent Event

Regulatory Matters [Line Items]

Number of items related to the calculation of rates | item

1

Number of parties who filed a brief | brief

2

Pennsylvania | ME

Regulatory Matters [Line Items]

Amount of requested rate increase (decrease)

$ 140,200

Pennsylvania | ME | Subsequent Event

Regulatory Matters [Line Items]

Amount of rate increase waiting approval

$ 96,000

Pennsylvania | ME | PPUC

Regulatory Matters [Line Items]

Demand reduction targets proposed return on equity (percent)

1.80%

Energy consumption reduction targets proposed return on equity (percent)

4.00%

Amount of requested rate increase (decrease)

$ 43,440

Pennsylvania | Penn

Regulatory Matters [Line Items]

Amount of requested rate increase (decrease)

42,000

Pennsylvania | Penn | Subsequent Event

Regulatory Matters [Line Items]

Amount of rate increase waiting approval

29,000

Pennsylvania | Penn | PPUC

Regulatory Matters [Line Items]

Demand reduction targets proposed return on equity (percent)

1.70%

Energy consumption reduction targets proposed return on equity (percent)

3.30%

Amount of requested rate increase (decrease)

56,350

Pennsylvania | WP

Regulatory Matters [Line Items]

Amount of requested rate increase (decrease)

98,200

Pennsylvania | WP | Subsequent Event

Regulatory Matters [Line Items]

Amount of rate increase waiting approval

66,000

Pennsylvania | WP | PPUC

Regulatory Matters [Line Items]

Demand reduction targets proposed return on equity (percent)

1.80%

Energy consumption reduction targets proposed return on equity (percent)

2.60%

Amount of requested rate increase (decrease)

88,340

Pennsylvania | PN

Regulatory Matters [Line Items]

Amount of requested rate increase (decrease)

$ 158,800

Pennsylvania | PN | Subsequent Event

Regulatory Matters [Line Items]

Amount of rate increase waiting approval

$ 100,000

Pennsylvania | PN | PPUC

Regulatory Matters [Line Items]

Demand reduction targets proposed return on equity (percent)

0.00%

Energy consumption reduction targets proposed return on equity (percent)

3.90%

Amount of requested rate increase (decrease)

$ 56,740

West Virginia | MP and PE | WVPSC

Regulatory Matters [Line Items]

Energy efficient reduction requirement (percent)

0.50%

Expenditures for cost recovery program

$ 10,400

Minimum energy requirement to file and implement a request for proposal | MW

100

Actual under-recovery balance

$ 119,000

Number of proposed efficient programs | program

3

West Virginia | MP and PE | WVPSC | ENEC

Regulatory Matters [Line Items]

Amount of requested rate increase (decrease)

$ 65,000

Amount of requested rate increase (percent)

4.70%

West Virginia | MP and PE | WVPSC | Modernization and Improvement Plan for Coal-Fired Boilers

Regulatory Matters [Line Items]

Amount of requested rate increase (decrease)

$ 6,900

Amount of requested rate increase (percent)

0.50%

West Virginia | MP and PE | WVPSC | Accelerated Recovery Costs For Modernizing and Improving Coal-Fired Boilers

Regulatory Matters [Line Items]

Amount of requested rate increase (decrease)

$ 7,400

Scenario, Forecast | West Virginia | MP and PE | WVPSC | ENEC

Regulatory Matters [Line Items]

Projected rate over-recovery

$ 54,000

Scenario, Forecast | West Virginia | MP and PE | WVPSC | Accelerated Recovery Costs For Modernizing and Improving Coal-Fired Boilers

Regulatory Matters [Line Items]

Public Utility, Capacity Shortfall | MW

700

Scenario, Forecast | West Virginia | MP | WVPSC | IRP

Regulatory Matters [Line Items]

Public Utility, Capacity Shortfall | MW

850

Regulatory Matters - Reliabilit

Regulatory Matters - Reliability Matters and FERC (Details) $ in Millions	Aug. 24, 2016USD ($)	Sep. 14, 2015	Aug. 24, 2012USD ($)	Sep. 30, 2016USD ($)entitiessubsidiary
Regulatory Matters [Line Items]
Regional enforcement entities | entities				8
FERC
Regulatory Matters [Line Items]
Denied recovery charges of exit fees				$ 78.8
FERC | California Claims Matters | Settled Litigation
Regulatory Matters [Line Items]
Settlement amount	$ 3.6
FERC | PATH-Allegheny | PATH Transmission Project
Regulatory Matters [Line Items]
Cost recovery, PP&E reclassified to Regulatory Assets			$ 62
FERC | Path-WV | PATH Transmission Project
Regulatory Matters [Line Items]
Cost recovery, PP&E reclassified to Regulatory Assets			$ 59
FERC | PATH | PATH Transmission Project
Regulatory Matters [Line Items]
Proposed return on equity			10.90%
Requested return on equity (percent)			10.40%
Return on equity granted for regional transmission organization participation			0.50%
Remaining recovery period of regulatory assets		5 years
FERC | FET
Regulatory Matters [Line Items]
Number of stand-alone transmission subsidiaries | subsidiary				2

Commitments, Guarantees and C66

Commitments, Guarantees and Contingencies (Details) $ in Millions	Sep. 30, 2016USD ($)
Guarantor Obligations [Line Items]
Guarantor obligations	$ 499
At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	81
Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	48
Upon Material Adverse Event
Guarantor Obligations [Line Items]
Guarantor obligations	10
Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	360
CES
Guarantor Obligations [Line Items]
Guarantor obligations	355
CES | At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	81
CES | Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	0
CES | Upon Material Adverse Event
Guarantor Obligations [Line Items]
Guarantor obligations	10
CES | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	264
Regulated
Guarantor Obligations [Line Items]
Guarantor obligations	144
Regulated | At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	0
Regulated | Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	48
Regulated | Upon Material Adverse Event
Guarantor Obligations [Line Items]
Guarantor obligations	0
Regulated | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	$ 96

Commitments, Guarantees and C67

Commitments, Guarantees and Contingencies (Details Textuals)

Oct. 01, 2015

Aug. 03, 2015T

Jun. 30, 2014

May 31, 2014

Sep. 30, 2016USD ($)phaseT

Sep. 30, 2015

Dec. 31, 2014USD ($)

Sep. 30, 2016USD ($)T

Nov. 04, 2016USD ($)

Aug. 01, 2016USD ($)

Dec. 31, 2015USD ($)

Oct. 31, 2012USD ($)

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

$ 3,400,000,000

$ 3,400,000,000

New syndicated senior secured term loan facility

$ 499,000,000

499,000,000

Proposed goal to reduce CO2 pollution (percent)

90.00%

Nuclear plant decommissioning trusts

$ 2,502,000,000

2,502,000,000

$ 2,282,000,000

Clean Water Act

Guarantor Obligations [Line Items]

Waste water discharge permit renewal cycle

5 years

Regulation of Waste Disposal

Guarantor Obligations [Line Items]

Bond closure and post closure period

45 years

Period to complete closure

12 years

Accrual for environmental loss contingencies

$ 121,000,000

121,000,000

Environmental liabilities former gas facilities

89,000,000

89,000,000

Nuclear Plant Matters

Guarantor Obligations [Line Items]

Nuclear plant decommissioning trusts

2,500,000,000

2,500,000,000

Parental guarantee

$ 24,500,000

24,500,000

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

20 years

Caa Compliance

Guarantor Obligations [Line Items]

Loss in period

$ 267,000,000

Amount remaining under contract | T

5,500,000

5,500,000

National Ambient Air Quality Standards

Guarantor Obligations [Line Items]

Capping of SO2 emissions under CSAPR | T

2,400,000

Capping of NOx emissions under CSAPR | T

1,200,000

National Ambient Air Quality Standards | CSAPR

Guarantor Obligations [Line Items]

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

2

Hazardous Air Pollutant Emissions

Guarantor Obligations [Line Items]

Potential cost of compliance, MATS

$ 345,000,000

$ 345,000,000

Climate Change

Guarantor Obligations [Line Items]

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

12.00%

Regulated Distribution | Caa Compliance

Guarantor Obligations [Line Items]

Loss in period

150,000,000

Regulated Distribution | Hazardous Air Pollutant Emissions

Guarantor Obligations [Line Items]

Potential cost of compliance, MATS

177,000,000

177,000,000

Competitive Energy Services

Guarantor Obligations [Line Items]

New syndicated senior secured term loan facility

355,000,000

355,000,000

Competitive Energy Services | Caa Compliance

Guarantor Obligations [Line Items]

Loss in period

117,000,000

Competitive Energy Services | Hazardous Air Pollutant Emissions

Guarantor Obligations [Line Items]

Potential cost of compliance, MATS

168,000,000

168,000,000

FES and AE Supply | Competitive Energy Services

Guarantor Obligations [Line Items]

Company posted collateral related to net liability positions

$ 53,000,000

Additional collateral posted or accelerated payments

81,000,000

81,000,000

FES

Guarantor Obligations [Line Items]

Company posted collateral related to net liability positions

193,000,000

193,000,000

Settlement amount

$ 70,000,000

Nuclear plant decommissioning trusts

1,542,000,000

1,542,000,000

$ 1,327,000,000

FES | Caa Compliance

Guarantor Obligations [Line Items]

Annual contested damage claim

$ 70,000,000

Period of annual contested damage claim

11 years

FES | Competitive Energy Services

Guarantor Obligations [Line Items]

Additional collateral posted or accelerated payments

$ 355,000,000

Global Holding | Senior Secured Term Loan | Senior Loans

Guarantor Obligations [Line Items]

New syndicated senior secured term loan facility

$ 300,000,000

$ 300,000,000

$ 350,000,000

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

Guarantor Obligations [Line Items]

Investment ownership percentage

69.99%

69.99%

FEV | 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%

AE Supply

Guarantor Obligations [Line Items]

Company posted collateral related to net liability positions

$ 4,000,000

$ 4,000,000

Environmental Protection Agency | Caa Compliance

Guarantor Obligations [Line Items]

Period of time to implement plan

3 years

Minimum | Clean Water Act

Guarantor Obligations [Line Items]

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

150,000,000

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

Certain Coal-Fired Power Plant | FirstEnergy Generation LLC | Mercury and Air Toxic Standards

Guarantor Obligations [Line Items]

Minimum coal supply commitment (ton) | T

3,500,000

Another Coal-Fired Power Plant | FirstEnergy Generation LLC | Mercury and Air Toxic Standards

Guarantor Obligations [Line Items]

Minimum coal supply commitment (ton) | T

2,500,000

FirstEnergy

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

584,000,000

584,000,000

Subsidiaries

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

2,000,000,000

2,000,000,000

Other Guarantee

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

$ 504,000,000

$ 504,000,000

Supplemental Guarantor Inform68

Supplemental Guarantor Information (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Consolidating Statements of Income
Revenues	[1]	$ 3,917	$ 4,123	$ 11,187	$ 11,485
OPERATING EXPENSES:
Fuel		450	482	1,269	1,378
Purchased power		979	1,209	2,992	3,311
Other operating expenses		953	842	2,835	2,799
Provision for depreciation		311	328	974	969
General taxes		265	236	786	747
Impairment of assets		0	8	1,447	24
Total operating expenses		3,056	3,215	10,525	9,429
OPERATING INCOME		861	908	662	2,056
OTHER INCOME (EXPENSE):
Investment income, including net income (loss) from equity investees		28	(28)	75	(14)
Interest expense		(286)	(285)	(863)	(846)
Capitalized financing costs		28	26	79	93
Total other expense		(230)	(287)	(709)	(767)
INCOME (LOSS) BEFORE INCOME TAXES		631	621	(47)	1,289
INCOME TAXES (BENEFITS)		251	226	334	485
NET INCOME (LOSS)		380	395	(381)	804
NET INCOME (LOSS)		380	395	(381)	804
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(18)	(31)	(54)	(94)
Amortized losses (gains) on derivative hedges		2	2	6	4
Change in unrealized gains on available-for-sale securities		4	(11)	67	(21)
Other comprehensive income (loss)		(12)	(40)	19	(111)
Income taxes (benefits) on other comprehensive income (loss)		(5)	(15)	6	(42)
Other comprehensive income (loss), net of tax		(7)	(25)	13	(69)
COMPREHENSIVE INCOME (LOSS)		$ 373	370	$ (368)	735
Bruce Mansfield Unit 1
Condensed Financial Statements, Captions [Line Items]
Percentage of undivided interest of non guarantor subsidiary		93.83%		93.83%
Eliminations
Consolidating Statements of Income
Revenues		$ (859)	(906)	$ (2,593)	(2,618)
OPERATING EXPENSES:
Fuel		0	0	0	0
Other operating expenses		11	12	37	36
Provision for depreciation		0	(1)	(2)	(2)
General taxes		0	0	0	0
Impairment of assets				0	0
Total operating expenses		(848)	(895)	(2,558)	(2,584)
OPERATING INCOME		(11)	(11)	(35)	(34)
OTHER INCOME (EXPENSE):
Investment income, including net income (loss) from equity investees		(236)	(198)	(342)	(569)
Miscellaneous income		0	0	0	0
Capitalized financing costs		0	0	0	0
Total other expense		(207)	(174)	(260)	(501)
INCOME (LOSS) BEFORE INCOME TAXES		(218)	(185)	(295)	(535)
INCOME TAXES (BENEFITS)		2	1	4	4
NET INCOME (LOSS)		(220)	(186)	(299)	(539)
NET INCOME (LOSS)		(220)	(186)	(299)	(539)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		3	3	10	11
Amortized losses (gains) on derivative hedges		0	0	0	0
Change in unrealized gains on available-for-sale securities		(5)	11	(60)	20
Other comprehensive income (loss)		(2)	14	(50)	31
Income taxes (benefits) on other comprehensive income (loss)		(1)	5	(19)	11
Other comprehensive income (loss), net of tax		(1)	9	(31)	20
COMPREHENSIVE INCOME (LOSS)		(221)	(177)	(330)	(519)
Eliminations | Affiliates
OPERATING EXPENSES:
Purchased power		(859)	(906)	(2,593)	(2,618)
OTHER INCOME (EXPENSE):
Interest expense		15	9	39	24
Eliminations | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense		14	15	43	44
FES
Consolidating Statements of Income
Revenues		1,065	1,293	3,281	3,699
OPERATING EXPENSES:
Fuel		0	0	0	0
Other operating expenses		95	34	218	300
Provision for depreciation		4	3	10	8
General taxes		8	10	23	36
Impairment of assets				23	16
Total operating expenses		1,304	1,380	3,991	4,353
OPERATING INCOME		(239)	(87)	(710)	(654)
OTHER INCOME (EXPENSE):
Investment income, including net income (loss) from equity investees		224	191	310	551
Miscellaneous income		0	0	3	1
Capitalized financing costs		0	0	0	0
Total other expense		197	170	239	492
INCOME (LOSS) BEFORE INCOME TAXES		(42)	83	(471)	(162)
INCOME TAXES (BENEFITS)		(82)	(37)	(204)	(258)
NET INCOME (LOSS)		40	120	(267)	96
NET INCOME (LOSS)		40	120	(267)	96
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(3)	(4)	(10)	(12)
Amortized losses (gains) on derivative hedges		1	0	0	(2)
Change in unrealized gains on available-for-sale securities		5	(11)	61	(20)
Other comprehensive income (loss)		3	(15)	51	(34)
Income taxes (benefits) on other comprehensive income (loss)		1	(6)	20	(13)
Other comprehensive income (loss), net of tax		2	(9)	31	(21)
COMPREHENSIVE INCOME (LOSS)		42	111	(236)	75
FES | Affiliates
OPERATING EXPENSES:
Purchased power		1,011	932	2,888	2,657
OTHER INCOME (EXPENSE):
Interest expense		(13)	(8)	(34)	(21)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power		186	401	829	1,336
OTHER INCOME (EXPENSE):
Interest expense		(14)	(13)	(40)	(39)
FG
Consolidating Statements of Income
Revenues		494	420	1,309	1,259
OPERATING EXPENSES:
Fuel		149	193	449	523
Other operating expenses		61	66	220	208
Provision for depreciation		28	30	91	92
General taxes		7	8	23	23
Impairment of assets				517	0
Total operating expenses		245	297	1,300	846
OPERATING INCOME		249	123	9	413
OTHER INCOME (EXPENSE):
Investment income, including net income (loss) from equity investees		8	4	21	12
Miscellaneous income		1	1	1	4
Capitalized financing costs		3	1	7	4
Total other expense		(18)	(22)	(57)	(64)
INCOME (LOSS) BEFORE INCOME TAXES		231	101	(48)	349
INCOME TAXES (BENEFITS)		87	36	(1)	131
NET INCOME (LOSS)		144	65	(47)	218
NET INCOME (LOSS)		144	65	(47)	218
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(3)	(3)	(10)	(11)
Amortized losses (gains) on derivative hedges		0	0	0	0
Change in unrealized gains on available-for-sale securities		0	0	0	0
Other comprehensive income (loss)		(3)	(3)	(10)	(11)
Income taxes (benefits) on other comprehensive income (loss)		(1)	(1)	(4)	(4)
Other comprehensive income (loss), net of tax		(2)	(2)	(6)	(7)
COMPREHENSIVE INCOME (LOSS)		142	63	(53)	211
FG | Affiliates
OPERATING EXPENSES:
Purchased power		0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense		(3)	(2)	(7)	(6)
FG | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense		(27)	(26)	(79)	(78)
NG
Consolidating Statements of Income
Revenues		400	531	1,404	1,494
OPERATING EXPENSES:
Fuel		53	52	146	143
Other operating expenses		149	134	450	452
Provision for depreciation		51	47	151	142
General taxes		6	6	20	19
Impairment of assets				0	0
Total operating expenses		298	316	912	967
OPERATING INCOME		102	215	492	527
OTHER INCOME (EXPENSE):
Investment income, including net income (loss) from equity investees		28	(18)	67	(1)
Miscellaneous income		0	0	0	0
Capitalized financing costs		6	7	20	22
Total other expense		23	(24)	50	(19)
INCOME (LOSS) BEFORE INCOME TAXES		125	191	542	508
INCOME TAXES (BENEFITS)		49	70	196	187
NET INCOME (LOSS)		76	121	346	321
NET INCOME (LOSS)		76	121	346	321
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		0	0	0	0
Amortized losses (gains) on derivative hedges		0	0	0	0
Change in unrealized gains on available-for-sale securities		5	(11)	60	(20)
Other comprehensive income (loss)		5	(11)	60	(20)
Income taxes (benefits) on other comprehensive income (loss)		2	(4)	23	(7)
Other comprehensive income (loss), net of tax		3	(7)	37	(13)
COMPREHENSIVE INCOME (LOSS)		79	114	383	308
NG | Affiliates
OPERATING EXPENSES:
Purchased power		39	77	145	211
OTHER INCOME (EXPENSE):
Interest expense		(2)	(1)	(4)	(3)
NG | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense		(9)	(12)	(33)	(37)
Consolidated
Consolidating Statements of Income
Revenues		1,100	1,338	3,401	3,834
OPERATING EXPENSES:
Fuel		202	245	595	666
Other operating expenses		316	246	925	996
Provision for depreciation		83	79	250	240
General taxes		21	24	66	78
Impairment of assets		0	0	540	16
Total operating expenses		999	1,098	3,645	3,582
OPERATING INCOME		101	240	(244)	252
OTHER INCOME (EXPENSE):
Investment income, including net income (loss) from equity investees		24	(21)	56	(7)
Miscellaneous income		1	1	4	5
Capitalized financing costs		9	8	27	26
Total other expense		(5)	(50)	(28)	(92)
INCOME (LOSS) BEFORE INCOME TAXES		96	190	(272)	160
INCOME TAXES (BENEFITS)		56	70	(5)	64
NET INCOME (LOSS)		40	120	(267)	96
NET INCOME (LOSS)		40	120	(267)	96
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(3)	(4)	(10)	(12)
Amortized losses (gains) on derivative hedges		1	0	0	(2)
Change in unrealized gains on available-for-sale securities		5	(11)	61	(20)
Other comprehensive income (loss)		3	(15)	51	(34)
Income taxes (benefits) on other comprehensive income (loss)		1	(6)	20	(13)
Other comprehensive income (loss), net of tax		2	(9)	31	(21)
COMPREHENSIVE INCOME (LOSS)		42	111	(236)	75
Consolidated | Affiliates
OPERATING EXPENSES:
Purchased power		191	103	440	250
OTHER INCOME (EXPENSE):
Interest expense		(3)	(2)	(6)	(6)
Consolidated | Non-Affiliates
OPERATING EXPENSES:
Purchased power		186	401	829	1,336
OTHER INCOME (EXPENSE):
Interest expense		$ (36)	$ (36)	$ (109)	$ (110)
[1]	Includes excise tax collections of $111 million and $109 million in the three months ended September 30, 2016 and 2015, respectively, and $310 million and $320 million in the nine months ended September 30, 2016 and 2015, respectively.

Supplemental Guarantor Inform69

Supplemental Guarantor Information (Details 1) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 551	$ 131	$ 86	$ 85
Receivables-
Customers	1,470	1,415
Other	159	180
Materials and supplies	699	785
Derivatives	152	157
Collateral	89	70
Prepayments and other	156	167
Total current assets	3,480	3,040
PROPERTY, PLANT AND EQUIPMENT:
In service	50,889	49,952
Less - Accumulated provision for depreciation	15,450	15,160
Property, plant and equipment in service net of accumulated provision for depreciation	35,439	34,792
Construction work in progress	2,394	2,422
Total net property, plant and equipment	37,833	37,214
INVESTMENTS:
Nuclear plant decommissioning trusts	2,502	2,282
Other	533	506
Total other property and investments	3,035	2,788
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	5,618	6,418	6,418
Other	907	1,286
Total deferred charges and other assets	7,613	9,052
Total assets	51,961	52,094	51,930
CURRENT LIABILITIES:
Currently payable long-term debt	1,216	1,166
Other	2,975	1,708
Accounts payable-
Accrued taxes	537	519
Derivatives	91	106
Other	915	694
Total current liabilities	7,043	5,602
CAPITALIZATION:
Total common stockholders' equity	11,503	12,421
Long-term debt and other long-term obligations	18,532	19,099
Total capitalization	30,035	31,521
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	765	791
Accumulated deferred income taxes	7,136	6,773
Retirement benefits	4,080	4,245
Asset retirement obligations	1,459	1,410
Other	1,269	1,555
Total noncurrent liabilities	14,883	14,971
Total liabilities and capitalization	51,961	52,094
Eliminations
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	(492)	(846)
Other	0	0
Notes receivable from affiliated companies	(3,102)	(2,410)
Materials and supplies	0	0
Derivatives	0	0
Collateral	0	0
Prepayments and other	0	0
Total current assets	(3,594)	(3,256)
PROPERTY, PLANT AND EQUIPMENT:
In service	(378)	(382)
Less - Accumulated provision for depreciation	(192)	(194)
Property, plant and equipment in service net of accumulated provision for depreciation	(186)	(188)
Construction work in progress	0	0
Total net property, plant and equipment	(186)	(188)
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	(7,826)	(7,452)
Other	0	0
Total other property and investments	(7,826)	(7,452)
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	(306)	(316)
Customer intangibles	0	0
Goodwill		0
Property taxes	0	0
Derivatives	0	0
Other	12	12
Total deferred charges and other assets	(294)	(304)
Total assets	(11,900)	(11,200)
CURRENT LIABILITIES:
Currently payable long-term debt	(25)	(25)
Other		0
Accounts payable-
Affiliated companies	(549)	(856)
Other	0	0
Accrued taxes	(38)	(86)
Derivatives	0	0
Other	33	45
Total current liabilities	(3,681)	(3,332)
CAPITALIZATION:
Total common stockholders' equity	(7,790)	(7,420)
Long-term debt and other long-term obligations	(1,104)	(1,136)
Total capitalization	(8,894)	(8,556)
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	765	791
Accumulated deferred income taxes	(90)	(103)
Retirement benefits	0	0
Asset retirement obligations	0	0
Derivatives	0	0
Other	0	0
Total noncurrent liabilities	675	688
Total liabilities and capitalization	(11,900)	(11,200)
Eliminations | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	(3,102)	(2,410)
FES
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	225	275
Affiliated companies	356	433
Other	21	36
Notes receivable from affiliated companies	494	406
Materials and supplies	38	53
Derivatives	146	154
Collateral	85	70
Prepayments and other	57	48
Total current assets	1,422	1,475
PROPERTY, PLANT AND EQUIPMENT:
In service	121	93
Less - Accumulated provision for depreciation	49	40
Property, plant and equipment in service net of accumulated provision for depreciation	72	53
Construction work in progress	3	30
Total net property, plant and equipment	75	83
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	7,826	7,452
Other	0	0
Total other property and investments	7,826	7,452
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	279	300
Customer intangibles	11	61
Goodwill		23
Property taxes	0	0
Derivatives	98	79
Other	29	29
Total deferred charges and other assets	417	492
Total assets	9,740	9,502
CURRENT LIABILITIES:
Currently payable long-term debt	0	0
Other		0
Accounts payable-
Affiliated companies	597	884
Other	18	21
Accrued taxes	31	7
Derivatives	88	103
Other	66	66
Total current liabilities	3,523	3,102
CAPITALIZATION:
Total common stockholders' equity	5,409	5,605
Long-term debt and other long-term obligations	691	690
Total capitalization	6,100	6,295
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	7	6
Retirement benefits	25	27
Asset retirement obligations	0	0
Derivatives	45	37
Other	40	35
Total noncurrent liabilities	117	105
Total liabilities and capitalization	9,740	9,502
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	2,723	2,021
FG
CURRENT ASSETS:
Cash and cash equivalents	2	2	2	2
Receivables-
Customers	0	0
Affiliated companies	351	403
Other	4	4
Notes receivable from affiliated companies	1,501	1,210
Materials and supplies	153	204
Derivatives	0	0
Collateral	0	0
Prepayments and other	14	18
Total current assets	2,025	1,841
PROPERTY, PLANT AND EQUIPMENT:
In service	5,683	6,367
Less - Accumulated provision for depreciation	1,915	2,144
Property, plant and equipment in service net of accumulated provision for depreciation	3,768	4,223
Construction work in progress	287	249
Total net property, plant and equipment	4,055	4,472
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	27	16
Customer intangibles	0	0
Goodwill		0
Property taxes	3	12
Derivatives	0	0
Other	333	312
Total deferred charges and other assets	363	340
Total assets	6,453	6,663
CURRENT LIABILITIES:
Currently payable long-term debt	199	229
Other		8
Accounts payable-
Affiliated companies	165	146
Other	71	118
Accrued taxes	28	93
Derivatives	1	1
Other	71	61
Total current liabilities	1,015	1,045
CAPITALIZATION:
Total common stockholders' equity	2,897	2,944
Long-term debt and other long-term obligations	2,108	2,116
Total capitalization	5,005	5,060
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	0	0
Retirement benefits	194	305
Asset retirement obligations	186	191
Derivatives	5	1
Other	48	61
Total noncurrent liabilities	433	558
Total liabilities and capitalization	6,453	6,663
FG | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	480	389
NG
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	267	461
Other	30	19
Notes receivable from affiliated companies	1,133	805
Materials and supplies	212	213
Derivatives	0	0
Collateral	0	0
Prepayments and other	1	0
Total current assets	1,643	1,498
PROPERTY, PLANT AND EQUIPMENT:
In service	8,674	8,233
Less - Accumulated provision for depreciation	4,050	3,775
Property, plant and equipment in service net of accumulated provision for depreciation	4,624	4,458
Construction work in progress	758	878
Total net property, plant and equipment	5,382	5,336
INVESTMENTS:
Nuclear plant decommissioning trusts	1,542	1,327
Investment in affiliated companies	0	0
Other	0	0
Total other property and investments	1,542	1,327
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	0	0
Goodwill		0
Property taxes	7	28
Derivatives	0	0
Other	0	14
Total deferred charges and other assets	7	42
Total assets	8,574	8,203
CURRENT LIABILITIES:
Currently payable long-term debt	8	308
Other		0
Accounts payable-
Affiliated companies	180	368
Other	0	0
Accrued taxes	51	62
Derivatives	0	0
Other	12	9
Total current liabilities	251	747
CAPITALIZATION:
Total common stockholders' equity	4,893	4,476
Long-term debt and other long-term obligations	1,120	840
Total capitalization	6,013	5,316
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	817	697
Retirement benefits	0	0
Asset retirement obligations	701	640
Derivatives	0	0
Other	792	803
Total noncurrent liabilities	2,310	2,140
Total liabilities and capitalization	8,574	8,203
NG | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	0	0
Consolidated
CURRENT ASSETS:
Cash and cash equivalents	2	2	$ 2	$ 2
Receivables-
Customers	225	275
Affiliated companies	482	451
Other	55	59
Notes receivable from affiliated companies	26	11
Materials and supplies	403	470
Derivatives	146	154
Collateral	85	70
Prepayments and other	72	66
Total current assets	1,496	1,558
PROPERTY, PLANT AND EQUIPMENT:
In service	14,100	14,311
Less - Accumulated provision for depreciation	5,822	5,765
Property, plant and equipment in service net of accumulated provision for depreciation	8,278	8,546
Construction work in progress	1,048	1,157
Total net property, plant and equipment	9,326	9,703
INVESTMENTS:
Nuclear plant decommissioning trusts	1,542	1,327
Investment in affiliated companies	0	0
Other	10	10
Total other property and investments	1,552	1,337
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	11	61
Goodwill	0	23
Property taxes	10	40
Derivatives	98	79
Other	374	367
Total deferred charges and other assets	493	570
Total assets	12,867	13,168
CURRENT LIABILITIES:
Currently payable long-term debt	182	512
Other	0	8
Accounts payable-
Affiliated companies	393	542
Other	89	139
Accrued taxes	72	76
Derivatives	89	104
Other	182	181
Total current liabilities	1,108	1,562
CAPITALIZATION:
Total common stockholders' equity	5,409	5,605
Long-term debt and other long-term obligations	2,815	2,510
Total capitalization	8,224	8,115
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	765	791
Accumulated deferred income taxes	734	600
Retirement benefits	219	332
Asset retirement obligations	887	831
Derivatives	50	38
Other	880	899
Total noncurrent liabilities	3,535	3,491
Total liabilities and capitalization	12,867	13,168
Consolidated | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	$ 101	$ 0

Supplemental Guarantor Inform70

Supplemental Guarantor Information (Details 2) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES			$ 2,580	$ 2,317
New Financing-
Long-term debt			521	1,084
Short-term borrowings, net			1,275	134
Redemptions and Repayments-
Long-term debt			(1,017)	(781)
Other			(5)	(11)
Net cash provided from (used for) financing activities			316	(29)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	$ (664)	$ (539)	(2,156)	(2,025)
Nuclear fuel			(195)	(101)
Sales of investment securities held in trusts			1,361	1,126
Purchases of investment securities held in trusts			(1,437)	(1,213)
Other			52	37
Net cash used for investing activities			(2,476)	(2,287)
Net change in cash and cash equivalents			420	1
Cash and cash equivalents at beginning of period			131	85
Cash and cash equivalents at end of period	551	86	551	86
Eliminations
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES			(12)	(12)
New Financing-
Long-term debt			0	0
Short-term borrowings, net			(692)	(740)
Redemptions and Repayments-
Long-term debt			12	12
Short-term borrowings, net				(82)
Other			0	0
Net cash provided from (used for) financing activities			(680)	(810)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			0	0
Nuclear fuel			0	0
Sales of investment securities held in trusts			0	0
Purchases of investment securities held in trusts			0	0
Cash investments			0	0
Loans to affiliated companies, net			692	822
Other			0	0
Net cash used for investing activities			692	822
Net change in cash and cash equivalents			0	0
Cash and cash equivalents at beginning of period			0	0
Cash and cash equivalents at end of period	0	0	0	0
FES
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES			(605)	(624)
New Financing-
Long-term debt			0	0
Short-term borrowings, net			701	689
Redemptions and Repayments-
Long-term debt			0	(17)
Short-term borrowings, net				0
Other			0	0
Net cash provided from (used for) financing activities			701	672
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(28)	(3)
Nuclear fuel			0	0
Sales of investment securities held in trusts			0	0
Purchases of investment securities held in trusts			0	0
Cash investments			10	(10)
Loans to affiliated companies, net			(87)	(45)
Other			9	10
Net cash used for investing activities			(96)	(48)
Net change in cash and cash equivalents			0	0
Cash and cash equivalents at beginning of period			0	0
Cash and cash equivalents at end of period	0	0	0	0
FG
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES			401	405
New Financing-
Long-term debt			186	43
Short-term borrowings, net			92	51
Redemptions and Repayments-
Long-term debt			(211)	(55)
Short-term borrowings, net				0
Other			(5)	(4)
Net cash provided from (used for) financing activities			62	35
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(171)	(144)
Nuclear fuel			0	0
Sales of investment securities held in trusts			0	0
Purchases of investment securities held in trusts			0	0
Cash investments			0	0
Loans to affiliated companies, net			(292)	(302)
Other			0	6
Net cash used for investing activities			(463)	(440)
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	2	2
NG
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES			820	867
New Financing-
Long-term debt			285	296
Short-term borrowings, net			0	0
Redemptions and Repayments-
Long-term debt			(304)	(322)
Short-term borrowings, net				(27)
Other			(2)	(1)
Net cash provided from (used for) financing activities			(21)	(54)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(233)	(194)
Nuclear fuel			(195)	(101)
Sales of investment securities held in trusts			576	503
Purchases of investment securities held in trusts			(619)	(546)
Cash investments			0	0
Loans to affiliated companies, net			(328)	(475)
Other			0	0
Net cash used for investing activities			(799)	(813)
Net change in cash and cash equivalents			0	0
Cash and cash equivalents at beginning of period			0	0
Cash and cash equivalents at end of period	0	0	0	0
Consolidated
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES			604	636
New Financing-
Long-term debt			471	339
Short-term borrowings, net			101	0
Redemptions and Repayments-
Long-term debt			(503)	(382)
Short-term borrowings, net			0	(109)
Other			(7)	(5)
Net cash provided from (used for) financing activities			62	(157)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(432)	(341)
Nuclear fuel			(195)	(101)
Sales of investment securities held in trusts			576	503
Purchases of investment securities held in trusts			(619)	(546)
Cash investments			10	(10)
Loans to affiliated companies, net			(15)	0
Other			9	16
Net cash used for investing activities			(666)	(479)
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	$ 2	$ 2

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Financial Information
Revenues		$ 3,917	$ 4,123	$ 11,187	$ 11,485
Revenues	[1]	3,917	4,123	11,187	11,485
Depreciation		311	328	974	969
Amortization of regulatory assets, net		98	110	222	201
Impairment of assets		0	8	1,447	24
Investment income (loss)		28	(28)	75	(14)
Interest expense		286	285	863	846
Income taxes (benefits)		251	226	334	485
NET INCOME (LOSS)		380	395	(381)	804
Total assets		51,961	51,930	51,961	51,930	$ 52,094
Goodwill		5,618	6,418	5,618	6,418	6,418
Property additions		664	539	2,156	2,025
Regulated Distribution
Segment Financial Information
Goodwill		5,092		5,092		5,092
Competitive Energy Services
Segment Financial Information
Goodwill		0		0		$ 800
Operating Segments | Regulated Distribution
Segment Financial Information
Revenues		2,702	2,624	7,423	7,425
Revenues		2,702	2,624	7,423	7,425
Depreciation		171	174	510	516
Amortization of regulatory assets, net		98	110	218	196
Impairment of assets			8	0	8
Investment income (loss)		13	8	37	33
Interest expense		139	149	431	439
Income taxes (benefits)		167	137	349	350
NET INCOME (LOSS)		283	234	594	598
Total assets		28,276	27,883	28,276	27,883
Goodwill		5,092	5,092	5,092	5,092
Property additions		303	292	878	884
Operating Segments | Regulated Transmission
Segment Financial Information
Revenues		285	248	824	755
Revenues		285	248	824	755
Depreciation		45	41	132	116
Amortization of regulatory assets, net		0	0	4	5
Impairment of assets			0	0	0
Investment income (loss)		0	0	0	0
Interest expense		43	40	128	119
Income taxes (benefits)		45	41	130	135
NET INCOME (LOSS)		78	70	223	231
Total assets		8,034	6,988	8,034	6,988
Goodwill		526	526	526	526
Property additions		246	149	755	700
Operating Segments | Competitive Energy Services
Segment Financial Information
Revenues		998	1,327	3,158	3,536
Revenues		1,115	1,468	3,535	4,099
Depreciation		79	98	284	293
Amortization of regulatory assets, net		0	0	0	0
Impairment of assets			0	1,447	16
Investment income (loss)		23	(19)	56	(7)
Interest expense		48	48	143	144
Income taxes (benefits)		49	84	(96)	76
NET INCOME (LOSS)		86	145	(1,029)	129
Total assets		15,165	16,229	15,165	16,229
Goodwill		0	800	0	800
Property additions		110	83	492	400
Corporate/Other
Segment Financial Information
Revenues		0	0	0	0
Revenues		0	0	0	0
Depreciation		16	15	48	44
Amortization of regulatory assets, net		0	0	0	0
Impairment of assets			0	0	0
Investment income (loss)		2	(6)	13	(9)
Interest expense		56	48	161	144
Income taxes (benefits)		(11)	(39)	(51)	(84)
NET INCOME (LOSS)		(67)	(54)	(169)	(154)
Total assets		486	830	486	830
Goodwill		0	0	0	0
Property additions		5	15	31	41
Intersegment Eliminations
Segment Financial Information
Revenues		(117)	(141)	(377)	(563)
Intersegment Eliminations | Competitive Energy Services
Segment Financial Information
Revenues		117	141	377	563
Reconciling Adjustments
Segment Financial Information
Revenues		(68)	(76)	(218)	(231)
Revenues		(185)	(217)	(595)	(794)
Depreciation		0	0	0	0
Amortization of regulatory assets, net		0	0	0	0
Impairment of assets			0	0	0
Investment income (loss)		(10)	(11)	(31)	(31)
Interest expense		0	0	0	0
Income taxes (benefits)		1	3	2	8
NET INCOME (LOSS)		0	0	0	0
Total assets		0	0	0	0
Goodwill		0	0	0	0
Property additions		$ 0	$ 0	$ 0	$ 0
[1]	Includes excise tax collections of $111 million and $109 million in the three months ended September 30, 2016 and 2015, respectively, and $310 million and $320 million in the nine months ended September 30, 2016 and 2015, respectively.

Segment Information (Details Te

Segment Information (Details Textuals) mi² in Thousands, customer in Millions, $ in Billions	9 Months Ended
	Sep. 30, 2016USD ($)mi²customercompanyMW
Regulated Distribution
Segment Reporting Information [Line Items]
Number of existing utility operating companies | company	10
Number of customers served by utility operating companies | customer	6
Number of square miles in service area | mi²	65
Megawatts of net demonstrated capacity of competitive segment | MW	3,790
Competitive Energy Services
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment | MW	13,162
Other/Corporate
Segment Reporting Information [Line Items]
Long-term debt and other long-term obligations | $	$ 4.2
Long-term debt percentage bearing variable interest (percent)	28.00%
FirstEnergy | Revolving Credit Facility | Other/Corporate
Segment Reporting Information [Line Items]
Long-term line of credit | $	$ 2.7