FirstEnergy (FE) 10-Q 27 Apr 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	3 Months Ended
	Mar. 31, 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	Mar. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding	443,740,014
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	Mar. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding	7

Consolidated Statements of Inco

Consolidated Statements of Income (FirstEnergy Corp.) - USD ($) shares in Millions, $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
REVENUES:
Regulated Distribution		$ 2,490	$ 2,510
Regulated Transmission		313	286
Unregulated businesses		749	1,073
Total revenues	[1]	3,552	3,869
OPERATING EXPENSES:
Fuel		368	381
Purchased power		863	1,124
Other operating expenses		1,142	918
Provision for depreciation		275	329
Amortization of regulatory assets, net		59	61
General taxes		271	280
Total operating expenses		2,978	3,093
OPERATING INCOME		574	776
OTHER INCOME (EXPENSE):
Investment income		24	28
Interest expense		(287)	(288)
Capitalized financing costs		20	25
Total other expense		(243)	(235)
INCOME BEFORE INCOME TAXES		331	541
INCOME TAXES		126	213
NET INCOME		$ 205	$ 328
EARNINGS PER SHARE OF COMMON STOCK:
Basic, in dollars per share		$ 0.46	$ 0.78
Diluted, in dollars per share		$ 0.46	$ 0.77
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic, in shares		443	424
Diluted, in shares		444	426
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share		$ 0.72	$ 0.72
Excise taxes collected		$ 100	$ 107
[1]	Includes excise tax collections of $100 million and $107 million in the three months ended March 31, 2017 and 2016, respectively.

Consolidated Statements of Inc3

Consolidated Statements of Income (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Statement [Abstract]
Excise taxes collected	$ 100	$ 107

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (FirstEnergy Corp.) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 205	$ 328
OTHER COMPREHENSIVE INCOME:
Pension and OPEB prior service costs	(18)	(18)
Amortized losses on derivative hedges	3	2
Change in unrealized gains on available-for-sale securities	16	28
Other comprehensive income	1	12
Income taxes on other comprehensive income	0	4
Other comprehensive income, net of tax	1	8
COMPREHENSIVE INCOME	$ 206	$ 336

Consolidated Balance Sheets (Fi

Consolidated Balance Sheets (FirstEnergy Corp.) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
CURRENT ASSETS:
Cash and cash equivalents	$ 164	$ 199
Receivables-
Customers, net of allowance for uncollectible accounts of $52 in 2017 and $53 in 2016	1,396	1,440
Other, net of allowance for uncollectible accounts of $1 in 2017 and 2016	155	175
Materials and supplies	531	564
Prepaid taxes	202	98
Derivatives	43	140
Collateral	122	176
Other	147	158
Total current assets	2,760	2,950
PROPERTY, PLANT AND EQUIPMENT:
In service	42,976	43,767
Less — Accumulated provision for depreciation	15,769	15,731
Property, plant and equipment in service net of accumulated provision for depreciation	27,207	28,036
Construction work in progress	1,588	1,351
Total net property, plant and equipment	28,795	29,387
INVESTMENTS:
Nuclear plant decommissioning trusts	2,571	2,514
Other	519	512
Total other property and investments	3,090	3,026
ASSETS HELD FOR SALE (Note 1)	921	0
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	5,618	5,618
Regulatory assets	1,000	1,014
Other	1,028	1,153
Total deferred charges and other assets	7,646	7,785
Total assets	43,212	43,148
CURRENT LIABILITIES:
Currently payable long-term debt	2,147	1,685
Short-term borrowings	2,750	2,675
Accounts payable	977	1,043
Accrued taxes	555	580
Accrued compensation and benefits	307	363
Derivatives	27	78
Collateral	46	42
Other	848	660
Total current liabilities	7,657	7,126
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 490,000,000 shares - 443,740,014 and 442,344,218 shares outstanding as of March 31, 2017 and December 31, 2016, respectively	44	44
Other paid-in capital	10,253	10,555
Accumulated other comprehensive income	175	174
Accumulated deficit	(4,333)	(4,532)
Total common stockholders’ equity	6,139	6,241
Long-term debt and other long-term obligations	17,762	18,192
Total capitalization	23,901	24,433
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	3,882	3,765
Retirement benefits	3,756	3,719
Asset retirement obligations	1,505	1,482
Deferred gain on sale and leaseback transaction	748	757
Adverse power contract liability	157	162
Other	1,606	1,704
Total noncurrent liabilities	11,654	11,589
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
Total liabilities and capitalization	$ 43,212	$ 43,148

Consolidated Balance Sheets (F6

Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Common stockholders’ equity-
Common stock, par value (in dollars per share)	$ 0.1	$ 0.1
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	443,740,014	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	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 205	$ 328
Adjustments to reconcile net income to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs	392	461
Deferred purchased power and other costs	23	(10)
Deferred income taxes and investment tax credits, net	114	206
Deferred costs on sale leaseback transaction, net	12	12
Retirement benefits, net of payments	10	16
Pension trust contributions	0	(160)
Commodity derivative transactions, net (Note 8)	47	(64)
Changes in current assets and liabilities-
Receivables	68	1
Materials and supplies	11	4
Prepaid taxes and other current assets	(111)	(82)
Accounts payable	45	25
Accrued taxes	(131)	(110)
Accrued compensation and benefits	(137)	(102)
Other current liabilities	20	66
Collateral, net	58	(6)
Other	159	65
Net cash provided from operating activities	785	650
New Financing-
Long-term debt	250	0
Short-term borrowings, net	75	425
Redemptions and Repayments-
Long-term debt	(211)	(31)
Common stock dividend payments	(159)	(152)
Other	(13)	(12)
Net cash (used for) provided from financing activities	(58)	230
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(588)	(698)
Nuclear fuel	(132)	(149)
Sales of investment securities held in trusts	738	465
Purchases of investment securities held in trusts	(761)	(488)
Asset removal costs	(35)	(34)
Other	16	39
Net cash used for investing activities	(762)	(865)
Net change in cash and cash equivalents	(35)	15
Cash and cash equivalents at beginning of period	199	131
Cash and cash equivalents at end of period	$ 164	$ 146

Consolidated Statements of Inc8

Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) (FirstEnergy Solutions Corp.) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
REVENUES:
Electric sales		$ 749	$ 1,073
Total revenues	[1]	3,552	3,869
OPERATING EXPENSES:
Fuel		368	381
Purchased power		863	1,124
Other operating expenses		1,142	918
Provision for depreciation		275	329
General taxes		271	280
Total operating expenses		2,978	3,093
OPERATING INCOME		574	776
OTHER INCOME (EXPENSE):
Investment income		24	28
Interest expense		(287)	(288)
Capitalized financing costs		20	25
Total other expense		(243)	(235)
INCOME BEFORE INCOME TAXES		331	541
INCOME TAXES		126	213
NET INCOME		205	328
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME		205	328
OTHER COMPREHENSIVE INCOME:
Pension and OPEB prior service costs		(18)	(18)
Change in unrealized gains on available-for-sale securities		16	28
Other comprehensive income		1	12
Income taxes (benefits) on other comprehensive income (loss)		0	4
Other comprehensive income, net of tax		1	8
COMPREHENSIVE INCOME		206	336
FES
REVENUES:
Other		35	45
Total revenues		914	1,199
OPERATING EXPENSES:
Fuel		144	165
Other operating expenses		518	240
Provision for depreciation		25	83
General taxes		21	26
Total operating expenses		1,031	973
OPERATING INCOME		(117)	226
OTHER INCOME (EXPENSE):
Investment income		20	13
Miscellaneous income		5	2
Capitalized financing costs		8	10
Total other expense		(4)	(13)
INCOME BEFORE INCOME TAXES		(121)	213
INCOME TAXES		(41)	82
NET INCOME		(80)	131
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME		(80)	131
OTHER COMPREHENSIVE INCOME:
Pension and OPEB prior service costs		(3)	(4)
Change in unrealized gains on available-for-sale securities		16	23
Other comprehensive income		13	19
Income taxes (benefits) on other comprehensive income (loss)		5	7
Other comprehensive income, net of tax		8	12
COMPREHENSIVE INCOME		(72)	143
FES | Affiliates
REVENUES:
Electric sales		111	147
OPERATING EXPENSES:
Purchased power		163	82
OTHER INCOME (EXPENSE):
Interest expense		(2)	(2)
FES | Non-Affiliates
REVENUES:
Electric sales		768	1,007
OPERATING EXPENSES:
Purchased power		160	377
OTHER INCOME (EXPENSE):
Interest expense		$ (35)	$ (36)
[1]	Includes excise tax collections of $100 million and $107 million in the three months ended March 31, 2017 and 2016, respectively.

Consolidated Balance Sheets (F9

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
CURRENT ASSETS:
Cash and cash equivalents	$ 164	$ 199
Receivables-
Customers, net of allowance for uncollectible accounts of $4 in 2017 and $5 in 2016	1,396	1,440
Other	155	175
Materials and supplies	531	564
Derivatives	43	140
Collateral	122	176
Prepaid taxes and other	147	158
Total current assets	2,760	2,950
PROPERTY, PLANT AND EQUIPMENT:
In service	42,976	43,767
Less — Accumulated provision for depreciation	15,769	15,731
Property, plant and equipment in service net of accumulated provision for depreciation	27,207	28,036
Construction work in progress	1,588	1,351
Total net property, plant and equipment	28,795	29,387
INVESTMENTS:
Nuclear plant decommissioning trusts	2,571	2,514
Other	519	512
Total other property and investments	3,090	3,026
DEFERRED CHARGES AND OTHER ASSETS:
Other	1,028	1,153
Total deferred charges and other assets	7,646	7,785
Total assets	43,212	43,148
CURRENT LIABILITIES:
Currently payable long-term debt	2,147	1,685
Accounts payable-
Accrued taxes	555	580
Derivatives	27	78
Other	848	660
Total current liabilities	7,657	7,126
Common stockholders’ equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of March 31, 2017 and December 31, 2016	44	44
Accumulated other comprehensive income	175	174
Accumulated deficit	(4,333)	(4,532)
Total common stockholders’ equity	6,139	6,241
Long-term debt and other long-term obligations	17,762	18,192
Total capitalization	23,901	24,433
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	748	757
Retirement benefits	3,756	3,719
Asset retirement obligations	1,505	1,482
Other	1,606	1,704
Total noncurrent liabilities	11,654	11,589
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
Total liabilities and capitalization	43,212	43,148
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2
Receivables-
Customers, net of allowance for uncollectible accounts of $4 in 2017 and $5 in 2016	173	213
Affiliated companies	376	452
Other	51	27
Notes receivable from affiliated companies	0	29
Materials and supplies	252	267
Derivatives	43	137
Collateral	107	157
Prepaid taxes and other	51	63
Total current assets	1,055	1,347
PROPERTY, PLANT AND EQUIPMENT:
In service	7,108	7,057
Less — Accumulated provision for depreciation	5,998	5,929
Property, plant and equipment in service net of accumulated provision for depreciation	1,110	1,128
Construction work in progress	488	427
Total net property, plant and equipment	1,598	1,555
INVESTMENTS:
Nuclear plant decommissioning trusts	1,593	1,552
Other	10	10
Total other property and investments	1,603	1,562
DEFERRED CHARGES AND OTHER ASSETS:
Property taxes	30	40
Accumulated deferred income taxes	2,268	2,279
Derivatives	17	77
Other	393	381
Total deferred charges and other assets	2,708	2,777
Total assets	6,964	7,241
CURRENT LIABILITIES:
Currently payable long-term debt	150	179
Accounts payable-
Affiliated companies	316	550
Other	107	110
Accrued taxes	137	143
Derivatives	25	77
Other	194	156
Total current liabilities	1,043	1,316
Common stockholders’ equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of March 31, 2017 and December 31, 2016	3,658	3,658
Accumulated other comprehensive income	77	69
Accumulated deficit	(3,589)	(3,509)
Total common stockholders’ equity	146	218
Long-term debt and other long-term obligations	2,812	2,813
Total capitalization	2,958	3,031
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	748	757
Retirement benefits	202	197
Asset retirement obligations	915	901
Derivatives	3	52
Other	1,095	987
Total noncurrent liabilities	2,963	2,894
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
Total liabilities and capitalization	6,964	7,241
FES | Affiliated Companies
CURRENT LIABILITIES:
Affiliated companies	$ 114	$ 101

Consolidated Balance Sheets (10

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Common stockholders’ equity-
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	443,740,014	442,344,218
FES
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 4	$ 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	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 205	$ 328
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	392	461
Deferred costs on sale and leaseback transaction, net	12	12
Deferred income taxes and investment tax credits, net	114	206
Commodity derivative transactions, net (Note 8)	47	(64)
Changes in current assets and liabilities-
Receivables	68	1
Materials and supplies	11	4
Prepaid taxes and other current assets	(111)	(82)
Accounts payable	45	25
Accrued taxes	(131)	(110)
Other current liabilities	20	66
Collateral, net	58	(6)
Other	159	65
Net cash provided from operating activities	785	650
New financing-
Short-term borrowings, net	75	425
Redemptions and Repayments-
Long-term debt	(211)	(31)
Other	(13)	(12)
Net cash (used for) provided from financing activities	(58)	230
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(588)	(698)
Nuclear fuel	(132)	(149)
Sales of investment securities held in trusts	738	465
Purchases of investment securities held in trusts	(761)	(488)
Other	16	39
Net cash used for investing activities	(762)	(865)
Net change in cash and cash equivalents	(35)	15
Cash and cash equivalents at beginning of period	199	131
Cash and cash equivalents at end of period	164	146
FES
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	(80)	131
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	78	138
Deferred costs on sale and leaseback transaction, net	12	12
Deferred income taxes and investment tax credits, net	6	113
Investment impairments	3	8
Commodity derivative transactions, net (Note 8)	47	(64)
Changes in current assets and liabilities-
Receivables	92	2
Materials and supplies	(2)	24
Prepaid taxes and other current assets	11	(12)
Accounts payable	(126)	(103)
Accrued taxes	(16)	(15)
Other current liabilities	21	4
Collateral, net	50	(10)
Other	125	1
Net cash provided from operating activities	221	229
New financing-
Short-term borrowings, net	13	49
Redemptions and Repayments-
Long-term debt	(29)	0
Other	(3)	(3)
Net cash (used for) provided from financing activities	(19)	46
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(85)	(143)
Nuclear fuel	(132)	(149)
Sales of investment securities held in trusts	231	138
Purchases of investment securities held in trusts	(245)	(151)
Cash investments	0	10
Loans to affiliated companies, net	29	11
Other	0	9
Net cash used for investing activities	(202)	(275)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	2	2
Cash and cash equivalents at end of period	$ 2	$ 2

Organization and Basis of Prese

Organization and Basis of Presentation	3 Months Ended
	Mar. 31, 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 six million customers in the Midwest and Mid-Atlantic regions. Its regulated and unregulated generation subsidiaries control nearly 17,000 MW of capacity from a diverse mix of non-emitting nuclear, scrubbed coal, natural gas, hydroelectric and other renewables. FirstEnergy’s transmission operations include approximately 24,000 miles of lines and two regional transmission operation centers. 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. FES purchases the entire output of the generation facilities owned by FG and NG, and the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements, and pursuant to full output, cost-of-service PSAs. 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 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 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 the three months ended March 31, 2017 and 2016 , capitalized financing costs on FirstEnergy's Consolidated Statements of Income include $8 million of allowance for equity funds used during construction and $12 million and $17 million , respectively, of capitalized interest. 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 prolonged decrease in demand and excess generation supply in the PJM Region, which has resulted in a period of protracted low power and capacity prices. 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 continue to be weak, as evidenced by the significantly depressed 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 that it had begun a strategic review of its competitive operations as it transitions to a fully regulated utility with a target to implement its exit from competitive operations by mid-2018. As a result of this strategic review, FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement to sell four of AE Supply’s natural gas generating plants and approximately 59% of AGC’s interest in Bath County ( 1,572 MWs of combined capacity) for an all-cash purchase price of $925 million , subject to customary and other closing conditions, including 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. As a further condition to closing, FE will provide the purchaser two limited guarantees of certain obligations of AE Supply and AGC arising under the purchase agreement. The guarantees vary in amount and scope and expire in one and three years, respectively. Assets held for sale as of March 31, 2017 include the property, plant and equipment (net of accumulated provision for depreciation) of $919 million , materials and supplies inventory of $3 million and asset retirement obligations of approximately $1 million . 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. In addition, on March 7, 2017, MP and AE Supply filed applications with the WVPSC and FERC requesting authorization for such purchase. The strategic options to exit the remaining portion of CES' generation 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, • Additional asset sales and/or plant deactivations, • Restructuring FES debt with its creditors, and/or • Seeking protection under U.S. bankruptcy laws for FES and possibly FENOC. Furthermore, the strategic options, and the timing thereof, could be impacted by various events, including but not limited to, the following: • The FES debt maturities, interest payments and sale-leaseback commitments due in June 2017. • The outcome of the recently announced directive by the Secretary of Energy to complete a study by mid-June 2017 that explores critical issues central to protecting the long-term reliability of the electric grid, including the impact of federal policy interventions and the changing nature of electricity fuel mix, compensation of on-site fuel supply and other factors that strengthen grid resilience, and the impact of regulatory burdens, mandates and tax and subsidy policies on the premature retirement of baseload power plants. • The resolution of recently introduced legislation before the Ohio General Assembly that would create a zero-emission nuclear (ZEN) credit that would compensate nuclear power plants for their environmental attributes and the potential for ZEN legislative action in Pennsylvania. • The inability to finalize and consummate settlement agreements with the parties to the previously disclosed disputes regarding long-term coal transportation contracts as discussed in "Environmental Matters" below, whereby FG could be subject to materially higher damages owed to CSX, BNSF and NS. 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 sale of AE Supply's natural gas generating plants and AGC’s interest in Bath County, as well as the transfer of the Pleasants Power station to MP, the size and generation capacity of CES’ portfolio will reduce to approximately 10,000 MWs with approximately 60 - 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 that have lowered the value of the business. 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 negative outlook from each of the rating agencies has challenged its ability to hedge generation with retail and forward wholesale sales due to collateral requirements that otherwise would reduce available liquidity. A lack of viable alternative strategies for its competitive portfolio has and would further stress the financial condition of FES. 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 35 - 40 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 March 31, 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. As previously disclosed, FES has $130 million of debt maturities in June of 2017 (and $515 million of maturing debt in 2018 beginning in the second quarter). Additionally, FES has interest payments and sale-leaseback commitments of $108 million due in June of 2017. 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, even on a secured basis. Failure to refinance the debt would further stress FES' anticipated liquidity. It is uncertain whether FES would use currently available liquidity to make upcoming debt and other payments. 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 require FES to restructure debt and other financial obligations with its creditors or seek protection under U.S. bankruptcy laws. In the event FES seeks protection under U.S. bankruptcy laws, FENOC may similarly 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 legislative efforts to explore a regulatory solution, these obligations and their impact on 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. New Accounting Pronouncements In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers". Subsequent accounting standards updates have been issued which amend and/or clarify the application of ASU 2014-09. The core principle of the new guidance is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. More detailed disclosures will also be required to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For public business entities, the new revenue recognition guidance will be effective for annual and interim reporting periods beginning after December 15, 2017. Earlier adoption is permitted for annual and interim reporting periods beginning after December 15, 2016. FirstEnergy will not early adopt the standards. The standards shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy has evaluated its revenues and expects limited impacts to current revenue recognition practices, dependent on the resolution of industry issues. FirstEnergy continues to assess the impact on its financial statements and disclosures as well as which transition method it will select to adopt the guidance. In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption for certain provisions can be elected for all financial statements of fiscal years and interim periods that have not yet been issued or that have not yet been made available for issuance. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted . Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment . FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In March of 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", which simplifies several aspects of the accounting for employee share-based 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 activity by reclassifying $12 million from operating activity to financing activity in the 2016 Statement of Cash Flow. In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”, which removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted for fiscal years beginning after December 15, 2018. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments". The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows, including the presentation of debt prepayment or debt extinguishment costs, all of which will be classified as financing activities. The guidance 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. In October 2016, the FASB issued ASU 2016-16, " Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory." ASU 2016-16 eliminates the exception for all intra-entity sales of assets other than inventory, which allows companies to defer the tax effects of intra-entity asset transfers. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the intra-entity transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted and the modified retrospective approach will be required for transition to the new guidance, with a cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" that will require entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2019. Early adoption in an interim period is permitted, but any adjustments must be reflected as of the beginning of the fiscal year that includes that interim period. FirstEnergy does not expect this ASU to have a material effect on its financial statements. On January 5, 2017, the FASB issued ASU 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business" that clarifies the definition of a business and assists entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The guidance 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. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. On March 10, 2017, the FASB issued ASU 2017-07, "Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost", which amends the requirements related to the presentation of the components of net periodic benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. ASU 2017-07 requires entities to (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. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. Additionally, during 2017, the FASB issued the following ASUs: • ASU 2017-03, "Accounting Changes and Error Corrections (Topic 250) and Investments—Equity Method and Joint Ventures (Topic 323): Amendments to SEC Paragraphs Pursuant to Staff Announcements at the September 22, 2016 and November 17, 2016 EITF Meetings (SEC Update),” • ASU 2017-04, "Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,” • ASU 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets" and • ASU 2017-08, "Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities." FirstEnergy does not expect these ASUs to have a material effect on its financial statements.

Earnings Per Share Of Common St

Earnings Per Share Of Common Stock	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
EARNINGS PER SHARE OF COMMON STOCK	EARNINGS PER SHARE OF COMMON STOCK Basic earnings per share of common stock are computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. As discussed above, FirstEnergy adopted ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting" beginning January 1, 2017. As of March 31, 2017 and March 31, 2016 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 per share of common stock: (In millions, except per share amounts) For the Three Months Ended March 31 Reconciliation of Basic and Diluted Earnings per Share of Common Stock 2017 2016 Net income $ 205 $ 328 Weighted average number of basic shares outstanding 443 424 Assumed exercise of dilutive stock options and awards (1) 1 2 Weighted average number of diluted shares outstanding 444 426 Basic earnings per share of common stock $ 0.46 $ 0.78 Diluted earnings per share of common stock $ 0.46 $ 0.77 (1) For both the three months ended March 31 , 2017 and March 31 , 2016 , one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

Pension and Other Postemploymen

Pension and Other Postemployment Benefits	3 Months Ended
	Mar. 31, 2017
Compensation and Retirement Disclosure [Abstract]
PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS	PENSION AND OTHER POSTEMPLOYMENT BENEFITS The components of the consolidated net periodic cost (credits) for pension and OPEB (including amounts capitalized) were as follows: Components of Net Periodic Benefit Costs (Credits) Pension OPEB For the Three Months Ended March 31 2017 2016 2017 2016 (In millions) Service costs $ 52 $ 48 $ 1 $ 1 Interest costs 97 100 7 7 Expected return on plan assets (112 ) (97 ) (8 ) (8 ) Amortization of prior service costs (credits) 2 2 (20 ) (20 ) Net periodic costs (credits) $ 39 $ 53 $ (20 ) $ (20 ) 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 March 31 $ 3 $ 6 $ (4 ) $ (4 ) 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 March 31 2017 2016 2017 2016 (In millions) FirstEnergy $ 32 $ 37 $ (15 ) $ (15 ) FES 3 6 (4 ) (4 ) As of March 31, 2017, and December 31, 2016, FES has $866 million of affiliated non-current liabilities related to allocated pension and OPEB mark-to-market costs, of which $570 million is from FENOC.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	3 Months Ended
	Mar. 31, 2017
Equity [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME	ACCUMULATED OTHER COMPREHENSIVE INCOME The changes in AOCI, net of tax, in the three months ended March 31, 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 January 1, 2017 $ (28 ) $ 52 $ 150 $ 174 Other comprehensive income before reclassifications — 32 — 32 Amounts reclassified from AOCI 3 (16 ) (18 ) (31 ) Other comprehensive income (loss) 3 16 (18 ) 1 Income taxes (benefits) on other comprehensive income (loss) 1 5 (6 ) — Other comprehensive income (loss), net of tax 2 11 (12 ) 1 AOCI Balance as of March 31, 2017 $ (26 ) $ 63 $ 138 $ 175 AOCI Balance as of January 1, 2016 $ (33 ) $ 18 $ 186 $ 171 Other comprehensive income before reclassifications — 41 — 41 Amounts reclassified from AOCI 2 (13 ) (18 ) (29 ) Other comprehensive income (loss) 2 28 (18 ) 12 Income taxes (benefits) on other comprehensive income (loss) 1 10 (7 ) 4 Other comprehensive income (loss), net of tax 1 18 (11 ) 8 AOCI Balance as of March 31, 2016 $ (32 ) $ 36 $ 175 $ 179 The following amounts were reclassified from AOCI for FirstEnergy in the three months ended March 31, 2017 and 2016 : For the Three Months Ended March 31 Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (2) 2017 2016 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ — Other operating expenses Long-term debt 3 2 Interest expense 3 2 Total before taxes (1 ) (1 ) Income taxes $ 2 $ 1 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (16 ) $ (13 ) Investment income 6 5 Income taxes $ (10 ) $ (8 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (18 ) $ (18 ) (1) 6 7 Income taxes $ (12 ) $ (11 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI. The changes in AOCI, net of tax, in the three months ended March 31, 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 January 1, 2017 $ (9 ) $ 48 $ 30 $ 69 Other comprehensive income before reclassifications — 31 — 31 Amounts reclassified from AOCI — (15 ) (3 ) (18 ) Other comprehensive income (loss) — 16 (3 ) 13 Income taxes (benefits) on other comprehensive income (loss) — 6 (1 ) 5 Other comprehensive income (loss), net of tax — 10 (2 ) 8 AOCI Balance as of March 31, 2017 $ (9 ) $ 58 $ 28 $ 77 AOCI Balance as of January 1, 2016 $ (9 ) $ 16 $ 39 $ 46 Other comprehensive income before reclassifications — 36 — 36 Amounts reclassified from AOCI — (13 ) (4 ) (17 ) Other comprehensive income (loss) — 23 (4 ) 19 Income tax (benefits) on other comprehensive income (loss) — 9 (2 ) 7 Other comprehensive income (loss), net of tax — 14 (2 ) 12 AOCI Balance as of March 31, 2016 $ (9 ) $ 30 $ 37 $ 58 The following amounts were reclassified from AOCI for FES in the three months ended March 31, 2017 and 2016 : For the Three Months Ended March 31 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2017 2016 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ — Other operating expenses — — Income taxes (benefits) $ — $ — Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (15 ) $ (13 ) Investment income 6 5 Income taxes (benefits) $ (9 ) $ (8 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (3 ) $ (4 ) (1) 1 2 Income taxes (benefits) $ (2 ) $ (2 ) 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	3 Months Ended
	Mar. 31, 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 March 31, 2017 and 2016 was 38.1% and 39.4% , respectively. The decrease in the effective tax rate is primarily due to tax benefits recognized in the first quarter of 2017. FES’ effective tax rate for the three months ended March 31, 2017 and 2016 was 33.9% on pre-tax losses and 38.5% on pre-tax income, respectively. The change in the effective tax rate is primarily due to valuation allowances on state tax benefits resulting from charges associated with long-term coal transportation contract disputes, as discussed in Note 10, Commitments, Guarantees, and Contingencies. As of March 31, 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 February 2017, the IRS completed its examination of FirstEnergy's 2015 federal income tax return and issued a Full Acceptance Letter with no changes or adjustments to FirstEnergy's taxable income or effective tax rate.

Variable Interest Entities

Variable Interest Entities	3 Months Ended
	Mar. 31, 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): • PNBV Trust - PNBV , a business trust established by OE in 1996, issued certain beneficial interests and notes to fund the acquisition of a portion of the bonds issued by certain owner trusts in connection with the sale and leaseback in 1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. The beneficial ownership of PNBV includes a 3% interest by unaffiliated third parties. • Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly-owned limited liability companies (SPEs) which issued phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase-in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of March 31, 2017 and December 31, 2016 , $327 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. In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consist primarily of bondable transition property. As of March 31, 2017 and December 31, 2016 , $74 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 special purpose limited liability companies own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's and PE's West Virginia service territories. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the special purpose limited liability companies, have no recourse to any assets or revenues of the special purpose limited liability companies. As of March 31, 2017 and December 31, 2016 , $395 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 10, 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 had previously suspended in February 2011, 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 March 31, 2017 and 2016 were $28 million and $31 million , respectively. • Sale and Leaseback Transactions - OE and FES have obligations that are not included on their Consolidated Balance Sheets related to the Beaver Valley Unit 2 and 2007 Bruce Mansfield Unit 1 sale and leaseback arrangements, respectively, which are satisfied through operating lease payments. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the arrangements. As of March 31, 2017, OE's leasehold interest was 2.60% of Beaver Valley Unit 2 and FES' leasehold interest was 93.83% of Bruce Mansfield Unit 1. On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors' interests in Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), for a combined $38 million , which right to repurchase, but not the obligation, was assigned to NG in 2014. If NG exercises that right, upon the completion of the repurchase, NG will have obtained all of the lessor equity interests at Beaver Valley Unit 2. Therefore, upon the expiration of the Beaver Valley Unit 2 leases, NG will be the sole owner of Beaver Valley Unit 2 and entitled to 100% of the unit's output. If NG does not exercise the repurchase right, OE will be obligated to repurchase these interests and, upon completion of the repurchase and expiration of the leases, will be the owner of a 2.60% interest in the unit and entitled to a pro rata share of the unit’s output. FES and other FE subsidiaries are exposed to losses under their applicable sale and leaseback agreements upon the occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions as of March 31, 2017 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy $ 1,133 $ 894 $ 239 FES 1,113 890 223

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 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 three years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on ICE quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of March 31, 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 three months ended March 31, 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 March 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,244 $ — $ 1,244 $ — $ 1,247 $ — $ 1,247 Derivative assets - commodity contracts — 60 — 60 10 200 — 210 Derivative assets - FTRs — — — — — — 7 7 Derivative assets - NUG contracts (1) — — — — — — 1 1 Equity securities (2) 982 — — 982 925 — — 925 Foreign government debt securities — 95 — 95 — 78 — 78 U.S. government debt securities — 152 — 152 — 161 — 161 U.S. state debt securities — 250 — 250 — 246 — 246 Other (3) 164 128 — 292 199 123 — 322 Total assets $ 1,146 $ 1,929 $ — $ 3,075 $ 1,134 $ 2,055 $ 8 $ 3,197 Liabilities Derivative liabilities - commodity contracts $ — $ (26 ) $ — $ (26 ) $ (6 ) $ (118 ) $ — $ (124 ) Derivative liabilities - FTRs — — (4 ) (4 ) — — (6 ) (6 ) Derivative liabilities - NUG contracts (1) — — (103 ) (103 ) — — (108 ) (108 ) Total liabilities $ — $ (26 ) $ (107 ) $ (133 ) $ (6 ) $ (118 ) $ (114 ) $ (238 ) Net assets (liabilities) (4) $ 1,146 $ 1,903 $ (107 ) $ 2,942 $ 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 $(14) million and $(3) million as of March 31, 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 March 31, 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 — (6 ) (6 ) — (1 ) (1 ) Settlements (1 ) 11 10 (7 ) 3 (4 ) March 31, 2017 Balance $ — $ (103 ) $ (103 ) $ — $ (4 ) $ (4 ) (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 March 31, 2017 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ (4 ) Model RTO auction clearing prices $(2.70) to $2.90 $0.30 Dollars/MWH NUG Contracts $ (103 ) Model Generation 400 to 2,766,000 560,000 MWH Regional electricity prices $31.70 to $33.60 $31.70 Dollars/MWH FES Recurring Fair Value Measurements March 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 746 $ — $ 746 $ — $ 726 $ — $ 726 Derivative assets - commodity contracts — 60 — 60 10 200 — 210 Derivative assets - FTRs — — — — — — 4 4 Equity securities (1) 667 — — 667 634 — — 634 Foreign government debt securities — 62 — 62 — 58 — 58 U.S. government debt securities — 30 — 30 — 48 — 48 U.S. state debt securities — 3 — 3 — 3 — 3 Other (2) 2 87 — 89 2 81 — 83 Total assets $ 669 $ 988 $ — $ 1,657 $ 646 $ 1,116 $ 4 $ 1,766 Liabilities Derivative liabilities - commodity contracts $ — $ (26 ) $ — $ (26 ) $ (6 ) $ (118 ) $ — $ (124 ) Derivative liabilities - FTRs — — (2 ) (2 ) — — (5 ) (5 ) Total liabilities $ — $ (26 ) $ (2 ) $ (28 ) $ (6 ) $ (118 ) $ (5 ) $ (129 ) Net assets (liabilities) (3) $ 669 $ 962 $ (2 ) $ 1,629 $ 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 $(2) million and $2 million as of March 31, 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 March 31, 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 ) Settlements (4 ) 3 (1 ) March 31, 2017 Balance $ — $ (2 ) $ (2 ) Level 3 Quantitative Information The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2017 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ (2 ) Model RTO auction clearing prices ($2.70) to $2.40 $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. 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 March 31, 2017 and December 31, 2016 : March 31, 2017 (1) December 31, 2016 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,746 $ 38 $ 1,784 $ 1,735 $ 38 $ 1,773 FES 855 28 883 847 27 874 Equity securities FirstEnergy $ 852 $ 130 $ 982 $ 822 $ 103 $ 925 FES 578 89 667 564 70 634 (1) Excludes short-term cash investments: FirstEnergy - $53 million ; FES - $43 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 months ended March 31, 2017 and 2016 were as follows: For the Three Months Ended March 31, 2017 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 738 $ 85 $ (63 ) $ (3 ) $ 23 FES 231 64 (48 ) (3 ) 14 March 31, 2016 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 465 $ 61 $ (50 ) $ (9 ) $ 23 FES 138 42 (29 ) (8 ) 13 Held-To-Maturity Securities Unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of March 31, 2017 and December 31, 2016 are immaterial to FirstEnergy. Investments in employee benefit trusts and equity method investments totaling $269 million as of March 31, 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: March 31, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 19,921 $ 20,029 $ 19,885 $ 19,829 FES 2,971 1,424 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 March 31, 2017 and December 31, 2016 .

Derivative Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 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 March 31, 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 $31 million (FES $3 million ) and $33 million (FES $3 million ) as of March 31, 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 months ended March 31, 2017 and 2016 . As of March 31, 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 March 31, 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 $8 million and $10 million as of March 31, 2017 and December 31, 2016 , respectively. During the next twelve months, approximately $5 million of unamortized gains are expected to be amortized to interest expense. 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 March 31, 2017 , FirstEnergy’s net asset position under commodity derivative contracts was $34 million , which related to FES positions. Under these commodity derivative contracts, FES posted $1 million of collateral. Based on commodity derivative contracts held as of March 31, 2017 , an increase in commodity prices of 10% would decrease net income by approximately $14 million during the next twelve months. NUGs As of March 31, 2017 , FirstEnergy's net liability position under NUG contracts was $103 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 March 31, 2017 , FirstEnergy's and FES' net liability associated with FTRs was $4 million and $2 million , respectively. As of December 31, 2016, FirstEnergy's net assets 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 March 31, December 31, March 31, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 43 $ 133 Commodity Contracts $ (23 ) $ (72 ) FTRs — 7 FTRs (4 ) (6 ) 43 140 (27 ) (78 ) Deferred Charges and Other Assets - Other Noncurrent Liabilities - Adverse Power Contract Liability NUGs (1) (103 ) (108 ) Noncurrent Liabilities - Other Commodity Contracts 17 77 Commodity Contracts (3 ) (52 ) NUGs (1) — 1 17 78 (106 ) (160 ) Derivative Assets $ 60 $ 218 Derivative Liabilities $ (133 ) $ (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 March 31, December 31, March 31, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 43 $ 133 Commodity Contracts $ (23 ) $ (72 ) FTRs — 4 FTRs (2 ) (5 ) 43 137 (25 ) (77 ) Deferred Charges and Other Assets - Other Noncurrent Liabilities - Other Commodity Contracts 17 77 Commodity Contracts (3 ) (52 ) 17 77 (3 ) (52 ) Derivative Assets $ 60 $ 214 Derivative Liabilities $ (28 ) $ (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 March 31, 2017 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 60 $ (21 ) $ — $ 39 $ 60 $ (21 ) $ — $ 39 Derivative Liabilities Commodity contracts $ (26 ) $ 21 $ — $ (5 ) FTRs (4 ) — 1 (3 ) NUG contracts (103 ) — — (103 ) $ (133 ) $ 21 $ 1 $ (111 ) 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 March 31, 2017 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 60 $ (21 ) $ — $ 39 $ 60 $ (21 ) $ — $ 39 Derivative Liabilities Commodity contracts $ (26 ) $ 21 $ — $ (5 ) FTRs (2 ) — 1 (1 ) $ (28 ) $ 21 $ 1 $ (6 ) 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 March 31, 2017 : Purchases Sales Net Units (In millions) Power Contracts 2 11 (9 ) MWH FTRs 13 — 13 MWH NUGs 3 — 3 MWH Natural Gas 1 1 — mmBTU The following table summarizes the volumes associated with FES' outstanding derivative transactions as of March 31, 2017 : Purchases Sales Net Units (In millions) Power Contracts 2 11 (9 ) MWH FTRs 11 — 11 MWH Natural Gas 1 1 — mmBTU The effect of active derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income during the three months ended March 31, 2017 and 2016 , are summarized in the following tables: For the Three Months Ended March 31 Commodity Contracts FTRs Total (In millions) 2017 Unrealized Loss Recognized in: Other Operating Expense $ (46 ) $ (1 ) $ (47 ) Realized Gain (Loss) Reclassified to: Revenues $ 25 $ — $ 25 Purchased Power Expense (7 ) — (7 ) Other Operating Expense — (9 ) (9 ) Fuel Expense 4 — 4 For the Three Months Ended March 31 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain Recognized in: Other Operating Expense $ 62 $ 2 $ 64 Realized Gain (Loss) Reclassified to: Revenues $ 71 $ 2 $ 73 Purchased Power Expense (45 ) — (45 ) Other Operating Expense — (12 ) (12 ) Fuel Expense (8 ) — (8 ) The effect of active derivative instruments not in a hedging relationship on FES' Consolidated Statements of Income (Loss) during the three months ended March 31, 2017 and 2016 , are summarized in the following tables: For the Three Months Ended March 31 Commodity Contracts FTRs Total 2017 (In millions) Unrealized Loss Recognized in: Other Operating Expense $ (46 ) $ (1 ) $ (47 ) Realized Gain (Loss) Reclassified to: Revenues $ 25 $ — $ 25 Purchased Power Expense (7 ) — (7 ) Other Operating Expense — (9 ) (9 ) For the Three Months Ended March 31 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain Recognized in: Other Operating Expense $ 62 $ 2 $ 64 Realized Gain (Loss) Reclassified to: Revenues $ 71 $ 2 $ 73 Purchased Power Expense (45 ) — (45 ) Other Operating Expense — (12 ) (12 ) The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during the three months ended March 31, 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 March 31 Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of January 1, 2017 $ (107 ) $ 2 $ (105 ) Unrealized loss (5 ) (1 ) (6 ) Settlements 9 (3 ) 6 Outstanding net liability as of March 31, 2017 $ (103 ) $ (2 ) $ (105 ) Outstanding net asset (liability) as of January 1, 2016 $ (136 ) $ 1 $ (135 ) Unrealized loss (12 ) (1 ) (13 ) Settlements 13 (2 ) 11 Outstanding net liability as of March 31, 2016 $ (135 ) $ (2 ) $ (137 )

Regulatory Matters

Regulatory Matters	3 Months Ended
	Mar. 31, 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 costs of the 2015-2017 plan are expected to be approximately $70 million , of which $47 million was incurred through March 31, 2017. PE continues to recover program costs subject to a five -year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE. On February 27, 2013, the MDPSC issued an order 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 this generic CTA proceeding to the New Jersey Superior Court and JCP&L filed to participate as a respondent in that proceeding supporting the order. Briefing was completed, and the oral argument was held on October 25, 2016. 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). On April 29, 2016 and May 2, 2016, several parties, including the Ohio Companies, filed applications for rehearing on the Ohio Companies’ ESP IV with the PUCO. On September 6, 2016, while the applications for rehearing were still pending before the PUCO, the OCC and NOAC filed a notice of appeal with the Ohio Supreme Court appealing various PUCO and Attorney Examiner entries on the parties’ applications for rehearing. On September 16, 2016, the Ohio Companies intervened and filed a motion to dismiss the appeal. The PUCO resolved such applications for rehearing in the October 12, 2016 Fifth Entry on Rehearing. The OCC and NOAC appeal was dismissed by the Ohio Supreme Court on February 22, 2017. On November 10, 2016 and November 14, 2016, several parties, including the Ohio Companies, filed additional 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 December 7, 2016, the PUCO granted the applications for rehearing for further consideration of the matters specified in the applications for rehearing. The matter remains pending before the PUCO. 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 SB 310 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. The matter is not yet scheduled for oral argument. On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers. On January 13, 2016, the PUCO granted reconsideration for further consideration of the matters specified in the applications for rehearing. 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 currently operate under DSPs that expire on May 31, 2017, and provide for the competitive procurement of generation supply for customers that do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. The default service supply is currently provided by wholesale suppliers through a mix of long-term and short-term contracts procured through spot market purchases, quarterly descending clock auctions for 3-, 12- and 24-month energy contracts, and one RFP seeking 2-year contracts to serve SRECs for ME, PN and Penn. Following the expiration of the current DSPs, the Pennsylvania Companies will operate under new DSPs for the June 1, 2017 through May 31, 2019 delivery period, which 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 new 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. In addition, the new DSPs include modifications to the Pennsylvania Companies’ existing POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges. ME, PN, Penn and WP currently 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 October 19, 2015, each of the Pennsylvania Companies filed LTIIPs with the PPUC for infrastructure improvement over the five -year period of 2016 to 2020 for the following costs: WP $88.3 million ; PN $56.7 million ; Penn $56.4 million ; and ME $43.4 million . On February 11, 2016, the PPUC approved the Pennsylvania Companies' LTIIPs. On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery associated with the capital projects approved in the LTIIPs. On June 9, 2016, the PPUC approved the Pennsylvania Companies’ DSIC riders to be effective July 1, 2016, subject to hearings and refund or reallocation among customer classes. The four proceedings were consolidated by the ALJ. On January 19, 2017, in the PPUC’s order approving the Pennsylvania Companies’ general rate cases the PPUC referred the issue of whether ADIT should be included in DSIC calculations to the consolidated DSIC proceeding. On February 2, 2017, the parties to the consolidated DSIC proceeding submitted a Joint Settlement to the ALJ that resolves issues the PPUC referred to the ALJ in its June 9, 2016 Order. This settlement is subject to PPUC approval and does not involve any refund or reallocation among customer classes. The ADIT issue will be considered separately from the issues resolved in the Joint Settlement Petition of February 2, 2017, and is the sole issue to be litigated in the consolidated DSIC proceeding. A hearing is scheduled for May 12, 2017. On March 1, 2017, ME, PN and Penn filed petitions with the PPUC to modify their LTIIPs for the four remaining years of 2017 through 2020, in which ME proposed to increase its LTIIP spending by $8.2 million per year, PN by $3.3 million per year, and Penn by $2.5 million per year. 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 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 applications with the WVPSC and MP and AE Supply filed with FERC requesting authorization for such purchase. The WVPSC has scheduled a hearing on this matter and an order is anticipated in the fourth quarter of 2017. With respect to the Bath County RFP, MP does not plan to move forward with the sale of its ownership interest. In the future, MP may re-evaluate its options with respect to its interest in Bath County. 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. On January 27, 2016, certain parties filed a complaint with FERC against FES and the Ohio Companies requesting FERC review the ESP IV PPA under Section 205 of the FPA. On April 27, 2016, FERC issued an order granting the complaint, prohibiting any transactions under the ESP IV PPA pending authorization by FERC, and directing FES to submit the ESP IV PPA for FERC review if the parties desired to transact under the agreement. FES and the Ohio Companies did not file the ESP IV PPA for FERC review but rather agreed to suspend the ESP IV PPA. FES and the Ohio Companies subsequently advised FERC of this course of action. On January 19, 2017, FERC issued an order accepting compliance filings by FES, its subsidiaries, and the Ohio Companies updating their respective market-based rate tariffs to clarify that affiliate sales restrictions under the tariffs apply to the ESP IV PPA, and also that the ESP IV PPA does not affect certain other waivers of its affiliate restrictions rules FERC previously granted these entities. On May 2, 2016, the Ohio Companies filed an Application for Rehearing with the PUCO that included a modified Rider RRS proposal that did not involve a FERC-jurisdictional PPA. Several parties subsequently filed protests and comments with FERC alleging, among other things, that the modified Rider RRS constituted a "virtual PPA". FERC rejected these protests in its January 19, 2017 order accepting the updated market-based rate tariffs of FES, its subsidiaries, and the Ohio Companies discussed below. 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. 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 transmis

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	3 Months Ended
	Mar. 31, 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 March 31, 2017 , FirstEnergy's outstanding guarantees and other assurances aggregated approximately $3.3 billion , consisting of parental guarantees ( $582 million ), subsidiaries' guarantees ( $1.9 billion ), other guarantees ( $300 million ) and other assurances ( $456 million ). Of this aggregate amount, substantially all relates to guarantees of wholly-owned consolidated entities of FirstEnergy. FES' debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each of FG and NG. Accordingly, present and future holders of indebtedness of FES, FG and NG would have claims against each of FES, FG and NG, regardless of whether their primary obligor is FES, FG or NG. COLLATERAL AND CONTINGENT-RELATED FEATURES In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel, and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on CES' power portfolio exposure as of March 31, 2017 , FES has posted collateral of $115 million and AE Supply has posted collateral of $4 million . The Regulated Distribution Segment has posted collateral of $4 million . These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of March 31, 2017. Potential Collateral Obligations FES AE Supply Regulated FE Corp Total (in millions) Contractual Obligations for Additional Collateral At Current Credit Rating $ 8 $ 3 $ — $ — $ 11 Upon Further Downgrade — — 50 — 50 Surety Bonds (Collateralized Amount) (1) 233 25 93 7 358 Total Exposure from Contractual Obligations $ 241 $ 28 $ 143 $ 7 $ 419 (1) Surety Bonds are not tied to a credit rating. Surety Bonds impact assumes maximum contractual obligations (typical obligations require 30 days to cure). Effective January 2017, FE is a guarantor for $169 million of FES' 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 March 31, 2017 , FES has $2 million collateral posted with their affiliates. OTHER COMMITMENTS AND CONTINGENCIES FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding borrowed $300 million . In addition to FE, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several guaranties of the obligations of Global Holding under the facility. In connection with the facility, 69.99% of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral. ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. 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 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. Depending on the outcome of the appeals and on how the EPA and the states implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's and FES' operations may result. 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. 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. 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. 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 subsidiary of FES, submitted to the AAA office in New York, N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure event that excuses FG’s performance under its coal transportation contract with these parties. Specifically, the dispute arises from a contract for the transportation by BNSF and CSX of a minimum of 3.5 million tons of coal annually through 2025 to certain coal-fired power plants owned by FG that are located in Ohio. As a result of and in compliance with MATS, all plants covered by this contract were deactivated by April 16, 2015. 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. The parties have agreed in principle to resolve all claims related to this consolidated proceeding on the terms and conditions set forth below. Upon completion of a definitive settlement agreement, all proceedings relating to these claims will be dismissed. If such definitive settlement agreement is not completed and the settlement does not become effective, a hearing to determine the liquidated damages to be paid will take place. Refer to the Strategic Review of Competitive Operations section of "Note 1, Organization and Basis of Presentation," for possible impacts this settlement may have as it relates to the strategic review of CES assets. 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 Plant. 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 parties are engaged in settlement discussions to resolve all claims related to this proceeding . 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. Refer to the "Strategic Review of Competitive Operations" section of "Note 1, Organization and Basis of Presentation," for possible impacts this settlement may have as it relates to the strategic review of CES assets. As to the BNSF and CSX arbitration proceeding referenced above , the parties have agreed in principle to resolve all claims in return for the payment by FG of $109 million, payable in three annual installments beginning on May 1, 2017, which would be guaranteed by FE. FirstEnergy and FES recorded a pre-tax charge of $164 million in the first quarter of 2017 in relation to both long term coal transportation contracts discussed above. If the definitive settlement agreement with CSX and BNSF is not completed, or the dispute with BNSF and NS is not settled, the amount of damages owed to CSX, BNSF and NS could be materially higher and may cause FES to seek protection under U.S. bankruptcy laws. As to a specific coal supply agreement, AE Supply 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 does 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 has filed an answer denying any liability related to the termination. This matter is currently in the discovery phase of litigation and no trial date has been established. On April 4, 2017, Tunnel Ridge moved to amend their complaint to add FE, FES and FG as defendants and seeking additional damages based on tort claims. On April 24, 2017, AE Supply filed to oppose addition of such defendants and claims, and oral argument is set for May 1, 2017. FirstEnergy 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. At this time, 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 United States Supreme Court decided that CO 2 or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies. The EPA released its final regulations in August 2015 (which have been stayed by the U.S. Supreme Court), to reduce CO 2 emissions from existing fossil fuel fired electric generating units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO 2 emission rate goals. The EPA’s CPP allows states to request a two-year extension to finalize SIPs by September 6, 2018. If states fail to develop SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions trading rules which states can also adopt in their SIPs. The EPA also finalized separate regulations imposing CO 2 emission limits for new, modified, and reconstructed fossil fuel fired electric generating units. 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. 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 are effective on November 4, 2016. It remains unclear whether and how the results of the 2016 United States election could impact the regulation of GHG emissions at the federal and state level. 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 will phase-in as permits are renewed on a five -year cycle from 2018 to 2023. The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits. On April 13, 2017, the EPA granted a Petition for Reconsideration of the ELG Rule and administratively stayed (effective upon publication in the Federal Register) all deadlines in the Rule pending a new rulemaking. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's and FES' operations may result. In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the effluent limits that were effective immediately under the terms of the NPDES permit. MP appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require an initial capital investment ranging from $150 million to $300 million in order to install technology to meet the TDS and sulfate limits, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of the appeal or estimate the possible loss or range of loss. FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the loss or range of loss. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although 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 July 6, 2015 and October 22, 2015, the Sierra Club filed Notices of Appeal with the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility. FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of March 31, 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 $135 million have been accrued through March 31, 2017 . Included in the total are accrued liabilities of approximately $89 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FirstEnergy or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time. OTHER LEGAL PROCEEDINGS Nuclear Plant Matters Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, 2017 , FirstEnergy had approximately $2.6 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. The values of FirstEnergy's NDTs fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs. FE and FES have also entered into a total of $24.5 million in parental guarantees in support of the decommissioning of the spent fuel storage facilities located at the nuclear facilities. As FES no longer maintains investment grade credit ratings from either S&P or Moody’s, NG funded a $10 million supplemental trust in 2016 in lieu of the FES parental guarantee that would be required to support the decommissioning of the spent fuel storage facilities. The termination of the FES parental guarantee is subject to NRC review. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantees, as appropriate. As part of routine inspections of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. These inspections revealed that the cracking condition had propagated a small amount in select areas. FENOC's analysis confirms that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions. In a May 28, 2015, Inspection Report regarding the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation for FENOC’s failure to request and obtain a license amendment for its method of evaluating the significance of the shield building cracking. The NRC also concluded that the shield building remained capable of performing its design safety functions despite the identified laminar cracking and that this issue was of very low safety significance. FENOC plans to submit a license amendment application to the NRC related to the laminar cracking in the Shield Building. On March 12, 2012, the NRC issued orders requiring safety enhancements at U.S. reactors based on recommendations from the lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders require additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in spent fuel pools. The NRC also requested that licensees including FENOC: re-analyze earthquake and flooding risks using the latest information available; conduct earthquake and flooding hazard walkdowns at their nuclear plants; assess the ability of current communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power; and assess plant staffing levels needed to fill emergency positions. Although a majority of the necessary modifications and upgrades at FirstEnergy’s nuclear facilities have been implemented, the improvements still remain subject to regulatory approval. FES provides a parental support agreement to NG of up to $400 million . The NRC typically relies on such parental support agreements to provide additional assurance that U.S. merchant nuclear plants, including NG's nuclear units, have the necessary financial resources to maintain safe operations, particularly in the event of extraordinary circumstances. So long as FES remains in the unregulated companies’ money pool, the $500 million secured line of credit with FE discussed above provides FES the needed liquidity in order for FES to satisfy its nuclear support obligations to NG. Other Legal Matters There are

Supplemental Guarantor Informat

Supplemental Guarantor Information	3 Months Ended
	Mar. 31, 2017
Supplemental Guarantor Information [Abstract]
SUPPLEMENTAL GUARANTOR INFORMATION	SUPPLEMENTAL GUARANTOR INFORMATION In 2007, FG completed a sale and leaseback transaction for a 93.83% undivided interest in Bruce Mansfield Unit 1. FG's parent company has fully and unconditionally and irrevocably guaranteed all of FG's obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FG or its parent company, but the notes are secured by, among other things, each lessor trust's undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES' lease guaranty. This transaction is classified as an operating lease for FES and FirstEnergy and as a financing lease for FG. The Condensed Consolidating Statements of Income (Loss) and Comprehensive Income (Loss) for the three months ended March 31, 2017 and 2016 , Condensed Consolidating Balance Sheets as of March 31, 2017 and December 31, 2016 , and Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 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 (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Three Months Ended March 31, 2017 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 880 $ 236 $ 336 $ (538 ) $ 914 OPERATING EXPENSES: Fuel — 98 46 — 144 Purchased power from affiliates 663 — 38 (538 ) 163 Purchased power from non-affiliates 160 — — — 160 Other operating expenses 114 225 167 12 518 Provision for depreciation 3 7 15 — 25 General taxes 6 8 7 — 21 Total operating expenses 946 338 273 (526 ) 1,031 OPERATING INCOME (LOSS) (66 ) (102 ) 63 (12 ) (117 ) OTHER INCOME (EXPENSE): Investment income (loss), including net income (loss) from equity investees (18 ) 10 27 1 20 Miscellaneous income — — 5 — 5 Interest expense — affiliates (18 ) (3 ) (1 ) 20 (2 ) Interest expense — other (11 ) (27 ) (11 ) 14 (35 ) Capitalized interest — 1 7 — 8 Total other income (expense) (47 ) (19 ) 27 35 (4 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (113 ) (121 ) 90 23 (121 ) INCOME TAXES (BENEFITS) (33 ) (42 ) 33 1 (41 ) NET INCOME (LOSS) $ (80 ) $ (79 ) $ 57 $ 22 $ (80 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (80 ) $ (79 ) $ 57 $ 22 $ (80 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (3 ) (3 ) — 3 (3 ) Change in unrealized gains on available-for-sale securities 16 — 16 (16 ) 16 Other comprehensive income (loss) 13 (3 ) 16 (13 ) 13 Income taxes (benefits) on other comprehensive income (loss) 5 (1 ) 6 (5 ) 5 Other comprehensive income (loss), net of tax 8 (2 ) 10 (8 ) 8 COMPREHENSIVE INCOME (LOSS) $ (72 ) $ (81 ) $ 67 $ 14 $ (72 ) FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Three Months Ended March 31, 2016 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 1,155 $ 415 $ 531 $ (902 ) $ 1,199 OPERATING EXPENSES: Fuel — 119 46 — 165 Purchased power from affiliates 927 — 57 (902 ) 82 Purchased power from non-affiliates 377 — — — 377 Other operating expenses 4 71 153 12 240 Provision for depreciation 3 31 50 (1 ) 83 General taxes 8 10 8 — 26 Total operating expenses 1,319 231 314 (891 ) 973 OPERATING INCOME (LOSS) (164 ) 184 217 (11 ) 226 OTHER INCOME (EXPENSE): Investment income, including net income from equity investees 249 6 17 (259 ) 13 Miscellaneous income 2 — — — 2 Interest expense — affiliates (9 ) (2 ) (2 ) 11 (2 ) Interest expense — other (13 ) (26 ) (11 ) 14 (36 ) Capitalized interest — 2 8 — 10 Total other income (expense) 229 (20 ) 12 (234 ) (13 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) 65 164 229 (245 ) 213 INCOME TAXES (BENEFITS) (66 ) 61 86 1 82 NET INCOME (LOSS) $ 131 $ 103 $ 143 $ (246 ) $ 131 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME (LOSS) $ 131 $ 103 $ 143 $ (246 ) $ 131 OTHER COMPREHENSIVE INCOME (LOSS) Pension and OPEB prior service costs (4 ) (3 ) — 3 (4 ) Change in unrealized gains on available-for-sale securities 23 — 23 (23 ) 23 Other comprehensive income (loss) 19 (3 ) 23 (20 ) 19 Income taxes (benefits) on other comprehensive income (loss) 7 (1 ) 8 (7 ) 7 Other comprehensive income (loss), net of tax 12 (2 ) 15 (13 ) 12 COMPREHENSIVE INCOME (LOSS) $ 143 $ 101 $ 158 $ (259 ) $ 143 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of March 31, 2017 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 173 — — — 173 Affiliated companies 266 188 237 (315 ) 376 Other 14 3 34 — 51 Notes receivable from affiliated companies 457 1,675 1,285 (3,417 ) — Materials and supplies 34 135 83 — 252 Derivatives 43 — — — 43 Collateral 106 1 — — 107 Prepayments and other 44 6 1 — 51 1,137 2,010 1,640 (3,732 ) 1,055 PROPERTY, PLANT AND EQUIPMENT: In service 121 2,550 4,718 (281 ) 7,108 Less — Accumulated provision for depreciation 56 1,931 4,198 (187 ) 5,998 65 619 520 (94 ) 1,110 Construction work in progress 3 58 427 — 488 68 677 947 (94 ) 1,598 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,593 — 1,593 Investment in affiliated companies 2,911 — — (2,911 ) — Other — 10 — — 10 2,911 10 1,593 (2,911 ) 1,603 DEFERRED CHARGES AND OTHER ASSETS: Property taxes — 9 21 — 30 Accumulated deferred income tax benefits 392 1,305 843 (272 ) 2,268 Derivatives 17 — — — 17 Other 33 335 — 25 393 442 1,649 864 (247 ) 2,708 $ 4,558 $ 4,346 $ 5,044 $ (6,984 ) $ 6,964 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 171 $ 5 $ (26 ) $ 150 Short-term borrowings- affiliated companies 3,069 461 1 (3,417 ) 114 Accounts payable- Affiliated companies 446 81 198 (409 ) 316 Other 26 81 — — 107 Accrued taxes 50 42 61 (16 ) 137 Derivatives 21 4 — — 25 Other 32 101 15 46 194 3,644 941 280 (3,822 ) 1,043 CAPITALIZATION: Total equity 146 741 2,073 (2,814 ) 146 Long-term debt and other long-term obligations 691 2,093 1,120 (1,092 ) 2,812 837 2,834 3,193 (3,906 ) 2,958 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 748 748 Accumulated deferred income taxes 4 — — (4 ) — Retirement benefits 27 175 — — 202 Asset retirement obligations — 189 726 — 915 Derivatives 3 — — — 3 Other 43 207 845 — 1,095 77 571 1,571 744 2,963 $ 4,558 $ 4,346 $ 5,044 $ (6,984 ) $ 6,964 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 Prepayments 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 Derivatives 52 — — — 52 Other 42 85 860 — 987 123 448 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 Three Months Ended March 31, 2017 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (142 ) $ 163 $ 200 $ — $ 221 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 100 — 1 (88 ) 13 Redemptions and Repayments- Long-term debt — (29 ) — — (29 ) Short-term borrowings, net — (22 ) — 22 — Other (1 ) (2 ) — — (3 ) Net cash provided from (used for) financing activities 99 (53 ) 1 (66 ) (19 ) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions — (21 ) (64 ) — (85 ) Nuclear fuel — — (132 ) — (132 ) Sales of investment securities held in trusts — — 231 — 231 Purchases of investment securities held in trusts — — (245 ) — (245 ) Loans to affiliated companies, net 43 (89 ) 9 66 29 Net cash provided from (used for) investing activities 43 (110 ) (201 ) 66 (202 ) 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 Three Months Ended March 31, 2016 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (356 ) $ 278 $ 307 $ — $ 229 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 352 8 1 (312 ) 49 Redemptions and Repayments- Short-term borrowings, net — (11 ) — 11 — Other — (3 ) — — (3 ) Net cash provided from (used for) financing activities 352 (6 ) 1 (301 ) 46 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (27 ) (53 ) (63 ) — (143 ) Nuclear fuel — — (149 ) — (149 ) Sales of investment securities held in trusts — — 138 — 138 Purchases of investment securities held in trusts — — (151 ) — (151 ) Cash Investments 10 — — — 10 Loans to affiliated companies, net 12 (219 ) (83 ) 301 11 Other 9 — — — 9 Net cash provided from (used for) investing activities 4 (272 ) (308 ) 301 (275 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 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 "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 further FERC hearing and settlement procedures. 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 March 31, 2017, this business segment controlled 13,162 MWs of electric generating capacity including, as discussed in "Note 9, Regulatory Matters", 1,572 MWs of natural gas and hydroelectric generating capacity subject to an asset purchase agreement with Aspen 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. 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 March 31, 2017, Corporate/Other had $4.5 billion of stand-alone holding company long-term debt, of which 33% was subject to variable-interest rates, and $2.8 billion was borrowed by FE under its revolving credit facility. Segment Financial Information For the Three Months Ended Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Reconciling Adjustments Consolidated (In millions) March 31, 2017 External revenues $ 2,490 $ 313 $ 814 $ — $ (65 ) $ 3,552 Internal revenues — — 117 — (117 ) — Total revenues 2,490 313 931 — (182 ) 3,552 Depreciation 178 51 28 18 — 275 Amortization of regulatory assets, net 57 2 — — — 59 Investment income 14 — 20 3 (13 ) 24 Interest expense 138 39 45 65 — 287 Income taxes (benefits) 138 52 (35 ) (29 ) — 126 Net income (loss) 237 88 (67 ) (53 ) — 205 Total assets 27,826 8,938 5,811 637 — 43,212 Total goodwill 5,004 614 — — — 5,618 Property additions 264 224 92 8 — 588 March 31, 2016 External revenues $ 2,510 $ 286 $ 1,152 $ — $ (79 ) $ 3,869 Internal revenues — — 152 — (152 ) — Total revenues 2,510 286 1,304 — (231 ) 3,869 Depreciation 167 45 102 15 — 329 Amortization of regulatory assets, net 59 2 — — — 61 Investment income 11 — 15 11 (9 ) 28 Interest expense 150 40 47 51 — 288 Income taxes (benefits) 94 47 85 (13 ) — 213 Net income (loss) 158 81 144 (55 ) — 328 Total assets 27,447 8,139 16,578 531 — 52,695 Total goodwill 5,004 614 800 — — 6,418 Property additions 241 279 169 9 — 698

Organization and Basis of Pre24

Organization and Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 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 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 In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers". Subsequent accounting standards updates have been issued which amend and/or clarify the application of ASU 2014-09. The core principle of the new guidance is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. More detailed disclosures will also be required to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For public business entities, the new revenue recognition guidance will be effective for annual and interim reporting periods beginning after December 15, 2017. Earlier adoption is permitted for annual and interim reporting periods beginning after December 15, 2016. FirstEnergy will not early adopt the standards. The standards shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy has evaluated its revenues and expects limited impacts to current revenue recognition practices, dependent on the resolution of industry issues. FirstEnergy continues to assess the impact on its financial statements and disclosures as well as which transition method it will select to adopt the guidance. In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption for certain provisions can be elected for all financial statements of fiscal years and interim periods that have not yet been issued or that have not yet been made available for issuance. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted . Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment . FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In March of 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", which simplifies several aspects of the accounting for employee share-based 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 activity by reclassifying $12 million from operating activity to financing activity in the 2016 Statement of Cash Flow. In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”, which removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted for fiscal years beginning after December 15, 2018. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments". The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows, including the presentation of debt prepayment or debt extinguishment costs, all of which will be classified as financing activities. The guidance 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. In October 2016, the FASB issued ASU 2016-16, " Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory." ASU 2016-16 eliminates the exception for all intra-entity sales of assets other than inventory, which allows companies to defer the tax effects of intra-entity asset transfers. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the intra-entity transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted and the modified retrospective approach will be required for transition to the new guidance, with a cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" that will require entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2019. Early adoption in an interim period is permitted, but any adjustments must be reflected as of the beginning of the fiscal year that includes that interim period. FirstEnergy does not expect this ASU to have a material effect on its financial statements. On January 5, 2017, the FASB issued ASU 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business" that clarifies the definition of a business and assists entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The guidance 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. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. On March 10, 2017, the FASB issued ASU 2017-07, "Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost", which amends the requirements related to the presentation of the components of net periodic benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. ASU 2017-07 requires entities to (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. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. Additionally, during 2017, the FASB issued the following ASUs: • ASU 2017-03, "Accounting Changes and Error Corrections (Topic 250) and Investments—Equity Method and Joint Ventures (Topic 323): Amendments to SEC Paragraphs Pursuant to Staff Announcements at the September 22, 2016 and November 17, 2016 EITF Meetings (SEC Update),” • ASU 2017-04, "Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,” • ASU 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets" and • ASU 2017-08, "Receivables - Nonrefundable Fees and Other Costs (Subtopic 310-20): Premium Amortization on Purchased Callable Debt Securities." FirstEnergy does not expect these ASUs to have a material effect on its financial statements.
Earnings Per Share	Basic earnings per share of common stock are computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. As discussed above, FirstEnergy adopted ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting" beginning January 1, 2017. As of March 31, 2017 and March 31, 2016 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	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 Per Share Of Common 25

Earnings Per Share Of Common Stock (Tables)	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Reconciliation of basic and diluted earnings per share	The following table reconciles basic and diluted earnings per share of common stock: (In millions, except per share amounts) For the Three Months Ended March 31 Reconciliation of Basic and Diluted Earnings per Share of Common Stock 2017 2016 Net income $ 205 $ 328 Weighted average number of basic shares outstanding 443 424 Assumed exercise of dilutive stock options and awards (1) 1 2 Weighted average number of diluted shares outstanding 444 426 Basic earnings per share of common stock $ 0.46 $ 0.78 Diluted earnings per share of common stock $ 0.46 $ 0.77 (1) For both the three months ended March 31 , 2017 and March 31 , 2016 , one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

Pension and Other Postemploym26

Pension and Other Postemployment Benefits (Tables)	3 Months Ended
	Mar. 31, 2017
Compensation and Retirement Disclosure [Abstract]
Components of Net Periodic Benefit Costs	The components of the consolidated net periodic cost (credits) for pension and OPEB (including amounts capitalized) were as follows: Components of Net Periodic Benefit Costs (Credits) Pension OPEB For the Three Months Ended March 31 2017 2016 2017 2016 (In millions) Service costs $ 52 $ 48 $ 1 $ 1 Interest costs 97 100 7 7 Expected return on plan assets (112 ) (97 ) (8 ) (8 ) Amortization of prior service costs (credits) 2 2 (20 ) (20 ) Net periodic costs (credits) $ 39 $ 53 $ (20 ) $ (20 )
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 March 31 $ 3 $ 6 $ (4 ) $ (4 ) 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 March 31 2017 2016 2017 2016 (In millions) FirstEnergy $ 32 $ 37 $ (15 ) $ (15 ) FES 3 6 (4 ) (4 )

Accumulated Other Comprehensi27

Accumulated Other Comprehensive Income (Tables)	3 Months Ended
	Mar. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of Accumulated Other Comprehensive Income	The changes in AOCI, net of tax, in the three months ended March 31, 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 January 1, 2017 $ (28 ) $ 52 $ 150 $ 174 Other comprehensive income before reclassifications — 32 — 32 Amounts reclassified from AOCI 3 (16 ) (18 ) (31 ) Other comprehensive income (loss) 3 16 (18 ) 1 Income taxes (benefits) on other comprehensive income (loss) 1 5 (6 ) — Other comprehensive income (loss), net of tax 2 11 (12 ) 1 AOCI Balance as of March 31, 2017 $ (26 ) $ 63 $ 138 $ 175 AOCI Balance as of January 1, 2016 $ (33 ) $ 18 $ 186 $ 171 Other comprehensive income before reclassifications — 41 — 41 Amounts reclassified from AOCI 2 (13 ) (18 ) (29 ) Other comprehensive income (loss) 2 28 (18 ) 12 Income taxes (benefits) on other comprehensive income (loss) 1 10 (7 ) 4 Other comprehensive income (loss), net of tax 1 18 (11 ) 8 AOCI Balance as of March 31, 2016 $ (32 ) $ 36 $ 175 $ 179
Reclassification out of Accumulated Other Comprehensive Income	The following amounts were reclassified from AOCI for FirstEnergy in the three months ended March 31, 2017 and 2016 : For the Three Months Ended March 31 Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (2) 2017 2016 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ — Other operating expenses Long-term debt 3 2 Interest expense 3 2 Total before taxes (1 ) (1 ) Income taxes $ 2 $ 1 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (16 ) $ (13 ) Investment income 6 5 Income taxes $ (10 ) $ (8 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (18 ) $ (18 ) (1) 6 7 Income taxes $ (12 ) $ (11 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI.
FES
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of Accumulated Other Comprehensive Income	The changes in AOCI, net of tax, in the three months ended March 31, 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 January 1, 2017 $ (9 ) $ 48 $ 30 $ 69 Other comprehensive income before reclassifications — 31 — 31 Amounts reclassified from AOCI — (15 ) (3 ) (18 ) Other comprehensive income (loss) — 16 (3 ) 13 Income taxes (benefits) on other comprehensive income (loss) — 6 (1 ) 5 Other comprehensive income (loss), net of tax — 10 (2 ) 8 AOCI Balance as of March 31, 2017 $ (9 ) $ 58 $ 28 $ 77 AOCI Balance as of January 1, 2016 $ (9 ) $ 16 $ 39 $ 46 Other comprehensive income before reclassifications — 36 — 36 Amounts reclassified from AOCI — (13 ) (4 ) (17 ) Other comprehensive income (loss) — 23 (4 ) 19 Income tax (benefits) on other comprehensive income (loss) — 9 (2 ) 7 Other comprehensive income (loss), net of tax — 14 (2 ) 12 AOCI Balance as of March 31, 2016 $ (9 ) $ 30 $ 37 $ 58
Reclassification out of Accumulated Other Comprehensive Income	The following amounts were reclassified from AOCI for FES in the three months ended March 31, 2017 and 2016 : For the Three Months Ended March 31 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2017 2016 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ — Other operating expenses — — Income taxes (benefits) $ — $ — Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (15 ) $ (13 ) Investment income 6 5 Income taxes (benefits) $ (9 ) $ (8 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (3 ) $ (4 ) (1) 1 2 Income taxes (benefits) $ (2 ) $ (2 ) 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)	3 Months Ended
	Mar. 31, 2017
Variable Interest Entities [Abstract]
Net exposure to loss based upon the casualty value provisions	The following table discloses each company’s net exposure to loss based upon the casualty value provisions as of March 31, 2017 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy $ 1,133 $ 894 $ 239 FES 1,113 890 223

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,244 $ — $ 1,244 $ — $ 1,247 $ — $ 1,247 Derivative assets - commodity contracts — 60 — 60 10 200 — 210 Derivative assets - FTRs — — — — — — 7 7 Derivative assets - NUG contracts (1) — — — — — — 1 1 Equity securities (2) 982 — — 982 925 — — 925 Foreign government debt securities — 95 — 95 — 78 — 78 U.S. government debt securities — 152 — 152 — 161 — 161 U.S. state debt securities — 250 — 250 — 246 — 246 Other (3) 164 128 — 292 199 123 — 322 Total assets $ 1,146 $ 1,929 $ — $ 3,075 $ 1,134 $ 2,055 $ 8 $ 3,197 Liabilities Derivative liabilities - commodity contracts $ — $ (26 ) $ — $ (26 ) $ (6 ) $ (118 ) $ — $ (124 ) Derivative liabilities - FTRs — — (4 ) (4 ) — — (6 ) (6 ) Derivative liabilities - NUG contracts (1) — — (103 ) (103 ) — — (108 ) (108 ) Total liabilities $ — $ (26 ) $ (107 ) $ (133 ) $ (6 ) $ (118 ) $ (114 ) $ (238 ) Net assets (liabilities) (4) $ 1,146 $ 1,903 $ (107 ) $ 2,942 $ 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 $(14) million and $(3) million as of March 31, 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 March 31, 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 — (6 ) (6 ) — (1 ) (1 ) Settlements (1 ) 11 10 (7 ) 3 (4 ) March 31, 2017 Balance $ — $ (103 ) $ (103 ) $ — $ (4 ) $ (4 ) (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 March 31, 2017 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ (4 ) Model RTO auction clearing prices $(2.70) to $2.90 $0.30 Dollars/MWH NUG Contracts $ (103 ) Model Generation 400 to 2,766,000 560,000 MWH Regional electricity prices $31.70 to $33.60 $31.70 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 March 31, 2017 and December 31, 2016 : March 31, 2017 (1) December 31, 2016 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,746 $ 38 $ 1,784 $ 1,735 $ 38 $ 1,773 FES 855 28 883 847 27 874 Equity securities FirstEnergy $ 852 $ 130 $ 982 $ 822 $ 103 $ 925 FES 578 89 667 564 70 634 (1) Excludes short-term cash investments: FirstEnergy - $53 million ; FES - $43 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 months ended March 31, 2017 and 2016 were as follows: For the Three Months Ended March 31, 2017 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 738 $ 85 $ (63 ) $ (3 ) $ 23 FES 231 64 (48 ) (3 ) 14 March 31, 2016 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 465 $ 61 $ (50 ) $ (9 ) $ 23 FES 138 42 (29 ) (8 ) 13
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: March 31, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 19,921 $ 20,029 $ 19,885 $ 19,829 FES 2,971 1,424 3,000 1,555
FES
Fair Value of Financial Instruments [Line Items]
Assets and liabilities measured on recurring basis	FES Recurring Fair Value Measurements March 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 746 $ — $ 746 $ — $ 726 $ — $ 726 Derivative assets - commodity contracts — 60 — 60 10 200 — 210 Derivative assets - FTRs — — — — — — 4 4 Equity securities (1) 667 — — 667 634 — — 634 Foreign government debt securities — 62 — 62 — 58 — 58 U.S. government debt securities — 30 — 30 — 48 — 48 U.S. state debt securities — 3 — 3 — 3 — 3 Other (2) 2 87 — 89 2 81 — 83 Total assets $ 669 $ 988 $ — $ 1,657 $ 646 $ 1,116 $ 4 $ 1,766 Liabilities Derivative liabilities - commodity contracts $ — $ (26 ) $ — $ (26 ) $ (6 ) $ (118 ) $ — $ (124 ) Derivative liabilities - FTRs — — (2 ) (2 ) — — (5 ) (5 ) Total liabilities $ — $ (26 ) $ (2 ) $ (28 ) $ (6 ) $ (118 ) $ (5 ) $ (129 ) Net assets (liabilities) (3) $ 669 $ 962 $ (2 ) $ 1,629 $ 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 $(2) million and $2 million as of March 31, 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 March 31, 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 ) Settlements (4 ) 3 (1 ) March 31, 2017 Balance $ — $ (2 ) $ (2 )
Quantitative information for level 3 valuation	The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2017 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ (2 ) Model RTO auction clearing prices ($2.70) to $2.40 $0.20 Dollars/MWH

Derivative Instruments (Tables)

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 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 March 31, December 31, March 31, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 43 $ 133 Commodity Contracts $ (23 ) $ (72 ) FTRs — 7 FTRs (4 ) (6 ) 43 140 (27 ) (78 ) Deferred Charges and Other Assets - Other Noncurrent Liabilities - Adverse Power Contract Liability NUGs (1) (103 ) (108 ) Noncurrent Liabilities - Other Commodity Contracts 17 77 Commodity Contracts (3 ) (52 ) NUGs (1) — 1 17 78 (106 ) (160 ) Derivative Assets $ 60 $ 218 Derivative Liabilities $ (133 ) $ (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 March 31, 2017 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 60 $ (21 ) $ — $ 39 $ 60 $ (21 ) $ — $ 39 Derivative Liabilities Commodity contracts $ (26 ) $ 21 $ — $ (5 ) FTRs (4 ) — 1 (3 ) NUG contracts (103 ) — — (103 ) $ (133 ) $ 21 $ 1 $ (111 ) 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 March 31, 2017 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 60 $ (21 ) $ — $ 39 $ 60 $ (21 ) $ — $ 39 Derivative Liabilities Commodity contracts $ (26 ) $ 21 $ — $ (5 ) FTRs (4 ) — 1 (3 ) NUG contracts (103 ) — — (103 ) $ (133 ) $ 21 $ 1 $ (111 ) 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 March 31, 2017 : Purchases Sales Net Units (In millions) Power Contracts 2 11 (9 ) MWH FTRs 13 — 13 MWH NUGs 3 — 3 MWH Natural Gas 1 1 — mmBTU
Effect of derivative instruments on statements of income and comprehensive income	The effect of active derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income during the three months ended March 31, 2017 and 2016 , are summarized in the following tables: For the Three Months Ended March 31 Commodity Contracts FTRs Total (In millions) 2017 Unrealized Loss Recognized in: Other Operating Expense $ (46 ) $ (1 ) $ (47 ) Realized Gain (Loss) Reclassified to: Revenues $ 25 $ — $ 25 Purchased Power Expense (7 ) — (7 ) Other Operating Expense — (9 ) (9 ) Fuel Expense 4 — 4 For the Three Months Ended March 31 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain Recognized in: Other Operating Expense $ 62 $ 2 $ 64 Realized Gain (Loss) Reclassified to: Revenues $ 71 $ 2 $ 73 Purchased Power Expense (45 ) — (45 ) Other Operating Expense — (12 ) (12 ) Fuel Expense (8 ) — (8 ) The effect of active derivative instruments not in a hedging relationship on FES' Consolidated Statements of Income (Loss) during the three months ended March 31, 2017 and 2016 , are summarized in the following tables: For the Three Months Ended March 31 Commodity Contracts FTRs Total 2017 (In millions) Unrealized Loss Recognized in: Other Operating Expense $ (46 ) $ (1 ) $ (47 ) Realized Gain (Loss) Reclassified to: Revenues $ 25 $ — $ 25 Purchased Power Expense (7 ) — (7 ) Other Operating Expense — (9 ) (9 ) For the Three Months Ended March 31 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain Recognized in: Other Operating Expense $ 62 $ 2 $ 64 Realized Gain (Loss) Reclassified to: Revenues $ 71 $ 2 $ 73 Purchased Power Expense (45 ) — (45 ) Other Operating Expense — (12 ) (12 )
Reconciliation of changes in the fair value of certain contracts that are deferred	The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during the three months ended March 31, 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 March 31 Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of January 1, 2017 $ (107 ) $ 2 $ (105 ) Unrealized loss (5 ) (1 ) (6 ) Settlements 9 (3 ) 6 Outstanding net liability as of March 31, 2017 $ (103 ) $ (2 ) $ (105 ) Outstanding net asset (liability) as of January 1, 2016 $ (136 ) $ 1 $ (135 ) Unrealized loss (12 ) (1 ) (13 ) Settlements 13 (2 ) 11 Outstanding net liability as of March 31, 2016 $ (135 ) $ (2 ) $ (137 )
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 March 31, December 31, March 31, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 43 $ 133 Commodity Contracts $ (23 ) $ (72 ) FTRs — 4 FTRs (2 ) (5 ) 43 137 (25 ) (77 ) Deferred Charges and Other Assets - Other Noncurrent Liabilities - Other Commodity Contracts 17 77 Commodity Contracts (3 ) (52 ) 17 77 (3 ) (52 ) Derivative Assets $ 60 $ 214 Derivative Liabilities $ (28 ) $ (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 March 31, 2017 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 60 $ (21 ) $ — $ 39 $ 60 $ (21 ) $ — $ 39 Derivative Liabilities Commodity contracts $ (26 ) $ 21 $ — $ (5 ) FTRs (2 ) — 1 (1 ) $ (28 ) $ 21 $ 1 $ (6 ) 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 March 31, 2017 Fair Value Derivative Instruments Cash Collateral Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 60 $ (21 ) $ — $ 39 $ 60 $ (21 ) $ — $ 39 Derivative Liabilities Commodity contracts $ (26 ) $ 21 $ — $ (5 ) FTRs (2 ) — 1 (1 ) $ (28 ) $ 21 $ 1 $ (6 ) 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 March 31, 2017 : Purchases Sales Net Units (In millions) Power Contracts 2 11 (9 ) MWH FTRs 11 — 11 MWH Natural Gas 1 1 — mmBTU

Commitments, Guarantees and C31

Commitments, Guarantees and Contingencies (Tables)	3 Months Ended
	Mar. 31, 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 $ 8 $ 3 $ — $ — $ 11 Upon Further Downgrade — — 50 — 50 Surety Bonds (Collateralized Amount) (1) 233 25 93 7 358 Total Exposure from Contractual Obligations $ 241 $ 28 $ 143 $ 7 $ 419 (1) Surety Bonds are not tied to a credit rating. Surety Bonds impact assumes maximum contractual obligations (typical obligations require 30 days to cure). Effective January 2017, FE is a guarantor for $169 million of FES' surety bonds for the benefit of the PA DEP with respect to LBR.

Supplemental Guarantor Inform32

Supplemental Guarantor Information (Tables)	3 Months Ended
	Mar. 31, 2017
Supplemental Guarantor Information [Abstract]
Condensed Consolidating Statements of Income (Loss) and Comprehensive Income (Loss)	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Three Months Ended March 31, 2017 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 880 $ 236 $ 336 $ (538 ) $ 914 OPERATING EXPENSES: Fuel — 98 46 — 144 Purchased power from affiliates 663 — 38 (538 ) 163 Purchased power from non-affiliates 160 — — — 160 Other operating expenses 114 225 167 12 518 Provision for depreciation 3 7 15 — 25 General taxes 6 8 7 — 21 Total operating expenses 946 338 273 (526 ) 1,031 OPERATING INCOME (LOSS) (66 ) (102 ) 63 (12 ) (117 ) OTHER INCOME (EXPENSE): Investment income (loss), including net income (loss) from equity investees (18 ) 10 27 1 20 Miscellaneous income — — 5 — 5 Interest expense — affiliates (18 ) (3 ) (1 ) 20 (2 ) Interest expense — other (11 ) (27 ) (11 ) 14 (35 ) Capitalized interest — 1 7 — 8 Total other income (expense) (47 ) (19 ) 27 35 (4 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (113 ) (121 ) 90 23 (121 ) INCOME TAXES (BENEFITS) (33 ) (42 ) 33 1 (41 ) NET INCOME (LOSS) $ (80 ) $ (79 ) $ 57 $ 22 $ (80 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (80 ) $ (79 ) $ 57 $ 22 $ (80 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (3 ) (3 ) — 3 (3 ) Change in unrealized gains on available-for-sale securities 16 — 16 (16 ) 16 Other comprehensive income (loss) 13 (3 ) 16 (13 ) 13 Income taxes (benefits) on other comprehensive income (loss) 5 (1 ) 6 (5 ) 5 Other comprehensive income (loss), net of tax 8 (2 ) 10 (8 ) 8 COMPREHENSIVE INCOME (LOSS) $ (72 ) $ (81 ) $ 67 $ 14 $ (72 ) FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Three Months Ended March 31, 2016 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 1,155 $ 415 $ 531 $ (902 ) $ 1,199 OPERATING EXPENSES: Fuel — 119 46 — 165 Purchased power from affiliates 927 — 57 (902 ) 82 Purchased power from non-affiliates 377 — — — 377 Other operating expenses 4 71 153 12 240 Provision for depreciation 3 31 50 (1 ) 83 General taxes 8 10 8 — 26 Total operating expenses 1,319 231 314 (891 ) 973 OPERATING INCOME (LOSS) (164 ) 184 217 (11 ) 226 OTHER INCOME (EXPENSE): Investment income, including net income from equity investees 249 6 17 (259 ) 13 Miscellaneous income 2 — — — 2 Interest expense — affiliates (9 ) (2 ) (2 ) 11 (2 ) Interest expense — other (13 ) (26 ) (11 ) 14 (36 ) Capitalized interest — 2 8 — 10 Total other income (expense) 229 (20 ) 12 (234 ) (13 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) 65 164 229 (245 ) 213 INCOME TAXES (BENEFITS) (66 ) 61 86 1 82 NET INCOME (LOSS) $ 131 $ 103 $ 143 $ (246 ) $ 131 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME (LOSS) $ 131 $ 103 $ 143 $ (246 ) $ 131 OTHER COMPREHENSIVE INCOME (LOSS) Pension and OPEB prior service costs (4 ) (3 ) — 3 (4 ) Change in unrealized gains on available-for-sale securities 23 — 23 (23 ) 23 Other comprehensive income (loss) 19 (3 ) 23 (20 ) 19 Income taxes (benefits) on other comprehensive income (loss) 7 (1 ) 8 (7 ) 7 Other comprehensive income (loss), net of tax 12 (2 ) 15 (13 ) 12 COMPREHENSIVE INCOME (LOSS) $ 143 $ 101 $ 158 $ (259 ) $ 143
Condensed Consolidating Balance Sheets	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of March 31, 2017 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 173 — — — 173 Affiliated companies 266 188 237 (315 ) 376 Other 14 3 34 — 51 Notes receivable from affiliated companies 457 1,675 1,285 (3,417 ) — Materials and supplies 34 135 83 — 252 Derivatives 43 — — — 43 Collateral 106 1 — — 107 Prepayments and other 44 6 1 — 51 1,137 2,010 1,640 (3,732 ) 1,055 PROPERTY, PLANT AND EQUIPMENT: In service 121 2,550 4,718 (281 ) 7,108 Less — Accumulated provision for depreciation 56 1,931 4,198 (187 ) 5,998 65 619 520 (94 ) 1,110 Construction work in progress 3 58 427 — 488 68 677 947 (94 ) 1,598 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,593 — 1,593 Investment in affiliated companies 2,911 — — (2,911 ) — Other — 10 — — 10 2,911 10 1,593 (2,911 ) 1,603 DEFERRED CHARGES AND OTHER ASSETS: Property taxes — 9 21 — 30 Accumulated deferred income tax benefits 392 1,305 843 (272 ) 2,268 Derivatives 17 — — — 17 Other 33 335 — 25 393 442 1,649 864 (247 ) 2,708 $ 4,558 $ 4,346 $ 5,044 $ (6,984 ) $ 6,964 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 171 $ 5 $ (26 ) $ 150 Short-term borrowings- affiliated companies 3,069 461 1 (3,417 ) 114 Accounts payable- Affiliated companies 446 81 198 (409 ) 316 Other 26 81 — — 107 Accrued taxes 50 42 61 (16 ) 137 Derivatives 21 4 — — 25 Other 32 101 15 46 194 3,644 941 280 (3,822 ) 1,043 CAPITALIZATION: Total equity 146 741 2,073 (2,814 ) 146 Long-term debt and other long-term obligations 691 2,093 1,120 (1,092 ) 2,812 837 2,834 3,193 (3,906 ) 2,958 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 748 748 Accumulated deferred income taxes 4 — — (4 ) — Retirement benefits 27 175 — — 202 Asset retirement obligations — 189 726 — 915 Derivatives 3 — — — 3 Other 43 207 845 — 1,095 77 571 1,571 744 2,963 $ 4,558 $ 4,346 $ 5,044 $ (6,984 ) $ 6,964 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 Prepayments 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 Derivatives 52 — — — 52 Other 42 85 860 — 987 123 448 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 Three Months Ended March 31, 2017 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (142 ) $ 163 $ 200 $ — $ 221 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 100 — 1 (88 ) 13 Redemptions and Repayments- Long-term debt — (29 ) — — (29 ) Short-term borrowings, net — (22 ) — 22 — Other (1 ) (2 ) — — (3 ) Net cash provided from (used for) financing activities 99 (53 ) 1 (66 ) (19 ) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions — (21 ) (64 ) — (85 ) Nuclear fuel — — (132 ) — (132 ) Sales of investment securities held in trusts — — 231 — 231 Purchases of investment securities held in trusts — — (245 ) — (245 ) Loans to affiliated companies, net 43 (89 ) 9 66 29 Net cash provided from (used for) investing activities 43 (110 ) (201 ) 66 (202 ) 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 Three Months Ended March 31, 2016 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (356 ) $ 278 $ 307 $ — $ 229 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 352 8 1 (312 ) 49 Redemptions and Repayments- Short-term borrowings, net — (11 ) — 11 — Other — (3 ) — — (3 ) Net cash provided from (used for) financing activities 352 (6 ) 1 (301 ) 46 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (27 ) (53 ) (63 ) — (143 ) Nuclear fuel — — (149 ) — (149 ) Sales of investment securities held in trusts — — 138 — 138 Purchases of investment securities held in trusts — — (151 ) — (151 ) Cash Investments 10 — — — 10 Loans to affiliated companies, net 12 (219 ) (83 ) 301 11 Other 9 — — — 9 Net cash provided from (used for) investing activities 4 (272 ) (308 ) 301 (275 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 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) March 31, 2017 External revenues $ 2,490 $ 313 $ 814 $ — $ (65 ) $ 3,552 Internal revenues — — 117 — (117 ) — Total revenues 2,490 313 931 — (182 ) 3,552 Depreciation 178 51 28 18 — 275 Amortization of regulatory assets, net 57 2 — — — 59 Investment income 14 — 20 3 (13 ) 24 Interest expense 138 39 45 65 — 287 Income taxes (benefits) 138 52 (35 ) (29 ) — 126 Net income (loss) 237 88 (67 ) (53 ) — 205 Total assets 27,826 8,938 5,811 637 — 43,212 Total goodwill 5,004 614 — — — 5,618 Property additions 264 224 92 8 — 588 March 31, 2016 External revenues $ 2,510 $ 286 $ 1,152 $ — $ (79 ) $ 3,869 Internal revenues — — 152 — (152 ) — Total revenues 2,510 286 1,304 — (231 ) 3,869 Depreciation 167 45 102 15 — 329 Amortization of regulatory assets, net 59 2 — — — 61 Investment income 11 — 15 11 (9 ) 28 Interest expense 150 40 47 51 — 288 Income taxes (benefits) 94 47 85 (13 ) — 213 Net income (loss) 158 81 144 (55 ) — 328 Total assets 27,447 8,139 16,578 531 — 52,695 Total goodwill 5,004 614 800 — — 6,418 Property additions 241 279 169 9 — 698

Organization and Basis of Pre34

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

Feb. 17, 2017USD ($)

Mar. 31, 2017USD ($)MWhtransmission_centerMW

Jan. 31, 2017USD ($)limited_guarantyNatural_gas_plantMW

Mar. 06, 2017MWhMW

Mar. 31, 2017USD ($)customertransmission_centercompanymiMW

Mar. 31, 2016USD ($)

Dec. 31, 2018MWh

Dec. 31, 2017MWh

Dec. 31, 2016USD ($)MWh

Dec. 31, 2020MW

Jun. 30, 2017USD ($)

Mar. 07, 2017USD ($)MW

Dec. 31, 2015MW

Property, Plant and Equipment [Line Items]

Aggregate amount of capacity | MW

17,000

Length of transmission lines | mi

24

Number of regional transmission centers | transmission_center

2

2

Capitalized cost of equity

$ 8,000,000

Capitalized interest

12,000,000

$ 17,000,000

Net cash used in operating activities

(785,000,000)

(650,000,000)

Net cash provided by financing activities

$ (58,000,000)

230,000,000

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

13,162

13,000

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

$ (221,000,000)

(229,000,000)

Net cash provided by financing activities

(19,000,000)

$ 46,000,000

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]

Inability to extend or refinance debt for the remainder of fiscal year

$ 130,000,000

Inability to extend or refinance interest payments and sale-leaseback commitments for the remainder of fiscal year

$ 108,000,000

Minimum | CES

Property, Plant and Equipment [Line Items]

Annual generation capacity (in MW) | MWh

60

70

Minimum | Scenario, Forecast | CES

Property, Plant and Equipment [Line Items]

Expected contract sales (in MWh) | MWh

35

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

40

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

1,572

1,572

1,572

Cash purchase price

$ 925,000,000

$ 925,000,000

Assets held for sale

$ 919,000,000

$ 919,000,000

Disposal Group, Including Discontinued Operation, Inventory

3,000,000

3,000,000

Disposal Group, Including Discontinued Operation, Asset Retirement Obligations

$ 1,000,000

$ 1,000,000

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

Number of limited guaranties | limited_guaranty

2

Purchase Agreement with Aspen Generating, LLC | AGC

Property, Plant and Equipment [Line Items]

Ownership percentage

59.00%

Purchase Agreement with Aspen Generating, LLC | Minimum | AE Supply

Property, Plant and Equipment [Line Items]

Term of guaranties

1 year

Purchase Agreement with Aspen Generating, LLC | Maximum | AE Supply

Property, Plant and Equipment [Line Items]

Term of guaranties

3 years

Pleasants Power Station

Property, Plant and Equipment [Line Items]

Plant capacity (in MW's) | MW

1,000

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 Per Share Of Common 35

Earnings Per Share Of Common Stock (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share [Abstract]
Net income (loss)	$ 205	$ 328
Weighted average number of basic shares outstanding	443	424
Assumed exercise of dilutive stock options and awards (in shares)	1	2
Weighted average number of diluted shares outstanding	444	426
Basic earnings (losses) per share of common stock (in dollars per share)	$ 0.46	$ 0.78
Diluted earnings (losses) per share of common stock (in dollars per share)	$ 0.46	$ 0.77
Shares excluded from the calculation of diluted shares outstanding, in shares	1	1

Pension and Other Postemploym36

Pension and Other Postemployment Benefits (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	$ 52	$ 48
Interest costs	97	100
Expected return on plan assets	(112)	(97)
Amortization of prior service costs (credits)	2	2
Net periodic costs (credits)	39	53
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	1	1
Interest costs	7	7
Expected return on plan assets	(8)	(8)
Amortization of prior service costs (credits)	(20)	(20)
Net periodic costs (credits)	(20)	(20)
FirstEnergy | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	32	37
FirstEnergy | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	(15)	(15)
FES
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-current liabilities	866		$ 866
FES | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)	3	6
Net periodic benefit expense (credit)	3	6
FES | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)	(4)	(4)
Net periodic benefit expense (credit)	(4)	$ (4)
FENOC
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-current liabilities	$ 570		$ 570

Accumulated Other Comprehensi37

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	$ 174	$ 171
Other comprehensive income before reclassifications	32	41
Amounts reclassified from AOCI	(31)	(29)
Other comprehensive income	1	12
Income taxes (benefits) on other comprehensive income (loss)	0	4
Other comprehensive income, net of tax	1	8
AOCI Ending Balance	175	179
Gains & Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(28)	(33)
Other comprehensive income before reclassifications	0	0
Amounts reclassified from AOCI	3	2
Other comprehensive income	3	2
Income taxes (benefits) on other comprehensive income (loss)	1	1
Other comprehensive income, net of tax	2	1
AOCI Ending Balance	(26)	(32)
Unrealized Gains on AFS Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	52	18
Other comprehensive income before reclassifications	32	41
Amounts reclassified from AOCI	(16)	(13)
Other comprehensive income	16	28
Income taxes (benefits) on other comprehensive income (loss)	5	10
Other comprehensive income, net of tax	11	18
AOCI Ending Balance	63	36
Defined Benefit Pension & OPEB Plans
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	150	186
Other comprehensive income before reclassifications	0	0
Amounts reclassified from AOCI	(18)	(18)
Other comprehensive income	(18)	(18)
Income taxes (benefits) on other comprehensive income (loss)	(6)	(7)
Other comprehensive income, net of tax	(12)	(11)
AOCI Ending Balance	138	175
FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	69	46
Other comprehensive income before reclassifications	31	36
Amounts reclassified from AOCI	(18)	(17)
Other comprehensive income	13	19
Income taxes (benefits) on other comprehensive income (loss)	5	7
Other comprehensive income, net of tax	8	12
AOCI Ending Balance	77	58
FES | Gains & Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(9)	(9)
Other comprehensive income before reclassifications	0	0
Amounts reclassified from AOCI	0	0
Other comprehensive income	0	0
Income taxes (benefits) on other comprehensive income (loss)	0	0
Other comprehensive income, net of tax	0	0
AOCI Ending Balance	(9)	(9)
FES | Unrealized Gains on AFS Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	48	16
Other comprehensive income before reclassifications	31	36
Amounts reclassified from AOCI	(15)	(13)
Other comprehensive income	16	23
Income taxes (benefits) on other comprehensive income (loss)	6	9
Other comprehensive income, net of tax	10	14
AOCI Ending Balance	58	30
FES | Defined Benefit Pension & OPEB Plans
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	30	39
Other comprehensive income before reclassifications	0	0
Amounts reclassified from AOCI	(3)	(4)
Other comprehensive income	(3)	(4)
Income taxes (benefits) on other comprehensive income (loss)	(1)	(2)
Other comprehensive income, net of tax	(2)	(2)
AOCI Ending Balance	$ 28	$ 37

Accumulated Other Comprehensi38

Accumulated Other Comprehensive Income (Details 1) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	$ (1,142)	$ (918)
Interest expense	(287)	(288)
INCOME BEFORE INCOME TAXES	331	541
Income taxes (benefits)	(126)	(213)
Prior-service costs	31	29
Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(3)	(2)
Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	16	13
Defined Benefit Pension & OPEB Plans
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	18	18
Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
INCOME BEFORE INCOME TAXES	3	2
Income taxes (benefits)	(1)	(1)
Net of tax	2	1
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	0	0
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	3	2
Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(16)	(13)
Income taxes (benefits)	6	5
Net of tax	(10)	(8)
Reclassifications from AOCI | Net prior service costs
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(18)	(18)
Income taxes	6	7
Net of tax	(12)	(11)
FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	(518)	(240)
INCOME BEFORE INCOME TAXES	(121)	213
Income taxes (benefits)	41	(82)
Prior-service costs	18	17
FES | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	0	0
FES | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	15	13
FES | Defined Benefit Pension & OPEB Plans
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	3	4
FES | Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Income taxes (benefits)	0	0
Net of tax	0	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	0	0
FES | Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(15)	(13)
Income taxes (benefits)	6	5
Net of tax	(9)	(8)
FES | Reclassifications from AOCI | Net prior service costs
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(3)	(4)
FES | Reclassifications from AOCI | Defined Benefit Pension & OPEB Plans
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Income taxes	1	2
Net of tax	$ (2)	$ (2)

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	38.10%	39.40%
Unrecognized tax benefits from lapse of statute of limitations	$ 51
Unrecognized tax benefits that would impact effective tax rate	$ 26
FES
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	33.90%	38.50%

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	Mar. 31, 2017USD ($)
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	$ 1,133
Discounted Lease Payments, net	894
Net Exposure	239
FES
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	1,113
Discounted Lease Payments, net	890
Net Exposure	$ 223

Variable Interest Entities (D41

Variable Interest Entities (Details Textuals)	3 Months Ended
	Mar. 31, 2017USD ($)agreemententity	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)	Jun. 24, 2014USD ($)
Variable Interest Entities (Textuals) [Abstract]
Equity interest by unaffiliated third party in PNBV (percent)	3.00%
Long-term transition bond	$ 74,000,000		$ 85,000,000
Long-term pollution control bond	395,000,000		406,000,000
Guarantor obligations	$ 419,000,000
Number of contracts that may contain variable interest | entity	1
Purchased power	$ 863,000,000	$ 1,124,000,000
Beaver Valley Unit 2
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary	2.60%
Bruce Mansfield Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary	93.83%
Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Ownership interest	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	$ 327,000,000		$ 339,000,000
Ohio Funding Companies
Variable Interest Entities (Textuals) [Abstract]
Annual servicing fees	$ 445,000
Other FE subsidiaries
Variable Interest Entities (Textuals) [Abstract]
Ownership interest	0.00%
Other FE subsidiaries | Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Purchased power	$ 28,000,000	$ 31,000,000
NG | Beaver Valley Unit 2
Variable Interest Entities (Textuals) [Abstract]
Percentage of high-voltage transmission line project owned by subsidiary of FE on the Allegheny Series				100.00%
OE | Beaver Valley Unit 2
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary				2.60%
Amount of irrevocable repurchase right				$ 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%
Percentage of high-voltage transmission line project owned by subsidiary of FE on the West Virginia Series	50.00%
Global Holding | Guarantee of senior secured loan facility
Variable Interest Entities (Textuals) [Abstract]
Guarantor obligations	$ 300,000,000
Signal Peak | Global Holding | FEV
Variable Interest Entities (Textuals) [Abstract]
Ownership interest	33.33%

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Recurring - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Assets
Fair value, assets	$ 3,075	$ 3,197
Liabilities
Fair value, liabilities	(133)	(238)
Net assets (liabilities)	2,942	2,959
FES
Assets
Fair value, assets	1,657	1,766
Liabilities
Fair value, liabilities	(28)	(129)
Net assets (liabilities)	1,629	1,637
Derivative liabilities - commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(26)	(124)
Derivative liabilities - commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(26)	(124)
Derivative liabilities - FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(4)	(6)
Derivative liabilities - FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(2)	(5)
Derivative liabilities - NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(103)	(108)
Corporate debt securities
Assets
Fair value, assets	1,244	1,247
Corporate debt securities | FES
Assets
Fair value, assets	746	726
Derivative liabilities - commodity contracts | Derivative Assets
Assets
Fair value, assets	60	210
Derivative liabilities - commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	60	210
Derivative liabilities - FTRs | Derivative Assets
Assets
Fair value, assets	0	7
Derivative liabilities - FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	4
Derivative liabilities - NUG contracts | Derivative Assets
Assets
Fair value, assets	0	1
Equity securities
Assets
Fair value, assets	982	925
Equity securities | FES
Assets
Fair value, assets	667	634
Foreign government debt securities
Assets
Fair value, assets	95	78
Foreign government debt securities | FES
Assets
Fair value, assets	62	58
U.S. government debt securities
Assets
Fair value, assets	152	161
U.S. government debt securities | FES
Assets
Fair value, assets	30	48
U.S. state debt securities
Assets
Fair value, assets	250	246
U.S. state debt securities | FES
Assets
Fair value, assets	3	3
Other
Assets
Fair value, assets	292	322
Other | FES
Assets
Fair value, assets	89	83
Level 1
Assets
Fair value, assets	1,146	1,134
Liabilities
Fair value, liabilities	0	(6)
Net assets (liabilities)	1,146	1,128
Level 1 | FES
Assets
Fair value, assets	669	646
Liabilities
Fair value, liabilities	0	(6)
Net assets (liabilities)	669	640
Level 1 | Derivative liabilities - commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	(6)
Level 1 | Derivative liabilities - commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	(6)
Level 1 | Derivative liabilities - FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 1 | Derivative liabilities - FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 1 | Derivative liabilities - NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 1 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 1 | Corporate debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | Derivative liabilities - commodity contracts | Derivative Assets
Assets
Fair value, assets	0	10
Level 1 | Derivative liabilities - commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	0	10
Level 1 | Derivative liabilities - FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | Derivative liabilities - FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 1 | Derivative liabilities - NUG contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | Equity securities
Assets
Fair value, assets	982	925
Level 1 | Equity securities | FES
Assets
Fair value, assets	667	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	164	199
Level 1 | Other | FES
Assets
Fair value, assets	2	2
Level 2
Assets
Fair value, assets	1,929	2,055
Liabilities
Fair value, liabilities	(26)	(118)
Net assets (liabilities)	1,903	1,937
Level 2 | FES
Assets
Fair value, assets	988	1,116
Liabilities
Fair value, liabilities	(26)	(118)
Net assets (liabilities)	962	998
Level 2 | Derivative liabilities - commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(26)	(118)
Level 2 | Derivative liabilities - commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(26)	(118)
Level 2 | Derivative liabilities - FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2 | Derivative liabilities - FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 2 | Derivative liabilities - NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2 | Corporate debt securities
Assets
Fair value, assets	1,244	1,247
Level 2 | Corporate debt securities | FES
Assets
Fair value, assets	746	726
Level 2 | Derivative liabilities - commodity contracts | Derivative Assets
Assets
Fair value, assets	60	200
Level 2 | Derivative liabilities - commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	60	200
Level 2 | Derivative liabilities - FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | Derivative liabilities - FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 2 | Derivative liabilities - NUG contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | Equity securities
Assets
Fair value, assets	0	0
Level 2 | Equity securities | FES
Assets
Fair value, assets	0	0
Level 2 | Foreign government debt securities
Assets
Fair value, assets	95	78
Level 2 | Foreign government debt securities | FES
Assets
Fair value, assets	62	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	30	48
Level 2 | U.S. state debt securities
Assets
Fair value, assets	250	246
Level 2 | U.S. state debt securities | FES
Assets
Fair value, assets	3	3
Level 2 | Other
Assets
Fair value, assets	128	123
Level 2 | Other | FES
Assets
Fair value, assets	87	81
Level 3
Assets
Fair value, assets	0	8
Liabilities
Fair value, liabilities	(107)	(114)
Net assets (liabilities)	(107)	(106)
Level 3 | FES
Assets
Fair value, assets	0	4
Liabilities
Fair value, liabilities	(2)	(5)
Net assets (liabilities)	(2)	(1)
Level 3 | Derivative liabilities - commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 3 | Derivative liabilities - commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 3 | Derivative liabilities - FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(4)	(6)
Level 3 | Derivative liabilities - FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(2)	(5)
Level 3 | Derivative liabilities - NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(103)	(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 | Derivative liabilities - commodity contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 3 | Derivative liabilities - commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 3 | Derivative liabilities - FTRs | Derivative Assets
Assets
Fair value, assets	0	7
Level 3 | Derivative liabilities - FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	4
Level 3 | Derivative liabilities - NUG contracts | Derivative Assets
Assets
Fair value, assets	0	1
Level 3 | Equity securities
Assets
Fair value, assets	0	0
Level 3 | Equity securities | FES
Assets
Fair value, assets	0	0
Level 3 | Foreign government debt securities
Assets
Fair value, assets	0	0
Level 3 | Foreign government debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | U.S. government debt securities
Assets
Fair value, assets	0	0
Level 3 | U.S. government debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | U.S. state debt securities
Assets
Fair value, assets	0	0
Level 3 | U.S. state debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | Other
Assets
Fair value, assets	0	0
Level 3 | Other | FES
Assets
Fair value, assets	$ 0	$ 0

Fair Value Measurements (Deta43

Fair Value Measurements (Details 1) - Level 3 - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 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 gain (loss), Derivative Liabilities	(6)	(17)
Unrealized gain (loss), Net	(6)	(15)
Purchases, Derivative Assets		0
Purchases, Derivative Liabilities		0
Purchases, Net		0
Settlements, Derivative Assets	(1)	(2)
Settlements, Derivative Liabilities	11	46
Settlements, Net	10	44
Ending Balance, Derivative Assets	0	1
Ending Balance, Derivative Liabilities	(103)	(108)
Ending Balance, Net	(103)	(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 gain (loss), Derivative Liabilities	(1)	(4)
Unrealized gain (loss), Net	(1)	(10)
Purchases, Derivative Assets		16
Purchases, Derivative Liabilities		(7)
Purchases, Net		9
Settlements, Derivative Assets	(7)	(11)
Settlements, Derivative Liabilities	3	18
Settlements, Net	(4)	7
Ending Balance, Derivative Assets	0	7
Ending Balance, Derivative Liabilities	(4)	(6)
Ending Balance, Net	(4)	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		(4)
Unrealized gain (loss), Derivative Liabilities		(3)
Unrealized gain (loss), Net		(7)
Purchases, Derivative Assets		10
Purchases, Derivative Liabilities		(5)
Purchases, Net		5
Settlements, Derivative Assets	(4)	(7)
Settlements, Derivative Liabilities	3	14
Settlements, Net	(1)	7
Ending Balance, Derivative Assets	0	4
Ending Balance, Derivative Liabilities	(2)	(5)
Ending Balance, Net	$ (2)	$ (1)

Fair Value Measurements (Deta44

Fair Value Measurements (Details 2) - Level 3 $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)MWh$ / MWh	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ (4)	$ 1	$ (5)
FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(2)	(1)	(6)
NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(103)	$ (107)	$ (136)
Model | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(4)
Model | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(2)
Model | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ (103)
Model | Minimum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	(2.70)
Model | Minimum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	(2.70)
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)	31.70
Model | Maximum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	2.90
Model | Maximum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	2.40
Model | Maximum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	2,766,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	33.60
Model | Weighted Average | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	0.30
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	560,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	31.70

Fair Value Measurements (Deta45

Fair Value Measurements (Details 3) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	$ 1,746	$ 1,735
Unrealized Gain	38	38
Fair Value	1,784	1,773
Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	852	822
Unrealized Gains	130	103
Fair Value	982	925
FES | Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	855	847
Unrealized Gain	28	27
Fair Value	883	874
FES | Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	578	564
Unrealized Gains	89	70
Fair Value	$ 667	$ 634

Fair Value Measurements (Deta46

Fair Value Measurements (Details 4) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 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	$ 738	$ 465
Realized Gains	85	61
Realized Losses	(63)	(50)
OTTI	(3)	(9)
Interest and Dividend Income	23	23
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	231	138
Realized Gains	64	42
Realized Losses	(48)	(29)
OTTI	(3)	(8)
Interest and Dividend Income	$ 14	$ 13

Fair Value Measurements (Deta47

Fair Value Measurements (Details 5) - USD ($) $ in Millions	Mar. 31, 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	$ 19,921	$ 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	2,971	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	20,029	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	$ 1,424	$ 1,555

Fair Value Measurements (Deta48

Fair Value Measurements (Details Textuals) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Fair Value of Financial Instruments [Line Items]
Investment excludes receivables, payables and accrued income	$ (14)	$ (3)
Cash balance excluded from available for sale securities	53	61
Investments not required to be disclosed	$ 269	266
NUG contracts
Fair Value of Financial Instruments [Line Items]
Period of future observable data to determine contract price	3 years
FES
Fair Value of Financial Instruments [Line Items]
Investment excludes receivables, payables and accrued income	$ (2)	2
Cash balance excluded from available for sale securities	$ 43	$ 44

Derivative Instruments (Details

Derivative Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Fair value of derivatives instruments
Derivative Assets	$ 60	$ 218
Derivative Liabilities	(133)	(238)
Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	43	140
Deferred Charges and Other Assets - Other
Fair value of derivatives instruments
Derivative Assets	17	78
Current Liabilities - Derivatives
Fair value of derivatives instruments
Derivative Liabilities	(27)	(78)
Noncurrent Liabilities
Fair value of derivatives instruments
Derivative Liabilities	(106)	(160)
Commodity contracts | Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	43	133
Commodity contracts | Deferred Charges and Other Assets - Other
Fair value of derivatives instruments
Derivative Assets	17	77
Commodity contracts | Current Liabilities - Derivatives
Fair value of derivatives instruments
Derivative Liabilities	(23)	(72)
Commodity contracts | Noncurrent Liabilities
Fair value of derivatives instruments
Derivative Liabilities	(3)	(52)
FTRs | Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	0	7
FTRs | Current Liabilities - Derivatives
Fair value of derivatives instruments
Derivative Liabilities	(4)	(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	(103)	(108)
FES
Fair value of derivatives instruments
Derivative Assets	60	214
Derivative Liabilities	(28)	(129)
FES | Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	43	137
FES | Deferred Charges and Other Assets - Other
Fair value of derivatives instruments
Derivative Assets	17	77
FES | Current Liabilities - Derivatives
Fair value of derivatives instruments
Derivative Liabilities	(25)	(77)
FES | Noncurrent Liabilities
Fair value of derivatives instruments
Derivative Liabilities	(3)	(52)
FES | Commodity contracts | Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	43	133
FES | Commodity contracts | Deferred Charges and Other Assets - Other
Fair value of derivatives instruments
Derivative Assets	17	77
FES | Commodity contracts | Current Liabilities - Derivatives
Fair value of derivatives instruments
Derivative Liabilities	(23)	(72)
FES | Commodity contracts | Noncurrent Liabilities
Fair value of derivatives instruments
Derivative Liabilities	(3)	(52)
FES | FTRs | Current Assets - Derivatives
Fair value of derivatives instruments
Derivative Assets	0	4
FES | FTRs | Current Liabilities - Derivatives
Fair value of derivatives instruments
Derivative Liabilities	$ (2)	$ (5)

Derivative Instruments (Detai50

Derivative Instruments (Details 1) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivative Assets
Fair Value	$ 60	$ 218
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(21)	(123)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	39	95
Derivative Liabilities
Fair Value	(133)	(238)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	21	123
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	1	1
Net Fair Value	(111)	(114)
Commodity contracts
Derivative Assets
Fair Value	60	210
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(21)	(117)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	39	93
Derivative Liabilities
Fair Value	(26)	(124)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	21	117
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	1
Net Fair Value	(5)	(6)
FTRs
Derivative Assets
Fair Value		7
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments		(6)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged		0
Net Fair Value		1
Derivative Liabilities
Fair Value	(4)	(6)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	0	6
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	1	0
Net Fair Value	(3)	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 (Received)/Pledged		0
Net Fair Value		1
Derivative Liabilities
Fair Value	(103)	(108)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	0	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	(103)	(108)
FES
Derivative Assets
Fair Value	60	214
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(21)	(121)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	39	93
Derivative Liabilities
Fair Value	(28)	(129)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	21	121
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	1	2
Net Fair Value	(6)	(6)
FES | Commodity contracts
Derivative Assets
Fair Value	60	210
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(21)	(117)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	39	93
Derivative Liabilities
Fair Value	(26)	(124)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	21	117
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	1
Net Fair Value	(5)	(6)
FES | FTRs
Derivative Assets
Fair Value		4
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments		(4)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged		0
Net Fair Value		0
Derivative Liabilities
Fair Value	(2)	(5)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	0	4
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	1	1
Net Fair Value	$ (1)	$ 0

Derivative Instruments (Detai51

Derivative Instruments (Details 2) MWh in Millions, MMBTU in Millions	Mar. 31, 2017MWhMMBTU
Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	2
Sales (in MWH or mmBTUs)	11
Net (in MWH or mmBTUs)	(9)
FTRs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	13
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	13
NUGs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	3
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	3
Natural Gas
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs) | MMBTU	1
Sales (in MWH or mmBTUs) | MMBTU	1
Net (in MWH or mmBTUs) | MMBTU	0
FES | Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	2
Sales (in MWH or mmBTUs)	11
Net (in MWH or mmBTUs)	(9)
FES | FTRs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	11
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	11
FES | Natural Gas
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs) | MMBTU	1
Sales (in MWH or mmBTUs) | MMBTU	1
Net (in MWH or mmBTUs) | MMBTU	0

Derivative Instruments (Detai52

Derivative Instruments (Details 3) - Not Designated as Hedging Instrument - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	$ 25	$ 73
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	(7)	(45)
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	(47)	64
Realized Gain (Loss) Reclassified	(9)	(12)
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	4	(8)
Commodity contracts | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	25	71
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	(7)	(45)
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	(46)	62
Realized Gain (Loss) Reclassified	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	4	(8)
FTRs | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	0	2
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
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	(1)	2
Realized Gain (Loss) Reclassified	(9)	(12)
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
FES | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	25	73
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	(7)	(45)
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	(47)	64
Realized Gain (Loss) Reclassified	(9)	(12)
FES | Commodity contracts | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	25	71
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	(7)	(45)
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	(46)	62
Realized Gain (Loss) Reclassified	0	0
FES | FTRs | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments not designated in hedging relationships
Realized Gain (Loss) Reclassified	0	2
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
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	(1)	2
Realized Gain (Loss) Reclassified	$ (9)	$ (12)

Derivative Instruments (Detai53

Derivative Instruments (Details 4) - Not Designated as Hedging Instrument - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	$ (105)	$ (135)
Unrealized loss	(6)	(13)
Settlements	6	11
Outstanding net asset (liability), Ending Balance	(105)	(137)
NUGs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(107)	(136)
Unrealized loss	(5)	(12)
Settlements	9	13
Outstanding net asset (liability), Ending Balance	(103)	(135)
Regulated FTRs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	2	1
Unrealized loss	(1)	(1)
Settlements	(3)	(2)
Outstanding net asset (liability), Ending Balance	$ (2)	$ (2)

Derivative Instruments (Detai54

Derivative Instruments (Details Textuals) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)agreement	Dec. 31, 2016USD ($)agreement
Derivative [Line Items]
Unamortized gains or losses associated with designated cash flow hedges	$ 11	$ 12
Possible adverse change in quoted market prices of derivative instruments	10.00%
Possible increase (decrease) net income due to ten percent adverse change in commodity prices	$ (14)
Cash Flow Hedges
Derivative [Line Items]
Less than 1 million dollar loss on cash flow hedge expected to be reclassified to earnings in next twelve months	2
Unamortized gains or losses associated with prior interest rate hedges	31	$ 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
Cash Flow Hedges | FES
Derivative [Line Items]
Unamortized gains or losses associated with prior interest rate hedges	$ 3	$ 3
Fair Value Hedging
Derivative [Line Items]
Gains (losses) to be amortized to interest expenses during next twelve months	$ 5
Number of fixed-for-floating interest rate swap agreements outstanding | agreement	0	0
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	$ 8	$ 10
Commodity contracts
Derivative [Line Items]
Net asset position under commodity derivative contracts	34
Commodity contracts | FES
Derivative [Line Items]
Collateral posted	1
NUGs
Derivative [Line Items]
Liability position	103
FTRs
Derivative [Line Items]
Derivative assets (liabilities)	(4)	1
FTRs | FES
Derivative [Line Items]
Derivative assets (liabilities)	$ (2)	$ (1)

Regulatory Matters - Maryland a

Regulatory Matters - Maryland and New Jersey (Details) $ in Millions	Dec. 12, 2016USD ($)	Jul. 16, 2015	Feb. 27, 2013USD ($)	Mar. 31, 2017USD ($)component	Dec. 31, 2017USD ($)
Maryland
Regulatory Matters [Line Items]
Incremental energy savings goal next 12 months (percent)		0.20%
Incremental energy savings goal thereafter (percent)		2.00%
Expenditures for cost recovery program incurred				$ 47
Recovery period for expenditures for cost recovery program		5 years		3 years
Expected infrastructure investments			$ 2,700
Period of expected infrastructure investments			15 years
New Jersey
Regulatory Matters [Line Items]
Number of supply components | component				2
PE | Maryland
Regulatory Matters [Line Items]
Incremental energy savings goal next 12 months (percent)		0.97%
JCP&L | NJBPU | New Jersey
Regulatory Matters [Line Items]
Approved amount of annual increase	$ 80
Scenario, Forecast | Maryland
Regulatory Matters [Line Items]
Expenditures for cost recovery program					$ 70

Regulatory Matters - Ohio (Deta

Regulatory Matters - Ohio (Details) $ in Millions	Nov. 14, 2016USD ($)	Oct. 12, 2016USD ($)	Apr. 15, 2016	Aug. 07, 2013USD ($)auction	Mar. 31, 2017USD ($)
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	Mar. 01, 2017USD ($)	Jan. 27, 2017USD ($)	Dec. 09, 2016USD ($)	Oct. 19, 2015USD ($)	Jun. 19, 2015	Oct. 10, 2013proposal	Mar. 31, 2016USD ($)	Mar. 31, 2017USD ($)program	Dec. 31, 2027MW	Dec. 31, 2020MW	Mar. 07, 2017USD ($)MW
Pennsylvania
Regulatory Matters [Line Items]
Number of RFP's | proposal						1
RFP term						2 years
Pennsylvania | Three month period
Regulatory Matters [Line Items]
Term of energy contract						3 months
Pennsylvania | Twelve month period
Regulatory Matters [Line Items]
Term of energy contract						12 months
Pennsylvania | Twenty-four month period
Regulatory Matters [Line Items]
Term of energy contract						24 months
Pennsylvania | PPUC
Regulatory Matters [Line Items]
LTIIP recovery period				5 years
LTIIP remaining recovery period	4 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 return on equity (percent)					1.80%
Energy consumption reduction targets proposed return on equity (percent)					4.00%
Amount of requested rate increase (decrease)				$ 43.4
Per year proposed increase to spending	$ 8.2
Pennsylvania | Penn
Regulatory Matters [Line Items]
Approved amount of annual increase		29
Pennsylvania | Penn | PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)					1.70%
Energy consumption reduction targets proposed return on equity (percent)					3.30%
Amount of requested rate increase (decrease)				56.4
Per year proposed increase to spending	2.5
Pennsylvania | WP
Regulatory Matters [Line Items]
Approved amount of annual increase		66
Pennsylvania | WP | PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)					1.80%
Energy consumption reduction targets proposed return on equity (percent)					2.60%
Amount of requested rate increase (decrease)				88.3
Pennsylvania | PN
Regulatory Matters [Line Items]
Approved amount of annual increase		$ 100
Pennsylvania | PN | PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)					0.00%
Energy consumption reduction targets proposed return on equity (percent)					3.90%
Amount of requested rate increase (decrease)				$ 56.7
Per year proposed increase to spending	$ 3.3
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 | 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											1,000
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	Feb. 20, 2017	Feb. 17, 2017USD ($)	Jan. 19, 2017	Sep. 14, 2015	Aug. 04, 2014	Aug. 24, 2012USD ($)	Jan. 31, 2017USD ($)MW	Mar. 31, 2017USD ($)entityconditionsubsidiaryMW	Jan. 18, 2017MW
Regulatory Matters [Line Items]
Regional enforcement entities | entity								8
Purchase Agreement with Aspen Generating, LLC
Regulatory Matters [Line Items]
Cash purchase price | $		$ 925					$ 925
Plant capacity (in MW's)							1,572	1,572
Springdale Generating Facility Units 1-5 | Purchase Agreement with Aspen Generating, LLC
Regulatory Matters [Line Items]
Plant capacity (in MW's)									638
Chamberburg Generating Facility Units 12-13 | Purchase Agreement with Aspen Generating, LLC
Regulatory Matters [Line Items]
Plant capacity (in MW's)									88
Gans Generating Facility Units 8-9 | Purchase Agreement with Aspen Generating, LLC
Regulatory Matters [Line Items]
Plant capacity (in MW's)									88
Hunlock Creek | Purchase Agreement with Aspen Generating, LLC
Regulatory Matters [Line Items]
Plant capacity (in MW's)									45
Bath County Hydro | Purchase Agreement with Aspen Generating, LLC
Regulatory Matters [Line Items]
Plant capacity (in MW's)									713
FERC
Regulatory Matters [Line Items]
Denied recovery charges of exit fees | $								$ 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]
Return on equity (percent)	10.40%		8.11%			10.40%
FERC | PATH | PATH Transmission Project
Regulatory Matters [Line Items]
Proposed return on equity						10.90%
Requested return on equity (percent)						10.40%
Return on equity granted for regional transmission organization participation						0.50%
Remaining recovery period of regulatory assets				5 years
FERC | FET
Regulatory Matters [Line Items]
Number of stand-alone transmission subsidiaries | subsidiary								2
FERC | The Ohio Companies | ESP IV PPA
Regulatory Matters [Line Items]
Proposed Purchase Power Agreement, Term					8 years

Commitments, Guarantees and C59

Commitments, Guarantees and Contingencies (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Jan. 31, 2017
Guarantor Obligations [Line Items]
Guarantor obligations	$ 419,000,000
At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	11,000,000
Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	50,000,000
Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	$ 358,000,000
Curing period	30 days
Regulated
Guarantor Obligations [Line Items]
Guarantor obligations	$ 143,000,000
Regulated | At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	0
Regulated | Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	50,000,000
Regulated | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	93,000,000
FirstEnergy
Guarantor Obligations [Line Items]
Guarantor obligations	7,000,000
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	7,000,000
FES
Guarantor Obligations [Line Items]
Guarantor obligations	241,000,000
FES | At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	8,000,000
FES | Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	0
FES | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	233,000,000
FES | Surety Bond (Collateralized Amount) | Little Bull Run [Member]
Guarantor Obligations [Line Items]
Amount of surety bond		$ 169,000,000
AE Supply
Guarantor Obligations [Line Items]
Guarantor obligations	28,000,000
AE Supply | At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	3,000,000
AE Supply | Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	0
AE Supply | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	$ 25,000,000

Commitments, Guarantees and C60

Commitments, Guarantees and Contingencies (Details Textuals)	Oct. 01, 2015	Aug. 03, 2015T	Jun. 30, 2014	Mar. 31, 2017USD ($)phaseinstallmentT	Mar. 31, 2016	Dec. 31, 2016USD ($)	Oct. 31, 2012USD ($)
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated				$ 3,300,000,000
New syndicated senior secured term loan facility				$ 419,000,000
Proposed goal to reduce CO2 pollution (percent)				90.00%
Nuclear plant decommissioning trusts				$ 2,571,000,000		$ 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				$ 135,000,000
Environmental liabilities former gas facilities				89,000,000
Nuclear Plant Matters
Guarantor Obligations [Line Items]
Nuclear plant decommissioning trusts				2,600,000,000
Parental guarantee				$ 24,500,000
Renewal length of operating license for Davis-Besse Nuclear Power Station				20 years
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				$ 164,000,000
Regulated Distribution
Guarantor Obligations [Line Items]
Company posted collateral related to net liability positions				4,000,000
FES
Guarantor Obligations [Line Items]
Company posted collateral related to net liability positions				115,000,000
New syndicated senior secured term loan facility				241,000,000
Nuclear plant decommissioning trusts				1,593,000,000		1,552,000,000
FES | Caa Compliance
Guarantor Obligations [Line Items]
Annual contested damage claim				$ 70,000,000
Period of annual contested damage claim				11 years
FES | Settled Litigation | Caa Compliance
Guarantor Obligations [Line Items]
Loss recognized in period				$ 164,000,000
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			$ 350,000,000
Global Holding | Senior Secured Term Loan | Senior Loans | Signal Peak, Global Rail and Affiliates
Guarantor Obligations [Line Items]
Investment ownership percentage				69.99%
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
NG | Nuclear Plant Matters
Guarantor Obligations [Line Items]
Nuclear plant decommissioning trusts						10,000,000
AE Supply
Guarantor Obligations [Line Items]
Company posted collateral related to net liability positions				4,000,000
New syndicated senior secured term loan facility				28,000,000
Environmental Protection Agency | Caa Compliance
Guarantor Obligations [Line Items]
Period of time to implement plan	3 years
Minimum | Clean Water Act
Guarantor Obligations [Line Items]
Maximum capital investment required to install technology to meet TDS and Sulfate limits				$ 150,000,000
Minimum | FES | Caa Compliance
Guarantor Obligations [Line Items]
Number of installment payments | installment				3
Maximum | Clean Water Act
Guarantor Obligations [Line Items]
Maximum capital investment required to install technology to meet TDS and Sulfate limits				$ 300,000,000
Maximum | State and Local Agencies | Climate Change
Guarantor Obligations [Line Items]
Potential MATS extension period			2 years
Certain Coal-Fired Power Plant | 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				582,000,000
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				456,000,000
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		$ 400,000,000

Supplemental Guarantor Inform61

Supplemental Guarantor Information (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Consolidating Statements of Income
Revenues	[1]	$ 3,552	$ 3,869
OPERATING EXPENSES:
Fuel		368	381
Purchased power		863	1,124
Other operating expenses		1,142	918
Provision for depreciation		275	329
General taxes		271	280
Total operating expenses		2,978	3,093
OPERATING INCOME		574	776
OTHER INCOME (EXPENSE):
Investment income (loss), including net income (loss) from equity investees		24	28
Interest expense		(287)	(288)
Capitalized interest		20	25
Total other expense		(243)	(235)
INCOME BEFORE INCOME TAXES		331	541
INCOME TAXES (BENEFITS)		126	213
NET INCOME		205	328
NET INCOME		205	328
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(18)	(18)
Change in unrealized gains on available-for-sale securities		16	28
Other comprehensive income		1	12
Income taxes (benefits) on other comprehensive income (loss)		0	4
Other comprehensive income, net of tax		1	8
COMPREHENSIVE INCOME		$ 206	336
Bruce Mansfield Unit 1
Condensed Financial Statements, Captions [Line Items]
Percentage of undivided interest of non guarantor subsidiary		93.83%
Eliminations
Consolidating Statements of Income
Revenues		$ (538)	(902)
OPERATING EXPENSES:
Fuel		0	0
Other operating expenses		12	12
Provision for depreciation		0	(1)
General taxes		0	0
Total operating expenses		(526)	(891)
OPERATING INCOME		(12)	(11)
OTHER INCOME (EXPENSE):
Investment income (loss), including net income (loss) from equity investees		1	(259)
Miscellaneous income		0	0
Capitalized interest		0	0
Total other expense		35	(234)
INCOME BEFORE INCOME TAXES		23	(245)
INCOME TAXES (BENEFITS)		1	1
NET INCOME		22	(246)
NET INCOME		22	(246)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		3	3
Change in unrealized gains on available-for-sale securities		(16)	(23)
Other comprehensive income		(13)	(20)
Income taxes (benefits) on other comprehensive income (loss)		(5)	(7)
Other comprehensive income, net of tax		(8)	(13)
COMPREHENSIVE INCOME		14	(259)
Eliminations | Affiliates
OPERATING EXPENSES:
Purchased power		(538)	(902)
OTHER INCOME (EXPENSE):
Interest expense		20	11
Eliminations | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0
OTHER INCOME (EXPENSE):
Interest expense		14	14
FES
Consolidating Statements of Income
Revenues		880	1,155
OPERATING EXPENSES:
Fuel		0	0
Other operating expenses		114	4
Provision for depreciation		3	3
General taxes		6	8
Total operating expenses		946	1,319
OPERATING INCOME		(66)	(164)
OTHER INCOME (EXPENSE):
Investment income (loss), including net income (loss) from equity investees		(18)	249
Miscellaneous income		0	2
Capitalized interest		0	0
Total other expense		(47)	229
INCOME BEFORE INCOME TAXES		(113)	65
INCOME TAXES (BENEFITS)		(33)	(66)
NET INCOME		(80)	131
NET INCOME		(80)	131
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(3)	(4)
Change in unrealized gains on available-for-sale securities		16	23
Other comprehensive income		13	19
Income taxes (benefits) on other comprehensive income (loss)		5	7
Other comprehensive income, net of tax		8	12
COMPREHENSIVE INCOME		(72)	143
FES | Affiliates
OPERATING EXPENSES:
Purchased power		663	927
OTHER INCOME (EXPENSE):
Interest expense		(18)	(9)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power		160	377
OTHER INCOME (EXPENSE):
Interest expense		(11)	(13)
FG
Consolidating Statements of Income
Revenues		236	415
OPERATING EXPENSES:
Fuel		98	119
Other operating expenses		225	71
Provision for depreciation		7	31
General taxes		8	10
Total operating expenses		338	231
OPERATING INCOME		(102)	184
OTHER INCOME (EXPENSE):
Investment income (loss), including net income (loss) from equity investees		10	6
Miscellaneous income		0	0
Capitalized interest		1	2
Total other expense		(19)	(20)
INCOME BEFORE INCOME TAXES		(121)	164
INCOME TAXES (BENEFITS)		(42)	61
NET INCOME		(79)	103
NET INCOME		(79)	103
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(3)	(3)
Change in unrealized gains on available-for-sale securities		0	0
Other comprehensive income		(3)	(3)
Income taxes (benefits) on other comprehensive income (loss)		(1)	(1)
Other comprehensive income, net of tax		(2)	(2)
COMPREHENSIVE INCOME		(81)	101
FG | Affiliates
OPERATING EXPENSES:
Purchased power		0	0
OTHER INCOME (EXPENSE):
Interest expense		(3)	(2)
FG | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0
OTHER INCOME (EXPENSE):
Interest expense		(27)	(26)
NG
Consolidating Statements of Income
Revenues		336	531
OPERATING EXPENSES:
Fuel		46	46
Other operating expenses		167	153
Provision for depreciation		15	50
General taxes		7	8
Total operating expenses		273	314
OPERATING INCOME		63	217
OTHER INCOME (EXPENSE):
Investment income (loss), including net income (loss) from equity investees		27	17
Miscellaneous income		5	0
Capitalized interest		7	8
Total other expense		27	12
INCOME BEFORE INCOME TAXES		90	229
INCOME TAXES (BENEFITS)		33	86
NET INCOME		57	143
NET INCOME		57	143
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		0	0
Change in unrealized gains on available-for-sale securities		16	23
Other comprehensive income		16	23
Income taxes (benefits) on other comprehensive income (loss)		6	8
Other comprehensive income, net of tax		10	15
COMPREHENSIVE INCOME		67	158
NG | Affiliates
OPERATING EXPENSES:
Purchased power		38	57
OTHER INCOME (EXPENSE):
Interest expense		(1)	(2)
NG | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0
OTHER INCOME (EXPENSE):
Interest expense		(11)	(11)
Consolidated
Consolidating Statements of Income
Revenues		914	1,199
OPERATING EXPENSES:
Fuel		144	165
Other operating expenses		518	240
Provision for depreciation		25	83
General taxes		21	26
Total operating expenses		1,031	973
OPERATING INCOME		(117)	226
OTHER INCOME (EXPENSE):
Investment income (loss), including net income (loss) from equity investees		20	13
Miscellaneous income		5	2
Capitalized interest		8	10
Total other expense		(4)	(13)
INCOME BEFORE INCOME TAXES		(121)	213
INCOME TAXES (BENEFITS)		(41)	82
NET INCOME		(80)	131
NET INCOME		(80)	131
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(3)	(4)
Change in unrealized gains on available-for-sale securities		16	23
Other comprehensive income		13	19
Income taxes (benefits) on other comprehensive income (loss)		5	7
Other comprehensive income, net of tax		8	12
COMPREHENSIVE INCOME		(72)	143
Consolidated | Affiliates
OPERATING EXPENSES:
Purchased power		163	82
OTHER INCOME (EXPENSE):
Interest expense		(2)	(2)
Consolidated | Non-Affiliates
OPERATING EXPENSES:
Purchased power		160	377
OTHER INCOME (EXPENSE):
Interest expense		$ (35)	$ (36)
[1]	Includes excise tax collections of $100 million and $107 million in the three months ended March 31, 2017 and 2016, respectively.

Supplemental Guarantor Inform62

Supplemental Guarantor Information (Details 1) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 164	$ 199	$ 146	$ 131
Receivables-
Customers	1,396	1,440
Other	155	175
Materials and supplies	531	564
Derivatives	43	140
Collateral	122	176
Prepaid taxes and other	147	158
Total current assets	2,760	2,950
PROPERTY, PLANT AND EQUIPMENT:
In service	42,976	43,767
Less — Accumulated provision for depreciation	15,769	15,731
Property, plant and equipment in service net of accumulated provision for depreciation	27,207	28,036
Construction work in progress	1,588	1,351
Total net property, plant and equipment	28,795	29,387
INVESTMENTS:
Nuclear plant decommissioning trusts	2,571	2,514
Other	519	512
Total other property and investments	3,090	3,026
DEFERRED CHARGES AND OTHER ASSETS:
Other	1,028	1,153
Total deferred charges and other assets	7,646	7,785
Total assets	43,212	43,148	52,695
CURRENT LIABILITIES:
Currently payable long-term debt	2,147	1,685
Accounts payable-
Accrued taxes	555	580
Derivatives	27	78
Other	848	660
Total current liabilities	7,657	7,126
CAPITALIZATION:
Total equity	6,139	6,241
Long-term debt and other long-term obligations	17,762	18,192
Total capitalization	23,901	24,433
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	748	757
Accumulated deferred income taxes	3,882	3,765
Retirement benefits	3,756	3,719
Asset retirement obligations	1,505	1,482
Other	1,606	1,704
Total noncurrent liabilities	11,654	11,589
Total liabilities and capitalization	43,212	43,148
Eliminations
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	(315)	(612)
Other	0	0
Notes receivable from affiliated companies	(3,417)	(3,351)
Materials and supplies	0	0
Derivatives	0	0
Collateral	0	0
Prepaid taxes and other	0	0
Total current assets	(3,732)	(3,963)
PROPERTY, PLANT AND EQUIPMENT:
In service	(281)	(290)
Less — Accumulated provision for depreciation	(187)	(187)
Property, plant and equipment in service net of accumulated provision for depreciation	(94)	(103)
Construction work in progress	0	0
Total net property, plant and equipment	(94)	(103)
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	(2,911)	(2,923)
Other	0	0
Total other property and investments	(2,911)	(2,923)
DEFERRED CHARGES AND OTHER ASSETS:
Property taxes	0	0
Accumulated deferred income tax benefits	(272)	(270)
Derivatives	0	0
Other	25	21
Total deferred charges and other assets	(247)	(249)
Total assets	(6,984)	(7,238)
CURRENT LIABILITIES:
Currently payable long-term debt	(26)	(26)
Accounts payable-
Affiliated companies	(409)	(706)
Other	0	0
Accrued taxes	(16)	(16)
Derivatives	0	0
Other	46	36
Total current liabilities	(3,822)	(4,063)
CAPITALIZATION:
Total equity	(2,814)	(2,834)
Long-term debt and other long-term obligations	(1,092)	(1,091)
Total capitalization	(3,906)	(3,925)
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	748	757
Accumulated deferred income taxes	(4)	(7)
Retirement benefits	0	0
Asset retirement obligations	0	0
Derivatives	0	0
Other	0	0
Total noncurrent liabilities	744	750
Total liabilities and capitalization	(6,984)	(7,238)
Eliminations | Affiliates
CURRENT LIABILITIES:
Short-term borrowings - affiliated companies	(3,417)	(3,351)
FES
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	173	213
Affiliated companies	266	332
Other	14	17
Notes receivable from affiliated companies	457	501
Materials and supplies	34	45
Derivatives	43	137
Collateral	106	157
Prepaid taxes and other	44	38
Total current assets	1,137	1,440
PROPERTY, PLANT AND EQUIPMENT:
In service	121	120
Less — Accumulated provision for depreciation	56	52
Property, plant and equipment in service net of accumulated provision for depreciation	65	68
Construction work in progress	3	2
Total net property, plant and equipment	68	70
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	2,911	2,923
Other	0	0
Total other property and investments	2,911	2,923
DEFERRED CHARGES AND OTHER ASSETS:
Property taxes	0	0
Accumulated deferred income tax benefits	392	395
Derivatives	17	77
Other	33	33
Total deferred charges and other assets	442	505
Total assets	4,558	4,938
CURRENT LIABILITIES:
Currently payable long-term debt	0	0
Accounts payable-
Affiliated companies	446	743
Other	26	17
Accrued taxes	50	50
Derivatives	21	71
Other	32	56
Total current liabilities	3,644	3,906
CAPITALIZATION:
Total equity	146	218
Long-term debt and other long-term obligations	691	691
Total capitalization	837	909
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	4	4
Retirement benefits	27	25
Asset retirement obligations	0	0
Derivatives	3	52
Other	43	42
Total noncurrent liabilities	77	123
Total liabilities and capitalization	4,558	4,938
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings - affiliated companies	3,069	2,969
FG
CURRENT ASSETS:
Cash and cash equivalents	2	2	2	2
Receivables-
Customers	0	0
Affiliated companies	188	315
Other	3	2
Notes receivable from affiliated companies	1,675	1,585
Materials and supplies	135	142
Derivatives	0	0
Collateral	1	0
Prepaid taxes and other	6	24
Total current assets	2,010	2,070
PROPERTY, PLANT AND EQUIPMENT:
In service	2,550	2,524
Less — Accumulated provision for depreciation	1,931	1,920
Property, plant and equipment in service net of accumulated provision for depreciation	619	604
Construction work in progress	58	67
Total net property, plant and equipment	677	671
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	0	0
Other	10	9
Total other property and investments	10	9
DEFERRED CHARGES AND OTHER ASSETS:
Property taxes	9	12
Accumulated deferred income tax benefits	1,305	1,271
Derivatives	0	0
Other	335	327
Total deferred charges and other assets	1,649	1,610
Total assets	4,346	4,360
CURRENT LIABILITIES:
Currently payable long-term debt	171	200
Accounts payable-
Affiliated companies	81	107
Other	81	93
Accrued taxes	42	48
Derivatives	4	6
Other	101	54
Total current liabilities	941	991
CAPITALIZATION:
Total equity	741	828
Long-term debt and other long-term obligations	2,093	2,093
Total capitalization	2,834	2,921
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	0	3
Retirement benefits	175	172
Asset retirement obligations	189	188
Derivatives	0	0
Other	207	85
Total noncurrent liabilities	571	448
Total liabilities and capitalization	4,346	4,360
FG | Affiliates
CURRENT LIABILITIES:
Short-term borrowings - affiliated companies	461	483
NG
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	237	417
Other	34	8
Notes receivable from affiliated companies	1,285	1,294
Materials and supplies	83	80
Derivatives	0	0
Collateral	0	0
Prepaid taxes and other	1	1
Total current assets	1,640	1,800
PROPERTY, PLANT AND EQUIPMENT:
In service	4,718	4,703
Less — Accumulated provision for depreciation	4,198	4,144
Property, plant and equipment in service net of accumulated provision for depreciation	520	559
Construction work in progress	427	358
Total net property, plant and equipment	947	917
INVESTMENTS:
Nuclear plant decommissioning trusts	1,593	1,552
Investment in affiliated companies	0	0
Other	0	1
Total other property and investments	1,593	1,553
DEFERRED CHARGES AND OTHER ASSETS:
Property taxes	21	28
Accumulated deferred income tax benefits	843	883
Derivatives	0	0
Other	0	0
Total deferred charges and other assets	864	911
Total assets	5,044	5,181
CURRENT LIABILITIES:
Currently payable long-term debt	5	5
Accounts payable-
Affiliated companies	198	406
Other	0	0
Accrued taxes	61	61
Derivatives	0	0
Other	15	10
Total current liabilities	280	482
CAPITALIZATION:
Total equity	2,073	2,006
Long-term debt and other long-term obligations	1,120	1,120
Total capitalization	3,193	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	726	713
Derivatives	0	0
Other	845	860
Total noncurrent liabilities	1,571	1,573
Total liabilities and capitalization	5,044	5,181
NG | Affiliates
CURRENT LIABILITIES:
Short-term borrowings - affiliated companies	1	0
Consolidated
CURRENT ASSETS:
Cash and cash equivalents	2	2	$ 2	$ 2
Receivables-
Customers	173	213
Affiliated companies	376	452
Other	51	27
Notes receivable from affiliated companies	0	29
Materials and supplies	252	267
Derivatives	43	137
Collateral	107	157
Prepaid taxes and other	51	63
Total current assets	1,055	1,347
PROPERTY, PLANT AND EQUIPMENT:
In service	7,108	7,057
Less — Accumulated provision for depreciation	5,998	5,929
Property, plant and equipment in service net of accumulated provision for depreciation	1,110	1,128
Construction work in progress	488	427
Total net property, plant and equipment	1,598	1,555
INVESTMENTS:
Nuclear plant decommissioning trusts	1,593	1,552
Investment in affiliated companies	0	0
Other	10	10
Total other property and investments	1,603	1,562
DEFERRED CHARGES AND OTHER ASSETS:
Property taxes	30	40
Accumulated deferred income tax benefits	2,268	2,279
Derivatives	17	77
Other	393	381
Total deferred charges and other assets	2,708	2,777
Total assets	6,964	7,241
CURRENT LIABILITIES:
Currently payable long-term debt	150	179
Accounts payable-
Affiliated companies	316	550
Other	107	110
Accrued taxes	137	143
Derivatives	25	77
Other	194	156
Total current liabilities	1,043	1,316
CAPITALIZATION:
Total equity	146	218
Long-term debt and other long-term obligations	2,812	2,813
Total capitalization	2,958	3,031
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	748	757
Accumulated deferred income taxes	0	0
Retirement benefits	202	197
Asset retirement obligations	915	901
Derivatives	3	52
Other	1,095	987
Total noncurrent liabilities	2,963	2,894
Total liabilities and capitalization	6,964	7,241
Consolidated | Affiliates
CURRENT LIABILITIES:
Short-term borrowings - affiliated companies	$ 114	$ 101

Supplemental Guarantor Inform63

Supplemental Guarantor Information (Details 2) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$ 785	$ 650
New Financing-
Short-term borrowings, net	75	425
Redemptions and Repayments-
Long-term debt	(211)	(31)
Other	(13)	(12)
Net cash (used for) provided from financing activities	(58)	230
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(588)	(698)
Nuclear fuel	(132)	(149)
Sales of investment securities held in trusts	738	465
Purchases of investment securities held in trusts	(761)	(488)
Other	16	39
Net cash used for investing activities	(762)	(865)
Net change in cash and cash equivalents	(35)	15
Cash and cash equivalents at beginning of period	199	131	$ 131
Cash and cash equivalents at end of period	164	146	199
Eliminations
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	0	0
New Financing-
Short-term borrowings, net	(88)	(312)
Redemptions and Repayments-
Long-term debt	0
Short-term borrowings, net	22	11
Other	0	0
Net cash (used for) provided from financing activities	(66)	(301)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	0	0
Nuclear fuel	0	0
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Cash investments		0
Loans to affiliated companies, net	66	301
Other		0
Net cash used for investing activities	66	301
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
FES
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	(142)	(356)
New Financing-
Short-term borrowings, net	100	352
Redemptions and Repayments-
Long-term debt	0
Short-term borrowings, net	0	0
Other	(1)	0
Net cash (used for) provided from financing activities	99	352
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	0	(27)
Nuclear fuel	0	0
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Cash investments		10
Loans to affiliated companies, net	43	12
Other		9
Net cash used for investing activities	43	4
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
FG
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	163	278
New Financing-
Short-term borrowings, net	0	8
Redemptions and Repayments-
Long-term debt	(29)
Short-term borrowings, net	(22)	(11)
Other	(2)	(3)
Net cash (used for) provided from financing activities	(53)	(6)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(21)	(53)
Nuclear fuel	0	0
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Cash investments		0
Loans to affiliated companies, net	(89)	(219)
Other		0
Net cash used for investing activities	(110)	(272)
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
NG
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	200	307
New Financing-
Short-term borrowings, net	1	1
Redemptions and Repayments-
Long-term debt	0
Short-term borrowings, net	0	0
Other	0	0
Net cash (used for) provided from financing activities	1	1
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(64)	(63)
Nuclear fuel	(132)	(149)
Sales of investment securities held in trusts	231	138
Purchases of investment securities held in trusts	(245)	(151)
Cash investments		0
Loans to affiliated companies, net	9	(83)
Other		0
Net cash used for investing activities	(201)	(308)
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
Consolidated
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	221	229
New Financing-
Short-term borrowings, net	13	49
Redemptions and Repayments-
Long-term debt	(29)	0
Short-term borrowings, net	0	0
Other	(3)	(3)
Net cash (used for) provided from financing activities	(19)	46
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(85)	(143)
Nuclear fuel	(132)	(149)
Sales of investment securities held in trusts	231	138
Purchases of investment securities held in trusts	(245)	(151)
Cash investments	0	10
Loans to affiliated companies, net	29	11
Other	0	9
Net cash used for investing activities	(202)	(275)
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

Segment Information (Details Te

Segment Information (Details Textuals) mi² in Thousands, customer in Millions, $ in Billions	3 Months Ended
	Mar. 31, 2017USD ($)mi²customercompanyMW	Mar. 07, 2017MW	Mar. 06, 2017MW	Jan. 31, 2017MW
Pleasants Power Station
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment		1,000
Purchase Agreement with Aspen Generating, LLC
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment	1,572			1,572
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 | $	$ 4.5
Long-term debt percentage bearing variable interest (percent)	33.00%
FirstEnergy | Revolving Credit Facility | Other/Corporate
Segment Reporting Information [Line Items]
Long-term line of credit | $	$ 2.8

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Segment Financial Information
Revenues		$ 3,552	$ 3,869
Revenues	[1]	3,552	3,869
Depreciation		275	329
Amortization of regulatory assets, net		59	61
Investment income		24	28
Interest expense		287	288
Income taxes (benefits)		126	213
NET INCOME		205	328
Total assets		43,212	52,695	$ 43,148
Goodwill		5,618	6,418	$ 5,618
Property additions		588	698
Operating Segments | Regulated Distribution
Segment Financial Information
Revenues		2,490	2,510
Revenues		2,490	2,510
Depreciation		178	167
Amortization of regulatory assets, net		57	59
Investment income		14	11
Interest expense		138	150
Income taxes (benefits)		138	94
NET INCOME		237	158
Total assets		27,826	27,447
Goodwill		5,004	5,004
Property additions		264	241
Operating Segments | Regulated Transmission
Segment Financial Information
Revenues		313	286
Revenues		313	286
Depreciation		51	45
Amortization of regulatory assets, net		2	2
Investment income		0	0
Interest expense		39	40
Income taxes (benefits)		52	47
NET INCOME		88	81
Total assets		8,938	8,139
Goodwill		614	614
Property additions		224	279
Operating Segments | Competitive Energy Services
Segment Financial Information
Revenues		814	1,152
Revenues		931	1,304
Depreciation		28	102
Amortization of regulatory assets, net		0	0
Investment income		20	15
Interest expense		45	47
Income taxes (benefits)		(35)	85
NET INCOME		(67)	144
Total assets		5,811	16,578
Goodwill		0	800
Property additions		92	169
Corporate/Other
Segment Financial Information
Revenues		0	0
Revenues		0	0
Depreciation		18	15
Amortization of regulatory assets, net		0	0
Investment income		3	11
Interest expense		65	51
Income taxes (benefits)		(29)	(13)
NET INCOME		(53)	(55)
Total assets		637	531
Goodwill		0	0
Property additions		8	9
Intersegment Eliminations
Segment Financial Information
Revenues		(117)	(152)
Intersegment Eliminations | Competitive Energy Services
Segment Financial Information
Revenues		117	152
Reconciling Adjustments
Segment Financial Information
Revenues		(65)	(79)
Revenues		(182)	(231)
Depreciation		0	0
Amortization of regulatory assets, net		0	0
Investment income		(13)	(9)
Interest expense		0	0
Income taxes (benefits)		0	0
NET INCOME		0	0
Total assets		0	0
Goodwill		0	0
Property additions		$ 0	$ 0
[1]	Includes excise tax collections of $100 million and $107 million in the three months ended March 31, 2017 and 2016, respectively.