FirstEnergy (FE) 10-Q 26 Apr 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	3 Months Ended
	Mar. 31, 2016shares
Entity Information [Line Items]
Entity Registrant Name	FIRSTENERGY CORP
Entity Central Index Key	1,031,296
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding	424,712,431
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, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
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, 2016	Mar. 31, 2015
REVENUES:
Regulated Distribution		$ 2,521	$ 2,562
Regulated Transmission		275	238
Unregulated businesses		1,073	1,097
Total revenues	[1]	3,869	3,897
OPERATING EXPENSES:
Fuel		381	513
Purchased power		1,124	1,113
Other operating expenses		918	1,057
Provision for depreciation		329	319
Amortization of regulatory assets, net		61	32
General taxes		280	269
Total operating expenses		3,093	3,303
OPERATING INCOME		776	594
OTHER INCOME (EXPENSE):
Investment income (loss)		28	17
Interest expense		(288)	(279)
Capitalized financing costs		25	34
Total other income (expense)		(235)	(228)
INCOME BEFORE INCOME TAXES		541	366
INCOME TAXES (BENEFITS)		213	144
NET INCOME (LOSS)		$ 328	$ 222
EARNINGS PER SHARE OF COMMON STOCK:
Basic - Net Earnings per Basic Share to FirstEnergy Corp., in dollars per share		$ 0.78	$ 0.53
Diluted - Net Earnings per Diluted Share Available to FirstEnergy Corp., in dollars per share		$ 0.77	$ 0.53
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic, in shares		424	421
Diluted, in shares		426	423
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share		$ 0.72	$ 0.72
[1]	Includes excise tax collections of $107 million and $115 million in the three months ended March 31, 2016 and 2015, respectively.

Consolidated Statements of Inc3

Consolidated Statements of Income (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Statement [Abstract]
Excise taxes collected	$ 107	$ 115

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (FirstEnergy Corp.) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
NET INCOME	$ 328	$ 222
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(18)	(31)
Amortized (gains) losses on derivative hedges	2	1
Change in unrealized gain on available-for-sale securities	28	4
Other comprehensive income (loss)	12	(26)
Income tax benefits on other comprehensive loss	4	(10)
Other comprehensive income (loss), net of tax	8	(16)
COMPREHENSIVE INCOME (LOSS)	$ 336	$ 206

Consolidated Balance Sheets (Fi

Consolidated Balance Sheets (FirstEnergy Corp.) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 146	$ 131
Receivables-
Customers, net of allowance for uncollectible accounts of $64 in 2016 and $69 in 2015	1,432	1,415
Other, net of allowance for uncollectible accounts of $5 in 2016 and 2015	162	180
Materials and supplies	781	785
Prepaid taxes	267	135
Derivatives	207	157
Collateral	80	70
Other	155	167
Total current assets	3,230	3,040
PROPERTY, PLANT AND EQUIPMENT:
In service	50,371	49,952
Less - Accumulated provision for depreciation	15,421	15,160
Property, plant and equipment in service net of accumulated provision for depreciation	34,950	34,792
Construction work in progress	2,694	2,422
Total net property, plant and equipment	37,644	37,214
INVESTMENTS:
Nuclear plant decommissioning trusts	2,360	2,282
Other	526	506
Total other property and investments	2,886	2,788
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418
Regulatory assets	1,279	1,348
Other	1,238	1,286
Total deferred charges and other assets	8,935	9,052
Total assets	52,695	52,094
CURRENT LIABILITIES:
Currently payable long-term debt	1,355	1,166
Short-term borrowings	2,125	1,708
Accounts payable	1,000	1,075
Accrued taxes	513	519
Accrued compensation and benefits	309	334
Derivatives	117	106
Other	970	694
Total current liabilities	6,389	5,602
Common stockholders' equity-
Common stock, $0.10 par value, authorized 490,000,000 shares - 424,712,431 and 423,560,397 shares outstanding as of March 31, 2016 and December 31, 2015, respectively	42	42
Other paid-in capital	9,963	9,952
Accumulated other comprehensive income	179	171
Retained earnings	2,279	2,256
Total common stockholders' equity	12,463	12,421
Noncontrolling interest	1	1
Total equity	12,464	12,422
Long-term debt and other long-term obligations	18,878	19,099
Total capitalization	31,342	31,521
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	6,996	6,773
Retirement benefits	4,135	4,245
Asset retirement obligations	1,427	1,410
Deferred gain on sale and leaseback transaction	782	791
Adverse power contract liability	194	197
Other	1,430	1,555
Total noncurrent liabilities	$ 14,964	$ 14,971
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	$ 52,695	$ 52,094

Consolidated Balance Sheets (F6

Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Common stockholders' equity-
Common stock, par value (in dollars per share)	$ 0.1	$ 0.1
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	424,712,431	423,560,397
Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 64	$ 69
Other [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 5	$ 5

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (FirstEnergy Corp.) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$ 328	$ 222
Adjustments to reconcile net income to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, and customer intangible asset amortization	455	425
Deferred purchased power and other costs	(10)	(31)
Deferred income taxes and investment tax credits, net	206	127
Deferred costs on sale leaseback transaction, net	12	12
Retirement benefits	16	(4)
Pension trust contributions	(160)	(143)
Commodity derivative transactions, net	(64)	2
Changes in current assets and liabilities-
Receivables	1	(97)
Materials and supplies	4	30
Prepayments and other current assets	(82)	(116)
Accounts payable	25	(177)
Accrued taxes	(110)	(80)
Accrued interest	47	44
Accrued compensation and benefits	(102)	(80)
Other current liabilities	19	11
Cash collateral, net	(6)	(15)
Other	59	63
Net cash provided from operating activities	638	193
New Financing-
Short-term borrowings, net	425	760
Redemptions and Repayments-
Long-term debt	(31)	(48)
Common stock dividend payments	(152)	(152)
Net cash provided from (used for) financing activities	242	560
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(698)	(668)
Nuclear fuel	(149)	(60)
Sales of investment securities held in trusts	465	371
Purchases of investment securities held in trusts	(488)	(394)
Cash investments	30	21
Asset removal costs	(34)	(28)
Other	9	10
Net cash used for investing activities	(865)	(748)
Net change in cash and cash equivalents	15	5
Cash and cash equivalents at beginning of period	131	$ 85
Cash and cash equivalents at end of period	$ 146

Consolidated Statements of Inc8

Consolidated Statements of Income and Comprehensive Income (Loss) (FirstEnergy Solutions Corp.) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
REVENUES:
Electric sales		$ 1,073	$ 1,097
Total revenues	[1]	3,869	3,897
OPERATING EXPENSES:
Fuel		381	513
Purchased power		1,124	1,113
Other operating expenses		918	1,057
Provision for depreciation		329	319
General taxes		280	269
Total operating expenses		3,093	3,303
OPERATING INCOME		776	594
OTHER INCOME (EXPENSE):
Investment income (loss)		28	17
Interest expense		(288)	(279)
Capitalized interest		25	34
Total other income (expense)		(235)	(228)
INCOME BEFORE INCOME TAXES		541	366
INCOME TAXES (BENEFITS)		213	144
NET INCOME (LOSS)		328	222
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)		328	222
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(18)	(31)
Amortized gains on derivative hedges		2	1
Change in unrealized gain on available-for-sale securities		28	4
Other comprehensive income (loss)		12	(26)
Income taxes (benefits) on other comprehensive income (loss)		4	(10)
Other comprehensive income (loss), net of tax		8	(16)
COMPREHENSIVE INCOME (LOSS)		336	206
FES
REVENUES:
Other		45	47
Total revenues		1,199	1,377
OPERATING EXPENSES:
Fuel		165	230
Other operating expenses		240	413
Provision for depreciation		83	80
General taxes		26	29
Total operating expenses		973	1,365
OPERATING INCOME		226	12
OTHER INCOME (EXPENSE):
Investment income (loss)		15	13
Capitalized interest		10	9
Total other income (expense)		(13)	(17)
INCOME BEFORE INCOME TAXES		213	(5)
INCOME TAXES (BENEFITS)		82	(2)
NET INCOME (LOSS)		131	(3)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)		131	(3)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(4)	(4)
Amortized gains on derivative hedges		0	(1)
Change in unrealized gain on available-for-sale securities		23	3
Other comprehensive income (loss)		19	(2)
Income taxes (benefits) on other comprehensive income (loss)		7	(1)
Other comprehensive income (loss), net of tax		12	(1)
COMPREHENSIVE INCOME (LOSS)		143	(4)
FES | Affiliates
REVENUES:
Electric sales		147	255
OPERATING EXPENSES:
Purchased power		82	70
OTHER INCOME (EXPENSE):
Interest expense		(2)	(2)
FES | Non-Affiliates
REVENUES:
Electric sales		1,007	1,075
OPERATING EXPENSES:
Purchased power		377	543
OTHER INCOME (EXPENSE):
Interest expense		$ (36)	$ (37)
[1]	Includes excise tax collections of $107 million and $115 million in the three months ended March 31, 2016 and 2015, respectively.

Consolidated Balance Sheets (F9

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 146	$ 131
Receivables-
Customers, net of allowance for uncollectible accounts of $8 in 2016 and 2015	1,432	1,415
Other, net of allowance for uncollectible accounts of $3 in 2016 and 2015	162	180
Materials and supplies	781	785
Derivatives	207	157
Collateral	80	70
Prepayments and other	155	167
Total current assets	3,230	3,040
PROPERTY, PLANT AND EQUIPMENT:
In service	50,371	49,952
Less - Accumulated provision for depreciation	15,421	15,160
Property, plant and equipment in service net of accumulated provision for depreciation	34,950	34,792
Construction work in progress	2,694	2,422
Total net property, plant and equipment	37,644	37,214
INVESTMENTS:
Nuclear plant decommissioning trusts	2,360	2,282
Other	526	506
Total other property and investments	2,886	2,788
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418
Other	1,238	1,286
Total deferred charges and other assets	8,935	9,052
Total assets	52,695	52,094
CURRENT LIABILITIES:
Currently payable long-term debt	1,355	1,166
Other	2,125	1,708
Accounts payable-
Accrued taxes	513	519
Derivatives	117	106
Other	970	694
Total current liabilities	6,389	5,602
Common stockholders' equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of March 31, 2016 and December 31, 2015	42	42
Accumulated other comprehensive income	179	171
Retained earnings	2,279	2,256
Total common stockholders' equity	12,463	12,421
Long-term debt and other long-term obligations	18,878	19,099
Total capitalization	31,342	31,521
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	782	791
Accumulated deferred income taxes	6,996	6,773
Retirement benefits	4,135	4,245
Asset retirement obligations	1,427	1,410
Other	1,430	1,555
Total noncurrent liabilities	$ 14,964	$ 14,971
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	$ 52,695	$ 52,094
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2
Receivables-
Customers, net of allowance for uncollectible accounts of $8 in 2016 and 2015	229	275
Affiliated companies	447	451
Other, net of allowance for uncollectible accounts of $3 in 2016 and 2015	107	59
Notes receivable from affiliated companies	0	11
Materials and supplies	446	470
Derivatives	207	154
Collateral	80	70
Prepayments and other	80	66
Total current assets	1,598	1,558
PROPERTY, PLANT AND EQUIPMENT:
In service	14,376	14,311
Less - Accumulated provision for depreciation	5,874	5,765
Property, plant and equipment in service net of accumulated provision for depreciation	8,502	8,546
Construction work in progress	1,273	1,157
Total net property, plant and equipment	9,775	9,703
INVESTMENTS:
Nuclear plant decommissioning trusts	1,372	1,327
Other	10	10
Total other property and investments	1,382	1,337
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	57	61
Goodwill	23	23
Property taxes	30	40
Derivatives	89	79
Other	385	367
Total deferred charges and other assets	584	570
Total assets	13,339	13,168
CURRENT LIABILITIES:
Currently payable long-term debt	549	512
Other		8
Accounts payable-
Affiliated companies	362	542
Other	116	139
Accrued taxes	71	76
Derivatives	115	104
Other	241	181
Total current liabilities	1,503	1,562
Common stockholders' equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of March 31, 2016 and December 31, 2015	3,614	3,613
Accumulated other comprehensive income	58	46
Retained earnings	2,077	1,946
Total common stockholders' equity	5,749	5,605
Long-term debt and other long-term obligations	2,480	2,510
Total capitalization	8,229	8,115
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	782	791
Accumulated deferred income taxes	722	600
Retirement benefits	339	332
Asset retirement obligations	838	831
Derivatives	21	38
Other	905	899
Total noncurrent liabilities	$ 3,607	$ 3,491
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	$ 13,339	$ 13,168
FES | Affiliated Entity [Member]
CURRENT LIABILITIES:
Affiliated companies	49	0
FES | Non-Affiliated Entity [Member]
CURRENT LIABILITIES:
Affiliated companies	$ 0	$ 8

Consolidated Balance Sheets (10

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Common stockholders' equity-
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	424,712,431	423,560,397
Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 64	$ 69
Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 5	$ 5
FES
Common stockholders' equity-
Common stock, no par value
Common stock, shares authorized	750	750
Common stock, shares outstanding	7	7
FES | Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 8	$ 8
FES | Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 3	$ 3

Consolidated Statements of Ca11

Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$ 328	$ 222
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, and customer intangible asset amortization	455	425
Deferred costs on sale and leaseback transaction, net	(12)	(12)
Deferred income taxes and investment tax credits, net	206	127
Commodity derivative transactions, net	(64)	2
Changes in current assets and liabilities-
Receivables	1	(97)
Materials and supplies	4	30
Prepayments and other current assets	(82)	(116)
Accounts payable	25	(177)
Accrued taxes	(110)	(80)
Accrued compensation and benefits	(102)	(80)
Other current liabilities	19	11
Cash collateral, net	(6)	(15)
Other	59	63
Net cash provided from operating activities	638	193
New financing-
Short-term borrowings, net	425	760
Redemptions and Repayments-
Long-term debt	(31)	(48)
Net cash provided from (used for) financing activities	242	560
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(698)	(668)
Nuclear fuel	(149)	(60)
Sales of investment securities held in trusts	465	371
Purchases of investment securities held in trusts	(488)	(394)
Cash investments	30	21
Other	9	10
Net cash used for investing activities	(865)	(748)
Net change in cash and cash equivalents	15	5
Cash and cash equivalents at beginning of period	131	85
Cash and cash equivalents at end of period	146
FES
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	131	(3)
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, and customer intangible asset amortization	138	144
Deferred costs on sale and leaseback transaction, net	(12)	(12)
Deferred income taxes and investment tax credits, net	113	34
Investment impairments	8	6
Commodity derivative transactions, net	(64)	1
Changes in current assets and liabilities-
Receivables	2	1
Materials and supplies	24	21
Prepayments and other current assets	(12)	(18)
Accounts payable	(103)	(75)
Accrued taxes	(15)	(24)
Accrued compensation and benefits	(11)	(9)
Other current liabilities	18	8
Cash collateral, net	(10)	12
Other	(3)	(5)
Net cash provided from operating activities	228	105
New financing-
Short-term borrowings, net	49	150
Redemptions and Repayments-
Long-term debt	0	(17)
Other	(2)	(2)
Net cash provided from (used for) financing activities	47	131
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(143)	(119)
Nuclear fuel	(149)	(60)
Sales of investment securities held in trusts	138	189
Purchases of investment securities held in trusts	(151)	(202)
Cash investments	10	0
Loans to affiliated companies, net	11	(44)
Other	9	0
Net cash used for investing activities	(275)	(236)
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, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	ORGANIZATION AND BASIS OF PRESENTATION Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms. FirstEnergy Corp. was organized under the laws of the State of Ohio in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, FES and its principal subsidiaries (FG and NG), AE Supply, MP, PE, WP, FET and its principal subsidiaries (ATSI and TrAIL), and AESC. In addition, FE holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., GPU Nuclear, Inc., and Allegheny Ventures, Inc. FirstEnergy and its subsidiaries are principally involved in the generation, transmission, and distribution of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving six million customers in the Midwest and Mid-Atlantic regions. Its generation subsidiaries control nearly 17,000 MW of capacity from a diverse mix of non-emitting nuclear, scrubbed coal, natural gas, hydroelectric and other renewables. FirstEnergy’s transmission operations include approximately 24,000 miles of lines and two regional transmission operation centers. These interim financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These interim financial statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2015 . These Notes to the Consolidated Financial Statements are combined for FirstEnergy and FES. FirstEnergy follows GAAP and complies with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The accompanying interim financial statements are unaudited, but reflect all adjustments, consisting of normal recurring adjustments, that, in the opinion of management, are necessary for a fair statement of the financial statements. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued. FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 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, 2016 and 2015 , capitalized financing costs on FirstEnergy's Consolidated Statements of Income include $8 million and $16 million , respectively, of allowance for equity funds used during construction and $17 million and $18 million , respectively, of capitalized interest. New Accounting Pronouncements In May 2014, the FASB issued, ASU 2014-09 "Revenue from Contracts with Customers", requiring entities to recognize revenue by applying a five-step model in accordance with the core principle to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue recognition are expanded. In August 2015, the FASB issued a final ASU deferring the effective date until fiscal years beginning after December 15, 2017. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, (the original effective date) . In March 2016, the FASB issued ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)", clarifying the principal versus agent implementation guidance in the following areas: unit of account at which the principal/agent determination is made; applying the control principle to certain types of transactions and the control principle and principal/agent indicators. In April 2016, the FASB issued ASU 2016-10, “Identifying Performance Obligations and Licensing”, clarifying the identification of performance obligations and the licensing implementation guidance. The standards shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting these standards. In February 2015, the FASB issued, ASU 2015-02 "Consolidations: Amendments to the Consolidation Analysis", which amends current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate whether an entity should be consolidated. A reporting entity must apply the amendments using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments retrospectively. FirstEnergy's adoption of ASU 2015-02, on January 1, 2016, did not result in a change in the consolidation of VIEs by FirstEnergy or its subsidiaries. See Note 6, Variable Interest Entities, for additional information. In April 2015, the FASB issued, ASU 2015-03 "Simplifying the Presentation of Debt Issuance Costs", which requires debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. I n addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements", which allows debt issuance costs related to line of credit arrangements to be presented as an asset and amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit. FirstEnergy adopted ASU 2015-15 and ASU 2015-03 beginning January 1, 2016. As of December 31, 2015, FirstEnergy and FES reclassified $93 million and $17 million of debt issuance costs included in Deferred Charges and Other Assets to Long-term Debt and Other Long-term Obligations. FirstEnergy will elect to continue presenting debt issuance costs relating to its revolving credit facilities as an asset. In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities . The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption can be elected for all financial statements of fiscal years and interim periods that have not yet been issued or that have not yet been made available for issuance. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted . Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment . FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In March of 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", which simplifies several aspects of the accounting for employee share-based payment. The new guidance will require all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also will not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. Additionally, in March of 2016, the FASB issued the following ASUs: • ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships” , • ASU 2016-06, “Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging Issues Task Force)", and • ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting”. 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, 2016
Earnings Per Share [Abstract]
EARNINGS PER SHARE OF COMMON STOCK	EARNINGS PER SHARE OF COMMON STOCK Basic earnings per share of common stock are computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock: (In millions, except per share amounts) For the Three Months Ended March 31 Reconciliation of Basic and Diluted Earnings per Share of Common Stock 2016 2015 Net income $ 328 $ 222 Weighted average number of basic shares outstanding 424 421 Assumed exercise of dilutive stock options and awards (1) 2 2 Weighted average number of diluted shares outstanding 426 423 Basic earnings per share of common stock $ 0.78 $ 0.53 Diluted earnings per share of common stock $ 0.77 $ 0.53 (1) For both the three months ended March 31, 2016 and March 31, 2015 , one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

Pension and Other Postemploymen

Pension and Other Postemployment Benefits	3 Months Ended
	Mar. 31, 2016
Compensation and Retirement Disclosure [Abstract]
PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS	PENSION AND OTHER POSTEMPLOYMENT BENEFITS In 2016, FirstEnergy has minimum required funding obligations of $381 million to its qualified pension plan, of which $160 million has been contributed to date. FirstEnergy expects to make future contributions to the qualified pension plan in 2016 with cash, equity or a combination thereof, depending on, among other things, market conditions. 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 2016 2015 2016 2015 (In millions) Service costs $ 48 $ 48 $ 1 $ 1 Interest costs 100 96 7 7 Expected return on plan assets (97 ) (111 ) (8 ) (8 ) Amortization of prior service costs (credits) 2 2 (20 ) (33 ) Net periodic costs (credits) $ 53 $ 35 $ (20 ) $ (33 ) FES' share of the net periodic pension and OPEB costs (credits) were as follows: Pension OPEB 2016 2015 2016 2015 (In millions) For the Three Months Ended March 31 $ 6 $ 4 $ (4 ) $ (5 ) Pension and OPEB obligations are allocated to FE's subsidiaries, including FES, employing the plan participants. The net periodic pension and OPEB costs (credits) (net of amounts capitalized) recognized in earnings by FE and FES were as follows: Net Periodic Benefit Expense (Credit) Pension OPEB For the Three Months Ended March 31 2016 2015 2016 2015 (In millions) FirstEnergy $ 37 $ 25 $ (15 ) $ (23 ) FES 6 4 (4 ) (4 )

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	3 Months Ended
	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME	ACCUMULATED OTHER COMPREHENSIVE INCOME The changes in AOCI, net of tax, in the three months ended March 31, 2016 and 2015 , for FirstEnergy are included in the following tables: FirstEnergy Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance as of 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 tax (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 AOCI Balance as of January 1, 2015 $ (37 ) $ 25 $ 258 $ 246 Other comprehensive income before reclassifications — 14 — 14 Amounts reclassified from AOCI 1 (10 ) (31 ) (40 ) Other comprehensive income (loss) 1 4 (31 ) (26 ) Income tax (benefits) on other comprehensive income (loss) — 1 (11 ) (10 ) Other comprehensive income (loss), net of tax 1 3 (20 ) (16 ) AOCI Balance as of March 31, 2015 $ (36 ) $ 28 $ 238 $ 230 The following amounts were reclassified from AOCI for FirstEnergy in the three months ended March 31, 2016 and 2015 : For the Three Months Ended March 31 Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (2) 2016 2015 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ (1 ) Other operating expenses Long-term debt 2 2 Interest expense 2 1 Total before taxes (1 ) — Income taxes $ 1 $ 1 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (13 ) $ (10 ) Investment income 5 4 Income taxes $ (8 ) $ (6 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (18 ) $ (31 ) (1) 7 11 Income taxes $ (11 ) $ (20 ) 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, 2016 and 2015 , for FES are included in the following tables: FES Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance as of 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 AOCI Balance as of January 1, 2015 $ (7 ) $ 21 $ 43 $ 57 Other comprehensive income before reclassifications — 13 — 13 Amounts reclassified from AOCI (1 ) (10 ) (4 ) (15 ) Other comprehensive income (loss) (1 ) 3 (4 ) (2 ) Income tax (benefits) on other comprehensive income (loss) — — (1 ) (1 ) Other comprehensive income (loss), net of tax (1 ) 3 (3 ) (1 ) AOCI Balance as of March 31, 2015 $ (8 ) $ 24 $ 40 $ 56 The following amounts were reclassified from AOCI for FES in the three months ended March 31, 2016 and 2015 : For the Three Months Ended March 31 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2016 2015 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ (1 ) Other operating expenses — — Income taxes (benefits) $ — $ (1 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (13 ) $ (10 ) Investment income 5 4 Income taxes (benefits) $ (8 ) $ (6 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (4 ) $ (4 ) (1) 2 1 Income taxes (benefits) $ (2 ) $ (3 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details. (2) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2016
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES FirstEnergy’s and FES’ interim effective tax rates reflect the estimated annual effective tax rates for 2016 and 2015 . These tax rates are affected by estimated annual permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period, but are not consistent from period to period. FirstEnergy’s effective tax rate from continuing operations for the three months ended March 31, 2016 and 2015 was 39.4% and 39.3% , respectively. FES’ effective tax rate from continuing operations for the three months ended March 31, 2016 and 2015 was 38.5% and 40.0% , respectively. During the three months ended March 31, 2016, FirstEnergy recorded unrecognized tax benefits of $69 million primarily related to protective refund claims filed with the state of Pennsylvania as a result of a recent ruling by the Commonwealth Court citing the state’s NOL carryover limitation violated the uniformity clause and was unconstitutional. The state of Pennsylvania has appealed this ruling to the Pennsylvania Supreme Court. As of March 31, 2016, it is reasonably possible that approximately $54 million of unrecognized tax benefits may be resolved within the next twelve months as a result of the statute of limitations expiring and an expected decision at the appeals level with respect to certain claims, of which approximately $16 million would affect FirstEnergy's effective tax rate. In February 2016, the IRS completed its examination of FirstEnergy’s 2014 federal income tax return and issued a full acceptance letter with no adjustments.

Variable Interest Entities

Variable Interest Entities	3 Months Ended
	Mar. 31, 2016
Variable Interest Entities [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. The caption "noncontrolling interest" within the consolidated financial statements is used to reflect the portion of a VIE that FirstEnergy consolidates, but does not own. In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance. Consolidated VIEs VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements): • PNBV Trust - PNBV , a business trust established by OE in 1996, issued certain beneficial interests and notes to fund the acquisition of a portion of the bonds issued by certain owner trusts in connection with the sale and leaseback in 1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. The beneficial ownership of PNBV includes a 3% interest by unaffiliated third parties. • Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly-owned limited liability companies (SPEs) which issued phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase-in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of March 31, 2016 and December 31, 2015 , $350 million and $362 million of the phase-in recovery bonds were outstanding, respectively. • JCP&L Securitization - In June 2002, JCP&L Transition Funding sold transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consist primarily of bondable transition property. As of March 31, 2016 and December 31, 2015 , $118 million and $128 million of the transition bonds were outstanding, respectively. • MP and PE Environmental Funding Companies - The entities issued bonds, the proceeds of which were used to construct environmental control facilities. The special purpose limited liability companies own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's and PE's West Virginia service territories. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the special purpose limited liability companies, have no recourse to any assets or revenues of the special purpose limited liability companies. As of March 31, 2016 and December 31, 2015 , $419 million and $429 million of the environmental control bonds were outstanding, respectively. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of the following VIEs: • Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture's economic performance. FEV's ownership interest is subject to the equity method of accounting. As discussed in Note 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 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. • Power Purchase Agreements - FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy maintains 14 long-term power purchase agreements with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that for all but one of these NUG entities, it does not have a variable interest in the entities or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities. Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contracts that may contain a variable interest during the three months ended March 31, 2016 and 2015 were $31 million . • Sale and Leaseback Transactions - FES and certain of the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to the Perry Unit 1, Beaver Valley Unit 2, and 2007 Bruce Mansfield Unit 1 sale and leaseback arrangements, 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, 2016, FirstEnergy's leasehold interest was 3.75% of Perry Unit 1, 93.83% of Bruce Mansfield Unit 1 and 2.60% of Beaver Valley Unit 2. On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors' interests in Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), which right to repurchase was assigned to NG. Additionally, on June 24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor equity interests of the remaining non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the end of the lease term. Upon the completion of these transactions, NG will have obtained all of the lessor equity interests at Perry Unit 1 and Beaver Valley Unit 2. FES and other FE subsidiaries are exposed to losses under their applicable sale and leaseback agreements upon the occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions as of March 31, 2016 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy $ 1,228 $ 967 $ 261 FES 1,171 949 222

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2016
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS RECURRING FAIR VALUE MEASUREMENTS Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows: Level 1 - Quoted prices for identical instruments in active market Level 2 - Quoted prices for similar instruments in active market - Quoted prices for identical or similar instruments in markets that are not active - Model-derived valuations for which all significant inputs are observable market data Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 - Valuation inputs are unobservable and significant to the fair value measurement FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast, which has been reviewed and approved by FirstEnergy's Risk Policy Committee, are used to measure fair value. A more detailed description of FirstEnergy's valuation process for FTRs and NUGs follows: FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 8, Derivative Instruments, for additional information regarding FirstEnergy's FTRs. NUG contracts represent purchase power agreements with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for the current year and next three years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on ICE quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of March 31, 2016 , from those used as of December 31, 2015 . The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements. Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the three months ended March 31, 2016 . The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: FirstEnergy Recurring Fair Value Measurements March 31, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,264 $ — $ 1,264 $ — $ 1,245 $ — $ 1,245 Derivative assets - commodity contracts 3 290 — 293 4 224 — 228 Derivative assets - FTRs — — 3 3 — — 8 8 Derivative assets - NUG contracts (1) — — 1 1 — — 1 1 Equity securities (2) 628 — — 628 576 — — 576 Foreign government debt securities — 73 — 73 — 75 — 75 U.S. government debt securities — 188 — 188 — 180 — 180 U.S. state debt securities — 245 — 245 — 246 — 246 Other (3) 146 232 — 378 105 212 — 317 Total assets $ 777 $ 2,292 $ 4 $ 3,073 $ 685 $ 2,182 $ 9 $ 2,876 Liabilities Derivative liabilities - commodity contracts $ (7 ) $ (122 ) $ — $ (129 ) $ (9 ) $ (122 ) $ — $ (131 ) Derivative liabilities - FTRs — — (9 ) (9 ) — — (13 ) (13 ) Derivative liabilities - NUG contracts (1) — — (136 ) (136 ) — — (137 ) (137 ) Total liabilities $ (7 ) $ (122 ) $ (145 ) $ (274 ) $ (9 ) $ (122 ) $ (150 ) $ (281 ) Net assets (liabilities) (4) $ 770 $ 2,170 $ (141 ) $ 2,799 $ 676 $ 2,060 $ (141 ) $ 2,595 (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (3) Primarily consists of short-term cash investments. (4) Excludes $(6) million and $7 million as of March 31, 2016 and December 31, 2015 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. Rollforward of Level 3 Measurements The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2016 and December 31, 2015 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2015 Balance $ 2 $ (153 ) $ (151 ) $ 39 $ (14 ) $ 25 Unrealized gain (loss) 2 (49 ) (47 ) (5 ) (7 ) (12 ) Purchases — — — 22 (11 ) 11 Settlements (3 ) 65 62 (48 ) 19 (29 ) December 31, 2015 Balance $ 1 $ (137 ) $ (136 ) $ 8 $ (13 ) $ (5 ) Unrealized loss — (12 ) (12 ) — (1 ) (1 ) Settlements — 13 13 (5 ) 5 — March 31, 2016 Balance $ 1 $ (136 ) $ (135 ) $ 3 $ (9 ) $ (6 ) (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings. Level 3 Quantitative Information The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2016 : Fair Value, Net (In millions) Valuation Technique Significant Input Range Weighted Average Units FTRs $ (6 ) Model RTO auction clearing prices ($4.60) to $3.70 $0.60 Dollars/MWH NUG Contracts $ (135 ) Model Generation 400 to 3,651,000 777,000 MWH Regional electricity prices $37.30 to $45.60 $39.60 Dollars/MWH FES Recurring Fair Value Measurements March 31, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 715 $ — $ 715 $ — $ 678 $ — $ 678 Derivative assets - commodity contracts 3 290 — 293 4 224 — 228 Derivative assets - FTRs — — 3 3 — — 5 5 Equity securities (1) 408 — — 408 378 — — 378 Foreign government debt securities — 58 — 58 — 59 — 59 U.S. government debt securities — 25 — 25 — 23 — 23 U.S. state debt securities — 4 — 4 — 4 — 4 Other (2) — 170 — 170 — 184 — 184 Total assets $ 411 $ 1,262 $ 3 $ 1,676 $ 382 $ 1,172 $ 5 $ 1,559 Liabilities Derivative liabilities - commodity contracts $ (7 ) $ (122 ) $ — $ (129 ) $ (9 ) $ (122 ) $ — $ (131 ) Derivative liabilities - FTRs — — (7 ) (7 ) — — (11 ) (11 ) Total liabilities $ (7 ) $ (122 ) $ (7 ) $ (136 ) $ (9 ) $ (122 ) $ (11 ) $ (142 ) Net assets (liabilities) (3) $ 404 $ 1,140 $ (4 ) $ 1,540 $ 373 $ 1,050 $ (6 ) $ 1,417 (1) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (2) Primarily consists of short-term cash investments. (3) Excludes $(8) million and $1 million as of March 31, 2016 and December 31, 2015 , 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, 2016 and December 31, 2015 : Derivative Asset Derivative Liability Net Asset (Liability) (In millions) January 1, 2015 Balance $ 27 $ (13 ) $ 14 Unrealized gain (loss) 2 (5 ) (3 ) Purchases 9 (10 ) (1 ) Settlements (33 ) 17 (16 ) December 31, 2015 Balance $ 5 $ (11 ) $ (6 ) Unrealized loss — (1 ) (1 ) Settlements (2 ) 5 3 March 31, 2016 Balance $ 3 $ (7 ) $ (4 ) 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, 2016 : Fair Value, Net (In millions) Valuation Technique Significant Input Range Weighted Average Units FTRs $ (4 ) Model RTO auction clearing prices ($4.60) to $3.70 $0.50 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, nuclear fuel disposal and NUG trusts. These trust investments are considered AFS securities, recognized at fair market value. FirstEnergy has no securities held for trading purposes. The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT, nuclear fuel disposal and NUG trusts as of March 31, 2016 and December 31, 2015 : March 31, 2016 (1) December 31, 2015 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,776 $ 44 $ 1,820 $ 1,778 $ 16 $ 1,794 FES 825 26 851 801 9 810 Equity securities FirstEnergy $ 576 $ 52 $ 628 $ 542 $ 34 $ 576 FES 372 36 408 354 24 378 (1) Excludes short-term cash investments: FE Consolidated - $161 million ; FES - $113 million . (2) Excludes short-term cash investments: FE Consolidated - $157 million ; FES - $139 million . Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three months ended March 31, 2016 and 2015 were as follows: Three Months Ended 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 March 31, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 371 $ 60 $ (50 ) $ (7 ) $ 25 FES 189 38 (28 ) (6 ) 14 Held-To-Maturity Securities The following table provides the amortized cost basis, unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of March 31, 2016 and December 31, 2015 : March 31, 2016 December 31, 2015 Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt Securities FirstEnergy $ 6 $ 1 $ 7 $ 6 $ 2 $ 8 The held-to-maturity debt securities contractually mature by June 30, 2017. Investments in employee benefit trusts and equity method investments totaling $271 million as of March 31, 2016 and $255 million as of December 31, 2015 , are excluded from the amounts reported above. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations, excluding capital lease obligations and net unamortized debt issuance costs, premiums and discounts: March 31, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 20,217 $ 21,821 $ 20,244 $ 21,519 FES 3,036 3,112 3,027 3,121 The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of March 31, 2016 and December 31, 2015 .

Derivative Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance. FirstEnergy has contractual derivative agreements through 2020 . Cash Flow Hedges FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating commodity prices and interest rates. Total pre-tax net unamortized losses included in AOCI associated with instruments previously designated as cash flow hedges totaled $11 million as of March 31, 2016 and December 31, 2015 . Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Less than $1 million of net unamortized losses is expected to be amortized to income during the next twelve months. FirstEnergy has used forward starting interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were designated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $39 million and $42 million as of March 31, 2016 and December 31, 2015 , respectively. Based on current estimates, approximately $9 million of these unamortized losses is expected to be amortized to interest expense during the next twelve months. Refer to Note 4, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the three months ended March 31, 2016 and 2015 . As of March 31, 2016 and December 31, 2015 , no commodity or interest rate derivatives were designated as cash flow hedges. Fair Value Hedges FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. As of March 31, 2016 and December 31, 2015 , no fixed-for-floating interest rate swap agreements were outstanding. Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $17 million and $20 million as of March 31, 2016 and December 31, 2015 , respectively. During the next twelve months, approximately $10 million of unamortized gains is expected to be amortized to interest expense. Amortization of unamortized gains included in long-term debt totaled approximately $3 million during the three months ended March 31, 2016 and 2015 . Commodity Derivatives FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances where the hedging relationship does not qualify for hedge accounting. Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas primarily for use in FirstEnergy’s combustion turbine units. Derivative instruments are not used in quantities greater than forecasted needs. As of March 31, 2016 , FirstEnergy’s net asset position under commodity derivative contracts was $164 million , which related to FES positions. Under these commodity derivative contracts, FES posted $4 million of collateral and received $25 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $5 million of additional collateral if the credit rating for its debt were to fall below investment grade. Based on commodity derivative contracts held as of March 31, 2016 , an increase in commodity prices of 10% would decrease net income by approximately $22 million during the next twelve months. NUGs As of March 31, 2016 , FirstEnergy's net liability position under NUG contracts was $135 million , representing contracts held at JCP&L, ME and PN. NUG contracts represent purchased power agreements with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. Changes in the fair value of NUG contracts are subject to regulatory accounting treatment and do not impact earnings. FTRs As of March 31, 2016 , FirstEnergy's and FES' FTR position was a $6 million and $4 million net liability, respectively, and FES posted $6 million of collateral. FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of PJM that have load serving obligations. The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets and have not been designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price less the obligation due to PJM, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FES and AE Supply are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s utilities are recorded as regulatory assets or liabilities. Directly allocated FTRs are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance. FirstEnergy records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets: Derivative Assets Derivative Liabilities Fair Value Fair Value March 31, December 31, March 31, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 205 $ 150 Commodity Contracts $ (109 ) $ (94 ) FTRs 2 7 FTRs (8 ) (12 ) 207 157 (117 ) (106 ) Deferred Charges and Other Assets - Other Noncurrent Liabilities - Adverse Power Contract Liability NUGs (1) (136 ) (137 ) Commodity Contracts 88 78 Noncurrent Liabilities - Other FTRs 1 1 Commodity Contracts (20 ) (37 ) NUGs (1) 1 1 FTRs (1 ) (1 ) 90 80 (157 ) (175 ) Derivative Assets $ 297 $ 237 Derivative Liabilities $ (274 ) $ (281 ) (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings. FirstEnergy enters into contracts with counterparties that allow for the offsetting of derivative assets and derivative liabilities under netting arrangements with the same counterparty. Certain of these contracts contain margining provisions that require the use of collateral to mitigate credit exposure between FirstEnergy and these counterparties. In situations where collateral is pledged to mitigate exposures related to derivative and non-derivative instruments with the same counterparty, FirstEnergy allocates the collateral based on the percentage of the net fair value of derivative instruments to the total fair value of the combined derivative and non-derivative instruments. The following tables summarize the fair value of derivative assets and derivative liabilities on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet March 31, 2016 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 293 $ (128 ) $ (25 ) $ 140 FTRs 3 (3 ) — — NUG contracts 1 — — 1 $ 297 $ (131 ) $ (25 ) $ 141 Derivative Liabilities Commodity contracts $ (129 ) $ 128 $ — $ (1 ) FTRs (9 ) 3 6 — NUG contracts (136 ) — — (136 ) $ (274 ) $ 131 $ 6 $ (137 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 228 $ (125 ) $ — $ 103 FTRs 8 (8 ) — — NUG contracts 1 — — 1 $ 237 $ (133 ) $ — $ 104 Derivative Liabilities Commodity contracts $ (131 ) $ 125 $ 3 $ (3 ) FTRs (13 ) 8 5 — NUG contracts (137 ) — — (137 ) $ (281 ) $ 133 $ 8 $ (140 ) The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of March 31, 2016 : Purchases Sales Net Units (In millions) Power Contracts 14 42 (28 ) MWH FTRs 15 — 15 MWH NUGs 4 — 4 MWH Natural Gas 81 1 80 mmBTU The effect of active derivative instruments not in a hedging relationship on the Consolidated Statements of Income during the three months ended March 31, 2016 and 2015 , are summarized in the following tables: Three Months Ended March 31 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain Recognized in: Other Operating Expense (1) $ 62 $ 2 $ 64 Realized Gain (Loss) Reclassified to: Revenues (1) $ 71 $ 2 $ 73 Purchased Power Expense (1) (45 ) — (45 ) Other Operating Expense (1) — (12 ) (12 ) Fuel Expense (8 ) — (8 ) (1) All amounts are associated with FES. Three Months Ended March 31 Commodity Contracts FTRs Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense (2) $ 11 $ (13 ) $ (2 ) Realized Gain (Loss) Reclassified to: Revenues (3) $ (1 ) $ 37 $ 36 Purchased Power Expense (4) (3 ) — (3 ) Other Operating Expense (5) — (13 ) (13 ) Fuel Expense (16 ) — (16 ) (2) Includes $11 million for commodity contracts and ($12) million for FTRs associated with FES. (3) Represents losses on structured financial contracts. Includes ($1) million for commodity contracts and $36 million for FTRs associated with FES. (4) Realized losses on financially settled wholesale sales contracts of $22 million were netted in purchased power. Includes ($3) million for commodity contracts associated with FES. (5) Includes ($13) million for FTRs associated with FES. The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during the three months ended March 31, 2016 and 2015 . Changes in the value of these instruments are deferred for future recovery from (or credit to) customers: Three Months Ended March 31 Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of January 1, 2016 $ (136 ) $ 1 $ (135 ) Unrealized loss (12 ) (1 ) (13 ) Settlements 13 (2 ) 11 Outstanding net asset (liability) as of March 31, 2016 $ (135 ) $ (2 ) $ (137 ) Outstanding net asset (liability) as of January 1, 2015 $ (151 ) $ 11 $ (140 ) Unrealized gain (loss) (8 ) 1 (7 ) Settlements 11 (11 ) — Outstanding net asset (liability) as of March 31, 2015 $ (148 ) $ 1 $ (147 )

Regulatory Matters

Regulatory Matters	3 Months Ended
	Mar. 31, 2016
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS STATE REGULATION Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates. In addition, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility. MARYLAND PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS. The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption and demand and requiring each electric utility to file a plan every three years. PE's current plan, covering the three-year period 2015-2017, was approved by the MDPSC on December 23, 2014. The costs of the 2015-2017 plan are expected to be approximately $66 million for that three-year period, of which $26 million was incurred through March 2016. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the level of savings achieved under PE's current plan for 2016, and ramping up 0.2% per year thereafter to reach 2% . PE continues to recover program costs subject to a five -year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE. On January 28, 2016, PE filed a request to increase plan spending by $2 million in order to reach the new goals for 2017 set in the July 16, 2015 order. On February 27, 2013, the MDPSC issued an order (the February 27 Order) requiring the Maryland electric utilities to submit analyses relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations. The order further required the Staff of the MDPSC to report on possible performance-based rate structures and to propose additional rules relating to feeder performance standards, outage communication and reporting, and sharing of special needs customer information. PE's responsive filings discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 27 Order, and projected that it would require approximately $2.7 billion in infrastructure investments over 15 years to attempt to achieve the quickest level of response for the largest storm projected in the February 27 Order. On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting. The Staff of the MDPSC also recommended the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that the utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not yet issued a ruling on any of those matters. NEW JERSEY JCP&L currently provides BGS for retail customers who do not choose a third party EGS and for customers of third party EGSs that fail to provide the contracted service. The supply for BGS is comprised of two components, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers. The second BGS component provides a fixed price service and is intended for smaller commercial and residential customers. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. Pursuant to the NJBPU's March 26, 2015 final order in JCP&L's 2012 rate case proceeding directing that certain studies be completed, on July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which include operational and financial components and is expected to take approximately one year to complete. In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases (Generic CTA proceeding), the NJBPU stated that it would continue to apply its current CTA policy in base rate cases, subject to incorporating the following modifications: (i) calculating savings using a five -year look back from the beginning of the test year; (ii) allocating savings with 75% retained by the company and 25% allocated to rate payers; and (iii) excluding transmission assets of electric distribution companies in the savings calculation. On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the Generic CTA proceeding to the New Jersey Superior Court and JCP&L has filed to participate as a respondent in that proceeding. Briefing has been completed, and oral argument has not yet been scheduled. In April 2016, JCP&L intends to file tariffs with the NJBPU proposing a general rate increase associated with its distribution operations that seeks to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses. The filing will request approval to increase annual operating revenues by approximately $142.1 million based upon a hybrid test year for the twelve months ending June 30, 2016. JCP&L will request that the new rates take effect in January 2017. On June 19, 2015, JCP&L, along with PN, ME, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. The procedural schedule was suspended while the NJBPU considers a motion on a legal issue regarding whether MAIT can be designated as a "public utility" in New Jersey. On February 24, 2016, the NJBPU issued an Order concluding that MAIT does not satisfy the “electricity distribution” element necessary for “public utility” status because MAIT would not own any electric distribution assets in New Jersey. On April 22, 2016, JCP&L and MAIT filed a supplemental petition and testimony seeking to include certain JCP&L distributions assets in the transfer to satisfy the "electricity distribution" element necessary for "public utility" status in accordance with the NJBPU’s February 24, 2016 order. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction. OHIO The Ohio Companies operate under their ESP 3 plan which expires on May 31, 2016. The material terms of ESP 3 include: • A base distribution rate freeze through May 31, 2016; • Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; • Economic development and assistance to low-income customers for the two -year plan period at levels established in the prior ESP; • A 6% generation rate discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); • A requirement to provide power to non-shopping customers at a market-based price set through an auction process; • Rider DCR that allows continued investment in the distribution system for the benefit of customers; • A commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five -year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million , subject to the outcome of certain FERC proceedings; • Securing generation supply for a longer period of time by conducting an auction for a three -year period rather than a one -year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility customers who do not switch to a competitive generation supplier; and • Extending the recovery period for costs associated with purchasing RECs mandated by SB221, Ohio's renewable energy and energy efficiency standard, through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the entire ESP period. Notices of appeal of the Ohio Companies' ESP 3 plan to the Supreme Court of Ohio were filed by the Northeast Ohio Public Energy Council and the ELPC. The oral argument in this matter occurred on January 6, 2016. The Ohio Companies filed an application with the PUCO on August 4, 2014 seeking approval of their ESP IV entitled Powering Ohio's Progress . The Ohio Companies filed a Stipulation and Recommendation on December 22, 2014, and supplemental stipulations and recommendations on May 28, 2015, and June 4, 2015. On December 1, 2015, the Ohio Companies filed a Third Supplemental Stipulation and Recommendation, which included PUCO Staff as a signatory party in addition to other signatories. The proposed ESP IV supports FirstEnergy's strategic focus on regulated operations and better positions the Ohio Companies to deliver on their ongoing commitment to upgrade, modernize and maintain reliable electric service for customers while preserving electric security in Ohio. The material terms of the proposed ESP IV, as modified by the stipulations include: • An eight -year term (June 1, 2016 - May 31, 2024); • Contemplates continuing a base distribution rate freeze through May 31, 2024; • An Economic Stability Program that flows through charges or credits through Rider RRS representing the net result of the price paid to FES through an eight -year FERC-jurisdictional PPA, referred to as the ESP IV PPA, for the output of the ESP IV PPA Facilities against the revenues received from selling such output into the PJM markets over the same period, subject to the PUCO’s termination of Rider RRS associated with any of the ESP IV PPA Facilities that may be sold or transferred; • Continuing to provide power to non-shopping customers at a market-based price set through an auction process; • Continuing Rider DCR with increased revenue caps of approximately $30 million per year from June 1, 2016 through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024 that supports continued investment related to the distribution system for the benefit of customers; • Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; • A risk-sharing mechanism that would provide guaranteed credits under Rider RRS in years five through eight to customers as follows: $10 million in year five, $20 million in year six, $30 million in year seven and $40 million in year eight; • A continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of the five -year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided by customers for certain types of products totals $360 million , including such costs from MISO along with such costs from PJM, subject to the outcome of certain FERC proceedings; • Potential procurement of 100 MW of new Ohio wind or solar resources subject to a demonstrated need to procure new renewable energy resources as part of a strategy to further diversify Ohio's energy portfolio; • An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential customers; • An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016); • A goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045; • A contribution of $3 million per year ( $24 million over the eight -year term) to fund energy conservation programs, economic development and job retention in the Ohio Companies service territory; • Contributions of $2.4 million per year ( $19 million over the eight -year term) to fund a fuel-fund in each of the Ohio Companies service territories to assist low-income customers; and • A contribution of $1 million per year ( $8 million over the eight -year term) to establish a Customary Advisory Council to ensure preservation and growth of the competitive market in Ohio. On March 31, 2016, the PUCO issued an Opinion and Order adopting and approving, with modifications, the Ohio Companies’ ESP IV. Changes arising from the approval of ESP IV will go into effect on June 1, 2016. The PUCO’s modifications of ESP IV, among others, included: • Limiting average customer bill amounts for the first two years of the plan, subject to certain exceptions, and permitting deferral for the second year; • Prohibiting recovery of retirement costs of the ESP IV PPA Facilities through Rider RRS; • Assigning the burden of capacity performance penalties incurred by the ESP IV PPA Facilities to the Ohio Companies, rather than customers, and to provide that all capacity performance bonuses earned by the ESP IV PPA Facilities be retained by the Ohio Companies, rather than customers; and • Providing for the modification of the severability provision previously included in ESP IV, to also address potential future PJM Tariff or rule changes prohibiting the Ohio Companies from offering output of the ESP IV PPA Facilities into PJM auctions. Applications for Rehearing may be filed within thirty days of the issuance of the March 31, 2016 Opinion and Order. On January 27, 2016, certain parties filed a complaint with FERC against FES and the Ohio Companies that requests FERC review the ESP IV PPA under Section 205 of the FPA. FES and the Ohio Companies responded to the complaint on February 23, 2016 and March 9, 2016. In a separate proceeding 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 asks that FERC issue an order by May 1, 2016, so the revised rule can be in effect for the May 2016 PJM capacity auction. The Ohio Companies responded to the complaint on April 11, 2016 and April 20, 2016. In addition to such proceedings, opponents have expressed an intention to challenge in the courts and/or before FERC, the ESP IV PPA or PUCO's approval of the ESP IV. Management intends to vigorously defend against such challenges. FES and the Ohio Companies entered into the ESP IV PPA on April 1, 2016. Under Ohio's energy efficiency standards (SB221 and SB310), and based on the Ohio Companies' amended energy efficiency plans, the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of 2,266 GWHs in 2015 and 2,288 GWHs in 2016, and then begin to increase by 1% each year in 2017, subject to legislative amendments to the energy efficiency standards discussed below. The Ohio Companies are also required to retain the 2014 peak demand reduction level for 2015 and 2016 and then increase the benchmark by an additional 0.75% thereafter through 2020, subject to legislative amendments to the peak demand reduction standards discussed below. On September 30, 2015, the Energy Mandates Study Committee issued its report related to energy efficiency and renewable energy mandates, recommending that the current level of mandates remain in place indefinitely. The report also recommended: (i) an expedited process for review of utility proposed energy efficiency plans; (ii) ensuring maximum credit for all of Ohio's Energy Initiatives; (iii) a switch from energy mandates to energy incentives; and (iv) a declaration be made that the General Assembly may determine energy policy of the state. No legislation has yet been introduced to change the standards described above. On September 24, 2014, the Ohio Companies filed an amendment to their energy efficiency portfolio plan as contemplated by SB310, seeking to suspend certain programs for the 2015-2016 period in order to better align the plan with the new benchmarks under SB310. On November 20, 2014, the PUCO approved the Ohio Companies' amended portfolio plan. Several applications for rehearing were filed, and the PUCO granted those applications for further consideration of the matters specified in those applications and the matter remains pending before the PUCO. On April 15, 2016, the Ohio Companies filed an application for approval of their three-year energy efficiency portfolio plans for the period from January 1, 2017 through December 31, 2019. The plans as proposed comply with benchmarks contemplated by SB310 and provisions of the ESP IV, and include a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities. The Ohio Companies anticipate the cost of the plans will be approximately $323 million over the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On September 16, 2013, the Ohio Companies filed with the Supreme Court of Ohio a notice of appeal of the PUCO's July 17, 2013 Entry on Rehearing related to energy efficiency, alternative energy, and long-term forecast rules stating that the rules issued by the PUCO are inconsistent with, and are not supported by, statutory authority. On October 23, 2013, the PUCO filed a motion to dismiss the appeal, which is still pending. The matter has not been scheduled for oral argument. Ohio law requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage amount through 2026, subject to legislative amendments discussed above, except 2015 and 2016 that remain at the 2014 level. The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements. In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs. The PUCO issued an Opinion and Order on August 7, 2013, approving the Ohio Companies' acquisition process and their purchases of RECs to meet statutory mandates in all instances except for certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of $43.4 million , plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent. On December 24, 2013, following the denial of their application for rehearing, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted. On February 18, 2014, the OCC and the ELPC also filed appeals of the PUCO's order. The Ohio Companies timely filed their merit brief with the Supreme Court of Ohio and the briefing process has concluded. The matter is not yet scheduled for oral argument. On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers. 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. On November 3, 2015, the Pennsylvania Companies filed their proposed DSPs for the June 1, 2017 through May 31, 2019 delivery period, which would provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Under the proposed programs, the supply would be provided by wholesale suppliers though 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 proposal includes modifications to the Pennsylvania Companies’ existing POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges. A hearing was held on February 25, 2016. A Joint Petition for Settlement resolving all issues was filed on April 1, 2016, which is subject to PPUC approval. Pursuant to Pennsylvania's EE&C legislation (Act 129 of 2008) and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies' Phase II EE&C Plans are effective through May 31, 2016. Total Phase II costs of these plans are expected to be approximately $175 million and recoverable through the Pennsylvania Companies' reconcilable EE&C riders. On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at 1.8% for ME, 1.7% for Penn, 1.8% for WP, and 0% for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at 4.0% for ME, 3.9% for PN, 3.3% for Penn, and 2.6% for WP. The Pennsylvania Companies filed their Phase III EE&C plans for the June 2016 through May 2021 period on November 23, 2015, which are designed to achieve the targets established in the PPUC's Phase III Final Implementation Order. EDCs are permitted to recover costs for implementing their EE&C plans. On February 10, 2016, the Pennsylvania Companies and the parties intervening in the PPUC's Phase III proceeding filed a joint settlement resolving all issues, which was subject to PPUC approval. On March 10, 2016, the PPUC entered an Opinion and Order approving the settlement and directing that the Pennsylvania Companies modify certain cost recovery methodologies to describe the allocation of EE&C Phase III common costs among customer classes and to describe the recovery of remaining costs of their Phase II EE&C Plans. None of the parties to the joint settlement elected to withdraw from the joint settlement due to the modifications. Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. Pennsylvania EDCs must file LTIIPs outlining infrastructure improvement plans for PPUC review and approval prior to approval of a DSIC. On October 19, 2015, each of the Pennsylvania Companies filed LTIIPs with the PPUC for infrastructure improvement over the five -year period of 2016 to 2020 for the following costs: WP $88.34 million ; PN $56.74 million ; Penn $56.35 million ; and ME $43.44 million . These amounts include all qualifying distribution capital additions identified in the revised implementation plan for the recent focused management and operations audit of the Pennsylvania Companies as discussed below. 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. The DSIC riders are expected to be effective July 1, 2016. Various parties have filed interventions, answers, or complaints with the PPUC in response to the Pennsylvania Companies’ request for approval of the DSIC filings raising cost allocation and other issues, and the Pennsylvania Companies have responded. In April 2016, each of the Pennsylvania Companies intends to file tariffs with the PPUC proposing general rate increases associated with their distribution operations that will benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements. The filings will request approval to increase annual operating revenues by approximately $140.2 million at ME, $158.8 million at PN, $42.0 million at Penn, and $98.2 million at WP, based upon fully projected future test years for the twelve months ending December 31, 2017 at each of the Pennsylvania Companies. The new rates are expected to take effect in January 2017. On June 19, 2015, ME and PN, along with JCP&L, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. On March 4, 2016, a Joint Petition for Full Settlement was submitted to the PPUC for consideration and approval. On April 18, 2016, the ALJs issued an Initial Decision approving the Joint Petition for Full Settlement without modifications. A final decision from the PPUC is expected by mid-2016. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction. WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP's and PE's ENEC rate is updated annually. MP and PE filed with the WVPSC on March 31, 2016 their Phase II energy efficiency program proposal for approval. MP and PE are proposing three energy efficiency programs to meet their Phase II requirement of energy efficiency reductions of 0.5% of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, as agreed to by MP and PE, and approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of Harrison Power Station to MP. The costs for the program are expected to be $9.9 million which would be recovered through the existing energy efficiency rider which is reviewed in the fuel (ENEC) case each year. MP and PE are requesting WVPSC approval by October 1, 2016 so MP and PE can implement the programs beginning January 1, 2017. RELIABILITY MATTERS Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, AE Supply, FG, FENOC, NG, ATSI and TrAIL. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC. FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy's part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, 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 For information regarding matters before FERC related to the ESP IV PPA between FES and the Ohio Companies, see “Regulatory Matters - Ohio” above. PJM Transmission Rates PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities. While FirstEnergy and other parties advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM. This question has been the subject of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit. On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines. The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole. The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings. Settlement discussions under a FERC-appointed settlement judge are ongoing. In a series of orders in certain Order No. 1000 dockets, FERC asserted that the PJM transmission owners do not hold an incumbent “right of first refusal” to construct, own and operate transmission projects within their r

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	3 Months Ended
	Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS, GUARANTEES AND CONTINGENCIES	COMMITMENTS, GUARANTEES AND CONTINGENCIES GUARANTEES AND OTHER ASSURANCES FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. As of March 31, 2016 , FirstEnergy's outstanding guarantees and other assurances aggregated approximately $3.7 billion , consisting of parental guarantees ( $591 million ), subsidiaries' guarantees ( $2.1 billion ), other guarantees ( $300 million ) and other assurances ( $669 million ). Of this aggregate amount, substantially all relates to guarantees of wholly-owned consolidated entities of FirstEnergy. FES' debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each of FG and NG. Accordingly, present and future holders of indebtedness of FES, FG and NG would have claims against each of FES, FG and NG, regardless of whether their primary obligor is FES, FG or NG. COLLATERAL AND CONTINGENT-RELATED FEATURES In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel, and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on FES' power portfolio exposures as of March 31, 2016 , FES has posted collateral of $180 million . The Regulated Distribution segment has posted collateral of $1 million . These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. Subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of FE or its subsidiaries. The following table discloses the additional credit contingent contractual obligations that may be required under certain events as of March 31, 2016 : Collateral Provisions FES/ AE Supply (Tied to FE Corp. Rating) FES/ AE Supply (Tied to FES Rating) Utilities Total (In millions) Split Rating (One rating agency's rating below investment grade) $ 25 $ 173 $ 40 $ 238 Non-Investment Grade Ratings (All Rating Agencies at or below BB+/Ba1) $ 25 $ 200 $ 40 $ 265 Total Exposure from Contractual Obligations $ 25 $ 341 $ 40 $ 406 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, 2016 , neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES would be required to post $3 million with affiliated parties. 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. During the first quarter of 2015, a subsidiary of Global Holding eliminated its right to put 2 million tons annually through 2024 from the Signal Peak mine to FG in exchange for FE extending its guarantee under Global Holding's $300 million senior secured term loan facility through 2020, resulting in a pre-tax charge of $24 million . See Note 6, Variable Interest Entities, for additional information regarding FEV's investment in Global Holding . ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Clean Air Act FirstEnergy complies with SO 2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls, generating more electricity from lower or non-emitting plants and/or using emission allowances. CSAPR requires reductions of NOx and SO 2 emissions in two phases (2015 and 2017), ultimately capping SO 2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions. 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 proposed a CSAPR update rule on November 16, 2015, that would reduce summertime NOx emissions from power plants in 23 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Depending on how the EPA and the states implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's and FES' operations may result. EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015. EPA stated the vast majority of U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and state rules and programs but EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017. States will then have roughly three years to develop implementation plans to attain the new 2015 ozone NAAQS. Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be material and changes to FirstEnergy’s and FES’ operations may result. MATS imposes emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant. FirstEnergy's total capital cost for compliance (over the 2012 to 2018 time period) is currently expected to be approximately $345 million (CES segment of $168 million and Regulated Distribution segment of $177 million ), of which $226 million has been spent through March 31, 2016 ( $96 million at CES and $130 million at Regulated Distribution). On August 3, 2015, FG, a subsidiary of FES, submitted to the AAA office in New York, N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure 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, those plants were deactivated by April 16, 2015. In January 2012, FG notified BNSF and CSX that MATS constituted a force majeure event under the contract that excused FG’s further performance. Separately, on August 4, 2015, BNSF and CSX submitted to the AAA office in Washington, D.C., a demand for arbitration and statement of claim against FG alleging that FG breached the contract and that FG’s declaration of a force majeure under the contract is not valid and seeking damages including, but not limited to, lost profits under the contract through 2025. As part of its statement of claim, a right to liquidated damages is alleged. The arbitration panel has determined to consolidate the claims with a liability hearing expected to begin in November 2016, and, if necessary, a damages hearing is expected to begin in May 2017. The decision on liability is expected to be issued within sixty days from the end of the liability hearings. FirstEnergy and FES continue to believe that MATS constitutes a force majeure event under the contract as it relates to the deactivated plants and that FG’s performance under the contract is therefore excused. FirstEnergy and FES intend to vigorously assert their position in the arbitration proceedings. If, however, the arbitration panel rules in favor of BNSF and CSX, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. FirstEnergy and FES are unable to estimate the loss or range of loss. FG is also a party to another coal transportation contract covering the delivery of 2.5 million tons annually through 2025, a portion of which is to be delivered to another coal-fired plant owned by FG that was deactivated as a result of MATS. FG has asserted a defense of force majeure in response to delivery shortfalls to such plant under this contract as well. If FirstEnergy and FES fail to reach a resolution with the applicable counterparties to the contract, and if it were ultimately determined that, contrary to FirstEnergy’s and FES’ belief, the force majeure provisions of that contract do not excuse the delivery shortfalls to the deactivated plant, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. FirstEnergy and FES are unable to estimate the loss or range of loss. As to both coal transportation agreements referenced above, FES paid in settlement approximately $70 million in liquidated damages for delivery shortfalls in 2014 related to its deactivated plants. As to a specific coal supply agreement, FirstEnergy and AE Supply have asserted termination rights effective in 2015. In response to notification of the termination, the coal supplier commenced litigation alleging FirstEnergy and AE Supply do not have sufficient justification to terminate the agreement. FirstEnergy and AE Supply have filed an answer denying any liability related to the termination. This matter is currently in the discovery phase of litigation and no trial date has been established. There are approximately 5.5 million tons remaining under the contract for delivery. At this time, FirstEnergy cannot estimate the loss or range of loss regarding the on-going litigation with respect to this agreement. In September 2007, AE received an NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia. The EPA's NOV alleges equipment replacements during maintenance outages triggered the pre-construction permitting requirements under the NSR and PSD programs. On June 29, 2012, January 31, 2013, and March 27, 2013, EPA issued CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. On December 12, 2014, EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009. FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss. Climate Change FirstEnergy has established a goal to reduce CO 2 emissions by 90% below 2005 levels by 2045. There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation. The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act” in December 2009, concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. The EPA released its final regulations in August 2015, to reduce CO 2 emissions from existing fossil fuel fired electric generating units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO 2 emission rate goals. The EPA’s CPP allows states to request a two -year extension to finalize SIPs by September 6, 2018. If states fail to develop SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions trading rules which states can also adopt in their SIPs. The EPA also finalized separate regulations imposing CO 2 emission limits for new, modified, and reconstructed fossil fuel fired electric generating units. On June 23, 2014, the United States Supreme Court decided that CO 2 or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies. Numerous states and private parties filed appeals and motions to stay the CPP with the U.S. Court of Appeals for the D.C. Circuit in October 2015. On January 21, 2015, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court . Depending on the outcome of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material. At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide greenhouse gas emissions by 26 to 28 percent below 2005 levels by 2025 and joined in adopting the agreement reached on December 12, 2015 at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement must be ratified by at least 55 countries representing at least 55% of global GHG emissions before its non-binding obligations to limit global warming to well below two degrees Celsius become effective. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. The CO 2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO 2 emitting gas-fired and nuclear generators. Clean Water Act Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from the plant's cooling water intake system. Depending on the results of such studies and any final action taken by the states based on those studies, the future capital costs of compliance with these standards may be substantial. On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations will phase-in as permits are renewed on a five -year cycle from 2018 to 2023. The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's and FES' operations may result. In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the effluent limits that were effective immediately under the terms of the NPDES permit. MP appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require an initial capital investment ranging from $150 million to $300 million in order to install technology to meet the TDS and sulfate limits, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of the appeal or estimate the possible loss or range of loss. FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the loss or range of loss. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although unexpected, changes in timing and closure plan requirements in the future could impact our asset retirement obligations significantly . Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRs by December 31, 2016 and FG to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FG to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCRs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The Bruce Mansfield plant is pursuing several options for disposal of CCRs following December 31, 2016 and expects beneficial reuse and disposal options will be sufficient for the ongoing operation of the plant. On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR. On July 6, 2015 and October 22, 2015, the Sierra Club filed Notices of Appeal with the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility. FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of March 31, 2016 based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $123 million have been accrued through March 31, 2016 . Included in the total are accrued liabilities of approximately $87 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, 2016 , FirstEnergy had approximately $2.4 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. The values of FirstEnergy's NDTs fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs. 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 required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantees, as appropriate. In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years. On December 8, 2015, the NRC renewed the operating license for Davis-Besse, which is now authorized to continue operation through April 22, 2037. Prior to that decision, the NRC Commissioners denied an intervenor's request to reopen the record and admit a contention on the NRC’s Continued Storage Rule. On August 6, 2015, this intervenor sought review of the NRC Commissioners' decision before the U.S. Court of Appeals for the DC Circuit. FENOC intervened in that proceeding. 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 related to the Shield Building analysis in 2016. On March 12, 2012, the NRC issued orders requiring safety enhancements at U.S. reactors based on recommendations from the lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders require additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in spent fuel pools. The NRC also requested that licensees including FENOC: re-analyze earthquake and flooding risks using the latest information available; conduct earthquake and flooding hazard walkdowns at their nuclear plants; assess the ability of current communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power; and assess plant staffing levels needed to fill emergency positions. These and other NRC requirements adopted as a result of the accident at Fukushima Daiichi are likely to result in additional material costs from plant modifications and upgrades at FirstEnergy's nuclear facilities. Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The loss or range of loss in these matters is not expected to be material to FirstEnergy or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 9, Regulatory Matters of the Combined Notes to Consolidated Financial Statements. FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.

Supplemental Guarantor Informat

Supplemental Guarantor Information	3 Months Ended
	Mar. 31, 2016
Supplemental Guarantor Information [Abstract]
SUPPLEMENTAL GUARANTOR INFORMATION	SUPPLEMENTAL GUARANTOR INFORMATION In 2007, FG completed a sale and leaseback transaction for a 93.83% undivided interest in Bruce Mansfield Unit 1. FES has fully and unconditionally and irrevocably guaranteed all of FG's obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FG, but the notes are secured by, among other things, each lessor trust's undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES' lease guaranty. This transaction is classified as an operating lease for FES and FirstEnergy and as a financing lease for FG. The Condensed Consolidating Statements of Income (Loss) and Comprehensive Income (Loss) for the three months ended March 31, 2016 and 2015 , Condensed Consolidating Balance Sheets as of March 31, 2016 and December 31, 2015 , and Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2016 and 2015 , for FES (parent and guarantor), FG and NG (non-guarantor) are presented below. These statements are provided as FES fully and unconditionally guarantees outstanding registered securities of FG as well as FG's obligations under the facility lease for the Bruce Mansfield sale and leaseback that underlie outstanding registered pass-through trust certificates. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FG and NG are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction. FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME 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 251 6 17 (259 ) 15 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 BEFORE INCOME TAXES (BENEFITS) 65 164 229 (245 ) 213 INCOME TAXES (BENEFITS) (66 ) 61 86 1 82 NET INCOME $ 131 $ 103 $ 143 $ (246 ) $ 131 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 131 $ 103 $ 143 $ (246 ) $ 131 OTHER COMPREHENSIVE INCOME (LOSS): Pensions and OPEB prior service costs (4 ) (3 ) — 3 (4 ) Change in unrealized gain 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 $ 143 $ 101 $ 158 $ (259 ) $ 143 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Three Months Ended March 31, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 1,332 $ 493 $ 507 $ (955 ) $ 1,377 OPERATING EXPENSES: Fuel — 180 50 — 230 Purchased power from affiliates 957 — 68 (955 ) 70 Purchased power from non-affiliates 543 — — — 543 Other operating expenses 180 67 154 12 413 Provision for depreciation 3 30 48 (1 ) 80 General taxes 15 8 6 — 29 Total operating expenses 1,698 285 326 (944 ) 1,365 OPERATING INCOME (LOSS) (366 ) 208 181 (11 ) 12 OTHER INCOME (EXPENSE): Investment income, including net income from equity investees 241 3 14 (245 ) 13 Interest expense — affiliates (6 ) (2 ) (1 ) 7 (2 ) Interest expense — other (13 ) (26 ) (13 ) 15 (37 ) Capitalized interest — 1 8 — 9 Total other income (expense) 222 (24 ) 8 (223 ) (17 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (144 ) 184 189 (234 ) (5 ) INCOME TAXES (BENEFITS) (141 ) 67 70 2 (2 ) NET INCOME (LOSS) $ (3 ) $ 117 $ 119 $ (236 ) $ (3 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (3 ) $ 117 $ 119 $ (236 ) $ (3 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (4 ) (4 ) 3 1 (4 ) Amortized gain on derivative hedges (1 ) — — — (1 ) Change in unrealized gain on available-for-sale securities 3 — — — 3 Other comprehensive income (loss) (2 ) (4 ) 3 1 (2 ) Income taxes (benefits) on other comprehensive income (loss) (1 ) (1 ) 1 — (1 ) Other comprehensive income (loss), net of tax (1 ) (3 ) 2 1 (1 ) COMPREHENSIVE INCOME (LOSS) $ (4 ) $ 114 $ 121 $ (235 ) $ (4 ) FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of March 31, 2016 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 229 — — — 229 Affiliated companies 442 310 305 (610 ) 447 Other 32 1 74 — 107 Notes receivable from affiliated companies 394 1,429 889 (2,712 ) — Materials and supplies 39 191 216 — 446 Derivatives 207 — — — 207 Collateral 80 — — — 80 Prepayments and other 69 11 — — 80 1,492 1,944 1,484 (3,322 ) 1,598 PROPERTY, PLANT AND EQUIPMENT: In service 92 6,389 8,277 (382 ) 14,376 Less — Accumulated provision for depreciation 43 2,163 3,863 (195 ) 5,874 49 4,226 4,414 (187 ) 8,502 Construction work in progress 30 271 972 — 1,273 79 4,497 5,386 (187 ) 9,775 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,372 — 1,372 Investment in affiliated companies 7,712 — — (7,712 ) — Other — 10 — — 10 7,712 10 1,372 (7,712 ) 1,382 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 276 — — (276 ) — Customer intangibles 57 — — — 57 Goodwill 23 — — — 23 Property taxes — 9 21 — 30 Derivatives 89 — — — 89 Other 24 301 4 56 385 469 310 25 (220 ) 584 $ 9,752 $ 6,761 $ 8,267 $ (11,441 ) $ 13,339 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 266 $ 308 $ (25 ) $ 549 Short-term borrowings- Affiliated companies 2,373 386 2 (2,712 ) 49 Accounts payable- Affiliated companies 619 190 172 (619 ) 362 Other 26 90 — — 116 Accrued taxes 3 52 101 (85 ) 71 Derivatives 115 — — — 115 Other 75 74 15 77 241 3,211 1,058 598 (3,364 ) 1,503 CAPITALIZATION: Total equity 5,749 3,046 4,634 (7,680 ) 5,749 Long-term debt and other long-term obligations 690 2,067 840 (1,117 ) 2,480 6,439 5,113 5,474 (8,797 ) 8,229 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 782 782 Accumulated deferred income taxes 6 35 743 (62 ) 722 Retirement benefits 28 311 — — 339 Asset retirement obligations — 188 650 — 838 Derivatives 21 — — — 21 Other 47 56 802 — 905 102 590 2,195 720 3,607 $ 9,752 $ 6,761 $ 8,267 $ (11,441 ) $ 13,339 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2015 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 275 — — — 275 Affiliated companies 433 403 461 (846 ) 451 Other 36 4 19 — 59 Notes receivable from affiliated companies 406 1,210 805 (2,410 ) 11 Materials and supplies 53 204 213 — 470 Derivatives 154 — — — 154 Collateral 70 — — — 70 Prepayments and other 48 18 — — 66 1,475 1,841 1,498 (3,256 ) 1,558 PROPERTY, PLANT AND EQUIPMENT: In service 93 6,367 8,233 (382 ) 14,311 Less — Accumulated provision for depreciation 40 2,144 3,775 (194 ) 5,765 53 4,223 4,458 (188 ) 8,546 Construction work in progress 30 249 878 — 1,157 83 4,472 5,336 (188 ) 9,703 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,327 — 1,327 Investment in affiliated companies 7,452 — — (7,452 ) — Other — 10 — — 10 7,452 10 1,327 (7,452 ) 1,337 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 300 16 — (316 ) — Customer intangibles 61 — — — 61 Goodwill 23 — — — 23 Property taxes — 12 28 — 40 Derivatives 79 — — — 79 Other 29 312 14 12 367 492 340 42 (304 ) 570 $ 9,502 $ 6,663 $ 8,203 $ (11,200 ) $ 13,168 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 229 $ 308 $ (25 ) $ 512 Short-term borrowings- Affiliated companies 2,021 389 — (2,410 ) — Other — 8 — — 8 Accounts payable- Affiliated companies 884 146 368 (856 ) 542 Other 21 118 — — 139 Accrued taxes 7 93 62 (86 ) 76 Derivatives 103 1 — — 104 Other 66 61 9 45 181 3,102 1,045 747 (3,332 ) 1,562 CAPITALIZATION: Total equity 5,605 2,944 4,476 (7,420 ) 5,605 Long-term debt and other long-term obligations 690 2,116 840 (1,136 ) 2,510 6,295 5,060 5,316 (8,556 ) 8,115 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 791 791 Accumulated deferred income taxes 6 — 697 (103 ) 600 Retirement benefits 27 305 — — 332 Asset retirement obligations — 191 640 — 831 Derivatives 37 1 — — 38 Other 35 61 803 — 899 105 558 2,140 688 3,491 $ 9,502 $ 6,663 $ 8,203 $ (11,200 ) $ 13,168 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Three Months Ended March 31, 2016 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (356 ) $ 277 $ 307 $ — $ 228 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 — (2 ) — — (2 ) Net cash provided from (used for) financing activities 352 (5 ) 1 (301 ) 47 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 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Three Months Ended March 31, 2015 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (662 ) $ 222 $ 545 $ — $ 105 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 674 — — (524 ) 150 Redemptions and Repayments- Long-term debt (17 ) — — — (17 ) Short-term borrowings, net — (5 ) (28 ) 33 — Other — (2 ) — — (2 ) Net cash provided from (used for) financing activities 657 (7 ) (28 ) (491 ) 131 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (1 ) (36 ) (82 ) — (119 ) Nuclear fuel — — (60 ) — (60 ) Sales of investment securities held in trusts — — 189 — 189 Purchases of investment securities held in trusts — — (202 ) — (202 ) Loans to affiliated companies, net 6 (179 ) (362 ) 491 (44 ) Net cash provided from (used for) investing activities 5 (215 ) (517 ) 491 (236 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission, and CES. Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does not have separate reportable operating segments. The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes regulated electric generation facilities located primarily in West Virginia, Virginia and New Jersey that MP and JCP&L, respectively, own or contractually control. The segment's results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs. As of March 31, 2016, this business segment controlled 3,790 MWs of generating capacity. The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, and certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP). This segment also includes the regulatory asset associated with the abandoned PATH project. The segment's revenues are primarily derived from forward-looking rates at ATSI and TrAIL, as well as fixed rates at certain of FirstEnergy’s utilities. Both the forward-looking and fixed rates recover costs and provide a return on transmission capital investment. Under the forward-looking rates, each of ATSI's and TrAIL’s revenue requirement is updated annually based on a projected rate base and projected costs, subject to annual true-up. Except for the recovery of the PATH abandoned project regulatory asset, the segment's revenues are primarily from transmission services provided to LSEs pursuant to the PJM Tariff. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities. The CES segment, through FES and AE Supply, primarily supplies electricity to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. As of March 31, 2016, this business segment controlled 13,162 MWs of generating capacity. The CES segment’s net income is primarily derived from electric generation sales less the related costs of electricity generation, including fuel, purchased power and net transmission (including congestion) and ancillary costs and capacity costs charged by PJM to deliver energy to the segment’s customers. Corporate support and other businesses that do not constitute an operating segment, interest expense on stand-alone holding company debt and corporate income taxes are categorized as Corporate/Other for reportable business segment purposes. Additionally, reconciling adjustments for the elimination of inter-segment transactions are included in Corporate/Other. As of March 31, 2016, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of which 28% was subject to variable-interest rates, and $2.1 billion was borrowed by FE under its revolving credit facility. Segment Financial Information Three Months Ended Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Reconciling Adjustments Consolidated (In millions) March 31, 2016 External revenues $ 2,521 $ 275 $ 1,152 $ (42 ) $ (37 ) $ 3,869 Internal revenues — — 152 — (152 ) — Total revenues 2,521 275 1,304 (42 ) (189 ) 3,869 Depreciation 169 43 102 15 — 329 Amortization of regulatory assets, net 59 2 — — — 61 Investment income 11 — 15 11 (9 ) 28 Interest expense 147 43 47 51 — 288 Income taxes (benefits) 98 43 85 (13 ) — 213 Net income (loss) 165 74 144 (55 ) — 328 Total assets 27,907 7,679 16,578 531 — 52,695 Total goodwill 5,092 526 800 — — 6,418 Property additions 262 258 169 9 — 698 March 31, 2015 External revenues $ 2,562 $ 238 $ 1,175 $ (42 ) $ (36 ) $ 3,897 Internal revenues — — 260 — (260 ) — Total revenues 2,562 238 1,435 (42 ) (296 ) 3,897 Depreciation 172 37 96 14 — 319 Amortization of regulatory assets, net 29 3 — — — 32 Investment income 13 — 12 2 (10 ) 17 Interest expense 144 39 48 47 1 279 Income taxes (benefits) 122 42 (4 ) (18 ) 2 144 Net income (loss) 208 72 (8 ) (50 ) — 222 Total assets 27,974 6,601 16,497 807 — 51,879 Total goodwill 5,092 526 800 — — 6,418 Property additions 280 254 126 8 — 668

Organization and Basis of Pre24

Organization and Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Accounting	FirstEnergy follows GAAP and complies with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The accompanying interim financial statements are unaudited, but reflect all adjustments, consisting of normal recurring adjustments, that, in the opinion of management, are necessary for a fair statement of the financial statements. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued.
Consolidation Policy	FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 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", requiring entities to recognize revenue by applying a five-step model in accordance with the core principle to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue recognition are expanded. In August 2015, the FASB issued a final ASU deferring the effective date until fiscal years beginning after December 15, 2017. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, (the original effective date) . In March 2016, the FASB issued ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)", clarifying the principal versus agent implementation guidance in the following areas: unit of account at which the principal/agent determination is made; applying the control principle to certain types of transactions and the control principle and principal/agent indicators. In April 2016, the FASB issued ASU 2016-10, “Identifying Performance Obligations and Licensing”, clarifying the identification of performance obligations and the licensing implementation guidance. The standards shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting these standards. In February 2015, the FASB issued, ASU 2015-02 "Consolidations: Amendments to the Consolidation Analysis", which amends current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate whether an entity should be consolidated. A reporting entity must apply the amendments using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments retrospectively. FirstEnergy's adoption of ASU 2015-02, on January 1, 2016, did not result in a change in the consolidation of VIEs by FirstEnergy or its subsidiaries. See Note 6, Variable Interest Entities, for additional information. In April 2015, the FASB issued, ASU 2015-03 "Simplifying the Presentation of Debt Issuance Costs", which requires debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. I n addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements", which allows debt issuance costs related to line of credit arrangements to be presented as an asset and amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit. FirstEnergy adopted ASU 2015-15 and ASU 2015-03 beginning January 1, 2016. As of December 31, 2015, FirstEnergy and FES reclassified $93 million and $17 million of debt issuance costs included in Deferred Charges and Other Assets to Long-term Debt and Other Long-term Obligations. FirstEnergy will elect to continue presenting debt issuance costs relating to its revolving credit facilities as an asset. In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities . The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption can be elected for all financial statements of fiscal years and interim periods that have not yet been issued or that have not yet been made available for issuance. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted . Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment . FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In March of 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", which simplifies several aspects of the accounting for employee share-based payment. The new guidance will require all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also will not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. Additionally, in March of 2016, the FASB issued the following ASUs: • ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships” , • ASU 2016-06, “Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging Issues Task Force)", and • ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting”. 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.
Variable Interest Entities	FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. The caption "noncontrolling interest" within the consolidated financial statements is used to reflect the portion of a VIE that FirstEnergy consolidates, but does not own.
Investment Policy	All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and AFS securities. At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value.
Long-Term Debt and Other Long-Term Obligations	All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value.
Derivatives Instruments Policy	FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance.

Earnings Per Share Of Common 25

Earnings Per Share Of Common Stock (Tables)	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Reconciliation of basic and diluted earnings per share	The following table reconciles basic and diluted earnings per share of common stock: (In millions, except per share amounts) For the Three Months Ended March 31 Reconciliation of Basic and Diluted Earnings per Share of Common Stock 2016 2015 Net income $ 328 $ 222 Weighted average number of basic shares outstanding 424 421 Assumed exercise of dilutive stock options and awards (1) 2 2 Weighted average number of diluted shares outstanding 426 423 Basic earnings per share of common stock $ 0.78 $ 0.53 Diluted earnings per share of common stock $ 0.77 $ 0.53 (1) For both the three months ended March 31, 2016 and March 31, 2015 , 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, 2016
Compensation and Retirement Disclosure [Abstract]
Components of Net Periodic Benefit Costs	The components of the consolidated net periodic cost (credits) for pension and OPEB (including amounts capitalized) were as follows: Components of Net Periodic Benefit Costs (Credits) Pension OPEB For the Three Months Ended March 31 2016 2015 2016 2015 (In millions) Service costs $ 48 $ 48 $ 1 $ 1 Interest costs 100 96 7 7 Expected return on plan assets (97 ) (111 ) (8 ) (8 ) Amortization of prior service costs (credits) 2 2 (20 ) (33 ) Net periodic costs (credits) $ 53 $ 35 $ (20 ) $ (33 )
Net Periodic Pension and OPEB Costs	FES' share of the net periodic pension and OPEB costs (credits) were as follows: Pension OPEB 2016 2015 2016 2015 (In millions) For the Three Months Ended March 31 $ 6 $ 4 $ (4 ) $ (5 ) Pension and OPEB obligations are allocated to FE's subsidiaries, including FES, employing the plan participants. The net periodic pension and OPEB costs (credits) (net of amounts capitalized) recognized in earnings by FE and FES were as follows: Net Periodic Benefit Expense (Credit) Pension OPEB For the Three Months Ended March 31 2016 2015 2016 2015 (In millions) FirstEnergy $ 37 $ 25 $ (15 ) $ (23 ) FES 6 4 (4 ) (4 )

Accumulated Other Comprehensi27

Accumulated Other Comprehensive Income (Tables)	3 Months Ended
	Mar. 31, 2016
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, 2016 and 2015 , for FirstEnergy are included in the following tables: FirstEnergy Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance as of 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 tax (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 AOCI Balance as of January 1, 2015 $ (37 ) $ 25 $ 258 $ 246 Other comprehensive income before reclassifications — 14 — 14 Amounts reclassified from AOCI 1 (10 ) (31 ) (40 ) Other comprehensive income (loss) 1 4 (31 ) (26 ) Income tax (benefits) on other comprehensive income (loss) — 1 (11 ) (10 ) Other comprehensive income (loss), net of tax 1 3 (20 ) (16 ) AOCI Balance as of March 31, 2015 $ (36 ) $ 28 $ 238 $ 230
Reclassification out of Accumulated Other Comprehensive Income	The following amounts were reclassified from AOCI for FirstEnergy in the three months ended March 31, 2016 and 2015 : For the Three Months Ended March 31 Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (2) 2016 2015 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ (1 ) Other operating expenses Long-term debt 2 2 Interest expense 2 1 Total before taxes (1 ) — Income taxes $ 1 $ 1 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (13 ) $ (10 ) Investment income 5 4 Income taxes $ (8 ) $ (6 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (18 ) $ (31 ) (1) 7 11 Income taxes $ (11 ) $ (20 ) 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, 2016 and 2015 , for FES are included in the following tables: FES Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance as of 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 AOCI Balance as of January 1, 2015 $ (7 ) $ 21 $ 43 $ 57 Other comprehensive income before reclassifications — 13 — 13 Amounts reclassified from AOCI (1 ) (10 ) (4 ) (15 ) Other comprehensive income (loss) (1 ) 3 (4 ) (2 ) Income tax (benefits) on other comprehensive income (loss) — — (1 ) (1 ) Other comprehensive income (loss), net of tax (1 ) 3 (3 ) (1 ) AOCI Balance as of March 31, 2015 $ (8 ) $ 24 $ 40 $ 56
Reclassification out of Accumulated Other Comprehensive Income	The following amounts were reclassified from AOCI for FES in the three months ended March 31, 2016 and 2015 : For the Three Months Ended March 31 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2016 2015 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ (1 ) Other operating expenses — — Income taxes (benefits) $ — $ (1 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (13 ) $ (10 ) Investment income 5 4 Income taxes (benefits) $ (8 ) $ (6 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (4 ) $ (4 ) (1) 2 1 Income taxes (benefits) $ (2 ) $ (3 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details. (2) 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, 2016
Variable Interest Entities [Abstract]
Net exposure to loss based upon the casualty value provisions	The following table discloses each company’s net exposure to loss based upon the casualty value provisions as of March 31, 2016 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy $ 1,228 $ 967 $ 261 FES 1,171 949 222

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2016
Fair Value of Financial Instruments [Line Items]
Assets and liabilities measured on recurring basis	The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: FirstEnergy Recurring Fair Value Measurements March 31, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,264 $ — $ 1,264 $ — $ 1,245 $ — $ 1,245 Derivative assets - commodity contracts 3 290 — 293 4 224 — 228 Derivative assets - FTRs — — 3 3 — — 8 8 Derivative assets - NUG contracts (1) — — 1 1 — — 1 1 Equity securities (2) 628 — — 628 576 — — 576 Foreign government debt securities — 73 — 73 — 75 — 75 U.S. government debt securities — 188 — 188 — 180 — 180 U.S. state debt securities — 245 — 245 — 246 — 246 Other (3) 146 232 — 378 105 212 — 317 Total assets $ 777 $ 2,292 $ 4 $ 3,073 $ 685 $ 2,182 $ 9 $ 2,876 Liabilities Derivative liabilities - commodity contracts $ (7 ) $ (122 ) $ — $ (129 ) $ (9 ) $ (122 ) $ — $ (131 ) Derivative liabilities - FTRs — — (9 ) (9 ) — — (13 ) (13 ) Derivative liabilities - NUG contracts (1) — — (136 ) (136 ) — — (137 ) (137 ) Total liabilities $ (7 ) $ (122 ) $ (145 ) $ (274 ) $ (9 ) $ (122 ) $ (150 ) $ (281 ) Net assets (liabilities) (4) $ 770 $ 2,170 $ (141 ) $ 2,799 $ 676 $ 2,060 $ (141 ) $ 2,595 (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (3) Primarily consists of short-term cash investments. (4) Excludes $(6) million and $7 million as of March 31, 2016 and December 31, 2015 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts	The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2016 and December 31, 2015 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2015 Balance $ 2 $ (153 ) $ (151 ) $ 39 $ (14 ) $ 25 Unrealized gain (loss) 2 (49 ) (47 ) (5 ) (7 ) (12 ) Purchases — — — 22 (11 ) 11 Settlements (3 ) 65 62 (48 ) 19 (29 ) December 31, 2015 Balance $ 1 $ (137 ) $ (136 ) $ 8 $ (13 ) $ (5 ) Unrealized loss — (12 ) (12 ) — (1 ) (1 ) Settlements — 13 13 (5 ) 5 — March 31, 2016 Balance $ 1 $ (136 ) $ (135 ) $ 3 $ (9 ) $ (6 ) (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
Quantitative information for level 3 valuation	The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2016 : Fair Value, Net (In millions) Valuation Technique Significant Input Range Weighted Average Units FTRs $ (6 ) Model RTO auction clearing prices ($4.60) to $3.70 $0.60 Dollars/MWH NUG Contracts $ (135 ) Model Generation 400 to 3,651,000 777,000 MWH Regional electricity prices $37.30 to $45.60 $39.60 Dollars/MWH
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities	The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT, nuclear fuel disposal and NUG trusts as of March 31, 2016 and December 31, 2015 : March 31, 2016 (1) December 31, 2015 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,776 $ 44 $ 1,820 $ 1,778 $ 16 $ 1,794 FES 825 26 851 801 9 810 Equity securities FirstEnergy $ 576 $ 52 $ 628 $ 542 $ 34 $ 576 FES 372 36 408 354 24 378 (1) Excludes short-term cash investments: FE Consolidated - $161 million ; FES - $113 million . (2) Excludes short-term cash investments: FE Consolidated - $157 million ; FES - $139 million .
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income	Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three months ended March 31, 2016 and 2015 were as follows: Three Months Ended 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 March 31, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 371 $ 60 $ (50 ) $ (7 ) $ 25 FES 189 38 (28 ) (6 ) 14
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities	The following table provides the amortized cost basis, unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of March 31, 2016 and December 31, 2015 : March 31, 2016 December 31, 2015 Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt Securities FirstEnergy $ 6 $ 1 $ 7 $ 6 $ 2 $ 8
Fair value and related carrying amounts of long-term debt and other long-term obligations	The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations, excluding capital lease obligations and net unamortized debt issuance costs, premiums and discounts: March 31, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 20,217 $ 21,821 $ 20,244 $ 21,519 FES 3,036 3,112 3,027 3,121
FES
Fair Value of Financial Instruments [Line Items]
Assets and liabilities measured on recurring basis	FES Recurring Fair Value Measurements March 31, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 715 $ — $ 715 $ — $ 678 $ — $ 678 Derivative assets - commodity contracts 3 290 — 293 4 224 — 228 Derivative assets - FTRs — — 3 3 — — 5 5 Equity securities (1) 408 — — 408 378 — — 378 Foreign government debt securities — 58 — 58 — 59 — 59 U.S. government debt securities — 25 — 25 — 23 — 23 U.S. state debt securities — 4 — 4 — 4 — 4 Other (2) — 170 — 170 — 184 — 184 Total assets $ 411 $ 1,262 $ 3 $ 1,676 $ 382 $ 1,172 $ 5 $ 1,559 Liabilities Derivative liabilities - commodity contracts $ (7 ) $ (122 ) $ — $ (129 ) $ (9 ) $ (122 ) $ — $ (131 ) Derivative liabilities - FTRs — — (7 ) (7 ) — — (11 ) (11 ) Total liabilities $ (7 ) $ (122 ) $ (7 ) $ (136 ) $ (9 ) $ (122 ) $ (11 ) $ (142 ) Net assets (liabilities) (3) $ 404 $ 1,140 $ (4 ) $ 1,540 $ 373 $ 1,050 $ (6 ) $ 1,417 (1) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (2) Primarily consists of short-term cash investments. (3) Excludes $(8) million and $1 million as of March 31, 2016 and December 31, 2015 , 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, 2016 and December 31, 2015 : Derivative Asset Derivative Liability Net Asset (Liability) (In millions) January 1, 2015 Balance $ 27 $ (13 ) $ 14 Unrealized gain (loss) 2 (5 ) (3 ) Purchases 9 (10 ) (1 ) Settlements (33 ) 17 (16 ) December 31, 2015 Balance $ 5 $ (11 ) $ (6 ) Unrealized loss — (1 ) (1 ) Settlements (2 ) 5 3 March 31, 2016 Balance $ 3 $ (7 ) $ (4 )
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, 2016 : Fair Value, Net (In millions) Valuation Technique Significant Input Range Weighted Average Units FTRs $ (4 ) Model RTO auction clearing prices ($4.60) to $3.70 $0.50 Dollars/MWH

Derivative Instruments (Tables)

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair value of derivatives instruments	The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets: Derivative Assets Derivative Liabilities Fair Value Fair Value March 31, December 31, March 31, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 205 $ 150 Commodity Contracts $ (109 ) $ (94 ) FTRs 2 7 FTRs (8 ) (12 ) 207 157 (117 ) (106 ) Deferred Charges and Other Assets - Other Noncurrent Liabilities - Adverse Power Contract Liability NUGs (1) (136 ) (137 ) Commodity Contracts 88 78 Noncurrent Liabilities - Other FTRs 1 1 Commodity Contracts (20 ) (37 ) NUGs (1) 1 1 FTRs (1 ) (1 ) 90 80 (157 ) (175 ) Derivative Assets $ 297 $ 237 Derivative Liabilities $ (274 ) $ (281 ) (1) NUG contracts are subject to regulatory accounting treatment and do not impact earnings.
Offsetting assets and liabilities	The following tables summarize the fair value of derivative assets and derivative liabilities on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet March 31, 2016 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 293 $ (128 ) $ (25 ) $ 140 FTRs 3 (3 ) — — NUG contracts 1 — — 1 $ 297 $ (131 ) $ (25 ) $ 141 Derivative Liabilities Commodity contracts $ (129 ) $ 128 $ — $ (1 ) FTRs (9 ) 3 6 — NUG contracts (136 ) — — (136 ) $ (274 ) $ 131 $ 6 $ (137 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 228 $ (125 ) $ — $ 103 FTRs 8 (8 ) — — NUG contracts 1 — — 1 $ 237 $ (133 ) $ — $ 104 Derivative Liabilities Commodity contracts $ (131 ) $ 125 $ 3 $ (3 ) FTRs (13 ) 8 5 — NUG contracts (137 ) — — (137 ) $ (281 ) $ 133 $ 8 $ (140 )
Volume of First Energy's outstanding derivative transactions	The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of March 31, 2016 : Purchases Sales Net Units (In millions) Power Contracts 14 42 (28 ) MWH FTRs 15 — 15 MWH NUGs 4 — 4 MWH Natural Gas 81 1 80 mmBTU
Effect of derivative instruments on statements of income and comprehensive income	The effect of active derivative instruments not in a hedging relationship on the Consolidated Statements of Income during the three months ended March 31, 2016 and 2015 , are summarized in the following tables: Three Months Ended March 31 Commodity Contracts FTRs Total (In millions) 2016 Unrealized Gain Recognized in: Other Operating Expense (1) $ 62 $ 2 $ 64 Realized Gain (Loss) Reclassified to: Revenues (1) $ 71 $ 2 $ 73 Purchased Power Expense (1) (45 ) — (45 ) Other Operating Expense (1) — (12 ) (12 ) Fuel Expense (8 ) — (8 ) (1) All amounts are associated with FES. Three Months Ended March 31 Commodity Contracts FTRs Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense (2) $ 11 $ (13 ) $ (2 ) Realized Gain (Loss) Reclassified to: Revenues (3) $ (1 ) $ 37 $ 36 Purchased Power Expense (4) (3 ) — (3 ) Other Operating Expense (5) — (13 ) (13 ) Fuel Expense (16 ) — (16 ) (2) Includes $11 million for commodity contracts and ($12) million for FTRs associated with FES. (3) Represents losses on structured financial contracts. Includes ($1) million for commodity contracts and $36 million for FTRs associated with FES. (4) Realized losses on financially settled wholesale sales contracts of $22 million were netted in purchased power. Includes ($3) million for commodity contracts associated with FES. (5) Includes ($13) million for FTRs associated with FES.
Reconciliation of changes in the fair value of certain contracts that are deferred	The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during the three months ended March 31, 2016 and 2015 . Changes in the value of these instruments are deferred for future recovery from (or credit to) customers: Three Months Ended March 31 Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of January 1, 2016 $ (136 ) $ 1 $ (135 ) Unrealized loss (12 ) (1 ) (13 ) Settlements 13 (2 ) 11 Outstanding net asset (liability) as of March 31, 2016 $ (135 ) $ (2 ) $ (137 ) Outstanding net asset (liability) as of January 1, 2015 $ (151 ) $ 11 $ (140 ) Unrealized gain (loss) (8 ) 1 (7 ) Settlements 11 (11 ) — Outstanding net asset (liability) as of March 31, 2015 $ (148 ) $ 1 $ (147 )

Commitments, Guarantees and C31

Commitments, Guarantees and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of Guarantor Obligations	The following table discloses the additional credit contingent contractual obligations that may be required under certain events as of March 31, 2016 : Collateral Provisions FES/ AE Supply (Tied to FE Corp. Rating) FES/ AE Supply (Tied to FES Rating) Utilities Total (In millions) Split Rating (One rating agency's rating below investment grade) $ 25 $ 173 $ 40 $ 238 Non-Investment Grade Ratings (All Rating Agencies at or below BB+/Ba1) $ 25 $ 200 $ 40 $ 265 Total Exposure from Contractual Obligations $ 25 $ 341 $ 40 $ 406

Supplemental Guarantor Inform32

Supplemental Guarantor Information (Tables)	3 Months Ended
	Mar. 31, 2016
Supplemental Guarantor Information [Abstract]
Condensed Consolidating Statements of Income and Comprehensive Income	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 251 6 17 (259 ) 15 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 BEFORE INCOME TAXES (BENEFITS) 65 164 229 (245 ) 213 INCOME TAXES (BENEFITS) (66 ) 61 86 1 82 NET INCOME $ 131 $ 103 $ 143 $ (246 ) $ 131 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 131 $ 103 $ 143 $ (246 ) $ 131 OTHER COMPREHENSIVE INCOME (LOSS): Pensions and OPEB prior service costs (4 ) (3 ) — 3 (4 ) Change in unrealized gain 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 $ 143 $ 101 $ 158 $ (259 ) $ 143 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Three Months Ended March 31, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 1,332 $ 493 $ 507 $ (955 ) $ 1,377 OPERATING EXPENSES: Fuel — 180 50 — 230 Purchased power from affiliates 957 — 68 (955 ) 70 Purchased power from non-affiliates 543 — — — 543 Other operating expenses 180 67 154 12 413 Provision for depreciation 3 30 48 (1 ) 80 General taxes 15 8 6 — 29 Total operating expenses 1,698 285 326 (944 ) 1,365 OPERATING INCOME (LOSS) (366 ) 208 181 (11 ) 12 OTHER INCOME (EXPENSE): Investment income, including net income from equity investees 241 3 14 (245 ) 13 Interest expense — affiliates (6 ) (2 ) (1 ) 7 (2 ) Interest expense — other (13 ) (26 ) (13 ) 15 (37 ) Capitalized interest — 1 8 — 9 Total other income (expense) 222 (24 ) 8 (223 ) (17 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (144 ) 184 189 (234 ) (5 ) INCOME TAXES (BENEFITS) (141 ) 67 70 2 (2 ) NET INCOME (LOSS) $ (3 ) $ 117 $ 119 $ (236 ) $ (3 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (3 ) $ 117 $ 119 $ (236 ) $ (3 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (4 ) (4 ) 3 1 (4 ) Amortized gain on derivative hedges (1 ) — — — (1 ) Change in unrealized gain on available-for-sale securities 3 — — — 3 Other comprehensive income (loss) (2 ) (4 ) 3 1 (2 ) Income taxes (benefits) on other comprehensive income (loss) (1 ) (1 ) 1 — (1 ) Other comprehensive income (loss), net of tax (1 ) (3 ) 2 1 (1 ) COMPREHENSIVE INCOME (LOSS) $ (4 ) $ 114 $ 121 $ (235 ) $ (4 )
Condensed Consolidating Balance Sheets	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of March 31, 2016 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 229 — — — 229 Affiliated companies 442 310 305 (610 ) 447 Other 32 1 74 — 107 Notes receivable from affiliated companies 394 1,429 889 (2,712 ) — Materials and supplies 39 191 216 — 446 Derivatives 207 — — — 207 Collateral 80 — — — 80 Prepayments and other 69 11 — — 80 1,492 1,944 1,484 (3,322 ) 1,598 PROPERTY, PLANT AND EQUIPMENT: In service 92 6,389 8,277 (382 ) 14,376 Less — Accumulated provision for depreciation 43 2,163 3,863 (195 ) 5,874 49 4,226 4,414 (187 ) 8,502 Construction work in progress 30 271 972 — 1,273 79 4,497 5,386 (187 ) 9,775 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,372 — 1,372 Investment in affiliated companies 7,712 — — (7,712 ) — Other — 10 — — 10 7,712 10 1,372 (7,712 ) 1,382 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 276 — — (276 ) — Customer intangibles 57 — — — 57 Goodwill 23 — — — 23 Property taxes — 9 21 — 30 Derivatives 89 — — — 89 Other 24 301 4 56 385 469 310 25 (220 ) 584 $ 9,752 $ 6,761 $ 8,267 $ (11,441 ) $ 13,339 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 266 $ 308 $ (25 ) $ 549 Short-term borrowings- Affiliated companies 2,373 386 2 (2,712 ) 49 Accounts payable- Affiliated companies 619 190 172 (619 ) 362 Other 26 90 — — 116 Accrued taxes 3 52 101 (85 ) 71 Derivatives 115 — — — 115 Other 75 74 15 77 241 3,211 1,058 598 (3,364 ) 1,503 CAPITALIZATION: Total equity 5,749 3,046 4,634 (7,680 ) 5,749 Long-term debt and other long-term obligations 690 2,067 840 (1,117 ) 2,480 6,439 5,113 5,474 (8,797 ) 8,229 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 782 782 Accumulated deferred income taxes 6 35 743 (62 ) 722 Retirement benefits 28 311 — — 339 Asset retirement obligations — 188 650 — 838 Derivatives 21 — — — 21 Other 47 56 802 — 905 102 590 2,195 720 3,607 $ 9,752 $ 6,761 $ 8,267 $ (11,441 ) $ 13,339 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2015 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 275 — — — 275 Affiliated companies 433 403 461 (846 ) 451 Other 36 4 19 — 59 Notes receivable from affiliated companies 406 1,210 805 (2,410 ) 11 Materials and supplies 53 204 213 — 470 Derivatives 154 — — — 154 Collateral 70 — — — 70 Prepayments and other 48 18 — — 66 1,475 1,841 1,498 (3,256 ) 1,558 PROPERTY, PLANT AND EQUIPMENT: In service 93 6,367 8,233 (382 ) 14,311 Less — Accumulated provision for depreciation 40 2,144 3,775 (194 ) 5,765 53 4,223 4,458 (188 ) 8,546 Construction work in progress 30 249 878 — 1,157 83 4,472 5,336 (188 ) 9,703 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,327 — 1,327 Investment in affiliated companies 7,452 — — (7,452 ) — Other — 10 — — 10 7,452 10 1,327 (7,452 ) 1,337 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 300 16 — (316 ) — Customer intangibles 61 — — — 61 Goodwill 23 — — — 23 Property taxes — 12 28 — 40 Derivatives 79 — — — 79 Other 29 312 14 12 367 492 340 42 (304 ) 570 $ 9,502 $ 6,663 $ 8,203 $ (11,200 ) $ 13,168 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 229 $ 308 $ (25 ) $ 512 Short-term borrowings- Affiliated companies 2,021 389 — (2,410 ) — Other — 8 — — 8 Accounts payable- Affiliated companies 884 146 368 (856 ) 542 Other 21 118 — — 139 Accrued taxes 7 93 62 (86 ) 76 Derivatives 103 1 — — 104 Other 66 61 9 45 181 3,102 1,045 747 (3,332 ) 1,562 CAPITALIZATION: Total equity 5,605 2,944 4,476 (7,420 ) 5,605 Long-term debt and other long-term obligations 690 2,116 840 (1,136 ) 2,510 6,295 5,060 5,316 (8,556 ) 8,115 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 791 791 Accumulated deferred income taxes 6 — 697 (103 ) 600 Retirement benefits 27 305 — — 332 Asset retirement obligations — 191 640 — 831 Derivatives 37 1 — — 38 Other 35 61 803 — 899 105 558 2,140 688 3,491 $ 9,502 $ 6,663 $ 8,203 $ (11,200 ) $ 13,168
Condensed Consolidating Statements of Cash Flows	FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Three Months Ended March 31, 2016 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (356 ) $ 277 $ 307 $ — $ 228 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 — (2 ) — — (2 ) Net cash provided from (used for) financing activities 352 (5 ) 1 (301 ) 47 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 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Three Months Ended March 31, 2015 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (662 ) $ 222 $ 545 $ — $ 105 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 674 — — (524 ) 150 Redemptions and Repayments- Long-term debt (17 ) — — — (17 ) Short-term borrowings, net — (5 ) (28 ) 33 — Other — (2 ) — — (2 ) Net cash provided from (used for) financing activities 657 (7 ) (28 ) (491 ) 131 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (1 ) (36 ) (82 ) — (119 ) Nuclear fuel — — (60 ) — (60 ) Sales of investment securities held in trusts — — 189 — 189 Purchases of investment securities held in trusts — — (202 ) — (202 ) Loans to affiliated companies, net 6 (179 ) (362 ) 491 (44 ) Net cash provided from (used for) investing activities 5 (215 ) (517 ) 491 (236 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
Segment Financial Information	Segment Financial Information Three Months Ended Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Reconciling Adjustments Consolidated (In millions) March 31, 2016 External revenues $ 2,521 $ 275 $ 1,152 $ (42 ) $ (37 ) $ 3,869 Internal revenues — — 152 — (152 ) — Total revenues 2,521 275 1,304 (42 ) (189 ) 3,869 Depreciation 169 43 102 15 — 329 Amortization of regulatory assets, net 59 2 — — — 61 Investment income 11 — 15 11 (9 ) 28 Interest expense 147 43 47 51 — 288 Income taxes (benefits) 98 43 85 (13 ) — 213 Net income (loss) 165 74 144 (55 ) — 328 Total assets 27,907 7,679 16,578 531 — 52,695 Total goodwill 5,092 526 800 — — 6,418 Property additions 262 258 169 9 — 698 March 31, 2015 External revenues $ 2,562 $ 238 $ 1,175 $ (42 ) $ (36 ) $ 3,897 Internal revenues — — 260 — (260 ) — Total revenues 2,562 238 1,435 (42 ) (296 ) 3,897 Depreciation 172 37 96 14 — 319 Amortization of regulatory assets, net 29 3 — — — 32 Investment income 13 — 12 2 (10 ) 17 Interest expense 144 39 48 47 1 279 Income taxes (benefits) 122 42 (4 ) (18 ) 2 144 Net income (loss) 208 72 (8 ) (50 ) — 222 Total assets 27,974 6,601 16,497 807 — 51,879 Total goodwill 5,092 526 800 — — 6,418 Property additions 280 254 126 8 — 668

Organization and Basis of Pre34

Organization and Basis of Presentation (Details Textuals) mi in Thousands, MW in Thousands, customer in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)customertransmission_centercompanymiMW	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)
Property, Plant and Equipment [Line Items]
Aggregate amount of capacity | MW	17
Length of transmission lines | mi	24
Number of regional transmission centers | transmission_center	2
Capitalized cost of equity	$ 8	$ 16
Capitalized interest	$ 17	$ 18
New Accounting Pronouncement, Early Adoption, Effect | Deferred Charges and Other Assets
Property, Plant and Equipment [Line Items]
Debt issuance costs			$ 93
Regulated Distribution
Property, Plant and Equipment [Line Items]
Number of existing utility operating companies | company	10
Number of customers served by utility operating companies | customer	6
FES | New Accounting Pronouncement, Early Adoption, Effect | Deferred Charges and Other Assets
Property, Plant and Equipment [Line Items]
Debt issuance costs			$ 17

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, 2016	Mar. 31, 2015
Earnings Per Share [Abstract]
NET INCOME	$ 328	$ 222
Weighted average number of basic shares outstanding	424	421
Assumed exercise of dilutive stock options and awards	2	2
Weighted average number of diluted shares outstanding	426	423
Basic earnings per share of common stock (in dollars per share)	$ 0.78	$ 0.53
Diluted earnings per share of common stock (in dollars per share)	$ 0.77	$ 0.53
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, 2016	Mar. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Minimum required funding obligations	$ 381
Pension contributions	160	$ 143
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	48	48
Interest costs	100	96
Expected return on plan assets	(97)	(111)
Amortization of prior service costs (credits)	2	2
Net periodic costs (credits)	53	35
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)	(33)
Net periodic costs (credits)	(20)	(33)
FirstEnergy | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	37	25
FirstEnergy | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	(15)	(23)
FES | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)	6	4
Net periodic benefit expense (credit)	6	4
FES | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)	(4)	(5)
Net periodic benefit expense (credit)	$ (4)	$ (4)

Accumulated Other Comprehensi37

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	$ 171	$ 246
Other comprehensive income (loss) before reclassifications	41	14
Amounts reclassified from AOCI	(29)	(40)
Other comprehensive income (loss)	12	(26)
Income taxes (benefits) on other comprehensive income (loss)	4	(10)
Other comprehensive income (loss), net of tax	8	(16)
AOCI Ending Balance	179	230
FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	46	57
Other comprehensive income (loss) before reclassifications	36	13
Amounts reclassified from AOCI	(17)	(15)
Other comprehensive income (loss)	19	(2)
Income taxes (benefits) on other comprehensive income (loss)	7	(1)
Other comprehensive income (loss), net of tax	12	(1)
AOCI Ending Balance	58	56
Gains & Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(33)	(37)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from AOCI	2	1
Other comprehensive income (loss)	2	1
Income taxes (benefits) on other comprehensive income (loss)	1	0
Other comprehensive income (loss), net of tax	1	1
AOCI Ending Balance	(32)	(36)
Gains & Losses on Cash Flow Hedges | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(9)	(7)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from AOCI	0	(1)
Other comprehensive income (loss)	0	(1)
Income taxes (benefits) on other comprehensive income (loss)	0	0
Other comprehensive income (loss), net of tax	0	(1)
AOCI Ending Balance	(9)	(8)
Unrealized Gains on AFS Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	18	25
Other comprehensive income (loss) before reclassifications	41	14
Amounts reclassified from AOCI	(13)	(10)
Other comprehensive income (loss)	28	4
Income taxes (benefits) on other comprehensive income (loss)	10	1
Other comprehensive income (loss), net of tax	18	3
AOCI Ending Balance	36	28
Unrealized Gains on AFS Securities | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	16	21
Other comprehensive income (loss) before reclassifications	36	13
Amounts reclassified from AOCI	(13)	(10)
Other comprehensive income (loss)	23	3
Income taxes (benefits) on other comprehensive income (loss)	9	0
Other comprehensive income (loss), net of tax	14	3
AOCI Ending Balance	30	24
Defined Benefit Pension & OPEB Plans
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	186	258
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from AOCI	(18)	(31)
Other comprehensive income (loss)	(18)	(31)
Income taxes (benefits) on other comprehensive income (loss)	(7)	(11)
Other comprehensive income (loss), net of tax	(11)	(20)
AOCI Ending Balance	175	238
Defined Benefit Pension & OPEB Plans | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	39	43
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from AOCI	(4)	(4)
Other comprehensive income (loss)	(4)	(4)
Income taxes (benefits) on other comprehensive income (loss)	(2)	(1)
Other comprehensive income (loss), net of tax	(2)	(3)
AOCI Ending Balance	$ 37	$ 40

Accumulated Other Comprehensi38

Accumulated Other Comprehensive Income (Details 1) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	$ 918	$ 1,057
Interest expense	288	279
Investment income (loss)	(28)	(17)
Total before taxes	(541)	(366)
Income taxes (benefits)	213	144
Net of tax	(328)	(222)
FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	240	413
Investment income (loss)	(15)	(13)
Total before taxes	(213)	5
Income taxes (benefits)	82	(2)
Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Total before taxes	2	1
Income taxes (benefits)	(1)	0
Net of tax	1	1
Reclassifications from AOCI | Gains & losses on cash flow hedges | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Income taxes (benefits)	0	0
Net of tax	0	(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	(1)
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	0	(1)
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	2	2
Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(13)	(10)
Income taxes (benefits)	5	4
Net of tax	(8)	(6)
Reclassifications from AOCI | Unrealized gains on AFS securities | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(13)	(10)
Income taxes (benefits)	5	4
Net of tax	(8)	(6)
Reclassifications from AOCI | Defined benefit pension and OPEB plans
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(18)	(31)
Income taxes (benefits)	7	11
Net of tax	(11)	(20)
Reclassifications from AOCI | Defined benefit pension and OPEB plans | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(4)	(4)
Income taxes (benefits)	2	1
Net of tax	$ (2)	$ (3)

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	39.40%	39.30%
Unrecognized tax benefits from lapse of statute of limitations	$ 54
Unrecognized tax benefits that would impact effective tax rate	$ 16
FES
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	38.50%	40.00%
State and Local Jurisdiction
Income Taxes (Textuals) [Abstract]
Increase resulting from settlements with taxing authorities	$ 69

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	Mar. 31, 2016USD ($)
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	$ 1,228
Discounted Lease Payments, net	967
Net Exposure	261
FES
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	1,171
Discounted Lease Payments, net	949
Net Exposure	$ 222

Variable Interest Entities (D41

Variable Interest Entities (Details Textuals)	3 Months Ended
	Mar. 31, 2016USD ($)agreemententities	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)
Variable Interest Entities (Textuals) [Abstract]
Equity interest by unaffiliated third party in PNBV (percent)	3.00%
Long-term transition bond	$ 118,000,000		$ 128,000,000
Long-term pollution control bond	419,000,000		429,000,000
Guarantor obligations	$ 406,000,000
Number of contracts that may contain variable interest | entities	1
Purchased power	$ 1,124,000,000	$ 1,113,000,000
Perry Power Plant Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary	3.75%
Bruce Mansfield Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary	93.83%
Beaver Valley Unit 2
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary	2.60%
Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities | agreement	14
Phase In Recovery Bonds
Variable Interest Entities (Textuals) [Abstract]
Long-term debt and other long-term obligations	$ 350,000,000		$ 362,000,000
Ohio Funding Companies
Variable Interest Entities (Textuals) [Abstract]
Annual servicing fees	$ 445,000
Other FE subsidiaries
Variable Interest Entities (Textuals) [Abstract]
Ownership interest	0.00%
Other FE subsidiaries | Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Purchased power	$ 31,000,000	$ 31,000,000
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, 2016	Dec. 31, 2015
Assets
Fair value, assets	$ 3,073	$ 2,876
Liabilities
Fair value, liabilities	(274)	(281)
Net assets (liabilities)	2,799	2,595
FES
Assets
Fair value, assets	1,676	1,559
Liabilities
Fair value, liabilities	(136)	(142)
Net assets (liabilities)	1,540	1,417
Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(129)	(131)
Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(129)	(131)
FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(9)	(13)
FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(7)	(11)
NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(136)	(137)
Corporate debt securities
Assets
Fair value, assets	1,264	1,245
Corporate debt securities | FES
Assets
Fair value, assets	715	678
Commodity contracts | Derivative Assets
Assets
Fair value, assets	293	228
Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	293	228
FTRs | Derivative Assets
Assets
Fair value, assets	3	8
FTRs | Derivative Assets | FES
Assets
Fair value, assets	3	5
NUG contracts | Derivative Assets
Assets
Fair value, assets	1	1
Equity securities
Assets
Fair value, assets	628	576
Equity securities | FES
Assets
Fair value, assets	408	378
Foreign government debt securities
Assets
Fair value, assets	73	75
Foreign government debt securities | FES
Assets
Fair value, assets	58	59
U.S. government debt securities
Assets
Fair value, assets	188	180
U.S. government debt securities | FES
Assets
Fair value, assets	25	23
U.S. state debt securities
Assets
Fair value, assets	245	246
U.S. state debt securities | FES
Assets
Fair value, assets	4	4
Other
Assets
Fair value, assets	378	317
Other | FES
Assets
Fair value, assets	170	184
Level 1
Assets
Fair value, assets	777	685
Liabilities
Fair value, liabilities	(7)	(9)
Net assets (liabilities)	770	676
Level 1 | FES
Assets
Fair value, assets	411	382
Liabilities
Fair value, liabilities	(7)	(9)
Net assets (liabilities)	404	373
Level 1 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(7)	(9)
Level 1 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(7)	(9)
Level 1 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 1 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 1 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 1 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 1 | Corporate debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	3	4
Level 1 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	3	4
Level 1 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 1 | NUG contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | Equity securities
Assets
Fair value, assets	628	576
Level 1 | Equity securities | FES
Assets
Fair value, assets	408	378
Level 1 | Foreign government debt securities
Assets
Fair value, assets	0	0
Level 1 | Foreign government debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | U.S. government debt securities
Assets
Fair value, assets	0	0
Level 1 | U.S. government debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | U.S. state debt securities
Assets
Fair value, assets	0	0
Level 1 | U.S. state debt securities | FES
Assets
Fair value, assets	0	0
Level 1 | Other
Assets
Fair value, assets	146	105
Level 1 | Other | FES
Assets
Fair value, assets	0	0
Level 2
Assets
Fair value, assets	2,292	2,182
Liabilities
Fair value, liabilities	(122)	(122)
Net assets (liabilities)	2,170	2,060
Level 2 | FES
Assets
Fair value, assets	1,262	1,172
Liabilities
Fair value, liabilities	(122)	(122)
Net assets (liabilities)	1,140	1,050
Level 2 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(122)	(122)
Level 2 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(122)	(122)
Level 2 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 2 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2 | Corporate debt securities
Assets
Fair value, assets	1,264	1,245
Level 2 | Corporate debt securities | FES
Assets
Fair value, assets	715	678
Level 2 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	290	224
Level 2 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	290	224
Level 2 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 2 | NUG contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | Equity securities
Assets
Fair value, assets	0	0
Level 2 | Equity securities | FES
Assets
Fair value, assets	0	0
Level 2 | Foreign government debt securities
Assets
Fair value, assets	73	75
Level 2 | Foreign government debt securities | FES
Assets
Fair value, assets	58	59
Level 2 | U.S. government debt securities
Assets
Fair value, assets	188	180
Level 2 | U.S. government debt securities | FES
Assets
Fair value, assets	25	23
Level 2 | U.S. state debt securities
Assets
Fair value, assets	245	246
Level 2 | U.S. state debt securities | FES
Assets
Fair value, assets	4	4
Level 2 | Other
Assets
Fair value, assets	232	212
Level 2 | Other | FES
Assets
Fair value, assets	170	184
Level 3
Assets
Fair value, assets	4	9
Liabilities
Fair value, liabilities	(145)	(150)
Net assets (liabilities)	(141)	(141)
Level 3 | FES
Assets
Fair value, assets	3	5
Liabilities
Fair value, liabilities	(7)	(11)
Net assets (liabilities)	(4)	(6)
Level 3 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 3 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 3 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(9)	(13)
Level 3 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(7)	(11)
Level 3 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(136)	(137)
Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 3 | Corporate debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 3 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 3 | FTRs | Derivative Assets
Assets
Fair value, assets	3	8
Level 3 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	3	5
Level 3 | NUG contracts | Derivative Assets
Assets
Fair value, assets	1	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, 2016	Dec. 31, 2015
NUG contracts
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	$ 1	$ 2
Beginning Balance, Derivative Liabilities	(137)	(153)
Beginning Balance, Net	(136)	(151)
Unrealized gain (loss), Derivative Assets	0	2
Unrealized gain (loss), Derivative Liabilities	(12)	(49)
Unrealized gain (loss), Net	(12)	(47)
Purchases, Derivative Assets		0
Purchases, Derivative Liabilities		0
Purchases, Net		0
Settlements, Derivative Assets	0	(3)
Settlements, Derivative Liabilities	13	65
Settlements, Net	13	62
Ending Balance, Derivative Assets	1	1
Ending Balance, Derivative Liabilities	(136)	(137)
Ending Balance, Net	(135)	(136)
FTRs
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	8	39
Beginning Balance, Derivative Liabilities	(13)	(14)
Beginning Balance, Net	(5)	25
Unrealized gain (loss), Derivative Assets	0	(5)
Unrealized gain (loss), Derivative Liabilities	(1)	(7)
Unrealized gain (loss), Net	(1)	(12)
Purchases, Derivative Assets		22
Purchases, Derivative Liabilities		(11)
Purchases, Net		11
Settlements, Derivative Assets	(5)	(48)
Settlements, Derivative Liabilities	5	19
Settlements, Net	0	(29)
Ending Balance, Derivative Assets	3	8
Ending Balance, Derivative Liabilities	(9)	(13)
Ending Balance, Net	(6)	(5)
FTRs | FES
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	5	27
Beginning Balance, Derivative Liabilities	(11)	(13)
Beginning Balance, Net	(6)	14
Unrealized gain (loss), Derivative Assets	0	2
Unrealized gain (loss), Derivative Liabilities	(1)	(5)
Unrealized gain (loss), Net	(1)	(3)
Purchases, Derivative Assets		9
Purchases, Derivative Liabilities		(10)
Purchases, Net		(1)
Settlements, Derivative Assets	(2)	(33)
Settlements, Derivative Liabilities	5	17
Settlements, Net	3	(16)
Ending Balance, Derivative Assets	3	5
Ending Balance, Derivative Liabilities	(7)	(11)
Ending Balance, Net	$ (4)	$ (6)

Fair Value Measurements (Deta44

Fair Value Measurements (Details 2) - Level 3 $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)MWh$ / MWh	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ (6)	$ (5)	$ 25
FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(4)	(6)	14
NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(135)	$ (136)	$ (151)
Model | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(6)
Model | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(4)
Model | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ (135)
Model | Minimum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	(4.60)
Model | Minimum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	(4.60)
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)	37.30
Model | Maximum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	3.70
Model | Maximum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	3.70
Model | Maximum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	3,651,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	45.60
Model | Weighted Average | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	0.60
Model | Weighted Average | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	0.50
Model | Weighted Average | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	777,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	39.60

Fair Value Measurements (Deta45

Fair Value Measurements (Details 3) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	$ 1,776	$ 1,778
Unrealized Gain	44	16
Fair Value	1,820	1,794
Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	576	542
Unrealized Gains	52	34
Fair Value	628	576
FES | Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	825	801
Unrealized Gain	26	9
Fair Value	851	810
FES | Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	372	354
Unrealized Gains	36	24
Fair Value	$ 408	$ 378

Fair Value Measurements (Deta46

Fair Value Measurements (Details 4) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income
Sales Proceeds	$ 465	$ 371
Realized Gains	61	60
Realized Losses	(50)	(50)
OTTI	(9)	(7)
Interest and Dividend Income	23	25
FES
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income
Sales Proceeds	138	189
Realized Gains	42	38
Realized Losses	(29)	(28)
OTTI	(8)	(6)
Interest and Dividend Income	$ 13	$ 14

Fair Value Measurements (Deta47

Fair Value Measurements (Details 5) - Debt Securities - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities
Cost Basis	$ 6	$ 6
Unrecognized Gains	1	2
Fair Value	$ 7	$ 8

Fair Value Measurements (Deta48

Fair Value Measurements (Details 6) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$ 20,217	$ 20,244
Carrying Value | FES
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	3,036	3,027
Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	21,821	21,519
Fair Value | FES
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$ 3,112	$ 3,121

Fair Value Measurements (Deta49

Fair Value Measurements (Details Textuals) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	$ (6)	$ 7
Cash balance excluded from available for sale securities	161	157
Investments not required to be disclosed	$ 271	255
NUG contracts
Fair Value of Financial Instruments [Line Items]
Period of future observable data to determine contract price	3 years
FES
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	$ (8)	1
Cash balance excluded from available for sale securities	$ 113	$ 139

Derivative Instruments (Details

Derivative Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Fair value of commodity derivatives
Derivative Assets	$ 297	$ 237
Derivative Liabilities	(274)	(281)
Current Assets
Fair value of commodity derivatives
Derivative Assets	207	157
Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	90	80
Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(117)	(106)
Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(157)	(175)
Commodity contracts | Current Assets
Fair value of commodity derivatives
Derivative Assets	205	150
Commodity contracts | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	88	78
Commodity contracts | Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(109)	(94)
Commodity contracts | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(20)	(37)
FTRs | Current Assets
Fair value of commodity derivatives
Derivative Assets	2	7
FTRs | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	1	1
FTRs | Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(8)	(12)
FTRs | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(1)	(1)
NUGs | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	1	1
NUGs | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	$ (136)	$ (137)

Derivative Instruments (Detai51

Derivative Instruments (Details 1) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Derivative Assets
Fair Value	$ 297	$ 237
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(131)	(133)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	(25)	0
Net Fair Value	141	104
Derivative Liabilities
Fair Value	(274)	(281)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	131	133
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	6	8
Net Fair Value	(137)	(140)
Commodity contracts
Derivative Assets
Fair Value	293	228
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(128)	(125)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	(25)	0
Net Fair Value	140	103
Derivative Liabilities
Fair Value	(129)	(131)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	128	125
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	3
Net Fair Value	(1)	(3)
FTRs
Derivative Assets
Fair Value	3	8
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(3)	(8)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	0	0
Derivative Liabilities
Fair Value	(9)	(13)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	3	8
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	6	5
Net Fair Value	0	0
NUGs
Derivative Assets
Fair Value	1	1
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	0	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	1	1
Derivative Liabilities
Fair Value	(136)	(137)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	0	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	$ (136)	$ (137)

Derivative Instruments (Detai52

Derivative Instruments (Details 2) MWh in Millions, MMBTU in Millions	Mar. 31, 2016MMBTUMWh
Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	14
Sales (in MWH or mmBTUs)	42
Net (in MWH or mmBTUs)	(28)
FTRs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	15
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	15
NUGs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	4
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	4
Natural Gas
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs) | MMBTU	81
Sales (in MWH or mmBTUs) | MMBTU	1
Net (in MWH or mmBTUs) | MMBTU	80

Derivative Instruments (Detai53

Derivative Instruments (Details 3) - Not Designated as Hedging Instrument - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	$ 73	$ 36
Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	(45)	(3)
Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	64	(2)
Realized Gain (Loss) Reclassified	(12)	(13)
Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	(8)	(16)
Commodity contracts | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	71	(1)
Commodity contracts | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	(45)	(3)
Commodity contracts | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	62	11
Realized Gain (Loss) Reclassified	0	0
Commodity contracts | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	(8)	(16)
FTRs | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	2	37
FTRs | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	0	0
FTRs | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	2	(13)
Realized Gain (Loss) Reclassified	(12)	(13)
FTRs | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	$ 0	0
FES | Commodity contracts | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified		(1)
FES | Commodity contracts | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified		(3)
FES | Commodity contracts | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized		11
FES | FTRs | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified		36
FES | FTRs | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized		(12)
Realized Gain (Loss) Reclassified		(13)
FES | Wholesale Sales Contract | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified		$ 22

Derivative Instruments (Detai54

Derivative Instruments (Details 4) - Not Designated as Hedging Instrument - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	$ (135)	$ (140)
Unrealized gain (loss)	(13)	(7)
Settlements	11	0
Outstanding net asset (liability), Ending Balance	(137)	(147)
NUGs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(136)	(151)
Unrealized gain (loss)	(12)	(8)
Settlements	13	11
Outstanding net asset (liability), Ending Balance	(135)	(148)
Regulated FTRs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	1	11
Unrealized gain (loss)	(1)	1
Settlements	(2)	(11)
Outstanding net asset (liability), Ending Balance	$ (2)	$ 1

Derivative Instruments (Detai55

Derivative Instruments (Details Textuals) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)agreement	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)agreement
Derivative [Line Items]
Unamortized gains or losses associated with designated cash flow hedges	$ 11		$ 11
Less than 1 million dollar loss on cash flow hedge expected to be reclassified to earnings in next twelve months	1
Unamortized gains or losses associated with prior interest rate hedges	39		42
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	17		20
Collateral received	$ 25		$ 0
Possible adverse change in quoted market prices of derivative instruments	10.00%
Possible increase net income due to ten percent adverse change in commodity prices	$ (22)
Cash Flow Hedges
Derivative [Line Items]
Number of forward starting swap agreements accounted for as a cash flow hedge outstanding | agreement	0		0
Losses to be amortized to interest expenses during next twelve months	$ 9
Number of outstanding commodity or interest rate derivatives | agreement			0
Fair Value Hedging
Derivative [Line Items]
Losses to be amortized to interest expenses during next twelve months	$ (10)
Number of outstanding commodity or interest rate derivatives | agreement	0		0
Number of fixed-for-floating interest rate swap agreements outstanding | agreement	0		0
Reclassifications from long-term debt	$ 3	$ 3
Commodity contracts
Derivative [Line Items]
Net asset position under commodity derivative contracts	164
Collateral received	25		$ 0
Commodity contracts | FES
Derivative [Line Items]
Net asset position under commodity derivative contracts	164
Collateral posted	4
Collateral received	25
Additional collateral related to commodity derivatives	5
NUGs
Derivative [Line Items]
Collateral received	0		0
Liability position	135
FTRs
Derivative [Line Items]
Collateral received	0		$ 0
Liability position	6
FTRs | FES
Derivative [Line Items]
Collateral posted	6
Liability position	$ 4

Regulatory Matters - Maryland a

Regulatory Matters - Maryland and New Jersey (Details) $ in Millions	Jul. 16, 2015	Feb. 27, 2013USD ($)	Apr. 26, 2016USD ($)	Mar. 31, 2016USD ($)componentbgs	Dec. 31, 2015	Jan. 28, 2016USD ($)
Maryland
Regulatory Matters [Line Items]
Expenditures for cost recovery program				$ 66
Expenditures for cost recovery program incurred				$ 26
Incremental energy savings goal next 12 months (percent)	0.20%
Incremental energy savings goal thereafter (percent)	2.00%
Recovery period for expenditures for cost recovery program				5 years	3 years
Requested increase in expenditures for cost recovery program						$ 2
Expected infrastructure investments		$ 2,700
Period of expected infrastructure investments		15 years
New Jersey
Regulatory Matters [Line Items]
Number of supply components | component				2
Number of basic generation services | bgs				1
JCP&L | NJBPU | New Jersey | Subsequent Event
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)			$ 142.1

Regulatory Matters - Ohio (Deta

Regulatory Matters - Ohio (Details) MWh in Thousands, $ in Millions	Aug. 07, 2013USD ($)auctions	Mar. 20, 2013	Mar. 31, 2016USD ($)MWhMW	Mar. 31, 2015USD ($)	Apr. 15, 2016USD ($)
Regulatory Matters [Line Items]
Proposed goal to reduce CO2 pollution (percent)			90.00%
Amortization (deferral) of regulatory assets, net			$ 61	$ 32
Ohio
Regulatory Matters [Line Items]
ESP extension term			2 years
Generation discount for low income customers (percent)			6.00%
Recovery period			5 years
Costs avoided by customers			$ 360
Proposed goal to reduce CO2 pollution (percent)			90.00%
Generation supply auction period, after approval			3 years
Generation supply auction period, before approval			1 year
Term of proposed purchase power agreement			8 years
Term of economic development and assistance plan			3 years
Annual revenue cap for rider			$ 30
Guaranteed credits, year seven			$ 30
Energy efficient portfolio plan term		3 years
Credit to non-shopping customers	$ 43.4
Ohio | Year 2015
Regulatory Matters [Line Items]
Annual energy savings (in GWH) | MWh			2,266
Ohio | Year 2016
Regulatory Matters [Line Items]
Annual energy savings (in GWH) | MWh			2,288
Ohio | Year 2017
Regulatory Matters [Line Items]
Annual increase in energy savings (percent)			1.00%
Ohio | Annually Through 2020
Regulatory Matters [Line Items]
Utilities required to additionally reduce peak demand			0.75%
Ohio | Wind or Solar Power
Regulatory Matters [Line Items]
Proposed potential plant acquisition (MW) | MW			100
Ohio | PUCO
Regulatory Matters [Line Items]
Number of renewable energy auctions | auctions	1
Approved period to limit average customer bill			2 years
Ohio | Ohio Companies | PUCO | Subsequent Event
Regulatory Matters [Line Items]
Expenditures for cost recovery program					$ 323
Ohio | Retail Rate Stability Rider
Regulatory Matters [Line Items]
Guaranteed credits, year five			$ 10
Guaranteed credits, year six			20
Guaranteed credits, year eight			$ 40
Ohio | Retail Rate Stability Rider | FES
Regulatory Matters [Line Items]
Term of proposed purchase power agreement			8 years
Ohio | Delivery Capital Recovery Rider
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 | Customary Advisory Council
Regulatory Matters [Line Items]
Term of proposed purchase power agreement			8 years
Annual contribution amount			$ 1
Contribution amount			$ 8
Ohio | Energy Conservation, Economic Development and Job Retention | Ohio Companies
Regulatory Matters [Line Items]
Term of proposed purchase power agreement			8 years
Annual contribution amount			$ 3
Contribution amount			$ 24
Ohio | Fuel-Fund | Ohio Companies
Regulatory Matters [Line Items]
Term of proposed purchase power agreement			8 years
Annual contribution amount			$ 2.4
Contribution amount			$ 19

Regulatory Matters - Pennsylvan

Regulatory Matters - Pennsylvania and West Virginia (Details) $ in Thousands	Oct. 19, 2015USD ($)	Jun. 19, 2015	May. 19, 2015	Oct. 10, 2013proposal	Apr. 26, 2016USD ($)	Mar. 31, 2016USD ($)program
Pennsylvania
Regulatory Matters [Line Items]
Number of requests for proposal | proposal				1
Request for proposal project term				2 years
Pennsylvania | Unfavorable Regulatory Action
Regulatory Matters [Line Items]
Maximum range of possible loss						$ 175,000
Revised implementation plan granted extension period			45 days
Pennsylvania | Three month period
Regulatory Matters [Line Items]
Term of energy contract				3 months
Pennsylvania | Twelve month period
Regulatory Matters [Line Items]
Term of energy contract				12 months
Pennsylvania | Twenty-four month period
Regulatory Matters [Line Items]
Term of energy contract				24 months
Pennsylvania | PPUC
Regulatory Matters [Line Items]
LTIIP recovery period	5 years
Pennsylvania | ME | Subsequent Event
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)					$ 140,200
Pennsylvania | ME | PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)		1.80%
Energy consumption reduction targets proposed return on equity (percent)		4.00%
Amount of requested rate increase (decrease)	$ 43,440
Pennsylvania | Penn | Subsequent Event
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)					42,000
Pennsylvania | Penn | PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)		1.70%
Energy consumption reduction targets proposed return on equity (percent)		3.30%
Amount of requested rate increase (decrease)	56,350
Pennsylvania | WP | Subsequent Event
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)					98,200
Pennsylvania | WP | PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)		1.80%
Energy consumption reduction targets proposed return on equity (percent)		2.60%
Amount of requested rate increase (decrease)	88,340
Pennsylvania | PN | Subsequent Event
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)					$ 158,800
Pennsylvania | PN | PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)		0.00%
Energy consumption reduction targets proposed return on equity (percent)		3.90%
Amount of requested rate increase (decrease)	$ 56,740
West Virginia | MP and PE | WVPSC
Regulatory Matters [Line Items]
Number of proposed efficient programs | program						3
Energy efficient reduction requirement (percent)						0.50%
Expenditures for cost recovery program						$ 9,900

Regulatory Matters - Reliabilit

Regulatory Matters - Reliability Matters and FERC (Details) $ in Millions	Sep. 14, 2015	Aug. 24, 2012USD ($)	Oct. 31, 2006proceeding	Mar. 31, 2016USD ($)entitiessubsidiary
Regulatory Matters [Line Items]
Regional enforcement entities | entities				8
FERC
Regulatory Matters [Line Items]
Denied recovery charges of exit fees				$ 78.8
FERC | California Claims Matters
Regulatory Matters [Line Items]
Settlement proposal claims				$ 190
Court proceedings from filed claims | proceeding			1
FERC | PATH-Allegheny | PATH Transmission Project
Regulatory Matters [Line Items]
Cost recovery, PP&E reclassified to Regulatory Assets		$ 62
FERC | Path-WV | PATH Transmission Project
Regulatory Matters [Line Items]
Cost recovery, PP&E reclassified to Regulatory Assets		$ 59
FERC | PATH | PATH Transmission Project
Regulatory Matters [Line Items]
Proposed return on equity		10.90%
Requested return on equity (percent)		10.40%
Return on equity granted for regional transmission organization participation		0.50%
Remaining recovery period of regulatory assets	5 years
FERC | FET
Regulatory Matters [Line Items]
Number of stand-alone transmission subsidiaries | subsidiary				2

Commitments, Guarantees and C60

Commitments, Guarantees and Contingencies (Details) $ in Millions	Mar. 31, 2016USD ($)
Guarantor Obligations [Line Items]
Guarantor obligations	$ 406
FES/AE Supply (Tied to FE Corp Rating)
Guarantor Obligations [Line Items]
Guarantor obligations	25
FES/AE Supply (Tied to FES Rating)
Guarantor Obligations [Line Items]
Guarantor obligations	341
Utilities
Guarantor Obligations [Line Items]
Guarantor obligations	40
Split Rating
Guarantor Obligations [Line Items]
Guarantor obligations	238
Split Rating | FES/AE Supply (Tied to FE Corp Rating)
Guarantor Obligations [Line Items]
Guarantor obligations	25
Split Rating | FES/AE Supply (Tied to FES Rating)
Guarantor Obligations [Line Items]
Guarantor obligations	173
Split Rating | Utilities
Guarantor Obligations [Line Items]
Guarantor obligations	40
Non-Investment Grade Rating
Guarantor Obligations [Line Items]
Guarantor obligations	265
Non-Investment Grade Rating | FES/AE Supply (Tied to FE Corp Rating)
Guarantor Obligations [Line Items]
Guarantor obligations	25
Non-Investment Grade Rating | FES/AE Supply (Tied to FES Rating)
Guarantor Obligations [Line Items]
Guarantor obligations	200
Non-Investment Grade Rating | Utilities
Guarantor Obligations [Line Items]
Guarantor obligations	$ 40

Commitments, Guarantees and C61

Commitments, Guarantees and Contingencies (Details Textuals)

Oct. 01, 2015

Aug. 03, 2015T

Apr. 19, 2013

Jun. 30, 2014

May. 31, 2014

Mar. 31, 2016USD ($)phasesT

Mar. 31, 2015USD ($)T

Dec. 31, 2014USD ($)

Mar. 31, 2016USD ($)T

Dec. 31, 2015USD ($)

Jun. 30, 2013

Oct. 31, 2012USD ($)

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

$ 3,700,000,000

$ 3,700,000,000

New syndicated senior secured term loan facility

$ 406,000,000

406,000,000

Proposed goal to reduce CO2 pollution (percent)

90.00%

Nuclear plant decommissioning trusts

$ 2,360,000,000

2,360,000,000

$ 2,282,000,000

Clean Water Act

Guarantor Obligations [Line Items]

Waste water discharge permit renewal cycle

5 years

Regulation of Waste Disposal

Guarantor Obligations [Line Items]

Bond closure and post closure period

45 years

Period to complete closure

12 years

Accrual for environmental loss contingencies

$ 123,000,000

123,000,000

Environmental liabilities former gas facilities

87,000,000

87,000,000

Nuclear Plant Matters

Guarantor Obligations [Line Items]

Nuclear plant decommissioning trusts

2,400,000,000

2,400,000,000

Parental guarantee

$ 24,500,000

24,500,000

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

20 years

Caa Compliance

Guarantor Obligations [Line Items]

Loss in period

$ 226,000,000

Amount remaining under contract | T

5,500,000

5,500,000

National Ambient Air Quality Standards

Guarantor Obligations [Line Items]

Capping of SO2 emissions under CSAPR | T

2,400,000

Capping of NOx emissions under CSAPR | T

1,200,000

National Ambient Air Quality Standards | CSAPR

Guarantor Obligations [Line Items]

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

2

Hazardous Air Pollutant Emissions

Guarantor Obligations [Line Items]

Potential cost of compliance, MATS

$ 345,000,000

$ 345,000,000

Climate Change

Guarantor Obligations [Line Items]

Percent reduction in GHG emissions between 2005 and 2012

10.00%

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

12.00%

Climate Change | Year 2016

Guarantor Obligations [Line Items]

Anticipated reduction in CO2 emissions (percent)

25.00%

Regulated Distribution

Guarantor Obligations [Line Items]

Company posted collateral related to net liability positions

1,000,000

1,000,000

Regulated Distribution | Caa Compliance

Guarantor Obligations [Line Items]

Loss in period

130,000,000

Regulated Distribution | Hazardous Air Pollutant Emissions

Guarantor Obligations [Line Items]

Potential cost of compliance, MATS

177,000,000

177,000,000

Competitive Energy Services | Caa Compliance

Guarantor Obligations [Line Items]

Loss in period

96,000,000

Competitive Energy Services | Hazardous Air Pollutant Emissions

Guarantor Obligations [Line Items]

Potential cost of compliance, MATS

168,000,000

168,000,000

FES

Guarantor Obligations [Line Items]

Company posted collateral related to net liability positions

180,000,000

180,000,000

Potential collateral posted related to net liability positions

3,000,000

3,000,000

New syndicated senior secured term loan facility

25,000,000

25,000,000

Settlement amount

$ 70,000,000

Nuclear plant decommissioning trusts

1,372,000,000

1,372,000,000

$ 1,327,000,000

Global Holding | Senior Secured Term Loan | Senior Loans

Guarantor Obligations [Line Items]

New syndicated senior secured term loan facility

$ 300,000,000

$ 300,000,000

$ 300,000,000

$ 350,000,000

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

Guarantor Obligations [Line Items]

Investment ownership percentage

69.99%

69.99%

FEV | Global Holding

Guarantor Obligations [Line Items]

Loss in period

$ 24,000,000

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

Guarantor Obligations [Line Items]

Investment ownership percentage

33.33%

33.33%

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

Guarantor Obligations [Line Items]

Investment ownership percentage

33.33%

33.33%

Environmental Protection Agency | Caa Compliance

Guarantor Obligations [Line Items]

Period of time to implement plan

3 years

Minimum | Clean Water Act

Guarantor Obligations [Line Items]

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

$ 150,000,000

Maximum | Clean Water Act

Guarantor Obligations [Line Items]

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

300,000,000

Maximum | State and Local Agencies | Climate Change

Guarantor Obligations [Line Items]

Potential MATS extension period

2 years

Put Option | FEV | Signal Peak

Guarantor Obligations [Line Items]

Derivative notional amount mass (tons) | T

2,000,000

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

Guarantor Obligations [Line Items]

Minimum coal supply commitment (ton) | T

3,500,000

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

Guarantor Obligations [Line Items]

Minimum coal supply commitment (ton) | T

2,500,000

FirstEnergy

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

591,000,000

$ 591,000,000

Subsidiaries

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

2,100,000,000

2,100,000,000

Other Guarantee

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

300,000,000

300,000,000

Other Assurances

Guarantor Obligations [Line Items]

Outstanding guarantees and other assurances aggregated

$ 669,000,000

$ 669,000,000

Supplemental Guarantor Inform62

Supplemental Guarantor Information (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Consolidating Statements of Income
Revenues	[1]	$ 3,869	$ 3,897
OPERATING EXPENSES:
Fuel		381	513
Purchased power		1,124	1,113
Other operating expenses		918	1,057
Provision for depreciation		329	319
General taxes		280	269
Total operating expenses		3,093	3,303
OPERATING INCOME		776	594
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from equity investees		28	17
Interest expense		(288)	(279)
Capitalized interest		25	34
Total other income (expense)		(235)	(228)
INCOME BEFORE INCOME TAXES		541	366
INCOME TAXES (BENEFITS)		213	144
NET INCOME (LOSS)		328	222
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		328	222
Pension and OPEB prior service costs		(18)	(31)
Amortized gains on derivative hedges		2	1
Change in unrealized gain on available-for-sale securities		28	4
Other comprehensive income (loss)		12	(26)
Income taxes (benefits) on other comprehensive income (loss)		4	(10)
Other comprehensive income (loss), net of tax		8	(16)
COMPREHENSIVE INCOME (LOSS)		336	206
FES
Consolidating Statements of Income
Revenues		1,155	1,332
OPERATING EXPENSES:
Fuel		0	0
Other operating expenses		4	180
Provision for depreciation		3	3
General taxes		8	15
Total operating expenses		1,319	1,698
OPERATING INCOME		(164)	(366)
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from equity investees		251	241
Capitalized interest		0	0
Total other income (expense)		229	222
INCOME BEFORE INCOME TAXES		65	(144)
INCOME TAXES (BENEFITS)		(66)	(141)
NET INCOME (LOSS)		131	(3)
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		131	(3)
Pension and OPEB prior service costs		(4)	(4)
Amortized gains on derivative hedges			(1)
Change in unrealized gain on available-for-sale securities		23	3
Other comprehensive income (loss)		19	(2)
Income taxes (benefits) on other comprehensive income (loss)		7	(1)
Other comprehensive income (loss), net of tax		12	(1)
COMPREHENSIVE INCOME (LOSS)		143	(4)
FES | Affiliates
OPERATING EXPENSES:
Purchased power		927	957
OTHER INCOME (EXPENSE):
Interest expense		(9)	(6)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power		377	543
OTHER INCOME (EXPENSE):
Interest expense		(13)	(13)
FGCO
Consolidating Statements of Income
Revenues		415	493
OPERATING EXPENSES:
Fuel		119	180
Other operating expenses		71	67
Provision for depreciation		31	30
General taxes		10	8
Total operating expenses		231	285
OPERATING INCOME		184	208
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from equity investees		6	3
Capitalized interest		2	1
Total other income (expense)		(20)	(24)
INCOME BEFORE INCOME TAXES		164	184
INCOME TAXES (BENEFITS)		61	67
NET INCOME (LOSS)		103	117
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		103	117
Pension and OPEB prior service costs		(3)	(4)
Amortized gains on derivative hedges			0
Change in unrealized gain on available-for-sale securities		0	0
Other comprehensive income (loss)		(3)	(4)
Income taxes (benefits) on other comprehensive income (loss)		(1)	(1)
Other comprehensive income (loss), net of tax		(2)	(3)
COMPREHENSIVE INCOME (LOSS)		101	114
FGCO | Affiliates
OPERATING EXPENSES:
Purchased power		0	0
OTHER INCOME (EXPENSE):
Interest expense		(2)	(2)
FGCO | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0
OTHER INCOME (EXPENSE):
Interest expense		(26)	(26)
Nuclear Generation Corp
Consolidating Statements of Income
Revenues		531	507
OPERATING EXPENSES:
Fuel		46	50
Other operating expenses		153	154
Provision for depreciation		50	48
General taxes		8	6
Total operating expenses		314	326
OPERATING INCOME		217	181
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from equity investees		17	14
Capitalized interest		8	8
Total other income (expense)		12	8
INCOME BEFORE INCOME TAXES		229	189
INCOME TAXES (BENEFITS)		86	70
NET INCOME (LOSS)		143	119
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		143	119
Pension and OPEB prior service costs		0	3
Amortized gains on derivative hedges			0
Change in unrealized gain on available-for-sale securities		23	0
Other comprehensive income (loss)		23	3
Income taxes (benefits) on other comprehensive income (loss)		8	1
Other comprehensive income (loss), net of tax		15	2
COMPREHENSIVE INCOME (LOSS)		158	121
Nuclear Generation Corp | Affiliates
OPERATING EXPENSES:
Purchased power		57	68
OTHER INCOME (EXPENSE):
Interest expense		(2)	(1)
Nuclear Generation Corp | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0
OTHER INCOME (EXPENSE):
Interest expense		(11)	(13)
Eliminations
Consolidating Statements of Income
Revenues		(902)	(955)
OPERATING EXPENSES:
Fuel		0	0
Other operating expenses		12	12
Provision for depreciation		(1)	(1)
General taxes		0	0
Total operating expenses		(891)	(944)
OPERATING INCOME		(11)	(11)
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from equity investees		(259)	(245)
Capitalized interest		0	0
Total other income (expense)		(234)	(223)
INCOME BEFORE INCOME TAXES		(245)	(234)
INCOME TAXES (BENEFITS)		1	2
NET INCOME (LOSS)		(246)	(236)
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		(246)	(236)
Pension and OPEB prior service costs		3	1
Amortized gains on derivative hedges			0
Change in unrealized gain on available-for-sale securities		(23)	0
Other comprehensive income (loss)		(20)	1
Income taxes (benefits) on other comprehensive income (loss)		(7)	0
Other comprehensive income (loss), net of tax		(13)	1
COMPREHENSIVE INCOME (LOSS)		(259)	(235)
Eliminations | Affiliates
OPERATING EXPENSES:
Purchased power		(902)	(955)
OTHER INCOME (EXPENSE):
Interest expense		11	7
Eliminations | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0
OTHER INCOME (EXPENSE):
Interest expense		14	15
FES
Consolidating Statements of Income
Revenues		1,199	1,377
OPERATING EXPENSES:
Fuel		165	230
Other operating expenses		240	413
Provision for depreciation		83	80
General taxes		26	29
Total operating expenses		973	1,365
OPERATING INCOME		226	12
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from equity investees		15	13
Capitalized interest		10	9
Total other income (expense)		(13)	(17)
INCOME BEFORE INCOME TAXES		213	(5)
INCOME TAXES (BENEFITS)		82	(2)
NET INCOME (LOSS)		131	(3)
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		131	(3)
Pension and OPEB prior service costs		(4)	(4)
Amortized gains on derivative hedges		0	(1)
Change in unrealized gain on available-for-sale securities		23	3
Other comprehensive income (loss)		19	(2)
Income taxes (benefits) on other comprehensive income (loss)		7	(1)
Other comprehensive income (loss), net of tax		12	(1)
COMPREHENSIVE INCOME (LOSS)		143	(4)
FES | Affiliates
OPERATING EXPENSES:
Purchased power		82	70
OTHER INCOME (EXPENSE):
Interest expense		(2)	(2)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power		377	543
OTHER INCOME (EXPENSE):
Interest expense		$ (36)	$ (37)
Bruce Mansfield Unit 1
Condensed Financial Statements, Captions [Line Items]
Percentage of undivided interest of non guarantor subsidiary		93.83%
[1]	Includes excise tax collections of $107 million and $115 million in the three months ended March 31, 2016 and 2015, respectively.

Supplemental Guarantor Inform63

Supplemental Guarantor Information (Details 1) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 146	$ 131		$ 85	$ 90
Receivables-
Customers	1,432	1,415
Other	162	180
Materials and supplies	781	785
Derivatives	207	157
Collateral	80	70
Prepayments and other	155	167
Total current assets	3,230	3,040
PROPERTY, PLANT AND EQUIPMENT:
In service	50,371	49,952
Less - Accumulated provision for depreciation	15,421	15,160
Property, plant and equipment in service net of accumulated provision for depreciation	34,950	34,792
Construction work in progress	2,694	2,422
Total net property, plant and equipment	37,644	37,214
INVESTMENTS:
Nuclear plant decommissioning trusts	2,360	2,282
Other	526	506
Total other property and investments	2,886	2,788
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418	$ 6,418
Other	1,238	1,286
Total deferred charges and other assets	8,935	9,052
Total assets	52,695	52,094	51,879
CURRENT LIABILITIES:
Currently payable long-term debt	1,355	1,166
Other	2,125	1,708
Accounts payable-
Accrued taxes	513	519
Derivatives	117	106
Other	970	694
Total current liabilities	6,389	5,602
CAPITALIZATION:
Total common stockholders' equity	12,463	12,421
Long-term debt and other long-term obligations	18,878	19,099
Total capitalization	31,342	31,521
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	782	791
Accumulated deferred income taxes	6,996	6,773
Retirement benefits	4,135	4,245
Asset retirement obligations	1,427	1,410
Other	1,430	1,555
Total noncurrent liabilities	14,964	14,971
Total liabilities and capitalization	52,695	52,094
FES
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	229	275
Affiliated companies	442	433
Other	32	36
Notes receivable from affiliated companies	394	406
Materials and supplies	39	53
Derivatives	207	154
Collateral	80	70
Prepayments and other	69	48
Total current assets	1,492	1,475
PROPERTY, PLANT AND EQUIPMENT:
In service	92	93
Less - Accumulated provision for depreciation	43	40
Property, plant and equipment in service net of accumulated provision for depreciation	49	53
Construction work in progress	30	30
Total net property, plant and equipment	79	83
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	7,712	7,452
Other	0	0
Total other property and investments	7,712	7,452
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	276	300
Customer intangibles	57	61
Goodwill	23	23
Property taxes	0	0
Derivatives	89	79
Other	24	29
Total deferred charges and other assets	469	492
Total assets	9,752	9,502
CURRENT LIABILITIES:
Currently payable long-term debt	0	0
Other		0
Accounts payable-
Affiliated companies	619	884
Other	26	21
Accrued taxes	3	7
Derivatives	115	103
Other	75	66
Total current liabilities	3,211	3,102
CAPITALIZATION:
Total common stockholders' equity	5,749	5,605
Long-term debt and other long-term obligations	690	690
Total capitalization	6,439	6,295
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	6	6
Retirement benefits	28	27
Asset retirement obligations	0	0
Derivatives	21	37
Other	47	35
Total noncurrent liabilities	102	105
Total liabilities and capitalization	9,752	9,502
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	2,373	2,021
FGCO
CURRENT ASSETS:
Cash and cash equivalents	2	2	2	2
Receivables-
Customers	0	0
Affiliated companies	310	403
Other	1	4
Notes receivable from affiliated companies	1,429	1,210
Materials and supplies	191	204
Derivatives	0	0
Collateral	0	0
Prepayments and other	11	18
Total current assets	1,944	1,841
PROPERTY, PLANT AND EQUIPMENT:
In service	6,389	6,367
Less - Accumulated provision for depreciation	2,163	2,144
Property, plant and equipment in service net of accumulated provision for depreciation	4,226	4,223
Construction work in progress	271	249
Total net property, plant and equipment	4,497	4,472
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	0	0
Other	10	10
Total other property and investments	10	10
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	16
Customer intangibles	0	0
Goodwill	0	0
Property taxes	9	12
Derivatives	0	0
Other	301	312
Total deferred charges and other assets	310	340
Total assets	6,761	6,663
CURRENT LIABILITIES:
Currently payable long-term debt	266	229
Other		8
Accounts payable-
Affiliated companies	190	146
Other	90	118
Accrued taxes	52	93
Derivatives	0	1
Other	74	61
Total current liabilities	1,058	1,045
CAPITALIZATION:
Total common stockholders' equity	3,046	2,944
Long-term debt and other long-term obligations	2,067	2,116
Total capitalization	5,113	5,060
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	35	0
Retirement benefits	311	305
Asset retirement obligations	188	191
Derivatives	0	1
Other	56	61
Total noncurrent liabilities	590	558
Total liabilities and capitalization	6,761	6,663
FGCO | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	386	389
Nuclear Generation Corp
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	305	461
Other	74	19
Notes receivable from affiliated companies	889	805
Materials and supplies	216	213
Derivatives	0	0
Collateral	0	0
Prepayments and other	0	0
Total current assets	1,484	1,498
PROPERTY, PLANT AND EQUIPMENT:
In service	8,277	8,233
Less - Accumulated provision for depreciation	3,863	3,775
Property, plant and equipment in service net of accumulated provision for depreciation	4,414	4,458
Construction work in progress	972	878
Total net property, plant and equipment	5,386	5,336
INVESTMENTS:
Nuclear plant decommissioning trusts	1,372	1,327
Investment in affiliated companies	0	0
Other	0	0
Total other property and investments	1,372	1,327
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	0	0
Goodwill	0	0
Property taxes	21	28
Derivatives	0	0
Other	4	14
Total deferred charges and other assets	25	42
Total assets	8,267	8,203
CURRENT LIABILITIES:
Currently payable long-term debt	308	308
Other		0
Accounts payable-
Affiliated companies	172	368
Other	0	0
Accrued taxes	101	62
Derivatives	0	0
Other	15	9
Total current liabilities	598	747
CAPITALIZATION:
Total common stockholders' equity	4,634	4,476
Long-term debt and other long-term obligations	840	840
Total capitalization	5,474	5,316
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	743	697
Retirement benefits	0	0
Asset retirement obligations	650	640
Derivatives	0	0
Other	802	803
Total noncurrent liabilities	2,195	2,140
Total liabilities and capitalization	8,267	8,203
Nuclear Generation Corp | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	2	0
Eliminations
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	(610)	(846)
Other	0	0
Notes receivable from affiliated companies	(2,712)	(2,410)
Materials and supplies	0	0
Derivatives	0	0
Collateral	0	0
Prepayments and other	0	0
Total current assets	(3,322)	(3,256)
PROPERTY, PLANT AND EQUIPMENT:
In service	(382)	(382)
Less - Accumulated provision for depreciation	(195)	(194)
Property, plant and equipment in service net of accumulated provision for depreciation	(187)	(188)
Construction work in progress	0	0
Total net property, plant and equipment	(187)	(188)
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	(7,712)	(7,452)
Other	0	0
Total other property and investments	(7,712)	(7,452)
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	(276)	(316)
Customer intangibles	0	0
Goodwill	0	0
Property taxes	0	0
Derivatives	0	0
Other	56	12
Total deferred charges and other assets	(220)	(304)
Total assets	(11,441)	(11,200)
CURRENT LIABILITIES:
Currently payable long-term debt	(25)	(25)
Other		0
Accounts payable-
Affiliated companies	(619)	(856)
Other	0	0
Accrued taxes	(85)	(86)
Derivatives	0	0
Other	77	45
Total current liabilities	(3,364)	(3,332)
CAPITALIZATION:
Total common stockholders' equity	(7,680)	(7,420)
Long-term debt and other long-term obligations	(1,117)	(1,136)
Total capitalization	(8,797)	(8,556)
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	782	791
Accumulated deferred income taxes	(62)	(103)
Retirement benefits	0	0
Asset retirement obligations	0	0
Derivatives	0	0
Other	0	0
Total noncurrent liabilities	720	688
Total liabilities and capitalization	(11,441)	(11,200)
Eliminations | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	(2,712)	(2,410)
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2	$ 2	$ 2
Receivables-
Customers	229	275
Affiliated companies	447	451
Other	107	59
Notes receivable from affiliated companies	0	11
Materials and supplies	446	470
Derivatives	207	154
Collateral	80	70
Prepayments and other	80	66
Total current assets	1,598	1,558
PROPERTY, PLANT AND EQUIPMENT:
In service	14,376	14,311
Less - Accumulated provision for depreciation	5,874	5,765
Property, plant and equipment in service net of accumulated provision for depreciation	8,502	8,546
Construction work in progress	1,273	1,157
Total net property, plant and equipment	9,775	9,703
INVESTMENTS:
Nuclear plant decommissioning trusts	1,372	1,327
Investment in affiliated companies	0	0
Other	10	10
Total other property and investments	1,382	1,337
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	57	61
Goodwill	23	23
Property taxes	30	40
Derivatives	89	79
Other	385	367
Total deferred charges and other assets	584	570
Total assets	13,339	13,168
CURRENT LIABILITIES:
Currently payable long-term debt	549	512
Other		8
Accounts payable-
Affiliated companies	362	542
Other	116	139
Accrued taxes	71	76
Derivatives	115	104
Other	241	181
Total current liabilities	1,503	1,562
CAPITALIZATION:
Total common stockholders' equity	5,749	5,605
Long-term debt and other long-term obligations	2,480	2,510
Total capitalization	8,229	8,115
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	782	791
Accumulated deferred income taxes	722	600
Retirement benefits	339	332
Asset retirement obligations	838	831
Derivatives	21	38
Other	905	899
Total noncurrent liabilities	3,607	3,491
Total liabilities and capitalization	13,339	13,168
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	$ 49	$ 0

Supplemental Guarantor Inform64

Supplemental Guarantor Information (Details 2) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	$ 638	$ 193
New Financing-
Short-term borrowings, net	425	760
Redemptions and Repayments-
Long-term debt	(31)	(48)
Net cash provided from (used for) financing activities	242	560
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(698)	(668)
Nuclear fuel	(149)	(60)
Sales of investment securities held in trusts	465	371
Purchases of investment securities held in trusts	(488)	(394)
Cash investments	30	21
Other	9	10
Net cash used for investing activities	(865)	(748)
Net change in cash and cash equivalents	15	5
Cash and cash equivalents at beginning of period	131	85
Cash and cash equivalents at end of period	146
FES
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	(356)	(662)
New Financing-
Short-term borrowings, net	352	674
Redemptions and Repayments-
Long-term debt		(17)
Short-term borrowings, net	0	0
Other		0
Net cash provided from (used for) financing activities	352	657
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(27)	(1)
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	12	6
Other	9
Net cash used for investing activities	4	5
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
FGCO
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	277	222
New Financing-
Short-term borrowings, net	8	0
Redemptions and Repayments-
Long-term debt		0
Short-term borrowings, net	(11)	(5)
Other	(2)	(2)
Net cash provided from (used for) financing activities	(5)	(7)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(53)	(36)
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	(219)	(179)
Other	0
Net cash used for investing activities	(272)	(215)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	2	2
Cash and cash equivalents at end of period	2	2
Nuclear Generation Corp
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	307	545
New Financing-
Short-term borrowings, net	1	0
Redemptions and Repayments-
Long-term debt		0
Short-term borrowings, net	0	(28)
Other		0
Net cash provided from (used for) financing activities	1	(28)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(63)	(82)
Nuclear fuel	(149)	(60)
Sales of investment securities held in trusts	138	189
Purchases of investment securities held in trusts	(151)	(202)
Cash investments	0
Loans to affiliated companies, net	(83)	(362)
Other	0
Net cash used for investing activities	(308)	(517)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
Eliminations
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	0	0
New Financing-
Short-term borrowings, net	(312)	(524)
Redemptions and Repayments-
Long-term debt		0
Short-term borrowings, net	11	33
Other		0
Net cash provided from (used for) financing activities	(301)	(491)
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	301	491
Other	0
Net cash used for investing activities	301	491
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
FES
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	228	105
New Financing-
Short-term borrowings, net	49	150
Redemptions and Repayments-
Long-term debt	0	(17)
Short-term borrowings, net	0	0
Other	(2)	(2)
Net cash provided from (used for) financing activities	47	131
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(143)	(119)
Nuclear fuel	(149)	(60)
Sales of investment securities held in trusts	138	189
Purchases of investment securities held in trusts	(151)	(202)
Cash investments	10	0
Loans to affiliated companies, net	11	(44)
Other	9	0
Net cash used for investing activities	(275)	(236)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	2	2
Cash and cash equivalents at end of period	$ 2	$ 2

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Segment Financial Information
Revenues		$ 3,869	$ 3,897
Revenues	[1]	3,869	3,897
Depreciation		329	319
Amortization of regulatory assets, net		61	32
Investment income (loss)		28	17
Interest expense		288	279
Income taxes (benefits)		213	144
NET INCOME (LOSS)		328	222
Total assets		52,695	51,879	$ 52,094
Goodwill		6,418	6,418	$ 6,418
Property additions		698	668
Intersegment Eliminations
Segment Financial Information
Revenues		0	0
Regulated Distribution
Segment Financial Information
Revenues		2,521	2,562
Revenues		2,521	2,562
Depreciation		169	172
Amortization of regulatory assets, net		59	29
Investment income (loss)		11	13
Interest expense		147	144
Income taxes (benefits)		98	122
NET INCOME (LOSS)		165	208
Total assets		27,907	27,974
Goodwill		5,092	5,092
Property additions		262	280
Regulated Distribution | Intersegment Eliminations
Segment Financial Information
Revenues		0	0
Regulated Transmission
Segment Financial Information
Revenues		275	238
Revenues		275	238
Depreciation		43	37
Amortization of regulatory assets, net		2	3
Investment income (loss)		0	0
Interest expense		43	39
Income taxes (benefits)		43	42
NET INCOME (LOSS)		74	72
Total assets		7,679	6,601
Goodwill		526	526
Property additions		258	254
Regulated Transmission | Intersegment Eliminations
Segment Financial Information
Revenues		0	0
Competitive Energy Services
Segment Financial Information
Revenues		1,152	1,175
Revenues		1,304	1,435
Depreciation		102	96
Amortization of regulatory assets, net		0	0
Investment income (loss)		15	12
Interest expense		47	48
Income taxes (benefits)		85	(4)
NET INCOME (LOSS)		144	(8)
Total assets		16,578	16,497
Goodwill		800	800
Property additions		169	126
Competitive Energy Services | Intersegment Eliminations
Segment Financial Information
Revenues		152	260
Other/Corporate
Segment Financial Information
Revenues		(42)	(42)
Revenues		(42)	(42)
Depreciation		15	14
Amortization of regulatory assets, net		0	0
Investment income (loss)		11	2
Interest expense		51	47
Income taxes (benefits)		(13)	(18)
NET INCOME (LOSS)		(55)	(50)
Total assets		531	807
Goodwill		0	0
Property additions		9	8
Other/Corporate | Intersegment Eliminations
Segment Financial Information
Revenues		0	0
Reconciling Adjustments
Segment Financial Information
Revenues		(37)	(36)
Revenues		(189)	(296)
Depreciation		0	0
Amortization of regulatory assets, net		0	0
Investment income (loss)		(9)	(10)
Interest expense		0	1
Income taxes (benefits)		0	2
NET INCOME (LOSS)		0	0
Total assets		0	0
Goodwill		0	0
Property additions		0	0
Reconciling Adjustments | Intersegment Eliminations
Segment Financial Information
Revenues		$ (152)	$ (260)
[1]	Includes excise tax collections of $107 million and $115 million in the three months ended March 31, 2016 and 2015, respectively.

Segment Information (Details Te

Segment Information (Details Textuals) mi² in Thousands, customer in Millions, $ in Billions	3 Months Ended
	Mar. 31, 2016USD ($)mi²customercompanyMW
Regulated Distribution
Segment Reporting Information [Line Items]
Number of existing utility operating companies | company	10
Number of customers served by utility operating companies | customer	6
Number of square miles in service area | mi²	65
Megawatts of net demonstrated capacity of competitive segment | MW	3,790
Competitive Energy Services
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment | MW	13,162
Other/Corporate
Segment Reporting Information [Line Items]
Long-term debt and other long-term obligations | $	$ 4.2
Long-term debt percentage bearing variable interest (percent)	28.00%
FirstEnergy | Revolving Credit Facility | Other/Corporate
Segment Reporting Information [Line Items]
Long-term line of credit | $	$ 2.1