FirstEnergy (FE) 10-Q 26 Oct 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	9 Months Ended
	Sep. 30, 2017shares
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, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding	444,858,003
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, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
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, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
REVENUES:
Regulated Distribution		$ 2,610	$ 2,691	$ 7,362	$ 7,390
Regulated Transmission		342	294	982	851
Unregulated businesses		762	932	2,231	2,946
Total revenues	[1]	3,714	3,917	10,575	11,187
OPERATING EXPENSES:
Fuel		363	450	1,074	1,269
Purchased power		861	979	2,459	2,992
Other operating expenses		942	953	3,041	2,835
Provision for depreciation		289	311	845	974
Amortization of regulatory assets, net		91	98	215	222
General taxes		253	265	777	786
Impairment of assets (Note 14)		31	0	162	1,447
Total operating expenses		2,830	3,056	8,573	10,525
OPERATING INCOME		884	861	2,002	662
OTHER INCOME (EXPENSE):
Investment income		37	28	78	75
Interest expense		(305)	(286)	(882)	(863)
Capitalized financing costs		19	28	59	79
Total other expense		(249)	(230)	(745)	(709)
INCOME (LOSS) BEFORE INCOME TAXES		635	631	1,257	(47)
INCOME TAXES		239	251	482	334
NET INCOME (LOSS)		$ 396	$ 380	$ 775	$ (381)
EARNINGS (LOSS) PER SHARE OF COMMON STOCK:
Basic, in dollars per share		$ 0.89	$ 0.89	$ 1.75	$ (0.90)
Diluted, in dollars per share		$ 0.89	$ 0.89	$ 1.74	$ (0.90)
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic, in shares		444	425	444	425
Diluted, in shares		446	427	445	425
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share		$ 0.72	$ 0.72	$ 1.44	$ 1.44
Excise taxes collected		$ 102	$ 111	$ 293	$ 310
[1]	Includes excise tax collections of $102 million and $111 million in the three months ended September 30, 2017 and 2016, respectively, and $293 million and $310 million in the nine months ended September 30, 2017 and 2016, respectively.

Consolidated Statements of Inc3

Consolidated Statements of Income (Loss) (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Statement [Abstract]
Excise taxes collected	$ 102	$ 111	$ 293	$ 310

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) (FirstEnergy Corp.) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ 396	$ 380	$ 775	$ (381)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(19)	(18)	(55)	(54)
Amortized losses on derivative hedges	4	2	8	6
Change in unrealized gains on available-for-sale securities	(6)	4	8	67
Other comprehensive income (loss)	(21)	(12)	(39)	19
Income taxes (benefits) on other comprehensive income (loss)	(9)	(5)	(16)	6
Other comprehensive income (loss), net of tax	(12)	(7)	(23)	13
COMPREHENSIVE INCOME (LOSS)	$ 384	$ 373	$ 752	$ (368)

Consolidated Balance Sheets (Fi

Consolidated Balance Sheets (FirstEnergy Corp.) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
CURRENT ASSETS:
Cash and cash equivalents	$ 399	$ 199
Receivables-
Customers, net of allowance for uncollectible accounts of $52 in 2017 and $53 in 2016	1,370	1,440
Other, net of allowance for uncollectible accounts of $1 in 2017 and 2016	172	175
Materials and supplies	543	564
Prepaid taxes	123	98
Derivatives	35	140
Collateral	146	176
Other	143	158
Total current assets	2,931	2,950
PROPERTY, PLANT AND EQUIPMENT:
In service	44,229	43,767
Less — Accumulated provision for depreciation	16,086	15,731
Property, plant and equipment in service net of accumulated provision for depreciation	28,143	28,036
Construction work in progress	1,355	1,351
Total net property, plant and equipment	29,498	29,387
INVESTMENTS:
Nuclear plant decommissioning trusts	2,632	2,514
Other	511	512
Total other property and investments	3,143	3,026
ASSETS HELD FOR SALE (Note 14)	788	0
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	5,618	5,618
Regulatory assets	929	1,014
Other	742	1,153
Total deferred charges and other assets	7,289	7,785
Total assets	43,649	43,148
CURRENT LIABILITIES:
Currently payable long-term debt	1,076	1,685
Short-term borrowings	500	2,675
Accounts payable	924	1,043
Accrued taxes	520	580
Accrued compensation and benefits	337	363
Collateral	31	42
Other	867	738
Total current liabilities	4,255	7,126
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 700,000,000 shares - 444,858,003 and 442,344,218 shares outstanding as of September 30, 2017 and December 31, 2016, respectively	44	44
Other paid-in capital	9,974	10,555
Accumulated other comprehensive income	151	174
Accumulated deficit	(3,763)	(4,532)
Total common stockholders’ equity	6,406	6,241
Long-term debt and other long-term obligations	21,089	18,192
Total capitalization	27,495	24,433
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	4,225	3,765
Retirement benefits	3,814	3,719
Asset retirement obligations	1,550	1,482
Deferred gain on sale and leaseback transaction	732	757
Adverse power contract liability	143	162
Other	1,435	1,704
Total noncurrent liabilities	11,899	11,589
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 11)
Total liabilities and capitalization	$ 43,649	$ 43,148

Consolidated Balance Sheets (F6

Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Common stockholders’ equity-
Common stock, par value (in dollars per share)	$ 0.1	$ 0.1
Common stock, shares authorized	700,000,000	490,000,000
Common stock, shares outstanding	444,858,003	442,344,218
Customer
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 52	$ 53
Other
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 1	$ 1

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (FirstEnergy Corp.) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$ 775	$ (381)
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs	1,248	1,477
Deferred purchased power and other costs	55	(34)
Deferred income taxes and investment tax credits, net	453	318
Impairment of assets (Note 14)	162	1,447
Investment impairments	10	13
Deferred costs on sale leaseback transaction, net	37	36
Retirement benefits, net of payments	28	45
Pension trust contributions	0	(297)
Unrealized (gain) loss on derivative transactions (Note 8)	64	(10)
Lease payments on sale and leaseback transaction	(47)	(94)
Changes in current assets and liabilities-
Receivables	73	(34)
Materials and supplies	(6)	45
Prepaid taxes and other current assets	(41)	(28)
Accounts payable	(22)	(17)
Accrued taxes	(161)	(81)
Accrued compensation and benefits	(54)	2
Other current liabilities	13	53
Collateral, net	19	25
Other	156	107
Net cash provided from operating activities	2,762	2,592
New Financing-
Long-term debt	4,050	521
Short-term borrowings, net	0	1,275
Redemptions and Repayments-
Long-term debt	(1,711)	(1,017)
Short-term borrowings, net	(2,175)	0
Common stock dividend payments	(478)	(458)
Other	(67)	(17)
Net cash (used for) provided from financing activities	(381)	304
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,847)	(2,156)
Nuclear fuel	(156)	(195)
Sales of investment securities held in trusts	1,923	1,361
Purchases of investment securities held in trusts	(1,995)	(1,437)
Asset removal costs	(130)	(101)
Other	24	52
Net cash used for investing activities	(2,181)	(2,476)
Net change in cash and cash equivalents	200	420
Cash and cash equivalents at beginning of period	199	131
Cash and cash equivalents at end of period	$ 399	$ 551

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, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
REVENUES:
Electric sales		$ 762	$ 932	$ 2,231	$ 2,946
Total revenues	[1]	3,714	3,917	10,575	11,187
OPERATING EXPENSES:
Fuel		363	450	1,074	1,269
Purchased power		861	979	2,459	2,992
Other operating expenses		942	953	3,041	2,835
Provision for depreciation		289	311	845	974
General taxes		253	265	777	786
Impairment of assets (Note 14)		31	0	162	1,447
Total operating expenses		2,830	3,056	8,573	10,525
OPERATING INCOME		884	861	2,002	662
OTHER INCOME (EXPENSE):
Investment income		37	28	78	75
Interest expense		(305)	(286)	(882)	(863)
Capitalized financing costs		19	28	59	79
Total other expense		(249)	(230)	(745)	(709)
INCOME (LOSS) BEFORE INCOME TAXES		635	631	1,257	(47)
INCOME TAXES		239	251	482	334
NET INCOME (LOSS)		396	380	775	(381)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME		396	380	775	(381)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(19)	(18)	(55)	(54)
Amortized losses on derivative hedges		4	2	8	6
Change in unrealized gains on available-for-sale securities		(6)	4	8	67
Other comprehensive income (loss)		(21)	(12)	(39)	19
Income taxes (benefits) on other comprehensive income (loss)		(9)	(5)	(16)	6
Other comprehensive income (loss), net of tax		(12)	(7)	(23)	13
COMPREHENSIVE INCOME (LOSS)		384	373	752	(368)
FES
REVENUES:
Other		2	37	63	124
Total revenues		743	1,100	2,398	3,401
OPERATING EXPENSES:
Fuel		165	202	463	595
Other operating expenses		291	316	1,095	925
Provision for depreciation		28	83	80	250
General taxes		5	21	44	66
Impairment of assets (Note 14)		0	0	0	540
Total operating expenses		641	999	2,352	3,645
OPERATING INCOME		102	101	46	(244)
OTHER INCOME (EXPENSE):
Investment income		39	24	74	56
Miscellaneous income		1	1	6	4
Capitalized financing costs		6	9	20	27
Total other expense		6	(5)	(17)	(28)
INCOME (LOSS) BEFORE INCOME TAXES		108	96	29	(272)
INCOME TAXES		32	56	14	(5)
NET INCOME (LOSS)		76	40	15	(267)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME		76	40	15	(267)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(3)	(3)	(10)	(10)
Amortized losses on derivative hedges		1	1	1	0
Change in unrealized gains on available-for-sale securities		(6)	5	16	61
Other comprehensive income (loss)		(8)	3	7	51
Income taxes (benefits) on other comprehensive income (loss)		(3)	1	2	20
Other comprehensive income (loss), net of tax		(5)	2	5	31
COMPREHENSIVE INCOME (LOSS)		71	42	20	(236)
FES | Affiliates
REVENUES:
Electric sales		88	111	279	360
OPERATING EXPENSES:
Purchased power		0	191	202	440
OTHER INCOME (EXPENSE):
Interest expense		(6)	(3)	(13)	(6)
FES | Non-Affiliates
REVENUES:
Electric sales		653	952	2,056	2,917
OPERATING EXPENSES:
Purchased power		152	186	468	829
OTHER INCOME (EXPENSE):
Interest expense		$ (34)	$ (36)	$ (104)	$ (109)
[1]	Includes excise tax collections of $102 million and $111 million in the three months ended September 30, 2017 and 2016, respectively, and $293 million and $310 million in the nine months ended September 30, 2017 and 2016, respectively.

Consolidated Balance Sheets (F9

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
CURRENT ASSETS:
Cash and cash equivalents	$ 399	$ 199
Receivables-
Customers, net of allowance for uncollectible accounts of $3 in 2017 and $5 in 2016	1,370	1,440
Other	172	175
Materials and supplies	543	564
Derivatives	35	140
Collateral	146	176
Prepaid taxes and other	143	158
Total current assets	2,931	2,950
PROPERTY, PLANT AND EQUIPMENT:
In service	44,229	43,767
Less — Accumulated provision for depreciation	16,086	15,731
Property, plant and equipment in service net of accumulated provision for depreciation	28,143	28,036
Construction work in progress	1,355	1,351
Total net property, plant and equipment	29,498	29,387
INVESTMENTS:
Nuclear plant decommissioning trusts	2,632	2,514
Other	511	512
Total other property and investments	3,143	3,026
DEFERRED CHARGES AND OTHER ASSETS:
Other	742	1,153
Total deferred charges and other assets	7,289	7,785
Total assets	43,649	43,148
CURRENT LIABILITIES:
Currently payable long-term debt	1,076	1,685
Accounts payable-
Accrued taxes	520	580
Other	867	738
Total current liabilities	4,255	7,126
Common stockholders’ equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of September 30, 2017 and December 31, 2016	44	44
Accumulated other comprehensive income	151	174
Accumulated deficit	(3,763)	(4,532)
Total common stockholders’ equity	6,406	6,241
Long-term debt and other long-term obligations	21,089	18,192
Total capitalization	27,495	24,433
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	732	757
Retirement benefits	3,814	3,719
Asset retirement obligations	1,550	1,482
Other	1,435	1,704
Total noncurrent liabilities	11,899	11,589
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 11)
Total liabilities and capitalization	43,649	43,148
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2
Receivables-
Customers, net of allowance for uncollectible accounts of $3 in 2017 and $5 in 2016	171	213
Affiliated companies	327	452
Other	13	27
Notes receivable from affiliated companies	0	29
Materials and supplies	263	267
Derivatives	31	137
Collateral	126	157
Prepaid taxes and other	29	63
Total current assets	962	1,347
PROPERTY, PLANT AND EQUIPMENT:
In service	7,443	7,057
Less — Accumulated provision for depreciation	6,123	5,929
Property, plant and equipment in service net of accumulated provision for depreciation	1,320	1,128
Construction work in progress	288	427
Total net property, plant and equipment	1,608	1,555
INVESTMENTS:
Nuclear plant decommissioning trusts	1,823	1,552
Other	9	10
Total other property and investments	1,832	1,562
DEFERRED CHARGES AND OTHER ASSETS:
Property taxes	6	40
Accumulated deferred income taxes	2,057	2,279
Derivatives	5	77
Other	369	381
Total deferred charges and other assets	2,437	2,777
Total assets	6,839	7,241
CURRENT LIABILITIES:
Currently payable long-term debt	267	179
Accounts payable-
Affiliated companies	230	550
Other	98	110
Accrued taxes	32	143
Derivatives	12	77
Other	167	156
Total current liabilities	992	1,316
Common stockholders’ equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of September 30, 2017 and December 31, 2016	3,748	3,658
Accumulated other comprehensive income	74	69
Accumulated deficit	(3,494)	(3,509)
Total common stockholders’ equity	328	218
Long-term debt and other long-term obligations	2,559	2,813
Total capitalization	2,887	3,031
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	732	757
Retirement benefits	207	197
Asset retirement obligations	988	901
Other	1,033	1,039
Total noncurrent liabilities	2,960	2,894
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 11)
Total liabilities and capitalization	6,839	7,241
FES | Affiliated Companies
CURRENT LIABILITIES:
Affiliated companies	$ 186	$ 101

Consolidated Balance Sheets (10

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Common stockholders’ equity-
Common stock, shares authorized	700,000,000	490,000,000
Common stock, shares outstanding	444,858,003	442,344,218
FES
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 3	$ 5
Common stockholders’ equity-
Common stock, shares authorized	750	750
Common stock, shares outstanding	7	7

Consolidated Statements of Ca11

Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$ 775	$ (381)
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs	1,248	1,477
Deferred costs on sale and leaseback transaction, net	37	36
Deferred income taxes and investment tax credits, net	453	318
Investment impairments	10	13
Pension trust contribution	0	(297)
Unrealized (gain) loss on derivative transactions (Note 8)	64	(10)
Lease payments on sale and leaseback transaction	(47)	(94)
Impairment of assets (Note 14)	162	1,447
Changes in current assets and liabilities-
Receivables	73	(34)
Materials and supplies	(6)	45
Prepaid taxes and other current assets	(41)	(28)
Accounts payable	(22)	(17)
Accrued taxes	(161)	(81)
Other current liabilities	13	53
Collateral, net	19	25
Other	156	107
Net cash provided from operating activities	2,762	2,592
New financing-
Long-term debt	4,050	521
Short-term borrowings, net	0	1,275
Redemptions and Repayments-
Long-term debt	(1,711)	(1,017)
Other	(67)	(17)
Net cash (used for) provided from financing activities	(381)	304
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,847)	(2,156)
Nuclear fuel	(156)	(195)
Sales of investment securities held in trusts	1,923	1,361
Purchases of investment securities held in trusts	(1,995)	(1,437)
Other	24	52
Net cash used for investing activities	(2,181)	(2,476)
Net change in cash and cash equivalents	200	420
Cash and cash equivalents at beginning of period	199	131
Cash and cash equivalents at end of period	399	551
FES
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	15	(267)
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs	245	485
Deferred costs on sale and leaseback transaction, net	37	36
Deferred income taxes and investment tax credits, net	156	90
Investment impairments	10	12
Pension trust contribution	0	(138)
Unrealized (gain) loss on derivative transactions (Note 8)	64	(10)
Lease payments on sale and leaseback transaction	(47)	(94)
Impairment of assets (Note 14)	0	540
Changes in current assets and liabilities-
Receivables	198	19
Materials and supplies	(24)	25
Prepaid taxes and other current assets	37	(3)
Accounts payable	(210)	(69)
Accrued taxes	(117)	(6)
Other current liabilities	(11)	13
Collateral, net	31	6
Other	74	(34)
Net cash provided from operating activities	458	605
New financing-
Long-term debt	0	471
Short-term borrowings, net	85	101
Redemptions and Repayments-
Long-term debt	(163)	(503)
Other	(5)	(8)
Net cash (used for) provided from financing activities	(83)	61
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(201)	(432)
Nuclear fuel	(156)	(195)
Sales of investment securities held in trusts	834	576
Purchases of investment securities held in trusts	(878)	(619)
Loans to affiliated companies, net	29	(15)
Other	(3)	19
Net cash used for investing activities	(375)	(666)
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
SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction: Affiliated net asset transfer (Note 9)	$ 73	$ 28

Organization and Basis of Prese

Organization and Basis of Presentation	9 Months Ended
	Sep. 30, 2017
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. FE 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 equity 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, MAIT and TrAIL), and AESC. In addition, FE holds all of the outstanding equity 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 over 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 24,500 miles of lines and two regional transmission operation centers. FES, a subsidiary of FE, was organized under the laws of the State of Ohio in 1997. FES provides energy-related products and services to retail and wholesale customers. FES also owns and operates, through its FG subsidiary, fossil generating facilities and owns, through its NG subsidiary, nuclear generating facilities, which are operated by FENOC. FES purchases the entire output of the generation facilities owned by FG and NG. Prior to April 1, 2016, FES financially purchased the uncommitted output of AE Supply's generation facilities under a PSA. On December 21, 2015, FES agreed, under a PSA, to physically purchase all the output of AE Supply's generation facilities effective April 1, 2016. FES and AE Supply terminated the PSA effective on April 1, 2017. FES complies with the regulations, orders, policies and practices prescribed by the SEC, FERC, NRC and applicable state regulatory authorities. 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, 2016 . 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 NRC, 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 6, "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 and Comprehensive Income. For each of the three months ended September 30, 2017 and 2016 , capitalized financing costs on FirstEnergy's Consolidated Statements of Income (Loss) include $8 million and $11 million , respectively, of allowance for equity funds used during construction and $11 million and $17 million , respectively, of capitalized interest. For each of the nine months ended September 30, 2017 and 2016 , capitalized financing costs on FirstEnergy's Consolidated Statements of Income (Loss) include $25 million and $28 million , respectively, of allowance for equity funds used during construction and $34 million and $51 million , respectively, of capitalized interest. During the third quarter of 2016, a reduction to depreciation expense of $21 million was recorded that related to prior periods ( $19 million prior to January 1, 2016). The out-of-period adjustment related to the utilization of an accelerated useful life for a component of a certain power station. Management determined this adjustment was not material to the third quarter of 2016 or any prior periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Strategic Review of Competitive Operations FirstEnergy believes having a combination of distribution, transmission and generation assets in a regulated or regulated-like construct is the best way to serve customers. FirstEnergy’s strategy is to be a fully regulated utility, focusing on stable and predictable earnings and cash flow from its regulated business units. Over the past several years, CES has been impacted by a decrease in demand and excess generation supply in the PJM Region, which has resulted in low power and capacity prices, as well as significant environmental compliance costs. To address this, CES sold or deactivated more than 6,770 MWs of competitive generation from 2012 to 2015 and announced in 2016 plans to exit and/or deactivate an additional 856 MWs by 2020 related to the Bay Shore Unit 1 generating station and Units 1-4 of the W.H. Sammis generating station. Additionally, CES has continued to focus on cost reductions, including those identified as part of FirstEnergy’s previously disclosed cash flow improvement plan. However, the energy and capacity markets remain weak with significantly low capacity clearing prices and current forward pricing as well as the long-term fundamental view on energy and capacity prices. In order to focus on stable and predictable cash flow from its regulated business units, in November of 2016, FirstEnergy announced a strategic review of its competitive operations with a target to implement its exit from competitive operations by mid-2018. In connection with this strategic review, AE Supply and AGC entered into an asset purchase agreement with a subsidiary of LS Power, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply's interest in the Buchanan Generating Facility and approximately 59% of AGC’s interest in Bath County ( 1,615 MWs of combined capacity) for an all-cash purchase price of $825 million , subject to adjustments. Closing of the transaction is subject to customary and other closing conditions including receipt of regulatory approvals from FERC and the VSCC, third party consents and the satisfaction and discharge of $305 million of AE Supply’s senior notes, which is expected to require the payment of a “make-whole” premium currently estimated to be approximately $100 million based on current interest rates, upon both (i) the consummation of the sale of the natural gas generating plants and (ii) either (a) the consummation of the sale of approximately 59% of AGC's interest in the Bath County hydroelectric power station or (b) the consummation of the pending sale of the Pleasants Power Station by AE Supply to its affiliate, MP, as discussed below. As a further condition to closing, FE will provide the purchaser two limited three -year guarantees of certain obligations of AE Supply and AGC arising under the amended and restated purchase agreement. The sale of the natural gas generating plants is expected to close in the fourth quarter of 2017 and the sale of approximately 59% of AGC’s interests in the Bath County hydroelectric power station and BU Energy’s 50% interest in the Buchanan Generating Facility are expected to close in the first quarter of 2018. For additional information see Note 14, "Asset Impairments." Additionally, AE Supply’s Pleasants power station ( 1,300 MWs) was selected in MP's RFP seeking additional generation capacity, and on March 6, 2017, MP and AE Supply signed an asset purchase agreement for MP to acquire the Pleasants power station for approximately $195 million , subject to customary and other closing conditions, including regulatory approvals as further discussed below in Note 10, "Regulatory Matters - State Regulation - West Virginia." The strategic options to exit the remaining portion of CES’ generation, which is primarily at FES, are still uncertain, but could include one or more of the following: • legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits; • restructuring FES debt with its creditors; • seeking protection under U.S. bankruptcy laws for FES and likely FENOC; and/or • additional asset sales and/or plant deactivations. Furthermore, the implementation of various strategic options, and the timing thereof, could be impacted by various events, including, but not limited to the following: • The outcome of efforts related to the NOPR released by the Secretary of Energy and action by FERC to address critical issues central to protecting the long-term reliability and resiliency of the electric grid provided by traditional baseload resources, such as coal and nuclear generation; • The resolution of legislation before the Ohio General Assembly that would create a zero-emission nuclear (ZEN) program that would provide compensation to nuclear power plants for their fuel diversity, environmental and other benefits and the potential for similar legislative action in Pennsylvania; and/or • The inability to finalize and consummate a settlement agreement with BNSF and NS regarding a previously disclosed long-term coal transportation contract dispute as discussed in Note 11, "Commitments, Guarantees and Contingencies - Environmental Matters" below, whereby FG could be subject to materially higher damages. Today, the competitive generation portfolio is comprised of more than 13,000 MWs of generation, primarily from coal, nuclear and natural gas and oil fuel sources. The assets can generate approximately 70 - 75 million MWHs annually, with up to an additional five million MWHs available from purchased power agreements for wind, solar, and CES' entitlement in OVEC, of which a portion is sold through various retail channels and the remainder targeting forward wholesale or spot sales. Subject to the completion of the AE Supply and AGC asset sale discussed above as well as the transfer of the Pleasants Power station to MP, the size and generation capacity of CES’ portfolio will be reduced to approximately 10,000 MWs, primarily at FES, with up to approximately 65 million MWHs produced annually. The competitive business continues to be managed conservatively due to the stress of weak energy prices, insufficient results from recent capacity auctions and anemic demand forecasts. Furthermore, the credit quality of CES, specifically FES' unsecured debt rating of Caa1 at Moody’s, CCC- at S&P and C at Fitch and a negative outlook from Moody's and S&P, has challenged its ability to hedge generation with retail and forward wholesale sales due to significant collateral requirements. As a result, CES' contract sales are expected to decline from 53 million MWHs in 2016 to 40 - 45 million MWHs in 2017 and to 30 - 35 million MWHs in 2018. While the reduced contract sales will decrease potential collateral requirements, market price volatility may significantly impact CES' financial results due to the increased exposure to the wholesale spot market. Going Concern at FES Although FES has access to a $500 million secured line of credit with FE, all of which was available as of September 30, 2017 , its current credit rating and the current forward wholesale pricing environment present significant challenges to FES. Furthermore, an inability to develop and execute upon viable alternative strategies for its competitive portfolio would continue to further stress the liquidity and financial condition of FES. Cash flow from operations at FES is expected to be sufficient to fund capital expenditures, nuclear fuel purchases, and repay money pool borrowings through March 2018. However, as previously disclosed, FES has $515 million of maturing debt in 2018, beginning in the second quarter. Additionally, FES has $48 million of interest and lease payments in December 2017 and $38 million of interest payments in the first quarter of 2018. Based on FES' current senior unsecured debt rating, capital structure and the forecasted decline in wholesale forward market prices over the next few years, the debt maturities are likely to be difficult to refinance. Furthermore, lack of clarity regarding the timing and viability of alternative strategies, including additional asset sales or deactivations and/or converting generation from competitive operations to a regulated or regulated-like construct in a way that provides FES with the means to satisfy its obligations over the long-term, may also require FES to restructure debt and other financial obligations with its creditors and/or seek protection under U.S. bankruptcy laws. In the event FES seeks protection under U.S. bankruptcy laws, FENOC will likely seek such protection. Although management is exploring capital and other cost reductions, asset sales, and other options to improve cash flow as well as continuing with efforts to explore legislative or regulatory solutions, these obligations and their impact to liquidity raise substantial doubt about FES’ ability to meet its obligations as they come due over the next twelve months and, as such, its ability to continue as a going concern. Goodwill FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. For 2017, 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. Key factors used in the assessment include: growth rates, interest rates, expected capital expenditures, utility sector market performance and other market considerations. 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. New Accounting Pronouncements Recently Adopted Pronouncements ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting" (Issued March 2016): ASU 2016-09 simplifies several aspects of the accounting for employee share-based payments. The new guidance requires all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also does not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. FirstEnergy adopted ASU 2016-09 on January 1, 2017. Upon adoption, FirstEnergy elected to account for forfeitures as they occur. The change was applied on a modified retrospective basis with a cumulative effect adjustment to retained earnings of approximately $6 million as of January 1, 2017. Additionally, FirstEnergy retrospectively applied the cash flow presentation requirement to present cash paid to tax authorities when shares are withheld to satisfy statutory tax withholding obligations as financing activities by reclassifying $12 million from operating activities to financing activities in the 2016 Consolidated Statement of Cash Flow. ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments" (Issued August 2016): The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments are presented and classified in the Consolidated Statements of Cash Flows, including the presentation of debt prepayment or debt extinguishment costs, all of which will be classified as financing activities. ASU 2016-15 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. FirstEnergy early adopted this ASU as of January 1, 2017. There was no impact to prior periods. Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below or in the 2016 Annual Report on Form 10-K based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. Below is an update to the discussion of pronouncements contained in the 2016 Annual Report on Form 10-K. ASU 2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to address implementation questions): For public business entities, the new revenue recognition guidance will be effective for annual and interim reporting periods beginning after December 15, 2017. FirstEnergy will not early adopt the standard. FirstEnergy has evaluated its revenues and expects limited impacts to current revenue recognition practices. FirstEnergy expects to apply the new guidance on a modified retrospective basis and continues to assess the impact on its financial statements and disclosures. ASU 2016-02, "Leases (Topic 842)" (Issued February 2016) : ASU 2016-02 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. ASU 2017-01, "Business Combinations: Clarifying the Definition of a Business" (Issued January 2017) : ASU 2017-01 assists entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. The ASU will be applied prospectively to any transactions occurring within the period of adoption. Early adoption is permitted, including for interim or annual periods in which the financial statements have not been issued or made available for issuance. ASU 2017-07, "Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" (Issued March 2017): ASU 2017-07 requires entities to retrospectively (1) disaggregate the current-service-cost component from the other components of net benefit cost (the “other components”) and present it with other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations if such a subtotal is presented. In addition, only service costs are eligible for capitalization on a prospective basis. Because the non-service cost components of net benefit cost will no longer be eligible for capitalization after December 31, 2017, FirstEnergy will recognize these components in income as a result of adopting the standard. FirstEnergy is currently evaluating presentation of the Statement of Income and the impact on disclosures as a result of adopting ASU 2017-07. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years.

Earnings (Loss) Per Share Of Co

Earnings (Loss) Per Share Of Common Stock	9 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
EARNINGS (LOSS) PER SHARE OF COMMON STOCK	EARNINGS (LOSS) 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. As discussed above, FirstEnergy adopted ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting" beginning January 1, 2017. For the three and nine months ended September 30, 2017, there were no material impacts to the basic or diluted earnings per share due to the new standard. The following table reconciles basic and diluted earnings (loss) 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 (Loss) per Share of Common Stock 2017 2016 2017 2016 Net income (loss) $ 396 $ 380 $ 775 $ (381 ) Weighted average number of basic shares outstanding 444 425 444 425 Assumed exercise of dilutive stock options and awards (1) 2 2 1 — Weighted average number of diluted shares outstanding 446 427 445 425 Basic earnings (loss) per share of common stock $ 0.89 $ 0.89 $ 1.75 $ (0.90 ) Diluted earnings (loss) per share of common stock $ 0.89 $ 0.89 $ 1.74 $ (0.90 ) (1) For both the three and nine months ended September 30 , 2017 , and the three months ended September 30, 2016, one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. 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.

Pension and Other Postemploymen

Pension and Other Postemployment Benefits	9 Months Ended
	Sep. 30, 2017
Retirement Benefits [Abstract]
PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS	PENSION AND OTHER POSTEMPLOYMENT BENEFITS The components of the consolidated net periodic costs (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 2017 2016 2017 2016 (In millions) Service costs $ 52 $ 48 $ 1 $ 2 Interest costs 97 99 7 7 Expected return on plan assets (112 ) (100 ) (7 ) (7 ) Amortization of prior service costs (credits) 2 2 (20 ) (20 ) Net periodic costs (credits) $ 39 $ 49 $ (19 ) $ (18 ) Components of Net Periodic Benefit Costs (Credits) Pension OPEB For the Nine Months Ended September 30 2017 2016 2017 2016 (In millions) Service costs $ 156 $ 144 $ 3 $ 4 Interest costs 291 298 21 22 Expected return on plan assets (336 ) (297 ) (22 ) (23 ) Amortization of prior service costs (credits) 6 6 (60 ) (60 ) Net periodic costs (credits) $ 117 $ 151 $ (58 ) $ (57 ) FES' share of the net periodic pension and OPEB costs (credits) were as follows: Pension OPEB 2017 2016 2017 2016 (In millions) For the Three Months Ended September 30 $ 3 $ 6 $ (4 ) $ (4 ) For the Nine Months Ended September 30 9 18 (12 ) (12 ) 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 2017 2016 2017 2016 (In millions) FirstEnergy $ 30 $ 35 $ (14 ) $ (11 ) FES 3 5 (4 ) (4 ) Net Periodic Benefit Expense (Credit) Pension OPEB For the Nine Months Ended September 30 2017 2016 2017 2016 (In millions) FirstEnergy $ 89 $ 107 $ (43 ) $ (41 ) FES 9 17 (12 ) (12 ) As of September 30, 2017, and December 31, 2016, FES had $866 million of affiliated non-current liabilities related to allocated pension and OPEB mark-to-market costs, of which $570 million was from FENOC.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	9 Months Ended
	Sep. 30, 2017
Equity [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, 2017 and 2016 , 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, 2017 $ (26 ) $ 61 $ 128 $ 163 Other comprehensive income before reclassifications — 27 — 27 Amounts reclassified from AOCI 4 (33 ) (19 ) (48 ) Other comprehensive income (loss) 4 (6 ) (19 ) (21 ) Income taxes (benefits) on other comprehensive income (loss) 1 (3 ) (7 ) (9 ) Other comprehensive income (loss), net of tax 3 (3 ) (12 ) (12 ) AOCI Balance as of September 30, 2017 $ (23 ) $ 58 $ 116 $ 151 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 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, 2017 $ (28 ) $ 52 $ 150 $ 174 Other comprehensive income before reclassifications — 63 — 63 Amounts reclassified from AOCI 8 (55 ) (55 ) (102 ) Other comprehensive income (loss) 8 8 (55 ) (39 ) Income taxes (benefits) on other comprehensive income (loss) 3 2 (21 ) (16 ) Other comprehensive income (loss), net of tax 5 6 (34 ) (23 ) AOCI Balance as of September 30, 2017 $ (23 ) $ 58 $ 116 $ 151 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 The following amounts were reclassified from AOCI for FirstEnergy in the three and nine months ended September 30, 2017 and 2016 : For the Three Months Ended September 30 For the Nine Months Ended September 30 Affected Line Item in the Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2017 2016 2017 2016 (In millions) Gains & losses on cash flow hedges Long-term debt $ 4 $ 2 $ 8 $ 6 Interest expense (1 ) — (3 ) (2 ) Income taxes $ 3 $ 2 $ 5 $ 4 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (33 ) $ (17 ) $ (55 ) $ (42 ) Investment income 12 7 20 16 Income taxes $ (21 ) $ (10 ) $ (35 ) $ (26 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (19 ) $ (18 ) $ (55 ) $ (54 ) (1) 7 7 21 21 Income taxes $ (12 ) $ (11 ) $ (34 ) $ (33 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, "Pension and Other Postemployment Benefits," for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. The changes in AOCI, net of tax, in the three and nine months ended September 30, 2017 and 2016 , 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, 2017 $ (9 ) $ 62 $ 26 $ 79 Other comprehensive income before reclassifications — 27 — 27 Amounts reclassified from AOCI 1 (33 ) (3 ) (35 ) Other comprehensive income (loss) 1 (6 ) (3 ) (8 ) Income tax benefits on other comprehensive income (loss) — (2 ) (1 ) (3 ) Other comprehensive income (loss), net of tax 1 (4 ) (2 ) (5 ) AOCI Balance as of September 30, 2017 $ (8 ) $ 58 $ 24 $ 74 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 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, 2017 $ (9 ) $ 48 $ 30 $ 69 Other comprehensive income before reclassifications — 70 — 70 Amounts reclassified from AOCI 1 (54 ) (10 ) (63 ) Other comprehensive income (loss) 1 16 (10 ) 7 Income taxes (benefits) on other comprehensive income (loss) — 6 (4 ) 2 Other comprehensive income (loss), net of tax 1 10 (6 ) 5 AOCI Balance as of September 30, 2017 $ (8 ) $ 58 $ 24 $ 74 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 The following amounts were reclassified from AOCI for FES in the three and nine months ended September 30, 2017 and 2016 : For the Three Months Ended September 30 For the Nine Months Ended September 30 Affected Line Item in the Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2017 2016 2017 2016 (In millions) Gains & losses on cash flow hedges Commodity contracts $ 1 $ 1 $ 1 $ — Other operating expenses — — — — Income taxes (benefits) $ 1 $ 1 $ 1 $ — Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (33 ) $ (17 ) $ (54 ) $ (41 ) Investment income 11 6 19 15 Income taxes (benefits) $ (22 ) $ (11 ) $ (35 ) $ (26 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (3 ) $ (3 ) $ (10 ) $ (10 ) (1) 1 1 4 4 Income taxes (benefits) $ (2 ) $ (2 ) $ (6 ) $ (6 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, "Pension and Other Postemployment Benefits," for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES FirstEnergy’s and FES’ interim effective tax rates reflect the estimated annual effective tax rates for 2017 and 2016 . 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, 2017 and 2016 was 37.6% and 39.8% , respectively. FirstEnergy’s effective tax rate for the nine months ended September 30, 2017 was 38.3% . For the nine months ended September 30, 2017, the change in the effective tax rate, as compared to the same period for 2016, is primarily due to the impairment of $800 million of goodwill recognized in 2016, of which $433 million was non-deductible for tax purposes. Additionally, $159 million of valuation allowances were recorded in 2016 against state and municipal NOL carryforwards that also impacted the 2016 effective tax rate. FES’ effective tax rate for the three months ended September 30, 2017 and 2016 was 29.6% and 58.3% , respectively. FES' effective tax rate for the nine months ended September 30, 2017 and 2016 was 48.3% and 1.8% , respectively. For the nine months ended September 30, 2017, the change in the effective tax rate was primarily due to $65 million of valuation allowance recognized in 2016 against state and local NOL carryforwards and the impairment of goodwill also recognized in 2016, of which $23 million was non-deductible for tax purposes. As of September 30, 2017 , it is reasonably possible that approximately $51 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 $ 26 million would affect FirstEnergy's effective tax rate. In August 2017 and February 2017, the IRS completed its examination of FirstEnergy's 2016 and 2015 federal income tax returns, respectively. The IRS has issued Full Acceptance Letters with no changes or adjustments to FirstEnergy's taxable income in either tax year.

Variable Interest Entities

Variable Interest Entities	9 Months Ended
	Sep. 30, 2017
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. 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): • Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly-owned limited liability company 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, 2017 and December 31, 2016 , $315 million and $339 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, which were paid in full at maturity on June 5, 2017. Additionally, 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 II and are collateralized by its equity and assets, which consist primarily of bondable transition property. As of September 30, 2017 and December 31, 2016 , $60 million and $85 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 limited liability company SPEs 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 limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of September 30, 2017 and December 31, 2016 , $383 million and $406 million of the environmental control bonds were outstanding, respectively. FES does not have any consolidated VIEs. 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 11, "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, a proposed transmission line from West Virginia through Virginia into Maryland which PJM cancelled in 2012, 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 12 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 contract that may contain a variable interest during the three months ended September 30, 2017 and 2016 were $29 million and $22 million , respectively, and $82 million and $78 million during the nine months ended September 30, 2017 and 2016 , respectively. • Sale and Leaseback Transactions - FES has obligations that are not included on its Consolidated Balance Sheet related to the 2007 Bruce Mansfield Unit 1 sale and leaseback arrangement, 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, 2017 , FES' leasehold interest was 93.83% of Bruce Mansfield Unit 1. FES is exposed to losses under the Bruce Mansfield Unit 1 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 FirstEnergy's net exposure to loss based upon the casualty value provisions as of September 30, 2017 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy (1) $ 1,095 $ 873 $ 222 (1) All amounts are associated with FES. On June 1, 2017, NG completed the purchase of the 2.60% lessor equity interests of the remaining non-affiliated leasehold interests in Beaver Valley Unit 2 for $38 million . In addition, the Beaver Valley Unit 2 leases expired in accordance with their terms on June 1, 2017, resulting in NG being the sole owner of Beaver Valley Unit 2. All debt obligations associated with those sale and leasebacks have been satisfied. Thereafter, OE and TE transferred their NDT assets and related AROs to NG associated with Beaver Valley Unit 2. See Note 9, "Asset Retirement Obligations," for additional information.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2017
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 8, "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 two 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, 2017 , from those used as of December 31, 2016 . 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, 2017 . 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, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,201 $ — $ 1,201 $ — $ 1,247 $ — $ 1,247 Derivative assets - commodity contracts — 35 — 35 10 200 — 210 Derivative assets - FTRs — — 5 5 — — 7 7 Derivative assets - NUG contracts (1) — — — — — — 1 1 Equity securities (2) 1,045 — — 1,045 925 — — 925 Foreign government debt securities — 92 — 92 — 78 — 78 U.S. government debt securities — 152 — 152 — 161 — 161 U.S. state debt securities — 274 — 274 — 246 — 246 Other (3) 399 152 — 551 199 123 — 322 Total assets $ 1,444 $ 1,906 $ 5 $ 3,355 $ 1,134 $ 2,055 $ 8 $ 3,197 Liabilities Derivative liabilities - commodity contracts $ — $ (12 ) $ — $ (12 ) $ (6 ) $ (118 ) $ — $ (124 ) Derivative liabilities - FTRs — — (2 ) (2 ) — — (6 ) (6 ) Derivative liabilities - NUG contracts (1) — — (92 ) (92 ) — — (108 ) (108 ) Total liabilities $ — $ (12 ) $ (94 ) $ (106 ) $ (6 ) $ (118 ) $ (114 ) $ (238 ) Net assets (liabilities) (4) $ 1,444 $ 1,894 $ (89 ) $ 3,249 $ 1,128 $ 1,937 $ (106 ) $ 2,959 (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 $(13) million and $(3) million as of September 30, 2017 and December 31, 2016 , 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, 2017 and December 31, 2016 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2016 Balance $ 1 $ (137 ) $ (136 ) $ 8 $ (13 ) $ (5 ) Unrealized gain (loss) 2 (17 ) (15 ) (6 ) (4 ) (10 ) Purchases — — — 16 (7 ) 9 Settlements (2 ) 46 44 (11 ) 18 7 December 31, 2016 Balance $ 1 $ (108 ) $ (107 ) $ 7 $ (6 ) $ 1 Unrealized loss — (14 ) (14 ) — (2 ) (2 ) Purchases — — — 5 (2 ) 3 Settlements (1 ) 30 29 (7 ) 8 1 September 30, 2017 Balance $ — $ (92 ) $ (92 ) $ 5 $ (2 ) $ 3 (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, 2017 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 3 Model RTO auction clearing prices $(5.00) to $4.60 $0.60 Dollars/MWH NUG Contracts $ (92 ) Model Generation 400 to 2,322,000 470,000 MWH Regional electricity prices $29.90 to $31.40 $29.90 Dollars/MWH FES Recurring Fair Value Measurements September 30, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 722 $ — $ 722 $ — $ 726 $ — $ 726 Derivative assets - commodity contracts — 35 — 35 10 200 — 210 Derivative assets - FTRs — — 1 1 — — 4 4 Equity securities (1) 765 — — 765 634 — — 634 Foreign government debt securities — 65 — 65 — 58 — 58 U.S. government debt securities — 138 — 138 — 48 — 48 U.S. state debt securities — 21 — 21 — 3 — 3 Other (2) 2 120 — 122 2 81 — 83 Total assets $ 767 $ 1,101 $ 1 $ 1,869 $ 646 $ 1,116 $ 4 $ 1,766 Liabilities Derivative liabilities - commodity contracts $ — $ (12 ) $ — $ (12 ) $ (6 ) $ (118 ) $ — $ (124 ) Derivative liabilities - FTRs — — (1 ) (1 ) — — (5 ) (5 ) Total liabilities $ — $ (12 ) $ (1 ) $ (13 ) $ (6 ) $ (118 ) $ (5 ) $ (129 ) Net assets (liabilities) (3) $ 767 $ 1,089 $ — $ 1,856 $ 640 $ 998 $ (1 ) $ 1,637 (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 $(8) million and $2 million as of September 30, 2017 and December 31, 2016 , respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table. Rollforward of Level 3 Measurements The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the periods ended September 30, 2017 and December 31, 2016 : Derivative Asset Derivative Liability Net Asset (Liability) (In millions) January 1, 2016 Balance $ 5 $ (11 ) $ (6 ) Unrealized loss (4 ) (3 ) (7 ) Purchases 10 (5 ) 5 Settlements (7 ) 14 7 December 31, 2016 Balance $ 4 $ (5 ) $ (1 ) Unrealized loss — (1 ) (1 ) Purchases 1 (1 ) — Settlements (4 ) 6 2 September 30, 2017 Balance $ 1 $ (1 ) $ — Level 3 Quantitative Information The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended September 30, 2017 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ — Model RTO auction clearing prices ($5.00) to $2.60 $0.20 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. During the second quarter of 2017, in connection with NG purchasing the lessor equity interests of the remaining non-affiliated leasehold interests from an owner participant in the Beaver Valley Unit 2 and the expiration of the leases, OE and TE transferred NDT assets of $189 million associated with their leasehold interests to NG. See Note 9, "Asset Retirement Obligations," for additional information. 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, 2017 and December 31, 2016 : September 30, 2017 (1) December 31, 2016 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,701 $ 42 $ 1,743 $ 1,735 $ 38 $ 1,773 FES 942 27 969 847 27 874 Equity securities FirstEnergy $ 927 $ 118 $ 1,045 $ 822 $ 103 $ 925 FES 675 90 765 564 70 634 (1) Excludes short-term cash investments: FirstEnergy - $100 million ; FES - $89 million . (2) Excludes short-term cash investments: FirstEnergy - $61 million ; FES - $44 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, 2017 and 2016 were as follows: For the Three Months Ended September 30, 2017 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 666 $ 93 $ (53 ) $ (3 ) $ 24 FES 397 73 (42 ) (3 ) 15 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 For the Nine Months Ended September 30, 2017 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 1,923 $ 276 $ (207 ) $ (10 ) $ 72 FES 834 206 (152 ) (10 ) 44 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 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, 2017 and December 31, 2016 are immaterial to FirstEnergy. Investments in employee benefit trusts and equity method investments totaling $255 million as of September 30, 2017 and $266 million as of December 31, 2016 , 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, which excludes capital lease obligations and net unamortized debt issuance costs, premiums and discounts: September 30, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 22,218 $ 22,994 $ 19,885 $ 19,829 FES 2,837 1,620 3,000 1,555 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, 2017 and December 31, 2016 .

Derivative Instruments

Derivative Instruments	9 Months Ended
	Sep. 30, 2017
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, 2017 and $12 million as of December 31, 2016 . Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $2 million of net unamortized losses is expected to be amortized to income during the next twelve months. FirstEnergy has used forward starting interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were designated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $27 million (FES $3 million ) and $33 million (FES $3 million ) as of September 30, 2017 and December 31, 2016 , 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 4, "Accumulated Other Comprehensive Income," for reclassifications from AOCI during the three and nine months ended September 30, 2017 and 2016 . As of September 30, 2017 and December 31, 2016 , 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, 2017 and December 31, 2016 , 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 $4 million and $10 million as of September 30, 2017 and December 31, 2016 , respectively. During the next twelve months, approximately $2 million of unamortized gains are expected to be amortized to interest expense. Amortization of unamortized gains included in long-term debt totaled approximately $1 million during the three months ended September 30, 2017 and $2 million during the three months ended September 30, 2016. Amortization of unamortized gains included in long-term debt totaled approximately $6 million during the nine months ended September 30, 2017 and $8 million during the nine months ended September 30, 2016. 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, 2017 , FirstEnergy’s net asset position under commodity derivative contracts was $23 million , which related to FES positions. Under these commodity derivative contracts, FES posted less than $1 million of collateral. Based on commodity derivative contracts held as of September 30, 2017 , an increase in commodity prices of 10% would decrease net income by approximately $6 million during the next twelve months. NUGs As of September 30, 2017 , FirstEnergy's net liability position under NUG contracts was $92 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, 2017 , FirstEnergy's net asset position associated with FTRs was $3 million and FES' net liability was less than $1 million . As of December 31, 2016, FirstEnergy's net asset position associated with FTRs was $1 million and FES' net liability was $1 million . 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 - Other Commodity Contracts $ 30 $ 133 Commodity Contracts $ (11 ) $ (72 ) FTRs 5 7 FTRs (2 ) (6 ) 35 140 (13 ) (78 ) Noncurrent Liabilities - Adverse Power Contract Liability NUGs (1) (92 ) (108 ) Deferred Charges and Other Assets - Other Noncurrent Liabilities - Other Commodity Contracts 5 77 Commodity Contracts (1 ) (52 ) NUGs (1) — 1 5 78 (93 ) (160 ) Derivative Assets $ 40 $ 218 Derivative Liabilities $ (106 ) $ (238 ) (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings. FES records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and classification of derivative instruments on FES' 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 $ 30 $ 133 Commodity Contracts $ (11 ) $ (72 ) FTRs 1 4 FTRs (1 ) (5 ) 31 137 (12 ) (77 ) Deferred Charges and Other Assets - Derivatives Noncurrent Liabilities - Other Commodity Contracts 5 77 Commodity Contracts (1 ) (52 ) 5 77 (1 ) (52 ) Derivative Assets $ 36 $ 214 Derivative Liabilities $ (13 ) $ (129 ) 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, 2017 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 35 $ (9 ) $ — $ 26 FTRs 5 (2 ) — 3 $ 40 $ (11 ) $ — $ 29 Derivative Liabilities Commodity contracts $ (12 ) $ 9 $ — $ (3 ) FTRs (2 ) 2 — — NUG contracts (92 ) — — (92 ) $ (106 ) $ 11 $ — $ (95 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2016 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 210 $ (117 ) $ — $ 93 FTRs 7 (6 ) — 1 NUG contracts 1 — — 1 $ 218 $ (123 ) $ — $ 95 Derivative Liabilities Commodity contracts $ (124 ) $ 117 $ 1 $ (6 ) FTRs (6 ) 6 — — NUG contracts (108 ) — — (108 ) $ (238 ) $ 123 $ 1 $ (114 ) The following tables summarize the fair value of derivative assets and derivative liabilities on FES’ Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet September 30, 2017 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 35 $ (9 ) $ — $ 26 FTRs 1 (1 ) — — $ 36 $ (10 ) $ — $ 26 Derivative Liabilities Commodity contracts $ (12 ) $ 9 $ — $ (3 ) FTRs (1 ) 1 — — $ (13 ) $ 10 $ — $ (3 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2016 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 210 $ (117 ) $ — $ 93 FTRs 4 (4 ) — — $ 214 $ (121 ) $ — $ 93 Derivative Liabilities Commodity contracts $ (124 ) $ 117 $ 1 $ (6 ) FTRs (5 ) 4 1 — $ (129 ) $ 121 $ 2 $ (6 ) The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of September 30, 2017 : Purchases Sales Net Units (In millions) Power Contracts 1 8 (7 ) MWH FTRs 14 — 14 MWH NUGs 2 — 2 MWH The following table summarizes the volumes associated with FES' outstanding derivative transactions as of September 30, 2017 : Purchases Sales Net Units (In millions) Power Contracts 1 8 (7 ) MWH FTRs 7 — 7 MWH The effect of active derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income (Loss) during the three and nine months ended September 30, 2017 and 2016 , are summarized in the following tables: For the Three Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2017 Unrealized Loss Recognized in: Other Operating Expense $ (11 ) $ — $ (11 ) Realized Gain (Loss) Reclassified to: Revenues $ 8 $ (1 ) $ 7 Purchased Power Expense (3 ) — (3 ) Other Operating Expense — (1 ) (1 ) For the Three Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ 19 $ (3 ) $ 16 Realized Gain (Loss) Reclassified to: Revenues $ 32 $ 1 $ 33 Purchased Power Expense (22 ) — (22 ) Other Operating Expense — (6 ) (6 ) Fuel Expense (2 ) — (2 ) For the Nine Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2017 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (65 ) $ 1 $ (64 ) Realized Gain (Loss) Reclassified to: Revenues $ 48 $ — $ 48 Purchased Power Expense (14 ) — (14 ) Other Operating Expense — (14 ) (14 ) Fuel Expense 5 — 5 For the Nine Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain Recognized in: Other Operating Expense $ 2 $ 8 $ 10 Realized Gain (Loss) Reclassified to: Revenues $ 162 $ 5 $ 167 Purchased Power Expense (105 ) — (105 ) Other Operating Expense — (28 ) (28 ) Fuel Expense (9 ) — (9 ) The effect of active derivative instruments not in a hedging relationship on FES' Consolidated Statements of Income (Loss) during the three and nine months ended September 30, 2017 and 2016 , are summarized in the following tables: For the Three Months Ended September 30 Commodity Contracts FTRs Total 2017 (In millions) Unrealized Loss Recognized in: Other Operating Expense $ (11 ) $ — $ (11 ) Realized Gain (Loss) Reclassified to: Revenues $ 8 $ (1 ) $ 7 Purchased Power Expense (3 ) — (3 ) Other Operating Expense — (1 ) (1 ) For the Three Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ 19 $ (3 ) $ 16 Realized Gain (Loss) Reclassified to: Revenues $ 32 $ 1 $ 33 Purchased Power Expense (22 ) — (22 ) Other Operating Expense — (6 ) (6 ) For the Nine Months Ended September 30 Commodity Contracts FTRs Total 2017 (In millions) Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (65 ) $ 1 $ (64 ) Realized Gain (Loss) Reclassified to: Revenues $ 48 $ — $ 48 Purchased Power Expense (14 ) — (14 ) Other Operating Expense — (14 ) (14 ) For the Nine Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain Recognized in: Other Operating Expense $ 2 $ 8 $ 10 Realized Gain (Loss) Reclassified to: Revenues $ 162 $ 5 $ 167 Purchased Power Expense (105 ) — (105 ) Other Operating Expense — (28 ) (28 ) 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, 2017 and 2016 . 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, 2017 $ (98 ) $ 3 $ (95 ) Unrealized loss (4 ) — (4 ) Settlements 10 — 10 Outstanding net asset (liability) as of September 30, 2017 $ (92 ) $ 3 $ (89 ) 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 ) 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, 2017 $ (107 ) $ 2 $ (105 ) Unrealized loss (14 ) (1 ) (15 ) Purchases — 3 3 Settlements 29 (1 ) 28 Outstanding net asset (liability) as of September 30, 2017 $ (92 ) $ 3 $ (89 ) 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 )

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2017
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. FirstEnergy and FES use an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs. The ARO liabilities for FES primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities, which aggregate to approximately $800 million and $713 million , as of September 30, 2017 and December 31, 2016, respectively. During the second quarter of 2017, in connection with NG purchasing the lessor equity interests of the remaining non-affiliated leasehold interests from an owner participant in the Beaver Valley Unit 2 sale leaseback and the expiration of the leases, OE and TE transferred an ARO of $49 million and NDT assets associated with their leasehold interests to NG, with the difference of $73 million credited to the common stock of FES. 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 the Perry Unit 1 sale leaseback, OE transferred the ARO and related NDT assets associated with the leasehold interest to NG, with the difference of $28 million credited to the common stock of FES.

Regulatory Matters

Regulatory Matters	9 Months Ended
	Sep. 30, 2017
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. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the goal of 0.97% savings achieved under PE's current plan for 2016, and increasing 0.2% per year thereafter to reach 2% . The Maryland legislature in April 2017 adopted a statute requiring the same 0.2% per year increase, up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. The costs of the 2015-2017 plan are expected to be approximately $70 million , of which approximately $56 million was incurred through September 30, 2017 . PE filed its 2018-2020 EmPOWER plan on August 31, 2017. The 2018-2020 plan continues and expands upon prior years' programs, and adds new programs, for a projected total cost of $116 million over the three-year period. The MDPSC will consider the 2018-2020 plan in hearings scheduled to begin on October 25, 2017, with a decision expected by December 31, 2017. PE recovers 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 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. 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 2013 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 2013 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, as well as 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 Maryland utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not yet issued a ruling on any of those matters. On September 26, 2016, the MDPSC initiated a new proceeding to consider an array of issues relating to electric distribution system design, including matters relating to electric vehicles, distributed energy resources, advanced metering infrastructure, energy storage, system planning, rate design, and impacts on low-income customers. Initial comments in the proceeding were filed on October 28, 2016, and the MDPSC held an initial hearing on the matter on December 8-9, 2016. On January 31, 2017, the MDPSC issued a notice establishing five working groups to address these issues over the following eighteen months, and also directed the retention of an outside consultant to prepare a report on costs and benefits of distributed solar generation in Maryland. 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. JCP&L currently operates under rates that were approved by the NJBPU on December 12, 2016, effective as of January 1, 2017. These rates provide an annual increase in operating revenues of approximately $80 million from those previously in place and are intended 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. In addition, on January 25, 2017, the NJBPU approved the acceleration of the amortization of JCP&L’s 2012 major storm expenses that are recovered through the SRC in order for JCP&L to achieve full recovery by December 31, 2019. 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 included 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, 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 Superior Court of New Jersey Appellate Division and JCP&L filed to participate as a respondent in that proceeding supporting the order. On September 18, 2017, the Superior Court of New Jersey Appellate Division reversed the NJBPU's Order on the basis that the NJBPU's modification of its CTA methodology did not comply with the procedures of the NJAPA. JCP&L's existing rates are not expected to be impacted by this order. On October 20, 2017, the NJBPU directed its staff to begin a formal rulemaking process to modify its CTA methodology. OHIO The Ohio Companies currently operate under ESP IV which commenced June 1, 2016 and expires May 31, 2024. The material terms of ESP IV, as approved in the PUCO’s Opinion and Order issued on March 31, 2016 and Fifth Entry on Rehearing on October 12, 2016, include 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 federal income 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. The PUCO set three conditions for continued recovery under 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. ESP IV also continues a base distribution rate freeze through May 31, 2024. In addition, ESP IV continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $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. Other material terms of ESP IV include: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (2) an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016 and remains pending); (3) a goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045; (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio; and (5) an agreement to file an application to transition to a straight fixed variable cost recovery mechanism for residential customers' base distribution rates (which filing was made on April 3, 2017 and remains pending). Several parties, including the Ohio Companies, filed applications for rehearing regarding the Ohio Companies’ ESP IV with the PUCO. The Ohio Companies’ application for rehearing challenged, among other things, the PUCO’s failure to adopt the Ohio Companies’ suggested modifications to Rider DMR. The Ohio Companies had previously suggested that a properly designed Rider DMR would be valued at $558 million annually for eight years, and include an additional amount that recognizes the value of the economic impact of FirstEnergy maintaining its headquarters in Ohio. Other parties’ applications for rehearing argued, among other things, that the PUCO’s adoption of Rider DMR is not supported by law or sufficient evidence. On August 16, 2017, the PUCO denied all remaining intervenor applications for rehearing, denied the Ohio Companies’ challenges to the modifications to Rider DMR and added a third-party monitor to ensure that Rider DMR funds are spent appropriately. On September 15, 2017, the Ohio Companies filed an application for rehearing of the PUCO’s August 16, 2017 ruling on the issues of the third-party monitor and the ROE calculation for advanced metering infrastructure. On October 11, 2017, the PUCO denied the Ohio Companies' application for rehearing on both issues. On October 16, 2017, the Sierra Club and the Ohio Manufacturer's Association Energy Group filed notices of appeal with the Supreme Court of Ohio appealing various PUCO entries on their applications for rehearing. For additional information, see “FERC Matters - Ohio ESP IV PPA” below. Under ORC 4928.66, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. Starting in 2017, ORC 4928.66 requires the energy savings benchmark to increase by 1% and the peak demand reduction benchmark to increase by 0.75% annually thereafter through 2020 and the energy savings benchmark to increase by 2% annually from 2021 through 2027, with a cumulative benchmark of 22.2% by 2027. 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 ORC 4928.66 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. On December 9, 2016, the Ohio Companies filed a Stipulation and Recommendation with several parties that contained changes to the plan and a decrease in the plan costs. The Ohio Companies anticipate the cost of the plans will be approximately $268 million over the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. The hearings were held in January 2017 . 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, except that in 2014 SB310 froze 2015 and 2016 at the 2014 level (2.5%), pushing back scheduled increases, which resumed in 2017 (3.5%), and increases 1% each year through 2026 (to 12.5%) and shall remain at 12.5% in 2027 and each year thereafter. 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. Oral argument on this matter was held on June 21, 2017. 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. On March 29, 2017, the PUCO issued a Second Entry on Rehearing that granted, in part, the applications for rehearing filed by FES and other parties, finding that the PUCO’s guidelines regarding fixed-price contracts should not apply to large mercantile customers. This finding changes the original order, which applied the guidelines to all customers, including mercantile customers. The PUCO also reaffirmed several provisions of the original order, including that the fixed-price guidelines only apply on a going-forward basis and not to existing contracts and that regulatory-out clauses in contracts are permissible. PENNSYLVANIA The Pennsylvania Companies operate under DSPs for the June 1, 2017 through May 31, 2019 delivery period, which 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 DSPs, the supply will 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. The DSPs include modifications to the Pennsylvania Companies’ POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges. The Pennsylvania Companies operate under rates that were approved by the PPUC on January 19, 2017, effective as of January 27, 2017. These rates provide annual increases in operating revenues of approximately $96 million at ME, $100 million at PN, $29 million at Penn, and $66 million at WP, and are intended to benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements. Pursuant to Pennsylvania's EE&C legislation in Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. 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, with expected costs up to $390 million , are designed to achieve the targets established in the PPUC's Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders. 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 February 11, 2016, the PPUC approved LTIIPs for each of the Pennsylvania Companies. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. The LTIIPs estimated costs for the five -year period of 2016 to 2020, as modified, are: WP $88.3 million ; PN $60.0 million ; Penn $58.9 million ; and ME $51.6 million . On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery, which were approved by the PPUC on June 9, 2016, and went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. On January 19, 2017, in the PPUC’s order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016, which is pending PPUC approval. The ADIT issue is subject to further litigation and a hearing was held on May 12, 2017. On August 31, 2017, the ALJ issued a decision recommending that the complaint of the Pennsylvania Office of Consumer Advocate be granted by the PPUC such that the Pennsylvania Companies reflect all federal and state income tax deductions related to DSIC-eligible property in the currently effective DSIC rates. If the decision is approved by the PPUC, the impact is not expected to be material to FirstEnergy . The Pennsylvania Companies filed exceptions to the decision on September 20, 2017, and reply exceptions on October 2, 2017. 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. On September 23, 2016, the WVPSC approved the Phase II energy efficiency program for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, which includes three energy efficiency programs to meet the Phase II requirement of energy efficiency reductions of 0.5% of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, which was approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of Harrison Power Station to MP. The costs for the Phase II program are expected to be $10.4 million and are eligible for recovery through the existing energy efficiency rider which is reviewed in the fuel (ENEC) case each year. On October 6, 2017, MP and PE proposed an annual decrease in their EE&C rates, effective January 1, 2018, which is not expected to be material to FirstEnergy. On December 9, 2016, the WVPSC approved the annual ENEC case for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, resulting in an increase in the ENEC rate of $25 million annually beginning January 1, 2017. In addition, ENEC rates will be maintained at the same level for a two -year period. On December 30, 2015, MP and PE filed an IRP with the WVPSC identifying a capacity shortfall starting in 2016 and exceeding 700 MWs by 2020 and 850 MWs by 2027. On June 3, 2016, the WVPSC accepted the IRP. On December 16, 2016, MP issued an RFP to address its generation shortfall, along with issuing a second RFP to sell its interest in Bath County. Bids were received by an independent evaluator in February 2017 for both RFPs. AE Supply was the winning bidder of the RFP to address MP’s generation shortfall and on March 6, 2017, MP and AE Supply signed an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station ( 1,300 MW) for approximately $195 million , subject to customary and other closing conditions, including regulatory approvals . In addition, on March 7, 2017, MP and PE filed an application with the WVPSC and MP and AE Supply filed an application with FERC requesting authorization for such purchase. The WVPSC held an evidentiary hearing commencing on September 26, 2017, and public hearings were held on September 6, 11, and 12, 2017. An order is anticipated by early 2018. On June 27, 2017, FERC issued a deficiency letter requesting additional information to facilitate FERC’s review of the transaction. MP responded to the deficiency letter on July 18, 2017, and to related protests and comments on August 28, 2017. The applications remain pending before the WVPSC and FERC, respectively. With respect to the Bath County RFP, MP does not plan to move forward with that sale of its ownership interest. In the future, MP may re-evaluate its options with respect to its interest in Bath County. On September 1, 2017, MP and PE filed with the WVPSC for a reconciliation of their VMS to confirm that rate recovery matches VMP costs and for a regular review of that program. MP and PE proposed a $15 million annual decrease in VMS rates effective January 1, 2018, and an additional $15 million decrease in rates for 2019. This is an overall decrease in total revenue and average rates of 1% . RELIABILITY MATTERS Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES and certain of its subsidiaries, AE Supply, FENOC, ATSI, MAIT and TrAIL. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC. FirstEnergy, including FES, believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy, including FES, occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy, including FES, develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy's, including FES, part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, and obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations and cash flows. FERC MATTERS Ohio ESP IV PPA On August 4, 2014, the Ohio Companies filed an application with the PUCO seeking approval of their ESP IV. 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 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, but subsequently agreed to suspend it and advised FERC of this course of action. 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. On January 9, 2017, the generation owners filed to amend their complaint to include challenges to certain legislation and regulatory programs in Illinois. On January 24, 2017, FESC, acting on behalf of its affected affiliates and along with other utility companies, filed a motion to dismiss the amended complaint for various reasons, including that the ESP IV PPA matter is now moot. In addition, on January 30, 2017, FESC along with other utility companies filed a substantive protest to the amended complaint, demonstrating that the question of the proper role for state participation in generation development should be addressed in the PJM stakeholder process. On August 30, 2017, the generation owners requested expedited action by FERC. This proceeding remains pending before FERC. PJM Transmission Rates PJM and its stakeholders have been debating the proper method to allocate costs for certain transmission facilities. While FirstEnergy and other parties advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM. This question has been the subject of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit. On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines. The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole. The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings. On June 15, 2016, various parties, including ATSI and the Utilities, filed a settlement agreement at FERC agreeing to apply a combined usage based/socialization approach to cost allocation for charges to transmission customers in the PJM Region for transmission projects operating at or above 500 kV. Certain other parties in the proceeding did not agree to the settlement and filed protests to the settlement seeking, among other issues, to strike certain of the evidence advanced by FirstEnergy and certain of the other settling parties in support of the settlement, as well as provided further comments in opposition to the settlement. FirstEnergy and certain of the other parties responded to such opposition. The settlement is pending before FERC. RTO Realignment On June 1, 2011, ATSI and the ATSI zone transferred from MISO to PJM. While many of the matters involved with the move have been resolved, FERC denied recovery under ATSI's transmission rate for certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation charges totaling approximately $78.8 million until such time as ATSI submits a cost/benefit analysis demonstrating net benefits to customers from the transfer to PJM. Subsequently, FERC rejected a proposed settlement agreement to resolve the exit fee and transmission cost allocation issues, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. On March 17, 2016, FERC denied FirstEnergy's request for rehearing of FERC's earlier order rejecting the settlement agreement and affirmed its prior ruling that ATSI must submit the cost/benefit analysis. Separately, ATSI

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	9 Months Ended
	Sep. 30, 2017
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, 2017 , FirstEnergy's outstanding guarantees and other assurances aggregated approximately $3.3 billion , consisting of parental guarantees ( $649 million ), subsidiaries' guarantees ( $1.9 billion ), other guarantees ( $300 million ) and other assurances ( $457 million ). Of the 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 CES' power portfolio exposure as of September 30, 2017 , FES has posted collateral of $128 million and AE Supply has posted collateral of $2 million . The Regulated Distribution Segment has posted collateral of $3 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. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of September 30, 2017. Potential Collateral Obligations FES AE Supply Regulated FE Corp Total (In millions) Contractual Obligations for Additional Collateral At Current Credit Rating $ 6 $ 2 $ — $ — $ 8 Upon Further Downgrade — — 42 — 42 Surety Bonds (Collateralized Amount) (1) 48 24 105 185 362 Total Exposure from Contractual Obligations $ 54 $ 26 $ 147 $ 185 $ 412 (1) Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for $169 million of FG surety bonds for the benefit of the PA DEP with respect to LBR. 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, 2017 , FES has $2 million of collateral posted with its 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. Pursuant to a March 28, 2017 executive order, the EPA and other federal agencies are to review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise, or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof, in particular with respect to existing environmental regulations, may impact its business, results of operations, cash flows and financial condition. 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. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry's bid for a lengthy pause in the litigation and set a briefing schedule. Depending on the outcome of the appeals, EPA’s reconsideration of the CSAPR update rule and how EPA and the states ultimately implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's and FES' operations may result. The EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015. The 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 the EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017. The EPA missed the October 1, 2017 deadline and has not yet promulgated the attainment designations. 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, the EPA extended the time frame for acting on the State Delaware's CAA Section 126 petition by six months to April 7, 2017 but has not taken any further action. In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3, Mansfield Unit 1 and Pleasants Units 1 and 2, significantly contribute to Maryland's inability to attain the ozone NAAQS. The petition seeks NOx emission rate limits for the 36 EGUs by May 1, 2017. On January 3, 2017, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to July 15, 2017 but has not taken any further action. On September 27, 2017 and October 4, 2017, the State of Maryland and various environmental organizations filed complaints in the U.S. District Court for the District of Maryland seeking an order that EPA either approve or deny the CAA Section 126 petition of November 16, 2016. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss. MATS imposed 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. The majority of FirstEnergy's MATS compliance program and related costs have been completed. On August 3, 2015, FG, a wholly owned 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 arose 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. 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 consolidated the claims and held a hearing in November and December 2016. On April 12, 2017, the arbitration panel ruled on liability in favor of BNSF and CSX. In the liability award, the panel found, among other things, that FG’s demand for declaratory judgment that force majeure excused FG’s performance was denied, that FG breached and repudiated the coal transportation contract and that the panel retains jurisdiction of claims for liquidated damages for the years 2015-2025. On May 1, 2017, FE and FG and CSX and BNSF entered into a definitive settlement agreement, which resolved all claims related to this consolidated proceeding on the terms and conditions set forth below. Pursuant to the settlement agreement, FG will pay CSX and BNSF an aggregate amount equal to $109 million which is payable in three annual installments, the first of which was made on May 1, 2017. FE agreed to unconditionally and continually guarantee the settlement payments due by FG pursuant to the terms of the settlement agreement. The settlement agreement further provides that in the event of the initiation of bankruptcy proceedings or failure to make timely settlement payments, the unpaid settlement amount will immediately accelerate and become due and payable in full. Further, FE and FG, and CSX and BNSF, agreed to release, waive and discharge each other from any further obligations under the claims covered by the settlement agreement upon payment in full of the settlement amount. Until such time, CSX and BNSF will retain the claims covered by the settlement agreement and in the event of a bankruptcy proceeding with respect to FG, to the extent the remaining settlement payments are not paid in full by FG or FE, CSX and BNSF shall be entitled to seek damages for such claims in an amount to be determined by the arbitration panel or otherwise agreed by the parties. On December 22, 2016, FG, a wholly owned subsidiary of FES, received a demand for arbitration and statement of claim from BNSF and NS, which are the counterparties to the coal transportation contract covering the delivery of 2.5 million tons annually through 2025, for FG’s coal-fired Bay Shore Units 2-4, deactivated on September 1, 2012, as a result of the EPA’s MATS and for FG’s W.H. Sammis generating station. The demand for arbitration was submitted to the AAA office in Washington, D.C. against FG alleging, among other things, that FG breached the agreement in 2015 and 2016 and repudiated the agreement for 2017-2025. The counterparties are seeking, among other things, damages, including lost profits through 2025, and a declaratory judgment that FG's claim of force majeure is invalid. The arbitration hearing is scheduled for June 2018. The parties have exchanged settlement proposals to resolve all claims related to this proceeding and all remaining claims. FirstEnergy and FES recorded a pre-tax charge of $55 million in the first quarter of 2017 based on an estimated settlement. If the dispute with BNSF and NS is not settled, the amount of damages owed to BNSF and NS could be materially higher and may cause FES to seek protection under U.S. bankruptcy laws. Absent a settlement, FG intends to vigorously assert its position in this arbitration proceeding, and if it were ultimately determined that the force majeure provisions or other defenses do not excuse the delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. As to a specific coal supply agreement, AE Supply, the party thereto, asserted termination rights effective in 2015 as a result of MATS. In response to notification of the termination, on January 15, 2015, Tunnel Ridge, LLC, the coal supplier, commenced litigation in the Court of Common Pleas of Allegheny County, Pennsylvania alleging AE Supply did not have sufficient justification to terminate the agreement and seeking damages for the difference between the market and contract price of the coal, or lost profits plus incidental damages. AE Supply filed an answer denying any liability related to the termination. On May 1, 2017, the complaint was amended to add FE, FES and FG, although not parties to the underlying contract, as defendants and to seek additional damages based on new claims of fraud, unjust enrichment, promissory estoppel and alter ego. On June 27, 2017, after oral argument, defendants' preliminary objections to the amended complaint were denied. FE, FES, FG and AE Supply believe the merits of this case are distinguishable from the rail arbitration proceedings above based on the contract terms and other elements of the case. There were approximately 5.5 million tons remaining under the contract for delivery. This matter is in the discovery phase of litigation and no trial date has been established. FE, FES, FG and AE Supply dispute the allegations and intend to vigorously defend the merits of the lawsuit. At this time, FE, FES, FG and AE Supply cannot estimate the loss or range of loss regarding the ongoing litigation with respect to this agreement. Damages, if any, are yet to be determined, but an adverse outcome could be material. 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, 2016, 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. On June 23, 2014, the U.S. 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. The EPA released its final CPP 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. 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, 2016, 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 . On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. Depending on the outcomes of the review pursuant to the executive order, 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 GHG 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 became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. 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 material. 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 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. On April 13, 2017, the EPA granted a Petition for Reconsideration and administratively stayed (effective upon publication in the Federal Register) all deadlines in the effluent limits rule pending a new rulemaking. Also, on September 18, 2017, the EPA postponed certain compliance deadlines for two years. 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 April 2015, 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. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. 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 not currently expected, any changes in timing and closure plan requirements in the future, including changes resulting from the strategic review at CES, 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 CCRs from the Bruce Mansfield plant are being beneficially reused with the majority used for reclamation of a site owned by the Marshall County Coal Company in Moundsville, W. Va. and the remainder recycled into drywall by National Gypsum. These beneficial reuse options should be sufficient for ongoing plant operations, however, the Bruce Mansfield plant is pursuing other options. 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 September 14, 2017, the Sierra Club's Notices of Appeal before the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility were resolved through a Consent Adjudication between FG, PA DEP and the Sierra Club requiring operational changes, which is subject to a thirty-day comment period with final approval expected in November 2017 . 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, 2017 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 $131 million have been accrued through September 30, 2017 . Included in the total are accrued liabilities of approximately $84 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, 2017 , FirstEnergy had approximately $2.6 billion (FES $1.8 billion ) invested in external trusts to be used for the decommissioning and environmental remediation of its nuclear generating facilities. The values of FirstEnergy's NDTs also 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. 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 po

Supplemental Guarantor Informat

Supplemental Guarantor Information	9 Months Ended
	Sep. 30, 2017
Supplemental Guarantor Information [Abstract]
SUPPLEMENTAL GUARANTOR INFORMATION	SUPPLEMENTAL GUARANTOR INFORMATION In 2007, FG, a 100% owned subsidiary of FES, completed a sale and leaseback transaction for a 93.83% undivided interest in Bruce Mansfield Unit 1. FG's parent company, FES, has fully and unconditionally and irrevocably guaranteed all of FG's obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by 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, 2017 and 2016 , Condensed Consolidating Balance Sheets as of September 30, 2017 and December 31, 2016 , and Condensed Consolidating Statements of Cash Flows for the nine months ended September 30, 2017 and 2016 , 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, 2017 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 741 $ 231 $ 292 $ (521 ) $ 743 OPERATING EXPENSES: Fuel — 108 57 — 165 Purchased power from affiliates 520 — 1 (521 ) — Purchased power from non-affiliates 152 — — — 152 Other operating expenses 70 62 147 12 291 Provision for depreciation 3 8 18 (1 ) 28 General taxes 4 3 (2 ) — 5 Total operating expenses 749 181 221 (510 ) 641 OPERATING INCOME (LOSS) (8 ) 50 71 (11 ) 102 OTHER INCOME (EXPENSE): Investment income (loss), including net income from equity investees 106 11 43 (121 ) 39 Miscellaneous income 1 — — — 1 Interest expense — affiliates (20 ) (3 ) 1 16 (6 ) Interest expense — other (12 ) (25 ) (11 ) 14 (34 ) Capitalized interest — — 6 — 6 Total other income (expense) 75 (17 ) 39 (91 ) 6 INCOME BEFORE INCOME TAXES (BENEFITS) 67 33 110 (102 ) 108 INCOME TAXES (BENEFITS) (9 ) 6 34 1 32 NET INCOME $ 76 $ 27 $ 76 $ (103 ) $ 76 STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME $ 76 $ 27 $ 76 $ (103 ) $ 76 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 (6 ) — (6 ) 6 (6 ) Other comprehensive loss (8 ) (3 ) (6 ) 9 (8 ) Income tax benefits on other comprehensive loss (3 ) (1 ) (2 ) 3 (3 ) Other comprehensive loss, net of tax (5 ) (2 ) (4 ) 6 (5 ) COMPREHENSIVE INCOME $ 71 $ 25 $ 72 $ (97 ) $ 71 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Nine Months Ended September 30, 2017 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 2,338 $ 941 $ 988 $ (1,869 ) $ 2,398 OPERATING EXPENSES: Fuel — 312 151 — 463 Purchased power from affiliates 1,994 — 77 (1,869 ) 202 Purchased power from non-affiliates 468 — — — 468 Other operating expenses 247 345 467 36 1,095 Provision for depreciation 9 24 49 (2 ) 80 General taxes 15 16 13 — 44 Total operating expenses 2,733 697 757 (1,835 ) 2,352 OPERATING INCOME (LOSS) (395 ) 244 231 (34 ) 46 OTHER INCOME (EXPENSE): Investment income (loss), including net income (loss) from equity investees 335 31 91 (383 ) 74 Miscellaneous income 1 — 5 — 6 Interest expense — affiliates (58 ) (9 ) (1 ) 55 (13 ) Interest expense — other (35 ) (78 ) (33 ) 42 (104 ) Capitalized interest — 1 19 — 20 Total other income (expense) 243 (55 ) 81 (286 ) (17 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (152 ) 189 312 (320 ) 29 INCOME TAXES (BENEFITS) (167 ) 66 112 3 14 NET INCOME $ 15 $ 123 $ 200 $ (323 ) $ 15 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 15 $ 123 $ 200 $ (323 ) $ 15 OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (10 ) (10 ) — 10 (10 ) Amortized gains on derivative hedges 1 — — — 1 Change in unrealized gains on available-for-sale securities 16 — 16 (16 ) 16 Other comprehensive income (loss) 7 (10 ) 16 (6 ) 7 Income taxes (benefits) on other comprehensive income (loss) 2 (4 ) 6 (2 ) 2 Other comprehensive income (loss), net of tax 5 (6 ) 10 (4 ) 5 COMPREHENSIVE INCOME $ 20 $ 117 $ 210 $ (327 ) $ 20 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) Pension 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 BALANCE SHEETS As of September 30, 2017 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 171 — — — 171 Affiliated companies 194 175 193 (235 ) 327 Other 9 4 — — 13 Notes receivable from affiliated companies 364 1,765 1,481 (3,610 ) — Materials and supplies 34 147 82 — 263 Derivatives 31 — — — 31 Collateral 101 25 — — 126 Prepaid taxes and other 12 16 1 — 29 916 2,134 1,757 (3,845 ) 962 PROPERTY, PLANT AND EQUIPMENT: In service 121 2,587 5,016 (281 ) 7,443 Less — Accumulated provision for depreciation 61 1,942 4,309 (189 ) 6,123 60 645 707 (92 ) 1,320 Construction work in progress 2 45 241 — 288 62 690 948 (92 ) 1,608 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,823 — 1,823 Investment in affiliated companies 3,347 — — (3,347 ) — Other — 9 — — 9 3,347 9 1,823 (3,347 ) 1,832 DEFERRED CHARGES AND OTHER ASSETS: Property taxes — 2 4 — 6 Accumulated deferred income tax benefits 428 1,212 690 (273 ) 2,057 Derivatives 5 — — — 5 Other 31 328 — 10 369 464 1,542 694 (263 ) 2,437 $ 4,789 $ 4,375 $ 5,222 $ (7,547 ) $ 6,839 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 180 $ 114 $ (27 ) $ 267 Short-term borrowings - affiliated companies 3,299 497 — (3,610 ) 186 Accounts payable- Affiliated companies 329 87 143 (329 ) 230 Other 11 87 — — 98 Accrued taxes 16 12 19 (15 ) 32 Derivatives 10 2 — — 12 Other 28 92 14 33 167 3,693 957 290 (3,948 ) 992 CAPITALIZATION: Total equity 328 946 2,301 (3,247 ) 328 Long-term debt and other long-term obligations 691 1,941 1,006 (1,079 ) 2,559 1,019 2,887 3,307 (4,326 ) 2,887 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 732 732 Accumulated deferred income taxes 5 — — (5 ) — Retirement benefits 26 181 — — 207 Asset retirement obligations — 187 801 — 988 Other 46 163 824 — 1,033 77 531 1,625 727 2,960 $ 4,789 $ 4,375 $ 5,222 $ (7,547 ) $ 6,839 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2016 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 213 — — — 213 Affiliated companies 332 315 417 (612 ) 452 Other 17 2 8 — 27 Notes receivable from affiliated companies 501 1,585 1,294 (3,351 ) 29 Materials and supplies 45 142 80 — 267 Derivatives 137 — — — 137 Collateral 157 — — — 157 Prepaid taxes and other 38 24 1 — 63 1,440 2,070 1,800 (3,963 ) 1,347 PROPERTY, PLANT AND EQUIPMENT: In service 120 2,524 4,703 (290 ) 7,057 Less — Accumulated provision for depreciation 52 1,920 4,144 (187 ) 5,929 68 604 559 (103 ) 1,128 Construction work in progress 2 67 358 — 427 70 671 917 (103 ) 1,555 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,552 — 1,552 Investment in affiliated companies 2,923 — — (2,923 ) — Other — 9 1 — 10 2,923 9 1,553 (2,923 ) 1,562 DEFERRED CHARGES AND OTHER ASSETS: Property taxes — 12 28 — 40 Accumulated deferred income tax benefits 395 1,271 883 (270 ) 2,279 Derivatives 77 — — — 77 Other 33 327 — 21 381 505 1,610 911 (249 ) 2,777 $ 4,938 $ 4,360 $ 5,181 $ (7,238 ) $ 7,241 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 200 $ 5 $ (26 ) $ 179 Short-term borrowings - affiliated companies 2,969 483 — (3,351 ) 101 Accounts payable- Affiliated companies 743 107 406 (706 ) 550 Other 17 93 — — 110 Accrued taxes 50 48 61 (16 ) 143 Derivatives 71 6 — — 77 Other 56 54 10 36 156 3,906 991 482 (4,063 ) 1,316 CAPITALIZATION: Total equity 218 828 2,006 (2,834 ) 218 Long-term debt and other long-term obligations 691 2,093 1,120 (1,091 ) 2,813 909 2,921 3,126 (3,925 ) 3,031 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 757 757 Accumulated deferred income taxes 4 3 — (7 ) — Retirement benefits 25 172 — — 197 Asset retirement obligations — 188 713 — 901 Other 94 85 860 — 1,039 123 448 1,573 750 2,894 $ 4,938 $ 4,360 $ 5,181 $ (7,238 ) $ 7,241 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Nine Months Ended September 30, 2017 FES FG NG Eliminations Consolidated (In millions) NET CASH (USED FOR) PROVIDED FROM OPERATING ACTIVITIES $ (463 ) $ 387 $ 547 $ (13 ) $ 458 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 330 14 — (259 ) 85 Redemptions and Repayments- Long-term debt — (171 ) (5 ) 13 (163 ) Other — (5 ) — — (5 ) Net cash (used for) provided from financing activities 330 (162 ) (5 ) (246 ) (83 ) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (1 ) (46 ) (154 ) — (201 ) Nuclear fuel — — (156 ) — (156 ) Sales of investment securities held in trusts — — 834 — 834 Purchases of investment securities held in trusts — — (878 ) — (878 ) Loans to affiliated companies, net 137 (179 ) (188 ) 259 29 Other (3 ) — — — (3 ) Net cash (used for) provided from investing activities 133 (225 ) (542 ) 259 (375 ) 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, 2016 FES FG NG Eliminations Consolidated (In millions) NET CASH (USED FOR) PROVIDED FROM OPERATING ACTIVITIES $ (605 ) $ 402 $ 820 $ (12 ) $ 605 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 — (6 ) (2 ) — (8 ) Net cash (used for) provided from financing activities 701 61 (21 ) (680 ) 61 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 ) Loans to affiliated companies, net (87 ) (292 ) (328 ) 692 (15 ) Other 19 — — — 19 Net cash (used for) provided from 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

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2017
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, MAIT (effective January 31, 2017) and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP). The segment's revenues are primarily derived from forward-looking rates at ATSI and TrAIL, as well as stated transmission rates at certain of FirstEnergy’s utilities. As discussed in Note 10, "Regulatory Matters - FERC Matters" above, MAIT and JCP&L submitted applications to FERC requesting authorization to implement forward-looking formula transmission rates. In March 2017, FERC approved JCP&L's and MAIT's forward-looking formula rate with effective dates of June 1, 2017, and July 1, 2017, respectively, both subject to refund pending the outcome of settlement and hearing proceedings and a final order by FERC. Both the forward-looking and stated rates recover costs and provide a return on transmission capital investment. Under forward-looking rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. 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, 2017, this business segment controlled 13,162 MWs of electric generating capacity , including, as discussed in Note 14, "Asset Impairments," 1,615 MWs of natural gas and hydroelectric generating capacity subject to an asset purchase agreement with a subsidiary of LS Power and the 1,300 MW Pleasants power station subject to an asset purchase agreement with MP resulting from MP's RFP process to address its generation shortfall, as discussed in Note 10, "Regulatory Matters - State Regulation - West Virginia." The CES segment’s operating results are 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 not charged to FE's subsidiaries, interest expense on stand-alone holding company debt, corporate income taxes and other businesses that do not constitute an operating segment 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, 2017, Corporate/Other had $6.8 billion of stand-alone holding company long-term debt, of which $1.45 billion was subject to variable-interest rates, and $500 million 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, 2017 External revenues $ 2,610 $ 342 $ 796 $ — $ (34 ) $ 3,714 Internal revenues — — 93 — (93 ) — Total revenues 2,610 342 889 — (127 ) 3,714 Depreciation 183 59 30 17 — 289 Amortization of regulatory assets, net 85 6 — — — 91 Impairment of assets (Note 14) — 13 18 — — 31 Investment income 13 — 34 3 (13 ) 37 Interest expense 133 38 44 90 — 305 Income taxes (benefits) 183 49 40 (33 ) — 239 Net income (loss) 314 84 66 (68 ) — 396 Total assets 27,866 9,356 5,814 613 — 43,649 Total goodwill 5,004 614 — — — 5,618 Property additions 286 248 45 14 — 593 September 30, 2016 External revenues $ 2,691 $ 294 $ 998 $ — $ (66 ) $ 3,917 Internal revenues — — 117 — (117 ) — Total revenues 2,691 294 1,115 — (183 ) 3,917 Depreciation 169 47 79 16 — 311 Amortization of regulatory assets, net 98 — — — — 98 Investment income 13 — 23 2 (10 ) 28 Interest expense 143 39 48 56 — 286 Income taxes (benefits) 162 50 49 (10 ) — 251 Net income (loss) 276 85 86 (67 ) — 380 Total assets 27,818 8,492 15,165 486 — 51,961 Total goodwill 5,004 614 — — — 5,618 Property additions 281 268 110 5 — 664 For the Nine Months Ended September 30, 2017 External revenues $ 7,362 $ 982 $ 2,388 $ — $ (157 ) $ 10,575 Internal revenues — — 296 — (296 ) — Total revenues 7,362 982 2,684 — (453 ) 10,575 Depreciation 540 164 87 54 — 845 Amortization of regulatory assets, net 204 11 — — — 215 Impairment of assets (Note 14) — 13 149 — — 162 Investment income 41 — 66 8 (37 ) 78 Interest expense 405 116 136 225 — 882 Income taxes (benefits) 442 154 (25 ) (89 ) — 482 Net income (loss) 756 264 (57 ) (188 ) — 775 Property additions 854 717 233 43 — 1,847 September 30, 2016 External revenues $ 7,390 $ 851 $ 3,158 $ — $ (212 ) $ 11,187 Internal revenues — — 377 — (377 ) — Total revenues 7,390 851 3,535 — (589 ) 11,187 Depreciation 504 138 284 48 — 974 Amortization of regulatory assets, net 218 4 — — — 222 Impairment of assets (Note 14) — — 1,447 — — 1,447 Investment income 37 — 56 13 (31 ) 75 Interest expense 441 118 143 161 — 863 Income taxes (benefits) 336 143 (96 ) (49 ) — 334 Net income (loss) 573 244 (1,029 ) (169 ) — (381 ) Property additions 809 824 492 31 — 2,156

Asset Impairments

Asset Impairments	9 Months Ended
	Sep. 30, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Asset Impairments	ASSET IMPAIRMENTS Competitive Generation Asset Sale FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement (which was subsequently amended and restated as described below) to sell four of AE Supply’s natural gas generating plants and approximately 59% of AGC’s interest in the Bath County pumped hydro facility ( 1,572 MWs of combined capacity) to a subsidiary of LS Power for an all-cash purchase price of $925 million , subject to customary and other closing conditions, including receipt of regulatory approvals from FERC and the VSCC, as applicable, and various third - party consents. On February 17, 2017, AE Supply and AGC submitted a filing with FERC and on June 13, 2017, FERC issued an order authorizing such transaction as described in the January 2017 asset purchase agreement. On September 29, 2017, the parties filed a request with FERC for authorization to transfer the related hydroelectric license for Bath County under Part I of the FPA. Additional filings have been submitted to FERC for the purpose of amending affected FERC-jurisdictional rates and implementing the transaction once all regulatory approvals are obtained. Additionally, the consent of VEPCO is needed for the sale of AGC’s interest in the Bath County pumped hydro facility, as well as agreement among AGC, LS Power and VEPCO with respect to certain amendments to the Bath County project agreements. On August 30, 2017, the parties, along with AE Supply's subsidiary BU Energy, executed an amended and restated asset purchase agreement to (1) reduce the purchase price to $ 825 million , subject to adjustments, (2) add BU Energy’s 50% interest in a joint venture that owns the Buchanan Generating Facility ( 43 MWs) to the transaction and (3) provide that each component of the transaction ( i.e. , the AE Supply natural gas facilities, AGC’s interest in the Bath County hydroelectric power station and BU Energy’s interest in the Buchanan Generating Facility) may close independently. The sale of the AE Supply natural gas generating plants is expected to close in the fourth quarter of 2017 and the sale of approximately 59% of AGC’s interests in the Bath County hydroelectric power station and BU Energy’s 50% interest in the Buchanan Generating Facility are expected to close in the first quarter of 2018, subject in each case to various customary and other closing conditions including, without limitation, receipt of regulatory approvals and third-party consents, including the consent of VEPCO as discussed above. Under the amended and restated purchase agreement, AE Supply has agreed to satisfy and discharge all of its approximately $305 million of currently outstanding senior notes, which is expected to require the payment of a “make-whole” premium currently estimated to be approximately $100 million based on current interest rates, upon both (i) the consummation of the sale of the natural gas generating plants and (ii) either (a) the consummation of the sale of approximately 59% of AGC's interest in the Bath County hydroelectric power station or (b) the consummation of the pending sale of the Pleasants Power Station by AE Supply to its affiliate, MP. As a further condition to closing, FE will provide the purchaser two limited three -year guarantees of certain obligations of AE Supply and AGC arising under the amended and restated purchase agreement. On September 29, 2017, the parties filed an application with FERC for authorization to complete the Buchanan Generating Facility sale. On October 20, 2017, the parties filed an application with the VSCC for approval of the sale of approximately 59% of AGC's interest in the Bath County hydroelectric power station. There can be no assurance that all regulatory approvals will be obtained and/or all closing conditions will be satisfied or that any of the transactions will be consummated. As a result of the amended asset purchase agreement, CES recorded non-cash pre-tax impairment charges of $158 million in the nine-month period ended September 30, 2017. Assets held for sale as of September 30, 2017 , include property, plant and equipment (net of accumulated provision for depreciation) of $765 million , investments of $20 million , materials and supplies inventory of $4 million , and AROs of approximately $1 million . MAIT Transmission Formula Rate Settlement As described in Note 10, “Regulatory Matters,” on October 13, 2017, MAIT and certain parties filed a settlement agreement with FERC, which is subject to a final order. As a result of the settlement agreement, MAIT recorded a pre-tax impairment charge of $ 13 million in the third quarter of 2017. Competitive Generation Deactivations and Other Exit Activities On July 22, 2016, FirstEnergy and FES announced their intent to exit operations of the Bay Shore Unit 1 generating station ( 136 MWs) by October 1, 2020, through either sale or deactivation and to deactivate Units 1-4 of the W.H. Sammis generating station ( 720 MWs) 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. PJM and the Independent Market Monitor have approved the W.H. Sammis Units 1-4 and Bay Shore Unit 1 deactivations. 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, which is included in Fuel expense in the Consolidated Statement of Income (Loss). Goodwill 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 7.0 x 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 in Impairment of assets in the Consolidated Statement of Income (Loss). 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).

Organization and Basis of Pre26

Organization and Basis of Presentation (Policies)	9 Months Ended
	Sep. 30, 2017
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 NRC, 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 6, "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 and Comprehensive Income.
New Accounting Pronouncements	New Accounting Pronouncements Recently Adopted Pronouncements ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting" (Issued March 2016): ASU 2016-09 simplifies several aspects of the accounting for employee share-based payments. The new guidance requires all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also does not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. FirstEnergy adopted ASU 2016-09 on January 1, 2017. Upon adoption, FirstEnergy elected to account for forfeitures as they occur. The change was applied on a modified retrospective basis with a cumulative effect adjustment to retained earnings of approximately $6 million as of January 1, 2017. Additionally, FirstEnergy retrospectively applied the cash flow presentation requirement to present cash paid to tax authorities when shares are withheld to satisfy statutory tax withholding obligations as financing activities by reclassifying $12 million from operating activities to financing activities in the 2016 Consolidated Statement of Cash Flow. ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments" (Issued August 2016): The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments are presented and classified in the Consolidated Statements of Cash Flows, including the presentation of debt prepayment or debt extinguishment costs, all of which will be classified as financing activities. ASU 2016-15 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. FirstEnergy early adopted this ASU as of January 1, 2017. There was no impact to prior periods. Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below or in the 2016 Annual Report on Form 10-K based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. Below is an update to the discussion of pronouncements contained in the 2016 Annual Report on Form 10-K. ASU 2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to address implementation questions): For public business entities, the new revenue recognition guidance will be effective for annual and interim reporting periods beginning after December 15, 2017. FirstEnergy will not early adopt the standard. FirstEnergy has evaluated its revenues and expects limited impacts to current revenue recognition practices. FirstEnergy expects to apply the new guidance on a modified retrospective basis and continues to assess the impact on its financial statements and disclosures. ASU 2016-02, "Leases (Topic 842)" (Issued February 2016) : ASU 2016-02 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. ASU 2017-01, "Business Combinations: Clarifying the Definition of a Business" (Issued January 2017) : ASU 2017-01 assists entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. The ASU will be applied prospectively to any transactions occurring within the period of adoption. Early adoption is permitted, including for interim or annual periods in which the financial statements have not been issued or made available for issuance. ASU 2017-07, "Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" (Issued March 2017): ASU 2017-07 requires entities to retrospectively (1) disaggregate the current-service-cost component from the other components of net benefit cost (the “other components”) and present it with other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations if such a subtotal is presented. In addition, only service costs are eligible for capitalization on a prospective basis. Because the non-service cost components of net benefit cost will no longer be eligible for capitalization after December 31, 2017, FirstEnergy will recognize these components in income as a result of adopting the standard. FirstEnergy is currently evaluating presentation of the Statement of Income and the impact on disclosures as a result of adopting ASU 2017-07. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years.
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. As discussed above, FirstEnergy adopted ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting" beginning January 1, 2017. For the three and nine months ended September 30, 2017, there were no material impacts to the basic or diluted earnings per share due to the new standard.
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.
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	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.

Earnings (Loss) Per Share Of 27

Earnings (Loss) Per Share Of Common Stock (Tables)	9 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
Reconciliation of basic and diluted earnings per share	The following table reconciles basic and diluted earnings (loss) per share of common stock: (In millions, except per share amounts) For the Three Months Ended September 30 For the Nine Months Ended September 30 Reconciliation of Basic and Diluted Earnings (Loss) per Share of Common Stock 2017 2016 2017 2016 Net income (loss) $ 396 $ 380 $ 775 $ (381 ) Weighted average number of basic shares outstanding 444 425 444 425 Assumed exercise of dilutive stock options and awards (1) 2 2 1 — Weighted average number of diluted shares outstanding 446 427 445 425 Basic earnings (loss) per share of common stock $ 0.89 $ 0.89 $ 1.75 $ (0.90 ) Diluted earnings (loss) per share of common stock $ 0.89 $ 0.89 $ 1.74 $ (0.90 ) (1) For both the three and nine months ended September 30 , 2017 , and the three months ended September 30, 2016, one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. 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.

Pension and Other Postemploym28

Pension and Other Postemployment Benefits (Tables)	9 Months Ended
	Sep. 30, 2017
Defined Benefit Plan Disclosure [Line Items]
Components of Net Periodic Benefit Costs	The components of the consolidated net periodic costs (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 2017 2016 2017 2016 (In millions) Service costs $ 52 $ 48 $ 1 $ 2 Interest costs 97 99 7 7 Expected return on plan assets (112 ) (100 ) (7 ) (7 ) Amortization of prior service costs (credits) 2 2 (20 ) (20 ) Net periodic costs (credits) $ 39 $ 49 $ (19 ) $ (18 ) Components of Net Periodic Benefit Costs (Credits) Pension OPEB For the Nine Months Ended September 30 2017 2016 2017 2016 (In millions) Service costs $ 156 $ 144 $ 3 $ 4 Interest costs 291 298 21 22 Expected return on plan assets (336 ) (297 ) (22 ) (23 ) Amortization of prior service costs (credits) 6 6 (60 ) (60 ) Net periodic costs (credits) $ 117 $ 151 $ (58 ) $ (57 )
Net Periodic Pension and OPEB Costs	FES' share of the net periodic pension and OPEB costs (credits) were as follows: Pension OPEB 2017 2016 2017 2016 (In millions) For the Three Months Ended September 30 $ 3 $ 6 $ (4 ) $ (4 ) For the Nine Months Ended September 30 9 18 (12 ) (12 ) 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 2017 2016 2017 2016 (In millions) FirstEnergy $ 30 $ 35 $ (14 ) $ (11 ) FES 3 5 (4 ) (4 ) Net Periodic Benefit Expense (Credit) Pension OPEB For the Nine Months Ended September 30 2017 2016 2017 2016 (In millions) FirstEnergy $ 89 $ 107 $ (43 ) $ (41 ) FES 9 17 (12 ) (12 )
FES
Defined Benefit Plan Disclosure [Line Items]
Components of Net Periodic Benefit Costs	FES' share of the net periodic pension and OPEB costs (credits) were as follows: Pension OPEB 2017 2016 2017 2016 (In millions) For the Three Months Ended September 30 $ 3 $ 6 $ (4 ) $ (4 ) For the Nine Months Ended September 30 9 18 (12 ) (12 )

Accumulated Other Comprehensi29

Accumulated Other Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2017
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, 2017 and 2016 , 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, 2017 $ (26 ) $ 61 $ 128 $ 163 Other comprehensive income before reclassifications — 27 — 27 Amounts reclassified from AOCI 4 (33 ) (19 ) (48 ) Other comprehensive income (loss) 4 (6 ) (19 ) (21 ) Income taxes (benefits) on other comprehensive income (loss) 1 (3 ) (7 ) (9 ) Other comprehensive income (loss), net of tax 3 (3 ) (12 ) (12 ) AOCI Balance as of September 30, 2017 $ (23 ) $ 58 $ 116 $ 151 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 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, 2017 $ (28 ) $ 52 $ 150 $ 174 Other comprehensive income before reclassifications — 63 — 63 Amounts reclassified from AOCI 8 (55 ) (55 ) (102 ) Other comprehensive income (loss) 8 8 (55 ) (39 ) Income taxes (benefits) on other comprehensive income (loss) 3 2 (21 ) (16 ) Other comprehensive income (loss), net of tax 5 6 (34 ) (23 ) AOCI Balance as of September 30, 2017 $ (23 ) $ 58 $ 116 $ 151 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
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, 2017 and 2016 : For the Three Months Ended September 30 For the Nine Months Ended September 30 Affected Line Item in the Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2017 2016 2017 2016 (In millions) Gains & losses on cash flow hedges Long-term debt $ 4 $ 2 $ 8 $ 6 Interest expense (1 ) — (3 ) (2 ) Income taxes $ 3 $ 2 $ 5 $ 4 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (33 ) $ (17 ) $ (55 ) $ (42 ) Investment income 12 7 20 16 Income taxes $ (21 ) $ (10 ) $ (35 ) $ (26 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (19 ) $ (18 ) $ (55 ) $ (54 ) (1) 7 7 21 21 Income taxes $ (12 ) $ (11 ) $ (34 ) $ (33 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, "Pension and Other Postemployment Benefits," for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Income (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, 2017 and 2016 , 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, 2017 $ (9 ) $ 62 $ 26 $ 79 Other comprehensive income before reclassifications — 27 — 27 Amounts reclassified from AOCI 1 (33 ) (3 ) (35 ) Other comprehensive income (loss) 1 (6 ) (3 ) (8 ) Income tax benefits on other comprehensive income (loss) — (2 ) (1 ) (3 ) Other comprehensive income (loss), net of tax 1 (4 ) (2 ) (5 ) AOCI Balance as of September 30, 2017 $ (8 ) $ 58 $ 24 $ 74 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 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, 2017 $ (9 ) $ 48 $ 30 $ 69 Other comprehensive income before reclassifications — 70 — 70 Amounts reclassified from AOCI 1 (54 ) (10 ) (63 ) Other comprehensive income (loss) 1 16 (10 ) 7 Income taxes (benefits) on other comprehensive income (loss) — 6 (4 ) 2 Other comprehensive income (loss), net of tax 1 10 (6 ) 5 AOCI Balance as of September 30, 2017 $ (8 ) $ 58 $ 24 $ 74 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
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, 2017 and 2016 : For the Three Months Ended September 30 For the Nine Months Ended September 30 Affected Line Item in the Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2017 2016 2017 2016 (In millions) Gains & losses on cash flow hedges Commodity contracts $ 1 $ 1 $ 1 $ — Other operating expenses — — — — Income taxes (benefits) $ 1 $ 1 $ 1 $ — Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (33 ) $ (17 ) $ (54 ) $ (41 ) Investment income 11 6 19 15 Income taxes (benefits) $ (22 ) $ (11 ) $ (35 ) $ (26 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (3 ) $ (3 ) $ (10 ) $ (10 ) (1) 1 1 4 4 Income taxes (benefits) $ (2 ) $ (2 ) $ (6 ) $ (6 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, "Pension and Other Postemployment Benefits," for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	9 Months Ended
	Sep. 30, 2017
Variable Interest Entities [Abstract]
Net exposure to loss based upon the casualty value provisions	The following table discloses FirstEnergy's net exposure to loss based upon the casualty value provisions as of September 30, 2017 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy (1) $ 1,095 $ 873 $ 222 (1) All amounts are associated with FES.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2017
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, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,201 $ — $ 1,201 $ — $ 1,247 $ — $ 1,247 Derivative assets - commodity contracts — 35 — 35 10 200 — 210 Derivative assets - FTRs — — 5 5 — — 7 7 Derivative assets - NUG contracts (1) — — — — — — 1 1 Equity securities (2) 1,045 — — 1,045 925 — — 925 Foreign government debt securities — 92 — 92 — 78 — 78 U.S. government debt securities — 152 — 152 — 161 — 161 U.S. state debt securities — 274 — 274 — 246 — 246 Other (3) 399 152 — 551 199 123 — 322 Total assets $ 1,444 $ 1,906 $ 5 $ 3,355 $ 1,134 $ 2,055 $ 8 $ 3,197 Liabilities Derivative liabilities - commodity contracts $ — $ (12 ) $ — $ (12 ) $ (6 ) $ (118 ) $ — $ (124 ) Derivative liabilities - FTRs — — (2 ) (2 ) — — (6 ) (6 ) Derivative liabilities - NUG contracts (1) — — (92 ) (92 ) — — (108 ) (108 ) Total liabilities $ — $ (12 ) $ (94 ) $ (106 ) $ (6 ) $ (118 ) $ (114 ) $ (238 ) Net assets (liabilities) (4) $ 1,444 $ 1,894 $ (89 ) $ 3,249 $ 1,128 $ 1,937 $ (106 ) $ 2,959 (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 $(13) million and $(3) million as of September 30, 2017 and December 31, 2016 , 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, 2017 and December 31, 2016 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2016 Balance $ 1 $ (137 ) $ (136 ) $ 8 $ (13 ) $ (5 ) Unrealized gain (loss) 2 (17 ) (15 ) (6 ) (4 ) (10 ) Purchases — — — 16 (7 ) 9 Settlements (2 ) 46 44 (11 ) 18 7 December 31, 2016 Balance $ 1 $ (108 ) $ (107 ) $ 7 $ (6 ) $ 1 Unrealized loss — (14 ) (14 ) — (2 ) (2 ) Purchases — — — 5 (2 ) 3 Settlements (1 ) 30 29 (7 ) 8 1 September 30, 2017 Balance $ — $ (92 ) $ (92 ) $ 5 $ (2 ) $ 3 (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, 2017 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 3 Model RTO auction clearing prices $(5.00) to $4.60 $0.60 Dollars/MWH NUG Contracts $ (92 ) Model Generation 400 to 2,322,000 470,000 MWH Regional electricity prices $29.90 to $31.40 $29.90 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, 2017 and December 31, 2016 : September 30, 2017 (1) December 31, 2016 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,701 $ 42 $ 1,743 $ 1,735 $ 38 $ 1,773 FES 942 27 969 847 27 874 Equity securities FirstEnergy $ 927 $ 118 $ 1,045 $ 822 $ 103 $ 925 FES 675 90 765 564 70 634 (1) Excludes short-term cash investments: FirstEnergy - $100 million ; FES - $89 million . (2) Excludes short-term cash investments: FirstEnergy - $61 million ; FES - $44 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, 2017 and 2016 were as follows: For the Three Months Ended September 30, 2017 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 666 $ 93 $ (53 ) $ (3 ) $ 24 FES 397 73 (42 ) (3 ) 15 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 For the Nine Months Ended September 30, 2017 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 1,923 $ 276 $ (207 ) $ (10 ) $ 72 FES 834 206 (152 ) (10 ) 44 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
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, which excludes capital lease obligations and net unamortized debt issuance costs, premiums and discounts: September 30, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 22,218 $ 22,994 $ 19,885 $ 19,829 FES 2,837 1,620 3,000 1,555
FES
Fair Value of Financial Instruments [Line Items]
Assets and liabilities measured on recurring basis	FES Recurring Fair Value Measurements September 30, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 722 $ — $ 722 $ — $ 726 $ — $ 726 Derivative assets - commodity contracts — 35 — 35 10 200 — 210 Derivative assets - FTRs — — 1 1 — — 4 4 Equity securities (1) 765 — — 765 634 — — 634 Foreign government debt securities — 65 — 65 — 58 — 58 U.S. government debt securities — 138 — 138 — 48 — 48 U.S. state debt securities — 21 — 21 — 3 — 3 Other (2) 2 120 — 122 2 81 — 83 Total assets $ 767 $ 1,101 $ 1 $ 1,869 $ 646 $ 1,116 $ 4 $ 1,766 Liabilities Derivative liabilities - commodity contracts $ — $ (12 ) $ — $ (12 ) $ (6 ) $ (118 ) $ — $ (124 ) Derivative liabilities - FTRs — — (1 ) (1 ) — — (5 ) (5 ) Total liabilities $ — $ (12 ) $ (1 ) $ (13 ) $ (6 ) $ (118 ) $ (5 ) $ (129 ) Net assets (liabilities) (3) $ 767 $ 1,089 $ — $ 1,856 $ 640 $ 998 $ (1 ) $ 1,637 (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 $(8) million and $2 million as of September 30, 2017 and December 31, 2016 , respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.
Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts	The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the periods ended September 30, 2017 and December 31, 2016 : Derivative Asset Derivative Liability Net Asset (Liability) (In millions) January 1, 2016 Balance $ 5 $ (11 ) $ (6 ) Unrealized loss (4 ) (3 ) (7 ) Purchases 10 (5 ) 5 Settlements (7 ) 14 7 December 31, 2016 Balance $ 4 $ (5 ) $ (1 ) Unrealized loss — (1 ) (1 ) Purchases 1 (1 ) — Settlements (4 ) 6 2 September 30, 2017 Balance $ 1 $ (1 ) $ —
Quantitative information for level 3 valuation	The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended September 30, 2017 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ — Model RTO auction clearing prices ($5.00) to $2.60 $0.20 Dollars/MWH

Derivative Instruments (Tables)

Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2017
Derivative [Line Items]
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 - Other Commodity Contracts $ 30 $ 133 Commodity Contracts $ (11 ) $ (72 ) FTRs 5 7 FTRs (2 ) (6 ) 35 140 (13 ) (78 ) Noncurrent Liabilities - Adverse Power Contract Liability NUGs (1) (92 ) (108 ) Deferred Charges and Other Assets - Other Noncurrent Liabilities - Other Commodity Contracts 5 77 Commodity Contracts (1 ) (52 ) NUGs (1) — 1 5 78 (93 ) (160 ) Derivative Assets $ 40 $ 218 Derivative Liabilities $ (106 ) $ (238 ) (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
Offsetting assets	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, 2017 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 35 $ (9 ) $ — $ 26 FTRs 5 (2 ) — 3 $ 40 $ (11 ) $ — $ 29 Derivative Liabilities Commodity contracts $ (12 ) $ 9 $ — $ (3 ) FTRs (2 ) 2 — — NUG contracts (92 ) — — (92 ) $ (106 ) $ 11 $ — $ (95 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2016 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 210 $ (117 ) $ — $ 93 FTRs 7 (6 ) — 1 NUG contracts 1 — — 1 $ 218 $ (123 ) $ — $ 95 Derivative Liabilities Commodity contracts $ (124 ) $ 117 $ 1 $ (6 ) FTRs (6 ) 6 — — NUG contracts (108 ) — — (108 ) $ (238 ) $ 123 $ 1 $ (114 )
Offsetting 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, 2017 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 35 $ (9 ) $ — $ 26 FTRs 5 (2 ) — 3 $ 40 $ (11 ) $ — $ 29 Derivative Liabilities Commodity contracts $ (12 ) $ 9 $ — $ (3 ) FTRs (2 ) 2 — — NUG contracts (92 ) — — (92 ) $ (106 ) $ 11 $ — $ (95 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2016 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 210 $ (117 ) $ — $ 93 FTRs 7 (6 ) — 1 NUG contracts 1 — — 1 $ 218 $ (123 ) $ — $ 95 Derivative Liabilities Commodity contracts $ (124 ) $ 117 $ 1 $ (6 ) FTRs (6 ) 6 — — NUG contracts (108 ) — — (108 ) $ (238 ) $ 123 $ 1 $ (114 )
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, 2017 : Purchases Sales Net Units (In millions) Power Contracts 1 8 (7 ) MWH FTRs 14 — 14 MWH NUGs 2 — 2 MWH
Effect of derivative instruments on statements of income and comprehensive income	The effect of active derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income (Loss) during the three and nine months ended September 30, 2017 and 2016 , are summarized in the following tables: For the Three Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2017 Unrealized Loss Recognized in: Other Operating Expense $ (11 ) $ — $ (11 ) Realized Gain (Loss) Reclassified to: Revenues $ 8 $ (1 ) $ 7 Purchased Power Expense (3 ) — (3 ) Other Operating Expense — (1 ) (1 ) For the Three Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ 19 $ (3 ) $ 16 Realized Gain (Loss) Reclassified to: Revenues $ 32 $ 1 $ 33 Purchased Power Expense (22 ) — (22 ) Other Operating Expense — (6 ) (6 ) Fuel Expense (2 ) — (2 ) For the Nine Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2017 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (65 ) $ 1 $ (64 ) Realized Gain (Loss) Reclassified to: Revenues $ 48 $ — $ 48 Purchased Power Expense (14 ) — (14 ) Other Operating Expense — (14 ) (14 ) Fuel Expense 5 — 5 For the Nine Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain Recognized in: Other Operating Expense $ 2 $ 8 $ 10 Realized Gain (Loss) Reclassified to: Revenues $ 162 $ 5 $ 167 Purchased Power Expense (105 ) — (105 ) Other Operating Expense — (28 ) (28 ) Fuel Expense (9 ) — (9 ) The effect of active derivative instruments not in a hedging relationship on FES' Consolidated Statements of Income (Loss) during the three and nine months ended September 30, 2017 and 2016 , are summarized in the following tables: For the Three Months Ended September 30 Commodity Contracts FTRs Total 2017 (In millions) Unrealized Loss Recognized in: Other Operating Expense $ (11 ) $ — $ (11 ) Realized Gain (Loss) Reclassified to: Revenues $ 8 $ (1 ) $ 7 Purchased Power Expense (3 ) — (3 ) Other Operating Expense — (1 ) (1 ) For the Three Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ 19 $ (3 ) $ 16 Realized Gain (Loss) Reclassified to: Revenues $ 32 $ 1 $ 33 Purchased Power Expense (22 ) — (22 ) Other Operating Expense — (6 ) (6 ) For the Nine Months Ended September 30 Commodity Contracts FTRs Total 2017 (In millions) Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (65 ) $ 1 $ (64 ) Realized Gain (Loss) Reclassified to: Revenues $ 48 $ — $ 48 Purchased Power Expense (14 ) — (14 ) Other Operating Expense — (14 ) (14 ) For the Nine Months Ended September 30 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain Recognized in: Other Operating Expense $ 2 $ 8 $ 10 Realized Gain (Loss) Reclassified to: Revenues $ 162 $ 5 $ 167 Purchased Power Expense (105 ) — (105 ) Other Operating Expense — (28 ) (28 )
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, 2017 and 2016 . 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, 2017 $ (98 ) $ 3 $ (95 ) Unrealized loss (4 ) — (4 ) Settlements 10 — 10 Outstanding net asset (liability) as of September 30, 2017 $ (92 ) $ 3 $ (89 ) 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 ) 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, 2017 $ (107 ) $ 2 $ (105 ) Unrealized loss (14 ) (1 ) (15 ) Purchases — 3 3 Settlements 29 (1 ) 28 Outstanding net asset (liability) as of September 30, 2017 $ (92 ) $ 3 $ (89 ) 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 )
FES
Derivative [Line Items]
Fair value of derivatives instruments	FES records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and classification of derivative instruments on FES' 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 $ 30 $ 133 Commodity Contracts $ (11 ) $ (72 ) FTRs 1 4 FTRs (1 ) (5 ) 31 137 (12 ) (77 ) Deferred Charges and Other Assets - Derivatives Noncurrent Liabilities - Other Commodity Contracts 5 77 Commodity Contracts (1 ) (52 ) 5 77 (1 ) (52 ) Derivative Assets $ 36 $ 214 Derivative Liabilities $ (13 ) $ (129 )
Offsetting assets	The following tables summarize the fair value of derivative assets and derivative liabilities on FES’ Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet September 30, 2017 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 35 $ (9 ) $ — $ 26 FTRs 1 (1 ) — — $ 36 $ (10 ) $ — $ 26 Derivative Liabilities Commodity contracts $ (12 ) $ 9 $ — $ (3 ) FTRs (1 ) 1 — — $ (13 ) $ 10 $ — $ (3 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2016 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 210 $ (117 ) $ — $ 93 FTRs 4 (4 ) — — $ 214 $ (121 ) $ — $ 93 Derivative Liabilities Commodity contracts $ (124 ) $ 117 $ 1 $ (6 ) FTRs (5 ) 4 1 — $ (129 ) $ 121 $ 2 $ (6 )
Offsetting liabilities	The following tables summarize the fair value of derivative assets and derivative liabilities on FES’ Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet September 30, 2017 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 35 $ (9 ) $ — $ 26 FTRs 1 (1 ) — — $ 36 $ (10 ) $ — $ 26 Derivative Liabilities Commodity contracts $ (12 ) $ 9 $ — $ (3 ) FTRs (1 ) 1 — — $ (13 ) $ 10 $ — $ (3 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2016 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 210 $ (117 ) $ — $ 93 FTRs 4 (4 ) — — $ 214 $ (121 ) $ — $ 93 Derivative Liabilities Commodity contracts $ (124 ) $ 117 $ 1 $ (6 ) FTRs (5 ) 4 1 — $ (129 ) $ 121 $ 2 $ (6 )
Volume of First Energy's outstanding derivative transactions	The following table summarizes the volumes associated with FES' outstanding derivative transactions as of September 30, 2017 : Purchases Sales Net Units (In millions) Power Contracts 1 8 (7 ) MWH FTRs 7 — 7 MWH

Commitments, Guarantees and C33

Commitments, Guarantees and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule of Guarantor Obligations	Potential Collateral Obligations FES AE Supply Regulated FE Corp Total (In millions) Contractual Obligations for Additional Collateral At Current Credit Rating $ 6 $ 2 $ — $ — $ 8 Upon Further Downgrade — — 42 — 42 Surety Bonds (Collateralized Amount) (1) 48 24 105 185 362 Total Exposure from Contractual Obligations $ 54 $ 26 $ 147 $ 185 $ 412 (1) Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for $169 million of FG surety bonds for the benefit of the PA DEP with respect to LBR.

Supplemental Guarantor Inform34

Supplemental Guarantor Information (Tables)	9 Months Ended
	Sep. 30, 2017
Supplemental Guarantor Information [Abstract]
Condensed Consolidating Statements of Income (Loss) and Comprehensive Income (Loss)	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Three Months Ended September 30, 2017 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 741 $ 231 $ 292 $ (521 ) $ 743 OPERATING EXPENSES: Fuel — 108 57 — 165 Purchased power from affiliates 520 — 1 (521 ) — Purchased power from non-affiliates 152 — — — 152 Other operating expenses 70 62 147 12 291 Provision for depreciation 3 8 18 (1 ) 28 General taxes 4 3 (2 ) — 5 Total operating expenses 749 181 221 (510 ) 641 OPERATING INCOME (LOSS) (8 ) 50 71 (11 ) 102 OTHER INCOME (EXPENSE): Investment income (loss), including net income from equity investees 106 11 43 (121 ) 39 Miscellaneous income 1 — — — 1 Interest expense — affiliates (20 ) (3 ) 1 16 (6 ) Interest expense — other (12 ) (25 ) (11 ) 14 (34 ) Capitalized interest — — 6 — 6 Total other income (expense) 75 (17 ) 39 (91 ) 6 INCOME BEFORE INCOME TAXES (BENEFITS) 67 33 110 (102 ) 108 INCOME TAXES (BENEFITS) (9 ) 6 34 1 32 NET INCOME $ 76 $ 27 $ 76 $ (103 ) $ 76 STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME $ 76 $ 27 $ 76 $ (103 ) $ 76 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 (6 ) — (6 ) 6 (6 ) Other comprehensive loss (8 ) (3 ) (6 ) 9 (8 ) Income tax benefits on other comprehensive loss (3 ) (1 ) (2 ) 3 (3 ) Other comprehensive loss, net of tax (5 ) (2 ) (4 ) 6 (5 ) COMPREHENSIVE INCOME $ 71 $ 25 $ 72 $ (97 ) $ 71 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Nine Months Ended September 30, 2017 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 2,338 $ 941 $ 988 $ (1,869 ) $ 2,398 OPERATING EXPENSES: Fuel — 312 151 — 463 Purchased power from affiliates 1,994 — 77 (1,869 ) 202 Purchased power from non-affiliates 468 — — — 468 Other operating expenses 247 345 467 36 1,095 Provision for depreciation 9 24 49 (2 ) 80 General taxes 15 16 13 — 44 Total operating expenses 2,733 697 757 (1,835 ) 2,352 OPERATING INCOME (LOSS) (395 ) 244 231 (34 ) 46 OTHER INCOME (EXPENSE): Investment income (loss), including net income (loss) from equity investees 335 31 91 (383 ) 74 Miscellaneous income 1 — 5 — 6 Interest expense — affiliates (58 ) (9 ) (1 ) 55 (13 ) Interest expense — other (35 ) (78 ) (33 ) 42 (104 ) Capitalized interest — 1 19 — 20 Total other income (expense) 243 (55 ) 81 (286 ) (17 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (152 ) 189 312 (320 ) 29 INCOME TAXES (BENEFITS) (167 ) 66 112 3 14 NET INCOME $ 15 $ 123 $ 200 $ (323 ) $ 15 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 15 $ 123 $ 200 $ (323 ) $ 15 OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (10 ) (10 ) — 10 (10 ) Amortized gains on derivative hedges 1 — — — 1 Change in unrealized gains on available-for-sale securities 16 — 16 (16 ) 16 Other comprehensive income (loss) 7 (10 ) 16 (6 ) 7 Income taxes (benefits) on other comprehensive income (loss) 2 (4 ) 6 (2 ) 2 Other comprehensive income (loss), net of tax 5 (6 ) 10 (4 ) 5 COMPREHENSIVE INCOME $ 20 $ 117 $ 210 $ (327 ) $ 20 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) Pension 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 )
Condensed Consolidating Balance Sheets	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of September 30, 2017 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 171 — — — 171 Affiliated companies 194 175 193 (235 ) 327 Other 9 4 — — 13 Notes receivable from affiliated companies 364 1,765 1,481 (3,610 ) — Materials and supplies 34 147 82 — 263 Derivatives 31 — — — 31 Collateral 101 25 — — 126 Prepaid taxes and other 12 16 1 — 29 916 2,134 1,757 (3,845 ) 962 PROPERTY, PLANT AND EQUIPMENT: In service 121 2,587 5,016 (281 ) 7,443 Less — Accumulated provision for depreciation 61 1,942 4,309 (189 ) 6,123 60 645 707 (92 ) 1,320 Construction work in progress 2 45 241 — 288 62 690 948 (92 ) 1,608 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,823 — 1,823 Investment in affiliated companies 3,347 — — (3,347 ) — Other — 9 — — 9 3,347 9 1,823 (3,347 ) 1,832 DEFERRED CHARGES AND OTHER ASSETS: Property taxes — 2 4 — 6 Accumulated deferred income tax benefits 428 1,212 690 (273 ) 2,057 Derivatives 5 — — — 5 Other 31 328 — 10 369 464 1,542 694 (263 ) 2,437 $ 4,789 $ 4,375 $ 5,222 $ (7,547 ) $ 6,839 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 180 $ 114 $ (27 ) $ 267 Short-term borrowings - affiliated companies 3,299 497 — (3,610 ) 186 Accounts payable- Affiliated companies 329 87 143 (329 ) 230 Other 11 87 — — 98 Accrued taxes 16 12 19 (15 ) 32 Derivatives 10 2 — — 12 Other 28 92 14 33 167 3,693 957 290 (3,948 ) 992 CAPITALIZATION: Total equity 328 946 2,301 (3,247 ) 328 Long-term debt and other long-term obligations 691 1,941 1,006 (1,079 ) 2,559 1,019 2,887 3,307 (4,326 ) 2,887 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 732 732 Accumulated deferred income taxes 5 — — (5 ) — Retirement benefits 26 181 — — 207 Asset retirement obligations — 187 801 — 988 Other 46 163 824 — 1,033 77 531 1,625 727 2,960 $ 4,789 $ 4,375 $ 5,222 $ (7,547 ) $ 6,839 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2016 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 213 — — — 213 Affiliated companies 332 315 417 (612 ) 452 Other 17 2 8 — 27 Notes receivable from affiliated companies 501 1,585 1,294 (3,351 ) 29 Materials and supplies 45 142 80 — 267 Derivatives 137 — — — 137 Collateral 157 — — — 157 Prepaid taxes and other 38 24 1 — 63 1,440 2,070 1,800 (3,963 ) 1,347 PROPERTY, PLANT AND EQUIPMENT: In service 120 2,524 4,703 (290 ) 7,057 Less — Accumulated provision for depreciation 52 1,920 4,144 (187 ) 5,929 68 604 559 (103 ) 1,128 Construction work in progress 2 67 358 — 427 70 671 917 (103 ) 1,555 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,552 — 1,552 Investment in affiliated companies 2,923 — — (2,923 ) — Other — 9 1 — 10 2,923 9 1,553 (2,923 ) 1,562 DEFERRED CHARGES AND OTHER ASSETS: Property taxes — 12 28 — 40 Accumulated deferred income tax benefits 395 1,271 883 (270 ) 2,279 Derivatives 77 — — — 77 Other 33 327 — 21 381 505 1,610 911 (249 ) 2,777 $ 4,938 $ 4,360 $ 5,181 $ (7,238 ) $ 7,241 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 200 $ 5 $ (26 ) $ 179 Short-term borrowings - affiliated companies 2,969 483 — (3,351 ) 101 Accounts payable- Affiliated companies 743 107 406 (706 ) 550 Other 17 93 — — 110 Accrued taxes 50 48 61 (16 ) 143 Derivatives 71 6 — — 77 Other 56 54 10 36 156 3,906 991 482 (4,063 ) 1,316 CAPITALIZATION: Total equity 218 828 2,006 (2,834 ) 218 Long-term debt and other long-term obligations 691 2,093 1,120 (1,091 ) 2,813 909 2,921 3,126 (3,925 ) 3,031 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 757 757 Accumulated deferred income taxes 4 3 — (7 ) — Retirement benefits 25 172 — — 197 Asset retirement obligations — 188 713 — 901 Other 94 85 860 — 1,039 123 448 1,573 750 2,894 $ 4,938 $ 4,360 $ 5,181 $ (7,238 ) $ 7,241
Condensed Consolidating Statements of Cash Flows	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Nine Months Ended September 30, 2017 FES FG NG Eliminations Consolidated (In millions) NET CASH (USED FOR) PROVIDED FROM OPERATING ACTIVITIES $ (463 ) $ 387 $ 547 $ (13 ) $ 458 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 330 14 — (259 ) 85 Redemptions and Repayments- Long-term debt — (171 ) (5 ) 13 (163 ) Other — (5 ) — — (5 ) Net cash (used for) provided from financing activities 330 (162 ) (5 ) (246 ) (83 ) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (1 ) (46 ) (154 ) — (201 ) Nuclear fuel — — (156 ) — (156 ) Sales of investment securities held in trusts — — 834 — 834 Purchases of investment securities held in trusts — — (878 ) — (878 ) Loans to affiliated companies, net 137 (179 ) (188 ) 259 29 Other (3 ) — — — (3 ) Net cash (used for) provided from investing activities 133 (225 ) (542 ) 259 (375 ) 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, 2016 FES FG NG Eliminations Consolidated (In millions) NET CASH (USED FOR) PROVIDED FROM OPERATING ACTIVITIES $ (605 ) $ 402 $ 820 $ (12 ) $ 605 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 — (6 ) (2 ) — (8 ) Net cash (used for) provided from financing activities 701 61 (21 ) (680 ) 61 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 ) Loans to affiliated companies, net (87 ) (292 ) (328 ) 692 (15 ) Other 19 — — — 19 Net cash (used for) provided from 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

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2017
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, 2017 External revenues $ 2,610 $ 342 $ 796 $ — $ (34 ) $ 3,714 Internal revenues — — 93 — (93 ) — Total revenues 2,610 342 889 — (127 ) 3,714 Depreciation 183 59 30 17 — 289 Amortization of regulatory assets, net 85 6 — — — 91 Impairment of assets (Note 14) — 13 18 — — 31 Investment income 13 — 34 3 (13 ) 37 Interest expense 133 38 44 90 — 305 Income taxes (benefits) 183 49 40 (33 ) — 239 Net income (loss) 314 84 66 (68 ) — 396 Total assets 27,866 9,356 5,814 613 — 43,649 Total goodwill 5,004 614 — — — 5,618 Property additions 286 248 45 14 — 593 September 30, 2016 External revenues $ 2,691 $ 294 $ 998 $ — $ (66 ) $ 3,917 Internal revenues — — 117 — (117 ) — Total revenues 2,691 294 1,115 — (183 ) 3,917 Depreciation 169 47 79 16 — 311 Amortization of regulatory assets, net 98 — — — — 98 Investment income 13 — 23 2 (10 ) 28 Interest expense 143 39 48 56 — 286 Income taxes (benefits) 162 50 49 (10 ) — 251 Net income (loss) 276 85 86 (67 ) — 380 Total assets 27,818 8,492 15,165 486 — 51,961 Total goodwill 5,004 614 — — — 5,618 Property additions 281 268 110 5 — 664 For the Nine Months Ended September 30, 2017 External revenues $ 7,362 $ 982 $ 2,388 $ — $ (157 ) $ 10,575 Internal revenues — — 296 — (296 ) — Total revenues 7,362 982 2,684 — (453 ) 10,575 Depreciation 540 164 87 54 — 845 Amortization of regulatory assets, net 204 11 — — — 215 Impairment of assets (Note 14) — 13 149 — — 162 Investment income 41 — 66 8 (37 ) 78 Interest expense 405 116 136 225 — 882 Income taxes (benefits) 442 154 (25 ) (89 ) — 482 Net income (loss) 756 264 (57 ) (188 ) — 775 Property additions 854 717 233 43 — 1,847 September 30, 2016 External revenues $ 7,390 $ 851 $ 3,158 $ — $ (212 ) $ 11,187 Internal revenues — — 377 — (377 ) — Total revenues 7,390 851 3,535 — (589 ) 11,187 Depreciation 504 138 284 48 — 974 Amortization of regulatory assets, net 218 4 — — — 222 Impairment of assets (Note 14) — — 1,447 — — 1,447 Investment income 37 — 56 13 (31 ) 75 Interest expense 441 118 143 161 — 863 Income taxes (benefits) 336 143 (96 ) (49 ) — 334 Net income (loss) 573 244 (1,029 ) (169 ) — (381 ) Property additions 809 824 492 31 — 2,156

Organization and Basis of Pre36

Organization and Basis of Presentation (Details Textuals) customer in Millions, MWh in Millions

Aug. 30, 2017

Aug. 30, 2017MW

Aug. 30, 2017Natural_gas_plant

Aug. 30, 2017transmission_center

Aug. 30, 2017USD ($)

Aug. 30, 2017

Aug. 30, 2017limited_guaranty

Dec. 31, 2017USD ($)

Mar. 31, 2017MWh

Jan. 31, 2017USD ($)MW

Mar. 06, 2017USD ($)MWhMW

Mar. 31, 2018USD ($)

Sep. 30, 2017USD ($)transmission_centerMW

Sep. 30, 2016USD ($)

Sep. 30, 2017USD ($)customertransmission_centercompanymiMW

Sep. 30, 2016USD ($)

Dec. 31, 2018MWh

Dec. 31, 2017MWh

Dec. 31, 2016USD ($)MWh

Dec. 31, 2015USD ($)MW

Dec. 31, 2020MW

Mar. 07, 2017MW

Property, Plant and Equipment [Line Items]

Aggregate amount of capacity | MW

17,000

Length of transmission lines | mi

24,500

Number of regional transmission centers | transmission_center

2

2

Capitalized cost of equity

$ 8,000,000

$ 11,000,000

$ 25,000,000

$ 28,000,000

Capitalized interest

$ 11,000,000

17,000,000

34,000,000

51,000,000

Net cash used in operating activities

(2,762,000,000)

(2,592,000,000)

Net cash provided by financing activities

$ (381,000,000)

304,000,000

Utilization of Accelerated Useful Life

Property, Plant and Equipment [Line Items]

Reduction to depreciation

$ 21,000,000

$ 19,000,000

Accounting Standards Update 2016-09

Property, Plant and Equipment [Line Items]

Net cash used in operating activities

$ 12,000,000

Net cash provided by financing activities

12,000,000

Accounting Standards Update 2016-09 | Retained Earnings

Property, Plant and Equipment [Line Items]

Cumulative effect of new accounting principle

$ 6,000,000

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

Plant capacity (in MW's) | MW

3,790

3,790

CES

Property, Plant and Equipment [Line Items]

Capacity in deactivated power plants (in MW's) | MW

6,770

Plant capacity (in MW's) | MW

13,000

13,162

13,162

10,000

Purchase power agreements additional capacity (in MWh) | MWh

5

Contract sales (in MWh) | MWh

53

FES

Property, Plant and Equipment [Line Items]

Net cash used in operating activities

$ (458,000,000)

(605,000,000)

Net cash provided by financing activities

(83,000,000)

$ 61,000,000

FES | CES

Property, Plant and Equipment [Line Items]

Inability to extend or refinance debt next year

$ 515,000,000

515,000,000

Scenario, Forecast | CES

Property, Plant and Equipment [Line Items]

Capacity in deactivated power plants (in MW's) | MW

856

Scenario, Forecast | FES | CES

Property, Plant and Equipment [Line Items]

Interest and lease payments

$ 48,000,000

Interest payments

$ 38,000,000

Minimum | CES

Property, Plant and Equipment [Line Items]

Annual generation capacity (in MW) | MWh

70

Minimum | Scenario, Forecast | CES

Property, Plant and Equipment [Line Items]

Expected contract sales (in MWh) | MWh

30

40

Maximum | CES

Property, Plant and Equipment [Line Items]

Annual generation capacity (in MW) | MWh

65

75

Maximum | Scenario, Forecast | CES

Property, Plant and Equipment [Line Items]

Expected contract sales (in MWh) | MWh

35

45

Line of Credit | Revolving Credit Facility

Property, Plant and Equipment [Line Items]

Maximum amount borrowed under revolving credit facility

$ 500,000,000

$ 500,000,000

Purchase Agreement with Aspen Generating, LLC

Property, Plant and Equipment [Line Items]

Plant capacity (in MW's) | MW

1,615

1,572

Cash purchase price

$ 825,000,000

$ 925,000,000

Number of limited guaranties

2

2

Term of guaranties

3 years

Purchase Agreement with Aspen Generating, LLC | AE Supply

Property, Plant and Equipment [Line Items]

Number of gas generating plants | Natural_gas_plant

4

Discharge of note indenture

305,000,000

Make-whole premiums

$ 100,000,000

Purchase Agreement with Aspen Generating, LLC | AGC

Property, Plant and Equipment [Line Items]

Ownership percentage

59.00%

Purchase Agreement with Aspen Generating, LLC | BU Energy

Property, Plant and Equipment [Line Items]

Ownership percentage

50.00%

Pleasants Power Station

Property, Plant and Equipment [Line Items]

Plant capacity (in MW's) | MW

1,300

Pleasants Power Station | CES

Property, Plant and Equipment [Line Items]

Plant capacity (in MW's) | MW

1,300

1,300

Held-for-sale | Pleasants Power Station

Property, Plant and Equipment [Line Items]

Assets held for sale

$ 195,000,000

Earnings (Loss) Per Share Of 37

Earnings (Loss) Per Share Of Common Stock (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Earnings Per Share [Abstract]
Net Income (Loss)	$ 396	$ 380	$ 775	$ (381)
Weighted average number of basic shares outstanding	444	425	444	425
Assumed exercise of dilutive stock options and awards (in shares)	2	2	1	0
Weighted average number of diluted shares outstanding	446	427	445	425
Basic earnings (loss) per share of common stock (in dollars per share)	$ 0.89	$ 0.89	$ 1.75	$ (0.90)
Diluted earnings (loss) per share of common stock (in dollars per share)	$ 0.89	$ 0.89	$ 1.74	$ (0.90)
Shares excluded from the calculation of diluted shares outstanding, in shares	1	3	1	3

Pension and Other Postemploym38

Pension and Other Postemployment Benefits (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	$ 52	$ 48	$ 156	$ 144
Interest costs	97	99	291	298
Expected return on plan assets	(112)	(100)	(336)	(297)
Amortization of prior service costs (credits)	2	2	6	6
Net periodic costs (credits)	39	49	117	151
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	1	2	3	4
Interest costs	7	7	21	22
Expected return on plan assets	(7)	(7)	(22)	(23)
Amortization of prior service costs (credits)	(20)	(20)	(60)	(60)
Net periodic costs (credits)	(19)	(18)	(58)	(57)
FirstEnergy | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	30	35	89	107
FirstEnergy | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	(14)	(11)	(43)	(41)
FES
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-current liabilities	866		866		$ 866
FES | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)	3	6	9	18
Net periodic benefit expense (credit)	3	5	9	17
FES | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)	(4)	(4)	(12)	(12)
Net periodic benefit expense (credit)	(4)	$ (4)	(12)	$ (12)
FENOC
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-current liabilities	$ 570		$ 570		$ 570

Accumulated Other Comprehensi39

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	$ 163	$ 191	$ 174	$ 171
Other comprehensive income before reclassifications	27	21	63	109
Amounts reclassified from AOCI	(48)	(33)	(102)	(90)
Other comprehensive income (loss)	(21)	(12)	(39)	19
Income taxes (benefits) on other comprehensive income (loss)	(9)	(5)	(16)	6
Other comprehensive income (loss), net of tax	(12)	(7)	(23)	13
AOCI Ending Balance	151	184	151	184
Gains & Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(26)	(31)	(28)	(33)
Other comprehensive income before reclassifications	0	0	0	0
Amounts reclassified from AOCI	4	2	8	6
Other comprehensive income (loss)	4	2	8	6
Income taxes (benefits) on other comprehensive income (loss)	1	0	3	2
Other comprehensive income (loss), net of tax	3	2	5	4
AOCI Ending Balance	(23)	(29)	(23)	(29)
Unrealized Gains on AFS Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	61	58	52	18
Other comprehensive income before reclassifications	27	21	63	109
Amounts reclassified from AOCI	(33)	(17)	(55)	(42)
Other comprehensive income (loss)	(6)	4	8	67
Income taxes (benefits) on other comprehensive income (loss)	(3)	2	2	25
Other comprehensive income (loss), net of tax	(3)	2	6	42
AOCI Ending Balance	58	60	58	60
Defined Benefit Pension & OPEB Plans
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	128	164	150	186
Other comprehensive income before reclassifications	0	0	0	0
Amounts reclassified from AOCI	(19)	(18)	(55)	(54)
Other comprehensive income (loss)	(19)	(18)	(55)	(54)
Income taxes (benefits) on other comprehensive income (loss)	(7)	(7)	(21)	(21)
Other comprehensive income (loss), net of tax	(12)	(11)	(34)	(33)
AOCI Ending Balance	116	153	116	153
FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	79	75	69	46
Other comprehensive income before reclassifications	27	22	70	102
Amounts reclassified from AOCI	(35)	(19)	(63)	(51)
Other comprehensive income (loss)	(8)	3	7	51
Income taxes (benefits) on other comprehensive income (loss)	(3)	1	2	20
Other comprehensive income (loss), net of tax	(5)	2	5	31
AOCI Ending Balance	74	77	74	77
FES | Gains & Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(9)	(10)	(9)	(9)
Other comprehensive income before reclassifications	0	0	0	0
Amounts reclassified from AOCI	1	1	1	0
Other comprehensive income (loss)	1	1	1	0
Income taxes (benefits) on other comprehensive income (loss)	0	0	0	0
Other comprehensive income (loss), net of tax	1	1	1	0
AOCI Ending Balance	(8)	(9)	(8)	(9)
FES | Unrealized Gains on AFS Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	62	50	48	16
Other comprehensive income before reclassifications	27	22	70	102
Amounts reclassified from AOCI	(33)	(17)	(54)	(41)
Other comprehensive income (loss)	(6)	5	16	61
Income taxes (benefits) on other comprehensive income (loss)	(2)	2	6	24
Other comprehensive income (loss), net of tax	(4)	3	10	37
AOCI Ending Balance	58	53	58	53
FES | Defined Benefit Pension & OPEB Plans
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	26	35	30	39
Other comprehensive income before reclassifications	0	0	0	0
Amounts reclassified from AOCI	(3)	(3)	(10)	(10)
Other comprehensive income (loss)	(3)	(3)	(10)	(10)
Income taxes (benefits) on other comprehensive income (loss)	(1)	(1)	(4)	(4)
Other comprehensive income (loss), net of tax	(2)	(2)	(6)	(6)
AOCI Ending Balance	$ 24	$ 33	$ 24	$ 33

Accumulated Other Comprehensi40

Accumulated Other Comprehensive Income (Details 1) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	$ 942	$ 953	$ 3,041	$ 2,835
Interest expense	305	286	882	863
Income taxes (benefits)	239	251	482	334
Prior-service costs	48	33	102	90
Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(4)	(2)	(8)	(6)
Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	33	17	55	42
Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Income taxes (benefits)	(1)	0	(3)	(2)
Net of tax	3	2	5	4
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	4	2	8	6
Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(33)	(17)	(55)	(42)
Income taxes (benefits)	12	7	20	16
Net of tax	(21)	(10)	(35)	(26)
Reclassifications from AOCI | Net prior service costs
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(19)	(18)	(55)	(54)
Income taxes	7	7	21	21
Net of tax	(12)	(11)	(34)	(33)
FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	291	316	1,095	925
Income taxes (benefits)	32	56	14	(5)
Prior-service costs	35	19	63	51
FES | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(1)	(1)	(1)	0
FES | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	33	17	54	41
FES | Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Income taxes (benefits)	0	0	0	0
Net of tax	1	1	1	0
FES | Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	1	1	1	0
FES | Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(33)	(17)	(54)	(41)
Income taxes (benefits)	11	6	19	15
Net of tax	(22)	(11)	(35)	(26)
FES | Reclassifications from AOCI | Net prior service costs
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(3)	(3)	(10)	(10)
Income taxes	1	1	4	4
Net of tax	$ (2)	$ (2)	$ (6)	$ (6)

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	37.60%	39.80%		38.30%
Impairment			$ 800			$ 800
Nondeductible expense from impairment of goodwill						433
Unrecognized tax benefits from lapse of statute of limitations				$ 51
Unrecognized tax benefits that would impact effective tax rate	$ 26			$ 26
State and Local Jurisdiction
Income Taxes (Textuals) [Abstract]
Valuation allowance						$ 159
FES
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	29.60%	58.30%		48.30%	1.80%
Impairment			$ 23
Nondeductible expense from impairment of goodwill		$ 23
FES | State and Local Jurisdiction
Income Taxes (Textuals) [Abstract]
Valuation allowance		$ 65			$ 65

Variable Interest Entities (Det

Variable Interest Entities (Details) - FirstEnergy $ in Millions	Sep. 30, 2017USD ($)
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	$ 1,095
Discounted Lease Payments, net	873
Net Exposure	$ 222

Variable Interest Entities (D43

Variable Interest Entities (Details Textuals)	Jun. 01, 2017USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)agreemententity	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)
Variable Interest Entities (Textuals) [Abstract]
Long-term transition bond		$ 60,000,000		$ 60,000,000		$ 85,000,000
Long-term pollution control bond		383,000,000		383,000,000		406,000,000
Guarantor obligations		412,000,000		$ 412,000,000
Number of contracts that may contain variable interest | entity				1
Purchased power		$ 861,000,000	$ 979,000,000	$ 2,459,000,000	$ 2,992,000,000
Bruce Mansfield Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary		93.83%		93.83%
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				12
Phase In Recovery Bonds
Variable Interest Entities (Textuals) [Abstract]
Long-term debt and other long-term obligations		$ 315,000,000		$ 315,000,000		$ 339,000,000
Ohio Funding Companies
Variable Interest Entities (Textuals) [Abstract]
Annual servicing fees				445,000
Other FE subsidiaries | Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Purchased power		$ 29,000,000	$ 22,000,000	$ 82,000,000	$ 78,000,000
NG | Beaver Valley Unit 2
Variable Interest Entities (Textuals) [Abstract]
Increase in plant ownership percentage (percent)	2.60%
Purchase of remaining non-affiliated leasehold interest	$ 38,000,000
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, 2017	Dec. 31, 2016
Assets
Fair value, assets	$ 3,355	$ 3,197
Liabilities
Fair value, liabilities	(106)	(238)
Net assets (liabilities)	3,249	2,959
FES
Assets
Fair value, assets	1,869	1,766
Liabilities
Fair value, liabilities	(13)	(129)
Net assets (liabilities)	1,856	1,637
Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(12)	(124)
Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(12)	(124)
FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(2)	(6)
FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(1)	(5)
NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(92)	(108)
Corporate debt securities
Assets
Fair value, assets	1,201	1,247
Corporate debt securities | FES
Assets
Fair value, assets	722	726
Commodity contracts | Derivative Assets
Assets
Fair value, assets	35	210
Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	35	210
FTRs | Derivative Assets
Assets
Fair value, assets	5	7
FTRs | Derivative Assets | FES
Assets
Fair value, assets	1	4
NUG contracts | Derivative Assets
Assets
Fair value, assets	0	1
Equity securities
Assets
Fair value, assets	1,045	925
Equity securities | FES
Assets
Fair value, assets	765	634
Foreign government debt securities
Assets
Fair value, assets	92	78
Foreign government debt securities | FES
Assets
Fair value, assets	65	58
U.S. government debt securities
Assets
Fair value, assets	152	161
U.S. government debt securities | FES
Assets
Fair value, assets	138	48
U.S. state debt securities
Assets
Fair value, assets	274	246
U.S. state debt securities | FES
Assets
Fair value, assets	21	3
Other
Assets
Fair value, assets	551	322
Other | FES
Assets
Fair value, assets	122	83
Level 1
Assets
Fair value, assets	1,444	1,134
Liabilities
Fair value, liabilities	0	(6)
Net assets (liabilities)	1,444	1,128
Level 1 | FES
Assets
Fair value, assets	767	646
Liabilities
Fair value, liabilities	0	(6)
Net assets (liabilities)	767	640
Level 1 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	(6)
Level 1 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	(6)
Level 1 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 1 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 1 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 1 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 1 | Corporate debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	0	10
Level 1 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	0	10
Level 1 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 1 | NUG contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | Equity securities
Assets
Fair value, assets	1,045	925
Level 1 | Equity securities | FES
Assets
Fair value, assets	765	634
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	399	199
Level 1 | Other | FES
Assets
Fair value, assets	2	2
Level 2
Assets
Fair value, assets	1,906	2,055
Liabilities
Fair value, liabilities	(12)	(118)
Net assets (liabilities)	1,894	1,937
Level 2 | FES
Assets
Fair value, assets	1,101	1,116
Liabilities
Fair value, liabilities	(12)	(118)
Net assets (liabilities)	1,089	998
Level 2 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(12)	(118)
Level 2 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(12)	(118)
Level 2 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 2 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2 | Corporate debt securities
Assets
Fair value, assets	1,201	1,247
Level 2 | Corporate debt securities | FES
Assets
Fair value, assets	722	726
Level 2 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	35	200
Level 2 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	35	200
Level 2 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 2 | NUG contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | Equity securities
Assets
Fair value, assets	0	0
Level 2 | Equity securities | FES
Assets
Fair value, assets	0	0
Level 2 | Foreign government debt securities
Assets
Fair value, assets	92	78
Level 2 | Foreign government debt securities | FES
Assets
Fair value, assets	65	58
Level 2 | U.S. government debt securities
Assets
Fair value, assets	152	161
Level 2 | U.S. government debt securities | FES
Assets
Fair value, assets	138	48
Level 2 | U.S. state debt securities
Assets
Fair value, assets	274	246
Level 2 | U.S. state debt securities | FES
Assets
Fair value, assets	21	3
Level 2 | Other
Assets
Fair value, assets	152	123
Level 2 | Other | FES
Assets
Fair value, assets	120	81
Level 3
Assets
Fair value, assets	5	8
Liabilities
Fair value, liabilities	(94)	(114)
Net assets (liabilities)	(89)	(106)
Level 3 | FES
Assets
Fair value, assets	1	4
Liabilities
Fair value, liabilities	(1)	(5)
Net assets (liabilities)	0	(1)
Level 3 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 3 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 3 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(2)	(6)
Level 3 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(1)	(5)
Level 3 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(92)	(108)
Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 3 | Corporate debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 3 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 3 | FTRs | Derivative Assets
Assets
Fair value, assets	5	7
Level 3 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	1	4
Level 3 | 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 (Deta45

Fair Value Measurements (Details 1) - Level 3 - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
NUG contracts
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	$ 1	$ 1
Beginning Balance, Derivative Liabilities	(108)	(137)
Beginning Balance, Net	(107)	(136)
Unrealized gain (loss), Derivative Assets	0	2
Unrealized loss, Derivative Liabilities	(14)	(17)
Unrealized loss, Net	(14)	(15)
Purchases, Derivative Assets	0	0
Purchases, Derivative Liabilities	0	0
Purchases, Net	0	0
Settlements, Derivative Assets	(1)	(2)
Settlements, Derivative Liabilities	30	46
Settlements, Net	29	44
Ending Balance, Derivative Assets	0	1
Ending Balance, Derivative Liabilities	(92)	(108)
Ending Balance, Net	(92)	(107)
FTRs
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	7	8
Beginning Balance, Derivative Liabilities	(6)	(13)
Beginning Balance, Net	1	(5)
Unrealized gain (loss), Derivative Assets	0	(6)
Unrealized loss, Derivative Liabilities	(2)	(4)
Unrealized loss, Net	(2)	(10)
Purchases, Derivative Assets	5	16
Purchases, Derivative Liabilities	(2)	(7)
Purchases, Net	3	9
Settlements, Derivative Assets	(7)	(11)
Settlements, Derivative Liabilities	8	18
Settlements, Net	1	7
Ending Balance, Derivative Assets	5	7
Ending Balance, Derivative Liabilities	(2)	(6)
Ending Balance, Net	3	1
FTRs | FES
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	4	5
Beginning Balance, Derivative Liabilities	(5)	(11)
Beginning Balance, Net	(1)	(6)
Unrealized gain (loss), Derivative Assets	0	(4)
Unrealized loss, Derivative Liabilities	(1)	(3)
Unrealized loss, Net	(1)	(7)
Purchases, Derivative Assets	1	10
Purchases, Derivative Liabilities	(1)	(5)
Purchases, Net	0	5
Settlements, Derivative Assets	(4)	(7)
Settlements, Derivative Liabilities	6	14
Settlements, Net	2	7
Ending Balance, Derivative Assets	1	4
Ending Balance, Derivative Liabilities	(1)	(5)
Ending Balance, Net	$ 0	$ (1)

Fair Value Measurements (Deta46

Fair Value Measurements (Details 2) - Level 3 $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)MWh$ / MWh	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ 3	$ 1	$ (5)
FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	0	(1)	(6)
NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(92)	$ (107)	$ (136)
Model | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	3
Model | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	0
Model | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ (92)
Model | Minimum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	(5)
Model | Minimum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	(5)
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)	29.90
Model | Maximum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	4.60
Model | Maximum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	2.60
Model | Maximum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	2,322,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	31.40
Model | Weighted Average | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	0.60
Model | Weighted Average | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	0.20
Model | Weighted Average | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	470,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	29.90

Fair Value Measurements (Deta47

Fair Value Measurements (Details 3) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	$ 1,701	$ 1,735
Unrealized Gain	42	38
Fair Value	1,743	1,773
Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	927	822
Unrealized Gains	118	103
Fair Value	1,045	925
FES | Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	942	847
Unrealized Gain	27	27
Fair Value	969	874
FES | Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	675	564
Unrealized Gains	90	70
Fair Value	$ 765	$ 634

Fair Value Measurements (Deta48

Fair Value Measurements (Details 4) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
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	$ 666	$ 337	$ 1,923	$ 1,361
Realized Gains	93	36	276	131
Realized Losses	(53)	(15)	(207)	(88)
OTTI	(3)	(3)	(10)	(13)
Interest and Dividend Income	24	27	72	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	397	135	834	576
Realized Gains	73	23	206	90
Realized Losses	(42)	(6)	(152)	(49)
OTTI	(3)	(3)	(10)	(12)
Interest and Dividend Income	$ 15	$ 16	$ 44	$ 42

Fair Value Measurements (Deta49

Fair Value Measurements (Details 5) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
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	$ 22,218	$ 19,885
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	2,837	3,000
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	22,994	19,829
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	$ 1,620	$ 1,555

Fair Value Measurements (Deta50

Fair Value Measurements (Details Textuals) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Jun. 30, 2017	Sep. 30, 2017	Dec. 31, 2016
Fair Value of Financial Instruments [Line Items]
Investment excludes receivables, payables and accrued income		$ (13)	$ (3)
Cash balance excluded from available for sale securities		100	61
Investments not required to be disclosed		$ 255	266
NUG contracts
Fair Value of Financial Instruments [Line Items]
Period of future observable data to determine contract price		2 years
FES
Fair Value of Financial Instruments [Line Items]
Investment excludes receivables, payables and accrued income		$ (8)	2
Cash balance excluded from available for sale securities		$ 89	$ 44
NG | Beaver Valley Unit 2
Fair Value of Financial Instruments [Line Items]
NDT assets transferred	$ 189

Derivative Instruments (Details

Derivative Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Fair value of derivatives instruments
Derivative Assets	$ 40	$ 218
Derivative Liabilities	(106)	(238)
Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	35	140
Deferred Charges and Other Assets - Other
Fair value of derivatives instruments
Derivative Assets	5	78
Current Liabilities - Other
Fair value of derivatives instruments
Derivative Liabilities	(13)	(78)
Noncurrent Liabilities
Fair value of derivatives instruments
Derivative Liabilities	(93)	(160)
Commodity contracts | Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	30	133
Commodity contracts | Deferred Charges and Other Assets - Other
Fair value of derivatives instruments
Derivative Assets	5	77
Commodity contracts | Current Liabilities - Other
Fair value of derivatives instruments
Derivative Liabilities	(11)	(72)
Commodity contracts | Noncurrent Liabilities
Fair value of derivatives instruments
Derivative Liabilities	(1)	(52)
FTRs | Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	5	7
FTRs | Current Liabilities - Other
Fair value of derivatives instruments
Derivative Liabilities	(2)	(6)
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	(92)	(108)
FES
Fair value of derivatives instruments
Derivative Assets	36	214
Derivative Liabilities	(13)	(129)
FES | Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	31	137
FES | Deferred Charges and Other Assets - Other
Fair value of derivatives instruments
Derivative Assets	5	77
FES | Current Liabilities - Other
Fair value of derivatives instruments
Derivative Liabilities	(12)	(77)
FES | Noncurrent Liabilities
Fair value of derivatives instruments
Derivative Liabilities	(1)	(52)
FES | Commodity contracts | Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	30	133
FES | Commodity contracts | Deferred Charges and Other Assets - Other
Fair value of derivatives instruments
Derivative Assets	5	77
FES | Commodity contracts | Current Liabilities - Other
Fair value of derivatives instruments
Derivative Liabilities	(11)	(72)
FES | Commodity contracts | Noncurrent Liabilities
Fair value of derivatives instruments
Derivative Liabilities	(1)	(52)
FES | FTRs | Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	1	4
FES | FTRs | Current Liabilities - Other
Fair value of derivatives instruments
Derivative Liabilities	$ (1)	$ (5)

Derivative Instruments (Detai52

Derivative Instruments (Details 1) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Derivative Assets
Fair Value	$ 40	$ 218
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(11)	(123)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged	0	0
Net Fair Value	29	95
Derivative Liabilities
Fair Value	(106)	(238)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	11	123
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged	0	1
Net Fair Value	(95)	(114)
Commodity contracts
Derivative Assets
Fair Value	35	210
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(9)	(117)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged	0	0
Net Fair Value	26	93
Derivative Liabilities
Fair Value	(12)	(124)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	9	117
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged	0	1
Net Fair Value	(3)	(6)
FTRs
Derivative Assets
Fair Value	5	7
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(2)	(6)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged	0	0
Net Fair Value	3	1
Derivative Liabilities
Fair Value	(2)	(6)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	2	6
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged	0	0
Net Fair Value	0	0
NUGs
Derivative Assets
Fair Value		1
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments		0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged		0
Net Fair Value		1
Derivative Liabilities
Fair Value	(92)	(108)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	0	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged	0	0
Net Fair Value	(92)	(108)
FES
Derivative Assets
Fair Value	36	214
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(10)	(121)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged	0	0
Net Fair Value	26	93
Derivative Liabilities
Fair Value	(13)	(129)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	10	121
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged	0	2
Net Fair Value	(3)	(6)
FES | Commodity contracts
Derivative Assets
Fair Value	35	210
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(9)	(117)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged	0	0
Net Fair Value	26	93
Derivative Liabilities
Fair Value	(12)	(124)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	9	117
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged	0	1
Net Fair Value	(3)	(6)
FES | FTRs
Derivative Assets
Fair Value	1	4
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(1)	(4)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged	0	0
Net Fair Value	0	0
Derivative Liabilities
Fair Value	(1)	(5)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	1	4
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral Pledged	0	1
Net Fair Value	$ 0	$ 0

Derivative Instruments (Detai53

Derivative Instruments (Details 2) MWh in Millions	Sep. 30, 2017MWh
Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	1
Sales (in MWH or mmBTUs)	8
Net (in MWH or mmBTUs)	(7)
FTRs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	14
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	14
NUGs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	2
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	2
FES | Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	1
Sales (in MWH or mmBTUs)	8
Net (in MWH or mmBTUs)	(7)
FES | FTRs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	7
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	7

Derivative Instruments (Detai54

Derivative Instruments (Details 3) - Not Designated as Hedging Instrument - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	$ 7	$ 33	$ 48	$ 167
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	(3)	(22)	(14)	(105)
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	(11)	16	(64)	10
Realized Gain (Loss) Reclassified	(1)	(6)	(14)	(28)
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)
Commodity contracts | Revenues
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	8	32	48	162
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	(3)	(22)	(14)	(105)
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	(11)	19	(65)	2
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)
FTRs | Revenues
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	(1)	1	0	5
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	0	(3)	1	8
Realized Gain (Loss) Reclassified	(1)	(6)	(14)	(28)
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
FES | Revenues
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	7	33	48	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	(3)	(22)	(14)	(105)
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	(11)	16	(64)	10
Realized Gain (Loss) Reclassified	(1)	(6)	(14)	(28)
FES | Commodity contracts | Revenues
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	8	32	48	162
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	(3)	(22)	(14)	(105)
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	(11)	19	(65)	2
Realized Gain (Loss) Reclassified	0	0	0	0
FES | FTRs | Revenues
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	(1)	1	0	5
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	0	(3)	1	8
Realized Gain (Loss) Reclassified	$ (1)	$ (6)	$ (14)	$ (28)

Derivative Instruments (Detai55

Derivative Instruments (Details 4) - Not Designated as Hedging Instrument - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	$ (95)	$ (120)	$ (105)	$ (135)
Unrealized loss	(4)	(6)	(15)	(18)
Purchases			3	4
Settlements	10	12	28	35
Outstanding net asset (liability), Ending Balance	(89)	(114)	(89)	(114)
NUGs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(98)	(124)	(107)	(136)
Unrealized loss	(4)	(6)	(14)	(17)
Purchases			0	0
Settlements	10	12	29	35
Outstanding net asset (liability), Ending Balance	(92)	(118)	(92)	(118)
Regulated FTRs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	3	4	2	1
Unrealized loss	0	0	(1)	(1)
Purchases			3	4
Settlements	0	0	(1)	0
Outstanding net asset (liability), Ending Balance	$ 3	$ 4	$ 3	$ 4

Derivative Instruments (Detai56

Derivative Instruments (Details Textuals) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017USD ($)agreement	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)agreement	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)agreement
Derivative [Line Items]
Unamortized losses associated with designated cash flow hedges	$ 11		$ 11		$ 12
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			$ (6)
Cash Flow Hedges
Derivative [Line Items]
Cash flow hedge losses expected to be reclassified to earnings in next twelve months			2
Unamortized losses associated with prior interest rate hedges	$ 27		27		$ 33
Gains (losses) to be amortized to interest expenses during next twelve months			$ (8)
Number of outstanding commodity or interest rate derivatives | agreement	0		0		0
Cash Flow Hedges | FES
Derivative [Line Items]
Unamortized losses associated with prior interest rate hedges	$ 3		$ 3		$ 3
Fair Value Hedging
Derivative [Line Items]
Gains (losses) to be amortized to interest expenses during next twelve months			$ 2
Number of fixed-for-floating interest rate swap agreements outstanding | agreement	0		0		0
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	$ 4		$ 4		$ 10
Reclassifications from long-term debt	1	$ 2	6	$ 8
Commodity contracts
Derivative [Line Items]
Net asset (liability) position	23		23
Commodity contracts | FES
Derivative [Line Items]
Collateral posted	1		1
NUGs
Derivative [Line Items]
Liability position	92		92
FTRs
Derivative [Line Items]
Net asset (liability) position	3		3		1
FTRs | FES
Derivative [Line Items]
Net asset (liability) position	$ (1)		$ (1)		$ (1)

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Sep. 30, 2017	Dec. 31, 2016
FES | Beaver Valley, Davis-Besse and Perry Power Plants
Asset Retirement Obligations [Line Items]
Asset retirement obligation			$ 800	$ 713
FES | Beaver Valley Unit 2
Asset Retirement Obligations [Line Items]
ARO transferred	$ 73
FES | Perry Power Plant Unit 1
Asset Retirement Obligations [Line Items]
ARO transferred		$ 28
NG | Beaver Valley Unit 2
Asset Retirement Obligations [Line Items]
ARO transferred	$ 49

Regulatory Matters - Maryland a

Regulatory Matters - Maryland and New Jersey (Details) $ in Millions	Dec. 12, 2016USD ($)	Jul. 16, 2015	Feb. 27, 2013USD ($)	Sep. 30, 2017component	Sep. 30, 2017USD ($)component	Dec. 31, 2020USD ($)	Dec. 31, 2017USD ($)
New Jersey
Regulatory Matters [Line Items]
Number of supply components | component				2	2
PE | Maryland
Regulatory Matters [Line Items]
Incremental energy savings goal next 12 months		0.97%
Incremental energy savings goal thereafter		0.20%
Incremental energy savings goal		2.00%
Expenditures for cost recovery program incurred					$ 56
Recovery period for expenditures for cost recovery program		5 years		3 years
Expected infrastructure investments			$ 2,700
Period of expected infrastructure investments			15 years
JCP&L | NJBPU | New Jersey
Regulatory Matters [Line Items]
Approved amount of annual increase	$ 80
Scenario, Forecast | PE | Maryland
Regulatory Matters [Line Items]
Expenditures for cost recovery program						$ 116	$ 70
Recovery period for expenditures for cost recovery program						3 years

Regulatory Matters - Ohio (Deta

Regulatory Matters - Ohio (Details) $ in Millions	Oct. 12, 2016USD ($)	Apr. 15, 2016	Aug. 07, 2013USD ($)auction	Sep. 30, 2017USD ($)
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
Estimated cost of plans				$ 268
Credit to non-shopping customers			$ 43.4
Ohio | PUCO
Regulatory Matters [Line Items]
Proposed goal to reduce CO2 pollution (percent)	90.00%
Number of renewable energy auctions | auction			1
Ohio | Distribution Modernization Rider
Regulatory Matters [Line Items]
Amount of rider valuation	$ 558
Period of rider valuation	8 years
Ohio | Distribution Modernization Rider | PUCO
Regulatory Matters [Line Items]
Annual revenue cap for rider	$ 132.5
Recovery period	3 years
Possible extension period	2 years
Approved amount for rider	$ 204
Excessive earnings test exclusion period	3 years
Renewal period for excessive earnings test exclusion period	2 years
Ohio | Delivery Capital Recovery Rider | PUCO
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 | Energy Conservation, Economic Development and Job Retention | PUCO
Regulatory Matters [Line Items]
Contribution amount	$ 51

Regulatory Matters - Pennsylvan

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

Sep. 01, 2017USD ($)

Jun. 14, 2017USD ($)

Jan. 27, 2017USD ($)

Dec. 09, 2016USD ($)

Jun. 19, 2015

Mar. 31, 2016USD ($)

Sep. 30, 2017USD ($)proposal

Dec. 31, 2019USD ($)

Dec. 31, 2027MW

Dec. 31, 2020MW

Mar. 06, 2017USD ($)MW

Sep. 23, 2016program

Pennsylvania

Regulatory Matters [Line Items]

Number of RFP's | proposal

1

RFP term

2 years

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 | PPUC | EE&C Phase III

Regulatory Matters [Line Items]

Approved amount of annual increase

$ 390

Pennsylvania | ME

Regulatory Matters [Line Items]

Approved amount of annual increase

$ 96

Pennsylvania | ME | PPUC

Regulatory Matters [Line Items]

Demand reduction targets proposed

1.80%

Energy consumption reduction targets proposed

4.00%

Amount of requested rate increase (decrease)

$ 51.6

Pennsylvania | Penn

Regulatory Matters [Line Items]

Approved amount of annual increase

29

Pennsylvania | Penn | PPUC

Regulatory Matters [Line Items]

Demand reduction targets proposed

1.70%

Energy consumption reduction targets proposed

3.30%

Amount of requested rate increase (decrease)

58.9

Pennsylvania | WP

Regulatory Matters [Line Items]

Approved amount of annual increase

66

Pennsylvania | WP | PPUC

Regulatory Matters [Line Items]

Demand reduction targets proposed

1.80%

Energy consumption reduction targets proposed

2.60%

Amount of requested rate increase (decrease)

88.3

Pennsylvania | PN

Regulatory Matters [Line Items]

Approved amount of annual increase

$ 100

Pennsylvania | PN | PPUC

Regulatory Matters [Line Items]

Demand reduction targets proposed

0.00%

Energy consumption reduction targets proposed

3.90%

Amount of requested rate increase (decrease)

$ 60

West Virginia | WVPSC | VMP Surcharge Rates

Regulatory Matters [Line Items]

Amount of requested rate increase (decrease)

$ (15)

Requested rate decrease

1.00%

West Virginia | MP and PE | WVPSC

Regulatory Matters [Line Items]

Number of proposed efficient programs | program

3

Energy efficient reduction requirement (percent)

0.50%

Expenditures for cost recovery program

$ 10.4

West Virginia | MP and PE | WVPSC | ENEC

Regulatory Matters [Line Items]

Approved amount of annual increase

$ 25

Rate stabilization period

2 years

Scenario, Forecast | West Virginia | WVPSC | VMP Surcharge Rates

Regulatory Matters [Line Items]

Amount of additional requested rate increase (decrease)

$ (15)

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

Regulatory Matters [Line Items]

Capacity shortfall (in MW's) | MW

700

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

Regulatory Matters [Line Items]

Capacity shortfall (in MW's) | MW

850

Pleasants Power Station

Regulatory Matters [Line Items]

Plant capacity (in MW's) | MW

1,300

Held-for-sale | Pleasants Power Station

Regulatory Matters [Line Items]

Assets held for sale

$ 195

Regulatory Matters - Reliabilit

Regulatory Matters - Reliability Matters and FERC (Details) $ in Millions	Oct. 13, 2017	Aug. 30, 2017USD ($)	Mar. 10, 2017	Feb. 21, 2017	Jan. 19, 2017	Aug. 04, 2014	Jan. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2017USD ($)entityconditionsubsidiary	Sep. 30, 2016USD ($)	Dec. 31, 2012USD ($)
Regulatory Matters [Line Items]
Regional enforcement entities | entity									8
Impairment of assets (Note 14)									$ 162	$ 1,447
Purchase Agreement with Aspen Generating, LLC
Regulatory Matters [Line Items]
Cash purchase price		$ 825					$ 925
FES
Regulatory Matters [Line Items]
Impairment of assets (Note 14)									0	$ 540
MAIT
Regulatory Matters [Line Items]
Impairment of assets (Note 14)								$ 13
FERC
Regulatory Matters [Line Items]
Denied recovery charges of exit fees								78.8	$ 78.8
Number of conditions | condition									1
Market-based rate authority renewal period									3 years
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
Regulatory Matters [Line Items]
Approved ROE					8.11%
Requested return on equity				10.40%							10.40%
FERC | PATH | PATH Transmission Project
Regulatory Matters [Line Items]
Proposed return on equity											10.90%
Requested return on equity											10.40%
Return on equity granted for regional transmission organization participation											0.50%
Return on equity denied for regional transmission organization participation											0.50%
Remaining recovery period of regulatory assets											5 years
FERC | FET
Regulatory Matters [Line Items]
Number of stand-alone transmission subsidiaries | subsidiary									2
FERC | The Ohio Companies | ESP IV PPA
Regulatory Matters [Line Items]
Term of proposed purchase power agreement						8 years
FERC | MAIT
Regulatory Matters [Line Items]
Approved suspension period			5 months
Approved ROE									11.00%
Impairment of assets (Note 14)								$ 13
FERC | MAIT | Subsequent Event
Regulatory Matters [Line Items]
Approved ROE	10.30%
Approved equity capital structure	60.00%
FERC | JCP&L
Regulatory Matters [Line Items]
Approved suspension period			5 months

Commitments, Guarantees and C62

Commitments, Guarantees and Contingencies (Details) - USD ($)	9 Months Ended
	Sep. 30, 2017	Jan. 31, 2017
Guarantor Obligations [Line Items]
Guarantor obligations	$ 412,000,000
At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	8,000,000
Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	42,000,000
Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	$ 362,000,000
Curing period	30 days
Regulated
Guarantor Obligations [Line Items]
Guarantor obligations	$ 147,000,000
Regulated | At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	0
Regulated | Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	42,000,000
Regulated | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	105,000,000
FirstEnergy
Guarantor Obligations [Line Items]
Guarantor obligations	185,000,000
FirstEnergy | At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	0
FirstEnergy | Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	0
FirstEnergy | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	185,000,000
FES
Guarantor Obligations [Line Items]
Guarantor obligations	54,000,000
FES | At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	6,000,000
FES | Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	0
FES | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	48,000,000
FES | Surety Bond (Collateralized Amount) | Little Bull Run | PA DEP
Guarantor Obligations [Line Items]
Amount of surety bond		$ 169,000,000
AE Supply
Guarantor Obligations [Line Items]
Guarantor obligations	26,000,000
AE Supply | At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	2,000,000
AE Supply | Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	0
AE Supply | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	$ 24,000,000

Commitments, Guarantees and C63

Commitments, Guarantees and Contingencies (Details Textuals)	May 01, 2017USD ($)installment	Dec. 22, 2016T	Aug. 03, 2015T	Mar. 31, 2017USD ($)	Sep. 30, 2017USD ($)phaseT	Dec. 31, 2016USD ($)
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated					$ 3,300,000,000
New syndicated senior secured term loan facility					$ 412,000,000
Proposed goal to reduce CO2 pollution (percent)					90.00%
Nuclear plant decommissioning trusts					$ 2,632,000,000	$ 2,514,000,000
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					$ 131,000,000
Environmental liabilities former gas facilities					84,000,000
Nuclear Plant Matters
Guarantor Obligations [Line Items]
Nuclear plant decommissioning trusts					$ 2,600,000,000
Caa Compliance
Guarantor Obligations [Line Items]
Amount remaining under contract | T					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
Settled Litigation | Caa Compliance
Guarantor Obligations [Line Items]
Loss recognized in period				$ 55,000,000
Regulated Distribution
Guarantor Obligations [Line Items]
Company posted collateral related to net liability positions					$ 3,000,000
FES
Guarantor Obligations [Line Items]
Company posted collateral related to net liability positions					128,000,000
New syndicated senior secured term loan facility					54,000,000
Nuclear plant decommissioning trusts					1,823,000,000	$ 1,552,000,000
FES | Nuclear Plant Matters
Guarantor Obligations [Line Items]
Nuclear plant decommissioning trusts					1,800,000,000
FES | Settled Litigation | Caa Compliance
Guarantor Obligations [Line Items]
Loss recognized in period				$ 55,000,000
FES | Competitive Energy Services
Guarantor Obligations [Line Items]
New syndicated senior secured term loan facility					2,000,000
Global Holding | Senior Secured Term Loan | Senior Loans
Guarantor Obligations [Line Items]
New syndicated senior secured term loan facility					$ 300,000,000
Global Holding | Senior Secured Term Loan | Senior Loans | Signal Peak, Global Rail and Affiliates
Guarantor Obligations [Line Items]
Investment ownership percentage					69.99%
FEV | Senior Secured Term Loan | Senior Loans | Signal Peak | Global Holding
Guarantor Obligations [Line Items]
Investment ownership percentage					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%
FG | Settled Litigation | Caa Compliance
Guarantor Obligations [Line Items]
Settlement amount	$ 109,000,000
Number of installment payments | installment	3
AE Supply
Guarantor Obligations [Line Items]
Company posted collateral related to net liability positions					$ 2,000,000
New syndicated senior secured term loan facility					26,000,000
Minimum | Clean Water Act
Guarantor Obligations [Line Items]
Capital investment required to install technology to meet TDS and Sulfate limits					150,000,000
Maximum | Clean Water Act
Guarantor Obligations [Line Items]
Capital investment required to install technology to meet TDS and Sulfate limits					300,000,000
Certain Coal-Fired Power Plant | FG | Mercury and Air Toxic Standards
Guarantor Obligations [Line Items]
Minimum coal supply commitment (ton) | T			3,500,000
Another Coal-Fired Power Plant | FG | 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					649,000,000
Subsidiaries
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated					1,900,000,000
Other Guarantee
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated					300,000,000
Other Assurances
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated					457,000,000
Line of Credit | Revolving Credit Facility
Guarantor Obligations [Line Items]
Maximum amount borrowed under revolving credit facility					500,000,000
Line of Credit | Revolving Credit Facility | Nuclear Plant Matters
Guarantor Obligations [Line Items]
Maximum amount borrowed under revolving credit facility					500,000,000
NG | Financial Guarantee | FES | Nuclear Plant Matters
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated					$ 400,000,000

Supplemental Guarantor Inform64

Supplemental Guarantor Information (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Consolidating Statements of Income
Revenues	[1]	$ 3,714	$ 3,917	$ 10,575	$ 11,187
OPERATING EXPENSES:
Fuel		363	450	1,074	1,269
Purchased power		861	979	2,459	2,992
Other operating expenses		942	953	3,041	2,835
Provision for depreciation		289	311	845	974
General taxes		253	265	777	786
Impairment of assets		31	0	162	1,447
Total operating expenses		2,830	3,056	8,573	10,525
OPERATING INCOME		884	861	2,002	662
OTHER INCOME (EXPENSE):
Investment income (loss), including net income (loss) from equity investees		37	28	78	75
Interest expense		(305)	(286)	(882)	(863)
Capitalized interest		19	28	59	79
Total other expense		(249)	(230)	(745)	(709)
INCOME (LOSS) BEFORE INCOME TAXES		635	631	1,257	(47)
INCOME TAXES (BENEFITS)		239	251	482	334
NET INCOME (LOSS)		396	380	775	(381)
NET INCOME		396	380	775	(381)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(19)	(18)	(55)	(54)
Amortized gains on derivative hedges		4	2	8	6
Change in unrealized gains on available-for-sale securities		(6)	4	8	67
Other comprehensive income (loss)		(21)	(12)	(39)	19
Income taxes (benefits) on other comprehensive income (loss)		(9)	(5)	(16)	6
Other comprehensive income (loss), net of tax		(12)	(7)	(23)	13
COMPREHENSIVE INCOME (LOSS)		$ 384	373	$ 752	(368)
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		$ (521)	(859)	$ (1,869)	(2,593)
OPERATING EXPENSES:
Fuel		0	0	0	0
Other operating expenses		12	11	36	37
Provision for depreciation		(1)	0	(2)	(2)
General taxes		0	0	0	0
Impairment of assets					0
Total operating expenses		(510)	(848)	(1,835)	(2,558)
OPERATING INCOME		(11)	(11)	(34)	(35)
OTHER INCOME (EXPENSE):
Investment income (loss), including net income (loss) from equity investees		(121)	(236)	(383)	(342)
Miscellaneous income		0	0	0	0
Capitalized interest		0	0	0	0
Total other expense		(91)	(207)	(286)	(260)
INCOME (LOSS) BEFORE INCOME TAXES		(102)	(218)	(320)	(295)
INCOME TAXES (BENEFITS)		1	2	3	4
NET INCOME (LOSS)		(103)	(220)	(323)	(299)
NET INCOME		(103)	(220)	(323)	(299)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		3	3	10	10
Amortized gains on derivative hedges		0	0	0	0
Change in unrealized gains on available-for-sale securities		6	(5)	(16)	(60)
Other comprehensive income (loss)		9	(2)	(6)	(50)
Income taxes (benefits) on other comprehensive income (loss)		3	(1)	(2)	(19)
Other comprehensive income (loss), net of tax		6	(1)	(4)	(31)
COMPREHENSIVE INCOME (LOSS)		(97)	(221)	(327)	(330)
Eliminations | Affiliates
OPERATING EXPENSES:
Purchased power		(521)	(859)	(1,869)	(2,593)
OTHER INCOME (EXPENSE):
Interest expense		16	15	55	39
Eliminations | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense		14	14	42	43
FES
Consolidating Statements of Income
Revenues		741	1,065	2,338	3,281
OPERATING EXPENSES:
Fuel		0	0	0	0
Other operating expenses		70	95	247	218
Provision for depreciation		3	4	9	10
General taxes		4	8	15	23
Impairment of assets					23
Total operating expenses		749	1,304	2,733	3,991
OPERATING INCOME		(8)	(239)	(395)	(710)
OTHER INCOME (EXPENSE):
Investment income (loss), including net income (loss) from equity investees		106	224	335	310
Miscellaneous income		1	0	1	3
Capitalized interest		0	0	0	0
Total other expense		75	197	243	239
INCOME (LOSS) BEFORE INCOME TAXES		67	(42)	(152)	(471)
INCOME TAXES (BENEFITS)		(9)	(82)	(167)	(204)
NET INCOME (LOSS)		76	40	15	(267)
NET INCOME		76	40	15	(267)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(3)	(3)	(10)	(10)
Amortized gains on derivative hedges		1	1	1	0
Change in unrealized gains on available-for-sale securities		(6)	5	16	61
Other comprehensive income (loss)		(8)	3	7	51
Income taxes (benefits) on other comprehensive income (loss)		(3)	1	2	20
Other comprehensive income (loss), net of tax		(5)	2	5	31
COMPREHENSIVE INCOME (LOSS)		71	42	20	(236)
FES | Affiliates
OPERATING EXPENSES:
Purchased power		520	1,011	1,994	2,888
OTHER INCOME (EXPENSE):
Interest expense		(20)	(13)	(58)	(34)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power		152	186	468	829
OTHER INCOME (EXPENSE):
Interest expense		(12)	(14)	(35)	(40)
FG
Consolidating Statements of Income
Revenues		231	494	941	1,309
OPERATING EXPENSES:
Fuel		108	149	312	449
Other operating expenses		62	61	345	220
Provision for depreciation		8	28	24	91
General taxes		3	7	16	23
Impairment of assets					517
Total operating expenses		181	245	697	1,300
OPERATING INCOME		50	249	244	9
OTHER INCOME (EXPENSE):
Investment income (loss), including net income (loss) from equity investees		11	8	31	21
Miscellaneous income		0	1	0	1
Capitalized interest		0	3	1	7
Total other expense		(17)	(18)	(55)	(57)
INCOME (LOSS) BEFORE INCOME TAXES		33	231	189	(48)
INCOME TAXES (BENEFITS)		6	87	66	(1)
NET INCOME (LOSS)		27	144	123	(47)
NET INCOME		27	144	123	(47)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(3)	(3)	(10)	(10)
Amortized 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)	(10)
Income taxes (benefits) on other comprehensive income (loss)		(1)	(1)	(4)	(4)
Other comprehensive income (loss), net of tax		(2)	(2)	(6)	(6)
COMPREHENSIVE INCOME (LOSS)		25	142	117	(53)
FG | Affiliates
OPERATING EXPENSES:
Purchased power		0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense		(3)	(3)	(9)	(7)
FG | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense		(25)	(27)	(78)	(79)
NG
Consolidating Statements of Income
Revenues		292	400	988	1,404
OPERATING EXPENSES:
Fuel		57	53	151	146
Other operating expenses		147	149	467	450
Provision for depreciation		18	51	49	151
General taxes		(2)	6	13	20
Impairment of assets					0
Total operating expenses		221	298	757	912
OPERATING INCOME		71	102	231	492
OTHER INCOME (EXPENSE):
Investment income (loss), including net income (loss) from equity investees		43	28	91	67
Miscellaneous income		0	0	5	0
Capitalized interest		6	6	19	20
Total other expense		39	23	81	50
INCOME (LOSS) BEFORE INCOME TAXES		110	125	312	542
INCOME TAXES (BENEFITS)		34	49	112	196
NET INCOME (LOSS)		76	76	200	346
NET INCOME		76	76	200	346
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		0	0	0	0
Amortized gains on derivative hedges		0	0	0	0
Change in unrealized gains on available-for-sale securities		(6)	5	16	60
Other comprehensive income (loss)		(6)	5	16	60
Income taxes (benefits) on other comprehensive income (loss)		(2)	2	6	23
Other comprehensive income (loss), net of tax		(4)	3	10	37
COMPREHENSIVE INCOME (LOSS)		72	79	210	383
NG | Affiliates
OPERATING EXPENSES:
Purchased power		1	39	77	145
OTHER INCOME (EXPENSE):
Interest expense		1	(2)	(1)	(4)
NG | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense		(11)	(9)	(33)	(33)
Consolidated
Consolidating Statements of Income
Revenues		743	1,100	2,398	3,401
OPERATING EXPENSES:
Fuel		165	202	463	595
Other operating expenses		291	316	1,095	925
Provision for depreciation		28	83	80	250
General taxes		5	21	44	66
Impairment of assets		0	0	0	540
Total operating expenses		641	999	2,352	3,645
OPERATING INCOME		102	101	46	(244)
OTHER INCOME (EXPENSE):
Investment income (loss), including net income (loss) from equity investees		39	24	74	56
Miscellaneous income		1	1	6	4
Capitalized interest		6	9	20	27
Total other expense		6	(5)	(17)	(28)
INCOME (LOSS) BEFORE INCOME TAXES		108	96	29	(272)
INCOME TAXES (BENEFITS)		32	56	14	(5)
NET INCOME (LOSS)		76	40	15	(267)
NET INCOME		76	40	15	(267)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(3)	(3)	(10)	(10)
Amortized gains on derivative hedges		1	1	1	0
Change in unrealized gains on available-for-sale securities		(6)	5	16	61
Other comprehensive income (loss)		(8)	3	7	51
Income taxes (benefits) on other comprehensive income (loss)		(3)	1	2	20
Other comprehensive income (loss), net of tax		(5)	2	5	31
COMPREHENSIVE INCOME (LOSS)		71	42	20	(236)
Consolidated | Affiliates
OPERATING EXPENSES:
Purchased power		0	191	202	440
OTHER INCOME (EXPENSE):
Interest expense		(6)	(3)	(13)	(6)
Consolidated | Non-Affiliates
OPERATING EXPENSES:
Purchased power		152	186	468	829
OTHER INCOME (EXPENSE):
Interest expense		$ (34)	$ (36)	$ (104)	$ (109)
[1]	Includes excise tax collections of $102 million and $111 million in the three months ended September 30, 2017 and 2016, respectively, and $293 million and $310 million in the nine months ended September 30, 2017 and 2016, respectively.

Supplemental Guarantor Inform65

Supplemental Guarantor Information (Details 1) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 399	$ 199	$ 551	$ 131
Receivables-
Customers	1,370	1,440
Other	172	175
Materials and supplies	543	564
Derivatives	35	140
Collateral	146	176
Prepaid taxes and other	143	158
Total current assets	2,931	2,950
PROPERTY, PLANT AND EQUIPMENT:
In service	44,229	43,767
Less — Accumulated provision for depreciation	16,086	15,731
Property, plant and equipment in service net of accumulated provision for depreciation	28,143	28,036
Construction work in progress	1,355	1,351
Total net property, plant and equipment	29,498	29,387
INVESTMENTS:
Nuclear plant decommissioning trusts	2,632	2,514
Other	511	512
Total other property and investments	3,143	3,026
DEFERRED CHARGES AND OTHER ASSETS:
Other	742	1,153
Total deferred charges and other assets	7,289	7,785
Total assets	43,649	43,148	51,961
CURRENT LIABILITIES:
Currently payable long-term debt	1,076	1,685
Accounts payable-
Accrued taxes	520	580
Other	867	738
Total current liabilities	4,255	7,126
CAPITALIZATION:
Total equity	6,406	6,241
Long-term debt and other long-term obligations	21,089	18,192
Total capitalization	27,495	24,433
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	732	757
Accumulated deferred income taxes	4,225	3,765
Retirement benefits	3,814	3,719
Asset retirement obligations	1,550	1,482
Other	1,435	1,704
Total noncurrent liabilities	11,899	11,589
Total liabilities and capitalization	43,649	43,148
Eliminations
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	(235)	(612)
Other	0	0
Notes receivable from affiliated companies	(3,610)	(3,351)
Materials and supplies	0	0
Derivatives	0	0
Collateral	0	0
Prepaid taxes and other	0	0
Total current assets	(3,845)	(3,963)
PROPERTY, PLANT AND EQUIPMENT:
In service	(281)	(290)
Less — Accumulated provision for depreciation	(189)	(187)
Property, plant and equipment in service net of accumulated provision for depreciation	(92)	(103)
Construction work in progress	0	0
Total net property, plant and equipment	(92)	(103)
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	(3,347)	(2,923)
Other	0	0
Total other property and investments	(3,347)	(2,923)
DEFERRED CHARGES AND OTHER ASSETS:
Property taxes	0	0
Accumulated deferred income tax benefits	(273)	(270)
Derivatives	0	0
Other	10	21
Total deferred charges and other assets	(263)	(249)
Total assets	(7,547)	(7,238)
CURRENT LIABILITIES:
Currently payable long-term debt	(27)	(26)
Accounts payable-
Affiliated companies	(329)	(706)
Other	0	0
Accrued taxes	(15)	(16)
Derivatives	0	0
Other	33	36
Total current liabilities	(3,948)	(4,063)
CAPITALIZATION:
Total equity	(3,247)	(2,834)
Long-term debt and other long-term obligations	(1,079)	(1,091)
Total capitalization	(4,326)	(3,925)
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	732	757
Accumulated deferred income taxes	(5)	(7)
Retirement benefits	0	0
Asset retirement obligations	0	0
Other	0	0
Total noncurrent liabilities	727	750
Total liabilities and capitalization	(7,547)	(7,238)
Eliminations | Affiliates
CURRENT LIABILITIES:
Short-term borrowings - affiliated companies	(3,610)	(3,351)
FES
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	171	213
Affiliated companies	194	332
Other	9	17
Notes receivable from affiliated companies	364	501
Materials and supplies	34	45
Derivatives	31	137
Collateral	101	157
Prepaid taxes and other	12	38
Total current assets	916	1,440
PROPERTY, PLANT AND EQUIPMENT:
In service	121	120
Less — Accumulated provision for depreciation	61	52
Property, plant and equipment in service net of accumulated provision for depreciation	60	68
Construction work in progress	2	2
Total net property, plant and equipment	62	70
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	3,347	2,923
Other	0	0
Total other property and investments	3,347	2,923
DEFERRED CHARGES AND OTHER ASSETS:
Property taxes	0	0
Accumulated deferred income tax benefits	428	395
Derivatives	5	77
Other	31	33
Total deferred charges and other assets	464	505
Total assets	4,789	4,938
CURRENT LIABILITIES:
Currently payable long-term debt	0	0
Accounts payable-
Affiliated companies	329	743
Other	11	17
Accrued taxes	16	50
Derivatives	10	71
Other	28	56
Total current liabilities	3,693	3,906
CAPITALIZATION:
Total equity	328	218
Long-term debt and other long-term obligations	691	691
Total capitalization	1,019	909
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	5	4
Retirement benefits	26	25
Asset retirement obligations	0	0
Other	46	94
Total noncurrent liabilities	77	123
Total liabilities and capitalization	4,789	4,938
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings - affiliated companies	3,299	2,969
FG
CURRENT ASSETS:
Cash and cash equivalents	2	2	2	2
Receivables-
Customers	0	0
Affiliated companies	175	315
Other	4	2
Notes receivable from affiliated companies	1,765	1,585
Materials and supplies	147	142
Derivatives	0	0
Collateral	25	0
Prepaid taxes and other	16	24
Total current assets	2,134	2,070
PROPERTY, PLANT AND EQUIPMENT:
In service	2,587	2,524
Less — Accumulated provision for depreciation	1,942	1,920
Property, plant and equipment in service net of accumulated provision for depreciation	645	604
Construction work in progress	45	67
Total net property, plant and equipment	690	671
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	0	0
Other	9	9
Total other property and investments	9	9
DEFERRED CHARGES AND OTHER ASSETS:
Property taxes	2	12
Accumulated deferred income tax benefits	1,212	1,271
Derivatives	0	0
Other	328	327
Total deferred charges and other assets	1,542	1,610
Total assets	4,375	4,360
CURRENT LIABILITIES:
Currently payable long-term debt	180	200
Accounts payable-
Affiliated companies	87	107
Other	87	93
Accrued taxes	12	48
Derivatives	2	6
Other	92	54
Total current liabilities	957	991
CAPITALIZATION:
Total equity	946	828
Long-term debt and other long-term obligations	1,941	2,093
Total capitalization	2,887	2,921
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	0	3
Retirement benefits	181	172
Asset retirement obligations	187	188
Other	163	85
Total noncurrent liabilities	531	448
Total liabilities and capitalization	4,375	4,360
FG | Affiliates
CURRENT LIABILITIES:
Short-term borrowings - affiliated companies	497	483
NG
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	193	417
Other	0	8
Notes receivable from affiliated companies	1,481	1,294
Materials and supplies	82	80
Derivatives	0	0
Collateral	0	0
Prepaid taxes and other	1	1
Total current assets	1,757	1,800
PROPERTY, PLANT AND EQUIPMENT:
In service	5,016	4,703
Less — Accumulated provision for depreciation	4,309	4,144
Property, plant and equipment in service net of accumulated provision for depreciation	707	559
Construction work in progress	241	358
Total net property, plant and equipment	948	917
INVESTMENTS:
Nuclear plant decommissioning trusts	1,823	1,552
Investment in affiliated companies	0	0
Other	0	1
Total other property and investments	1,823	1,553
DEFERRED CHARGES AND OTHER ASSETS:
Property taxes	4	28
Accumulated deferred income tax benefits	690	883
Derivatives	0	0
Other	0	0
Total deferred charges and other assets	694	911
Total assets	5,222	5,181
CURRENT LIABILITIES:
Currently payable long-term debt	114	5
Accounts payable-
Affiliated companies	143	406
Other	0	0
Accrued taxes	19	61
Derivatives	0	0
Other	14	10
Total current liabilities	290	482
CAPITALIZATION:
Total equity	2,301	2,006
Long-term debt and other long-term obligations	1,006	1,120
Total capitalization	3,307	3,126
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	0	0
Retirement benefits	0	0
Asset retirement obligations	801	713
Other	824	860
Total noncurrent liabilities	1,625	1,573
Total liabilities and capitalization	5,222	5,181
NG | Affiliates
CURRENT LIABILITIES:
Short-term borrowings - affiliated companies	0	0
Consolidated
CURRENT ASSETS:
Cash and cash equivalents	2	2	$ 2	$ 2
Receivables-
Customers	171	213
Affiliated companies	327	452
Other	13	27
Notes receivable from affiliated companies	0	29
Materials and supplies	263	267
Derivatives	31	137
Collateral	126	157
Prepaid taxes and other	29	63
Total current assets	962	1,347
PROPERTY, PLANT AND EQUIPMENT:
In service	7,443	7,057
Less — Accumulated provision for depreciation	6,123	5,929
Property, plant and equipment in service net of accumulated provision for depreciation	1,320	1,128
Construction work in progress	288	427
Total net property, plant and equipment	1,608	1,555
INVESTMENTS:
Nuclear plant decommissioning trusts	1,823	1,552
Investment in affiliated companies	0	0
Other	9	10
Total other property and investments	1,832	1,562
DEFERRED CHARGES AND OTHER ASSETS:
Property taxes	6	40
Accumulated deferred income tax benefits	2,057	2,279
Derivatives	5	77
Other	369	381
Total deferred charges and other assets	2,437	2,777
Total assets	6,839	7,241
CURRENT LIABILITIES:
Currently payable long-term debt	267	179
Accounts payable-
Affiliated companies	230	550
Other	98	110
Accrued taxes	32	143
Derivatives	12	77
Other	167	156
Total current liabilities	992	1,316
CAPITALIZATION:
Total equity	328	218
Long-term debt and other long-term obligations	2,559	2,813
Total capitalization	2,887	3,031
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	732	757
Accumulated deferred income taxes	0	0
Retirement benefits	207	197
Asset retirement obligations	988	901
Other	1,033	1,039
Total noncurrent liabilities	2,960	2,894
Total liabilities and capitalization	6,839	7,241
Consolidated | Affiliates
CURRENT LIABILITIES:
Short-term borrowings - affiliated companies	$ 186	$ 101

Supplemental Guarantor Inform66

Supplemental Guarantor Information (Details 2) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Consolidated Statements of Cash Flows [Abstract]
NET CASH (USED FOR) PROVIDED FROM OPERATING ACTIVITIES			$ 2,762	$ 2,592
New Financing-
Long-term debt			4,050	521
Short-term borrowings, net			0	1,275
Redemptions and Repayments-
Long-term debt			(1,711)	(1,017)
Other			(67)	(17)
Net cash (used for) provided from financing activities			(381)	304
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	$ (593)	$ (664)	(1,847)	(2,156)
Nuclear fuel			(156)	(195)
Sales of investment securities held in trusts			1,923	1,361
Purchases of investment securities held in trusts			(1,995)	(1,437)
Other			24	52
Net cash used for investing activities			(2,181)	(2,476)
Net change in cash and cash equivalents			200	420
Cash and cash equivalents at beginning of period			199	131	$ 131
Cash and cash equivalents at end of period	399	551	399	551	199
Eliminations
Consolidated Statements of Cash Flows [Abstract]
NET CASH (USED FOR) PROVIDED FROM OPERATING ACTIVITIES			(13)	(12)
New Financing-
Long-term debt				0
Short-term borrowings, net			(259)	(692)
Redemptions and Repayments-
Long-term debt			13	12
Other			0	0
Net cash (used for) provided from financing activities			(246)	(680)
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
Loans to affiliated companies, net			259	692
Other			0	0
Net cash used for investing activities			259	692
Net change in cash and cash equivalents			0	0
Cash and cash equivalents at beginning of period			0	0	0
Cash and cash equivalents at end of period	0	0	0	0	0
FES
Consolidated Statements of Cash Flows [Abstract]
NET CASH (USED FOR) PROVIDED FROM OPERATING ACTIVITIES			(463)	(605)
New Financing-
Long-term debt				0
Short-term borrowings, net			330	701
Redemptions and Repayments-
Long-term debt			0	0
Other			0	0
Net cash (used for) provided from financing activities			330	701
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(1)	(28)
Nuclear fuel			0	0
Sales of investment securities held in trusts			0	0
Purchases of investment securities held in trusts			0	0
Loans to affiliated companies, net			137	(87)
Other			(3)	19
Net cash used for investing activities			133	(96)
Net change in cash and cash equivalents			0	0
Cash and cash equivalents at beginning of period			0	0	0
Cash and cash equivalents at end of period	0	0	0	0	0
FG
Consolidated Statements of Cash Flows [Abstract]
NET CASH (USED FOR) PROVIDED FROM OPERATING ACTIVITIES			387	402
New Financing-
Long-term debt				186
Short-term borrowings, net			14	92
Redemptions and Repayments-
Long-term debt			(171)	(211)
Other			(5)	(6)
Net cash (used for) provided from financing activities			(162)	61
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(46)	(171)
Nuclear fuel			0	0
Sales of investment securities held in trusts			0	0
Purchases of investment securities held in trusts			0	0
Loans to affiliated companies, net			(179)	(292)
Other			0	0
Net cash used for investing activities			(225)	(463)
Net change in cash and cash equivalents			0	0
Cash and cash equivalents at beginning of period			2	2	2
Cash and cash equivalents at end of period	2	2	2	2	2
NG
Consolidated Statements of Cash Flows [Abstract]
NET CASH (USED FOR) PROVIDED FROM OPERATING ACTIVITIES			547	820
New Financing-
Long-term debt				285
Short-term borrowings, net			0	0
Redemptions and Repayments-
Long-term debt			(5)	(304)
Other			0	(2)
Net cash (used for) provided from financing activities			(5)	(21)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(154)	(233)
Nuclear fuel			(156)	(195)
Sales of investment securities held in trusts			834	576
Purchases of investment securities held in trusts			(878)	(619)
Loans to affiliated companies, net			(188)	(328)
Other			0	0
Net cash used for investing activities			(542)	(799)
Net change in cash and cash equivalents			0	0
Cash and cash equivalents at beginning of period			0	0	0
Cash and cash equivalents at end of period	0	0	0	0	0
Consolidated
Consolidated Statements of Cash Flows [Abstract]
NET CASH (USED FOR) PROVIDED FROM OPERATING ACTIVITIES			458	605
New Financing-
Long-term debt			0	471
Short-term borrowings, net			85	101
Redemptions and Repayments-
Long-term debt			(163)	(503)
Other			(5)	(8)
Net cash (used for) provided from financing activities			(83)	61
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(201)	(432)
Nuclear fuel			(156)	(195)
Sales of investment securities held in trusts			834	576
Purchases of investment securities held in trusts			(878)	(619)
Loans to affiliated companies, net			29	(15)
Other			(3)	19
Net cash used for investing activities			(375)	(666)
Net change in cash and cash equivalents			0	0
Cash and cash equivalents at beginning of period			2	2	2
Cash and cash equivalents at end of period	$ 2	$ 2	$ 2	$ 2	$ 2

Segment Information (Details Te

Segment Information (Details Textuals) mi² in Thousands, customer in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)mi²customercompanyMW	Mar. 07, 2017MW	Mar. 06, 2017MW
Pleasants Power Station
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment			1,300
Purchase Agreement with LS Power
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment	1,615
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	3,790
Competitive Energy Services
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment	13,162	10,000	13,000
Competitive Energy Services | Pleasants Power Station
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment	1,300
Other/Corporate
Segment Reporting Information [Line Items]
Long-term debt and other long-term obligations | $	$ 6,800
Long-term debt subject to variable rates | $	1,450
FirstEnergy | Revolving Credit Facility | Other/Corporate
Segment Reporting Information [Line Items]
Long-term line of credit | $	$ 500

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Segment Financial Information
Revenues		$ 3,714	$ 3,917	$ 10,575	$ 11,187
Revenues	[1]	3,714	3,917	10,575	11,187
Depreciation		289	311	845	974
Amortization of regulatory assets, net		91	98	215	222
Impairment of assets (Note 14)		31	0	162	1,447
Investment income		37	28	78	75
Interest expense		305	286	882	863
Income taxes (benefits)		239	251	482	334
NET INCOME (LOSS)		396	380	775	(381)
Total assets		43,649	51,961	43,649	51,961	$ 43,148
Goodwill		5,618	5,618	5,618	5,618	$ 5,618
Property additions		593	664	1,847	2,156
Regulated Distribution
Segment Financial Information
Impairment of assets (Note 14)		0
Regulated Transmission
Segment Financial Information
Impairment of assets (Note 14)		13
Competitive Energy Services
Segment Financial Information
Impairment of assets (Note 14)		18
Other Business Operations [Member]
Segment Financial Information
Impairment of assets (Note 14)		0
Reconciling Adjustments [Member]
Segment Financial Information
Impairment of assets (Note 14)		0
Operating Segments | Regulated Distribution
Segment Financial Information
Revenues		2,610	2,691	7,362	7,390
Revenues		2,610	2,691	7,362	7,390
Depreciation		183	169	540	504
Amortization of regulatory assets, net		85	98	204	218
Impairment of assets (Note 14)				0	0
Investment income		13	13	41	37
Interest expense		133	143	405	441
Income taxes (benefits)		183	162	442	336
NET INCOME (LOSS)		314	276	756	573
Total assets		27,866	27,818	27,866	27,818
Goodwill		5,004	5,004	5,004	5,004
Property additions		286	281	854	809
Operating Segments | Regulated Transmission
Segment Financial Information
Revenues		342	294	982	851
Revenues		342	294	982	851
Depreciation		59	47	164	138
Amortization of regulatory assets, net		6	0	11	4
Impairment of assets (Note 14)				13	0
Investment income		0	0	0	0
Interest expense		38	39	116	118
Income taxes (benefits)		49	50	154	143
NET INCOME (LOSS)		84	85	264	244
Total assets		9,356	8,492	9,356	8,492
Goodwill		614	614	614	614
Property additions		248	268	717	824
Operating Segments | Competitive Energy Services
Segment Financial Information
Revenues		796	998	2,388	3,158
Revenues		889	1,115	2,684	3,535
Depreciation		30	79	87	284
Amortization of regulatory assets, net		0	0	0	0
Impairment of assets (Note 14)				149	1,447
Investment income		34	23	66	56
Interest expense		44	48	136	143
Income taxes (benefits)		40	49	(25)	(96)
NET INCOME (LOSS)		66	86	(57)	(1,029)
Total assets		5,814	15,165	5,814	15,165
Goodwill		0	0	0	0
Property additions		45	110	233	492
Corporate/Other
Segment Financial Information
Revenues		0	0	0	0
Revenues		0	0	0	0
Depreciation		17	16	54	48
Amortization of regulatory assets, net		0	0	0	0
Impairment of assets (Note 14)				0	0
Investment income		3	2	8	13
Interest expense		90	56	225	161
Income taxes (benefits)		(33)	(10)	(89)	(49)
NET INCOME (LOSS)		(68)	(67)	(188)	(169)
Total assets		613	486	613	486
Goodwill		0	0	0	0
Property additions		14	5	43	31
Intersegment Eliminations
Segment Financial Information
Revenues		(93)	(117)	(296)	(377)
Intersegment Eliminations | Competitive Energy Services
Segment Financial Information
Revenues		93	117	296	377
Reconciling Adjustments
Segment Financial Information
Revenues		(34)	(66)	(157)	(212)
Revenues		(127)	(183)	(453)	(589)
Depreciation		0	0	0	0
Amortization of regulatory assets, net		0	0	0	0
Impairment of assets (Note 14)				0	0
Investment income		(13)	(10)	(37)	(31)
Interest expense		0	0	0	0
Income taxes (benefits)		0	0	0	0
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 $102 million and $111 million in the three months ended September 30, 2017 and 2016, respectively, and $293 million and $310 million in the nine months ended September 30, 2017 and 2016, respectively.

Asset Impairments (Details 1)

Asset Impairments (Details 1) $ in Millions

Oct. 20, 2017

Aug. 30, 2017

Aug. 30, 2017MW

Aug. 30, 2017Natural_gas_plant

Aug. 30, 2017transmission_center

Aug. 30, 2017USD ($)

Aug. 30, 2017

Aug. 30, 2017limited_guaranty

Jul. 22, 2016MW

Jan. 31, 2017USD ($)MW

Sep. 30, 2017USD ($)

Sep. 30, 2016USD ($)

Jun. 30, 2016USD ($)

Sep. 30, 2017USD ($)

Sep. 30, 2016USD ($)

Dec. 31, 2016USD ($)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Impairment of assets

$ 647

Impairment of assets (Note 14)

$ 162

$ 1,447

Impairment

800

$ 800

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

158

Competitive Energy Services | Income Approach Valuation Technique

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

$ 517

Impairment of assets (Note 14)

0

$ 540

Impairment

$ 23

Loss on contract termination

$ 32

MAIT

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Impairment of assets (Note 14)

$ 13

Purchase Agreement with Aspen Generating, LLC

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Plant capacity (in MW's) | MW

1,615

1,572

Cash purchase price

$ 825

$ 925

Number of limited guaranties

2

2

Term of guaranties

3 years

Purchase Agreement with Aspen Generating, LLC | AE Supply

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Number of gas generating plants | Natural_gas_plant

4

Discharge of note indenture

305

Make-whole premiums

$ 100

Purchase Agreement with Aspen Generating, LLC | AGC

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Ownership percentage

59.00%

Purchase Agreement with Aspen Generating, LLC | AGC | Subsequent Event

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Ownership percentage

59.00%

Purchase Agreement with Aspen Generating, LLC | BU Energy

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Ownership percentage

50.00%

Purchase Agreement with Aspen Generating, LLC | Buchanan Power Station [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Plant capacity (in MW's) | MW

43

Disposal Group | Bay Shore Unit 1

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Plant capacity (in MW's) | MW

136

Disposal Group | 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

Held-for-sale

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Assets held-for-sale

765

765

Investments

20

20

Inventory

4

4

Asset retirement obligations

$ 1

$ 1