NRG Energy (NRG) 10-K 29 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Jan. 31, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Entity Registrant Name	NRG ENERGY, INC.
Entity Central Index Key	1,013,871
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 6,713,289,371
Entity Common Stock, Shares Outstanding		314,890,647
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Operating Revenues
Total operating revenues	$ 3,011	$ 4,434	$ 3,400	$ 3,829	$ 4,192	$ 4,569	$ 3,621	$ 3,486	$ 14,674	[1]	$ 15,868	[2]	$ 11,295	[3]
Total operating revenues
Cost of operations									10,755		11,794		8,130
Depreciation and amortization									1,566		1,523		1,256
Impairment losses									5,030		97		459
Selling, general and administrative									1,220		1,027		895
Acquisition-related transaction and integration costs									10		84		128
Research and Development Expense									154		91		84
Total operating costs and expenses									18,735		14,616		10,952
Gain on sale of assets									21		19		0
Operating(Loss)/Income	(4,727)	379	232	76	453	549	89	180	(4,040)		1,271		343
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates									36		38		7
Impairment losses on investments									(56)		0		(99)
Other income, net									33		22		13
(Loss)/gain on sale of equity-method investment									(14)		18		0
Net gain/(loss) on debt extinguishment									75		(95)		(50)
Interest expense									(1,128)		(1,119)		(848)
Total other expense									(1,054)		(1,136)		(977)
(Loss)/Income Before Income Taxes									(5,094)		135		(634)
Income tax expense/(benefit)									1,342		3		(282)
Net (Loss)/Income	(6,358)	67	(9)	(136)	97	182	(80)	(67)	(6,436)		132		(352)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	(44)	1	5	(16)	(22)	14	17	(11)	(54)		(2)		34
Net Income (Loss) Attributable to Nonredeemable Noncontrolling Interest											17
Net (Loss)/Income Attributable to NRG Energy, Inc.	(6,314)	66	(14)	(120)	119	168	(97)	(56)	(6,382)		134		(386)
Dividends for preferred shares									20		56		9
Dividends, Preferred Stock, Cash									20		9		(9)
(Loss)/Income Available for Common Stockholders	$ (6,319)	$ 61	$ (19)	$ (125)	$ 70	$ 166	$ (100)	$ (58)	$ (6,402)		$ 78		$ (395)
(Loss)/Earnings Per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic	315	331	333	336	338	338	337	324	329		334		323
Net (Loss)/Income per Weighted Average Common Share — Basic	$ (20.08)	$ 0.18	$ (0.06)	$ (0.37)	$ 0.21	$ 0.49	$ (0.30)	$ (0.18)	$ (19.46)		$ 0.23		$ (1.22)
Weighted average number of common shares outstanding — diluted	315	332	333	336	342	343	337	324	329		339		323
Net (Loss)/Income per Weighted Average Common Share — Diluted	$ (20.08)	$ 0.18	$ (0.06)	$ (0.37)	$ 0.20	$ 0.48	$ (0.30)	$ (0.18)	$ (19.46)		$ 0.23		$ (1.22)
Dividends Per Common Share									$ 0.58		$ 0.54		$ 0.45
[1]	(a) Operating revenues include inter-segment sales and net derivative gains and losses of:$947 $6 $1 $23 $29 $212 $— $1,218
[2]	(c) Operating revenues include inter-segment sales and net derivative gains and losses of:$1,820 $7 $— $25 $12 $85 $— $1,949
[3]	(f) Operating revenues include inter-segment sales and net derivative gains and losses of:$2,055 $5 $— $14 $7 $227 $— $2,308

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net (Loss)/Income	$ (6,358)	$ 67	$ (9)	$ (136)	$ 97	$ 182	$ (80)	$ (67)	$ (6,436)	$ 132	$ (352)
Other Comprehensive (Loss)/Income, net of tax
Unrealized (loss)/gain on derivatives, net of income tax expense/(benefit) of $19, $(21), and $(6)									(15)	(45)	8
Foreign currency translation adjustments, net of income tax benefit of $0, $5, and $14									(11)	(8)	(24)
Available-for-sale securities, net of income tax (benefit)/expense of $(3), $(2), and $2									17	(7)	3
Defined benefit plan, net of income tax expense/(benefit) of $69, $(88), and $100									10	(129)	168
Other comprehensive income/(loss)									1	(189)	155
Comprehensive Loss									(6,435)	(57)	(197)
Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									73	(8)	(34)
Comprehensive Loss Attributable to NRG Energy, Inc.									(6,362)	(65)	(231)
Dividends for preferred shares									20	56	9
Comprehensive Loss Available for Common Stockholders									$ (6,382)	$ (121)	$ (240)

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Unrealized loss/gain on derivatives, income tax benefit/(expense)	$ (19)	$ 21	$ 6
Foreign currency translation adjustments, income tax benefit/(expense)	0	5	14
Available-for-sale securities, income tax benefit/(expense)	3	(2)	2
Defined benefit plan, income tax benefit/(expense)	$ (69)	$ 88	$ (100)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 1,518	$ 2,116
Funds deposited by counterparties	106	72
Restricted cash	414	457
Accounts receivable — trade, less allowance for doubtful accounts of $21 and $23	1,157	1,322
Inventory	1,252	1,247
Derivative instruments	1,915	2,425
Cash collateral paid in support of energy risk management activities	568	187
Renewable energy grant receivable	13	135
Current assets held-for-sale	6	0
Prepayments and other current assets	442	447
Total current assets	7,391	8,408
Property, Plant and Equipment
In service	24,909	29,487
Under construction	627	770
Total property, plant and equipment	25,536	30,257
Less accumulated depreciation	(6,804)	(7,890)
Net property, plant and equipment	18,732	22,367
Other Assets
Equity investments in affiliates	1,045	771
Notes receivable, less current portion	53	72
Goodwill	999	2,574
Intangible assets, net of accumulated amortization of $1,525 and $1,402	2,310	2,567
Nuclear decommissioning trust fund	561	585
Derivative instruments	305	480
Deferred income taxes	167	1,580
Non-current assets held-for-sale	105	17
Other non-current assets	1,214	1,045
Total other assets	6,759	9,691
Total Assets	32,882	40,466
Current Liabilities
Current portion of long-term debt and capital leases	481	474
Accounts payable	869	1,060
Derivative instruments	1,721	2,054
Cash collateral received in support of energy risk management activities	106	72
Accrued interest expense	242	252
Other accrued expenses	568	553
Current liabilities held-for-sale	2	0
Other current liabilities	386	394
Total current liabilities	4,375	4,859
Other Liabilities
Long-term debt and capital leases	18,983	19,701
Nuclear decommissioning reserve	326	310
Nuclear decommissioning trust liability	283	333
Postretirement and other benefit obligations	588	727
Deferred income taxes	19	21
Derivative instruments	493	438
Non-current liabilities held-for-sale	4	0
Off-market Lease, Unfavorable	1,146	1,244
Other non-current liabilities	900	847
Total non-current liabilities	22,742	23,621
Total Liabilities	27,117	28,480
2.822% convertible perpetual preferred stock; $0.01 par value; 250,000 shares issued and outstanding	302	291
Redeemable noncontrolling interest in subsidiaries	29	19
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 416,939,950 and 415,506,176 shares issued; and 314,190,042 and 336,662,624 shares outstanding at December 31, 2015 and 2014	4	4
Additional paid-in capital	8,296	8,327
Retained (deficit)/earnings	(3,007)	3,588
Less treasury stock, at cost; 102,749,908 and 78,843,552 shares at December 31, 2015 and 2014	(2,413)	(1,983)
Accumulated other comprehensive loss	(173)	(174)
Noncontrolling interest	2,727	1,914
Total Stockholders' Equity	5,434	11,676
Total Liabilities and Stockholders' Equity	$ 32,882	$ 40,466

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($)	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014
Accounts receivable - trade, allowance for doubtful accounts (in millions)	$ 21,000,000		$ 23,000,000
Intangible assets, accumulated amortization (in millions)	$ 1,525,000,000	[1]	$ 1,402,000,000
3.625% convertible perpetual preferred stock, par value (in dollars)	$ 0.01		$ 0.01
3.625% convertible perpetual preferred stock, shares issued	250,000		250,000
3.625% convertible perpetual preferred stock, shares outstanding	250,000		250,000
3.625% convertible perpetual preferred stock, liquidation value (in dollars)	$ 250		$ 250
Common stock, par value (in dollars)	$ 0		$ 0.01
Common stock, shares authorized	500,000,000		500,000,000
Common stock, shares issued	416,939,950		415,506,176
Common stock, shares outstanding	314,190,042		336,662,624
Treasury stock, shares	102,749,908		78,843,552
Convertible Preferred Stock [Member]
Preferred Stock, Dividend Rate Amended, Percentage	2.822%		2.822%
[1]	Adjusted for write-off of fully amortized emissions allowances of $154 million.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows from Operating Activities
Net (Loss)/Income	$ (6,436)	$ 132	$ (352)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	37	49	84
Depreciation and amortization	1,566	1,523	1,256
Provision for bad debts	64	64	67
Amortization of nuclear fuel	45	46	36
Amortization of financing costs and debt discount/premiums	11	12	33
Adjustment to (gain)/loss on debt extinguishment	(75)	25	(15)
Amortization of intangibles and out-of-market contracts	81	64	49
Amortization of unearned equity compensation	41	42	38
Gain on post retirement benefits curtailment and sales of assets	(7)	(4)	(3)
Impairment losses	5,086	97	558
Changes in derivative instruments	233	(61)	164
Changes in deferred income taxes and liability for uncertain tax benefits	1,326	(154)	(67)
Changes in nuclear decommissioning trust liability	(2)	19	15
Cash provided/(used) by changes in other working capital, net of acquisition and disposition effects:
Accounts receivable - trade	136	(2)	(224)
Inventory	(26)	(245)	11
Prepayments and other current assets	8	36	25
Accounts payable	(218)	(12)	275
Accrued expenses and other current liabilities	(9)	(26)	(114)
Other assets and liabilities	(149)	(217)	(453)
Net Cash Provided by Operating Activities	1,309	1,510	1,270
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired	(31)	(2,936)	(494)
Capital expenditures	(1,283)	(909)	(1,987)
Decrease/(increase) in restricted cash, net	8	57	(22)
Decrease/(increase) in restricted cash to support equity requirements for U.S. DOE funded projects	35	(206)	(26)
Increase (Decrease) in Notes Receivables	18	25	(11)
Proceeds from renewable energy grants	82	916	55
Purchases of emission allowances, net of proceeds	41	(16)	5
Investments in nuclear decommissioning trust fund securities	(629)	(619)	(514)
Proceeds from sales of nuclear decommissioning trust fund securities	631	600	488
Proceeds from sale of assets, net	27	203	13
Investments in unconsolidated affiliates	(395)	(103)	0
Other	11	85	(35)
Net Cash Used by Investing Activities	(1,485)	(2,903)	(2,528)
Cash Flows from Financing Activities
Payment of dividends to preferred and common stockholders	(201)	(196)	(154)
Net receipts from settlement of acquired derivatives that include financing elements	196	9	267
Payment for treasury stock	(437)	(39)	(25)
Sales proceeds and other contributions from noncontrolling interests in subsidiaries	647	819	531
Proceeds from issuance of common stock	1	21	16
Proceeds from issuance of long-term debt	1,004	4,563	1,777
Payment of debt issuance and hedging costs	(21)	(67)	(50)
Payments for short and long-term debt	(1,599)	(3,827)	(935)
Proceeds from (Payments for) Other Financing Activities	(22)	(18)	0
Net Cash (Used)/Provided by Financing Activities	(432)	1,265	1,427
Effect of exchange rate changes on cash and cash equivalents	10	(10)	(2)
Net (Decrease)/Increase in Cash and Cash Equivalents	(598)	(138)	167
Cash and Cash Equivalents at Beginning of Period	2,116	2,254	2,087
Cash and Cash Equivalents at End of Period	1,518	2,116	2,254
Changes in Collateral Deposits Supporting Energy Risk Management Activities	$ (381)	$ 146	$ (47)

Consolidated Statement of Stock

Consolidated Statement of Stockholders' Equity - USD ($) $ in Millions	Total	Common Stock	Additional Paid-In Capital	Retained Earnings/ (Accum-ulated Deficit)	Treasury Stock	Accumulated Other Comprehensive Income/(Loss)	Noncontrolling Interest	NRG Yield
Balance at Dec. 31, 2012	$ 10,269	$ 4	$ 7,587	$ 4,230	$ (1,920)	$ (150)	$ 518
Increase (Decrease) in Stockholders' Equity
Net (loss)/income attributable to NRG Energy, Inc.	(386)
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest	(352)
Other Comprehensive Income (Loss), Net of Tax	155
Equity-based compensation	36		$ 36
Purchase of treasury stock	25				25
Preferred stock dividends	9			9
Common stock dividends	145			145
ESPP share purchases	8			5	3
Proceeds from issuance of common stock	16
Other Preferred Stock Dividends and Adjustments	0
Impact of NRG Yield, Inc. public offering			$ (217)
Noncontrolling Interest, Increase from Subsidiary Equity Issuance	457						240
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	73						73
Balance at Dec. 31, 2013	10,467	4	7,840	3,695	(1,942)	5	865
Increase (Decrease) in Stockholders' Equity
Net (loss)/income attributable to NRG Energy, Inc.	134
Net income/(loss) attributable to noncontrolling interest	17
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest	151
Other Comprehensive Income (Loss), Net of Tax	(189)					(179)
Issuance of shares for acquisition of EME	401		401
Noncontrolling Interest, Increase from Business Combination	352						352
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	(57)
Equity-based compensation	45		45
Purchase of treasury stock	44				44
Preferred stock dividends	(9)			9
Common stock dividends	181			181
ESPP share purchases	(1)			(4)	3
Proceeds from issuance of common stock	21		41				(41)	$ 0
Other Preferred Stock Dividends and Adjustments	(47)			(47)
Non-cash adjustment for issuance of convertible debt	23						23
Noncontrolling Interest, Increase from Subsidiary Equity Issuance	630						630
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	125						125
Balance at Dec. 31, 2014	11,676	4	8,327	3,588	(1,983)	(174)	1,914
Increase (Decrease) in Stockholders' Equity
Net (loss)/income attributable to NRG Energy, Inc.	(6,382)
Net income/(loss) attributable to noncontrolling interest							(37)
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest	(6,419)
Other Comprehensive Income (Loss), Net of Tax	1					1
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Noncontrolling Interest							(4)
Other Comprehensive Income (Loss), Including OCI for NCI	(3)
Sale of Assets Under Common Control			(56)				83	27
Noncontrolling Interest, Increase from Business Combination							74	$ 74
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	(159)
Equity-based compensation	24		26	(2)
Purchase of treasury stock	437				437
Preferred stock dividends	(20)			20
Common stock dividends	191			191
ESPP share purchases	6		(1)		7
Noncontrolling Interest, Contributions from Noncontrolling Interest Holders	234						234
Proceeds from issuance of common stock	1
Other Preferred Stock Dividends and Adjustments	0
Non-cash adjustment for issuance of convertible debt	23						23
Noncontrolling Interest, Increase from Subsidiary Equity Issuance	599						599
Balance at Dec. 31, 2015	$ 5,434	$ 4	$ 8,296	$ (3,007)	$ (2,413)	$ (173)	$ 2,727

Nature of Business

Nature of Business	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Business	Nature of Business General NRG Energy, Inc., or NRG or the Company, is an integrated competitive power company, which produces, sells and delivers energy and energy products and services in major competitive power markets in the U.S. while positioning itself as a leader in the way residential, industrial and commercial consumers think about and use energy products and services. NRG has one of the nation's largest and most diverse competitive generation portfolios balanced with the nation's largest competitive retail energy business. The Company owns and operates approximately 50,000 MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the names “NRG”, "Reliant" and other retail brand names owned by NRG. The following table summarizes NRG's global generation portfolio as of December 31, 2015 : Global Generation Portfolio (a) (In MW) NRG Business Generation Type Gulf Coast East West NRG Home Solar (b) NRG Renew (c) NRG Yield (d) Total Domestic Other (Inter-national) Total Global Natural gas (e) 8,651 7,876 6,085 — — 1,879 24,491 144 24,635 Coal (f) 5,114 10,122 — — — — 15,236 605 15,841 Oil (g) — 5,581 — — — 190 5,771 — 5,771 Nuclear 1,176 — — — — — 1,176 — 1,176 Wind — — — — 1,061 2,005 3,066 — 3,066 Utility Scale Solar — — — — 845 482 1,327 — 1,327 Distributed Solar — — — 93 60 9 162 — 162 Total generation capacity 14,941 23,579 6,085 93 1,966 4,565 51,229 749 51,978 Capacity attributable to noncontrolling interest — — — — (638 ) (2,053 ) (2,691 ) — (2,691 ) Total net generation capacity 14,941 23,579 6,085 93 1,328 2,512 48,538 749 49,287 (a) Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units. (b) Includes the aggregate production capacity of installed and activated residential solar energy systems. Also includes capacity from operating portfolios of residential solar assets held by RPV Holdco, a partnership between NRG Home Solar and NRG Yield, Inc. (c) Includes Distributed Solar capacity from assets held by DGPV Holdco, a partnership between NRG Renew DG Holdings LLC and NRG Yield, Inc. (d) Does not include NRG Yield, Inc.'s thermal converted (MWt) capacity, which is part of the NRG Yield operating segment. (e) Natural gas generation portfolio does not include: 463 MW related to Osceola, which was mothballed on January 1, 2015; 636 MW related to Coolwater, which was retired on January 1, 2015; 16 MW related to SD Jets Kearny 1, which was deactivated in March 2015; 160 MW related to Glen Gardner, which was retired on May 1, 2015; 98 MW related to Gilbert, which was retired on May 1, 2015; 335 MW related to El Segundo 4, which was deactivated on December 31, 2015; and 60 MW related to SD Jets Kearny 2A-2D, which were deactivated on December 31, 2015. (f) Coal generation portfolio does not include: 251 MW related to Will County, which was retired on April 15, 2015; 597 MW related to Shawville, which was mothballed on May 31, 2015; 575 MW related to Big Cajun Unit 2, which was converted to natural gas in July 2015; 401 MW related to Portland, which was deactivated on December 1, 2015; and 75 MW related to Dunkirk 2, which was mothballed on December 31, 2015. (g) Oil generation portfolio does not include 212 MW related to Werner, which was retired on May 1, 2015. NRG Business consists of the Company’s wholesale operations, commercial operations, EPC operations, energy services and other critical related functions. NRG has traditionally referred to this business as its wholesale power generation business. In addition to the traditional functions from NRG’s wholesale power generation business, NRG Business also includes NRG’s B2B solutions, which include demand response, commodity sales, energy efficiency and energy management services, and NRG’s conventional distributed generation business, consisting of reliability, combined heat and power, thermal and district heating and cooling and large-scale distributed generation. NRG Home is a consumer facing business that includes the Company’s residential retail business and NRG’s residential solar business. Products and services range from retail energy, rooftop solar, portable solar and battery products home services, and a variety of bundled products which combine energy with protection products, energy efficiency and renewable energy solutions. As of December 31, 2015 , NRG's retail businesses within NRG Home and NRG Business served approximately 2.77 million Recurring customers and approximately 624,000 Discrete customers. NRG Renew operates the Company’s existing renewables business, including operation of the NRG Yield renewable assets. NRG Renew is also one of the largest solar and wind power developers and owner-operators in the U.S., having developed, constructed and financed a full range of solutions for utilities, schools, municipalities and commercial market segments. NRG was incorporated as a Delaware corporation on May 29, 1992. NRG's common stock is listed on the New York Stock Exchange under the symbol "NRG". The Company's principal executive offices are located at 211 Carnegie Center, Princeton, New Jersey 08540. NRG is dual headquartered, with financial and commercial headquarters in Princeton, New Jersey and operational headquarters in Houston, Texas. NRG's telephone number is (609) 524-4500. The address of the Company's website is www.nrg.com . NRG's recent annual reports, quarterly reports, current reports, and other periodic filings are available free of charge through the Company's website. NRG Yield, Inc. Ownership In 2013, the Company formed NRG Yield, Inc. to own and operate a portfolio of contracted generation assets and thermal infrastructure assets that have historically been owned and/or operated by NRG and its subsidiaries. In 2013 and 2014, NRG Yield, Inc. issued Class A common stock to its public shareholders and utilized the proceeds to acquire a controlling interest in NRG Yield LLC, through its ownership of Class A units. At that time, the Company owned the Class B common stock of NRG Yield, Inc. and the Class B units of NRG Yield LLC. On May 14, 2015, NRG Yield, Inc. completed a stock split in connection with which each outstanding share of Class A common stock was split into one share of Class A common stock and one share of Class C common stock, and each outstanding share of Class B common stock was split into one share of Class B common stock and one share of Class D common stock. A similar split was effected at NRG Yield LLC with respect to its member units. The Company consolidates NRG Yield, Inc. for financial reporting purposes as it maintains a controlling voting interest, and presents the public ownership of the Class A and Class C common stock as noncontrolling interest. The Company receives distributions from NRG Yield LLC, through its ownership of Class B and Class D units. The following table represents the structure of NRG Yield, Inc. as of December 31, 2015 :

Summary of Significant Accounti

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation The Company's consolidated financial statements have been prepared in accordance with U.S. GAAP. The ASC, established by the FASB, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants. The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a VIE, should be consolidated. Segment Reporting Effective in December 2014, the Company's segment structure and its allocation of corporate expenses were updated to reflect how management makes financial decisions and allocates resources. The Company has recast data from prior periods to reflect this change in reportable segments to conform to the current year presentation. The Company's businesses are segregated as follows: NRG Business, which includes conventional power generation, the carbon capture business and energy services; NRG Home, which includes NRG Home Retail consisting of residential retail services and products, and NRG Home Solar, which includes the installation and leasing of residential solar services; NRG Renew, which includes solar and wind assets, excluding those in the NRG Yield and NRG Home Solar segments; NRG Yield and corporate activities. NRG Yield includes certain of the Company's contracted generation assets. The Company's corporate segment includes BETM, international business and electric vehicle services. Cash and Cash Equivalents Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase. Funds Deposited by Counterparties Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Some amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities. Changes in funds deposited by counterparties are closely associated with the Company's operating activities and are classified as an operating activity in the Company's consolidated statements of cash flows. Restricted Cash Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use. Of these funds, approximately $45 million is designated for current debt service payments, $61 million is designated to fund operating expenses, and $21 million is designated to fund distributions, with the remaining $287 million restricted for reserves including debt service, performance obligations and other reserves, as well as capital expenditures. Trade Receivables and Allowance for Doubtful Accounts Trade receivables are reported in the balance sheet at outstanding principal adjusted for any write-offs and the allowance for doubtful accounts. For its retail business, the Company accrues an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings (for commercial and industrial customers), historical collections, accounts receivable aging and other factors. The retail business writes-off accounts receivable balances against the allowance for doubtful accounts when it determines a receivable is uncollectible. Inventory Inventory is valued at the lower of weighted average cost or market, and consists principally of fuel oil, coal and raw materials used to generate electricity or steam. The Company removes these inventories as they are used in the production of electricity or steam. Spare parts inventory is valued at a weighted average cost. The Company removes these inventories when they are used for repairs, maintenance or capital projects. The Company expects to recover the fuel oil, coal, raw materials, and spare parts costs in the ordinary course of business. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows. Finished goods inventory is valued at the lower of cost or net realizable value with cost being determined on a first-in first-out basis. The Company removes these inventories as they are sold to customers. During the year ended December 31, 2015 , the Company recorded a lower of weighted average cost or market adjustment of $19 million related to fuel oil. Property, Plant and Equipment Property, plant and equipment are stated at cost or, in the case of business acquisitions, fair value; however impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. See Note 3 , Business Acquisitions and Dispositions , for more information on acquired property, plant and equipment. NRG also classifies nuclear fuel related to the Company's 44% ownership interest in STP as part of the Company's property, plant, and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation other than nuclear fuel is computed using the straight-line method, while nuclear fuel is amortized based on units of production over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of operations. Asset Impairments Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the statements of operations. Fair values are determined by a variety of valuation methods, including third-party appraisals, sales prices of similar assets and present value techniques. Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-Equity Method and Joint Ventures , or ASC 323, which requires that a loss in value of an investment that is other than a temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value. For further discussion of these matters, refer to Note 10 , Asset Impairments . Development Activity Expenses and Capitalized Interest Development activity expenses include project development costs, which are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including, among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset. When a project is available for operations, capitalized project development costs are reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable. Development activity expenses also include selling, general, and administrative expenses associated with the current operations of certain developing businesses including residential solar, electric vehicles, waste-to-energy, carbon capture and other emerging technologies. The revenue associated with these businesses was immaterial for the years ended December 31, 2015 , 2014 , and 2013 . When it is determined that a business will remain an ongoing part of the Company's operations or when operating revenues become material relative to the operating costs of the underlying business, the Company no longer classifies a business as a development activity. Beginning in 2014, the Company no longer classifies costs associated with residential solar or carbon capture as development activity expenses. Interest incurred on funds borrowed to finance capital projects is capitalized until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2015 , 2014 , and 2013 , was $30 million , $29 million , and $64 million , respectively. When a project is available for operations, capitalized interest and project development costs are reclassified to property, plant and equipment and depreciated on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable. Debt Issuance Costs Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt. As discussed below, as of December 31, 2015, the Company adopted ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, and reclassified debt issuance costs to be presented as a direct deduction from the carrying amount of the related debt in both the current and prior periods. Intangible Assets Intangible assets represent contractual rights held by NRG. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, marketing partnerships, power purchase agreements, trade names, emission allowances, and fuel contracts when specific rights and contracts are acquired. In addition, NRG also established values for emission allowances and power contracts upon adoption of Fresh Start reporting. These intangible assets are amortized based on expected volumes, expected delivery, expected discounted future net cash flows, straight line or units of production basis. Intangible assets determined to have indefinite lives are not amortized, but rather are tested for impairment at least annually or more frequently if events or changes in circumstances indicate that such acquired intangible assets have been determined to have finite lives and should now be amortized over their useful lives. NRG had no intangible assets with indefinite lives recorded as of December 31, 2015 . Emission allowances held-for-sale, which are included in other non-current assets on the Company's consolidated balance sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360. Goodwill In accordance with ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed. NRG performs goodwill impairment tests annually, during the fourth quarter, and when events or changes in circumstances indicate that the carrying value may not be recoverable. The Company first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. In the absence of sufficient qualitative factors, goodwill impairment is determined using a two step process: Step one — Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two. Step two — Compare the implied fair value of the reporting unit's goodwill to the book value of the reporting unit goodwill. If the book value of goodwill exceeds the implied fair value, an impairment charge is recognized for the excess. For further discussion of goodwill and goodwill impairment losses recognized during 2015, refer to Note 11 , Goodwill and Other Intangibles . Income Taxes NRG accounts for income taxes using the liability method in accordance with ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences. NRG has two categories of income tax expense or benefit — current and deferred, as follows: • Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and • Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income. NRG reports some of the Company's revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. NRG measures the Company's deferred income tax assets and deferred income tax liabilities using income tax rates that are currently in effect. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets, net of valuation allowances. In arriving at this conclusion to utilize projections of future profit before tax in its estimate of future taxable income, the Company considered the profit before tax generated in recent years. A valuation allowance is recorded to reduce the Company's net deferred tax assets to an amount that is more-likely-than-not to be realized. NRG reduces its current income tax expense in the consolidated statement of operations for any investment tax credits, or ITCs, that are not convertible into cash grants, as well as other tax credits, in the period the tax credit is generated. ITCs that are convertible into cash grants, as well as the deferred income tax benefit generated by the difference in the financial statement and tax basis of the related assets, are recorded as a reduction to the carrying value of the underlying property and subsequently amortized to earnings on a straight-line basis over the useful life of each underlying property. The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense. In accordance with ASC 805 and as discussed further in Note 19 , Income Taxes , changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax expense. Revenue Recognition Energy — Both physical and financial transactions are entered into to optimize the financial performance of NRG's generating facilities. Electric energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. Financial transactions, or the buying and selling of energy for trading purposes, are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815. Capacity — Capacity revenues are recognized when contractually earned, and consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements. Sale of Emission Allowances — NRG records the Company's bank of emission allowances as part of the Company's intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of usage from the Company's emission bank to intangible assets held-for-sale for trading purposes. NRG records the sale of emission allowances on a net basis within operating revenue in the Company's consolidated statements of operations. Contract Amortization — Assets and liabilities recognized from power sales agreements assumed at Fresh Start and through acquisitions related to the sale of electric capacity and energy in future periods for which the fair value has been determined to be significantly less (more) than market are amortized to revenue over the term of each underlying contract based on actual generation and/or contracted volumes. Retail revenues — Gross revenues for energy sales and services to retail customers are recognized upon delivery under the accrual method. Energy sales and services that have been delivered but not billed by period end are estimated. Gross revenues also includes energy revenues from resales of purchased power, which were $165 million , $387 million and $166 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. These revenues represent the sale of excess supply to third parties in the market. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed. NRG recorded receivables for unbilled revenues of $309 million , $341 million and $356 million as of December 31, 2015 , 2014 , and 2013 , respectively, for retail energy sales and services. Consumer product revenues are recognized when title and risk of loss pass to the retailer, distributor, or end-customer and when all of the following have occurred: a firm sales agreement is in place, delivery has occurred, pricing is fixed and determinable, and collection is reasonably assured. Revenue is recognized as the net amount expected to be received after deducting estimated amounts for product returns, discounts, and allowances based on historical return rates and reasonable judgment. Lessor Accounting Certain of the Company’s revenues are obtained through PPAs or other contractual agreements. It was determined that certain of these PPAs qualify as operating leases for which the Company is the operating lessor and are accounted for in accordance with ASC 840, Leases . In order to determine lease classification as operating, the Company evaluates the terms of the PPA to determine if the lease includes any of the following provisions which would indicate capital lease treatment: • Transfers the ownership of the generating facility, • Bargain purchase option at the end of the term of the lease, • Lease term is greater than 75% of the economic life of the generating facility, or • Present value of minimum lease payments exceeds 90% of the fair value of the generating facility at inception of the lease. In considering the above it was determined that many of the Company’s PPAs are operating leases. ASC 840 requires the minimum lease payments received to be amortized over the term of the lease and contingent rentals are recorded when the achievement of the contingency becomes probable. Certain of these leases have no minimum lease payments and all of the rent is recorded as contingent rent on an actual basis when the electricity is delivered. Judgment is required by management in determining the economic life of each generating facility, in evaluating whether certain lease provisions constitute minimum payments or represent contingent rent and other factors in determining whether a contract contains a lease and whether the lease is an operating lease or capital lease. Contingent rental income recognized in the years ended December 31, 2015 , 2014 , and 2013 was $777 million , $544 million , and $260 million , respectively. Gross Receipts and Sales Taxes In connection with its retail business, the Company records gross receipts taxes on a gross basis in revenues and cost of operations in its consolidated statements of operations. During the years ended December 31, 2015 , 2014 , and 2013 , NRG's revenues and cost of operations included gross receipts taxes of $110 million , $108 million , and $88 million , respectively. Additionally, the retail business records sales taxes collected from its taxable customers and remitted to the various governmental entities on a net basis; thus, there is no impact on the Company's consolidated statement of operations. Cost of Energy for Retail Operations The cost of energy for electricity sales and services to retail customers is included in cost of operations and is based on estimated supply volumes for the applicable reporting period. A portion of the cost of energy ( $85 million , $86 million and $90 million as of December 31, 2015 , 2014 , and 2013 , respectively) was accrued and consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities. In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees are estimated using the same method used for electricity sales and services to retail customers. In addition, ISO fees are estimated based on historical trends, estimated supply volumes and initial ERCOT ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period. Derivative Financial Instruments NRG accounts for derivative financial instruments under ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value unless they qualify for a NPNS exception. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as hedges, if elected for hedge accounting, are either: • Recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments; or • Deferred and recorded as a component of accumulated OCI until the hedged transactions occur and are recognized in earnings. NRG's primary derivative instruments are power purchase or sales contracts, fuels purchase contracts, other energy related commodities, and interest rate instruments used to mitigate variability in earnings due to fluctuations in market prices and interest rates. On an ongoing basis, NRG assesses the effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. Internal analyses that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such a contract designated as a hedge. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. In this case, the gain or loss previously deferred in accumulated OCI would be frozen until the underlying hedged instrument is delivered unless the transactions being hedged are no longer probable of occurring in which case the amount in OCI would be immediately reclassified into earnings. If the derivative instrument is terminated, the effective portion of this derivative deferred in accumulated OCI will be frozen until the underlying hedged item is delivered. Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings. NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings. Foreign Currency Translation and Transaction Gains and Losses The local currencies are generally the functional currency of NRG's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the Company's statements of operations for the period, but are accumulated and reported as a separate component of stockholders' equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign currency transaction gains or losses are reported within other income/(expense) in the Company's statements of operations. For the years ended December 31, 2015 , 2014 , and 2013 , amounts recognized as foreign currency transaction gains (losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2015 , 2014 , and 2013 were $(10) million , $1 million and $15 million , respectively. Concentrations of Credit Risk Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of trust funds, accounts receivable, notes receivable, derivatives, and investments in debt securities. Trust funds are held in accounts managed by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling agreements. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See Note 4 , Fair Value of Financial Instruments , for a further discussion of derivative concentrations. Fair Value of Financial Instruments The carrying amount of cash and cash equivalents, funds deposited by counterparties, receivables, accounts payable, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. See Note 4 , Fair Value of Financial Instruments , for a further discussion of fair value of financial instruments. Asset Retirement Obligations NRG accounts for AROs in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made. Upon initial recognition of a liability for an ARO, NRG capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. See Note 13 , Asset Retirement Obligations , for a further discussion of AROs. Pensions and Other Postretirement Benefits NRG offers pension benefits through a defined benefit pension plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. NRG accounts for pension and other postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits. NRG recognizes the funded status of the Company's defined benefit plans in the statement of financial position and records an offset for gains and losses as well as all prior service costs that have not been included as part of the Company's net periodic benefit cost to other comprehensive income. The determination of NRG's obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. NRG's actuarial consultants determine assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company. NRG measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Stock-Based Compensation NRG accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock Compensation, or ASC 718 . The fair value of the Company's non-qualified stock options and performance units are estimated on the date of grant using the Black-Scholes option-pricing model and the Monte Carlo valuation model, respectively. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's restricted stock units and deferred stock units. Forfeiture rates are estimated based on an analysis of NRG's historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award. Investments Accounted for by the Equity Method NRG has investments in various domestic energy projects, as well as one Australian project. The equity method of accountin

Business Acquisitions and Dispo

Business Acquisitions and Dispositions (Notes)	12 Months Ended
	Dec. 31, 2015
Business Acquisitions and Dispositions [Abstract]
Business Acquisitions and Dispositions	Business Acquisitions and Dispositions The Company has completed the following business acquisitions and dispositions that are material to the Company's financial statements: Acquisitions 2015 Acquisition of Desert Sunlight On June 29, 2015, NRG Yield, Inc., through its subsidiary Yield Operating, acquired 25% of the membership interest in Desert Sunlight Investment Holdings, LLC, which owns two solar photovoltaic facilities that total 550 MW located in Desert Center, California from EFS Desert Sun, LLC, an affiliate of GE Energy Financial Services, for a purchase price of $285 million . The Company accounts for its 25% investment as an equity method investment. 2014 Acquisition of Alta Wind On August 12, 2014, NRG Yield, Inc., through its subsidiary Yield Operating, completed the acquisition of 100% of the membership interests of Alta Wind Asset Management Holdings, LLC, Alta Wind Company, LLC, Alta Wind X Holding Company, LLC, and Alta Wind XI Holding Company, LLC, which collectively own seven wind facilities that total 947 MW located in Tehachapi, California and a portfolio of land leases, or the Alta Wind Assets. Power generated by the Alta Wind facility is sold to Southern California Edison under long-term power purchase agreements with 21 years of remaining contract life for Alta I-V. The Alta X and XI power purchase agreements began in January 2016 with terms of 22 years and currently sell energy and renewable energy credits on a merchant basis. The purchase price of the Alta Wind Assets was $923 million , which was comprised of a purchase price of $870 million and $53 million paid for working capital balances. In order to fund the purchase price of the acquisition, NRG Yield, Inc. issued 12,075,000 shares of its Class A common stock on July 29, 2014 for net proceeds of $630 million . In addition, on August 5, 2014, Yield Operating issued $500 million in aggregate principal amount at par of 5.375% senior notes due August 2024. Interest on the notes is payable semi-annually on February 15 and August 15 of each year, and commenced on February 15, 2015. The notes are senior unsecured obligations of Yield Operating and are guaranteed by NRG Yield LLC, Yield Operating’s parent company, and by certain of Yield Operating’s wholly owned subsidiaries. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The accounting for the business combination was completed as of August 11, 2015, at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of December 31, 2015, as well as adjustments made through August 11, 2015, when the allocation became final. The purchase price of $923 million was allocated as follows: Acquisition Date Fair Value at December 31, 2014 Measurement period adjustments Revised Acquisition Date (In millions) Assets Cash $ 22 — $ 22 Current and non-current assets 49 (2 ) 47 Property, plant and equipment 1,304 6 1,310 Intangible assets 1,177 (6 ) 1,171 Total assets acquired 2,552 (2 ) 2,550 Liabilities Debt 1,591 — 1,591 Current and non-current liabilities 38 (2 ) 36 Total liabilities assumed 1,629 (2 ) 1,627 Net assets acquired $ 923 $ — $ 923 2014 Acquisition of Dominion's Competitive Electric Retail Business On March 31, 2014, the Company acquired the competitive retail electricity business of Dominion Resources, Inc., or Dominion. The acquisition of Dominion's competitive retail electricity business increased NRG’s retail portfolio by approximately 540,000 customers in the aggregate by the end of 2014. The acquisition supports NRG's ongoing efforts to expand the Company's retail footprint in the Northeast and to grow its retail position in Texas. The Company paid approximately $192 million as cash consideration for the acquisition, including $165 million of purchase price and $27 million paid for working capital balances, which was funded by cash on hand. The purchase price was allocated to the following: $40 million to accounts receivable-trade, $64 million to customer relationships, $9 million to trade names, $14 million to current assets, $21 million to derivative assets, $47 million to current and non-current liabilities, and goodwill of $91 million of which $8 million is deductible for U.S. income tax purposes in future periods. The consideration and assets include amounts paid for customer relationships in the Northeast that were accounted for as an asset acquisition. The factors that resulted in goodwill arising from the acquisition include the revenues associated with new customers in new regions and through the synergies associated with combining a new retail business with the Company's existing retail and generation assets. The acquired assets and liabilities are included within the NRG Home Retail segment. The accounting for the Dominion acquisition was completed as of March 30, 2015, at which point the provisional fair values became final with no material changes. 2014 Acquisition of EME On April 1, 2014, the Company acquired substantially all of the assets of EME. EME, through its subsidiaries and affiliates, owned or leased and operated a portfolio of approximately 8,000 MW consisting of wind energy facilities and coal- and gas-fired generating facilities. The Company paid an aggregate purchase price of $3.5 billion , which was funded through the issuance of 12,671,977 shares of NRG common stock on April 1, 2014, the issuance of $700 million in newly-issued corporate debt, as described in Note 12 , Debt and Capital Leases , and cash on hand. The Company also assumed non-recourse debt of approximately $1.2 billion . In connection with the transaction, NRG agreed to certain conditions with the parties to the Powerton and Joliet, or POJO, sale-leaseback transaction subject to which an NRG subsidiary assumed the POJO leveraged leases and NRG guaranteed the remaining payments under each lease, which total $405 million through 2034. In connection with this agreement, NRG has committed to fund up to $350 million in capital expenditures for plant modifications at Powerton and Joliet to comply with environmental regulations, as discussed further in Note 24, Environmental Matters . On April 30, 2014, subsequent to the acquisition, the Company acquired the remaining 50% ownership of Mission Del Sol LLC, which owns the Sunrise facility, a 586 MW natural gas facility in Fellows, California, from Chevron Power Holdings Inc. increasing the Company's ownership interest to 100% in exchange for the Company's 50% interest in six cogeneration facilities, previously co-owned with Chevron Power Holdings Inc. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The accounting for the EME acquisition was completed as of March 31, 2015, at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of December 31, 2014, as well as adjustments made through March 31, 2015, when the allocation became final. Measurement period adjustments primarily reflect the tax impact of the acquisition date fair values and final estimates for asset retirement obligations. The purchase price of $3.5 billion was allocated as follows: Acquisition Date Fair Value at December 31, 2014 Measurement period adjustments Revised Acquisition Date (In millions) Assets Cash 1,422 — $ 1,422 Current assets 724 72 796 Property, plant and equipment 2,438 (3 ) 2,435 Intangible assets 172 — 172 Goodwill 334 (56 ) 278 Non-current assets 773 — 773 Total assets acquired 5,863 13 5,876 Liabilities Current and non-current liabilities 629 13 642 Out-of-market contracts and leases 159 — 159 Long-term debt 1,249 — 1,249 Total liabilities assumed 2,037 13 2,050 Less: noncontrolling interest 352 — 352 Net assets acquired $ 3,474 $ — $ 3,474 2013 Acquisition of Energy Systems On December 31, 2013, NRG Energy Center Omaha Holdings, LLC, an indirect wholly owned subsidiary of NRG Yield LLC, acquired 100% of Energy Systems Company, or Energy Systems, for approximately $120 million . The acquisition was financed from cash on hand. Energy Systems is an operator of steam and chilled thermal facilities that provides heating and cooling services to nonresidential customers in Omaha, Nebraska. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The purchase price was primarily allocated to property, plant and equipment of $60 million , customer relationships of $59 million , and working capital of $1 million . The accounting for Energy Systems was completed as of September 30, 2014, at which point the provisional fair values became final with no material changes. 2013 Acquisition of Gregory On August 7, 2013, NRG Texas Gregory, LLC, a wholly owned subsidiary of NRG, acquired Gregory Power Partners, L.P. for approximately $245 million in cash, net of $32 million cash acquired. Gregory is a cogeneration plant located in Corpus Christi, Texas, which has generation capacity of 388 MW and steam capacity of 160 MWt. The Gregory cogeneration plant provides steam, processed water and a small percentage of its electrical generation to the Corpus Christi Sherwin Alumina plant. The majority of the plant's generation is available for sale in the ERCOT market. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The purchase price was allocated to property, plant, and equipment of $248 million , current assets of $13 million , and other liabilities of $16 million . The accounting for the Gregory acquisition was completed as of June 30, 2014, at which point the provisional fair values became final with no material changes. Dispositions 2016 Disposition of Shelby On November 9, 2015, the Company, through its subsidiary GenOn, Inc., entered into an agreement with Rockland Power Partners II, LP to sell 100% of its interest in Shelby County Energy Center, LLC, or Shelby, for cash consideration of $46 million . Shelby owns a 352 MW natural gas-fired facility located in Illinois. At December 31, 2015, NRG had $1 million of current assets, $22 million of non-current assets, and $1 million of current liabilities classified as held for sale for Shelby on its balance sheet. The sale is expected to be completed in March of 2016, and the transaction is expected to result in a gain recognized recorded in the consolidated results of operations during the first quarter of 2016. 2016 Disposition of Seward On November 24, 2015, the Company, through its subsidiary GenOn, Inc., entered into an agreement with Robindale Energy Services, Inc. to sell 100% of its interest in Seward Generation, LLC, or Seward, for cash consideration of $75 million . Seward owns a 525 MW coal-fired facility in Pennsylvania. The transaction triggered an impairment indicator as the sale price was less than the carrying amount of the assets, and, as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sale price. The Company recorded an impairment loss of $134 million for the year ended December 31, 2015, to reduce the carrying amount of the assets held for sale to the fair market value. At December 31, 2015, NRG had $5 million of current assets, $83 million of non-current assets, $1 million of current liabilities and $4 million of non-current liabilities classified as held for sale for Seward on its balance sheet. On February 2, 2016, GenOn completed the sale of Seward. For further discussion on this impairment, refer to Note 10 — Asset Impairments . 2015 Disposition of Altenex On December 31, 2015, the Company completed the sale of its 32% interest in Altenex, LLC to Edison Energy, LLC and Edison Energy NewCo 2, LLC for cash consideration of $26 million . The Company had accounted for its investment in Altenex as an equity method investment and recognized a loss of $14 million as a result of the transaction within the Company's consolidated statements of operations. 2014 Sale of Sabine On December 2, 2014, the Company, through its subsidiaries GenOn Sabine (Delaware), Inc. and GenOn Sabine (Texas), Inc., completed the sale of its 50% interest in Sabine Cogen, L.P., or Sabine, to Bayou Power, LLC, an affiliate of Rockland Capital, LLC. Sabine owns a 105 MW natural gas-fired cogeneration facility located in Texas. The Company received cash consideration of $35 million at closing. A gain of $18 million was recognized as a result of the transaction and recorded as a gain on sale of equity-method investments within the Company's consolidated statements of operations. 2014 Disposition of 50% Interest in Petra Nova Parish Holdings LLC On July 3, 2014, the Company, through its wholly owned subsidiary Petra Nova Holdings LLC, sold 50% of its interest in Petra Nova Parish Holdings LLC to JX Nippon Oil Exploration (EOR) Limited, or JX Nippon, a wholly owned subsidiary of JX Nippon Oil & Gas Exploration Corporation. As a result of the sale, the Company no longer has a controlling interest in and has deconsolidated Petra Nova Parish Holdings LLC as of the date of the sale. On July 7, 2014, the Company made its initial capital contribution into the partnership of $35 million , which was funded with a portion of the sale proceeds of $76 million . On March 3, 2014, Petra Nova CCS I LLC, a wholly owned subsidiary of Petra Nova Parish Holdings LLC, entered into a fixed-price agreement to build and operate a CCF at the W.A. Parish facility with a consortium of Mitsubishi Heavy Industries America, Inc. and TIC - The Industrial Company. Notice to proceed for the construction on the CCF was issued on July 15, 2014, and commercial operation is expected in late 2016. Petra Nova Parish Holdings LLC also owns a 75 MW peaking unit at W.A. Parish, which achieved commercial operations on June 26, 2013. The peaking unit will be converted into a cogeneration facility to provide power and steam to the CCF. The CCF is being financed by: (i) up to $167 million from a U.S. DOE CCPI grant of which $7 million has already been received from the grant in the initial design and engineering phase and $106 million has already been received from the grant under the construction phase, (ii) $250 million in loans provided by the Japan Bank for International Cooperation and Mizuho Bank, Ltd., and (iii) approximately $300 million in equity contributions from each of the Company and JX Nippon. The Company’s contribution will include investments already made during the development of the project. In February 2016, Petra Nova Parish Holdings LLC received notice of an additional $23 million in U.S. DOE funding. On July 14, 2014, Petra Nova Parish Holdings LLC entered into two credit facilities, or the Petra Nova Parish Credit Agreements, to fund the cost of construction of the CCF at the W.A. Parish facility. The Petra Nova Parish Credit Agreements are comprised of a $75 million Nippon Export and Investment Insurance, or NEXI, covered loan and a $175 million Japan Bank for International Cooperation, or JBIC, facility. The NEXI covered loan has an interest rate of LIBOR plus an applicable margin of 1.75% and the JBIC facility has an interest rate of LIBOR plus an applicable margin of 0.50% during the construction phase which escalates to an applicable margin of 1.50% upon completion of the CCF. Both credit facilities mature in April 2026. NRG has guaranteed its 50% share of the obligations under the Petra Nova Parish Credit Agreements through mechanical completion as defined by the credit agreements. Transfers of Assets under Common Control On November 3, 2015, the Company sold 75% of the Class B interests of NRG Wind TE Holdco, which owns a portfolio of 12 wind facilities totaling 814 net MW, to NRG Yield, Inc. NRG Yield Inc. paid total cash consideration of $209 million , subject to working capital adjustments. NRG Yield, Inc. will be responsible for its pro-rata share of non-recourse project debt of $193 million and noncontrolling interest associated with a tax equity structure of $159 million (as of the acquisition date). In February 2016, the company made a final working capital payment of $2 million to NRG Yield, Inc. reducing total cash consideration to $207 million . On January 2, 2015, the Company sold the following facilities to NRG Yield, Inc.: Walnut Creek, the Tapestry projects (Buffalo Bear, Pinnacle and Taloga) and Laredo Ridge. NRG Yield, Inc. paid total cash consideration of $489 million , including $9 million of working capital adjustments, plus assumed project level debt of $737 million . On June 30, 2014, the Company sold the following facilities to NRG Yield, Inc.: High Desert, Kansas South, and El Segundo Energy Center. NRG Yield, Inc. paid total cash consideration of $357 million , which represents a base purchase price of $349 million and $8 million of working capital adjustments, plus assumed project level debt of approximately $612 million . The above sales were recorded as transfers of entities under common control and the related assets were transferred at their carrying value.

Fair Value of Financial Instrum

Fair Value of Financial Instruments (Notes)	12 Months Ended
	Dec. 31, 2015
Fair Value of Financial Instruments Disclosure [Abstract]
Fair Value of Financial Instruments	Fair Value of Financial Instruments For cash and cash equivalents, funds deposited by counterparties, accounts and other receivables, accounts payable, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy. The estimated carrying values and fair values of NRG's recorded financial instruments not carried at fair market value are as follows: As of December 31, 2015 2014 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Assets Notes receivable (a) $ 73 $ 73 $ 91 $ 91 Liabilities Long-term debt, including current portion (b) 19,620 18,263 20,366 20,361 (a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets. (b) Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets. The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. The fair value of debt securities, non publicly-traded long-term debt, and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy. Fair Value Accounting under ASC 820 ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: • Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG's financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments. • Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG's financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over the counter derivatives such as swaps, options and forward contracts. • Level 3 — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date. NRG's financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models. In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety. Recurring Fair Value Measurements Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value. The following tables present assets and liabilities measured and recorded at fair value on the Company's consolidated balance sheets on a recurring basis and their level within the fair value hierarchy: As of December 31, 2015 Fair Value Level 1 Level 2 Level 3 Total (In millions) Investment in available-for-sale securities (classified within other non-current assets): Debt securities $ — $ — $ 17 $ 17 Available-for-sale securities 9 — — 9 Other (a) 14 — — 14 Nuclear trust fund investments: Cash and cash equivalents 6 — — 6 U.S. government and federal agency obligations 54 1 — 55 Federal agency mortgage-backed securities — 59 — 59 Commercial mortgage-backed securities — 25 — 25 Corporate debt securities — 81 — 81 Equity securities 280 — 54 334 Foreign government fixed income securities — 1 — 1 Other trust fund investments: U.S. government and federal agency obligations 1 — — 1 Derivative assets: Commodity contracts 622 1,449 149 2,220 Total assets $ 986 $ 1,616 $ 220 $ 2,822 Derivative liabilities: Commodity contracts $ 868 $ 1,036 $ 182 $ 2,086 Interest rate contracts — 128 — 128 Total liabilities $ 868 $ 1,164 $ 182 $ 2,214 (a) Consists primarily of mutual funds held in a rabbi trust for non-qualified deferred compensation plans for some key and highly compensated employees and a total return swap that does not meet the definition of a derivative. As of December 31, 2014 Fair Value Level 1 Level 2 Level 3 Total (In millions) Investment in available-for-sale securities (classified within other non-current assets): Debt securities $ — $ — $ 18 $ 18 Available-for-sale securities 30 — — 30 Other (a) 21 — 11 32 Nuclear trust fund investments: Cash and cash equivalents 14 — — 14 U.S. government and federal agency obligations 44 3 — 47 Federal agency mortgage-backed securities — 74 — 74 Commercial mortgage-backed securities — 25 — 25 Corporate debt securities — 78 — 78 Equity securities 292 — 52 344 Foreign government fixed income securities — 3 — 3 Other trust fund investments: U.S. government and federal agency obligations 1 — — 1 Derivative assets: Commodity contracts 1,078 1,515 309 2,902 Interest rate contracts — 2 — 2 Equity contracts — — 1 1 Total assets $ 1,480 $ 1,700 $ 391 $ 3,571 Derivative liabilities: Commodity contracts $ 1,004 $ 1,093 $ 230 $ 2,327 Interest rate contracts — 165 — 165 Total liabilities $ 1,004 $ 1,258 $ 230 $ 2,492 (a) Primarily consists of mutual funds held in a rabbi trusts for non-qualified deferred compensation plans for certain former employees and a total return swap that does not meet the definition of a derivative. There have been no transfers during the year ended December 31, 2015 , between Levels 1 and 2. The following tables reconcile, for the years ended December 31, 2015 , and 2014 , the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs: For the Year Ended December 31, 2015 Fair Value Measurement Using Significant Unobservable Inputs (Level 3) Debt Securities Other Trust Fund Investments Derivatives (a) Total (In millions) Beginning balance as of January 1, 2015 $ 18 $ 11 $ 52 $ 80 $ 161 Total losses realized/unrealized: Included in earnings (1 ) (11 ) — (100 ) (112 ) Included in nuclear decommissioning obligations — — (2 ) — (2 ) Purchases — — 4 (19 ) (15 ) Transfers into Level 3 (b) — — — 3 3 Transfers out of Level 3 (b) — — — 3 3 Ending balance as of December 31, 2015 $ 17 $ — $ 54 $ (33 ) $ 38 Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of December 31, 2015 $ — $ — $ — $ (30 ) $ (30 ) (a) Consists of derivatives assets and liabilities, net. (b) Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2. For the Year Ended December 31, 2014 Fair Value Measurement Using Significant Unobservable Inputs (Level 3) Debt Securities Other Trust Fund Investments Derivatives (a) Total (In millions) Beginning balance as of January 1, 2014 $ 16 $ 10 $ 56 $ 13 $ 95 Total gains/(losses) realized/unrealized: Included in OCI 2 — — — 2 Included in earnings — 1 — (24 ) (23 ) Included in nuclear decommissioning obligations — — (5 ) — (5 ) Purchases — — 2 49 51 Contracts acquired in Dominion and EME acquisitions — — — 39 39 Sales — — (1 ) — (1 ) Transfers into Level 3 (b) — — — 2 2 Transfer out of Level 3 (b) — — — 1 1 Ending balance as of December 31, 2014 $ 18 $ 11 $ 52 $ 80 $ 161 Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of December 31, 2014 $ — $ — $ — $ 20 $ 20 (a) Consists of derivatives assets and liabilities, net. (b) Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2. Realized and unrealized gains and losses included in earnings that are related to the energy derivatives are recorded in operating revenues and cost of operations. Non-derivative fair value measurements NRG's investments in debt securities are classified as Level 3 and consist of non-traded debt instruments that are valued based on third-party market value assessments. The trust fund investments are held primarily to satisfy NRG's nuclear decommissioning obligations. These trust fund investments hold debt and equity securities directly and equity securities indirectly through commingled funds. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. In addition, U.S. government and federal agency obligations are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of corporate debt securities are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized in Level 2. Certain equity securities, classified as commingled funds, are analogous to mutual funds, are maintained by investment companies, and hold certain investments in accordance with a stated set of fund objectives. The fair value of the equity securities classified as commingled funds are based on net asset values per fund share (the unit of account), derived from the quoted prices in active markets of the underlying equity securities. However, because the shares in the commingled funds are not publicly quoted, not traded in an active market and are subject to certain restrictions regarding their purchase and sale, the commingled funds are categorized in Level 3. See also Note 6 , Nuclear Decommissioning Trust Fund . Derivative fair value measurements A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company's prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote, then the mid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of the Company's derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate those transactions and the Company believes such price quotes are executable. The Company does not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities represents contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up 7% of derivative assets and 8% of derivative liabilities. The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk, which for interest rate swaps is calculated utilizing the bilateral method based on published default probabilities. For commodities, to the extent that NRG's net exposure under a specific master agreement is an asset, the Company uses the counterparty's default swap rate. If the exposure under a specific master agreement is a liability, the Company uses NRG's default swap rate. For interest rate swaps and commodities, the credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG's liabilities or that a market participant would be willing to pay for NRG's assets. As of December 31, 2015 , the credit reserve resulted in a $5 million increase in fair value which is composed of a $2 million gain in OCI and a $3 million gain in operating revenue and cost of operations. As of December 31, 2014 the credit reserve resulted in a $2 million increase in fair value which is reflected as a gain in OCI. The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2015 , and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material. NRG's significant positions classified as Level 3 include physical and financial power and physical coal executed in illiquid markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power and coal location pricing which is derived as a basis to liquid locations. The basis spread is based on observable market data when available or derived from historic prices and forward market prices from similar observable markets when not available. For FTRs, NRG uses the most recent auction prices to derive the fair value. The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of December 31, 2015 , and December 31, 2014 : Significant Unobservable Inputs December 31, 2015 Fair Value Input/Range Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average (In millions) Power Contracts $ 86 $ 100 Discounted Cash Flow Forward Market Price (per MWh) $ 10 $ 92 $ 27 Coal Contracts — 12 Discounted Cash Flow Forward Market Price (per ton) 28 45 35 FTRs 63 70 Discounted Cash Flow Auction Prices (per MWh) (98 ) 87 — $ 149 $ 182 Significant Unobservable Inputs December 31, 2014 Fair Value Input/Range Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average (In millions) Power Contracts $ 195 $ 154 Discounted Cash Flow Forward Market Price (per MWh) $ 15 $ 92 $ 47 Coal Contracts 3 1 Discounted Cash Flow Forward Market Price (per ton) 53 56 54 FTRs 111 75 Discounted Cash Flow Auction Prices (per MWh) (29 ) 30 — $ 309 $ 230 The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of December 31, 2015 , and December 31, 2014 : Significant Unobservable Input Position Change In Input Impact on Fair Value Measurement Forward Market Price Power/Coal Buy Increase/(Decrease) Higher/(Lower) Forward Market Price Power/Coal Sell Increase/(Decrease) Lower/(Higher) FTR Prices Buy Increase/(Decrease) Higher/(Lower) FTR Prices Sell Increase/(Decrease) Lower/(Higher) Under the guidance of ASC 815, entities may choose to offset cash collateral paid or received against the fair value of derivative positions executed with the same counterparties under the same master netting agreements. The Company has chosen not to offset positions as defined in ASC 815. As of December 31, 2015 , the Company recorded $568 million of cash collateral paid and $106 million of cash collateral received on its balance sheet. Concentration of Credit Risk In addition to the credit risk discussion as disclosed in Note 2 , Summary of Significant Accounting Policies , the following item is a discussion of the concentration of credit risk for the Company's financial instruments. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle. Counterparty Credit Risk As of December 31, 2015 , counterparty credit exposure, excluding credit risk exposure under certain long-term agreements, was $ 969 million and NRG held collateral (cash and letters of credit) against those positions of $240 million , resulting in a net exposure of $733 million . Approximately 97% of the Company's exposure before collateral is expected to roll off by the end of 2017 . Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables. Category Net Exposure (a) (% of Total) Financial institutions 47 % Utilities, energy merchants, marketers and other 36 ISOs 17 Total 100 % Category Net Exposure (a) (% of Total) Investment grade 96 % Non-Investment grade 2 Non-Rated 2 Total 100 % (a) Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices. NRG has counterparty credit risk exposure to certain counterparties, each of which represent more than 10% of total net exposure discussed above. The aggregate of such counterparties' exposure was $247 million . Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any of NRG's counterparties. Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, Gulf Coast load obligations, wind and solar PPAs, and a coal supply agreement. As external sources or observable market quotes are not available to estimate such exposure, the Company values these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of December 31, 2015 , aggregate credit risk exposure managed by NRG to these counterparties was approximately $3.7 billion , including $2.7 billion related to assets of NRG Yield, Inc., for the next five years. This amount excludes potential credit exposures for projects with long term PPAs that have not reached commercial operations. The majority of these power contracts are with utilities or public power entities with strong credit quality and public utility commission or other regulatory support. However, such regulated utility counterparties can be impacted by changes in government regulations, which NRG is unable to predict. In the case of the coal supply agreement, NRG holds a lien against the underlying asset which significantly reduces the risk of loss. Retail Customer Credit Risk NRG is exposed to retail credit risk through the Company's retail electricity providers, which serve C&I customers and the Mass market. Retail credit risk results when a customer fails to pay for services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio and the use of credit mitigation measures such as deposits or prepayment arrangements. As of December 31, 2015 , the Company's retail customer credit exposure to C&I and Mass customers was diversified across many customers and various industries, as well as government entities. The Company is also subject to risk with respect to its NRG Home Solar customers. The Company's bad debt expense was $64 million , $64 million , and $67 million for the years ending December 31, 2015 , 2014 , and 2013 , respectively. Current economic conditions may affect the Company's customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense.

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities (Notes)	12 Months Ended
	Dec. 31, 2015
Accounting for Derivative Instruments and Hedging Activities Disclosure [Abstract]
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities ASC 815 requires NRG to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a NPNS exception. NRG may elect to designate certain derivatives as cash flow hedges, if certain conditions are met, and defer the effective portion of the change in fair value of the derivatives to accumulated OCI, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings. For derivatives designated as hedges of the fair value of assets or liabilities, the changes in fair value of both the derivative and the hedged transaction are recorded in current earnings. For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 applies to NRG's energy related commodity contracts, interest rate swaps, and equity contracts. As the Company engages principally in the trading and marketing of its generation assets and retail businesses, some of NRG's commercial activities qualify for hedge accounting. In order for the generation assets to qualify, the physical generation and sale of electricity should be highly probable at inception of the trade and throughout the period it is held, as is the case with the Company's baseload plants. For this reason, many trades in support of NRG's baseload units normally qualify for NPNS or cash flow hedge accounting treatment, and trades in support of NRG's peaking units' asset optimization will generally not qualify for hedge accounting treatment, with any changes in fair value likely to be reflected on a mark-to-market basis in the statement of operations. Most of the retail load contracts either qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority of the retail supply and fuels supply contracts are recorded under mark-to-market accounting. All of NRG's hedging and trading activities are subject to limits within the Company's Risk Management Policy. Energy-Related Commodities To manage the commodity price risk associated with the Company's competitive supply activities and the price risk associated with wholesale power sales from the Company's electric generation facilities and retail power sales from NRG's retail businesses, NRG enters into a variety of derivative and non-derivative hedging instruments, utilizing the following: • Forward contracts, which commit NRG to purchase or sell energy commodities or purchase fuels in the future; • Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument; • Swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual, or notional, quantity; • Option contracts, which convey to the option holder the right but not the obligation to purchase or sell a commodity; • Extendable swaps, which include a combination of swaps and options executed simultaneously for different periods. This combination of instruments allows NRG to sell out-year volatility through call options in exchange for natural gas swaps with fixed prices in excess of the market price for natural gas at that time. The above-market swap combined with its later-year call option are priced in aggregate at market at the trade's inception; and • Weather and hurricane derivative products used to mitigate a portion of Reliant Energy's lost revenue due to weather. The objectives for entering into derivative contracts designated as hedges include: • Fixing the price for a portion of anticipated future electricity sales that provides an acceptable return on the Company's electric generation operations; • Fixing the price of a portion of anticipated fuel purchases for the operation of the Company's power plants; and • Fixing the price of a portion of anticipated power purchases for the Company's retail sales. NRG's trading and hedging activities are subject to limits within the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings. As of December 31, 2015 , NRG's derivative assets and liabilities consisted primarily of the following: • Forward and financial contracts for the purchase/sale of electricity and related products economically hedging NRG's generation assets' forecasted output or NRG's retail load obligations through 2021; • Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG's generation assets through 2018; and • Other energy derivatives instruments extending through 2024. Also, as of December 31, 2015 , NRG had other energy-related contracts that did not meet the definition of a derivative instrument or qualified for the NPNS exception and were therefore exempt from fair value accounting treatment as follows: • Load-following forward electric sale contracts extending through 2026; • Power tolling contracts through 2039; • Coal purchase contract through 2018; • Power transmission contracts through 2025; • Natural gas transportation contracts and storage agreements through 2030; and • Coal transportation contracts through 2029. Interest Rate Swaps NRG is exposed to changes in interest rates through the Company's issuance of variable rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of December 31, 2015 , NRG had interest rate derivative instruments on non-recourse debt extending through 2032, the majority of which are designated as cash flow hedges. Volumetric Underlying Derivative Transactions The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of December 31, 2015 , and 2014 . Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date. Total Volume Commodity Units December 31, 2015 December 31, 2014 (In millions) Emissions Short Ton 1 2 Coal Short Ton 35 57 Natural Gas MMBtu 293 (58 ) Oil Barrel 1 1 Power MWh (74 ) (56 ) Capacity MW/Day (1 ) — Interest Dollars $ 2,326 $ 3,440 Equity Shares 1 2 The increase in the natural gas position was primarily the result of additional retail hedges, as well as the settlement of generation hedge positions. The decrease in the interest rate position was primarily the result of settling the Alta X and Alta XI interest rate swaps in connection with the repayment of project-level debt, as described in Note 12, Debt and Capital Leases . Fair Value of Derivative Instruments The following table summarizes the fair value within the derivative instrument valuation on the balance sheet: Fair Value Derivative Assets Derivative Liabilities (In millions) December 31, 2015 December 31, 2014 December 31, 2015 December 31, 2014 Derivatives Designated as Cash Flow or Fair Value Hedges : Interest rate contracts current $ — $ — $ 42 $ 55 Interest rate contracts long-term — 2 68 74 Total Derivatives Designated as Cash Flow or Fair Value Hedges — 2 110 129 Derivatives Not Designated as Cash Flow or Fair Value Hedges : Interest rate contracts current — — 5 8 Interest rate contracts long-term — — 13 28 Commodity contracts current 1,915 2,425 1,674 1,991 Commodity contracts long-term 305 477 412 336 Equity contracts long-term — 1 — — Total Derivatives Not Designated as Cash Flow or Fair Value Hedges 2,220 2,903 2,104 2,363 Total Derivatives $ 2,220 $ 2,905 $ 2,214 $ 2,492 The Company has elected to present derivative assets and liabilities on the balance sheet on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. In addition, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. The following table summarizes the offsetting derivatives by counterparty master agreement level and collateral received or paid: Gross Amounts Not Offset in the Statement of Financial Position Gross Amounts of Recognized Assets/Liabilities Derivative Instruments Cash Collateral (Held)/Posted Net Amount As of December 31, 2015 (In millions) Commodity contracts: Derivative assets $ 2,220 $ (1,616 ) $ (113 ) $ 491 Derivative liabilities (2,086 ) 1,616 271 (199 ) Total commodity contracts 134 — 158 292 Interest rate contracts: Derivative liabilities (128 ) — — (128 ) Total derivative instruments $ 6 $ — $ 158 $ 164 Gross Amounts Not Offset in the Statement of Financial Position Gross Amounts of Recognized Assets/Liabilities Derivative Instruments Cash Collateral (Held)/Posted Net Amount As of December 31, 2014 (In millions) Commodity contracts: Derivative assets $ 2,902 $ (2,155 ) $ (72 ) $ 675 Derivative liabilities (2,327 ) 2,155 27 (145 ) Total commodity contracts 575 — (45 ) 530 Interest rate contracts: Derivative assets 2 (2 ) — — Derivative liabilities (165 ) 2 — (163 ) Total interest rate contracts (163 ) — — (163 ) Equity contracts: Derivative assets 1 — — 1 Total derivative instruments $ 413 $ — $ (45 ) $ 368 Accumulated Other Comprehensive Income The following tables summarize the effects on NRG's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax: Year Ended December 31, 2015 Energy Commodities Interest Rate Total (In millions) Accumulated OCI balance at December 31, 2014 $ (1 ) $ (67 ) $ (68 ) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts 1 14 15 Mark-to-market of cash flow hedge accounting contracts — (48 ) (48 ) Accumulated OCI balance at December 31, 2015, net of $16 tax — (101 ) (101 ) Losses expected to be realized from OCI during the next 12 months, net of $3 tax $ — $ (18 ) $ (18 ) There were no gains or losses recognized in income from the ineffective portion of cash flow hedges for the year ended December 31, 2015 . Year Ended December 31, 2014 Energy Commodities Interest Rate Total (In millions) Accumulated OCI balance at December 31, 2013 $ (1 ) $ (22 ) $ (23 ) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts — 13 13 Mark-to-market of cash flow hedge accounting contracts — (58 ) (58 ) Accumulated OCI balance at December 31, 2014, net of $35 tax $ (1 ) $ (67 ) $ (68 ) There were no gains or losses recognized in income from the ineffective portion of cash flow hedges for the year ended December 31, 2014 . Year Ended December 31, 2013 Energy Commodities Interest Rate Total (In millions) Accumulated OCI balance at December 31, 2012 $ 41 $ (72 ) $ (31 ) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts (51 ) 20 (31 ) Mark-to-market of cash flow hedge accounting contracts 9 30 39 Accumulated OCI balance at December 31, 2013, net of $14 tax $ (1 ) $ (22 ) $ (23 ) There were no gains or losses recognized in income from the ineffective portion of cash flow hedges for the year ended December 31, 2013 . Amounts reclassified from accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to operating revenue for commodity contracts and interest expense for interest rate contracts. Impact of Derivative Instruments on the Statement of Operations Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges and ineffectiveness of hedge derivatives are reflected in current period earnings. The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges, and trading activity on NRG's statement of operations. The effect of commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges is included in interest expense. Year Ended December 31, 2015 2014 2013 (In millions) Unrealized mark-to-market results Reversal of previously recognized unrealized gains on settled positions related to economic hedges $ (275 ) $ (15 ) $ (105 ) Reversal of acquired gain positions related to economic hedges (106 ) (333 ) (357 ) Net unrealized gains on open positions related to economic hedges 9 361 177 Total unrealized mark-to-market (losses)/gains for economic hedging activities (372 ) 13 (285 ) Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity (46 ) 1 (50 ) Reversal of acquired gain positions related to trading activity (14 ) (32 ) — Net unrealized (losses)/gains on open positions related to trading activity (16 ) 45 7 Total unrealized mark-to-market (losses)/gains for trading activity (76 ) 14 (43 ) Total unrealized (losses)/gains $ (448 ) $ 27 $ (328 ) Year Ended December 31, 2015 2014 2013 (In millions) Unrealized (losses)/gains included in operating revenues $ (320 ) $ 515 $ (621 ) Unrealized (losses)/gains included in cost of operations (128 ) (488 ) 293 Total impact to statement of operations — energy commodities $ (448 ) $ 27 $ (328 ) Total impact to statement of operations — interest rate contracts $ 17 $ (31 ) $ 15 The reversal of gain or loss positions acquired as part of acquisitions were valued based upon the forward prices on the acquisition dates. The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in revenue or cost of operations during the same period. For the year ended December 31, 2015 , the $9 million gain from economic hedge positions was primarily the result of an increase in the value of forward sales of electricity due to a decrease in power prices. For the year ended December 31, 2014 , the $361 million gain from economic hedge positions was primarily the result of an increase in the value of forward sales of natural gas due to a decrease in natural gas prices. During 2014, NRG had interest rate swaps designated as cash flow hedges on the Dandan solar project. The notional amount on the swaps exceeded the actual debt draws on the project. As such, NRG discontinued cash flow hedge accounting for these contracts and $6 million of losses previously deferred in OCI was recognized in the statement of operations for the year ended December 31, 2014 . For the year ended December 31, 2013 , the $ 177 million gain from economic hedge positions was primarily the result of an increase in the value of forward sales of natural gas and electricity due to a decrease in forward power and gas prices and an increase in the value of forward purchases of coal due to an increase in forward coal prices. During 2013, NRG had interest rate swaps designated as cash flow hedges on the CVSR solar project. The notional amount on the swaps exceeded the actual debt draws on the project. As such, NRG discontinued cash flow hedge accounting for these contracts and $5 million of losses previously deferred in OCI was recognized in the statement of operations for the year ended December 31, 2013 . Credit Risk Related Contingent Features Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed "adequate assurance" under the agreements, or require the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts that have adequate assurance clauses that are in net liability positions as of December 31, 2015 , was $204 million . The collateral required for contracts with credit rating contingent features that are in a net liability position as of December 31, 2015 , was $34 million . The Company is also a party to certain marginable agreements under which it has a net liability position, but the counterparty has not called for the collateral due, which was approximately $3 million as of December 31, 2015 . See Note 4 , Fair Value of Financial Instruments , for discussion regarding concentration of credit risk.

Nuclear Decommissioning Trust F

Nuclear Decommissioning Trust Fund (Notes)	12 Months Ended
	Dec. 31, 2015
Nuclear Decommissioning Trust Fund Disclosure [Abstract]
Nuclear Decommissioning Trust Fund	Nuclear Decommissioning Trust Fund NRG's Nuclear Decommissioning Trust Fund assets, which are for the decommissioning of STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. Although NRG is responsible for managing the decommissioning of its 44% interest in STP, the predecessor utilities that owned STP are authorized by the PUCT to collect decommissioning funds from their ratepayers to cover decommissioning costs on behalf of NRG. NRC requirements determine the decommissioning cost estimate which is the minimum required level of funding. In the event that funds from the ratepayers that accumulate in the nuclear decommissioning trust are ultimately determined to be inadequate to decommission the STP facilities, the utilities will be required to collect through rates charged to rate payers all additional amounts, with no obligation from NRG, provided that NRG has complied with PUCT rules and regulations regarding decommissioning trusts. Following completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective ratepayers of the utilities. NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations , or ASC 980, because the Company's nuclear decommissioning activities are subject to approval by the PUCT, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust Liability and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment. The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities. As of December 31, 2015 As of December 31, 2014 (In millions, except otherwise noted) Fair Value Unrealized Gains Unrealized Losses Weighted- average maturities (in years) Fair Value Unrealized Gains Unrealized Losses Weighted- average maturities (in years) Cash and cash equivalents $ 6 $ — $ — — $ 14 $ — $ — — U.S. government and federal agency obligations 55 1 — 11 47 2 — 11 Federal agency mortgage-backed securities 59 1 — 25 74 2 — 25 Commercial mortgage-backed securities 25 — 2 28 25 — 1 30 Corporate debt securities 81 1 1 10 78 2 1 11 Equity securities 334 199 — — 344 211 — — Foreign government fixed income securities 1 — — 9 3 1 — 16 Total $ 561 $ 202 $ 3 $ 585 $ 218 $ 2 The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined using the specific identification method. Year Ended December 31, 2015 2014 2013 (In millions) Realized gains $ 21 $ 29 $ 25 Realized losses 14 8 8 Proceeds from sale of securities 631 600 488

Inventory (Notes)

Inventory (Notes)	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Inventory	Inventory Inventory consisted of: As of December 31, 2015 2014 (In millions) Fuel oil $ 312 $ 375 Coal/Lignite 471 414 Natural gas 12 16 Spare parts 437 424 Other 20 18 Total Inventory $ 1,252 $ 1,247 During the year ended December 31, 2015, the Company recorded a lower of weighted average cost or market adjustment related to fuel oil of $19 million .

Notes Receivable (Notes)

Notes Receivable (Notes)	12 Months Ended
	Dec. 31, 2015
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Capital Leases and Notes Receivable	Notes Receivable Notes receivable consist of fixed and variable rate notes related primarily to amounts owed to the Company from transmission owners for certain projects for the financing of network upgrades. NRG's notes receivable were as follows: As of December 31, 2015 2014 (In millions) Notes receivable $ 73 $ 91 Less current maturities (a) 20 19 Total notes receivable — noncurrent $ 53 $ 72 (a) The current portion of notes receivable is recorded in prepayments and other current assets on the consolidated balance sheets.

Property, Plant and Equipment (

Property, Plant and Equipment (Notes)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment NRG's major classes of property, plant, and equipment were as follows: As of December 31, Depreciable 2015 2014 Lives (In millions) Facilities and equipment $ 22,676 $ 27,457 1-40 Years Land and improvements 1,226 1,194 Nuclear fuel 545 490 5 Years Office furnishings and equipment 462 346 2-10 Years Construction in progress 627 770 Total property, plant, and equipment 25,536 30,257 Accumulated depreciation (6,804 ) (7,890 ) Net property, plant, and equipment $ 18,732 $ 22,367 The Company recorded long-lived asset impairments during 2015, as further described in Note 10, Asset Impairments.

Asset Impairments (Notes)

Asset Impairments (Notes)	12 Months Ended
	Dec. 31, 2015
Asset Impairment Charges [Abstract]
Asset Impairments	Asset Impairments 2015 Impairment Losses Seward — As described in Note 3, Business Acquisitions and Dispositions , on November 24, 2015, the Company entered into an agreement with Robindale Energy Services, Inc. to sell 100% of its interest in Seward for cash consideration of $75 million . The transaction triggered an impairment indicator as the sale price was less than the carrying amount of the assets, and, as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sale price. The Company recorded an impairment loss of $134 million for the year ended December 31, 2015, to reduce the carrying amount of the assets held for sale to the fair market value. Limestone and W.A. Parish — During the fourth quarter of 2015, as the Company updated its view for long-term prices in connection with the preparation of its annual budget, it was noted that the cash flows for the Limestone and W.A. Parish coal-fired facilities located in Texas were lower than the carrying amount, primarily driven by declining power prices as the cost of commodities continues to decline and the assets were impaired. The fair value of the Limestone and W.A. Parish plants was determined using an income approach by applying a discounted cash flow methodology to the long-term budgets for each respective plant. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, and include key inputs such as forecasted power prices, fuel costs and emissions credit expense, forecasted operating and capital expenditures and discount rates. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets and recognized impairment losses of $1,514 million and $1,295 million related to Limestone and W.A. Parish, respectively. Huntley — On August 25, 2015, the Company filed a notice with the NYSPSC of its intent to retire Huntley's operating units on March 1, 2016. The Company considered this to be an indicator of impairment and performed an impairment test for these assets under ASC 360, Property, Plant and Equipment . On October 14, 2015, the Company filed a cost-of-service filing at FERC in anticipation that the Huntley operating units would be needed for reliability purposes, proposing a reliability must run service agreement for a four-year period beginning on March 1, 2016. On October 30, 2015, NYISO released the results of its reliability study, indicating that the Huntley operating units are not needed for bulk system reliability. The Company considered the impact of the reliability study conducted and evaluated the estimated cash flows associated with the facility. Accordingly, the Company determined that the carrying amount of the assets was higher than the estimated future net cash flows expected to be generated by the assets and that the assets were impaired. The fair value of the Huntley operating units was determined using the income approach. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, and include key inputs such as forecasted contract prices, forecasted operating expenses and discount rates. The Company recorded an impairment loss of $132 million during the year ended December 31, 2015. Dunkirk — The Company signed a ten-year agreement in November 2014 with National Grid to add natural gas-burning capabilities at the Dunkirk facility. On August 25, 2015, NRG announced that Dunkirk Unit 2 would be mothballed on January 1, 2016 at the expiration of its reliability support services agreement. The project to add natural gas-burning capabilities has been suspended, pending the outcome of litigation with respect to the gas addition contract and its validity. On October 30, 2015, NYISO released the results of its reliability study, indicating that the Dunkirk facility is not needed for system reliability. In connection with the planned mothball of the facility, the pending litigation and the latest reliability assessment completed by NYISO, the Company evaluated whether the related fixed assets were impaired. The Company determined that the carrying amount of the assets was higher than the estimated future net cash flows expected to be generated by the assets and that the assets were impaired. The fair value of the Dunkirk facility was determined using the income approach. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, and include key inputs such as forecasted contract prices, forecasted operating and capital expenditures and discount rates. The Company recorded an impairment loss of $160 million during the year ended December 31, 2015. Gregory — During the fourth quarter of 2015, the Company determined that the carrying amount of the assets was higher than the estimated future net cash flows expected to be generated by the assets and that the assets were impaired. The fair value of the Gregory facility was determined using the income approach, which utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, and include key inputs such as forecasted prices, operating and capital expenditures and discount rates. The Company recorded an impairment loss of $176 million during the year ended December 31, 2015. Solar Panels — During the fourth quarter of 2015, the Company recorded an impairment loss of $29 million to reduce the carrying value of certain solar panels to their approximate fair value. Investments — During the fourth quarter of 2015, the Company reviewed certain of its cost method and equity method investments and concluded that losses incurred by these investments were other than temporary. These losses were primarily driven by the sustained decline in stock price of a publicly traded investment as well as change in financing structures of certain non-publicly traded investments. As a result, the Company recorded losses related to these investments of $56 million . 2014 Impairment Losses Coolwater — During the fourth quarter of 2014, the Company determined that it would retire the 636 MW natural-gas fired Coolwater facility in Dagget, California. The facility faced critical repairs on the cooling towers for units 3 and 4 and, during the fourth quarter of 2014, did not receive any awards in a near-term capacity auction and no interest in a bilateral capacity deal. The Company considered this to be an indicator of impairment and performed an impairment test for these assets under ASC 360, Property, Plant and Equipment . The carrying amount of the assets was higher than the future net cash flows expected to be generated by the assets and as a result, the assets are considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets. The Company retired the Coolwater facility effective January 1, 2015. All remaining fixed assets of the station were written off resulting in an impairment loss of $22 million recorded during the fourth quarter of 2014. Osceola — During the third quarter of 2014, the Company determined that it would mothball the 463 MW natural gas-fired Osceola facility, in Saint Cloud, Florida. The Company considered this to be an indicator of impairment and performed an impairment test for these assets under ASC 360, Property, Plant and Equipment . The carrying amount of the assets was higher than the future net cash flows expected to be generated by the assets and as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets. Due to the location of the facility, it was determined that the best indicator of fair value is the market value of the combustion turbines. The Company recorded an impairment loss of approximately $60 million during the third quarter of 2014, which represents the excess of the carrying value over the fair market value. Solar Panels — During the third quarter of 2014, the Company recorded an impairment loss of $10 million to reduce the carrying value of certain solar panels to their approximate fair value. 2013 Impairment Losses Indian River — Annually during the fourth quarter, the Company revises its views of power and fuel prices including the Company's view for long-term prices in connection with the preparation of its annual budget. Changes to the Company’s views of long-term power and fuel prices impacted the Company’s projections of profitability, based on management's estimate of supply and demand within the sub-markets for each plant and the physical and economic characteristics of each plant. The Company's revised views of projected profitability for Indian River resulted in a significant adverse change in the extent to which the assets are expected to be used. As a result, the Company considered this to be an indicator of impairment and performed an impairment test for these assets under ASC 360, Property, Plant and Equipment . The carrying amount of the assets was higher than the future net cash flows expected to be generated by the asset, considering project specific assumptions for long-term power pool prices, escalated future project operating costs and expected plant operations. As a result, the assets were considered to be impaired, and the Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets. The fair value of the assets was determined by factoring in the probability weighting of different courses of action available to the Company and included both an income approach and a market approach. The Company recorded an impairment loss related to Indian River in the fourth quarter of 2013 of $459 million . Gladstone — During the fourth quarter of 2013, the Company reviewed its 37.5% interest in Gladstone for impairment utilizing the other-than-temporary impairment model under ASC 820, Fair Value Measurements , due to future market expectations as well as discussions with the managing joint venture participants regarding the plant's expected life. In determining fair value, the Company utilized an income approach and considered project specific assumptions for future project operating revenues and costs and expected plant operations. The carrying amount of the Company's equity method investment exceeded the fair value of the investment and the Company concluded that the decline is considered to be other than temporary. As a result, the Company measured the impairment loss as the difference between the carrying amount and fair value of the investment and recorded an impairment loss in the fourth quarter of 2013 of $92 million .

Goodwill and Other Intangibles

Goodwill and Other Intangibles (Notes)	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Other Intangibles	Goodwill and Other Intangibles Goodwill NRG's goodwill balance was $999 million as of December 31, 2015 , and $2.6 billion as of December 31, 2014 . The Company initially recorded approximately $1.7 billion of goodwill in connection with the acquisition of Texas Genco in 2006. The Company recorded $144 million of goodwill in connection with the 2010 acquisition of Green Mountain Energy, and $29 million in connection with the 2011 acquisition of Energy Plus. The Company recorded $278 million of goodwill in connection with the 2014 acquisition of EME, which is discussed further in Note 3 , Business Acquisitions and Dispositions . During the year ended December 31, 2015 , the Company recorded goodwill impairment charges of $1.5 billion , the details of which are discussed below. As of December 31, 2015 , and 2014 , NRG had approximately $620 million and $831 million , respectively, of goodwill that is deductible for U.S. income tax purposes in future periods. NRG Texas — In connection with the annual impairment assessment, the Company performed step one of the two-step impairment test for the NRG Texas reporting unit, for which $1.7 billion of goodwill was recognized as part of the Texas Genco acquisition in 2006. The Company determined the fair value of the NRG Texas reporting unit primarily using an income approach through which the Company applied a discounted cash flow methodology to the long-term budgets for all plants in the regions. Significant inputs impacting the income approach include the Company's views of power and fuel prices for the first five-year period and the Company's view for the longer term, which were finalized in connection with the preparation of the fourth quarter financial statements, projected generation based on an hourly dispatch meant to simulate the dispatch of each unit into the power market which is impacted by power prices, fuel prices, and the physical and economic characteristics of each plant, intangible value to NRG Texas for synergies it provides to NRG's retail businesses, and the discount rate applied to cash flow projections. Under step one, the estimated fair value of the NRG Texas invested capital was 76% below its carrying value as of December 31, 2015, and the Company concluded step two was required. Based on the results of step two of the impairment test, the Company determined the carrying amount of the reporting unit was higher than the fair value, and accordingly, the Company recognized an impairment loss of $1.4 billion as of December 31, 2015. NRG Home Solar — The Company performed the two-step impairment test as part of its annual impairment testing for the NRG Home Solar reporting unit utilizing an income approach developed through applying a discounted cash flow methodology to the long-term budget for the reporting unit. As a result, the Company determined that the carrying value of the reporting unit was higher than the fair value, and accordingly, the Company recognized an impairment loss of $125 million during the year ended December 31, 2015 to reduce the carrying value of the goodwill that was recognized in connection with acquisitions made by NRG Home Solar. Goal Zero — During the third quarter of 2015, the Company agreed to relieve the Goal Zero seller of all known and unknown claims in return for the seller's agreement to forego all contingent consideration. Concurrently, the Company determined that there was an indication of goodwill impairment and performed an impairment test . The carrying amount of the reporting unit was higher than the fair value, and accordingly, the Company recognized an impairment loss of $36 million during the third quarter of 2015 to reduce the carrying value of the goodwill that was recognized in connection with the acquisition. Intangible Assets The Company's intangible assets as of December 31, 2015 , primarily reflect intangible assets established with the acquisitions of various companies and are comprised of the following: • Emission Allowances — These intangibles primarily consist of SO 2 and NO x emission allowances established with the 2012 GenOn acquisition and 2006 Texas Genco acquisition and also include RGGI emission credits which NRG began purchasing in 2009. These emission allowances are held-for-use and are amortized to cost of operations, with NO x allowances amortized on a straight-line basis and SO 2 allowances and RGGI credits amortized based on units of production. • Energy supply contracts — Established with the acquisitions of Reliant Energy and Green Mountain Energy, these represent the fair value at the acquisition date of in-market contracts for the purchase of energy to serve retail electric customers. The contracts are amortized to cost of operations based on the expected delivery under the respective contracts. • In-market fuel (gas and nuclear) contracts — These intangibles were established with the Texas Genco acquisition in 2006 and are amortized to cost of operations over expected volumes over the life of each contract. • Customer contracts — Established with the acquisitions of Reliant Energy, Green Mountain Energy, and Northwind Phoenix , these intangibles represent the fair value at the acquisition date of contracts that primarily provide electricity to Reliant Energy's and Green Mountain Energy's C&I customers. These contracts are amortized to revenues based on expected volumes to be delivered for the portfolio. • Customer relationships — These intangibles represent the fair value at the acquisition date of acquired businesses' customer base, primarily for Dominion, Energy Alternatives, Energy Plus, Reliant Energy, Green Mountain Energy, Energy Systems and Energy Curtailment Specialists. The customer relationships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year. • Marketing partnerships — Established with the acquisition of Energy Plus, these intangibles represent the fair value at the acquisition date of existing agreements with loyalty and affinity partners. The marketing partnerships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year. • Trade names — Established with the Reliant Energy, Green Mountain, Energy Plus and Dominion acquisitions, these intangibles are amortized to depreciation and amortization expense, on a straight-line basis. • Power purchase agreements — Established predominantly with the EME and Alta Wind acquisitions, these represent the fair value of PPAs acquired. These will be amortized to revenues, generally on a straight-line basis, over the term of the PPA. • Other — Consists of renewable energy credits, wind leasehold rights, costs to extend the operating license for STP Units 1 and 2, and the intangible asset related to a purchased ground lease. The following tables summarize the components of NRG's intangible assets subject to amortization: Contracts Year Ended December 31, 2015 Emission Allowances Energy Supply Fuel Customer Customer Relationships Marketing Partnerships Trade Names PPA Other Total (In millions) January 1, 2015 $ 1,018 $ 54 $ 72 $ 16 $ 831 $ 88 $ 353 $ 1,269 $ 268 $ 3,969 Purchases 77 — — — 3 — — — 57 137 Usage (33 ) — — — — — — — (62 ) (95 ) Write-off of fully amortized balances (154 ) — — — — — — — — (154 ) Impairment — — — — — — (6 ) — (5 ) (11 ) Other 12 — — — — — (5 ) (6 ) (12 ) (11 ) December 31, 2015 920 54 72 16 834 88 342 1,263 246 3,835 Less accumulated amortization (a) (502 ) (47 ) (65 ) (6 ) (624 ) (41 ) (137 ) (75 ) (28 ) (1,525 ) Net carrying amount $ 418 $ 7 $ 7 $ 10 $ 210 $ 47 $ 205 $ 1,188 $ 218 $ 2,310 (a) Adjusted for write-off of fully amortized emissions allowances of $154 million . Contracts Year Ended December 31, 2014 Emission Allowances Energy Supply Fuel Customer Customer Relationships Marketing Partnerships Trade Names PPA Other Total (In millions) January 1, 2014 $ 871 $ 54 $ 72 $ 859 $ 743 $ 88 $ 318 $ 14 $ 98 $ 3,117 Purchases 141 — — — 8 — — — 33 182 Acquisition of businesses 12 — — — 80 — 35 1,252 162 1,541 Usage — — — — — — — — (34 ) (34 ) Write-off of fully amortized balances — — — (843 ) — — — — — (843 ) Other (6 ) — — — — — — 3 9 6 December 31, 2014 1,018 54 72 16 831 88 353 1,269 268 3,969 Less accumulated amortization (a) (557 ) (42 ) (63 ) (4 ) (557 ) (27 ) (114 ) (25 ) (13 ) (1,402 ) Net carrying amount $ 461 $ 12 $ 9 $ 12 $ 274 $ 61 $ 239 $ 1,244 $ 255 $ 2,567 (a) Adjusted for write-off of fully amortized customer contracts of $843 million . The following table presents NRG's amortization of intangible assets for each of the past three years: Years Ended December 31, Amortization 2015 2014 2013 (In millions) Emission allowances $ 99 $ 124 $ 104 Energy supply contracts 5 6 6 Fuel contracts 2 2 2 Customer contracts 2 — 53 Customer relationships 67 70 72 Marketing partnerships 14 15 8 Trade names 23 21 29 Power purchase agreements 50 24 1 Other 15 6 4 Total amortization $ 277 $ 268 $ 279 The following table presents estimated amortization of NRG's intangible assets for each of the next five years: Contracts Year Ended December 31, Emission Allowances Energy Supply Fuel Customer Customer Relationships Marketing Partnerships Trade Names PPA Other Total 2016 $ 112 $ 7 $ 2 $ 1 $ 48 $ 9 $ 23 $ 63 $ 10 $ 275 2017 53 — 1 1 33 5 23 63 10 189 2018 48 — — 1 20 5 23 63 10 170 2019 32 — — 1 16 4 23 63 9 148 2020 17 — — 1 14 4 23 63 7 129 Intangible assets held for sale — From time to time, management may authorize the transfer from the Company's emission bank of emission allowances held-for-use to intangible assets held-for-sale. Emission allowances held-for-sale are included in other non current assets on the Company's consolidated balance sheet and are not amortized, but rather expensed as sold. As of December 31, 2015 , the value of emission allowances held-for-sale is $22 million and is managed within the Corporate segment. Once transferred to held-for-sale, these emission allowances are prohibited from moving back to held-for-use. Out-of-market contracts — Due primarily to business acquisitions, NRG acquired certain out-of-market contracts, which are classified as non-current liabilities on NRG's consolidated balance sheet. These include out-of-market lease contracts of $159 million and $790 million acquired in the acquisitions of EME and GenOn, respectively, and out-of-market gas transportation and storage contracts of $327 million acquired in the acquisition of GenOn. These out-of-market contracts are amortized to cost of operations. The following table summarizes the estimated amortization related to NRG's out-of-market contracts: Year Ended December 31, Power Contracts Leases Gas Transportation Total (In millions) 2016 $ 16 47 $ 42 $ 105 2017 16 47 37 100 2018 16 47 32 95 2019 17 47 29 93 2020 17 47 29 93

Debt and Capital Leases (Notes)

Debt and Capital Leases (Notes)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt and Capital Leases	Debt and Capital Leases Long-term debt and capital leases consisted of the following: As of December 31, December 31, 2015 2015 2014 Interest Rate % (a) (In millions except rates) NRG Recourse Debt: Senior notes, due 2018 $ 1,039 $ 1,130 7.625 Senior notes, due 2020 1,058 1,063 8.250 Senior notes, due 2021 1,128 1,128 7.875 Senior notes, due 2022 1,100 1,100 6.250 Senior notes, due 2023 936 990 6.625 Senior notes, due 2024 904 1,000 6.250 Term loan facility, due 2018 1,964 1,983 L+2.00 Tax Exempt Bonds 455 406 4.125 - 6.00 Subtotal NRG Recourse Debt 8,584 8,800 NRG Non-Recourse Debt: GenOn senior notes 1,956 2,133 7.875 - 9.875 GenOn Americas Generation senior notes 752 929 8.500 - 9.125 GenOn Other 56 60 Subtotal GenOn debt (non-recourse to NRG) 2,764 3,122 Yield Operating LLC Senior Notes, due 2024 500 500 5.375 Yield LLC and Yield Operating LLC Revolving Credit Facility, due 2019 306 — L+2.75 Yield Inc. Convertible Senior Notes, due 2019 330 326 3.500 Yield Inc. Convertible Senior Notes, due 2020 266 — 3.250 El Segundo Energy Center, due 2023 485 506 L+1.625 - L+2.25 Marsh Landing, due 2017 and 2023 418 464 L+1.75 - L+1.875 Alta Wind I-V lease financing arrangements, due 2034 and 2035 1,002 1,036 5.696 - 7.015 Alta Wind X, due 2021 — 300 L+2.00 Alta Wind XI, due 2021 — 191 L+2.00 Walnut Creek, term loans due 2023 351 391 L+1.625 Tapestry, due 2021 181 192 L+1.625 Laredo Ridge, due 2028 104 108 L+1.875 Alpine, due 2022 154 163 L+1.750 Energy Center Minneapolis, due 2017, and 2025 108 121 5.95 - 7.25 Viento, due 2023 189 196 L+2.75 Yield Other 469 489 various Subtotal Yield debt (non-recourse to NRG) 4,863 4,983 Ivanpah, due 2033 and 2038 1,149 1,183 2.285 - 4.256 Agua Caliente, due 2037 879 898 2.395 - 3.633 CVSR, due 2037 793 815 2.339 - 3.775 Dandan, due 2033 98 54 L+2.25 Peaker bonds, due 2019 72 100 L+1.07 Cedro Hill, due 2025 103 111 L+3.125 NRG Other 315 300 various Subtotal other NRG non-recourse debt 3,409 3,461 Subtotal all non-recourse debt 11,036 11,566 Subtotal long-term debt (including current maturities) 19,620 20,366 Capital leases: Home Solar capital leases 13 — various Chalk Point capital lease, due 2015 — 5 8.190 Other 3 3 various Subtotal long-term debt and capital leases (including current maturities) 19,636 20,374 Less current maturities 481 474 Less debt issuance costs (b) $ 172 $ 199 Total long-term debt and capital leases $ 18,983 $ 19,701 (a) As of December 31, 2015 , L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Marsh Landing term loan, Walnut Creek loan, and Yield Operating LLC Revolving Credit facility, which are 1 month LIBOR plus x% (b) Total net debt reflects the reclassification of deferred financing costs to reduce long-term debt as further described in Note 2, Summary of Significant Accounting Policies . Long-term debt includes the following premiums/(discounts): As of December 31, 2015 2014 (in millions) Term loan facility, due 2018 (a) $ (3 ) $ (4 ) Peaker bonds, due 2019 (b) (4 ) (6 ) Yield, Inc. Convertible notes, due 2019 (15 ) (19 ) Yield, Inc. Convertible notes, due 2020 (21 ) — GenOn senior notes, due 2017 (c) 23 41 GenOn senior notes, due 2018 (c) 59 83 GenOn senior notes, due 2020 (c) 44 60 GenOn Americas Generation senior notes, due 2021 (c) 32 46 GenOn Americas Generation senior notes, due 2031 (c) 25 33 Total premium/(discount) $ 140 $ 234 (a) Discount of $1 million is related to current maturities in 2015 and 2014 . (b) Discount of $2 million are related to current maturities in 2015 and 2014 . (c) Premiums for long-term debt acquired in the GenOn acquisition represent adjustments to record the debt at fair value in connection with the acquisition. Consolidated Annual Maturities Annual payments based on the maturities of NRG's debt and capital leases, for the years ending after December 31, 2015 , are as follows: (In millions) 2016 $ 484 2017 1,153 2018 4,008 2019 1,052 2020 2,288 Thereafter 10,511 Total $ 19,496 NRG Recourse Debt Senior Notes 2015 Senior Notes Repurchases During the fourth quarter of 2015, the Company repurchased $246 million in aggregate principal of the following outstanding Senior Notes in the open market for $231 million , including accrued interest. Principal Repurchased Average Early Redemption Percentage Gain/(Loss) on Debt Extinguishment Amount in millions, except rates 8.25% Senior Note, due 2020 $ 5 96.500 % $ — 6.625% Senior Note, due 2023 54 85.972 % 7 6.25% Senior Note, due 2024 95 84.725 % 14 7.625% Senior Note, due 2018 92 102.232 % (2 ) Total $ 246 $ 19 Issuance of 2022 Senior Notes On January 27, 2014, NRG issued $1.1 billion in aggregate principal amount at par of 6.25% senior notes due 2022. The notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is payable semi-annually beginning on July 15, 2014, until the maturity date of July 15, 2022. The proceeds were utilized to redeem the 8.5% and 7.625% 2019 Senior Notes, as described below, and to fund the acquisition of EME. Issuance of 2024 Senior Notes On April 21, 2014, NRG issued $1.0 billion in aggregate principal amount at par of 6.25% senior notes due 2024. The notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is payable semi-annually beginning on November 1, 2014, until the maturity date of November 1, 2024. A portion of the cash proceeds were used to redeem all remaining of its 7.625% 2019 Senior Notes, and the rest of the proceeds were used to redeem all remaining $225 million of its 8.5% 2019 Senior Notes in September 2014, as discussed below. 2014 Senior Notes Redemptions In 2014, the Company redeemed $1.4 billion in aggregate principal of its Senior Notes, due 2019 for $1.5 billion , including accrued interest. Principal Redeemed Average Early Redemption Percentage Loss on Debt Extinguishment Amount in millions, except rates 8.5% Senior Note, due 2019 $ 607 105.764 % $ 45 7.625% Senior Note, due 2019 800 104.169 % 41 Total $ 1,407 $ 86 Senior Notes Outstanding As of December 31, 2015 , NRG had six outstanding issuances of senior notes, or Senior Notes: (i.) 8.250% senior notes, issued August 20, 2010 and due September 1, 2020, or the 2020 Senior Notes; (ii.) 7.625% senior notes, issued January 26, 2011 and due January 15, 2018, or the 2018 Senior Notes; (iii.) 7.875% senior notes, issued May 24, 2011 and due May 15, 2021, or the 2021 Senior Notes; (iv.) 6.625% senior notes, issued September 24, 2012 and due March 15, 2023, or the 2023 Senior Notes; (v.) 6.250% senior notes, issued January 27, 2014 and due July 15, 2022, or the 2022 Senior Notes; and (vi.) 6.250% senior notes, issued April 21, 2014 and due May 1, 2024 or the 2024 Senior Notes. The Company periodically enters into supplemental indentures for the purpose of adding entities under the Senior Notes as guarantors. The indentures and the form of notes provide, among other things, that the Senior Notes will be senior unsecured obligations of NRG. The indentures also provide for customary events of default, which include, among others: nonpayment of principal or interest; breach of other agreements in the indentures; defaults in failure to pay certain other indebtedness; the rendering of judgments to pay certain amounts of money against NRG and its subsidiaries; the failure of certain guarantees to be enforceable; and certain events of bankruptcy or insolvency. Generally, if an event of default occurs, the Trustee or the Holders of at least 25% in principal amount of the then outstanding series of Senior Notes may declare all of the Senior Notes of such series to be due and payable immediately. The terms of the indentures, among other things, limit NRG's ability and certain of its subsidiaries' ability to return capital to stockholders, grant liens on assets to lenders and incur additional debt. Interest is payable semi-annually on the Senior Notes until their maturity dates. 2018 Senior Notes Prior to maturity, NRG may redeem all or a portion of the 2018 Senior Notes at a redemption price equal to 100% of the principal amount of the notes redeemed plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note or (ii) the excess of the present value of the principal amount at maturity plus all required interest payments due on the note through the maturity date discounted at a Treasury rate plus 0.50%. 2020 Senior Notes NRG may redeem some or all of the 2020 Senior Notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: Redemption Period Redemption Percentage On or after September 1, 2015 104.125 % On or after September 1, 2016 102.750 % On or after September 1, 2017 101.375 % September 1, 2018 and thereafter 100.000 % 2021 Senior Notes Prior to May 15, 2016, NRG may redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.875% of the principal amount. Prior to May 15, 2016, NRG may redeem all or a portion of the 2021 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.938% of the note, plus interest payments due on the note from the date of redemption through May 15, 2016, discounted at a Treasury rate plus 0.50%. In addition, on or after May 15, 2016, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: Redemption Period Redemption Percentage May 15, 2016 to May 14, 2017 103.938 % May 15, 2017 to May 14, 2018 102.625 % May 15, 2018 to May 14, 2019 101.313 % May 15, 2019 and thereafter 100.000 % 2022 Senior Notes At any time prior to July 15, 2017, NRG may redeem up to 35% of the aggregate principal amount of the 2022 Senior Notes, at a redemption price equal to 106.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings. At any time prior to July 15, 2018, NRG may redeem all or a part of the 2022 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.125% of the note, plus interest payments due on the note from the date of redemption through July 15, 2018, computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after July 15, 2018, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: Redemption Period Redemption Percentage July 15, 2018 to July 14, 2019 103.125 % July 15, 2019 to July 14, 2020 101.563 % July 15, 2020 and thereafter 100.000 % 2023 Senior Notes Prior to September 15, 2017, NRG may redeem all or a portion of the 2023 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.313% of the note, plus interest payments due on the note from the date of redemption through September 15, 2017, discounted at a Treasury rate plus 0.50%. In addition, on or after September 15, 2017, NRG may redeem some or all of the 2023 Senior Notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: Redemption Period Redemption Percentage September 15, 2017 to September 14, 2018 103.313 % September 15, 2018 to September 14, 2019 102.208 % September 15, 2019 to September 14, 2020 101.104 % September 15, 2020 and thereafter 100.000 % 2024 Senior Notes At any time prior to May 1, 2017, NRG may redeem up to 35% of the aggregate principal amount of the 2024 Senior Notes, at a redemption price equal to 106.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings. At any time prior to May 1, 2019, NRG may redeem all or a part of the 2024 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.125% of the note, plus interest payments due on the note from the date of redemption through May 1, 2019 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In addition, on or after May 1, 2019, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: Redemption Period Redemption Percentage May 1, 2019 to April 30, 2020 103.125 % May 1, 2020 to April 30, 2021 102.083 % May 1, 2021 to April 30, 2022 101.042 % May 1, 2022 and thereafter 100.000 % Senior Credit Facility On June 4, 2013, NRG amended the Term Loan Facility to (i) obtain additional financing of $450 million , which was issued at a discount of 99.5% ; and (ii) adjust the interest rate from LIBOR plus 2.50% to LIBOR plus 2.00% . Repayments under the Term Loan Facility will consist of 0.25% per quarter, with the remainder due at maturity. The Company also amended the Revolving Credit Facility to (i) increase the capacity by $211 million to a total of $2.5 billion ; (ii) adjust the interest rate to LIBOR plus 2.25% ; and (iii) extend the maturity date to July 1, 2018, to coincide with the maturity date of the Term Loan Facility. As of December 31, 2015 , a total of $1.1 billion of letters of credit were issued under the Revolving Credit Facility, with $1.4 billion remaining available to be issued. Commitment fees of 0.50% are charged on the unused portion of the Revolving Credit Facility. The Senior Credit Facility is guaranteed by substantially all of NRG's existing and future direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries, and certain other subsidiaries, including GenOn and its subsidiaries. The capital stock of these guarantor subsidiaries has been pledged for the benefit of the Senior Credit Facility's lenders. The Senior Credit Facility is also secured by first-priority perfected security interests in substantially all of the property and assets owned or acquired by NRG and its subsidiaries, other than certain limited exceptions. These exceptions include assets of certain unrestricted subsidiaries, equity interests in certain of NRG's affiliates that have non-recourse debt financing, including GenOn and its subsidiaries, and voting equity interests in excess of 66% of the total outstanding voting equity interest of certain of NRG's foreign subsidiaries. The Senior Credit Facility contains customary covenants, which, among other things, require NRG to meet certain financial tests, including minimum interest coverage ratio and a maximum leverage ratio on a consolidated basis, and limit NRG's ability to: • incur indebtedness and liens and enter into sale and lease-back transactions; • make investments, loans and advances; and • return capital to stockholders. Tax Exempt Bonds As of December 31, 2015 2014 Interest Rate % Amount in millions, except rates Indian River Power tax exempt bonds, due 2040 57 57 6.000 Indian River Power LLC, tax exempt bonds, due 2045 190 190 5.375 Dunkirk Power LLC, tax exempt bonds, due 2042 59 59 5.875 Fort Bend County, tax exempt bonds, due 2045 22 10 4.125 Fort Bend County, tax exempt bonds, due 2038 54 54 4.750 Fort Bend County, tax exempt bonds, due 2042 73 36 4.750 Total $ 455 $ 406 NRG Non-Recourse Debt The following are descriptions of certain indebtedness of NRG's subsidiaries that are outstanding as of December 31, 2015 . All of NRG's non-recourse debt is secured by the assets in the respective GenOn subsidiaries and project subsidiaries as further described below. The net assets in the GenOn and project subsidiaries are subject to restrictions, including the ability to transfer assets out of the subsidiaries. As of December 31, 2015 , NRG had net assets of $5.6 billion that were deemed restricted for purposes of Rule 4-08(e)(3)(ii) of Regulation S-X. The indebtedness described below is non-recourse to NRG, unless otherwise noted. GenOn Senior Notes As of December 31, 2015 2014 Interest Rate % Amount in millions, except rates Senior unsecured notes, due 2017 714 766 7.875 Senior unsecured notes, due 2018 708 757 9.500 Senior unsecured notes, due 2020 534 610 9.875 Total $ 1,956 $ 2,133 Under the GenOn Senior Notes and the related indentures, the GenOn Senior Notes are the sole obligation of GenOn and are not guaranteed by any subsidiary or affiliate of GenOn. The GenOn Senior Notes are senior unsecured obligations of GenOn having no recourse to any subsidiary or affiliate of GenOn. The GenOn Senior Notes restrict the ability of GenOn and its subsidiaries to encumber their assets. The GenOn Senior Notes are subject to acceleration of GenOn's obligations thereunder upon the occurrence of certain events of default, including: (a) default in interest payment for 30 days, (b) default in the payment of principal or premium, if any, (c) failure after 90 days of specified notice to comply with any other agreements in the indenture, (d) certain cross-acceleration events, (e) failure by GenOn or its significant subsidiaries to pay certain final and non-appealable judgments after 90 days and (f) certain events of bankruptcy and insolvency. Repurchase of GenOn Senior Notes During the fourth quarter of 2015, the Company repurchased $119 million in aggregate principal of the following outstanding Senior Notes in the open market for $108 million , including accrued interest. Principal Repurchased Average Early Redemption Percentage Gain on Debt Extinguishment Amount in millions, except rates Senior unsecured notes, due 2017 $ 33 95.172 % $ 3 Senior unsecured notes, due 2018 25 90.950 % 5 Senior unsecured notes, due 2020 61 83.847 % 15 Total $ 119 $ 23 2018 and 2020 GenOn Senior Notes The GenOn Senior Notes due 2018 and 2020 and the related indentures restrict the ability of GenOn to incur additional liens and make certain restricted payments, including dividends. In the event of a default or if restricted payment tests are not satisfied, GenOn would not be able to distribute cash to its parent, NRG. At December 31, 2015 , GenOn failed the consolidated debt ratio component of the restricted payments test. Under the related indentures, the ability of GenOn to make restricted payments, including dividends, loans and advances to NRG, is limited to specified exclusions, including up to $250 million of such restricted payments. As of December 31, 2015 , GenOn net assets of $277 million were deemed restricted for purposes of Rule 4-08(e)(3)(ii) of Regulation S-X. Prior to maturity, GenOn may redeem the senior notes due 2018, in whole or in part, at a redemption price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the following: the present value of 100% of the note, plus interest payments due on the note through maturity, discounted at a Treasury rate plus 0.50% over the principal amount of the note. GenOn may redeem some or all of the Senior Notes due 2020 at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption rate: Redemption Period Redemption Percentage October 15, 2015 to October 14, 2016 104.938 % October 15, 2016 to October 14, 2017 103.292 % October 15, 2017 to October 14, 2018 101.646 % October 15, 2018 and thereafter 100.000 % 2017 GenOn Senior Notes Prior to maturity, GenOn may redeem all or a part of the GenOn Senior Notes due 2017 at a redemption price equal to 100% of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the following: the present value of 100% of the note, plus interest payments due on the note through maturity, discounted at a Treasury rate plus 0.50% over the principal amount of the note . GenOn Americas Generation Senior Notes As of December 31, 2015 2014 Interest Rate % Amount in millions, except rates Senior unsecured notes, due 2021 398 496 8.500 Senior unsecured notes, due 2031 354 433 9.125 Total $ 752 $ 929 The GenOn Americas Generation Senior Notes due 2021 and 2031 are senior unsecured obligations of GenOn Americas Generation, a wholly owned subsidiary of NRG, having no recourse to any subsidiary or affiliate of GenOn Americas Generation. Repurchase of GenOn Americas Generation Senior Notes During the fourth quarter of 2015, the Company repurchased $155 million in aggregate principal of the following outstanding Senior Notes in the open market for $128 million , including accrued interest. Principal Repurchased Average Early Redemption Percentage Gain on Debt Extinguishment Amount in millions, except rates Senior unsecured notes, due 2021 $ 84 84.910 % $ 20 Senior unsecured notes, due 2031 71 77.018 % 22 Total $ 155 $ 42 2021 and 2031 GenOn Senior Notes Prior to maturity, GenOn Americas Generation may redeem all or a part of the senior notes due 2021 and 2031 at a redemption price equal to 100% of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) the discounted present value of the then-remaining scheduled payments of principal and interest on the outstanding notes, discounted at a Treasury rate plus 0.375%, less the unpaid principal amount; and (ii) zero. Yield Operating LLC Senior Notes 2024 Yield Operating Senior Notes On August 5, 2014, Yield Operating issued $500 million of senior unsecured notes and utilized the proceeds to fund the acquisition of the Alta Wind Assets. The Yield Operating senior notes bear interest at 5.375% and mature in August 2024. Interest on the notes is payable semi-annually on February 15 th and August 15 th of each year, and commenced on February 15, 2015. The notes are senior unsecured obligations of Yield Operating and are guaranteed by NRG Yield LLC, Yield Operating’s parent company, and by certain of Yield Operating’s wholly owned current and future subsidiaries. Yield LLC and Yield Operating LLC Revolving Credit Facility NRG Yield LLC and its direct wholly owned subsidiary, NRG Yield Operating LLC, entered into a senior secured revolving credit facility, which was amended on June 26, 2015, to, among other things, increase the availability from $450 million to $495 million . The revolving credit facility can be used for cash or for the issuance of letters of credit. At December 31, 2015, there was $306 million outstanding and $56 million of letters of credit were issued under the revolving credit facility. Yield, Inc. Convertible Notes 2020 Yield Inc. Convertible Notes On June 29, 2015, NRG Yield, Inc. closed on its offering of $287.5 million aggregate principal amount of 3.25% Convertible Senior Notes due 2020, or the 2020 Convertible Notes. The 2020 Convertible Notes are convertible, under certain circumstances, into NRG Yield, Inc. Class C common stock, cash or a combination thereof at an initial conversion price of $27.50 per Class C common share, which is equivalent to an initial conversion rate of approximately 36.3636 shares of Class C common stock per $1,000 principal amount of notes. Interest on the 2020 Convertible Notes is payable semi-annually in arrears on June 1 and December 1 of each year, commencing on December 1, 2015. The 2020 Convertible Notes mature on June 1, 2020, unless earlier repurchased or converted in accordance with their terms. Prior to the close of business on the business day immediately preceding December 1, 2019, the 2020 Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the close of business on the second scheduled trading day immediately preceding the maturity date. The 2020 Convertible Notes are accounted for in accordance with ASC 470-20, under which issuers of convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are required to separately account for the liability (debt) and equity (conversion option) components. The equity component, the $23 million conversion option value, was recorded to NRG's noncontrolling interest for NRG Yield, Inc. with the offset to debt discount. The debt discount is being amortized to interest expense over the term of the notes. 2019 Yield Inc. Convertible Notes In the first quarter of 2014, NRG Yield, Inc. closed on its offering of $345 million aggregate principal amount of 3.50% Convertible Senior Notes due 2019, or the 2019 Convertible Notes. The 2019 Convertible Notes were convertible, under certain circumstances, into NRG Yield, Inc. Class A common stock, cash or a combination thereof at an initial conversion price of $46.55 per Class A common share, which is equivalent to an initial conversion rate of approximately 21.4822 shares of Class A common stock per $1,000 principal amount of 2019 Convertible Notes. Effective May 15, 2015, the conversion rate was adjusted to 42.9644 shares of Class A common stock per $1,000 principal amount of 2019 Convertible Notes in accordance with the terms of the related indenture. Interest on the 2019 Convertible Notes is payable semi-annually in arrears on February 1 and August 1 of each year, commencing on August 1, 2014. The 2019 Convertible Notes mature on February 1, 2019, unless earlier repurchased or converted in accordance with their terms. Prior to the close of business on the business day immediately preceding August 1, 2018, the 2019 Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the close of business on the second scheduled trading day immediately preceding the maturity date. The 2019 Convertible Notes are accounted for in accordance with ASC 470-20. The equity component, the $23 million conversion option value, was recorded to NRG's noncontrolling interest for NRG Yield, Inc. with the offset to debt discount. The debt discount is being amortized to interest expense over the term of the notes. The 2019 Convertible Notes are guaranteed by NRG Yield Operating LLC and NRG Yield LLC. Project Financings The following are descriptions of certain indebtedness of NRG's project subsidiaries that are outstanding as of December 31, 2015 . Alta Wind X and Alta Wind XI due 2021 On June 30, 2015, the Company entered into a tax equity financing arrangement through which Yield Operating, a subsidiary of NRG Yield, Inc., received $119 million in net proceeds. These proceeds, as well as proceeds obtained from the June 29, 2015, NRG Yield, Inc. common stock issuance and the 2020 Convertible Notes issuance, were utilized to repay all of the outstanding project indebtedness associated with Alta Wind X and Alta Wind XI facilities. The Company also settled interest rate swaps associated with the project level debt for Alta Wind X and Alta Wind XI and incurred a fee of $17 million . Alta Wind lease financing arrangements Alta Wind Holdings (Alta Wind II - V) and Alta I have finance lease obligations issued under lease transactions whereby the respective operating entities sold and leased back undivided interests in specific assets of the projects. All of the assets of Alta I-V are pledged as collateral under these arrangements. The sale and related lease transactions are accounted for as financing arrangements as the operating entities have continued involvement with the property. Amount in millions, except rates Lease Financing Arrangement Letter of Credit Facility Non-Recourse Debt Amount Outstanding as of December 31, 2015 Interest Rate Maturity Date Amount Outstanding as of December 31, 2015 Interest Rate Maturity Date Alta Wind I $ 252 7.015% 12/30/2034 $ 16 3.250% 1/5/2021 Alta Wind II 198 5.696% 12/30/2034 28 2.750% 6/30/2017& 12/31/2017 Alta Wind III 206 6.067% 12/30/2034 28 2.750% 4/13/2018 Alta Wind IV 133 5.938% 12/30/2034 19 2.750% 8/24/2018 Alta Wind V 213 6.071% 6/30/2035 31 2.750% 10/24/2018 Total $ 1,002 $ 122 High Lonesome Mesa Facility Prior to the Company's acquisition of EME, an intercompany tax credit agreement related to the High Lonesome Mesa facility was terminated. The termination resulted in an event of default under the project financing arrangement. The Company received additional default notices for various items. The facility is secured by the assets of High Lonesome Mesa and is non-recourse to NRG. On November 3, 2015, the lender sent a notice of acceleration and indicated that it will accept the Company's interest in the assets in lieu of repayment. As of December 31, 2015, $57 million was outstanding under the project financing agreement. On January 27, 2016, High Lonesome Mesa, LLC (HLM) filed at FERC for approval to transfer 100% of the ownership interests in HLM to subsidiaries of the lien holders (Macquarie Bank Limited and Hannon Armstrong Capital, LLC). HLM requested FERC approval by March 11, 2016. Upon receipt of FERC approval the Company will transfer 100% of its interest in HLM to the lien holders. Dandan Financing In December 2013, NRG, through its wholly-owned subsidiary, NRG Solar Dandan LLC, or Dandan, entered into a credit agreement with a bank, or the Dandan Financing Agreement, for a $81 million construction loan and a $23 million cash grant loan. The construction loans have interest rates of LIBOR plus an applicable margin of 2.25% or base rate plus 1.25% and the cash grant loans have an interest rate of LIBOR plus an applicable margin of 1.75% . The term loan has an interest rate of LIBOR plus an applicable margin of 2.25% , which escalates 0.25% on the fifth, tenth, and fifteenth anniversary of the term conversion. The term loan, which is secured by all the assets of Dandan, matures January 2033, and amortizes based upon a predetermined schedule. The Dandan Financing Agreement also includes a letter of credit facility on behalf of Dandan of up to $5 million . Dandan pays an availability fee of 2.25% from the closing date until the 5th anniversary of the term conversion date and 2.50% from the 5th anniversary of the term conversion date on issued letters of credit. As of December 31, 2015, $81 million was outstanding under the construction loan, $17 million under the cash grant loan and $5 million in letters of credit in support of the project were issued. On January 29, 2016, the construction loan converted to a $79 million term loan with $23 million outstanding under the cash grant loan. In addition, a $4 million debt service letter of credit was issued replacing the $5 million construction letter of credit that was outstanding at year end. El Segundo Energy Center Credit Agreement On May 29, 2015, NRG West Holdings LLC amended its financing agreement to increase borrowings under the Tranche A facility by $5 million and to reduce the related interest rate to LIBOR plus an applicable margin of 1.625% from May 29, 2015, to August 31, 2017, LIBOR plus an applicable margin of 1.75% from September 1, 2017, to August 31, 2020, and LIBOR plus 1.875% from September 1, 2020, through the maturity date; and to reduce Tranche B loan interest rate to LIBOR plus an applicable margin of 2.25% from May

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations NRG's AROs are primarily related to the future dismantlement of equipment on leased property and environmental obligations related to nuclear decommissioning, ash disposal, site closures, and fuel storage facilities. In addition, NRG has also identified conditional AROs for asbestos removal and disposal, which are specific to certain power generation operations. See Note 6 , Nuclear Decommissioning Trust Fund , for a further discussion of NRG's nuclear decommissioning obligations. Accretion for the nuclear decommissioning ARO and amortization of the related ARO asset are recorded to the Nuclear Decommissioning Trust Liability to the ratepayers and are not included in net income, consistent with regulatory treatment. The following table represents the balance of ARO obligations as of December 31, 2015 , and 2014 , along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2015 : (In millions) Balance as of December 31, 2014 $ 763 Revisions in estimates for current obligations 122 Additions 18 Additions for acquisitions 2 Spending for current obligations (11 ) Accretion — Expense 35 Accretion — Nuclear decommissioning 16 Balance as of December 31, 2015 $ 945

Benefit Plans and Other Postret

Benefit Plans and Other Postretirement Benefit Plans (Notes)	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Benefit Plans and Other Postretirement Benefits	Benefit Plans and Other Postretirement Benefits NRG sponsors and operates defined benefit pension and other postretirement plans. As part of the GenOn acquisition in 2012, NRG assumed GenOn's defined benefit pension plans and other postretirement benefit plans, and GenOn's benefit plan obligations were recorded at fair value at the time of the acquisition. NRG expects to contribute $33 million to the Company's pension plans in 2016 . NRG pension benefits are available to eligible non-union and union employees through various defined benefit pension plans. These benefits are based on pay, service history and age at retirement. Most pension benefits are provided through tax-qualified plans. Certain executive pension benefits that cannot be provided by the tax-qualified plans are provided through unfunded non-tax-qualified plans. NRG also provides postretirement health and welfare benefits for certain groups of employees. Cost sharing provisions vary by the terms of any applicable collective bargaining agreements. As part of the change in control associated with the GenOn acquisition, NRG decided to terminate/settle the nonqualified legacy GenOn Benefit Restoration Plan and Supplemental Executive Retirement Plan. Final settlement payments totaling $12 million were paid to remaining participants during 2014. On December 31, 2014, NRG merged eight qualified pension plans into two separate qualified pension plans, the NRG Pension Plan for Bargained Employees and the NRG Pension Plan. The NRG Pension Plan for Bargained Employees, GenOn Mirant Bargaining Unit Pension Plan, GenOn First Energy Pension Plan, GenOn Duquesne Pension Plan, and GenOn REMA Pension Plan were merged into the NRG Pension Plan for Bargained Employees. The NRG Texas Retirement Plan, and GenOn Mirant Pension Plan were merged into the NRG Pension Plan for Non-Bargained Employees and renamed the NRG Pension Plan. These actions were conducted to simplify internal administration of the plans, reduce regulatory filings, and lower fees paid to outside vendors. The benefits provided to current participants in the Plans were not impacted. NRG Defined Benefit Plans The annual net periodic benefit cost/(credit) related to NRG's pension and other postretirement benefit plans include the following components: Year Ended December 31, Pension Benefits 2015 2014 2013 (In millions) Service cost benefits earned $ 32 $ 30 $ 30 Interest cost on benefit obligation 53 53 47 Expected return on plan assets (62 ) (62 ) (55 ) Amortization of unrecognized net loss/(gain) 2 (6 ) 9 Curtailment — — (1 ) Net periodic benefit cost $ 25 $ 15 $ 30 Year Ended December 31, Other Postretirement Benefits 2015 2014 2013 (In millions) Service cost benefits earned $ 3 $ 3 $ 4 Interest cost on benefit obligation 9 9 9 Amortization of unrecognized prior service credit (5 ) (17 ) — Amortization of unrecognized net loss 1 — — Curtailment gain (14 ) — — Net periodic benefit (credit)/cost $ (6 ) $ (5 ) $ 13 A comparison of the pension benefit obligation, other postretirement benefit obligations and related plan assets for NRG's plans on a combined basis is as follows: As of December 31, Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 (In millions) Benefit obligation at January 1 $ 1,305 $ 1,060 $ 238 $ 191 Obligations resulting from the EME acquisition — 43 — 16 Service cost 32 30 3 3 Interest cost 53 53 9 9 Plan amendments — — (6 ) (18 ) Actuarial (gain)/loss (120 ) 174 (31 ) 46 Employee and retiree contributions — — 2 3 Benefit payments (74 ) (55 ) (12 ) (12 ) Curtailment — — (25 ) — Benefit obligation at December 31 1,196 1,305 178 238 Fair value of plan assets at January 1 988 880 — — Actual return on plan assets (26 ) 85 — — Employee and retiree contributions — — 2 3 Employer contributions 28 78 10 9 Benefit payments (74 ) (55 ) (12 ) (12 ) Fair value of plan assets at December 31 916 988 — — Funded status at December 31 — excess of obligation over assets $ (280 ) $ (317 ) $ (178 ) $ (238 ) Amounts recognized in NRG's balance sheets were as follows: As of December 31, Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 (In millions) Current liabilities $ — $ — $ 12 $ 10 Non-current liabilities 280 317 166 228 Amounts recognized in NRG's accumulated OCI that have not yet been recognized as components of net periodic benefit cost were as follows: As of December 31, Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 (In millions) Net loss/(gain) $ 68 $ 101 $ (9 ) $ 34 Prior service cost/(credit) 3 4 (9 ) (7 ) Other changes in plan assets and benefit obligations recognized in OCI were as follows: Year Ended December 31, Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 (In millions) Net actuarial (gain)/loss $ (31 ) $ 152 $ (31 ) $ 46 Amortization of net actuarial (gain)/loss (2 ) 6 (1 ) — Prior service (credit)/cost (1 ) — (7 ) (18 ) Amortization of prior service cost — — 5 17 Curtailment — — (11 ) — Total recognized in other comprehensive (income)/loss $ (34 ) $ 158 $ (45 ) $ 45 Total recognized in net periodic pension (credit)/cost and other comprehensive (income)/loss $ (8 ) $ 173 $ (37 ) $ 40 The change in net actuarial loss/(gain) from 2014 to 2015 primarily reflects the use of an updated mortality table and the change in discount rates described below. The Company's estimated unrecognized loss and unrecognized prior service cost for NRG's pension plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year is approximately $2 million . The Company's estimated unrecognized loss and unrecognized prior service credit for NRG's postretirement plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year is $1 million and $2 million , respectively. The following table presents the balances of significant components of NRG's pension plan: As of December 31, Pension Benefits 2015 2014 (In millions) Projected benefit obligation $ 1,196 $ 1,305 Accumulated benefit obligation 1,115 1,172 Fair value of plan assets 916 988 NRG's market-related value of its plan assets is the fair value of the assets. The fair values of the Company's pension plan assets by asset category and their level within the fair value hierarchy are as follows: Fair Value Measurements as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Total (In millions) Common/collective trust investment — U.S. equity $ — $ 255 $ 255 Common/collective trust investment — non-U.S. equity — 147 147 Common/collective trust investment — global equity — 90 90 Common/collective trust investment — fixed income — 400 400 Partnerships/joint ventures — 18 18 Short-term investment fund 6 — 6 Total $ 6 $ 910 $ 916 Fair Value Measurements as of December 31, 2014 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Total (In millions) Common/collective trust investment — U.S. equity $ — $ 287 $ 287 Common/collective trust investment — non-U.S. equity — 149 149 Common/collective trust investment — global equity — 96 96 Common/collective trust investment — fixed income — 431 431 Partnerships/joint ventures — 21 21 Short-term investment fund 4 — 4 Total $ 4 $ 984 $ 988 In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety. The fair value of the common/collective trusts is valued at fair value which is equal to the sum of the market value of all of the fund's underlying investments, and is categorized as Level 2. Partnerships/joint ventures Level 2 investments consist primarily of a partnership which invests in emerging market equity securities. There are no investments categorized as Level 3. The following table presents the significant assumptions used to calculate NRG's benefit obligations: As of December 31, Pension Benefits Other Postretirement Benefits Weighted-Average Assumptions 2015 2014 2015 2014 Discount rate 4.52 % 4.16 % 4.55 % 4.20 % Rate of compensation increase 3.00 % 3.45 % N/A N/A Health care trend rate — — 7.25% grading to 5.0% in 2025 8.6% grading to The following table presents the significant assumptions used to calculate NRG's benefit expense: As of December 31, Pension Benefits Other Postretirement Benefits Weighted-Average Assumptions 2015 2014 2013 2015 2014 2013 Discount rate 4.16 % 4.99 % 4.16 % 4.20 % 5.06 % 4.31 % Expected return on plan assets 6.36 % 6.81 % 7.12 % — — — Rate of compensation increase 3.45 % 3.65 % 3.57 % — — — Health care trend rate — — — 8.6% grading to 5.0% in 2023 8.5% grading to 5.5% in 2019 8.3% grading to NRG uses December 31 of each respective year as the measurement date for the Company's pension and other postretirement benefit plans. The Company sets the discount rate assumptions on an annual basis for each of NRG's defined benefit retirement plans as of December 31. The discount rate assumptions represent the current rate at which the associated liabilities could be effectively settled at December 31. The Company utilizes the Aon Hewitt AA Above Median, or AA-AM, yield curve to select the appropriate discount rate assumption for each retirement plan. The AA-AM yield curve is a hypothetical AA yield curve represented by a series of annualized individual spot discount rates from 6 months to 99 years. Each bond issue used to build this yield curve must be non-callable, and have an average rating of AA when averaging available Moody's Investor Services, Standard & Poor's and Fitch ratings. NRG employs a total return investment approach, whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The Investment Committee reviews the asset mix periodically and as the plan assets increase in future years, the Investment Committee may examine other asset classes such as real estate or private equity. NRG employs a building block approach to determining the long-term rate of return assumption for plan assets, with proper consideration given to diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed income are preserved, consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonableness and appropriateness. In 2016, NRG will change the approach utilized to estimate the service cost and interest cost components of net periodic benefit cost for pension and postretirement benefit plans. Historically, the Company estimated these components by using a single weighted average discount rate derived from the yield curve used to measure the benefit obligation. The Company will elect to use a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the yield curve to the relevant projected cash flows, as this provides a better estimate of service and interest costs. This is considered a change in estimate and, accordingly, will account for it prospectively starting in 2016. This change does not affect the measurement of NRG's total benefit obligation. The target allocations of NRG's pension plan assets were as follows for the year ended December 31, 2015 : U.S. equity 27 % Non-U.S. equity 15 % Global equity 10 % Emerging market equity 3 % U.S. fixed income 45 % Plan assets are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S., non-U.S., global, and emerging market equities, as well as among growth, value, small and large capitalization stocks. Investment risk and performance are monitored on an ongoing basis through quarterly portfolio reviews of each asset fund class to a related performance benchmark, if applicable, and annual pension liability measurements. Performance benchmarks are composed of the following indices: Asset Class Index U.S. equities Dow Jones U.S. Total Stock Market Index Non-U.S. equities MSCI All Country World Ex-U.S. IMI Index Global equities MSCI World Index Emerging market equities MSCI Emerging Markets Index Fixed income securities Barclays Capital Long Term Government/Credit Index & Barclays US Aggregate Bond Index NRG's expected future benefit payments for each of the next five years, and in the aggregate for the five years thereafter, are as follows: Other Postretirement Benefit Pension Benefit Payments Benefit Payments Medicare Prescription Drug Reimbursements (In millions) 2016 $ 60 $ 12 $ — 2017 64 9 — 2018 67 10 — 2019 71 10 — 2020 75 10 — 2021-2025 409 52 1 Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect: 1-Percentage- Point Increase 1-Percentage- Point Decrease (In millions) Effect on total service and interest cost components $ 1 $ (1 ) Effect on postretirement benefit obligation 13 (11 ) STP Defined Benefit Plans NRG has a 44% undivided ownership interest in STP, as discussed further in Note 27 , Jointly Owned Plants . STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. For the year ended December 31, 2015 , NRG reimbursed STPNOC $9 million towards its defined benefit plans. For the year ended December 31, 2014, NRG reimbursed STPNOC $14 million towards its defined benefit plans. In 2016 , NRG expects to reimburse STPNOC $7 million for its contribution towards the plans. The Company has recognized the following in its statement of financial position, statement of operations and accumulated OCI related to its 44% interest in STP: As of December 31, Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 (In millions) Funded status — STPNOC benefit plans $ (63 ) $ (71 ) $ (26 ) $ (30 ) Net periodic benefit cost/(credit) 10 6 (8 ) 3 Other changes in plan assets and benefit obligations recognized in other comprehensive income (8 ) 37 6 (29 ) Defined Contribution Plans NRG's employees are also eligible to participate in defined contribution 401(k) plans. Upon completion of the GenOn acquisition, NRG assumed GenOn's defined contribution 401(k) plans and amended the plan covering the majority of employees with NRG 401(k) plan features, effective January 1, 2013. On July 5, 2013, the GenOn defined contribution 401(k) plans were merged into the NRG 401(k) plan. The Company's contributions to these plans were as follows: Year Ended December 31, 2015 2014 2013 (In millions) Company contributions to defined contribution plans $ 53 $ 47 $ 34

Capital Structure (Notes)

Capital Structure (Notes)	12 Months Ended
	Dec. 31, 2015
Stockholders' Equity Note [Abstract]
Capital Structure	Capital Structure For the period from December 31, 2012 to December 31, 2015 , the Company had 10,000,000 shares of preferred stock authorized, 500,000,000 shares of common stock authorized and 250,000 shares of preferred stock issued and outstanding. The following table reflects the changes in NRG's common shares issued and outstanding for each period presented: Common Issued Treasury Outstanding Balance as of December 31, 2012 399,112,616 (76,505,718 ) 322,606,898 Shares issued under ESPP — 130,482 130,482 Shares issued under LTIPs 2,014,164 — 2,014,164 Share repurchases — (972,292 ) (972,292 ) Balance as of December 31, 2013 401,126,780 (77,347,528 ) 323,779,252 Shares issued under ESPP — 128,336 128,336 Shares issued under LTIPs 1,707,419 — 1,707,419 Shares issued in connection with the EME acquisition 12,671,977 — 12,671,977 Share repurchases — (1,624,360 ) (1,624,360 ) Balance as of December 31, 2014 415,506,176 (78,843,552 ) 336,662,624 Shares issued under ESPP — 283,139 283,139 Shares issued under LTIPs 1,433,774 — 1,433,774 Share repurchases — (24,189,495 ) (24,189,495 ) Balance as of December 31, 2015 416,939,950 (102,749,908 ) 314,190,042 Common Stock The following table summarizes NRG's common stock reserved for the maximum number of shares potentially issuable based on the conversion and redemption features of outstanding equity instruments and the long-term incentive plans as of December 31, 2015 : Equity Instrument Common Stock Reserve Balance 2.822% Convertible perpetual preferred 16,000,000 Long-term incentive plans 17,979,967 Total 33,979,967 Common stock dividends — In 2013, NRG paid quarterly dividends on the Company's common stock of $0.12 per share, or $0.48 per share on an annualized basis. In 2015 and 2014 , the Company increased its annual common stock dividend by 4% to $0.58 per share and 17% to $0.56 per share, respectively. The following table lists the dividends paid per common share during 2015 , 2014 and 2013 : Fourth Quarter Third Quarter Second Quarter First Quarter 2015 $ 0.145 $ 0.145 $ 0.145 $ 0.145 2014 $ 0.140 $ 0.140 $ 0.140 $ 0.120 2013 $ 0.120 $ 0.120 $ 0.120 $ 0.090 On January 18, 2016 , NRG declared a quarterly dividend on the Company's common stock of $0.145 per share, or $0.58 per share on an annualized basis, payable on February 16, 2016 , to stockholders of record as of February 1, 2016. Employee Stock Purchase Plan — Under the ESPP, eligible employees may elect to withhold up to 10% of their eligible compensation to purchase shares of NRG common stock at the lesser of 85% of its fair market value on the offering date or 85% of the fair market value on the exercise date. An offering date occurs each January 1 and July 1. An exercise date occurs each June 30 and December 31. As of December 31, 2015 , there remained 1,276,913 shares of treasury stock reserved for issuance under the ESPP, and in the first quarter of 2016 , 299,127 shares of common stock were issued to employee accounts from treasury stock. Share Repurchases The Company's board of directors authorized share repurchases of $481 million of its common stock, which were made as follows: Total number of shares purchased Average price paid per share (a) Amounts paid for shares purchased (in millions) (a) Board Authorized Share Repurchases Fourth Quarter 2014 1,624,360 $ 26.95 $ 44 First Quarter 2015 3,146,484 25.15 79 Second Quarter 2015 4,379,907 24.53 107 Third Quarter 2015 11,104,184 15.06 167 Fourth Quarter 2015 5,558,920 15.03 84 Total Board Authorized Share Repurchases 25,813,855 $ 481 (a) The average price paid per share and amounts paid for shares purchased exclude the commissions of $0.015 per share paid in connection with the share repurchase. Preferred Stock 2.822% Redeemable Preferred Stock On December 23, 2014, NRG and the Credit Suisse Group amended and restated its 250,000 shares of 3.625% Convertible Perpetual Preferred Stock, or 3.625% Preferred Stock, which is treated as redeemable preferred stock, initially issued on August 11, 2005, to the Credit Suisse Group in a private placement. The amendment resulted in a reduction of the rate from 3.625% to 2.822% and is hereby referred to as the 2.822% Preferred Stock. The transaction was accounted for as an extinguishment of the 3.625% Preferred Stock and the issuance of new 2.822% Preferred Stock. The loss on extinguishment of the 3.625% Preferred Stock of $42 million represents the increase in redeemable preferred stock as the Company recorded the 2.822% Preferred Stock at a fair value of $291 million in connection with the amendment. The loss on extinguishment of $42 million as well as $5 million in consent fees paid to Credit Suisse, were recorded as a dividend on the preferred shares. This amount reduced net income to arrive at net income/(loss) available to NRG common stockholders in the calculation of earnings per share for the year ended December 31, 2014. The 2.822% Preferred Stock amount is located after the liabilities but before the stockholders' equity section on the balance sheet, due to the fact that the preferred shares can be redeemed in cash by the stockholder. The 2.822% Preferred Stock has a liquidation preference of $1,378 per share. Holders of the 2.822% Preferred Stock are entitled to receive, out of legally available funds, cash dividends at the rate of 2.822% per annum, or $28.22 per share per year, payable in cash quarterly in arrears commencing on December 30, 2014. Each share of the 2.822% Preferred Stock is convertible during the 90 -day period beginning December 23, 2019, at the option of NRG or the holder. Holders tendering the 2.822% Preferred Stock for conversion shall be entitled to receive, for each share of 2.822% Preferred Stock converted, $1,378 in cash and a number of shares of NRG common stock equal in value to the product of (a) the greater of (i) the difference between the average closing share price of NRG common stock on each of the twenty consecutive scheduled trading days starting on the date thirty exchange business days immediately prior to the conversion date, or the Market Price, and $40.71 and (ii) zero, times (b) 50.7743. The number of shares of NRG common stock to be delivered under the conversion feature is limited to 16,000,000 shares. If upon conversion, the Market Price is less than $27.14, then the Holder will deliver to NRG cash or a number of shares of NRG common stock equal in value to the product of (i) $27.14 minus the Market Price, times (ii) 50.7743. NRG may elect to make a cash payment in lieu of delivering shares of NRG common stock in connection with such conversion, and NRG may elect to receive cash in lieu of shares of common stock, if any, from the Holder in connection with such conversion. The conversion feature is considered an embedded derivative per ASC 815 that is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815. If a fundamental change occurs, including, among others, insolvency or a change of control, the holders will have the right to require NRG to repurchase all or a portion of the 2.822% Preferred Stock for a period of time after the fundamental change at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends. The 2.822% Preferred Stock is senior to all classes of common stock and junior to all of the Company's existing and future debt obligations and all of NRG subsidiaries' existing and future liabilities and capital stock held by persons other than NRG or its subsidiaries. The following table reflects the changes in the Company's redeemable preferred stock balance for the years ended December 31, 2015 , and 2014 . (In millions) Balance as of December 31, 2013 $ 249 Loss recorded in connection with extinguishment of 3.625% preferred stock and issuance of 2.822% preferred stock 42 Balance as of December 31, 2014 291 Accretion to redemption value 11 Balance as of December 31, 2015 $ 302

Investments Accounted for by th

Investments Accounted for by the Equity Method and Variable Interest Entities (Notes)	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Investments Accounted for by the Equity Method and Variable Interest Entities	Investments Accounted for by the Equity Method and Variable Interest Entities Entities that are not Consolidated NRG accounts for the Company's significant investments using the equity method of accounting. NRG's carrying value of equity investments can be impacted by impairments, unrealized gains and losses on derivatives and movements in foreign currency exchange rates, as well as other adjustments. The following table summarizes NRG's significant equity method investments as of December 31, 2015 : Name Economic Interest Investment Balance (in millions) Avenal Solar Holdings LLC (a) 50.0 % $ (9 ) Community Wind North, LLC 99.0 % 57 Desert Sunlight Investment Holdings, LLC (a) 25.0 % 291 Elkhorn Ridge Wind, LLC (a) 66.7 % 96 GenConn Energy LLC (a) 50.0 % 110 Midway-Sunset Cogeneration Company 50.0 % 25 Petra Nova Parish Holdings LLC 50.0 % 136 Saguaro Power Company 50.0 % (20 ) San Juan Mesa Wind Project, LLC (a) 75.0 % 80 Sherbino I Wind Farm LLC 50.0 % 80 Watson Cogeneration Company 49.0 % 36 Gladstone Power Station (b) 37.5 % 149 Other Various 14 (a) Equity method investments owned by NRG Yield (b) Gladstone Power Station is located in Australia As of December 31, 2015 2014 (In millions) Undistributed earnings from equity investments $ 55 $ 76 Desert Sunlight — As described in Note 3 , Business Acquisitions and Dispositions , on June 29, 2015, NRG Yield, Inc., through its subsidiary Yield Operating, acquired 25% of the membership interest in Desert Sunlight Investment Holdings, LLC, which owns two solar photovoltaic facilities that total 550 MW located in Desert Center, California from EFS Desert Sun, LLC, an affiliate of GE Energy Financial Services, for a purchase price of $285 million . The Company accounts for its 25% investment as an equity method investment. Petra Nova — As further described in Note 3 , Business Acquisitions and Dispositions , on July 3, 2014, NRG, through its wholly owned subsidiary Petra Nova Holdings LLC, sold 50% of its interest in Petra Nova Parish Holdings LLC to JX Nippon Oil Exploration (EOR) Limited, or JX Nippon, a wholly owned subsidiary of JX Nippon Oil & Gas Exploration Corporation. As a result of the sale, the Company no longer has a controlling interest in and has deconsolidated Petra Nova Parish Holdings LLC as of the date of the sale. NRG's 50% interest in the partnership is accounted for as an equity method investment. Variable Interest Entities NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, but NRG is not the primary beneficiary, under the equity method. GenConn — NRG owns a 50% interest in GenConn, a limited liability company formed to construct, own and operate two 190 MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. GenConn has a $237 million note with an interest rate of 4.73% and a maturity date of July 2041 and a 5 -year, $35 million working capital facility which can be used to issue letters of credit at an interest rate of 1.875% . As of December 31, 2015 , $220 million was outstanding under the note and $14 million was drawn on the working capital facility. The note is secured by all of the GenConn assets. NRG's maximum exposure to loss is limited to its equity investment, which was $110 million as of December 31, 2015. As discussed in Note 21 , Related Party Transactions , NRG earns revenues from an operations and management agreements with Devon and Middletown and interest income from a note receivable with GenConn. Sherbino — NRG owns a 50% interest in Sherbino, a joint venture with BP Wind Energy North America Inc. Sherbino is a 150 MW wind farm, which commenced commercial operations in October 2008. In December 2008, Sherbino entered into a 15 -year term loan facility which is non-recourse to NRG. As of December 31, 2015 , the outstanding principal balance of the term loan facility was $87 million , and is secured by substantially all of Sherbino's assets and membership interests. NRG's maximum exposure to loss is limited to its equity investment, which was $80 million as of December 31, 2015 . Other Equity Investments Gladstone — Through a joint venture, NRG owns a 37.5% interest in Gladstone, a 1,613 MW coal-fueled power generation facility in Queensland, Australia. The power generation facility is managed by the joint venture participants and the facility is operated by NRG. Operating expenses incurred in connection with the operation of the facility are funded by each of the participants in proportion to their ownership interests. Coal is sourced from local mines in Queensland. NRG and the joint venture participants receive their respective share of revenues directly from the off takers in proportion to the ownership interests in the joint venture. Power generated by the facility is primarily sold to an adjacent aluminum smelter, with excess power sold to the Queensland Government owned utility under long term supply contracts. The Company recorded an impairment loss for Gladstone in the fourth quarter of 2013 of $92 million , as described in Note 10 , Asset Impairments . NRG's investment in Gladstone was $149 million as of December 31, 2015 . Entities that are Consolidated The Company has a controlling financial interest in certain entities which have been identified as VIEs under ASC 810. These arrangements are primarily related to tax equity arrangements entered into with third-parties in order to finance the cost of solar energy systems under operating leases and wind facilities eligible for certain tax credits as further described in Note 2 , Summary of Significant Accounting Policies . For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to $23 million as of December 31, 2015, which would be required to be funded if the arrangement were to be dissolved. The summarized financial information for the Company's consolidated VIEs consisted of the following: (In millions) December 31, 2015 Current assets $ 84 Net property, plant and equipment 1,807 Other long-term assets 863 Total assets 2,754 Current liabilities 56 Long-term debt 366 Other long-term liabilities 179 Total liabilities 601 Noncontrolling interests 493 Net assets less noncontrolling interests $ 1,660

Segment Reporting (Notes)

Segment Reporting (Notes)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segment Reporting	Segment Reporting Effective in December 2014, the Company's segment structure and its allocation of corporate expenses were updated to reflect how management makes financial decisions and allocates resources. The Company has recast data from prior periods to reflect this change in reportable segments to conform to the current year presentation. The Company's businesses are segregated as follows: NRG Business; NRG Home, which includes NRG Home Retail and NRG Home Solar; NRG Renew, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield and corporate activities. The Company's corporate segment includes BETM, international business and electric vehicle services. Intersegment sales are accounted for at market. NRG Yield includes certain of the Company's contracted generation assets. NRG Yield acquired certain assets from the Company, which were accounted for as transfers of entities under common control and accordingly, all historical periods have been recast to reflect these changes: • On June 30, 2014, El Segundo Energy Center, formerly in the NRG Business segment, Kansas South and High Desert, both formerly in the NRG Renew segment. • On January 2, 2015, Walnut Creek, formerly in the NRG Business segment, the Tapestry projects (Buffalo Bear, Pinnacle, and Taloga) and Laredo Ridge, both formerly in the NRG Renew segment. • On November 3, 2015, 75% of the class B interests in NRG Wind TE Holdco, which owns a portfolio of 12 wind facilities, formerly in the NRG Renew segment. NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and capital for allocation, as well as net income/(loss) and net income/(loss) attributable to NRG Energy, Inc. For the years ended December 31, 2015 , 2014 , and 2013 , there were no customers from whom the Company derived more than 10% of the Company's consolidated revenues. For the Year Ended December 31, 2015 NRG Home NRG Business Retail Solar NRG Renew NRG Yield Corporate Eliminations Total (in millions) Operating revenues (a) $ 9,142 $ 5,389 $ 32 $ 474 $ 869 $ (14 ) $ (1,218 ) $ 14,674 Operating expenses 7,811 4,577 204 218 324 61 (1,220 ) 11,975 Depreciation and amortization 907 123 25 212 265 34 — 1,566 Impairment charges 4,827 36 132 13 — — 22 5,030 Acquisition-related transaction and integration costs — 1 (8 ) — 3 14 — 10 Development activity expenses 24 — — 70 — 60 — 154 Total operating cost and expenses 13,569 4,737 353 513 592 169 (1,198 ) 18,735 Gain on sale of assets 21 — — — — — — 21 Operating (loss)/income (4,406 ) 652 (321 ) (39 ) 277 (183 ) (20 ) (4,040 ) Equity in earnings/(losses) of unconsolidated affiliates 7 — — 1 35 — (7 ) 36 Impairment losses on investments (14 ) — — — (42 ) — (56 ) Other income, net 40 — — 4 2 84 (97 ) 33 Loss on sale of equity-method investment — — — — — (14 ) — (14 ) (Loss)/gain on debt extinguishment — — — — (9 ) 84 — 75 Interest expense (98 ) — (3 ) (108 ) (238 ) (776 ) 95 (1,128 ) (Loss)/income before income taxes (4,471 ) 652 (324 ) (142 ) 67 (847 ) (29 ) (5,094 ) Income tax expense/(benefit) 1 — — (18 ) 12 1,347 — 1,342 Net (loss)/income $ (4,472 ) $ 652 $ (324 ) $ (124 ) $ 55 $ (2,194 ) $ (29 ) $ (6,436 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests $ — $ — $ (20 ) $ 6 $ 19 $ (17 ) $ (42 ) $ (54 ) Net (loss)/income attributable to NRG Energy, Inc. $ (4,472 ) $ 652 $ (304 ) $ (130 ) $ 36 $ (2,177 ) $ 13 $ (6,382 ) Balance sheet Equity investments in affiliates 185 — 134 798 276 (348 ) 1,045 Capital expenditures (b) 798 30 144 163 30 102 — 1,267 Goodwill 536 340 — 12 — 111 — 999 Total assets 17,139 1,876 413 5,954 7,775 19,576 (19,851 ) 32,882 (a) Operating revenues include inter-segment sales and net derivative gains and losses of: $ 947 $ 6 $ 1 $ 23 $ 29 $ 212 $ — $ 1,218 (b) Includes accruals. For the Year Ended December 31, 2014 NRG Home NRG Business Retail Solar NRG Renew (d) NRG Yield Corporate Eliminations (d) Total (in millions) Operating revenues (c) $ 11,024 $ 5,503 $ 42 $ 427 $ 746 $ 75 $ (1,949 ) $ 15,868 Operating expenses 8,894 5,240 108 183 274 72 (1,950 ) 12,821 Depreciation and amortization 966 122 6 195 202 32 — 1,523 Impairment charges 87 — — 32 — — (22 ) 97 Acquisition-related transaction and integration costs 1 3 — — 4 76 — 84 Development activity expenses 13 — — 42 — 36 — 91 Total operating cost and expenses 9,961 5,365 114 452 480 216 (1,972 ) 14,616 Gain on sale of assets 19 — — — — — — 19 Operating income/(loss) 1,082 138 (72 ) (25 ) 266 (141 ) 23 1,271 Equity in earnings/(losses) of unconsolidated affiliates 23 — — (4 ) 25 3 (9 ) 38 Other income, net 35 — — 5 3 78 (99 ) 22 Gain on sale of equity-method investment 18 — — — — — — 18 Loss on debt extinguishment — — — (1 ) — (94 ) — (95 ) Interest expense (95 ) (1 ) (1 ) (122 ) (191 ) (806 ) 97 (1,119 ) Income/(loss) before income taxes 1,063 137 (73 ) (147 ) 103 (960 ) 12 135 Income tax expense/(benefit) 1 — — — 4 (2 ) — 3 Net income/(loss) 1,062 137 (73 ) (147 ) 99 (958 ) 12 132 Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests (1 ) — (19 ) 2 16 24 (24 ) (2 ) Net income/(loss) attributable to NRG Energy, Inc. $ 1,063 $ 137 $ (54 ) $ (149 ) $ 83 $ (982 ) $ 36 $ 134 Balance sheet Equity investments in affiliates $ 141 $ — $ — $ 148 $ 410 $ 174 $ (102 ) $ 771 Capital expenditures (e) 611 34 113 160 13 53 — 984 Goodwill 1,746 387 98 12 — 331 — 2,574 Total assets $ 28,317 $ 6,049 $ 222 $ 6,481 $ 7,860 $ 30,727 $ (39,190 ) $ 40,466 (c) Operating revenues include inter-segment sales and net derivative gains and losses of: $ 1,820 $ 7 $ — $ 25 $ 12 $ 85 $ — $ 1,949 (d) Includes an impairment loss resulting from the intercompany sale of solar panels at current market rates. The use of these long-lived assets is anticipated to generate sufficient cash flows to recover the historical cost of the assets and accordingly, the impairment loss was eliminated and the assets remain at historical cost in consolidation. (e) Includes accruals. For the Year Ended December 31, 2013 NRG Home NRG Business Retail Solar NRG Renew NRG Yield Corporate Eliminations Total (in millions) Operating revenues (f) $ 8,638 $ 4,341 $ 4 $ 214 $ 387 $ 19 $ (2,308 ) $ 11,295 Operating expenses 7,235 3,814 — 77 155 41 (2,297 ) 9,025 Depreciation and amortization 930 141 4 86 74 21 — 1,256 Impairment charges 459 — — — — — — 459 Acquisition-related transaction and integration costs — — — — — 128 — 128 Development activity expenses 14 — 9 34 — 27 — 84 Total operating costs and expenses 8,638 3,955 13 197 229 217 (2,297 ) 10,952 Operating income/(loss) — 386 (9 ) 17 158 (198 ) (11 ) 343 Equity in earnings/of unconsolidated affiliates (6 ) — — (7 ) 22 — (2 ) 7 Impairment losses on investments — — — — — (99 ) — (99 ) Other income, net 32 — — 2 3 77 (101 ) 13 Loss on debt extinguishment — — — — — (50 ) — (50 ) Interest expense (107 ) (2 ) — (52 ) (52 ) (735 ) 100 (848 ) (Loss)/income before income taxes (81 ) 384 (9 ) (40 ) 131 (1,005 ) (14 ) (634 ) Income tax expense/(benefit) — — — — 8 (290 ) — (282 ) Net (loss)/income (81 ) 384 (9 ) (40 ) 123 (715 ) (14 ) (352 ) Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests — — — 22 13 14 (15 ) 34 Net (loss)/income attributable to NRG Energy, Inc. (81 ) 384 (9 ) (62 ) 110 (729 ) 1 (386 ) (f) Operating revenues include inter-segment sales and net derivative gains and losses of: $ 2,055 $ 5 $ — $ 14 $ 7 $ 227 $ — $ 2,308

Earnings Per Share (Notes)

Earnings Per Share (Notes)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Share	Earnings/(Loss) Per Share Basic earnings/(loss) per common share is computed by dividing net income/(loss) less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings/(loss) per share is computed in a manner consistent with that of basic earnings/(loss) per share while giving effect to all potentially dilutive common shares that were outstanding during the period. Dilutive effect for equity compensation and other equity instruments — The outstanding non-qualified stock options, non-vested restricted stock units, and market stock units are not considered outstanding for purposes of computing basic earnings/(loss) per share. However, these instruments are included in the denominator for purposes of computing diluted earnings/(loss) per share under the treasury stock method. The if-converted method is used to determine the dilutive effect of embedded derivatives in the Company's 2.822% Preferred Stock. The reconciliation of NRG's basic earnings/(loss) per share to diluted earnings/(loss) per share is shown in the following table: Year Ended December 31, 2015 2014 2013 (In millions, except per share amounts) Basic (loss)/earnings per share attributable to NRG common stockholders Net (loss)/income attributable to NRG Energy, Inc. $ (6,382 ) $ 134 $ (386 ) Dividends for preferred shares 20 9 9 Dividends for refinancing of preferred shares — 47 — (Loss)/Income Available to Common Stockholders $ (6,402 ) $ 78 $ (395 ) Weighted average number of common shares outstanding 329 334 323 (Loss)/Earnings per weighted average common share — basic $ (19.46 ) $ 0.23 $ (1.22 ) Diluted (loss)/earnings per share attributable to NRG common stockholders Weighted average number of common shares outstanding 329 334 323 Incremental shares attributable to the issuance of equity compensation (treasury stock method) — 5 — Total dilutive shares 329 339 323 (Loss)/Earnings per weighted average common share — diluted $ (19.46 ) $ 0.23 $ (1.22 ) The following table summarizes NRG's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted earnings/(loss) per share: Year Ended December 31, 2015 2014 2013 (In millions of shares) Equity compensation 6 1 9 Embedded derivative of 2.822% redeemable perpetual preferred stock (a) 16 16 16 Total 22 17 25 (a) At December 31, 2013, the redeemable perpetual preferred stock had an interest rate of 3.625%.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The income tax provision from continuing operations consisted of the following amounts: Year Ended December 31, 2015 2014 2013 (In millions, except percentages) Current State $ 6 $ 8 $ 11 Total — current 6 8 11 Deferred U.S. Federal 1,020 (50 ) (207 ) State 315 41 (57 ) Foreign 1 4 (29 ) Total — deferred 1,336 (5 ) (293 ) Total income tax expense/(benefit) $ 1,342 $ 3 $ (282 ) Effective tax rate (26.3 )% 2.2 % 44.5 % The following represents the domestic and foreign components of income/(loss) before income tax expense/(benefit): Year Ended December 31, 2015 2014 2013 (In millions) U.S. $ (5,105 ) $ 126 $ (549 ) Foreign 11 9 (85 ) Total $ (5,094 ) $ 135 $ (634 ) A reconciliation of the U.S. federal statutory rate of 35% to NRG's effective rate is as follows: Year Ended December 31, 2015 2014 2013 (In millions, except percentages) (Loss)/Income Before Income Taxes $ (5,094 ) $ 135 $ (634 ) Tax at 35% (1,783 ) 47 (222 ) State taxes (218 ) 9 19 Foreign operations 1 1 5 Federal and state tax credits, excluding PTCs (5 ) (1 ) (36 ) Valuation allowance 3,039 6 (5 ) Expiration/utilization of capital losses — — 10 Reversal of valuation allowance on expired/utilized capital losses — — (10 ) Impact of non-taxable equity earnings (10 ) (11 ) (14 ) Book goodwill impairment 340 — — Net interest accrued on uncertain tax positions (3 ) (2 ) (3 ) Production tax credit (33 ) (48 ) (14 ) Recognition of uncertain tax benefits (15 ) (30 ) (11 ) Tax expense attributable to consolidated partnerships 12 4 8 Impact of change in effective state tax rate 19 22 (21 ) Other (2 ) 6 12 Income tax expense/(benefit) $ 1,342 $ 3 $ (282 ) Effective income tax rate (26.3 )% 2.2 % 44.5 % For the year ended December 31, 2015, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to recording of a valuation allowance on the federal and certain state net deferred tax assets that may not be realizable under a “more likely than not” measurement. In addition, a portion of the book goodwill impairment is classified as a permanent reversal impacting the effective tax rate. For the year ended December 31, 2014 , NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the generation of PTCs generated from various wind facilities including assets acquired in the EME transaction, and a benefit resulting from the recognition of uncertain tax benefits, partially offset by state and local income taxes including a change in the effective state rate. For the year ended December 31, 2013 , NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the generation of ITCs from the Company's Agua Caliente solar project in Arizona of $36 million and PTCs generated from certain Gulf Coast wind facilities of $14 million . The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following: As of December 31, 2015 2014 (In millions) Deferred tax liabilities: Emissions allowances $ 31 $ 25 Difference between book and tax basis of property — 127 Derivatives, net 22 320 Goodwill — 202 Cumulative translation adjustments 2 8 Investment in projects 838 849 Intangibles amortization (excluding goodwill) — 99 Other — 2 Total deferred tax liabilities 893 1,632 Deferred tax assets: Deferred compensation, pension, accrued vacation and other reserves 255 266 Discount/premium on notes 68 99 Difference between book and tax basis of property 1,210 — Goodwill 39 — Differences between book and tax basis of contracts 516 531 Pension and other postretirement benefits 218 157 Equity compensation 50 77 Bad debt reserve 6 9 U.S. capital loss carryforwards 1 — U.S. Federal net operating loss carryforwards 1,373 1,523 Foreign net operating loss carryforwards 59 65 State net operating loss carryforwards 230 302 Foreign capital loss carryforwards 1 1 Deferred financing costs 6 23 Federal and state tax credit carryforwards 439 357 Federal benefit on state uncertain tax positions 17 17 Intangibles amortization (excluding goodwill) 90 — Inventory obsolescence 27 29 Other 11 — Total deferred tax assets 4,616 3,456 Valuation allowance (3,575 ) (265 ) Total deferred tax assets, net of valuation allowance 1,041 3,191 Net deferred tax asset $ 148 $ 1,559 The following table summarizes NRG's net deferred tax position: As of December 31, 2015 2014 (In millions) Net deferred tax asset — noncurrent $ 167 $ 1,580 Net deferred tax liability — noncurrent (19 ) (21 ) Net deferred tax asset $ 148 $ 1,559 Deferred tax assets and valuation allowance Net deferred tax balance — As of December 31, 2015 , and 2014 , NRG recorded a net deferred tax asset of $148 million and $1.5 billion , respectively. The Company believes the federal and certain state net deferred tax assets may not be realizable under a “more likely than not” measurement and as such, a valuation allowance has been recorded to reduce the asset accordingly. The Company assesses cumulative and forecasted pretax book earnings, the future reversal of existing taxable temporary differences as well as assumptions and analysis used in assessing certain fixed assets and goodwill impairments during the quarter. Based on the Company's assessment of positive and negative evidence, including available tax planning strategies, NRG believes that it is more likely than not that a benefit will not be realized on $3,575 million and $265 million of tax assets as of December 31, 2015 , and 2014 , respectively, thus a valuation allowance has been recorded. NOL carryforwards — At December 31, 2015 , the Company had tax effected cumulative domestic NOLs consisting of carryforwards for federal income tax purposes of $1.4 billion and state of $230 million . The Company estimates it will need to generate future taxable income to fully realize the net federal deferred tax asset before expiration commencing in 2026. In addition, NRG has cumulative foreign NOL carryforwards of $59 million with no expiration date. Valuation allowance — As of December 31, 2015 , the Company's tax effected valuation allowance was $3,575 million , consisting of domestic federal net deferred tax assets of approximately $2,973 million , domestic state net deferred tax assets of $542 million , foreign net operating loss carryforwards of $59 million and foreign capital loss carryforwards of approximately $1 million . Based upon the assessment of cumulative and forecasted pretax book earnings, the future reversal of existing taxable temporary differences as well as assumptions and analysis used in assessing certain fixed assets and goodwill impairments, it was determined that a valuation allowance was required to be recorded during the quarter. Taxes Receivable and Payable As of December 31, 2015 , NRG recorded a current tax payable of $5 million that represents a tax liability due for domestic state taxes. NRG has a domestic tax receivable of $42 million , of which $13 million relates to federal cash grants applied for eligible solar energy projects, net of sequestration. The remaining balance of $29 million is primarily related to current tax refunds due from the New York State Empire Zone program generated in years 2010 through 2014. Uncertain tax benefits NRG has identified uncertain tax benefits whose after-tax value is $32 million for which, as of December 31, 2015, and 2014, NRG has recorded a non-current tax liability of $35 million and $53 million , respectively. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense. During the year ended December 31, 2015 , the Company recognized a benefit of $5 million in interest and penalties and accrued interest of $2 million . As of December 31, 2015 and 2014 , NRG had cumulative interest and penalties related to these uncertain tax benefits of $3 million and $5 million , respectively. Tax jurisdictions — NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2012. With few exceptions, state and local income tax examinations are no longer open for years before 2009. The following table reconciles the total amounts of uncertain tax benefits: As of December 31, 2015 2014 (In millions) Balance as of January 1 $ 71 $ 115 Increase due to current year positions 4 — Increase due to prior year positions — 10 Decrease due to prior year positions (25 ) (27 ) Decrease due to settlements and payments (18 ) (27 ) Uncertain tax benefits as of December 31 $ 32 $ 71

Stock-Based Compensation (Notes

Stock-Based Compensation (Notes)	12 Months Ended
	Dec. 31, 2015
Share-based Compensation [Abstract]
Stock-Based Compensation	Stock-Based Compensation NRG Energy, Inc. Long-Term Incentive Plan As of December 31, 2015 , and 2014 , a total of 22,000,000 shares of NRG common stock were authorized for issuance under the NRG LTIP, and 5,558,390 shares of NRG common stock were authorized for issuance under the NRG GenOn LTIP. The NRG LTIP and the NRG GenOn LTIP are subject to adjustments in the event of reorganization, recapitalization, stock split, reverse stock split, stock dividend, and a combination of shares, merger or similar change in NRG's structure or outstanding shares of common stock. There were 6,240,648 and 6,184,157 shares of common stock remaining available for grants under the NRG LTIP as of December 31, 2015 , and 2014 , respectively. There were 1,671,633 and 2,150,019 shares of common stock remaining available for grants under the NRG GenOn LTIP as of December 31, 2015 , and 2014 , respectively. Non-Qualified Stock Options NQSOs granted under the NRG LTIP and the NRG GenOn LTIP typically have three -year graded vesting schedules beginning on the grant date and become exercisable at the end of the requisite service period. NRG recognizes compensation costs for NQSOs over the requisite service period for the entire award. The maximum contractual term is 10 years for NRG's outstanding NQSOs. No NQSOs were granted in 2015, 2014 or 2013. The following table summarizes the Company's NQSO activity and changes during the year: Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Term (In years) Aggregate Intrinsic Value (In millions) (In whole) Outstanding at December 31, 2014 2,533,177 $ 30.95 2 $ 9 Forfeited (59,617 ) 35.28 Exercised (401,647 ) 23.23 Outstanding at December 31, 2015 2,071,913 32.27 3 — Exercisable at December 31, 2015 2,071,913 32.27 3 — The following table summarizes the total intrinsic value of options exercised and the cash received from the exercises of options: Year Ended December 31, 2015 2014 2013 (In millions, except for weighted average) Total intrinsic value of options exercised $ 2 $ 7 $ 19 Cash received from options exercised 9 21 33 Restricted Stock Units As of December 31, 2015 , RSUs granted under the Company's LTIPs typically fully vest three years from the date of issuance. Fair value of the RSUs is based on the closing price of NRG common stock on the date of grant. The following table summarizes the Company's non-vested RSU awards and changes during the year: Units Weighted Average Grant-Date Fair Value per Unit (In whole) Non-vested at December 31, 2014 2,674,626 $ 26.15 Granted 741,351 27.31 Forfeited (266,802 ) 27.98 Vested (887,179 ) 23.31 Non-vested at December 31, 2015 2,261,996 27.59 The total fair value of RSUs vested during the years ended December 31, 2015 , 2014 , and 2013 , was $10 million , $26 million and $22 million , respectively. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2015 , 2014 , and 2013 was $27.31 , $29.90 , and $23.37 , respectively. In January 2016, an additional 200,366 restricted stock units were forfeited. Deferred Stock Units DSUs represent the right of a participant to be paid one share of NRG common stock at the end of a deferral period established under the terms of the award. DSUs granted under the Company's LTIPs are fully vested at the date of issuance. Fair value of the DSUs, which is based on the closing price of NRG common stock on the date of grant, is recorded as compensation expense in the period of grant. The following table summarizes the Company's outstanding DSU awards and changes during the year: Units Weighted Average Grant-Date Fair Value per Unit (In whole) Outstanding at December 31, 2014 384,663 $ 21.21 Granted 70,929 25.14 Converted to Common Stock (28,014 ) 24.78 Outstanding at December 31, 2015 427,578 21.88 The aggregate intrinsic values for DSUs outstanding as of December 31, 2015 , 2014 , and 2013 were approximately $5 million , $10 million , and $7 million respectively. The aggregate intrinsic values for DSUs converted to common stock for the years ended December 31, 2015 , 2014 , and 2013 were less than a million, $1 million and $12 million , respectively. The weighted average grant date fair value of DSUs granted during the years ended December 31, 2015 , 2014 , and 2013 was $25.14 , $35.63 and $23.18 , respectively. Market Stock Units MSUs are restricted grants where the quantity of shares increases and decreases alongside the Company's Total Shareholder Return, or TSR. Each MSU represents the potential to receive NRG common stock after the completion of the performance period, typically three years of service from the date of grant. For awards prior to 2014, the number of shares of NRG common stock to be paid (if any) as of the vesting date for each MSU will depend on the TSR. The number of shares of common stock to be paid as of the vesting date for each MSU is equal to: (i) one half of one share of common stock if the TSR has decreased by no more than 50% of the value of the common stock on the date of grant; (ii) one share of common stock, if the TSR equals the value of the common stock on the date of grant; and (iii) two shares of common stock if the TSR is 200% or greater of the value of the common stock on the date of grant. If the TSR is less than 50% of the value of the common stock on the date of grant, no common stock will be paid. If the TSR is between 50% and 200%, shares awarded are interpolated. The value of the common stock on the date of grant is based on the 20-day average of the common stock closing price. For 2014 and future awards, the number of shares of NRG common stock to be paid (if any) as of the vesting date for each MSU will depend on the TSR. The number of shares of common stock to be paid as of the vesting date for each MSU is equal to: (i) three quarters of one share of common stock if the TSR has decreased by no more than 25% of the value of the common stock on the date of grant; (ii) one share of common stock, if the TSR equals the value of the common stock on the date of grant; and (iii) two shares of common stock if the TSR is 200% or greater of the value of the common stock on the date of grant. If the TSR is less than 75% of the value of the common stock on the date of grant, no common stock will be paid. If the TSR is between 75% and 200%, shares awarded are interpolated. The value of the common stock on the date of grant is based on the 20-day average of the common stock closing price. The following table summarizes the Company's non-vested MSU awards and changes during the year: Units Weighted Average Grant-Date Fair Value per Unit (In whole) Non-vested at December 31, 2014 2,304,569 $ 26.13 Granted 1,108,410 26.68 Vested (1,230,410 ) 21.86 Forfeited (202,412 ) 29.44 Non-vested at December 31, 2015 1,980,157 29.54 The weighted average grant date fair value of MSUs granted during the years ended December 31, 2015 , 2014 and 2013 , was $26.68 , $31.90 and $27.46 , respectively. In January 2016, an additional 1,239,829 market stock units were forfeited due to employee terminations and not meeting performance targets. The fair value of MSUs is estimated on the date of grant using a Monte Carlo simulation model and expensed over the service period, which equals the vesting period. Significant assumptions used in the fair value model with respect to the Company's MSUs are summarized below: 2015 2014 Expected volatility 24.08%-25.20% 23.62%-27.43% Expected term (in years) 1-3 3-4 Risk free rate 0.25%-1.07% 0.76%-1.21% For the years ended December 31, 2015 , and 2014 , expected volatility is calculated based on NRG's historical stock price volatility data over the period commensurate with the expected term of the MSU, which equals the vesting period. Supplemental Information The following table summarizes NRG's total compensation expense recognized for the years presented as well as total non-vested compensation costs not yet recognized and the period over which this expense is expected to be recognized as of December 31, 2015 , for each of the five types of awards issued under the LTIPs. Minimum tax withholdings of $21 million , $16 million , and $13 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively, are reflected as a reduction to Additional Paid-in Capital on the Company's Consolidated Balance Sheet and are reflected as operating activities on the Company's Consolidated Statement of Cash Flows. Non-vested Compensation Cost Compensation Expense Unrecognized Total Cost Weighted Average Recognition Period Remaining (In years) Year Ended December 31 As of December 31 Award 2015 2014 2013 2015 2015 (In millions, except weighted average data) NQSOs (a) $ — $ 1 $ 4 $ — — RSUs 23 20 18 26 1.79 DSUs 2 2 2 — — MSUs 16 19 14 12 1.44 PUs (a) — — 2 — — Total $ 41 $ 42 $ 40 $ 38 Tax detriment recognized $ (12 ) $ (8 ) $ (6 ) (a) All NQSOs and PUs granted under the Company's LTIP were fully vested as of December 31, 2015.

Related Party Transactions (Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions The following table summarizes NRG's material related party transactions with affiliates that are included in the Company's operating revenues, operating costs and other income and expense: Year Ended December 31, 2015 2014 2013 (In millions) Revenues from Related Parties Included in Operating Revenues Gladstone $ 4 $ 6 $ 6 GenConn 4 6 5 Total $ 8 $ 12 $ 11 Gladstone — NRG provides services to Gladstone, an equity method investment, under an operations and maintenance agreement. Fees for services under this contract primarily include recovery of NRG's costs of operating the plant as approved in the annual budget, as well as a base monthly fee. GenConn — NRG has O&M agreements with GenConn Devon and GenConn Middletown that began in June 2011. See further discussion in Note 16 , Investments Accounted for by the Equity Method and Variable Interest Entities . Conemaugh and Keystone facilities — The Company operates the Conemaugh and Keystone facilities under five-year agreements that initially expired in December 2015 and were renewed through December 2020 that, subject to certain provisions and notifications, could be terminated annually with one year's notice. The Company is reimbursed by the other owners for the cost of direct services provided to the Conemaugh and Keystone facilities. Additionally, the Company received fees of $11 million during 2015 , $10 million in 2014 , and $10 million in 2013 .

Commitments and Contingencies (

Commitments and Contingencies (Notes)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Operating Lease Commitments Powerton and Joliet Leases The Company leases 100% interests in the Powerton facility and Unit 7 and Unit 8 of the Joliet facility through 2034 and 2030 , respectively, through its indirect subsidiary, Midwest Generation, LLC. The Company accounts for these leases as operating leases and records lease expense on a straight-line basis over the lease term. As further described in Note 3 , Business Acquisitions and Dispositions , in connection with the acquisition of EME, the Company recorded the out-of-market value as a liability in out-of-market contracts of $159 million . The liability will be amortized through rent expense on a straight-line basis over the term of the lease. The Company expects to record lease expense, net of amortization of the out-of-market liability, of approximately $14 million per year through the term of the lease. Future minimum lease commitments under the Powerton and Joliet operating leases for the years ending after December 31, 2015 , are as follows: Period (In millions) 2016 $ 26 2017 1 2018 1 2019 1 2020 1 Thereafter 237 Total $ 267 GenOn Mid-Atlantic Leases The Company leases 100% interests in the Dickerson and Morgantown coal generation units and associated property through 2029 and 2034 , respectively, through its indirect subsidiary, GenOn MidAtlantic, LLC. The Company accounts for these leases as operating leases and records lease expense on a straight-line basis over the lease term. In connection with the acquisition of GenOn, the Company recorded the out-of-market value as a liability in out-of-market contracts of $604 million . The liability is being amortized through rent expense on a straight-line basis over the term of the lease. The Company expects to record lease expense, net of amortization of the out-of-market liability, of approximately $43 million per year through the term of the lease. Future minimum lease commitments under the GenOn Mid-Atlantic operating leases for the years ending after December 31, 2015 , are as follows: Period (In millions) 2016 $ 150 2017 144 2018 105 2019 139 2020 105 Thereafter 442 Total $ 1,085 REMA Leases The Company, through its indirect subsidiary, NRG REMA, LLC, leases a 100% interest in the Shawville coal generation facility through 2026 and leases 16.5% and 16.7% interests in the Keystone and Conemaugh coal generation facilities through 2034, and expects to make payments under the leases through 2029 in accordance with the terms of the leases. The Company accounts for these leases as operating leases and records lease expense on a straight-line basis over the lease term. In connection with the acquisition of GenOn, the Company recorded the out-of-market value as a liability in out-of-market contracts of $186 million . The liability is being amortized through rent expense on a straight-line basis over the term of the lease. The Company expects to record lease expense, net of amortization of the out-of-market liability, of approximately $29 million per year through the term of the lease. In May 2015, NRG mothballed the coal-fired Units 1, 2, 3, and 4 at Shawville generating facility ( 597 MW) and plans to return those units to service no later than the summer of 2016 using natural gas. Under the lease agreement for Shawville, NRG's obligations generally are to pay the required rent and to maintain the leased assets in accordance with the lease documentation, including in compliance with prudent competitive electric generating industry practice and applicable laws. Future minimum lease commitments under the REMA operating leases for the years ending after December 31, 2015 , are as follows: Period (In millions) 2016 $ 61 2017 63 2018 55 2019 65 2020 56 Thereafter 278 Total $ 578 Other Operating Leases NRG leases certain Company facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2044. NRG also has certain tolling arrangements to purchase power, which qualify as operating leases. Certain operating lease agreements include provisions such as scheduled rent increases, leasehold incentives, and rent concessions over their lease term. The Company recognizes the effects of these scheduled rent increases, leasehold incentives, and rent concessions on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Lease expense under operating leases was $100 million , $106 million , and $88 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. Future minimum lease commitments under operating leases for the years ending after December 31, 2015 , are as follows: Period (In millions) 2016 $ 104 2017 79 2018 72 2019 61 2020 56 Thereafter 410 Total (a) $ 782 (a) Amounts in the table exclude future sublease income of $17 million associated with long-term leases for office locations in Texas. Coal, Gas and Transportation Commitments NRG has entered into long-term contractual arrangements to procure fuel and transportation services for the Company's generation assets and for the years ended December 31, 2015 , 2014 , and 2013 , the Company purchased $2.6 billion , $3.5 billion , and $2.8 billion , respectively, under such arrangements. As of December 31, 2015 , the Company's commitments under such outstanding agreements are as follows: Period (In millions) 2016 $ 887 2017 295 2018 261 2019 169 2020 174 Thereafter 549 Total $ 2,335 Purchased Power Commitments NRG has purchased power contracts of various quantities and durations that are not classified as derivative assets and liabilities and do not qualify as operating leases. These contracts are not included in the consolidated balance sheet as of December 31, 2015 . Minimum purchase commitment obligations are as follows as of December 31, 2015 : Period (In millions) 2016 $ 50 2017 17 2018 2 2019 1 2020 — Thereafter — Total (a) $ 70 (a) As of December 31, 2015 , the maximum remaining term under any individual purchased power contract is five years. Lignite Contract with Texas Westmoreland Coal Co. The lignite used to fuel the Gulf Coast region's Limestone facility is obtained from the Jewett mine, a surface mine adjacent to the Limestone facility, under a long-term contract with Texas Westmoreland Coal Co., or TWCC. The contract is based on a cost-plus arrangement with incentives and penalties to ensure proper management of the mine. NRG has the flexibility to increase or decrease lignite purchases from the mine within certain ranges, including the ability to suspend or terminate lignite purchases with adequate notice. The mining period extends through 2018 with an option to further extend the mining period by two five -year intervals. TWCC is responsible for performing ongoing reclamation activities at the mine until all lignite reserves have been produced. When production is completed at the mine, NRG will be responsible for final mine reclamation obligations and maintains an appropriate ARO. The Railroad Commission of Texas has imposed a bond obligation of $107.5 million on TWCC for the reclamation of this lignite mine. Pursuant to the contract with TWCC, NRG supports this obligation as follows: $76 million is guaranteed by NRG Energy, Inc., and $31.5 million is supported by surety bonds posted by NRG. Additionally, NRG is required to provide additional performance assurance over TWCC's current bond obligations if required by the Railroad Commission of Texas. First Lien Structure NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired in the GenOn and EME (including Midwest Generation) acquisitions, assets held by NRG Yield, Inc. and NRG's assets that have project-level financing, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of December 31, 2015 , hedges under the first lien were in-the-money for NRG on a counterparty aggregate basis. Nuclear Insurance STP maintains required insurance coverage for liability claims arising from nuclear incidents pursuant to the Price-Anderson Act. Effective October 22, 2015, the current liability limit per incident is $13.5 billion , subject to change to account for the effects of inflation and the number of licensed reactors. An inflation adjustment must be made at least once every five years with the most recent adjustment effective September 10, 2013. Under the Price-Anderson Act, owners of nuclear power plants in the U.S. are required to purchase primary insurance limits of $375 million for each operating site. In addition, the Price-Anderson Act requires an additional layer of protection through mandatory participation in a retrospective rating plan for power reactors resulting in an additional $13.5 billion in funds available for public liability claims. The current maximum assessment per incident, per reactor, is approximately $127 million , taking into account a 5% adjustment for administrative fees, payable at approximately $19 million per year, per reactor. NRG would be responsible for 44% of the maximum assessment, or $8 million per year, per reactor, and a maximum of $112 million per incident. In addition, the U.S. Congress retains the ability to impose additional financial requirements on the nuclear industry to pay liability claims that exceed $13.5 billion for a single incident. The liabilities of the co-owners of STP with respect to the retrospective premium assessments for nuclear liability insurance are joint and several. STP purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Limited, or NEIL, an industry mutual insurance company, of which STP is a member. STP has purchased $2.75 billion in limits for nuclear events and $1.5 billion in limits for non-nuclear events, the maximum available from NEIL. The upper $1.25 billion in limits (excess of the first $1.5 billion in limits) is a single limit blanket policy shared with two Diablo Canyon nuclear reactors, which have no affiliation with the Company. This shared limit is not subject to automatic reinstatement in the event of a loss. The NEIL policy covers both nuclear and non-nuclear property damage events, and a NEIL companion policy provides Accidental Outage coverage for the co-owners of STP's lost revenue following a property damage event, at a weekly indemnity limit of $2.52 million per unit up to a maximum of $274.4 million nuclear and $183.5 million non-nuclear, and is subject to an eight-week waiting period. NRG also purchased an Accidental Outage policy from NEIL, which provides protection for lost revenue due to an insurable event. This coverage allows for reimbursement up to $1.98 million per week per unit up to a maximum of $215.6 million nuclear and $144 million non-nuclear, and is subject to an eight-week waiting period. Under the terms of the NEIL policies, member companies may be assessed up to ten times their annual premium if the NEIL Board of Directors determines their surplus has been depleted due to the payment of property losses at any of the licensed reactors in a single policy year. NEIL requires that its members maintain an investment grade credit rating or insure their annual retrospective obligation by providing a financial guarantee, letter of credit, deposit premium, or an insurance policy. NRG has purchased an insurance policy from NEIL to guarantee the Company's obligation; however this insurance will only respond to retrospective premium adjustments assessed within twenty-four months after the policy term, whereas NEIL's Board of Directors can make such an adjustment up to 6 years after the policy expires. Ivanpah Energy Production Guarantee The Company's PPAs with PG&E with respect to the Ivanpah project contain provisions for contract quantity and guaranteed energy production, which require that Ivanpah units 1 and 3 deliver to PG&E no less than the guaranteed energy production amount specified in the PPAs in any period of twenty-four consecutive months, or performance measurement period, during the term of the PPAs. If either of Ivanpah units 1 and 3 deliver less than the guaranteed energy production amount in any performance measurement period, PG&E may, at its option, declare an event of default. The two units did not meet their guaranteed energy production amount for the initial performance measurement period. On December 18, 2015, PG&E filed a request with the CPUC that it approve, no later than March 31, 2016, forbearance agreements relating to Ivanpah units 1 and 3. Under the forbearance agreements, PG&E agrees to refrain from taking certain actions (including declaring an event of default and invoking associated remedies) for an initial six-month period of time. If the units meet certain production requirements during such period, then the forbearance agreements provide for a six-month extension of such period. On January 15, 2016, three parties submitted protests to the forbearance agreements. On February 16, 2016, the CPUC issued a draft resolution recommending approval of the Forbearance Agreement. The CPUC will vote on the draft resolution no earlier than 30 days after its issuance. Contingencies The Company's material legal proceedings are described below. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material. In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows. Midwest Generation Asbestos Liabilities — The Company, through its subsidiary, Midwest Generation, may be subject to potential asbestos liabilities as a result of its acquisition of EME. The Company is currently analyzing the scope of potential liability as it may relate to Midwest Generation. The Company believes that it has established an adequate reserve for these cases. Actions Pursued by MC Asset Recovery — With Mirant Corporation's emergence from bankruptcy protection in 2006, certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings. MC Asset Recovery is governed by a manager who is independent of NRG and GenOn. MC Asset Recovery is a disregarded entity for income tax purposes. Under the remaining action transferred to MC Asset Recovery, MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks, or the Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to Mirant's bankruptcy proceedings. In December 2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants. In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank Defendants to the U.S. Court of Appeals for the Fifth Circuit. In March 2012, the Court of Appeals reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants. On December 10, 2015, the District Court granted the Commerzbank Defendants' motion for summary judgment. On December 29, 2015, MC Asset Recovery filed a notice to appeal this ruling. If MC Asset Recovery succeeds in obtaining any recoveries from the Commerzbank Defendants, the Commerzbank Defendants have asserted that they will seek to file claims in Mirant's bankruptcy proceedings for the amount of those recoveries. GenOn Energy Holdings would vigorously contest the allowance of any such claims. If the Commerzbank Defendants were to receive an allowed claim as a result of a recovery by MC Asset Recovery on its claims against them, GenOn Energy Holdings would retain from the net amount recovered by MC Asset Recovery an amount equal to the dollar amount of the resulting allowed claim. Natural Gas Litigation — GenOn is party to several lawsuits, certain of which are class action lawsuits, in state and federal courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in 2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of state antitrust law and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name as parties a number of energy companies unaffiliated with NRG. In July 2011, the U.S. District Court for the District of Nevada, which was handling four of the five cases, granted the defendants' motion for summary judgment and dismissed all claims against GenOn in those cases. The plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit which reversed the decision of the District Court. GenOn along with the other defendants in the lawsuit filed a petition for a writ of certiorari to the U.S. Supreme Court challenging the Court of Appeals' decision and the Supreme Court granted the petition. On April 21, 2015, the Supreme Court affirmed the Ninth Circuit’s holding that plaintiffs’ state antitrust law claims are not field-preempted by the federal Natural Gas Act and the Supremacy Clause of the U.S. Constitution. The Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The U.S. Supreme Court directed that the case be remanded to the U.S. District Court for the District of Nevada. The case is proceeding in that court. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits. In September 2012, the State of Nevada Supreme Court, which was handling the remaining case, affirmed dismissal by the Eighth Judicial District Court for Clark County, Nevada of all plaintiffs' claims against GenOn. In February 2013, the plaintiffs in the Nevada case filed a petition for a writ of certiorari to the U.S. Supreme Court. In June 2013, the Supreme Court denied the petition for a writ of certiorari, thereby ending one of the five lawsuits. Energy Plus Holdings — On August 7, 2012, Energy Plus Holdings received a subpoena from the NYAG which generally sought information and business records related to Energy Plus Holdings' sales, marketing and business practices. Energy Plus Holdings provided documents and information to the NYAG. On June 22, 2015, the NYAG issued another subpoena seeking additional information. Energy Plus Holdings is responding to this second subpoena. The Company does not expect the resolution of this matter to have a material impact on the Company's consolidated financial position, results of operations, or cash flows. Maryland Department of the Environment v. GenOn Chalk Point and GenOn Mid-Atlantic — On January 25, 2013, Food & Water Watch, the Patuxent Riverkeeper and the Potomac Riverkeeper (together, the Citizens Group) sent GenOn Mid-Atlantic a letter alleging that the Chalk Point, Dickerson and Morgantown generating facilities were violating the terms of the three National Pollution Discharge Elimination System permits by discharging nitrogen and phosphorous in excess of the limits in each permit. On March 21, 2013, the MDE sent GenOn Mid-Atlantic a similar letter with respect to the Chalk Point and Dickerson generating facilities, threatening to sue within 60 days if the generating facilities were not brought into compliance. On June 11, 2013, the Maryland Attorney General on behalf of the MDE filed a complaint in the U.S. District Court for the District of Maryland alleging violations of the CWA and Maryland environmental laws related to water. The lawsuit is ongoing and seeks injunctive relief and civil penalties in excess of $100,000 . The Company does not expect the resolution of this matter to have a material impact on the Company's consolidated financial position, results of operations, or cash flows. Midwest Generation New Source Review Litigation — In August 2009, the EPA and the Illinois Attorney General, or the Government Plaintiffs, filed a complaint, or the Governments’ Complaint, in the U.S. District Court for the Northern District of Illinois alleging violations of CAA PSD requirements by Midwest Generation arising from maintenance, repair or replacement projects at six Illinois coal-fired electric generating stations performed by Midwest Generation or ComEd, a prior owner of the stations, including alleged failures to obtain PSD construction permits and to comply with BACT requirements. The Government Plaintiffs also alleged violations of opacity and PM standards at the Midwest Generation plants. Finally, the Government Plaintiffs alleged that Midwest Generation violated certain operating permit requirements under Title V of the CAA allegedly arising from such claimed PSD, opacity and PM emission violations. In addition to seeking penalties of up to $37,500 per violation, per day, the complaint seeks an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at the units subject to the complaint and other remedies, which could go well beyond the requirements of the CPS. Several environmental groups intervened as plaintiffs in this litigation and filed a complaint, or the Intervenors’ Complaint, which alleged opacity, PM and related Title V violations. Midwest Generation filed a motion to dismiss nine of the ten PSD counts in the Governments’ Complaint, and to dismiss the tenth PSD count to the extent the Governments’ Complaint sought civil penalties for that count. The trial court granted the motion in March 2010. In June 2010, the Government Plaintiffs and Intervenors each filed an amended complaint. The Governments’ Amended Complaint again alleged that Midwest Generation violated PSD (based upon the same projects as alleged in their original complaint, but adding allegations that the Company was liable as the “successor” to ComEd), Title V and opacity and PM standards. It named EME and ComEd as additional defendants and alleged PSD violations (again, premised on the same projects) against them. The Intervenors’ Amended Complaint named only Midwest Generation as a defendant and alleged Title V and opacity/PM violations, as well as one of the ten PSD violations alleged in the Governments’ Amended Complaint. Midwest Generation again moved to dismiss all but one of the Government Plaintiffs’ PSD claims and the related Title V claims. Midwest Generation also filed a motion to dismiss the PSD claim in the Intervenors’ Amended Complaint and the related Title V claims. In March 2011, the trial court granted Midwest Generation’s partial motion to dismiss the Government Plaintiffs’ PSD claims. The trial court denied Midwest Generation’s motion to dismiss the PSD claim asserted in the Intervenors’ Amended Complaint, but noted that the plaintiffs would be required to convince the court that the statute of limitations should be equitably tolled. The trial court did not address other counts in the amended complaints that allege violations of opacity and PM emission limitations under the Illinois State Implementation Plan and related Title V claims. The trial court also granted the motions to dismiss the PSD claims asserted against EME and ComEd. Following the trial court ruling, the Government Plaintiffs appealed the trial court’s dismissals of their PSD claims, including the dismissal of nine of the ten PSD claims against Midwest Generation and of the PSD claims against the other defendants. Those PSD claim dismissals were affirmed by the U.S. Court of Appeals for the Seventh Circuit in July 2013. In addition, in 2012, all but one of the environmental groups that had intervened in the case dismissed their claims without prejudice. As a result, only one environmental group remains a plaintiff intervenor in the case. The Company does not expect the resolution of this matter to have a material impact on the Company’s consolidated financial position, results of operations or cash flows. Potomac River Environmental Investigation — In March 2013, NRG Potomac River LLC received notice that the District of Columbia Department of Environment (now renamed the Department of Energy and Environment, or DOEE) was investigating potential discharges to the Potomac River originating from the Potomac River Generating facility site, a site where the generation facility is no longer in operation. In connection with that investigation, DOEE served a civil subpoena on NRG Potomac River LLC requesting information related to the site and potential discharges occurring from the site. NRG Potomac River LLC provided various responsive materials. In January 2016, DOEE advised NRG Potomac River that DOEE believed various environmental violations had occurred as a result of discharges DOEE believes occurred to the Potomac River from the Potomac River Generating facility site and as a result of associated failures to accurately or sufficiently report such discharges. DOEE has indicated it believes that penalties are appropriate in light of the violations. NRG is currently reviewing the information provided by DOEE. Telephone Consumer Protection Act Purported Class Actions — Three purported class action lawsuits have been filed against NRG Residential Solar Solutions, LLC, one in California and two in New Jersey. The plaintiffs generally allege misrepresentation by the call agents and violations of the TCPA, claiming that the defendants engaged in a telemarketing campaign placing unsolicited calls to individuals on the “Do Not Call List.” The plaintiffs seek statutory damages of up to $1,500 per plaintiff, actual damages and equitable relief. The Company is vigorously defending against these lawsuits. NRG requested and was granted a stay in the California case and one of the New Jersey cases pending a decision of an unrelated case by the U.S. Supreme Court, the results of which could materially affect these lawsuits. El Segundo Environmental Liability — During the maintenance of breakers in 2012, the Company’s El Segundo plant exceeded California’s limit regarding SF6 losses. SF6 is an electrical insulator and GHG. On December 16, 2015, the Company entered into a settlement agreement with the California Air Resources Board thereby resolving the matter. Pursuant to the settlement agreement, the Company agreed to pay a penalty of $150,000 plus an additional $50,000 directed to clean air/clear air funding for a community college system. California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC — On January 29, 2016, CDWR and SDG&E filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation. In June 2001, CDWR and Sunrise entered into a 10-year PPA under which Sunrise would construct and operate a generating facility and provide power to CDWR. At the time the PPA was entered into, Sunrise had a transportation services agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018. In August 2003, CDWR entered into an agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA. After the PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise did not. As such, the plaintiffs have brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good faith and fair dealing and improper distributions. Plaintiffs generally claim damages of $1.2 million per month for the remaining 70 months of the TSA.

Regulatory Matters (Notes)

Regulatory Matters (Notes)	12 Months Ended
	Dec. 31, 2015
Regulatory Matters Disclosure [Abstract]
Regulatory Matters	Regulatory Matters NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail businesses. In addition to the regulatory proceedings noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows. National U.S. Supreme Court Agrees to Consider the Constitutionality of Maryland's Generator Contracting Programs — On October 19, 2015, the U.S. Supreme Court agreed to hear a case challenging the constitutionality of certain state-directed procurements of new electric generating facilities. The case involves the authority of the Maryland Public Service Commission to direct load-serving utilities in the state to enter into long-term power purchase contracts with a generation developer to encourage the construction of new generation capacity in Maryland. The constitutionality of the long-term contracts was challenged in the U.S. District Court for the District of Maryland, which, in an October 24, 2013, decision, found that the contracts violated the Supremacy Clause of the U.S. Constitution because they were both conflict preempted and field preempted by the FPA and the authority that the FPA granted to FERC. On June 30, 2014, the U.S. Court of Appeals for the Fourth Circuit affirmed the District Court's decision. A case arising out of New Jersey and raising similar issues was decided by the U.S. Court of Appeals for the Third Circuit, which also determined that the state-mandated contracts were preempted. After the Supreme Court granted certiorari in the Maryland case, the Company filed a friend-of-the-court brief urging the Court to uphold the right of states to incentivize new generation by directing utilities in the state to enter into long-term contracts — but noted that FERC has both the authority and the statutory obligation to protect wholesale markets by requiring that bids in the wholesale markets reflect costs and by ensuring that uneconomic entry does not distort auction outcomes. The Supreme Court heard oral argument on February 24, 2016. The outcome of this litigation could have broad impacts on whether and how states require utilities to contract with new generation resources, as well as how such contracted resources interact with the FERC-jurisdictional wholesale markets. U.S. Supreme Court Allows FERC to Retain Jurisdiction Over Demand Response — On January 25, 2016, the U.S. Supreme Court issued a 6-2 decision affirming FERC’s ability to exercise jurisdiction over demand response resources seeking to voluntarily participate in the wholesale markets. Additionally, the Supreme Court upheld FERC’s preferred scheme for pricing demand response in the energy market. This case arose out of a May 23, 2014, decision by the D.C. Circuit which vacated FERC’s rules (known as Order No. 745) that set the compensation level for demand response resources participating in the FERC-jurisdictional energy markets. The Court of Appeals had held that the FPA does not authorize FERC to exercise jurisdiction over demand response and that instead demand response is part of the retail market over which the states have jurisdiction. With the Supreme Court’s decision, FERC will resume exercising jurisdiction over demand response, which the Company views as a positive for both its wholesale and distributed businesses. East Region Montgomery County Station Power Tax — On December 20, 2013, the Company received a letter from Montgomery County, Maryland requesting payment of an energy tax for the consumption of station power at the Dickerson Facility over the previous three years. Montgomery County seeks payment in the amount of $22 million , which includes tax, interest and penalties. The Company disputed the applicability of the tax. On December 11, 2015, the Maryland Tax Court reversed Montgomery County's assessment. Montgomery County has filed an appeal. Retail MISO SECA — Green Mountain Energy previously provided competitive retail energy supply in the MISO region during the period of January 1, 2002, to December 31, 2005. By order dated November 18, 2004, FERC eliminated certain regional through-and-out transmission rates charged by transmission owners in MISO and PJM. In order to temporarily compensate the transmission owners for lost revenues, FERC ordered MISO, PJM and their respective transmission owners to eliminate seams charges and in the meantime, as a temporary measure, allowed them to recover transition charges known as SECA charges. The tariff amendments filed by MISO and the MISO transmission owners allocated certain SECA charges to various zones and sub-zones within MISO, including a sub-zone called the Green Mountain Energy Company Sub-zone. During several years of extensive litigation before FERC, several transmission owners sought to recover SECA charges from Green Mountain Energy. Green Mountain Energy denied responsibility for any SECA charges and did not pay any asserted SECA charges. On May 21, 2010, FERC issued two orders, including its Order on Initial Decision, in which FERC determined that approximately $22 million plus interest of SECA charges were owed not by Green Mountain Energy but rather by BP Energy — one of Green Mountain Energy's suppliers during the period at issue. On August 19, 2010, the transmission owners and MISO made compliance filings in accordance with FERC's Orders allocating SECA charges to a BP Energy Sub-zone, and making no allocation to a Green Mountain Energy Sub-zone. On September 16, 2015, FERC issued an order conditionally accepting those compliance filings, and setting for hearing and settlement proceedings issues related to service to certain Michigan customers during 2002 and 2003. On September 30, 2011, FERC issued orders denying all requests for rehearing and again determined that SECA charges were not owed by Green Mountain Energy. Numerous parties, including BP Energy, sought judicial review of FERC's orders, and Green Mountain Energy was granted intervenor status in the consolidated appeals. Most appellants subsequently settled with the transmission owners and withdrew their appeals, including BP Energy, which agreed to pay approximately $24 million to the three transmission owners signing the agreement, with another $1 million offered to the remaining PJM transmission owners, should they choose to join the settlement; all chose to do so. FERC approved the settlement, and BP Energy moved to dismiss its appeals; its motions to dismiss were granted by the Court. West Region Carlsbad Energy Center — On May 21, 2015, the CPUC approved the Carlsbad Energy Center PPTA for a nominally rated 500 MW five unit natural gas peaking plant. On December 7, 2015, three parties filed two petitions for a writ of review with the California Court of Appeal appealing the CPUC's decision. The petitions remain pending. Additionally, on July 30, 2015, the CEC approved an amendment to the design of the Carlsbad Energy Center. On September 22, 2015, the CEC granted rehearing of its decision approving the amendment to permit the California Department of Fish and Wildlife, or CDFW, to file comments on the proposed decision. On November 12, 2015, the CEC issued an order on rehearing affirming its decision approving the amendment. No party appealed the CEC's decision. California Station Power — As the result of unfavorable final and non-appealable litigation, the Company has accrued a liability associated with its power plants’ consumption of station power in California, after August 30, 2010. The majority of the liability is associated with the Company's Encina, El Segundo, and Long Beach facilities. The Company has established an appropriate reserve and is awaiting final billing decisions from SCE.

Environmental Matters (Notes)

Environmental Matters (Notes)	12 Months Ended
	Dec. 31, 2015
Environmental Matters Disclosure [Abstract]
Environmental Matters	Environmental Matters NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. Environmental laws have become increasingly stringent and NRG expects this trend to continue. The electric generation industry is facing new requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose certain restrictions on the operations of the Company's facilities, which could have a material effect on the Company's operations. The EPA finalized CSAPR in 2011, which was intended to replace CAIR in January 2012, to address certain states' obligation to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011, the D.C. Circuit stayed the implementation of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On July 28, 2015, the D.C. Circuit held that the EPA had exceeded its authority by requiring certain reductions that were not necessary for downwind states to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPA to revise the Phase 2 (or 2017) (i) SO 2 budgets for four states including Texas and (ii) ozone-season NO x budgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. The EPA is currently reviewing the decision. In December 2015, the EPA proposed the CSAPR Update Rule using the 2008 Ozone NAAQS, which would reduce the total amount of ozone season NO x as compared with the previously utilized 1997 Ozone NAAQS. If finalized, this proposal would reduce future NO x allocations and/or current banked allowances. While NRG cannot predict the final outcome of this rulemaking, the Company believes its investment in pollution controls and cleaner technologies leave the fleet well-positioned for compliance. In February 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which limits had to be met beginning in April 2015 (with some units getting a 1-year extension). In June 2015, the U.S. Supreme Court issued a decision in the case of Michigan v. EPA , and held that the EPA unreasonably refused to consider costs when it determined that it was "appropriate and necessary" to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not vacate the MATS rule but rather remanded it to the D.C. Circuit for further proceedings. In November 2015, the EPA proposed a supplemental finding that including a consideration of cost does not alter the EPA's previous determination that it is appropriate and necessary to regulate air toxics, including mercury from power plants. In December 2015, the D.C. Circuit remanded the rule to the EPA without vacatur. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule. Water In August 2014, the EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the next several years as NPDES permits are renewed. Byproducts, Wastes, Hazardous Materials and Contamination In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. The Company has evaluated the impact of the new rule on its results of operations, financial condition and cash flows and has accrued its environmental and asset retirement obligations under the rule based on current estimates as of December 31, 2015. East Region Maryland Environmental Regulations — In December 2014, MDE proposed a regulation regarding NO x emissions from coal-fired electric generating units, which had it been finalized would have required by 2020 the Company (at each of the three Dickerson coal-fired units and the Chalk Point coal-fired unit that does not have an SCR) to either (1) install and operate an SCR; (2) retire the unit; or (3) convert the fuel source from coal to natural gas. In early 2015, the State of Maryland decided not to finalize the regulation as proposed. In November 2015, MDE finalized revised regulations to address future NO x reductions, which although more stringent than previous regulations, will not cause the Company to spend capital to comply. As a result of the new regulations, on February 29, 2016, NRG notified PJM that it was withdrawing the standing deactivation notices for Dickerson Units 1, 2 and 3 and Chalk Point Units 1 and 2. New Source Review — The EPA and various states are investigating compliance of electric generating facilities with the pre-construction permitting requirements of the CAA known as “new source review,” or NSR. In 2007, Midwest Generation received an NOV from the EPA alleging that past work at Crawford, Fisk, Joliet, Powerton, Waukegan and Will County generating stations violated NSR and other regulations. These alleged violations are the subject of the litigation described in Item 15 — Note 22, Commitments and Contingencies . In January 2009, GenOn received an NOV from the EPA alleging that past work at Keystone, Portland and Shawville generating stations violated regulations regarding NSR. In June 2011, GenOn received an NOV from the EPA alleging that past work at Avon Lake and Niles generating stations violated NSR. In December 2007, the NJDEP filed suit alleging that NSR violations occurred at the Portland generating station, which suit was resolved pursuant to a July 2013 consent decree. Additionally, in April 2013, the Connecticut Department of Energy and Environmental Protection issued four NOVs alleging that past work at oil-fired combustion turbines at the Torrington Terminal, Franklin, Branford and Middletown generation stations violated regulations regarding NSR. Burton Island Old Ash Landfill — In January 2006, NRG's Indian River Power LLC was notified that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself required a Remedial Investigation and Feasibility Study to determine the type and scope of any additional required work. The DNREC approved the Feasibility Study in December 2012. In January 2013, DNREC proposed a remediation plan based on the Feasibility Study. The remediation plan was approved in October 2013. The cost of completing the work required by the approved remediation plan is consistent with amounts previously budgeted. On May 29, 2008, DNREC requested that NRG's Indian River Power LLC participate in the development and performance of a Natural Resource Damage Assessment at the Burton Island Old Ash Landfill. NRG is currently working with DNREC and other trustees to close out the assessment process. For further discussion of these matters, refer to Note 22 , Commitments and Contingencies . Environmental Capital Expenditures NRG estimates that environmental capital expenditures from 2016 through 2020 required to comply with environmental laws will be approximately $350 million , which includes $68 million for GenOn and $263 million for Midwest Generation. These costs, the majority of which will be expended by the end of 2016, are primarily associated with (i) DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion to satisfy the IL CPS and (ii) MATS compliance at the Avon Lake facility.

Cash Flow Information (Notes)

Cash Flow Information (Notes)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Cash Flow Information	Cash Flow Information Detail of supplemental disclosures of cash flow and non-cash investing and financing information was: Year Ended December 31, 2015 2014 2013 (In millions) Interest paid, net of amount capitalized $ 1,172 $ 1,067 $ 836 Income taxes (refunded)/paid (a) 16 (6 ) (60 ) Consent fee paid, preferred stock — 5 — Non-cash investing and financing activities: (Decrease)/additions to fixed assets for accrued capital expenditures (24 ) 87 405 Decrease to fixed assets for accrued grants and related tax impact — (711 ) (681 ) Issuance of shares for EME acquisition — (401 ) — (a) In 2015 , the net income taxes paid reflect $17 million in income taxes paid and $1 million in income tax refunds. In 2014 , the net income taxes refunded are net of $15 million income taxes paid and $21 million income tax refunds. In 2013 , the net income taxes refunded are net of $28 million income taxes paid and $87 million income tax refunds.

Guarantees (Notes)

Guarantees (Notes)	12 Months Ended
	Dec. 31, 2015
Guarantees [Abstract]
Guarantees	Guarantees NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of the Company's business activities. Examples of these contracts include asset purchases and sale agreements, commodity sale and purchase agreements, retail contracts, joint venture agreements, EPC agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. The Company is obligated with respect to customer deposits associated with the Company's retail businesses. NRG has also assumed guarantees for some non-qualified benefits of existing retirees resulting from the acquisition of GenOn. In some cases, NRG's maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential liability. In accordance with ASC 460, Guarantees , or ASC 460, NRG has estimated that the current fair value for issuing these guarantees was $3.6 million as of December 31, 2015 , and the liability in this amount is included in the Company's non-current liabilities. The following table summarizes the maximum potential exposures that can be estimated for NRG's guarantees, indemnities, and other contingent liabilities by maturity: By Remaining Maturity at December 31, 2015 Guarantees Under 1 Year 1-3 Years 3-5 Years Over 5 Years Total 2014 Total (In millions) Letters of credit and surety bonds $ 1,805 $ 92 $ — $ 2 $ 1,899 $ 1,914 Asset sales guarantee obligations — — 257 — 257 292 Other guarantees — 1 — 721 722 1,174 Total guarantees $ 1,805 $ 93 $ 257 $ 723 $ 2,878 $ 3,380 Letters of credit and surety bonds — As of December 31, 2015 , NRG and its consolidated subsidiaries were contingently obligated for a total of $1.9 billion under letters of credit and surety bonds. Most of these letters of credit and surety bonds are issued in support of the Company's obligations to perform under commodity agreements and obligations associated with future closure and maintenance of ash sites, as well as for financing or other arrangements. A majority of these letters of credit and surety bonds expire within one year of issuance, and it is typical for the Company to renew them on similar terms. The material indemnities, within the scope of ASC 460, are as follows: Asset sales — The purchase and sale agreements which govern NRG's asset or share investments and divestitures customarily contain guarantees and indemnifications of the transaction to third parties. The contracts indemnify the parties for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party, or as a result of a change in tax laws. These obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or estimate at the time of the transaction. In several cases, the contract limits the liability of the indemnifier. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations. Other guarantees — NRG has issued other guarantees of obligations including payments under certain agreements with respect to certain of its unconsolidated subsidiaries, payment or performance by fuel providers and payment or reimbursement of credit support and deposits. The Company does not believe that it will be required to perform under these guarantees. Other indemnities — Other indemnifications NRG has provided cover operational, tax, litigation and breaches of representations, warranties and covenants. NRG has also indemnified, on a routine basis in the ordinary course of business, consultants or other vendors who have provided services to the Company. NRG's maximum potential exposure under these indemnifications can range from a specified dollar amount to an indeterminate amount, depending on the nature of the transaction. Total maximum potential exposure under these indemnifications is not estimable due to uncertainty as to whether claims will be made or how they will be resolved. NRG does not have any reason to believe that the Company will be required to make any material payments under these indemnity provisions. Because many of the guarantees and indemnities NRG issues to third parties and affiliates do not limit the amount or duration of its obligations to perform under them, there exists a risk that the Company may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit the Company's liability exposure, it may not be able to estimate what the Company's liability would be, until a claim is made for payment or performance, due to the contingent nature of these contracts.

Jointly Owned Plants (Notes)

Jointly Owned Plants (Notes)	12 Months Ended
	Dec. 31, 2015
Jointly Owned Plants Disclosure [Abstract]
Jointly Owned Plants	Jointly Owned Plants Certain NRG subsidiaries own undivided interests in jointly-owned plants, as described below. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. NRG is responsible for its subsidiaries' share of operating costs and direct expenses and includes its proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of the Company's consolidated financial statements. The following table summarizes NRG's proportionate ownership interest in the Company's jointly-owned facilities: As of December 31, 2015 Ownership Interest Property, Plant & Equipment Accumulated Depreciation Construction in Progress (In millions unless otherwise stated) South Texas Project Units 1 and 2, Bay City, TX 44.00 % $ 3,246 $ (1,599 ) $ 38 Big Cajun II Unit 3, New Roads, LA 58.00 % 206 (114 ) — Cedar Bayou Unit 4, Baytown, TX 50.00 % 211 (57 ) — Keystone, Shelocta, PA 3.70 % 97 (44 ) — Conemaugh, New Florence, PA 3.72 % 101 (46 ) 1

Unaudited Quarterly Financial D

Unaudited Quarterly Financial Data (Notes)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Unaudited Quarterly Financial Data	Unaudited Quarterly Financial Data Refer to Note 3 , Business Acquisitions and Dispositions , and Note 10 , Asset Impairments , for a description of the effect of unusual or infrequently occurring events during the quarterly periods. Summarized unaudited quarterly financial data is as follows: Quarter Ended 2015 December 31 September 30 June 30 March 31 (In millions, except per share data) Operating revenues $ 3,011 $ 4,434 $ 3,400 $ 3,829 Operating (loss)/income (4,727 ) 379 232 76 Net (loss)/income (6,358 ) 67 (9 ) (136 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests (44 ) 1 5 (16 ) Net (loss)/income attributable to NRG Energy, Inc. (6,314 ) 66 (14 ) (120 ) (Loss)/income available to Common Stockholders $ (6,319 ) $ 61 $ (19 ) $ (125 ) Weighted average number of common shares outstanding — basic 315 331 333 336 Net (loss)/income per weighted average common share — basic $ (20.08 ) $ 0.18 $ (0.06 ) $ (0.37 ) Weighted average number of common shares outstanding — diluted 315 332 333 336 Net (loss)/income per weighted average common share — diluted $ (20.08 ) $ 0.18 $ (0.06 ) $ (0.37 ) Quarter Ended 2014 December 31 September 30 June 30 March 31 (In millions, except per share data) Operating revenues $ 4,192 $ 4,569 $ 3,621 $ 3,486 Operating income 453 549 89 180 Net income/(loss) 97 182 (80 ) (67 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests (22 ) 14 17 (11 ) Net income/(loss) attributable to NRG Energy, Inc. 119 168 (97 ) (56 ) Income/(loss) available to Common Stockholders $ 70 $ 166 $ (100 ) $ (58 ) Weighted average number of common shares outstanding — basic 338 338 337 324 Net income/(loss) per weighted average common share — basic $ 0.21 $ 0.49 $ (0.30 ) $ (0.18 ) Weighted average number of common shares outstanding — diluted 342 343 337 324 Net income/(loss) per weighted average common share — diluted $ 0.20 $ 0.48 $ (0.30 ) $ (0.18 )

Condensed Consolidating Financi

Condensed Consolidating Financial Information (Notes)	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	Condensed Consolidating Financial Information As of December 31, 2015 , the Company had outstanding $6.2 billion of Senior Notes due 2018 - 2024, as shown in Note 12 , Debt and Capital Leases . These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries. These guarantees are both joint and several. The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries, including GenOn and its subsidiaries, and NRG Yield , Inc. and its subsidiaries Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of December 31, 2015 : Ace Energy, Inc. NEO Freehold-Gen LLC NRG Operating Services, Inc. Allied Warranty LLC NEO Power Services Inc. NRG Oswego Harbor Power Operations Inc. Arthur Kill Power LLC New Genco GP, LLC NRG PacGen Inc. Astoria Gas Turbine Power LLC Norwalk Power LLC NRG Portable Power LLC Bayou Cove Peaking Power LLC NRG Affiliate Services Inc. NRG Power Marketing LLC BidURenergy, Inc. NRG Artesian Energy LLC NRG Reliability Solutions LLC Cabrillo Power I LLC NRG Arthur Kill Operations Inc. NRG Renter's Protection LLC Cabrillo Power II LLC NRG Astoria Gas Turbine Operations Inc. NRG Retail LLC Carbon Management Solutions LLC NRG Bayou Cove LLC NRG Retail Northeast LLC Cirro Group, Inc. NRG Business Solutions LLC NRG Rockford Acquisition LLC Cirro Energy Services, Inc. NRG Cabrillo Power Operations Inc. NRG Saguaro Operations Inc. Clean Edge Energy LLC NRG California Peaker Operations LLC NRG Security LLC Conemaugh Power LLC NRG Cedar Bayou Development Company, LLC NRG Services Corporation Connecticut Jet Power LLC NRG Connected Home LLC NRG SimplySmart Solutions LLC Cottonwood Development LLC NRG Connecticut Affiliate Services Inc. NRG South Central Affiliate Services Inc. Cottonwood Energy Company LP NRG Construction LLC NRG South Central Generating LLC Cottonwood Generating Partners I LLC NRG Curtailment Solutions LLC NRG South Central Operations Inc. Cottonwood Generating Partners II LLC NRG Development Company Inc. NRG South Texas LP Cottonwood Generating Partners III LLC NRG Devon Operations Inc. NRG Texas C&I Supply LLC Cottonwood Technology Partners LP NRG Dispatch Services LLC NRG Texas Gregory LLC Devon Power LLC NRG Distributed Generation PR LLC NRG Texas Holding Inc. Dunkirk Power LLC NRG Dunkirk Operations Inc. NRG Texas LLC Eastern Sierra Energy Company LLC NRG El Segundo Operations Inc. NRG Texas Power LLC El Segundo Power, LLC NRG Energy Efficiency-L LLC NRG Warranty Services LLC El Segundo Power II LLC NRG Energy Efficiency-P LLC NRG West Coast LLC Energy Alternatives Wholesale, LLC NRG Energy Labor Services LLC NRG Western Affiliate Services Inc. Energy Choice Solutions, LLC NRG ECOKAP Holdings, LLC O'Brien Cogeneration, Inc. II NRG Curtailment Solutions, Inc. NRG Energy Services Group LLC ONSITE Energy, Inc. Energy Plus Holdings LLC NRG Energy Services International Inc. Oswego Harbor Power LLC Energy Plus Natural Gas LLC NRG Energy Services LLC RE Retail Receivables, LLC Energy Protection Insurance Company NRG Generation Holdings, Inc. Reliant Energy Northeast LLC Everything Energy LLC NRG Home & Business Solutions LLC Reliant Energy Power Supply, LLC Forward Home Security, LLC NRG Home Solutions LLC Reliant Energy Retail Holdings, LLC GCP Funding Company, LLC NRG Home Solutions Product LLC Reliant Energy Retail Services, LLC Green Mountain Energy Company NRG Homer City Services LLC RERH Holdings LLC Gregory Partners, LLC NRG Huntley Operations Inc. Saguaro Power LLC Gregory Power Partners LLC NRG HQ DG LLC Somerset Operations Inc. Huntley Power LLC NRG Identity Protect LLC Somerset Power LLC Independence Energy Alliance LLC NRG Ilion Limited Partnership Texas Genco Financing Corp. Independence Energy Group LLC NRG Ilion LP LLC Texas Genco GP, LLC Independence Energy Natural Gas LLC NRG International LLC Texas Genco Holdings, Inc. Indian River Operations Inc. NRG Maintenance Services LLC Texas Genco LP, LLC Indian River Power LLC NRG Mextrans Inc. Texas Genco Operating Services, LLC Keystone Power LLC NRG MidAtlantic Affiliate Services Inc. Texas Genco Services, LP Langford Wind Power LLC NRG Middletown Operations Inc. US Retailers LLC NRG Home Services LLC NRG Montville Operations Inc. Vienna Operations Inc. Louisiana Generating LLC NRG New Roads Holdings LLC Vienna Power LLC Meriden Gas Turbines LLC NRG North Central Operations Inc. WCP (Generation) Holdings LLC Middletown Power LLC NRG Northeast Affiliate Services Inc. West Coast Power LLC Montville Power LLC NRG Norwalk Harbor Operations Inc. NEO Corporation NRG GreenCo, LLC NRG Business Services LLC NRG GreenCo Holdings, LLC The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries, including GenOn and its subsidiaries. NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. Except for NRG Bayou Cove, LLC, which is subject to certain restrictions under the Company's Peaker financing agreements, there are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. In addition, there may be restrictions for certain non-guarantor subsidiaries. The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the Securities and Exchange Commission's Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities. In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis. In addition, the condensed parent company financial statements are provided in accordance with Rule 12-04, Schedule I of Regulation S-X, as the restricted net assets of NRG Energy, Inc.’s subsidiaries exceed 25 percent of the consolidated net assets of NRG Energy, Inc. These statements should be read in conjunction with the consolidated statements and notes thereto of NRG Energy, Inc. For a discussion of NRG Energy, Inc.'s long-term debt, see Note 12 , Debt and Capital Leases to the consolidated financial statements. For a discussion of NRG Energy, Inc.'s contingencies, see Note 22 , Commitments and Contingencies to the consolidated financial statements. For a discussion of NRG Energy, Inc.'s guarantees, see Note 26 , Guarantees to the consolidated financial statements. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS For the Year Ended December 31, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Operating Revenues Total operating revenues $ 10,024 $ 4,768 $ — $ (118 ) $ 14,674 Operating Costs and Expenses Cost of operations 7,712 3,147 14 (118 ) 10,755 Depreciation and amortization 787 759 20 — 1,566 Impairment losses 4,655 375 — — 5,030 Selling, general and administrative 467 403 350 — 1,220 Acquisition-related transaction and integration costs 1 (5 ) 14 — 10 Development activity expenses — 61 93 — 154 Total operating costs and expenses 13,622 4,740 491 (118 ) 18,735 Gain on postretirement benefits curtailment — 21 — — 21 Operating (Loss)/Income (3,598 ) 49 (491 ) — (4,040 ) Other Income/(Expense) Equity in losses of consolidated subsidiaries (86 ) (29 ) (2,799 ) 2,914 — Equity in earnings of unconsolidated affiliates 8 37 — (9 ) 36 Impairment charge on investment — (25 ) (31 ) — (56 ) Other income, net 4 29 — — 33 Loss on sale of equity-method investment — — (14 ) — (14 ) Net gain on debt extinguishment — 56 19 — 75 Interest expense (18 ) (564 ) (546 ) — (1,128 ) Total other expense (92 ) (496 ) (3,371 ) 2,905 (1,054 ) Loss Before Income Taxes (3,690 ) (447 ) (3,862 ) 2,905 (5,094 ) Income tax (benefit)/expense (1,104 ) (96 ) 2,489 53 1,342 Net Loss (2,586 ) (351 ) (6,351 ) 2,852 (6,436 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — (23 ) 31 (62 ) (54 ) Net Loss Attributable to NRG Energy, Inc. $ (2,586 ) $ (328 ) $ (6,382 ) $ 2,914 $ (6,382 ) (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) For the Year Ended December 31, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Net Loss $ (2,586 ) $ (351 ) $ (6,351 ) $ 2,852 $ (6,436 ) Other Comprehensive (Loss)/Income, net of tax Unrealized (loss)/gain on derivatives, net (9 ) (13 ) 48 (41 ) (15 ) Foreign currency translation adjustments, net — (7 ) (4 ) — (11 ) Available-for-sale securities, net — (1 ) 18 — 17 Defined benefit plan, net (22 ) (15 ) 47 — 10 Other comprehensive (loss)/income (31 ) (36 ) 109 (41 ) 1 Comprehensive Loss (2,617 ) (387 ) (6,242 ) 2,811 (6,435 ) Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — (42 ) 31 (62 ) (73 ) Comprehensive Loss Attributable to NRG Energy, Inc. (2,617 ) (345 ) (6,273 ) 2,873 (6,362 ) Dividends for preferred shares — — 20 — 20 Comprehensive Loss Available for Common Stockholders $ (2,617 ) $ (345 ) $ (6,293 ) $ 2,873 $ (6,382 ) (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) ASSETS Current Assets Cash and cash equivalents $ — $ 825 $ 693 $ — $ 1,518 Funds deposited by counterparties 55 51 — — 106 Restricted cash 5 409 — — 414 Accounts receivable - trade, net 851 304 2 — 1,157 Accounts receivable - Affiliate 395 260 571 (1,222 ) 4 Inventory 570 682 — — 1,252 Derivative instruments 1,202 871 — (158 ) 1,915 Cash collateral paid in support of energy risk management activities 474 94 — — 568 Renewable energy grant receivable — 13 — — 13 Current assets held-for-sale — 6 — — 6 Prepayments and other current assets 93 274 71 — 438 Total current assets 3,645 3,789 1,337 (1,380 ) 7,391 Net Property, Plant and Equipment 4,767 13,773 219 (27 ) 18,732 Other Assets Investment in subsidiaries 842 2,244 11,039 (14,125 ) — Equity investments in affiliates (14 ) 1,160 1 (102 ) 1,045 Notes receivable, less current portion — 46 7 — 53 Goodwill 697 302 — — 999 Intangible assets, net 763 1,551 2 (6 ) 2,310 Nuclear decommissioning trust fund 561 — — — 561 Deferred income taxes (6 ) 815 (642 ) — 167 Derivative instruments 153 184 — (32 ) 305 Non-current assets held for sale — 105 — — 105 Other non-current assets 80 749 385 — 1,214 Total other assets 3,076 7,156 10,792 (14,265 ) 6,759 Total Assets $ 11,488 $ 24,718 $ 12,348 $ (15,672 ) $ 32,882 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Current portion of long-term debt and capital leases $ 2 $ 460 $ 19 $ — $ 481 Accounts payable 553 277 39 — 869 Accounts payable - affiliate 151 2,000 (929 ) (1,222 ) — Derivative instruments 1,130 749 — (158 ) 1,721 Cash collateral received in support of energy risk management activities 55 51 — — 106 Accrued interest expense 5 91 147 (1 ) 242 Other accrued expenses 122 151 295 — 568 Current liabilities held-for-sale — 2 — — 2 Other current liabilities 192 187 7 — 386 Total current liabilities 2,210 3,968 (422 ) (1,381 ) 4,375 Other Liabilities Long-term debt and capital leases 302 10,496 8,185 — 18,983 Nuclear decommissioning reserve 326 — — — 326 Nuclear decommissioning trust liability 283 — — — 283 Postretirement and other benefit obligations 236 200 152 — 588 Deferred income taxes 179 (1,088 ) 928 — 19 Derivative instruments 301 224 — (32 ) 493 Out-of-market contracts 95 1,051 — — 1,146 Non-current liabilities held-for-sale — 4 — — 4 Other non-current liabilities 318 535 47 — 900 Total non-current liabilities 2,040 11,422 9,312 (32 ) 22,742 Total Liabilities 4,250 15,390 8,890 (1,413 ) 27,117 2.822% Preferred Stock — — 302 — 302 Redeemable noncontrolling interest in subsidiaries — 29 — — 29 Stockholders' Equity 7,238 9,299 3,156 (14,259 ) 5,434 Total Liabilities and Stockholders' Equity $ 11,488 $ 24,718 $ 12,348 $ (15,672 ) $ 32,882 (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Cash Flows from Operating Activities Net Loss (2,586 ) (351 ) (6,351 ) 2,852 (6,436 ) Adjustments to reconcile net loss to net cash provided by operating activities: Distributions from unconsolidated affiliates 3 91 — (21 ) 73 Equity in losses of unconsolidated affiliates (8 ) (37 ) — 9 (36 ) Depreciation and amortization 787 759 20 — 1,566 Provision for bad debts 58 3 3 — 64 Amortization of nuclear fuel 45 — — — 45 Amortization of financing costs and debt discount/premiums — (37 ) 26 — (11 ) Adjustment to gain on debt extinguishment — (56 ) (19 ) — (75 ) Amortization of intangibles and out-of-market contracts 52 29 — — 81 Amortization of unearned equity compensation — — 41 — 41 Gain on post retirement benefits curtailment and sales of assets — (21 ) 14 — (7 ) Impairment losses 4,655 400 31 — 5,086 Changes in derivative instruments 264 (31 ) — — 233 Changes in collateral deposits supporting energy risk management activities (360 ) (21 ) — — (381 ) Changes in deferred income taxes and liability for uncertain tax benefits (1,092 ) (237 ) 2,655 — 1,326 Changes in nuclear decommissioning trust liability (2 ) — — — (2 ) Cash used by changes in other working capital (8,744 ) (950 ) 12,276 (2,840 ) (258 ) Net Cash (Used)/Provided by Operating Activities (6,928 ) (459 ) 8,696 — 1,309 Cash Flows from Investing Activities Proceeds from intercompany loans to subsidiaries 7,183 1,258 — (8,441 ) — Acquisition of 2015 Drop Down Assets, net of cash acquired — (698 ) — 698 — Acquisition of businesses, net of cash acquired — (31 ) — — (31 ) Capital expenditures (316 ) (908 ) (59 ) — (1,283 ) (Increase)/decrease in restricted cash, net (1 ) 9 — — 8 Decrease in restricted cash - U.S. DOE projects — 34 1 — 35 Decrease in notes receivable — 18 — — 18 Proceeds from renewable energy grants — 82 — — 82 Purchases of emission allowances, net of proceeds 41 — — — 41 Investments in nuclear decommissioning trust securities (629 ) — — — (629 ) Proceeds from sales of nuclear decommissioning trust fund securities 631 — — — 631 Proceeds from sale of assets, net — 1 26 — 27 Investments in unconsolidated affiliates 1 (357 ) (39 ) — (395 ) Other — 11 — — 11 Net Cash Provided/(Used) by Investing Activities 6,910 (581 ) (71 ) (7,743 ) (1,485 ) Cash Flows from Financing Activities Payments from intercompany loans — — (8,441 ) 8,441 — Acquisition of 2015 Drop Down Assets, net of cash acquired — — 698 (698 ) — Payment of dividends to preferred and common stockholders — — (201 ) — (201 ) Net receipts from settlement of acquired derivatives that include financing elements — 196 — — 196 Payment for treasury stock — — (437 ) — (437 ) Sale proceeds and other contributions from noncontrolling interests in subsidiaries — 647 — — 647 Proceeds from issuance of common stock — — 1 — 1 Proceeds from issuance of long-term debt — 953 51 — 1,004 Payment of debt issuance and hedging costs — (21 ) — — (21 ) Payments for short and long-term debt — (1,353 ) (246 ) — (1,599 ) Other — (22 ) — — (22 ) Net Cash (Used)/Provided by Financing Activities — 400 (8,575 ) 7,743 (432 ) Effect of exchange rate changes on cash and cash equivalents — 10 — — 10 Net (Decrease)/Increase in Cash and Cash Equivalents (18 ) (630 ) 50 — (598 ) Cash and Cash Equivalents at Beginning of Period 18 1,455 643 — 2,116 Cash and Cash Equivalents at End of Period $ — $ 825 $ 693 $ — $ 1,518 (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS For the Year Ended December 31, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Operating Revenues Total operating revenues $ 9,974 $ 6,287 $ — $ (393 ) $ 15,868 Operating Costs and Expenses Cost of operations 7,909 4,206 4 (325 ) 11,794 Depreciation and amortization 801 706 16 — 1,523 Impairment losses — 119 — (22 ) 97 Selling, general and administrative 333 390 304 — 1,027 Acquisition-related transactions and integration costs 3 15 66 — 84 Development activity expense — 35 56 — 91 Total operating costs and expenses 9,046 5,471 446 (347 ) 14,616 Gain on sale of assets — 19 — — 19 Operating Income/(Loss) 928 835 (446 ) (46 ) 1,271 Other Income/(Expense) Equity in earnings of consolidated subsidiaries 317 219 775 (1,311 ) — Equity in earnings of unconsolidated affiliates 13 33 — (8 ) 38 Impairment losses on investments — — — — — Other income, net 7 14 3 (2 ) 22 Gain on sale of equity-method investment — 18 — — 18 Loss on debt extinguishment — (9 ) (86 ) — (95 ) Interest expense (19 ) (525 ) (575 ) — (1,119 ) Total other income/(expense) 318 (250 ) 117 (1,321 ) (1,136 ) Income/(Loss) Before Income Taxes 1,246 585 (329 ) (1,367 ) 135 Income tax expense/(benefit) 322 159 (478 ) — 3 Net Income $ 924 $ 426 $ 149 $ (1,367 ) $ 132 Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests — 57 15 (74 ) (2 ) Net Income Attributable to NRG Energy, Inc. $ 924 $ 369 $ 134 $ (1,293 ) $ 134 (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) For the Year Ended December 31, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Net Income $ 924 $ 426 $ 149 $ (1,367 ) $ 132 Other Comprehensive (Loss)/Income, net of tax Unrealized loss on derivatives, net (49 ) (89 ) (215 ) 308 (45 ) Foreign currency translation adjustments, net — (12 ) 4 — (8 ) Available-for-sale securities, net — 1 (8 ) — (7 ) Defined benefit plan, net 5 (104 ) (30 ) — (129 ) Other comprehensive loss (44 ) (204 ) (249 ) 308 (189 ) Comprehensive Income/(Loss) 880 222 (100 ) (1,059 ) (57 ) Less: Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests — 67 15 (74 ) 8 Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. 880 155 (115 ) (985 ) (65 ) Dividends for preferred shares — — 56 — 56 Comprehensive Income/(Loss) Available for Common Stockholders $ 880 $ 155 $ (171 ) $ (985 ) $ (121 ) (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) ASSETS Current Assets Cash and cash equivalents $ 18 $ 1,455 $ 643 $ — $ 2,116 Funds deposited by counterparties 9 63 — — 72 Restricted cash 5 451 1 — 457 Accounts receivable - trade, net 924 392 6 — 1,322 Inventory 537 710 — — 1,247 Derivative instruments 1,657 1,209 — (441 ) 2,425 Cash collateral paid in support of energy risk management activities 114 73 — — 187 Accounts receivable - affiliate 7,449 1,988 (5,991 ) (3,437 ) 9 Renewable energy grant receivable — 134 1 — 135 Prepayments and other current assets 94 269 75 — 438 Total current assets 10,807 6,744 (5,265 ) (3,878 ) 8,408 Net Property, Plant and Equipment 8,344 13,877 171 (25 ) 22,367 Other Assets Investment in subsidiaries 140 2,293 23,410 (25,843 ) — Equity investments in affiliates (18 ) 891 — (102 ) 771 Notes receivable, less current portion 1 60 109 (98 ) 72 Goodwill 1,921 653 — — 2,574 Intangible assets, net 765 1,806 2 (6 ) 2,567 Nuclear decommissioning trust fund 585 — — — 585 Derivative instruments 242 288 1 (51 ) 480 Deferred income taxes (247 ) 722 1,105 — 1,580 Non-current assets held for sale — 17 — — 17 Other non-current assets 108 520 417 — 1,045 Total other assets 3,497 7,250 25,044 (26,100 ) 9,691 Total Assets $ 22,648 $ 27,871 $ 19,950 $ (30,003 ) $ 40,466 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Current portion of long-term debt and capital leases $ 1 $ 444 $ 127 $ (98 ) $ 474 Accounts payable 598 416 46 — 1,060 Accounts payable - affiliate 1,588 2,447 (598 ) (3,437 ) — Derivative instruments 1,532 963 — (441 ) 2,054 Cash collateral received in support of energy risk management activities 9 63 — — 72 Accrued expenses and other current liabilities 283 498 418 — 1,199 Total current liabilities 4,011 4,831 (7 ) (3,976 ) 4,859 Other Liabilities Long-term debt and capital leases 302 11,123 8,276 — 19,701 Nuclear decommissioning reserve 310 — — — 310 Nuclear decommissioning trust liability 333 — — — 333 Postretirement and other benefit obligations 277 234 216 — 727 Deferred income taxes 1,043 (1,012 ) (10 ) — 21 Derivative instruments 248 241 — (51 ) 438 Out-of-market commodity contracts 111 1,133 — — 1,244 Other non-current liabilities 188 561 98 — 847 Total non-current liabilities 2,812 12,280 8,580 (51 ) 23,621 Total Liabilities 6,823 17,111 8,573 (4,027 ) 28,480 2.822% Preferred Stock — — 291 — 291 Redeemable noncontrolling interest in subsidiaries — 19 — — 19 Stockholders' Equity 15,825 10,741 11,086 (25,976 ) 11,676 Total Liabilities and Stockholders' Equity $ 22,648 $ 27,871 $ 19,950 $ (30,003 ) $ 40,466 (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) Cash Flows from Operating Activities Net Income 924 426 149 (1,367 ) 132 Adjustments to reconcile net loss to net cash provided by operating activities: Distributions from unconsolidated affiliates — 87 — — 87 Equity in losses of unconsolidated affiliates (13 ) (33 ) — 8 (38 ) Depreciation and amortization 801 706 16 — 1,523 Provision for bad debts 64 — — — 64 Amortization of nuclear fuel 46 — — — 46 Amortization of financing costs and debt discount/premiums — (40 ) 28 — (12 ) Adjustment to loss on debt extinguishment — 8 17 — 25 Amortization of intangibles and out-of-market contracts 65 (1 ) — — 64 Amortization of unearned equity compensation — — 42 — 42 Gain on sale of assets, net — (4 ) — — (4 ) Impairment losses — 119 — (22 ) 97 Changes in derivative instruments (149 ) 88 — — (61 ) Changes in deferred income taxes and liability for uncertain tax benefits 242 (115 ) (281 ) — (154 ) Changes in nuclear decommissioning trust liability 19 — — — 19 Cash used by changes in other working capital 787 (973 ) (4,723 ) 4,589 (320 ) Net Cash Provided/(Used) by Operating Activities 2,786 268 (4,752 ) 3,208 1,510 Cash Flows from Investing Activities Intercompany loans to subsidiaries (2,523 ) (685 ) 3,208 — — Acquisition of businesses, net of cash acquired — (25 ) (2,911 ) — (2,936 ) Capital expenditures (252 ) (619 ) (38 ) — (909 ) Decrease in restricted cash, net — 57 — — 57 (Increase) in restricted cash - U.S. DOE projects — (209 ) 3 — (206 ) Decrease in notes receivable — 25 — — 25 Proceeds from renewable energy grants — 916 — — 916 Purchases of emission allowances, net of proceeds (16 ) — — — (16 ) Investments in nuclear decommissioning trust fund securities (619 ) — — — (619 ) Proceeds from sales of nuclear decommissioning trust fund securities 600 — — — 600 Proceeds from sale of assets, net — — 203 — 203 Investments in unconsolidated affiliates — (25 ) (78 ) — (103 ) Other — 85 — — 85 Net Cash (Used)/Provided by Investing Activities (2,810 ) (480 ) 387 — (2,903 ) Cash Flows from Financing Activities Proceeds from intercompany loans — — 3,208 (3,208 ) — Payment of dividends to preferred stockholders — — (196 ) — (196 ) Net receipts from acquired derivatives that include financing elements — 9 — — 9 Payment for treasury stock — — (39 ) — (39 ) Sales proceeds from sale of noncontrolling interest in subsidiaries — 819 — — 819 Proceeds from issuance of common stock — — 21 — 21 Proceeds from issuance of long-term debt — 1,182 3,381 — 4,563 Payment of debt issuance and hedging costs — (39 ) (28 ) — (67 ) Payments of short and long-term debt — (1,160 ) (2,667 ) — (3,827 ) Other (14 ) (4 ) — — (18 ) Net Cash (Used)/Provided by Financing Activities (14 ) 807 3,680 (3,208 ) 1,265 Effect of exchange rate changes on cash and cash equivalents — (10 ) — — (10 ) Net (Decrease)/Increase in Cash and Cash Equivalents (38 ) 585 (685 ) — (138 ) Cash and Cash Equivalents at Beginning of Period 56 870 1,328 — 2,254 Cash and Cash Equivalents at End of Period $ 18 $ 1,455 $ 643 $ — $ 2,116 (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS For the Year Ended December 31, 2013 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) Operating Revenues Total operating revenues $ 8,223 $ 3,211 $ — $ (139 ) $ 11,295 Operating Costs and Expenses Cost of operations 6,150 2,113 — (133 ) 8,130 Depreciation and amortization 837 407 12 — 1,256 Impairment losses 459 — — — 459 Selling, general and administrative 446 221 234 (6 ) 895 Acquisition-related transaction and integration costs — 70 58 — 128 Development activity expenses — 34 50 — 84 Total operating costs and expenses 7,892 2,845 354 (139 ) 10,952 Operating Income/(Loss) 331 366 (354 ) — 343 Other (Expense)/Income Equity in (losses)/earnings of consolidated subsidiaries (67 ) (14 ) 221 (140 ) — Equity in (losses)/earnings of unconsolidated affiliates (11 ) 22 — (4 ) 7 Impairment losses on investment — (99 ) — — (99 ) Other income/(loss), net 6 11 (2 ) (2 ) 13 Loss on debt extinguishment — (12 ) (38 ) — (50 ) Interest expense (24 ) (318 ) (506 ) — (848 ) Total other expense (96 ) (410 ) (325 ) (146 ) (977 ) Income/(Loss) Before Income Taxes 235 (44 ) (679 ) (146 ) (634 ) Income tax expense/(benefit) 114 (89 ) (307 ) — (282 ) Net Income/(Loss) 121 45 (372 ) (146 ) (352 ) Less: Net income attributable to noncontrolling interest — 27 13 (6 ) 34 Net Income/(Loss) Attributable to NRG Energy, Inc $ 121 $ 18 $ (385 ) $ (140 ) $ (386 ) (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME For the Year Ended December 31, 2013 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Net Income/(Loss) $ 121 $ 45 $ (372 ) $ (146 ) $ (352 ) Other Comprehensive Income/(Loss), net of tax Unrealized (loss)/income on derivatives, net (71 ) 50 120 (91 ) 8 Foreign currency translation adjustments, net — (20 ) (4 ) — (24 ) Available-for-sale securities, net — — 3 — 3 Defined benefit plan, net 75 63 30 — 168 Other comprehensive income 4 93 149 (91 ) 155 Comprehensive Income/(Loss) 125 138 (223 ) (237 ) (197 ) Less: Comprehensive income attributable to noncontrolling interest — 27 13 (6 ) 34 Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. 125 111 (236 ) (231 ) (231 ) Dividends for preferred shares — — 9 — 9 Comprehensive Income/(Loss) Available for Common Stockholders $ 125 $ 111 $ (245 ) $ (231 ) $ (240 ) (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2013 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) Cash Flows from Operating Activities Net Income/(Loss) 121 45 (372 ) (146 ) (352 ) Adjustments to reconcile net loss to net cash provided by operating activities: Distributions from unconsolidated affiliates 51 26 — — 77 Equity in losses of unconsolidated affiliates 11 (22 ) — 4 (7 ) Depreciation and amortization 837 407 12 — 1,256 Provision for bad debts 67 — — — 67 Amortization of nuclear fuel 36 — — — 36 Amortization of financing costs and debt discount/premiums — (9 ) (24 ) — (33 ) Adjustment for debt extinguishment — (27 ) 12 — (15 ) Amortization of intangibles and out-of-market contracts 100 (51 ) — — 49 Amortization of unearned equity compensation — — 38 — 38 Gain on sale of assets, net — (3 ) — — (3 ) Impairment losses 459 99 — — 558 Changes in derivative instruments 197 (33 ) — — 164 Changes in deferred income taxes and liability for uncertain tax benefits (58 ) 292 (301 ) — (67 ) Changes in nuclear decommissioning trust liability 15 — — — 15 Cash used by changes in other working capital 482 (941 ) (1,911 ) 1,857 (513 ) Net Cash Provided/(Used) by Operating Activities 2,318 (217 ) (2,546 ) 1,715 1,270 Cash Flows from Investing Activities Intercompany loans to subsidiaries (1,722 ) 7 1,715 — — Acquisition of business, net of cash acquired — (179 ) (315 ) — (494 ) Capital expenditures (528 ) (1,413 ) (46 ) — (1,987 ) (Increase)/decrease in restricted cash (1 ) (22 ) 1 — (22 ) (Increase)/decrease in restricted cash - U.S. DOE projects — (31 ) 5 — (26 ) Decrease/(increase) in notes receivable 2 (7 ) (6 ) — (11 ) Proceeds from renewable energy grants — 55 — — 55 Purchases of emission allowances, net of proceeds 5 — — — 5 Investments in nuclear decommissioning trust fund securities (514 ) — — — (514 ) Proceeds from sales of nuclear decommissioning trust fund securities 488 — — — 488 Proceeds from sale of assets, net 13 — — — 13 Other (4 ) (11 ) (20 ) — (35 ) Net Cash Used by Investing Activities (2,261 ) (1,601 ) 1,334 — (2,528 ) Cash Flows from Financing Activities Proceeds from intercompany loans — — 1,715 (1,715 ) — Payment for dividends to preferred stockholders — — (154 ) — (154 ) Net (payments for)/receipts from acquired derivatives that include financing elements (79 ) 346 — — 267 Payment for treasury stock — — (25 ) — (25 ) Sales proceeds from sale of noncontrolling interest in subsidiary — 531 — — 531 Proceeds from issuance of common stock — — 16 — 16 Proceeds from issuance of long-term debt — 1,292 485 — 1,777 Payment of debt issuance and hedging costs — (21 ) (29 ) — (50 ) Payments of short and long-term debt — (716 ) (219 ) — (935 ) Net Cash (Used)/Provided by Financing Activities (79 ) 1,432 1,789 (1,715 ) 1,427 Effect of exchange rate changes on cash and cash equivalents — (2 ) — — (2 ) Net Increase/(Decrease) in Cash and Cash Equivalents (22 ) (388 ) 577 — 167 Cash and Cash Equivalents at Beginning of Period 78 1,258 751 — 2,087 Cash and Cash Equivalents at End of Period $ 56 $ 870 $ 1,328 $ — $ 2,254 (a) All significant intercompany transactions have been eliminated in consolidation.

Summary of Significant Accoun38

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Summary of Significant Accounting Policies Disclosure
Basis of Presentation	The Company's consolidated financial statements have been prepared in accordance with U.S. GAAP. The ASC, established by the FASB, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants.
Principles of Consolidation	The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a VIE, should be consolidated.
Segment Reporting	Segment Reporting Effective in December 2014, the Company's segment structure and its allocation of corporate expenses were updated to reflect how management makes financial decisions and allocates resources. The Company has recast data from prior periods to reflect this change in reportable segments to conform to the current year presentation. The Company's businesses are segregated as follows: NRG Business, which includes conventional power generation, the carbon capture business and energy services; NRG Home, which includes NRG Home Retail consisting of residential retail services and products, and NRG Home Solar, which includes the installation and leasing of residential solar services; NRG Renew, which includes solar and wind assets, excluding those in the NRG Yield and NRG Home Solar segments; NRG Yield and corporate activities. NRG Yield includes certain of the Company's contracted generation assets. The Company's corporate segment includes BETM, international business and electric vehicle services.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.
Funds Deposited by Counterparties	Funds Deposited by Counterparties Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Some amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities. Changes in funds deposited by counterparties are closely associated with the Company's operating activities and are classified as an operating activity in the Company's consolidated statements of cash flows.
Restricted Cash	Restricted Cash Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use. Of these funds, approximately $45 million is designated for current debt service payments, $61 million is designated to fund operating expenses, and $21 million is designated to fund distributions, with the remaining $287 million restricted for reserves including debt service, performance obligations and other reserves, as well as capital expenditures.
Trade Receivables and Allowance for Doubtful Accounts	Trade Receivables and Allowance for Doubtful Accounts Trade receivables are reported in the balance sheet at outstanding principal adjusted for any write-offs and the allowance for doubtful accounts. For its retail business, the Company accrues an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings (for commercial and industrial customers), historical collections, accounts receivable aging and other factors. The retail business writes-off accounts receivable balances against the allowance for doubtful accounts when it determines a receivable is uncollectible.
Inventory	Inventory Inventory is valued at the lower of weighted average cost or market, and consists principally of fuel oil, coal and raw materials used to generate electricity or steam. The Company removes these inventories as they are used in the production of electricity or steam. Spare parts inventory is valued at a weighted average cost. The Company removes these inventories when they are used for repairs, maintenance or capital projects. The Company expects to recover the fuel oil, coal, raw materials, and spare parts costs in the ordinary course of business. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows. Finished goods inventory is valued at the lower of cost or net realizable value with cost being determined on a first-in first-out basis. The Company removes these inventories as they are sold to customers. During the year ended December 31, 2015 , the Company recorded a lower of weighted average cost or market adjustment of $19 million related to fuel oil.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment are stated at cost or, in the case of business acquisitions, fair value; however impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. See Note 3 , Business Acquisitions and Dispositions , for more information on acquired property, plant and equipment. NRG also classifies nuclear fuel related to the Company's 44% ownership interest in STP as part of the Company's property, plant, and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation other than nuclear fuel is computed using the straight-line method, while nuclear fuel is amortized based on units of production over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of operations.
Asset Impairments	Asset Impairments Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the statements of operations. Fair values are determined by a variety of valuation methods, including third-party appraisals, sales prices of similar assets and present value techniques. Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-Equity Method and Joint Ventures , or ASC 323, which requires that a loss in value of an investment that is other than a temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value. For further discussion of these matters, refer to Note 10 , Asset Impairments .
Project Development Costs and Capitalized Interest	Development Activity Expenses and Capitalized Interest Development activity expenses include project development costs, which are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including, among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset. When a project is available for operations, capitalized project development costs are reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable. Development activity expenses also include selling, general, and administrative expenses associated with the current operations of certain developing businesses including residential solar, electric vehicles, waste-to-energy, carbon capture and other emerging technologies. The revenue associated with these businesses was immaterial for the years ended December 31, 2015 , 2014 , and 2013 . When it is determined that a business will remain an ongoing part of the Company's operations or when operating revenues become material relative to the operating costs of the underlying business, the Company no longer classifies a business as a development activity. Beginning in 2014, the Company no longer classifies costs associated with residential solar or carbon capture as development activity expenses. Interest incurred on funds borrowed to finance capital projects is capitalized until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2015 , 2014 , and 2013 , was $30 million , $29 million , and $64 million , respectively. When a project is available for operations, capitalized interest and project development costs are reclassified to property, plant and equipment and depreciated on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.
Debt Issuance Costs	Debt Issuance Costs Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt. As discussed below, as of December 31, 2015, the Company adopted ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, and reclassified debt issuance costs to be presented as a direct deduction from the carrying amount of the related debt in both the current and prior periods.
Intangible Assets	Intangible Assets Intangible assets represent contractual rights held by NRG. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, marketing partnerships, power purchase agreements, trade names, emission allowances, and fuel contracts when specific rights and contracts are acquired. In addition, NRG also established values for emission allowances and power contracts upon adoption of Fresh Start reporting. These intangible assets are amortized based on expected volumes, expected delivery, expected discounted future net cash flows, straight line or units of production basis. Intangible assets determined to have indefinite lives are not amortized, but rather are tested for impairment at least annually or more frequently if events or changes in circumstances indicate that such acquired intangible assets have been determined to have finite lives and should now be amortized over their useful lives. NRG had no intangible assets with indefinite lives recorded as of December 31, 2015 . Emission allowances held-for-sale, which are included in other non-current assets on the Company's consolidated balance sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360.
Goodwill	Goodwill In accordance with ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed. NRG performs goodwill impairment tests annually, during the fourth quarter, and when events or changes in circumstances indicate that the carrying value may not be recoverable. The Company first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. In the absence of sufficient qualitative factors, goodwill impairment is determined using a two step process: Step one — Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two. Step two — Compare the implied fair value of the reporting unit's goodwill to the book value of the reporting unit goodwill. If the book value of goodwill exceeds the implied fair value, an impairment charge is recognized for the excess. For further discussion of goodwill and goodwill impairment losses recognized during 2015, refer to Note 11 , Goodwill and Other Intangibles .
Income Taxes	Income Taxes NRG accounts for income taxes using the liability method in accordance with ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences. NRG has two categories of income tax expense or benefit — current and deferred, as follows: • Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and • Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income. NRG reports some of the Company's revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. NRG measures the Company's deferred income tax assets and deferred income tax liabilities using income tax rates that are currently in effect. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets, net of valuation allowances. In arriving at this conclusion to utilize projections of future profit before tax in its estimate of future taxable income, the Company considered the profit before tax generated in recent years. A valuation allowance is recorded to reduce the Company's net deferred tax assets to an amount that is more-likely-than-not to be realized. NRG reduces its current income tax expense in the consolidated statement of operations for any investment tax credits, or ITCs, that are not convertible into cash grants, as well as other tax credits, in the period the tax credit is generated. ITCs that are convertible into cash grants, as well as the deferred income tax benefit generated by the difference in the financial statement and tax basis of the related assets, are recorded as a reduction to the carrying value of the underlying property and subsequently amortized to earnings on a straight-line basis over the useful life of each underlying property. The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense. In accordance with ASC 805 and as discussed further in Note 19 , Income Taxes , changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax expense.
Revenue Recognition	Revenue Recognition Energy — Both physical and financial transactions are entered into to optimize the financial performance of NRG's generating facilities. Electric energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. Financial transactions, or the buying and selling of energy for trading purposes, are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815. Capacity — Capacity revenues are recognized when contractually earned, and consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements. Sale of Emission Allowances — NRG records the Company's bank of emission allowances as part of the Company's intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of usage from the Company's emission bank to intangible assets held-for-sale for trading purposes. NRG records the sale of emission allowances on a net basis within operating revenue in the Company's consolidated statements of operations. Contract Amortization — Assets and liabilities recognized from power sales agreements assumed at Fresh Start and through acquisitions related to the sale of electric capacity and energy in future periods for which the fair value has been determined to be significantly less (more) than market are amortized to revenue over the term of each underlying contract based on actual generation and/or contracted volumes. Retail revenues — Gross revenues for energy sales and services to retail customers are recognized upon delivery under the accrual method. Energy sales and services that have been delivered but not billed by period end are estimated. Gross revenues also includes energy revenues from resales of purchased power, which were $165 million , $387 million and $166 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. These revenues represent the sale of excess supply to third parties in the market. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed. NRG recorded receivables for unbilled revenues of $309 million , $341 million and $356 million as of December 31, 2015 , 2014 , and 2013 , respectively, for retail energy sales and services. Consumer product revenues are recognized when title and risk of loss pass to the retailer, distributor, or end-customer and when all of the following have occurred: a firm sales agreement is in place, delivery has occurred, pricing is fixed and determinable, and collection is reasonably assured. Revenue is recognized as the net amount expected to be received after deducting estimated amounts for product returns, discounts, and allowances based on historical return rates and reasonable judgment.
Lease, Policy [Policy Text Block]	Lessor Accounting Certain of the Company’s revenues are obtained through PPAs or other contractual agreements. It was determined that certain of these PPAs qualify as operating leases for which the Company is the operating lessor and are accounted for in accordance with ASC 840, Leases . In order to determine lease classification as operating, the Company evaluates the terms of the PPA to determine if the lease includes any of the following provisions which would indicate capital lease treatment: • Transfers the ownership of the generating facility, • Bargain purchase option at the end of the term of the lease, • Lease term is greater than 75% of the economic life of the generating facility, or • Present value of minimum lease payments exceeds 90% of the fair value of the generating facility at inception of the lease. In considering the above it was determined that many of the Company’s PPAs are operating leases. ASC 840 requires the minimum lease payments received to be amortized over the term of the lease and contingent rentals are recorded when the achievement of the contingency becomes probable. Certain of these leases have no minimum lease payments and all of the rent is recorded as contingent rent on an actual basis when the electricity is delivered. Judgment is required by management in determining the economic life of each generating facility, in evaluating whether certain lease provisions constitute minimum payments or represent contingent rent and other factors in determining whether a contract contains a lease and whether the lease is an operating lease or capital lease. Contingent rental income recognized in the years ended December 31, 2015 , 2014 , and 2013 was $777 million , $544 million , and $260 million , respectively.
Gross Receipts and Sales Taxes	Gross Receipts and Sales Taxes In connection with its retail business, the Company records gross receipts taxes on a gross basis in revenues and cost of operations in its consolidated statements of operations. During the years ended December 31, 2015 , 2014 , and 2013 , NRG's revenues and cost of operations included gross receipts taxes of $110 million , $108 million , and $88 million , respectively. Additionally, the retail business records sales taxes collected from its taxable customers and remitted to the various governmental entities on a net basis; thus, there is no impact on the Company's consolidated statement of operations.
Derivative Financial Instruments	Derivative Financial Instruments NRG accounts for derivative financial instruments under ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value unless they qualify for a NPNS exception. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as hedges, if elected for hedge accounting, are either: • Recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments; or • Deferred and recorded as a component of accumulated OCI until the hedged transactions occur and are recognized in earnings. NRG's primary derivative instruments are power purchase or sales contracts, fuels purchase contracts, other energy related commodities, and interest rate instruments used to mitigate variability in earnings due to fluctuations in market prices and interest rates. On an ongoing basis, NRG assesses the effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. Internal analyses that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such a contract designated as a hedge. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. In this case, the gain or loss previously deferred in accumulated OCI would be frozen until the underlying hedged instrument is delivered unless the transactions being hedged are no longer probable of occurring in which case the amount in OCI would be immediately reclassified into earnings. If the derivative instrument is terminated, the effective portion of this derivative deferred in accumulated OCI will be frozen until the underlying hedged item is delivered. Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings. NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.
Foreign Currency Translation and Transaction Gains and Losses	Foreign Currency Translation and Transaction Gains and Losses The local currencies are generally the functional currency of NRG's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the Company's statements of operations for the period, but are accumulated and reported as a separate component of stockholders' equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign currency transaction gains or losses are reported within other income/(expense) in the Company's statements of operations. For the years ended December 31, 2015 , 2014 , and 2013 , amounts recognized as foreign currency transaction gains (losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2015 , 2014 , and 2013 were $(10) million , $1 million and $15 million , respectively.
Concentrations of Credit Risk	Concentrations of Credit Risk Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of trust funds, accounts receivable, notes receivable, derivatives, and investments in debt securities. Trust funds are held in accounts managed by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling agreements. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See Note 4 , Fair Value of Financial Instruments , for a further discussion of derivative concentrations.
Fair Value of Financial Instruments	Fair Value of Financial Instruments The carrying amount of cash and cash equivalents, funds deposited by counterparties, receivables, accounts payable, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. See Note 4 , Fair Value of Financial Instruments , for a further discussion of fair value of financial instruments.
Asset Retirement Obligations	Asset Retirement Obligations NRG accounts for AROs in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made. Upon initial recognition of a liability for an ARO, NRG capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. See Note 13 , Asset Retirement Obligations , for a further discussion of AROs.
Pensions	Pensions and Other Postretirement Benefits NRG offers pension benefits through a defined benefit pension plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. NRG accounts for pension and other postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits. NRG recognizes the funded status of the Company's defined benefit plans in the statement of financial position and records an offset for gains and losses as well as all prior service costs that have not been included as part of the Company's net periodic benefit cost to other comprehensive income. The determination of NRG's obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. NRG's actuarial consultants determine assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company. NRG measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820.
Stock-Based Compensation	Stock-Based Compensation NRG accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock Compensation, or ASC 718 . The fair value of the Company's non-qualified stock options and performance units are estimated on the date of grant using the Black-Scholes option-pricing model and the Monte Carlo valuation model, respectively. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's restricted stock units and deferred stock units. Forfeiture rates are estimated based on an analysis of NRG's historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award.
Investments Accounted for by the Equity Method	Investments Accounted for by the Equity Method NRG has investments in various domestic energy projects, as well as one Australian project. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents NRG from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of domestic partnerships and, generally, in the net income or losses of its Australian project, are reflected as equity in earnings of unconsolidated affiliates. Distributions from equity method investments that represent a return on the Company's investment are included within cash flows from operating activities and distributions from equity method investments that represent a return of the Company's investment are included within cash flows from investing activities.
Tax Equity Arrangements, Policy [Policy Text Block]	Tax Equity Arrangements NRG’s redeemable noncontrolling interest in subsidiaries and noncontrolling interest, included in interest, represents third-party interests in the net assets under certain tax equity arrangements, which are consolidated by the Company, that have been entered into to finance the cost of solar energy systems under operating leases and wind facilities eligible for certain tax credits. The Company has determined that the provisions in the contractual agreements of these structures represent substantive profit sharing arrangements. Further, the Company has determined that the appropriate methodology for calculating the noncontrolling interest and redeemable noncontrolling interest that reflects the substantive profit sharing arrangements is a balance sheet approach utilizing the hypothetical liquidation at book value, or HLBV, method. Under the HLBV method, the amounts reported as noncontrolling interest and redeemable noncontrolling interests represent the amounts the investors that are party to the tax equity arrangements would hypothetically receive at each balance sheet date under the liquidation provisions of the contractual agreements, assuming the net assets of the funding structures were liquidated at their recorded amounts determined in accordance with GAAP. The investors’ interests in the results of operations of the funding structures are determined as the difference in noncontrolling interest and redeemable noncontrolling interests at the start and end of each reporting period, after taking into account any capital transactions between the structures and the funds’ investors. The calculations utilized to apply the HLBV method include estimated calculations of taxable income or losses for each reporting period. Redeemable Noncontrolling Interest To the extent that the third-party has the right to redeem their interests for cash or other assets, NRG has included the noncontrolling interest attributable to the third party as a component of temporary equity in the mezzanine section of the consolidated balance sheet. The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the years ended December 31, 2015 , and 2014 . (In millions) Balance as of December 31, 2013 $ 2 Cash contributions from noncontrolling interest 36 Comprehensive loss attributable to noncontrolling interest (19 ) Balance as of December 31, 2014 19 Cash contributions from noncontrolling interest 27 Comprehensive loss attributable to noncontrolling interest (17 ) Balance as of December 31, 2015 $ 29
Sale Leaseback Transactions, Policy [Policy Text Block]	Sale Leaseback Arrangements NRG is party to sale-leaseback arrangements that provide for the sale of certain assets to a third party and simultaneous leaseback to the Company. In accordance with ASC 840-40, Sale-Leaseback Transactions , if the seller-lessee retains, through the leaseback, substantially all of the benefits and risks incident to the ownership of the property sold, the sale-leaseback transaction is accounted for as a financing arrangement. An example of this type of continuing involvement would include an option to repurchase the assets or the buyer-lessor having the option to sell the assets back to the Company. This provision is included in most of the Company’s sale-leaseback arrangements. As such, the Company accounts for these arrangements as financings. Under the financing method, the Company does not recognize as income any of the sale proceeds received from the lessor that contractually constitutes payment to acquire the assets subject to these arrangements. Instead, the sale proceeds received are accounted for as financing obligations and leaseback payments made by the Company are allocated between interest expense and a reduction to the financing obligation. Interest on the financing obligation is calculated using the Company’s incremental borrowing rate at the inception of the arrangement on the outstanding financing obligation. Judgment is required to determine the appropriate borrowing rate for the arrangement and in determining any gain or loss on the transaction that would be recorded either at the end of or over the lease term.
Marketing and Advertising Costs	The Company expenses its marketing and advertising costs as incurred which are included within selling, general and administrative expenses. Marketing and advertising expenses for the years ended December 31, 2015, 2014, and 2013 were $307 million , $208 million , and $195 million , respectively. The costs of tangible assets used in advertising campaigns are recorded as fixed assets or deferred advertising costs and amortized as advertising costs over the shorter of the useful life of the asset or the advertising campaign. The Company has several long-term sponsorship arrangements. Payments related to these arrangements are deferred and expensed over the term of the arrangement. Advertising expenses for the years ended December 31, 2015, 2014 and 2013 were $135 million , $87 million , and $69 million , respectively.
Business Combinations	Business Combinations The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805. ASC 805 requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity's financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. In recording transactions and balances resulting from business operations, NRG uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, and the valuation of energy commodity contracts, environmental liabilities, legal costs incurred in connection with recorded loss contingencies, and assets acquired and liabilities assumed in business combinations, among others. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Reclassifications	Reclassifications Certain prior-year amounts have been reclassified for comparative purposes.
Nuclear Decommissioning Policy	NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations , or ASC 980, because the Company's nuclear decommissioning activities are subject to approval by the PUCT, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust Liability and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.
New Accounting Pronouncements, Policy [Policy Text Block]	Recent Accounting Developments ASU 2016-01 — In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, or ASU No. 2016-01. The amendments of ASU No. 2016-01 eliminate available-for-sale classification of equity investments and require that equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be generally measured at fair value with changes in fair value recognized in net income. Further, the amendments require that financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset. The guidance in ASU No. 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position. ASU 2015-17 — In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes , or ASU No. 2015-17. The amendments of ASU No. 2015-17 require that deferred tax liabilities and assets, as well as any related valuation allowance, be presented as noncurrent in a classified statement of financial position. The guidance in ASU No. 2015-17 is effective for financial statements issued for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. The amendments may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. Early adoption is permitted. The Company adopted ASU No. 2015-17 for the year ended December 31, 2015 and elected to apply the amendments retrospectively. The adoption did not have any impact on the Company's results of operations, cash flows, or net assets. ASU 2015-16 — In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments , or ASU No. 2015-16. The amendments of ASU No. 2015-16 require that an acquirer recognize measurement period adjustments to the provisional amounts recognized in a business combination in the reporting period during which the adjustments are determined. Additionally, the amendments of ASU No. 2015-16 require the acquirer to record in the same period's financial statements the effect on earnings of changes in depreciation, amortization or other income effects, if any, as a result of the measurement period adjustment, calculated as if the accounting had been completed at the acquisition date as well as disclosing either on the face of the income statement or in the notes the portion of the amount recorded in current period earnings that would have been recorded in previous reporting periods. The guidance in ASU No. 2015-16 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amendments should be applied prospectively. The adoption of this standard is not expected to have a material impact on the Company's results of operations, cash flows or financial position. ASU 2015-03 and ASU 2015-15 — In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs , or ASU No. 2015-03. The amendments of ASU No. 2015-03 were issued to reduce complexity in the balance sheet presentation of debt issuance costs. ASU No. 2015-03 requires that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this standard. Additionally, in August 2015, the FASB issued ASU No. 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements, or ASU No. 2015-15, as ASU No. 2015-03 did not specifically address presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements. ASU No. 2015-15 allows an entity to continue to defer and present debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance in ASU No. 2015-03 and ASU No. 2015-15 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been previously issued. The Company adopted ASU No. 2015-03 for the year ended December 31, 2015, and the adoption did not have a material impact on the Company's balance sheets on a gross basis and had no impact on net assets. ASU 2015-02 — In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis , or ASU No. 2015-02. The amendments of ASU No. 2015-02 were issued in an effort to minimize situations under previously existing guidance in which a reporting entity was required to consolidate another legal entity in which that reporting entity did not have: (1) the ability through contractual rights to act primarily on its own behalf; (2) ownership of the majority of the legal entity's voting rights; or (3) the exposure to a majority of the legal entity's economic benefits. ASU No. 2015-02 affects reporting entities that are required to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. The guidance in ASU No. 2015-02 is effective for periods beginning after December 15, 2015. Early adoption is permitted. The Company adopted the standard effective January 1, 2015, and the adoption of this standard did not impact the Company's results of operations, cash flows or financial position. ASU 2014-16 — In November 2014, the FASB issued ASU No. 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity , or ASU No. 2014-16. The amendments of ASU No. 2014-16 clarify how U.S. GAAP should be applied in determining whether the nature of a host contract is more akin to debt or equity and in evaluating whether the economic characteristics and risks of an embedded feature are "clearly and closely related" to its host contract. The guidance in ASU No. 2014-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The Company adopted this standard effective January 1, 2015, and the adoption did not impact the Company's results of operations, cash flows or financial position. ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) , or ASU No. 2014-09. The amendments of ASU No. 2014-09 complete the joint effort between the FASB and the International Accounting Standards Board, IASB, to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards, or IFRS, and to improve financial reporting. The guidance in ASU No. 2014-09 provides that an entity should recognize revenue to depict the transfer of goods or services provided and establishes the following steps to be applied by an entity: (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies the performance obligation. In August 2015, the FASB issued ASU 2015-14, which formally deferred the effective date by one year to make the guidance of ASU No. 2014-09 effective for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted, but not prior to the original effective date, which was for annual reporting periods beginning after December 15, 2016. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.
Retail
Summary of Significant Accounting Policies Disclosure
Cost of Energy for Retail Operations	Cost of Energy for Retail Operations The cost of energy for electricity sales and services to retail customers is included in cost of operations and is based on estimated supply volumes for the applicable reporting period. A portion of the cost of energy ( $85 million , $86 million and $90 million as of December 31, 2015 , 2014 , and 2013 , respectively) was accrued and consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities. In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees are estimated using the same method used for electricity sales and services to retail customers. In addition, ISO fees are estimated based on historical trends, estimated supply volumes and initial ERCOT ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.

Nature of Business (Tables)

Nature of Business (Tables)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Global Generation Portfolio by Operating Segment	The following table summarizes NRG's global generation portfolio as of December 31, 2015 : Global Generation Portfolio (a) (In MW) NRG Business Generation Type Gulf Coast East West NRG Home Solar (b) NRG Renew (c) NRG Yield (d) Total Domestic Other (Inter-national) Total Global Natural gas (e) 8,651 7,876 6,085 — — 1,879 24,491 144 24,635 Coal (f) 5,114 10,122 — — — — 15,236 605 15,841 Oil (g) — 5,581 — — — 190 5,771 — 5,771 Nuclear 1,176 — — — — — 1,176 — 1,176 Wind — — — — 1,061 2,005 3,066 — 3,066 Utility Scale Solar — — — — 845 482 1,327 — 1,327 Distributed Solar — — — 93 60 9 162 — 162 Total generation capacity 14,941 23,579 6,085 93 1,966 4,565 51,229 749 51,978 Capacity attributable to noncontrolling interest — — — — (638 ) (2,053 ) (2,691 ) — (2,691 ) Total net generation capacity 14,941 23,579 6,085 93 1,328 2,512 48,538 749 49,287 (a) Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units. (b) Includes the aggregate production capacity of installed and activated residential solar energy systems. Also includes capacity from operating portfolios of residential solar assets held by RPV Holdco, a partnership between NRG Home Solar and NRG Yield, Inc. (c) Includes Distributed Solar capacity from assets held by DGPV Holdco, a partnership between NRG Renew DG Holdings LLC and NRG Yield, Inc. (d) Does not include NRG Yield, Inc.'s thermal converted (MWt) capacity, which is part of the NRG Yield operating segment. (e) Natural gas generation portfolio does not include: 463 MW related to Osceola, which was mothballed on January 1, 2015; 636 MW related to Coolwater, which was retired on January 1, 2015; 16 MW related to SD Jets Kearny 1, which was deactivated in March 2015; 160 MW related to Glen Gardner, which was retired on May 1, 2015; 98 MW related to Gilbert, which was retired on May 1, 2015; 335 MW related to El Segundo 4, which was deactivated on December 31, 2015; and 60 MW related to SD Jets Kearny 2A-2D, which were deactivated on December 31, 2015. (f) Coal generation portfolio does not include: 251 MW related to Will County, which was retired on April 15, 2015; 597 MW related to Shawville, which was mothballed on May 31, 2015; 575 MW related to Big Cajun Unit 2, which was converted to natural gas in July 2015; 401 MW related to Portland, which was deactivated on December 1, 2015; and 75 MW related to Dunkirk 2, which was mothballed on December 31, 2015. (g) Oil generation portfolio does not include 212 MW related to Werner, which was retired on May 1, 2015.

Summary of Significant Accoun40

Summary of Significant Accounting Policies Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Redeemable Noncontrolling Interest [Table Text Block]	The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the years ended December 31, 2015 , and 2014 . (In millions) Balance as of December 31, 2013 $ 2 Cash contributions from noncontrolling interest 36 Comprehensive loss attributable to noncontrolling interest (19 ) Balance as of December 31, 2014 19 Cash contributions from noncontrolling interest 27 Comprehensive loss attributable to noncontrolling interest (17 ) Balance as of December 31, 2015 $ 29

Business Acquisitions and Dis41

Business Acquisitions and Dispositions (Tables)	12 Months Ended
	Dec. 31, 2015
Edison Mission Energy [Member]
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The purchase price of $3.5 billion was allocated as follows: Acquisition Date Fair Value at December 31, 2014 Measurement period adjustments Revised Acquisition Date (In millions) Assets Cash 1,422 — $ 1,422 Current assets 724 72 796 Property, plant and equipment 2,438 (3 ) 2,435 Intangible assets 172 — 172 Goodwill 334 (56 ) 278 Non-current assets 773 — 773 Total assets acquired 5,863 13 5,876 Liabilities Current and non-current liabilities 629 13 642 Out-of-market contracts and leases 159 — 159 Long-term debt 1,249 — 1,249 Total liabilities assumed 2,037 13 2,050 Less: noncontrolling interest 352 — 352 Net assets acquired $ 3,474 $ — $ 3,474
Alta Wind Portfolio [Member]
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The purchase price of $923 million was allocated as follows: Acquisition Date Fair Value at December 31, 2014 Measurement period adjustments Revised Acquisition Date (In millions) Assets Cash $ 22 — $ 22 Current and non-current assets 49 (2 ) 47 Property, plant and equipment 1,304 6 1,310 Intangible assets 1,177 (6 ) 1,171 Total assets acquired 2,552 (2 ) 2,550 Liabilities Debt 1,591 — 1,591 Current and non-current liabilities 38 (2 ) 36 Total liabilities assumed 1,629 (2 ) 1,627 Net assets acquired $ 923 $ — $ 923

Fair Value of Financial Instr42

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value of Financial Instruments Disclosure [Abstract]
Fair Value Inputs, Assets, Quantitative Information [Table Text Block]	The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of December 31, 2015 , and December 31, 2014 : Significant Unobservable Inputs December 31, 2015 Fair Value Input/Range Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average (In millions) Power Contracts $ 86 $ 100 Discounted Cash Flow Forward Market Price (per MWh) $ 10 $ 92 $ 27 Coal Contracts — 12 Discounted Cash Flow Forward Market Price (per ton) 28 45 35 FTRs 63 70 Discounted Cash Flow Auction Prices (per MWh) (98 ) 87 — $ 149 $ 182 Significant Unobservable Inputs December 31, 2014 Fair Value Input/Range Assets Liabilities Valuation Technique Significant Unobservable Input Low High Weighted Average (In millions) Power Contracts $ 195 $ 154 Discounted Cash Flow Forward Market Price (per MWh) $ 15 $ 92 $ 47 Coal Contracts 3 1 Discounted Cash Flow Forward Market Price (per ton) 53 56 54 FTRs 111 75 Discounted Cash Flow Auction Prices (per MWh) (29 ) 30 — $ 309 $ 230
Estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value	The estimated carrying values and fair values of NRG's recorded financial instruments not carried at fair market value are as follows: As of December 31, 2015 2014 Carrying Amount Fair Value Carrying Amount Fair Value (In millions) Assets Notes receivable (a) $ 73 $ 73 $ 91 $ 91 Liabilities Long-term debt, including current portion (b) 19,620 18,263 20,366 20,361 (a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets. (b) Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets.
Assets and liabilities measured and recorded at fair value on the consolidated balance sheets on a recurring basis	The following tables present assets and liabilities measured and recorded at fair value on the Company's consolidated balance sheets on a recurring basis and their level within the fair value hierarchy: As of December 31, 2015 Fair Value Level 1 Level 2 Level 3 Total (In millions) Investment in available-for-sale securities (classified within other non-current assets): Debt securities $ — $ — $ 17 $ 17 Available-for-sale securities 9 — — 9 Other (a) 14 — — 14 Nuclear trust fund investments: Cash and cash equivalents 6 — — 6 U.S. government and federal agency obligations 54 1 — 55 Federal agency mortgage-backed securities — 59 — 59 Commercial mortgage-backed securities — 25 — 25 Corporate debt securities — 81 — 81 Equity securities 280 — 54 334 Foreign government fixed income securities — 1 — 1 Other trust fund investments: U.S. government and federal agency obligations 1 — — 1 Derivative assets: Commodity contracts 622 1,449 149 2,220 Total assets $ 986 $ 1,616 $ 220 $ 2,822 Derivative liabilities: Commodity contracts $ 868 $ 1,036 $ 182 $ 2,086 Interest rate contracts — 128 — 128 Total liabilities $ 868 $ 1,164 $ 182 $ 2,214 (a) Consists primarily of mutual funds held in a rabbi trust for non-qualified deferred compensation plans for some key and highly compensated employees and a total return swap that does not meet the definition of a derivative. As of December 31, 2014 Fair Value Level 1 Level 2 Level 3 Total (In millions) Investment in available-for-sale securities (classified within other non-current assets): Debt securities $ — $ — $ 18 $ 18 Available-for-sale securities 30 — — 30 Other (a) 21 — 11 32 Nuclear trust fund investments: Cash and cash equivalents 14 — — 14 U.S. government and federal agency obligations 44 3 — 47 Federal agency mortgage-backed securities — 74 — 74 Commercial mortgage-backed securities — 25 — 25 Corporate debt securities — 78 — 78 Equity securities 292 — 52 344 Foreign government fixed income securities — 3 — 3 Other trust fund investments: U.S. government and federal agency obligations 1 — — 1 Derivative assets: Commodity contracts 1,078 1,515 309 2,902 Interest rate contracts — 2 — 2 Equity contracts — — 1 1 Total assets $ 1,480 $ 1,700 $ 391 $ 3,571 Derivative liabilities: Commodity contracts $ 1,004 $ 1,093 $ 230 $ 2,327 Interest rate contracts — 165 — 165 Total liabilities $ 1,004 $ 1,258 $ 230 $ 2,492 (a) Primarily consists of mutual funds held in a rabbi trusts for non-qualified deferred compensation plans for certain former employees and a total return swap that does not meet the definition of a derivative.
Reconciliation of beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs	The following tables reconcile, for the years ended December 31, 2015 , and 2014 , the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs: For the Year Ended December 31, 2015 Fair Value Measurement Using Significant Unobservable Inputs (Level 3) Debt Securities Other Trust Fund Investments Derivatives (a) Total (In millions) Beginning balance as of January 1, 2015 $ 18 $ 11 $ 52 $ 80 $ 161 Total losses realized/unrealized: Included in earnings (1 ) (11 ) — (100 ) (112 ) Included in nuclear decommissioning obligations — — (2 ) — (2 ) Purchases — — 4 (19 ) (15 ) Transfers into Level 3 (b) — — — 3 3 Transfers out of Level 3 (b) — — — 3 3 Ending balance as of December 31, 2015 $ 17 $ — $ 54 $ (33 ) $ 38 Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of December 31, 2015 $ — $ — $ — $ (30 ) $ (30 ) (a) Consists of derivatives assets and liabilities, net. (b) Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2. For the Year Ended December 31, 2014 Fair Value Measurement Using Significant Unobservable Inputs (Level 3) Debt Securities Other Trust Fund Investments Derivatives (a) Total (In millions) Beginning balance as of January 1, 2014 $ 16 $ 10 $ 56 $ 13 $ 95 Total gains/(losses) realized/unrealized: Included in OCI 2 — — — 2 Included in earnings — 1 — (24 ) (23 ) Included in nuclear decommissioning obligations — — (5 ) — (5 ) Purchases — — 2 49 51 Contracts acquired in Dominion and EME acquisitions — — — 39 39 Sales — — (1 ) — (1 ) Transfers into Level 3 (b) — — — 2 2 Transfer out of Level 3 (b) — — — 1 1 Ending balance as of December 31, 2014 $ 18 $ 11 $ 52 $ 80 $ 161 Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of December 31, 2014 $ — $ — $ — $ 20 $ 20 (a) Consists of derivatives assets and liabilities, net. (b) Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2.
Net counterparty credit exposure by industry sector and by counterparty credit quality	The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables. Category Net Exposure (a) (% of Total) Financial institutions 47 % Utilities, energy merchants, marketers and other 36 ISOs 17 Total 100 % Category Net Exposure (a) (% of Total) Investment grade 96 % Non-Investment grade 2 Non-Rated 2 Total 100 % (a) Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.
Fair Value Inputs, Sensitivity Analysis [Table Text Block]	The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of December 31, 2015 , and December 31, 2014 : Significant Unobservable Input Position Change In Input Impact on Fair Value Measurement Forward Market Price Power/Coal Buy Increase/(Decrease) Higher/(Lower) Forward Market Price Power/Coal Sell Increase/(Decrease) Lower/(Higher) FTR Prices Buy Increase/(Decrease) Higher/(Lower) FTR Prices Sell Increase/(Decrease) Lower/(Higher)

Accounting for Derivative Ins43

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting for Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity	The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of December 31, 2015 , and 2014 . Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date. Total Volume Commodity Units December 31, 2015 December 31, 2014 (In millions) Emissions Short Ton 1 2 Coal Short Ton 35 57 Natural Gas MMBtu 293 (58 ) Oil Barrel 1 1 Power MWh (74 ) (56 ) Capacity MW/Day (1 ) — Interest Dollars $ 2,326 $ 3,440 Equity Shares 1 2
Fair value within the derivative instrument valuation on the balance sheets	The following table summarizes the fair value within the derivative instrument valuation on the balance sheet: Fair Value Derivative Assets Derivative Liabilities (In millions) December 31, 2015 December 31, 2014 December 31, 2015 December 31, 2014 Derivatives Designated as Cash Flow or Fair Value Hedges : Interest rate contracts current $ — $ — $ 42 $ 55 Interest rate contracts long-term — 2 68 74 Total Derivatives Designated as Cash Flow or Fair Value Hedges — 2 110 129 Derivatives Not Designated as Cash Flow or Fair Value Hedges : Interest rate contracts current — — 5 8 Interest rate contracts long-term — — 13 28 Commodity contracts current 1,915 2,425 1,674 1,991 Commodity contracts long-term 305 477 412 336 Equity contracts long-term — 1 — — Total Derivatives Not Designated as Cash Flow or Fair Value Hedges 2,220 2,903 2,104 2,363 Total Derivatives $ 2,220 $ 2,905 $ 2,214 $ 2,492
Offsetting of derivatives by counterparty master agreement level and collateral received or paid	The following table summarizes the offsetting derivatives by counterparty master agreement level and collateral received or paid: Gross Amounts Not Offset in the Statement of Financial Position Gross Amounts of Recognized Assets/Liabilities Derivative Instruments Cash Collateral (Held)/Posted Net Amount As of December 31, 2015 (In millions) Commodity contracts: Derivative assets $ 2,220 $ (1,616 ) $ (113 ) $ 491 Derivative liabilities (2,086 ) 1,616 271 (199 ) Total commodity contracts 134 — 158 292 Interest rate contracts: Derivative liabilities (128 ) — — (128 ) Total derivative instruments $ 6 $ — $ 158 $ 164 Gross Amounts Not Offset in the Statement of Financial Position Gross Amounts of Recognized Assets/Liabilities Derivative Instruments Cash Collateral (Held)/Posted Net Amount As of December 31, 2014 (In millions) Commodity contracts: Derivative assets $ 2,902 $ (2,155 ) $ (72 ) $ 675 Derivative liabilities (2,327 ) 2,155 27 (145 ) Total commodity contracts 575 — (45 ) 530 Interest rate contracts: Derivative assets 2 (2 ) — — Derivative liabilities (165 ) 2 — (163 ) Total interest rate contracts (163 ) — — (163 ) Equity contracts: Derivative assets 1 — — 1 Total derivative instruments $ 413 $ — $ (45 ) $ 368
Effects of ASC 815 on the Company's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax	The following tables summarize the effects on NRG's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax: Year Ended December 31, 2015 Energy Commodities Interest Rate Total (In millions) Accumulated OCI balance at December 31, 2014 $ (1 ) $ (67 ) $ (68 ) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts 1 14 15 Mark-to-market of cash flow hedge accounting contracts — (48 ) (48 ) Accumulated OCI balance at December 31, 2015, net of $16 tax — (101 ) (101 ) Losses expected to be realized from OCI during the next 12 months, net of $3 tax $ — $ (18 ) $ (18 ) There were no gains or losses recognized in income from the ineffective portion of cash flow hedges for the year ended December 31, 2015 . Year Ended December 31, 2014 Energy Commodities Interest Rate Total (In millions) Accumulated OCI balance at December 31, 2013 $ (1 ) $ (22 ) $ (23 ) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts — 13 13 Mark-to-market of cash flow hedge accounting contracts — (58 ) (58 ) Accumulated OCI balance at December 31, 2014, net of $35 tax $ (1 ) $ (67 ) $ (68 ) There were no gains or losses recognized in income from the ineffective portion of cash flow hedges for the year ended December 31, 2014 . Year Ended December 31, 2013 Energy Commodities Interest Rate Total (In millions) Accumulated OCI balance at December 31, 2012 $ 41 $ (72 ) $ (31 ) Reclassified from accumulated OCI to income: Due to realization of previously deferred amounts (51 ) 20 (31 ) Mark-to-market of cash flow hedge accounting contracts 9 30 39 Accumulated OCI balance at December 31, 2013, net of $14 tax $ (1 ) $ (22 ) $ (23 )
Pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges and trading activity on the Company's statement of operations	The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges, and trading activity on NRG's statement of operations. The effect of commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges is included in interest expense. Year Ended December 31, 2015 2014 2013 (In millions) Unrealized mark-to-market results Reversal of previously recognized unrealized gains on settled positions related to economic hedges $ (275 ) $ (15 ) $ (105 ) Reversal of acquired gain positions related to economic hedges (106 ) (333 ) (357 ) Net unrealized gains on open positions related to economic hedges 9 361 177 Total unrealized mark-to-market (losses)/gains for economic hedging activities (372 ) 13 (285 ) Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity (46 ) 1 (50 ) Reversal of acquired gain positions related to trading activity (14 ) (32 ) — Net unrealized (losses)/gains on open positions related to trading activity (16 ) 45 7 Total unrealized mark-to-market (losses)/gains for trading activity (76 ) 14 (43 ) Total unrealized (losses)/gains $ (448 ) $ 27 $ (328 ) Year Ended December 31, 2015 2014 2013 (In millions) Unrealized (losses)/gains included in operating revenues $ (320 ) $ 515 $ (621 ) Unrealized (losses)/gains included in cost of operations (128 ) (488 ) 293 Total impact to statement of operations — energy commodities $ (448 ) $ 27 $ (328 ) Total impact to statement of operations — interest rate contracts $ 17 $ (31 ) $ 15

Nuclear Decommissioning Trust44

Nuclear Decommissioning Trust Fund (Tables)	12 Months Ended
	Dec. 31, 2015
Nuclear Decommissioning Trust Fund Disclosure [Abstract]
Summary of aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the nuclear decommissioning trust fund	The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities. As of December 31, 2015 As of December 31, 2014 (In millions, except otherwise noted) Fair Value Unrealized Gains Unrealized Losses Weighted- average maturities (in years) Fair Value Unrealized Gains Unrealized Losses Weighted- average maturities (in years) Cash and cash equivalents $ 6 $ — $ — — $ 14 $ — $ — — U.S. government and federal agency obligations 55 1 — 11 47 2 — 11 Federal agency mortgage-backed securities 59 1 — 25 74 2 — 25 Commercial mortgage-backed securities 25 — 2 28 25 — 1 30 Corporate debt securities 81 1 1 10 78 2 1 11 Equity securities 334 199 — — 344 211 — — Foreign government fixed income securities 1 — — 9 3 1 — 16 Total $ 561 $ 202 $ 3 $ 585 $ 218 $ 2
Summary of proceeds from sales of available-for-sale securities and the related realized gains and losses	The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined using the specific identification method. Year Ended December 31, 2015 2014 2013 (In millions) Realized gains $ 21 $ 29 $ 25 Realized losses 14 8 8 Proceeds from sale of securities 631 600 488

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Schedule of Inventory	Inventory consisted of: As of December 31, 2015 2014 (In millions) Fuel oil $ 312 $ 375 Coal/Lignite 471 414 Natural gas 12 16 Spare parts 437 424 Other 20 18 Total Inventory $ 1,252 $ 1,247

Notes Receivable (Tables)

Notes Receivable (Tables)	12 Months Ended
	Dec. 31, 2015
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Schedule of NRG's notes receivable and capital leases	NRG's notes receivable were as follows: As of December 31, 2015 2014 (In millions) Notes receivable $ 73 $ 91 Less current maturities (a) 20 19 Total notes receivable — noncurrent $ 53 $ 72 (a) The current portion of notes receivable is recorded in prepayments and other current assets on the consolidated balance sheets.

Property, Plant and Equipment47

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
NRG's major classes of property, plant and equipment	NRG's major classes of property, plant, and equipment were as follows: As of December 31, Depreciable 2015 2014 Lives (In millions) Facilities and equipment $ 22,676 $ 27,457 1-40 Years Land and improvements 1,226 1,194 Nuclear fuel 545 490 5 Years Office furnishings and equipment 462 346 2-10 Years Construction in progress 627 770 Total property, plant, and equipment 25,536 30,257 Accumulated depreciation (6,804 ) (7,890 ) Net property, plant, and equipment $ 18,732 $ 22,367

Goodwill an Other Intangibles (

Goodwill an Other Intangibles (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill and Other Intangibles Disclosure [Abstract]
Schedule of Out of Market Contracts, Future Amortization [Table Text Block]	The following table summarizes the estimated amortization related to NRG's out-of-market contracts: Year Ended December 31, Power Contracts Leases Gas Transportation Total (In millions) 2016 $ 16 47 $ 42 $ 105 2017 16 47 37 100 2018 16 47 32 95 2019 17 47 29 93 2020 17 47 29 93
Finite-lived Intangible Assets Amortization Expense [Table Text Block]	The following table presents NRG's amortization of intangible assets for each of the past three years: Years Ended December 31, Amortization 2015 2014 2013 (In millions) Emission allowances $ 99 $ 124 $ 104 Energy supply contracts 5 6 6 Fuel contracts 2 2 2 Customer contracts 2 — 53 Customer relationships 67 70 72 Marketing partnerships 14 15 8 Trade names 23 21 29 Power purchase agreements 50 24 1 Other 15 6 4 Total amortization $ 277 $ 268 $ 279
Summary of the components of NRG's intangible assets subject to amortization	The following tables summarize the components of NRG's intangible assets subject to amortization: Contracts Year Ended December 31, 2015 Emission Allowances Energy Supply Fuel Customer Customer Relationships Marketing Partnerships Trade Names PPA Other Total (In millions) January 1, 2015 $ 1,018 $ 54 $ 72 $ 16 $ 831 $ 88 $ 353 $ 1,269 $ 268 $ 3,969 Purchases 77 — — — 3 — — — 57 137 Usage (33 ) — — — — — — — (62 ) (95 ) Write-off of fully amortized balances (154 ) — — — — — — — — (154 ) Impairment — — — — — — (6 ) — (5 ) (11 ) Other 12 — — — — — (5 ) (6 ) (12 ) (11 ) December 31, 2015 920 54 72 16 834 88 342 1,263 246 3,835 Less accumulated amortization (a) (502 ) (47 ) (65 ) (6 ) (624 ) (41 ) (137 ) (75 ) (28 ) (1,525 ) Net carrying amount $ 418 $ 7 $ 7 $ 10 $ 210 $ 47 $ 205 $ 1,188 $ 218 $ 2,310 (a) Adjusted for write-off of fully amortized emissions allowances of $154 million . Contracts Year Ended December 31, 2014 Emission Allowances Energy Supply Fuel Customer Customer Relationships Marketing Partnerships Trade Names PPA Other Total (In millions) January 1, 2014 $ 871 $ 54 $ 72 $ 859 $ 743 $ 88 $ 318 $ 14 $ 98 $ 3,117 Purchases 141 — — — 8 — — — 33 182 Acquisition of businesses 12 — — — 80 — 35 1,252 162 1,541 Usage — — — — — — — — (34 ) (34 ) Write-off of fully amortized balances — — — (843 ) — — — — — (843 ) Other (6 ) — — — — — — 3 9 6 December 31, 2014 1,018 54 72 16 831 88 353 1,269 268 3,969 Less accumulated amortization (a) (557 ) (42 ) (63 ) (4 ) (557 ) (27 ) (114 ) (25 ) (13 ) (1,402 ) Net carrying amount $ 461 $ 12 $ 9 $ 12 $ 274 $ 61 $ 239 $ 1,244 $ 255 $ 2,567 (a) Adjusted for write-off of fully amortized customer contracts of $843 million .
Schedule of estimated amortization of NRG's intangible assets for each of the next five years	The following table presents estimated amortization of NRG's intangible assets for each of the next five years: Contracts Year Ended December 31, Emission Allowances Energy Supply Fuel Customer Customer Relationships Marketing Partnerships Trade Names PPA Other Total 2016 $ 112 $ 7 $ 2 $ 1 $ 48 $ 9 $ 23 $ 63 $ 10 $ 275 2017 53 — 1 1 33 5 23 63 10 189 2018 48 — — 1 20 5 23 63 10 170 2019 32 — — 1 16 4 23 63 9 148 2020 17 — — 1 14 4 23 63 7 129

Debt and Capital Leases (Tables

Debt and Capital Leases (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Instrument
Long-term debt and capital leases	Long-term debt and capital leases consisted of the following: As of December 31, December 31, 2015 2015 2014 Interest Rate % (a) (In millions except rates) NRG Recourse Debt: Senior notes, due 2018 $ 1,039 $ 1,130 7.625 Senior notes, due 2020 1,058 1,063 8.250 Senior notes, due 2021 1,128 1,128 7.875 Senior notes, due 2022 1,100 1,100 6.250 Senior notes, due 2023 936 990 6.625 Senior notes, due 2024 904 1,000 6.250 Term loan facility, due 2018 1,964 1,983 L+2.00 Tax Exempt Bonds 455 406 4.125 - 6.00 Subtotal NRG Recourse Debt 8,584 8,800 NRG Non-Recourse Debt: GenOn senior notes 1,956 2,133 7.875 - 9.875 GenOn Americas Generation senior notes 752 929 8.500 - 9.125 GenOn Other 56 60 Subtotal GenOn debt (non-recourse to NRG) 2,764 3,122 Yield Operating LLC Senior Notes, due 2024 500 500 5.375 Yield LLC and Yield Operating LLC Revolving Credit Facility, due 2019 306 — L+2.75 Yield Inc. Convertible Senior Notes, due 2019 330 326 3.500 Yield Inc. Convertible Senior Notes, due 2020 266 — 3.250 El Segundo Energy Center, due 2023 485 506 L+1.625 - L+2.25 Marsh Landing, due 2017 and 2023 418 464 L+1.75 - L+1.875 Alta Wind I-V lease financing arrangements, due 2034 and 2035 1,002 1,036 5.696 - 7.015 Alta Wind X, due 2021 — 300 L+2.00 Alta Wind XI, due 2021 — 191 L+2.00 Walnut Creek, term loans due 2023 351 391 L+1.625 Tapestry, due 2021 181 192 L+1.625 Laredo Ridge, due 2028 104 108 L+1.875 Alpine, due 2022 154 163 L+1.750 Energy Center Minneapolis, due 2017, and 2025 108 121 5.95 - 7.25 Viento, due 2023 189 196 L+2.75 Yield Other 469 489 various Subtotal Yield debt (non-recourse to NRG) 4,863 4,983 Ivanpah, due 2033 and 2038 1,149 1,183 2.285 - 4.256 Agua Caliente, due 2037 879 898 2.395 - 3.633 CVSR, due 2037 793 815 2.339 - 3.775 Dandan, due 2033 98 54 L+2.25 Peaker bonds, due 2019 72 100 L+1.07 Cedro Hill, due 2025 103 111 L+3.125 NRG Other 315 300 various Subtotal other NRG non-recourse debt 3,409 3,461 Subtotal all non-recourse debt 11,036 11,566 Subtotal long-term debt (including current maturities) 19,620 20,366 Capital leases: Home Solar capital leases 13 — various Chalk Point capital lease, due 2015 — 5 8.190 Other 3 3 various Subtotal long-term debt and capital leases (including current maturities) 19,636 20,374 Less current maturities 481 474 Less debt issuance costs (b) $ 172 $ 199 Total long-term debt and capital leases $ 18,983 $ 19,701 (a) As of December 31, 2015 , L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Marsh Landing term loan, Walnut Creek loan, and Yield Operating LLC Revolving Credit facility, which are 1 month LIBOR plus x% (b) Total net debt reflects the reclassification of deferred financing costs to reduce long-term debt as further described in Note 2, Summary of Significant Accounting Policies . Long-term debt includes the following premiums/(discounts): As of December 31, 2015 2014 (in millions) Term loan facility, due 2018 (a) $ (3 ) $ (4 ) Peaker bonds, due 2019 (b) (4 ) (6 ) Yield, Inc. Convertible notes, due 2019 (15 ) (19 ) Yield, Inc. Convertible notes, due 2020 (21 ) — GenOn senior notes, due 2017 (c) 23 41 GenOn senior notes, due 2018 (c) 59 83 GenOn senior notes, due 2020 (c) 44 60 GenOn Americas Generation senior notes, due 2021 (c) 32 46 GenOn Americas Generation senior notes, due 2031 (c) 25 33 Total premium/(discount) $ 140 $ 234 (a) Discount of $1 million is related to current maturities in 2015 and 2014 . (b) Discount of $2 million are related to current maturities in 2015 and 2014 . (c) Premiums for long-term debt acquired in the GenOn acquisition represent adjustments to record the debt at fair value in connection with the acquisition.
Schedule of swaps related to project level debt	The following table summarizes the swaps, some of which are forward starting as indicated, related to NRG's project level debt as of December 31, 2015 . Non-Recourse Debt % of Principal Fixed Interest Rate Floating Interest Rate Notional Amount at December 31, 2015 (In millions) Effective Date Maturity Date NRG Peaker Finance Co. LLC 100 % 6.673 % 3-mo. LIBOR + 1.07% $ 76 June 18, 2002 June 10, 2019 NRG West Holdings LLC 75 % 2.417 % 3-mo. LIBOR 358 November 30, 2011 August 31, 2023 South Trent Wind LLC 75 % 3.265 % 3-mo. LIBOR 46 June 15, 2010 June 14, 2020 South Trent Wind LLC 75 % 4.95 % 3-mo. LIBOR 21 June 30, 2020 June 14, 2028 NRG Solar Roadrunner LLC 75 % 4.313 % 3-mo. LIBOR 30 September 30, 2011 December 31, 2029 NRG Solar Alpine LLC 85 % 2.744 % 3-mo. LIBOR 122 various December 31, 2029 NRG Solar Alpine LLC 85 % 2.421 % 3-mo. LIBOR 9 June 24, 2014 June 30, 2025 NRG Solar Avra Valley LLC 85 % 2.333 % 3-mo. LIBOR 51 November 30, 2012 November 30, 2030 NRG Marsh Landing 75 % 3.244 % 3-mo. LIBOR 387 June 28, 2013 June 30, 2023 Other 75 % various various 154 various various EME Project Financings Broken Bow 75 % 2.960 % 3-mo. LIBOR 41 December 31, 2013 December 21, 2027 Cedro Hill 90 % 4.290 % 3-mo. LIBOR 93 December 31, 2010 December 31, 2025 Crofton Bluffs 75 % 2.748 % 3-mo. LIBOR 21 December 31, 2013 December 21, 2027 Laredo Ridge 75 % 2.310 % 3-mo. LIBOR 83 March 31, 2011 March 31, 2026 Tapestry 75 % 2.210 % 3-mo. LIBOR 163 December 30, 2011 December 21, 2021 Tapestry 50 % 3.570 % 3-mo. LIBOR 60 December 21, 2021 December 21, 2029 Viento Funding II 90 % various 6-mo. LIBOR 170 various various Viento Funding II 90 % 4.985 % 6-mo. LIBOR 65 July 11, 2023 June 30, 2028 Walnut Creek Energy 75 % various 3-mo. LIBOR 311 June 28, 2013 May 31, 2023 WCEP Holdings 90 % 4.003 % 3-mo. LIBOR 46 June 28, 2013 May 21, 2023 Subtotal EME 1,053 Alta Wind Project Financings AWAM 100 % 2.470 % 3-mo. LIBOR 19 May 22, 2013 May 15, 2031 Subtotal Alta Wind 19 Total 2,326
Annual payments based on the maturities of NRG's debt	Annual payments based on the maturities of NRG's debt and capital leases, for the years ending after December 31, 2015 , are as follows: (In millions) 2016 $ 484 2017 1,153 2018 4,008 2019 1,052 2020 2,288 Thereafter 10,511 Total $ 19,496
GenOn Americas Generation senior notes
Debt Instrument
Schedule of Long-term Debt Instruments [Table Text Block]	As of December 31, 2015 2014 Interest Rate % Amount in millions, except rates Senior unsecured notes, due 2021 398 496 8.500 Senior unsecured notes, due 2031 354 433 9.125 Total $ 752 $ 929
Debt Instrument Redemption [Table Text Block]	During the fourth quarter of 2015, the Company repurchased $155 million in aggregate principal of the following outstanding Senior Notes in the open market for $128 million , including accrued interest. Principal Repurchased Average Early Redemption Percentage Gain on Debt Extinguishment Amount in millions, except rates Senior unsecured notes, due 2021 $ 84 84.910 % $ 20 Senior unsecured notes, due 2031 71 77.018 % 22 Total $ 155 $ 42
Tax Exempt Bonds
Debt Instrument
Schedule of Long-term Debt Instruments [Table Text Block]	Tax Exempt Bonds As of December 31, 2015 2014 Interest Rate % Amount in millions, except rates Indian River Power tax exempt bonds, due 2040 57 57 6.000 Indian River Power LLC, tax exempt bonds, due 2045 190 190 5.375 Dunkirk Power LLC, tax exempt bonds, due 2042 59 59 5.875 Fort Bend County, tax exempt bonds, due 2045 22 10 4.125 Fort Bend County, tax exempt bonds, due 2038 54 54 4.750 Fort Bend County, tax exempt bonds, due 2042 73 36 4.750 Total $ 455 $ 406
Senior Notes [Member]
Debt Instrument
Debt Instrument Redemption [Table Text Block]	In 2014, the Company redeemed $1.4 billion in aggregate principal of its Senior Notes, due 2019 for $1.5 billion , including accrued interest. Principal Redeemed Average Early Redemption Percentage Loss on Debt Extinguishment Amount in millions, except rates 8.5% Senior Note, due 2019 $ 607 105.764 % $ 45 7.625% Senior Note, due 2019 800 104.169 % 41 Total $ 1,407 $ 86 During the fourth quarter of 2015, the Company repurchased $246 million in aggregate principal of the following outstanding Senior Notes in the open market for $231 million , including accrued interest. Principal Repurchased Average Early Redemption Percentage Gain/(Loss) on Debt Extinguishment Amount in millions, except rates 8.25% Senior Note, due 2020 $ 5 96.500 % $ — 6.625% Senior Note, due 2023 54 85.972 % 7 6.25% Senior Note, due 2024 95 84.725 % 14 7.625% Senior Note, due 2018 92 102.232 % (2 ) Total $ 246 $ 19
Senior notes, due 2020
Debt Instrument
Debt Instrument Redemption [Table Text Block]	NRG may redeem some or all of the 2020 Senior Notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: Redemption Period Redemption Percentage On or after September 1, 2015 104.125 % On or after September 1, 2016 102.750 % On or after September 1, 2017 101.375 % September 1, 2018 and thereafter 100.000 %
Senior notes, due 2021
Debt Instrument
Debt Instrument Redemption [Table Text Block]	In addition, on or after May 15, 2016, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: Redemption Period Redemption Percentage May 15, 2016 to May 14, 2017 103.938 % May 15, 2017 to May 14, 2018 102.625 % May 15, 2018 to May 14, 2019 101.313 % May 15, 2019 and thereafter 100.000 %
Senior notes, due 2023
Debt Instrument
Debt Instrument Redemption [Table Text Block]	In addition, on or after September 15, 2017, NRG may redeem some or all of the 2023 Senior Notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: Redemption Period Redemption Percentage September 15, 2017 to September 14, 2018 103.313 % September 15, 2018 to September 14, 2019 102.208 % September 15, 2019 to September 14, 2020 101.104 % September 15, 2020 and thereafter 100.000 %
GenOn senior notes, due 2020
Debt Instrument
Debt Instrument Redemption [Table Text Block]	GenOn may redeem some or all of the Senior Notes due 2020 at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption rate: Redemption Period Redemption Percentage October 15, 2015 to October 14, 2016 104.938 % October 15, 2016 to October 14, 2017 103.292 % October 15, 2017 to October 14, 2018 101.646 % October 15, 2018 and thereafter 100.000 %
Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument Redemption [Table Text Block]	In addition, on or after July 15, 2018, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: Redemption Period Redemption Percentage July 15, 2018 to July 14, 2019 103.125 % July 15, 2019 to July 14, 2020 101.563 % July 15, 2020 and thereafter 100.000 %
Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument Redemption [Table Text Block]	In addition, on or after May 1, 2019, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date: Redemption Period Redemption Percentage May 1, 2019 to April 30, 2020 103.125 % May 1, 2020 to April 30, 2021 102.083 % May 1, 2021 to April 30, 2022 101.042 % May 1, 2022 and thereafter 100.000 %
GenOn Senior Notes [Member]
Debt Instrument
Schedule of Long-term Debt Instruments [Table Text Block]	As of December 31, 2015 2014 Interest Rate % Amount in millions, except rates Senior unsecured notes, due 2017 714 766 7.875 Senior unsecured notes, due 2018 708 757 9.500 Senior unsecured notes, due 2020 534 610 9.875 Total $ 1,956 $ 2,133
Debt Instrument Redemption [Table Text Block]	During the fourth quarter of 2015, the Company repurchased $119 million in aggregate principal of the following outstanding Senior Notes in the open market for $108 million , including accrued interest. Principal Repurchased Average Early Redemption Percentage Gain on Debt Extinguishment Amount in millions, except rates Senior unsecured notes, due 2017 $ 33 95.172 % $ 3 Senior unsecured notes, due 2018 25 90.950 % 5 Senior unsecured notes, due 2020 61 83.847 % 15 Total $ 119 $ 23
Leasing Arrangement [Member]
Debt Instrument
Schedule of Project level debt assumed during acquisition [Table Text Block]	Amount in millions, except rates Lease Financing Arrangement Letter of Credit Facility Non-Recourse Debt Amount Outstanding as of December 31, 2015 Interest Rate Maturity Date Amount Outstanding as of December 31, 2015 Interest Rate Maturity Date Alta Wind I $ 252 7.015% 12/30/2034 $ 16 3.250% 1/5/2021 Alta Wind II 198 5.696% 12/30/2034 28 2.750% 6/30/2017& 12/31/2017 Alta Wind III 206 6.067% 12/30/2034 28 2.750% 4/13/2018 Alta Wind IV 133 5.938% 12/30/2034 19 2.750% 8/24/2018 Alta Wind V 213 6.071% 6/30/2035 31 2.750% 10/24/2018 Total $ 1,002 $ 122

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of company's ARO obligations and related additions, reductions and accretion	The following table represents the balance of ARO obligations as of December 31, 2015 , and 2014 , along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2015 : (In millions) Balance as of December 31, 2014 $ 763 Revisions in estimates for current obligations 122 Additions 18 Additions for acquisitions 2 Spending for current obligations (11 ) Accretion — Expense 35 Accretion — Nuclear decommissioning 16 Balance as of December 31, 2015 $ 945

Benefit Plans and Other Postr51

Benefit Plans and Other Postretirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Annual net periodic benefit cost related to NRG's pension and other postretirement benefit plans	The annual net periodic benefit cost/(credit) related to NRG's pension and other postretirement benefit plans include the following components: Year Ended December 31, Pension Benefits 2015 2014 2013 (In millions) Service cost benefits earned $ 32 $ 30 $ 30 Interest cost on benefit obligation 53 53 47 Expected return on plan assets (62 ) (62 ) (55 ) Amortization of unrecognized net loss/(gain) 2 (6 ) 9 Curtailment — — (1 ) Net periodic benefit cost $ 25 $ 15 $ 30 Year Ended December 31, Other Postretirement Benefits 2015 2014 2013 (In millions) Service cost benefits earned $ 3 $ 3 $ 4 Interest cost on benefit obligation 9 9 9 Amortization of unrecognized prior service credit (5 ) (17 ) — Amortization of unrecognized net loss 1 — — Curtailment gain (14 ) — — Net periodic benefit (credit)/cost $ (6 ) $ (5 ) $ 13
Pension benefit obligation, other post retirement benefit obligations and related plan assets for NRG plans on a combined basis	A comparison of the pension benefit obligation, other postretirement benefit obligations and related plan assets for NRG's plans on a combined basis is as follows: As of December 31, Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 (In millions) Benefit obligation at January 1 $ 1,305 $ 1,060 $ 238 $ 191 Obligations resulting from the EME acquisition — 43 — 16 Service cost 32 30 3 3 Interest cost 53 53 9 9 Plan amendments — — (6 ) (18 ) Actuarial (gain)/loss (120 ) 174 (31 ) 46 Employee and retiree contributions — — 2 3 Benefit payments (74 ) (55 ) (12 ) (12 ) Curtailment — — (25 ) — Benefit obligation at December 31 1,196 1,305 178 238 Fair value of plan assets at January 1 988 880 — — Actual return on plan assets (26 ) 85 — — Employee and retiree contributions — — 2 3 Employer contributions 28 78 10 9 Benefit payments (74 ) (55 ) (12 ) (12 ) Fair value of plan assets at December 31 916 988 — — Funded status at December 31 — excess of obligation over assets $ (280 ) $ (317 ) $ (178 ) $ (238 )
Amounts recognized in NRG's balance sheets	Amounts recognized in NRG's balance sheets were as follows: As of December 31, Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 (In millions) Current liabilities $ — $ — $ 12 $ 10 Non-current liabilities 280 317 166 228
Amounts recognized in NRG's accumulated OCI that have not yet been recognized as components of net periodic benefit cost	Amounts recognized in NRG's accumulated OCI that have not yet been recognized as components of net periodic benefit cost were as follows: As of December 31, Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 (In millions) Net loss/(gain) $ 68 $ 101 $ (9 ) $ 34 Prior service cost/(credit) 3 4 (9 ) (7 )
Other changes in plan assets and benefit obligations recognized in OCI	Other changes in plan assets and benefit obligations recognized in OCI were as follows: Year Ended December 31, Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 (In millions) Net actuarial (gain)/loss $ (31 ) $ 152 $ (31 ) $ 46 Amortization of net actuarial (gain)/loss (2 ) 6 (1 ) — Prior service (credit)/cost (1 ) — (7 ) (18 ) Amortization of prior service cost — — 5 17 Curtailment — — (11 ) — Total recognized in other comprehensive (income)/loss $ (34 ) $ 158 $ (45 ) $ 45 Total recognized in net periodic pension (credit)/cost and other comprehensive (income)/loss $ (8 ) $ 173 $ (37 ) $ 40
Balances of significant components of NRG's domestic pension plan	The following table presents the balances of significant components of NRG's pension plan: As of December 31, Pension Benefits 2015 2014 (In millions) Projected benefit obligation $ 1,196 $ 1,305 Accumulated benefit obligation 1,115 1,172 Fair value of plan assets 916 988
Fair values of the Company's pension plan assets by asset category and their level within the fair value hierarchy	NRG's market-related value of its plan assets is the fair value of the assets. The fair values of the Company's pension plan assets by asset category and their level within the fair value hierarchy are as follows: Fair Value Measurements as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Total (In millions) Common/collective trust investment — U.S. equity $ — $ 255 $ 255 Common/collective trust investment — non-U.S. equity — 147 147 Common/collective trust investment — global equity — 90 90 Common/collective trust investment — fixed income — 400 400 Partnerships/joint ventures — 18 18 Short-term investment fund 6 — 6 Total $ 6 $ 910 $ 916 Fair Value Measurements as of December 31, 2014 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Total (In millions) Common/collective trust investment — U.S. equity $ — $ 287 $ 287 Common/collective trust investment — non-U.S. equity — 149 149 Common/collective trust investment — global equity — 96 96 Common/collective trust investment — fixed income — 431 431 Partnerships/joint ventures — 21 21 Short-term investment fund 4 — 4 Total $ 4 $ 984 $ 988
Significant assumptions used to calculate NRG's benefit obligations and benefit expense	The following table presents the significant assumptions used to calculate NRG's benefit obligations: As of December 31, Pension Benefits Other Postretirement Benefits Weighted-Average Assumptions 2015 2014 2015 2014 Discount rate 4.52 % 4.16 % 4.55 % 4.20 % Rate of compensation increase 3.00 % 3.45 % N/A N/A Health care trend rate — — 7.25% grading to 5.0% in 2025 8.6% grading to The following table presents the significant assumptions used to calculate NRG's benefit expense: As of December 31, Pension Benefits Other Postretirement Benefits Weighted-Average Assumptions 2015 2014 2013 2015 2014 2013 Discount rate 4.16 % 4.99 % 4.16 % 4.20 % 5.06 % 4.31 % Expected return on plan assets 6.36 % 6.81 % 7.12 % — — — Rate of compensation increase 3.45 % 3.65 % 3.57 % — — — Health care trend rate — — — 8.6% grading to 5.0% in 2023 8.5% grading to 5.5% in 2019 8.3% grading to
Target allocations of NRG's pension plan assets	The target allocations of NRG's pension plan assets were as follows for the year ended December 31, 2015 : U.S. equity 27 % Non-U.S. equity 15 % Global equity 10 % Emerging market equity 3 % U.S. fixed income 45 %
Expected future benefit payments for each of the next five years and in the aggregate for the five years thereafter	NRG's expected future benefit payments for each of the next five years, and in the aggregate for the five years thereafter, are as follows: Other Postretirement Benefit Pension Benefit Payments Benefit Payments Medicare Prescription Drug Reimbursements (In millions) 2016 $ 60 $ 12 $ — 2017 64 9 — 2018 67 10 — 2019 71 10 — 2020 75 10 — 2021-2025 409 52 1
Effect of one-percentage-point change in assumed health care cost trend rates	Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect: 1-Percentage- Point Increase 1-Percentage- Point Decrease (In millions) Effect on total service and interest cost components $ 1 $ (1 ) Effect on postretirement benefit obligation 13 (11 )
Contributions to defined contribution plans	The Company's contributions to these plans were as follows: Year Ended December 31, 2015 2014 2013 (In millions) Company contributions to defined contribution plans $ 53 $ 47 $ 34
South Texas Project Units 1 And 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Amounts recognized in NRG's statement of fiancial position, statement of operations and accumulated OCI related to its interest in STP	The Company has recognized the following in its statement of financial position, statement of operations and accumulated OCI related to its 44% interest in STP: As of December 31, Pension Benefits Other Postretirement Benefits 2015 2014 2015 2014 (In millions) Funded status — STPNOC benefit plans $ (63 ) $ (71 ) $ (26 ) $ (30 ) Net periodic benefit cost/(credit) 10 6 (8 ) 3 Other changes in plan assets and benefit obligations recognized in other comprehensive income (8 ) 37 6 (29 )

Capital Structure (Tables)

Capital Structure (Tables)	12 Months Ended
	Dec. 31, 2015
Preferred Units [Line Items]
Class of Treasury Stock [Table Text Block]	The Company's board of directors authorized share repurchases of $481 million of its common stock, which were made as follows: Total number of shares purchased Average price paid per share (a) Amounts paid for shares purchased (in millions) (a) Board Authorized Share Repurchases Fourth Quarter 2014 1,624,360 $ 26.95 $ 44 First Quarter 2015 3,146,484 25.15 79 Second Quarter 2015 4,379,907 24.53 107 Third Quarter 2015 11,104,184 15.06 167 Fourth Quarter 2015 5,558,920 15.03 84 Total Board Authorized Share Repurchases 25,813,855 $ 481 (a) The average price paid per share and amounts paid for shares purchased exclude the commissions of $0.015 per share paid in connection with the share repurchase.
Temporary Equity [Table Text Block]	The following table reflects the changes in the Company's redeemable preferred stock balance for the years ended December 31, 2015 , and 2014 . (In millions) Balance as of December 31, 2013 $ 249 Loss recorded in connection with extinguishment of 3.625% preferred stock and issuance of 2.822% preferred stock 42 Balance as of December 31, 2014 291 Accretion to redemption value 11 Balance as of December 31, 2015 $ 302
Changes in NRG's common shares issued and outstanding	The following table reflects the changes in NRG's common shares issued and outstanding for each period presented: Common Issued Treasury Outstanding Balance as of December 31, 2012 399,112,616 (76,505,718 ) 322,606,898 Shares issued under ESPP — 130,482 130,482 Shares issued under LTIPs 2,014,164 — 2,014,164 Share repurchases — (972,292 ) (972,292 ) Balance as of December 31, 2013 401,126,780 (77,347,528 ) 323,779,252 Shares issued under ESPP — 128,336 128,336 Shares issued under LTIPs 1,707,419 — 1,707,419 Shares issued in connection with the EME acquisition 12,671,977 — 12,671,977 Share repurchases — (1,624,360 ) (1,624,360 ) Balance as of December 31, 2014 415,506,176 (78,843,552 ) 336,662,624 Shares issued under ESPP — 283,139 283,139 Shares issued under LTIPs 1,433,774 — 1,433,774 Share repurchases — (24,189,495 ) (24,189,495 ) Balance as of December 31, 2015 416,939,950 (102,749,908 ) 314,190,042
NRG's common stock reserved for the maximum number of shares potentially issuable based on the conversion and redemption features of outstanding equity instruments and the long-term incentive plans	The following table summarizes NRG's common stock reserved for the maximum number of shares potentially issuable based on the conversion and redemption features of outstanding equity instruments and the long-term incentive plans as of December 31, 2015 : Equity Instrument Common Stock Reserve Balance 2.822% Convertible perpetual preferred 16,000,000 Long-term incentive plans 17,979,967 Total 33,979,967
Dividends paid per common share	The following table lists the dividends paid per common share during 2015 , 2014 and 2013 : Fourth Quarter Third Quarter Second Quarter First Quarter 2015 $ 0.145 $ 0.145 $ 0.145 $ 0.145 2014 $ 0.140 $ 0.140 $ 0.140 $ 0.120 2013 $ 0.120 $ 0.120 $ 0.120 $ 0.090

Investments Accounted for by 53

Investments Accounted for by the Equity Method and Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Additional Financial Information Disclosure [Text Block]	The summarized financial information for the Company's consolidated VIEs consisted of the following: (In millions) December 31, 2015 Current assets $ 84 Net property, plant and equipment 1,807 Other long-term assets 863 Total assets 2,754 Current liabilities 56 Long-term debt 366 Other long-term liabilities 179 Total liabilities 601 Noncontrolling interests 493 Net assets less noncontrolling interests $ 1,660
Undistributed earnings by equity investment	As of December 31, 2015 2014 (In millions) Undistributed earnings from equity investments $ 55 $ 76
Summary NRG's equity method investments	The following table summarizes NRG's significant equity method investments as of December 31, 2015 : Name Economic Interest Investment Balance (in millions) Avenal Solar Holdings LLC (a) 50.0 % $ (9 ) Community Wind North, LLC 99.0 % 57 Desert Sunlight Investment Holdings, LLC (a) 25.0 % 291 Elkhorn Ridge Wind, LLC (a) 66.7 % 96 GenConn Energy LLC (a) 50.0 % 110 Midway-Sunset Cogeneration Company 50.0 % 25 Petra Nova Parish Holdings LLC 50.0 % 136 Saguaro Power Company 50.0 % (20 ) San Juan Mesa Wind Project, LLC (a) 75.0 % 80 Sherbino I Wind Farm LLC 50.0 % 80 Watson Cogeneration Company 49.0 % 36 Gladstone Power Station (b) 37.5 % 149 Other Various 14 (a) Equity method investments owned by NRG Yield (b) Gladstone Power Station is located in Australia

Segment Reporting (Tables)

Segment Reporting (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segment reporting information	For the Year Ended December 31, 2015 NRG Home NRG Business Retail Solar NRG Renew NRG Yield Corporate Eliminations Total (in millions) Operating revenues (a) $ 9,142 $ 5,389 $ 32 $ 474 $ 869 $ (14 ) $ (1,218 ) $ 14,674 Operating expenses 7,811 4,577 204 218 324 61 (1,220 ) 11,975 Depreciation and amortization 907 123 25 212 265 34 — 1,566 Impairment charges 4,827 36 132 13 — — 22 5,030 Acquisition-related transaction and integration costs — 1 (8 ) — 3 14 — 10 Development activity expenses 24 — — 70 — 60 — 154 Total operating cost and expenses 13,569 4,737 353 513 592 169 (1,198 ) 18,735 Gain on sale of assets 21 — — — — — — 21 Operating (loss)/income (4,406 ) 652 (321 ) (39 ) 277 (183 ) (20 ) (4,040 ) Equity in earnings/(losses) of unconsolidated affiliates 7 — — 1 35 — (7 ) 36 Impairment losses on investments (14 ) — — — (42 ) — (56 ) Other income, net 40 — — 4 2 84 (97 ) 33 Loss on sale of equity-method investment — — — — — (14 ) — (14 ) (Loss)/gain on debt extinguishment — — — — (9 ) 84 — 75 Interest expense (98 ) — (3 ) (108 ) (238 ) (776 ) 95 (1,128 ) (Loss)/income before income taxes (4,471 ) 652 (324 ) (142 ) 67 (847 ) (29 ) (5,094 ) Income tax expense/(benefit) 1 — — (18 ) 12 1,347 — 1,342 Net (loss)/income $ (4,472 ) $ 652 $ (324 ) $ (124 ) $ 55 $ (2,194 ) $ (29 ) $ (6,436 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests $ — $ — $ (20 ) $ 6 $ 19 $ (17 ) $ (42 ) $ (54 ) Net (loss)/income attributable to NRG Energy, Inc. $ (4,472 ) $ 652 $ (304 ) $ (130 ) $ 36 $ (2,177 ) $ 13 $ (6,382 ) Balance sheet Equity investments in affiliates 185 — 134 798 276 (348 ) 1,045 Capital expenditures (b) 798 30 144 163 30 102 — 1,267 Goodwill 536 340 — 12 — 111 — 999 Total assets 17,139 1,876 413 5,954 7,775 19,576 (19,851 ) 32,882 (a) Operating revenues include inter-segment sales and net derivative gains and losses of: $ 947 $ 6 $ 1 $ 23 $ 29 $ 212 $ — $ 1,218 (b) Includes accruals. For the Year Ended December 31, 2014 NRG Home NRG Business Retail Solar NRG Renew (d) NRG Yield Corporate Eliminations (d) Total (in millions) Operating revenues (c) $ 11,024 $ 5,503 $ 42 $ 427 $ 746 $ 75 $ (1,949 ) $ 15,868 Operating expenses 8,894 5,240 108 183 274 72 (1,950 ) 12,821 Depreciation and amortization 966 122 6 195 202 32 — 1,523 Impairment charges 87 — — 32 — — (22 ) 97 Acquisition-related transaction and integration costs 1 3 — — 4 76 — 84 Development activity expenses 13 — — 42 — 36 — 91 Total operating cost and expenses 9,961 5,365 114 452 480 216 (1,972 ) 14,616 Gain on sale of assets 19 — — — — — — 19 Operating income/(loss) 1,082 138 (72 ) (25 ) 266 (141 ) 23 1,271 Equity in earnings/(losses) of unconsolidated affiliates 23 — — (4 ) 25 3 (9 ) 38 Other income, net 35 — — 5 3 78 (99 ) 22 Gain on sale of equity-method investment 18 — — — — — — 18 Loss on debt extinguishment — — — (1 ) — (94 ) — (95 ) Interest expense (95 ) (1 ) (1 ) (122 ) (191 ) (806 ) 97 (1,119 ) Income/(loss) before income taxes 1,063 137 (73 ) (147 ) 103 (960 ) 12 135 Income tax expense/(benefit) 1 — — — 4 (2 ) — 3 Net income/(loss) 1,062 137 (73 ) (147 ) 99 (958 ) 12 132 Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests (1 ) — (19 ) 2 16 24 (24 ) (2 ) Net income/(loss) attributable to NRG Energy, Inc. $ 1,063 $ 137 $ (54 ) $ (149 ) $ 83 $ (982 ) $ 36 $ 134 Balance sheet Equity investments in affiliates $ 141 $ — $ — $ 148 $ 410 $ 174 $ (102 ) $ 771 Capital expenditures (e) 611 34 113 160 13 53 — 984 Goodwill 1,746 387 98 12 — 331 — 2,574 Total assets $ 28,317 $ 6,049 $ 222 $ 6,481 $ 7,860 $ 30,727 $ (39,190 ) $ 40,466 (c) Operating revenues include inter-segment sales and net derivative gains and losses of: $ 1,820 $ 7 $ — $ 25 $ 12 $ 85 $ — $ 1,949 (d) Includes an impairment loss resulting from the intercompany sale of solar panels at current market rates. The use of these long-lived assets is anticipated to generate sufficient cash flows to recover the historical cost of the assets and accordingly, the impairment loss was eliminated and the assets remain at historical cost in consolidation. (e) Includes accruals. For the Year Ended December 31, 2013 NRG Home NRG Business Retail Solar NRG Renew NRG Yield Corporate Eliminations Total (in millions) Operating revenues (f) $ 8,638 $ 4,341 $ 4 $ 214 $ 387 $ 19 $ (2,308 ) $ 11,295 Operating expenses 7,235 3,814 — 77 155 41 (2,297 ) 9,025 Depreciation and amortization 930 141 4 86 74 21 — 1,256 Impairment charges 459 — — — — — — 459 Acquisition-related transaction and integration costs — — — — — 128 — 128 Development activity expenses 14 — 9 34 — 27 — 84 Total operating costs and expenses 8,638 3,955 13 197 229 217 (2,297 ) 10,952 Operating income/(loss) — 386 (9 ) 17 158 (198 ) (11 ) 343 Equity in earnings/of unconsolidated affiliates (6 ) — — (7 ) 22 — (2 ) 7 Impairment losses on investments — — — — — (99 ) — (99 ) Other income, net 32 — — 2 3 77 (101 ) 13 Loss on debt extinguishment — — — — — (50 ) — (50 ) Interest expense (107 ) (2 ) — (52 ) (52 ) (735 ) 100 (848 ) (Loss)/income before income taxes (81 ) 384 (9 ) (40 ) 131 (1,005 ) (14 ) (634 ) Income tax expense/(benefit) — — — — 8 (290 ) — (282 ) Net (loss)/income (81 ) 384 (9 ) (40 ) 123 (715 ) (14 ) (352 ) Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests — — — 22 13 14 (15 ) 34 Net (loss)/income attributable to NRG Energy, Inc. (81 ) 384 (9 ) (62 ) 110 (729 ) 1 (386 ) (f) Operating revenues include inter-segment sales and net derivative gains and losses of: $ 2,055 $ 5 $ — $ 14 $ 7 $ 227 $ — $ 2,308

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Reconciliation of NRG's basic and diluted earnings per share	The reconciliation of NRG's basic earnings/(loss) per share to diluted earnings/(loss) per share is shown in the following table: Year Ended December 31, 2015 2014 2013 (In millions, except per share amounts) Basic (loss)/earnings per share attributable to NRG common stockholders Net (loss)/income attributable to NRG Energy, Inc. $ (6,382 ) $ 134 $ (386 ) Dividends for preferred shares 20 9 9 Dividends for refinancing of preferred shares — 47 — (Loss)/Income Available to Common Stockholders $ (6,402 ) $ 78 $ (395 ) Weighted average number of common shares outstanding 329 334 323 (Loss)/Earnings per weighted average common share — basic $ (19.46 ) $ 0.23 $ (1.22 ) Diluted (loss)/earnings per share attributable to NRG common stockholders Weighted average number of common shares outstanding 329 334 323 Incremental shares attributable to the issuance of equity compensation (treasury stock method) — 5 — Total dilutive shares 329 339 323 (Loss)/Earnings per weighted average common share — diluted $ (19.46 ) $ 0.23 $ (1.22 )
Summary of NRG's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted earnings per share	The following table summarizes NRG's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted earnings/(loss) per share: Year Ended December 31, 2015 2014 2013 (In millions of shares) Equity compensation 6 1 9 Embedded derivative of 2.822% redeemable perpetual preferred stock (a) 16 16 16 Total 22 17 25 (a) At December 31, 2013, the redeemable perpetual preferred stock had an interest rate of 3.625%.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income tax provision from continuing operations	The income tax provision from continuing operations consisted of the following amounts: Year Ended December 31, 2015 2014 2013 (In millions, except percentages) Current State $ 6 $ 8 $ 11 Total — current 6 8 11 Deferred U.S. Federal 1,020 (50 ) (207 ) State 315 41 (57 ) Foreign 1 4 (29 ) Total — deferred 1,336 (5 ) (293 ) Total income tax expense/(benefit) $ 1,342 $ 3 $ (282 ) Effective tax rate (26.3 )% 2.2 % 44.5 %
Domestic and foreign components of income/(loss) before income tax (benefit)/expense	The following represents the domestic and foreign components of income/(loss) before income tax expense/(benefit): Year Ended December 31, 2015 2014 2013 (In millions) U.S. $ (5,105 ) $ 126 $ (549 ) Foreign 11 9 (85 ) Total $ (5,094 ) $ 135 $ (634 )
Reconciliation of the U.S. federal statutory rate to NRG's effective rate	A reconciliation of the U.S. federal statutory rate of 35% to NRG's effective rate is as follows: Year Ended December 31, 2015 2014 2013 (In millions, except percentages) (Loss)/Income Before Income Taxes $ (5,094 ) $ 135 $ (634 ) Tax at 35% (1,783 ) 47 (222 ) State taxes (218 ) 9 19 Foreign operations 1 1 5 Federal and state tax credits, excluding PTCs (5 ) (1 ) (36 ) Valuation allowance 3,039 6 (5 ) Expiration/utilization of capital losses — — 10 Reversal of valuation allowance on expired/utilized capital losses — — (10 ) Impact of non-taxable equity earnings (10 ) (11 ) (14 ) Book goodwill impairment 340 — — Net interest accrued on uncertain tax positions (3 ) (2 ) (3 ) Production tax credit (33 ) (48 ) (14 ) Recognition of uncertain tax benefits (15 ) (30 ) (11 ) Tax expense attributable to consolidated partnerships 12 4 8 Impact of change in effective state tax rate 19 22 (21 ) Other (2 ) 6 12 Income tax expense/(benefit) $ 1,342 $ 3 $ (282 ) Effective income tax rate (26.3 )% 2.2 % 44.5 %
Company's deferred tax assets and liabilities	The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following: As of December 31, 2015 2014 (In millions) Deferred tax liabilities: Emissions allowances $ 31 $ 25 Difference between book and tax basis of property — 127 Derivatives, net 22 320 Goodwill — 202 Cumulative translation adjustments 2 8 Investment in projects 838 849 Intangibles amortization (excluding goodwill) — 99 Other — 2 Total deferred tax liabilities 893 1,632 Deferred tax assets: Deferred compensation, pension, accrued vacation and other reserves 255 266 Discount/premium on notes 68 99 Difference between book and tax basis of property 1,210 — Goodwill 39 — Differences between book and tax basis of contracts 516 531 Pension and other postretirement benefits 218 157 Equity compensation 50 77 Bad debt reserve 6 9 U.S. capital loss carryforwards 1 — U.S. Federal net operating loss carryforwards 1,373 1,523 Foreign net operating loss carryforwards 59 65 State net operating loss carryforwards 230 302 Foreign capital loss carryforwards 1 1 Deferred financing costs 6 23 Federal and state tax credit carryforwards 439 357 Federal benefit on state uncertain tax positions 17 17 Intangibles amortization (excluding goodwill) 90 — Inventory obsolescence 27 29 Other 11 — Total deferred tax assets 4,616 3,456 Valuation allowance (3,575 ) (265 ) Total deferred tax assets, net of valuation allowance 1,041 3,191 Net deferred tax asset $ 148 $ 1,559
Summary of NRG's net deferred tax position	The following table summarizes NRG's net deferred tax position: As of December 31, 2015 2014 (In millions) Net deferred tax asset — noncurrent $ 167 $ 1,580 Net deferred tax liability — noncurrent (19 ) (21 ) Net deferred tax asset $ 148 $ 1,559
Reconciliation of total amounts of uncertain tax benefits	The following table reconciles the total amounts of uncertain tax benefits: As of December 31, 2015 2014 (In millions) Balance as of January 1 $ 71 $ 115 Increase due to current year positions 4 — Increase due to prior year positions — 10 Decrease due to prior year positions (25 ) (27 ) Decrease due to settlements and payments (18 ) (27 ) Uncertain tax benefits as of December 31 $ 32 $ 71

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Summary of Company's NQSO activity, and changes during the year	The following table summarizes the Company's NQSO activity and changes during the year: Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Term (In years) Aggregate Intrinsic Value (In millions) (In whole) Outstanding at December 31, 2014 2,533,177 $ 30.95 2 $ 9 Forfeited (59,617 ) 35.28 Exercised (401,647 ) 23.23 Outstanding at December 31, 2015 2,071,913 32.27 3 — Exercisable at December 31, 2015 2,071,913 32.27 3 —
Summary of weighted average grant date fair value of options granted, the total intrinsic value of options exercised, and the cash received from the exercises of options	The following table summarizes the total intrinsic value of options exercised and the cash received from the exercises of options: Year Ended December 31, 2015 2014 2013 (In millions, except for weighted average) Total intrinsic value of options exercised $ 2 $ 7 $ 19 Cash received from options exercised 9 21 33
Summary of Company's non-vested RSU awards and changes during the year	The following table summarizes the Company's non-vested RSU awards and changes during the year: Units Weighted Average Grant-Date Fair Value per Unit (In whole) Non-vested at December 31, 2014 2,674,626 $ 26.15 Granted 741,351 27.31 Forfeited (266,802 ) 27.98 Vested (887,179 ) 23.31 Non-vested at December 31, 2015 2,261,996 27.59
Summary of Company's non-vested MSU awards and changes during the year	The following table summarizes the Company's non-vested MSU awards and changes during the year: Units Weighted Average Grant-Date Fair Value per Unit (In whole) Non-vested at December 31, 2014 2,304,569 $ 26.13 Granted 1,108,410 26.68 Vested (1,230,410 ) 21.86 Forfeited (202,412 ) 29.44 Non-vested at December 31, 2015 1,980,157 29.54
Summary of significant assumptions used in the fair value model with respect to the Company's MSUs	Significant assumptions used in the fair value model with respect to the Company's MSUs are summarized below: 2015 2014 Expected volatility 24.08%-25.20% 23.62%-27.43% Expected term (in years) 1-3 3-4 Risk free rate 0.25%-1.07% 0.76%-1.21%
Summary of NRG's total compensation expense recognized and total non-vested compensation costs not yet recognized and the period over which this expense is expected to be recognized	The following table summarizes NRG's total compensation expense recognized for the years presented as well as total non-vested compensation costs not yet recognized and the period over which this expense is expected to be recognized as of December 31, 2015 , for each of the five types of awards issued under the LTIPs. Minimum tax withholdings of $21 million , $16 million , and $13 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively, are reflected as a reduction to Additional Paid-in Capital on the Company's Consolidated Balance Sheet and are reflected as operating activities on the Company's Consolidated Statement of Cash Flows. Non-vested Compensation Cost Compensation Expense Unrecognized Total Cost Weighted Average Recognition Period Remaining (In years) Year Ended December 31 As of December 31 Award 2015 2014 2013 2015 2015 (In millions, except weighted average data) NQSOs (a) $ — $ 1 $ 4 $ — — RSUs 23 20 18 26 1.79 DSUs 2 2 2 — — MSUs 16 19 14 12 1.44 PUs (a) — — 2 — — Total $ 41 $ 42 $ 40 $ 38 Tax detriment recognized $ (12 ) $ (8 ) $ (6 ) (a) All NQSOs and PUs granted under the Company's LTIP were fully vested as of December 31, 2015.
Deferred Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Summary of Company's outstanding DSU awards and changes during the year	The following table summarizes the Company's outstanding DSU awards and changes during the year: Units Weighted Average Grant-Date Fair Value per Unit (In whole) Outstanding at December 31, 2014 384,663 $ 21.21 Granted 70,929 25.14 Converted to Common Stock (28,014 ) 24.78 Outstanding at December 31, 2015 427,578 21.88

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Summary of NRG's material related-party transactions with affiliates	The following table summarizes NRG's material related party transactions with affiliates that are included in the Company's operating revenues, operating costs and other income and expense: Year Ended December 31, 2015 2014 2013 (In millions) Revenues from Related Parties Included in Operating Revenues Gladstone $ 4 $ 6 $ 6 GenConn 4 6 5 Total $ 8 $ 12 $ 11

Commitments and Contingencies59

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Other Commitments [Line Items]
Future minimum lease commitments under operating leases	Future minimum lease commitments under operating leases for the years ending after December 31, 2015 , are as follows: Period (In millions) 2016 $ 104 2017 79 2018 72 2019 61 2020 56 Thereafter 410 Total (a) $ 782 (a) Amounts in the table exclude future sublease income of $17 million associated with long-term leases for office locations in Texas.
Commitments under coal, gas and transportation contractual agreements	As of December 31, 2015 , the Company's commitments under such outstanding agreements are as follows: Period (In millions) 2016 $ 887 2017 295 2018 261 2019 169 2020 174 Thereafter 549 Total $ 2,335
Minimum purchase commitment obligations under purchased power agreements	Minimum purchase commitment obligations are as follows as of December 31, 2015 : Period (In millions) 2016 $ 50 2017 17 2018 2 2019 1 2020 — Thereafter — Total (a) $ 70 (a) As of December 31, 2015 , the maximum remaining term under any individual purchased power contract is five years.
EME [Member]
Other Commitments [Line Items]
Future minimum lease commitments under operating leases	Future minimum lease commitments under the Powerton and Joliet operating leases for the years ending after December 31, 2015 , are as follows: Period (In millions) 2016 $ 26 2017 1 2018 1 2019 1 2020 1 Thereafter 237 Total $ 267
REMA [Member]
Other Commitments [Line Items]
Future minimum lease commitments under operating leases	Future minimum lease commitments under the REMA operating leases for the years ending after December 31, 2015 , are as follows: Period (In millions) 2016 $ 61 2017 63 2018 55 2019 65 2020 56 Thereafter 278 Total $ 578
GenOn Mid-Atlantic
Other Commitments [Line Items]
Future minimum lease commitments under operating leases	Future minimum lease commitments under the GenOn Mid-Atlantic operating leases for the years ending after December 31, 2015 , are as follows: Period (In millions) 2016 $ 150 2017 144 2018 105 2019 139 2020 105 Thereafter 442 Total $ 1,085

Cash Flow Information (Tables)

Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Details of supplemental disclosures of cash flow and non-cash investing and financing information	Detail of supplemental disclosures of cash flow and non-cash investing and financing information was: Year Ended December 31, 2015 2014 2013 (In millions) Interest paid, net of amount capitalized $ 1,172 $ 1,067 $ 836 Income taxes (refunded)/paid (a) 16 (6 ) (60 ) Consent fee paid, preferred stock — 5 — Non-cash investing and financing activities: (Decrease)/additions to fixed assets for accrued capital expenditures (24 ) 87 405 Decrease to fixed assets for accrued grants and related tax impact — (711 ) (681 ) Issuance of shares for EME acquisition — (401 ) — (a) In 2015 , the net income taxes paid reflect $17 million in income taxes paid and $1 million in income tax refunds. In 2014 , the net income taxes refunded are net of $15 million income taxes paid and $21 million income tax refunds. In 2013 , the net income taxes refunded are net of $28 million income taxes paid and $87 million income tax refunds.

Guarantees Guarantees (Tables)

Guarantees Guarantees (Tables)	12 Months Ended
	Dec. 31, 2015
Guarantees [Abstract]
Summary of NRG's estimated guarantees, indemnity, and other contingent liability	The following table summarizes the maximum potential exposures that can be estimated for NRG's guarantees, indemnities, and other contingent liabilities by maturity: By Remaining Maturity at December 31, 2015 Guarantees Under 1 Year 1-3 Years 3-5 Years Over 5 Years Total 2014 Total (In millions) Letters of credit and surety bonds $ 1,805 $ 92 $ — $ 2 $ 1,899 $ 1,914 Asset sales guarantee obligations — — 257 — 257 292 Other guarantees — 1 — 721 722 1,174 Total guarantees $ 1,805 $ 93 $ 257 $ 723 $ 2,878 $ 3,380

Jointly Owned Plants (Tables)

Jointly Owned Plants (Tables)	12 Months Ended
	Dec. 31, 2015
Jointly Owned Plants Disclosure [Abstract]
Summary of NRG's proportionate ownership interest in the company's jointly-owned facilities	The following table summarizes NRG's proportionate ownership interest in the Company's jointly-owned facilities: As of December 31, 2015 Ownership Interest Property, Plant & Equipment Accumulated Depreciation Construction in Progress (In millions unless otherwise stated) South Texas Project Units 1 and 2, Bay City, TX 44.00 % $ 3,246 $ (1,599 ) $ 38 Big Cajun II Unit 3, New Roads, LA 58.00 % 206 (114 ) — Cedar Bayou Unit 4, Baytown, TX 50.00 % 211 (57 ) — Keystone, Shelocta, PA 3.70 % 97 (44 ) — Conemaugh, New Florence, PA 3.72 % 101 (46 ) 1

Unaudited Quarterly Financial63

Unaudited Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Summary of Unaudited Quarterly Financial Data	Summarized unaudited quarterly financial data is as follows: Quarter Ended 2015 December 31 September 30 June 30 March 31 (In millions, except per share data) Operating revenues $ 3,011 $ 4,434 $ 3,400 $ 3,829 Operating (loss)/income (4,727 ) 379 232 76 Net (loss)/income (6,358 ) 67 (9 ) (136 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests (44 ) 1 5 (16 ) Net (loss)/income attributable to NRG Energy, Inc. (6,314 ) 66 (14 ) (120 ) (Loss)/income available to Common Stockholders $ (6,319 ) $ 61 $ (19 ) $ (125 ) Weighted average number of common shares outstanding — basic 315 331 333 336 Net (loss)/income per weighted average common share — basic $ (20.08 ) $ 0.18 $ (0.06 ) $ (0.37 ) Weighted average number of common shares outstanding — diluted 315 332 333 336 Net (loss)/income per weighted average common share — diluted $ (20.08 ) $ 0.18 $ (0.06 ) $ (0.37 ) Quarter Ended 2014 December 31 September 30 June 30 March 31 (In millions, except per share data) Operating revenues $ 4,192 $ 4,569 $ 3,621 $ 3,486 Operating income 453 549 89 180 Net income/(loss) 97 182 (80 ) (67 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests (22 ) 14 17 (11 ) Net income/(loss) attributable to NRG Energy, Inc. 119 168 (97 ) (56 ) Income/(loss) available to Common Stockholders $ 70 $ 166 $ (100 ) $ (58 ) Weighted average number of common shares outstanding — basic 338 338 337 324 Net income/(loss) per weighted average common share — basic $ 0.21 $ 0.49 $ (0.30 ) $ (0.18 ) Weighted average number of common shares outstanding — diluted 342 343 337 324 Net income/(loss) per weighted average common share — diluted $ 0.20 $ 0.48 $ (0.30 ) $ (0.18 )

Condensed Consolidating Finan64

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule of Guarantor Subsidiaries	Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of December 31, 2015 : Ace Energy, Inc. NEO Freehold-Gen LLC NRG Operating Services, Inc. Allied Warranty LLC NEO Power Services Inc. NRG Oswego Harbor Power Operations Inc. Arthur Kill Power LLC New Genco GP, LLC NRG PacGen Inc. Astoria Gas Turbine Power LLC Norwalk Power LLC NRG Portable Power LLC Bayou Cove Peaking Power LLC NRG Affiliate Services Inc. NRG Power Marketing LLC BidURenergy, Inc. NRG Artesian Energy LLC NRG Reliability Solutions LLC Cabrillo Power I LLC NRG Arthur Kill Operations Inc. NRG Renter's Protection LLC Cabrillo Power II LLC NRG Astoria Gas Turbine Operations Inc. NRG Retail LLC Carbon Management Solutions LLC NRG Bayou Cove LLC NRG Retail Northeast LLC Cirro Group, Inc. NRG Business Solutions LLC NRG Rockford Acquisition LLC Cirro Energy Services, Inc. NRG Cabrillo Power Operations Inc. NRG Saguaro Operations Inc. Clean Edge Energy LLC NRG California Peaker Operations LLC NRG Security LLC Conemaugh Power LLC NRG Cedar Bayou Development Company, LLC NRG Services Corporation Connecticut Jet Power LLC NRG Connected Home LLC NRG SimplySmart Solutions LLC Cottonwood Development LLC NRG Connecticut Affiliate Services Inc. NRG South Central Affiliate Services Inc. Cottonwood Energy Company LP NRG Construction LLC NRG South Central Generating LLC Cottonwood Generating Partners I LLC NRG Curtailment Solutions LLC NRG South Central Operations Inc. Cottonwood Generating Partners II LLC NRG Development Company Inc. NRG South Texas LP Cottonwood Generating Partners III LLC NRG Devon Operations Inc. NRG Texas C&I Supply LLC Cottonwood Technology Partners LP NRG Dispatch Services LLC NRG Texas Gregory LLC Devon Power LLC NRG Distributed Generation PR LLC NRG Texas Holding Inc. Dunkirk Power LLC NRG Dunkirk Operations Inc. NRG Texas LLC Eastern Sierra Energy Company LLC NRG El Segundo Operations Inc. NRG Texas Power LLC El Segundo Power, LLC NRG Energy Efficiency-L LLC NRG Warranty Services LLC El Segundo Power II LLC NRG Energy Efficiency-P LLC NRG West Coast LLC Energy Alternatives Wholesale, LLC NRG Energy Labor Services LLC NRG Western Affiliate Services Inc. Energy Choice Solutions, LLC NRG ECOKAP Holdings, LLC O'Brien Cogeneration, Inc. II NRG Curtailment Solutions, Inc. NRG Energy Services Group LLC ONSITE Energy, Inc. Energy Plus Holdings LLC NRG Energy Services International Inc. Oswego Harbor Power LLC Energy Plus Natural Gas LLC NRG Energy Services LLC RE Retail Receivables, LLC Energy Protection Insurance Company NRG Generation Holdings, Inc. Reliant Energy Northeast LLC Everything Energy LLC NRG Home & Business Solutions LLC Reliant Energy Power Supply, LLC Forward Home Security, LLC NRG Home Solutions LLC Reliant Energy Retail Holdings, LLC GCP Funding Company, LLC NRG Home Solutions Product LLC Reliant Energy Retail Services, LLC Green Mountain Energy Company NRG Homer City Services LLC RERH Holdings LLC Gregory Partners, LLC NRG Huntley Operations Inc. Saguaro Power LLC Gregory Power Partners LLC NRG HQ DG LLC Somerset Operations Inc. Huntley Power LLC NRG Identity Protect LLC Somerset Power LLC Independence Energy Alliance LLC NRG Ilion Limited Partnership Texas Genco Financing Corp. Independence Energy Group LLC NRG Ilion LP LLC Texas Genco GP, LLC Independence Energy Natural Gas LLC NRG International LLC Texas Genco Holdings, Inc. Indian River Operations Inc. NRG Maintenance Services LLC Texas Genco LP, LLC Indian River Power LLC NRG Mextrans Inc. Texas Genco Operating Services, LLC Keystone Power LLC NRG MidAtlantic Affiliate Services Inc. Texas Genco Services, LP Langford Wind Power LLC NRG Middletown Operations Inc. US Retailers LLC NRG Home Services LLC NRG Montville Operations Inc. Vienna Operations Inc. Louisiana Generating LLC NRG New Roads Holdings LLC Vienna Power LLC Meriden Gas Turbines LLC NRG North Central Operations Inc. WCP (Generation) Holdings LLC Middletown Power LLC NRG Northeast Affiliate Services Inc. West Coast Power LLC Montville Power LLC NRG Norwalk Harbor Operations Inc. NEO Corporation NRG GreenCo, LLC NRG Business Services LLC NRG GreenCo Holdings, LLC
Condensed Consolidating Statement of Operations	NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS For the Year Ended December 31, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Operating Revenues Total operating revenues $ 10,024 $ 4,768 $ — $ (118 ) $ 14,674 Operating Costs and Expenses Cost of operations 7,712 3,147 14 (118 ) 10,755 Depreciation and amortization 787 759 20 — 1,566 Impairment losses 4,655 375 — — 5,030 Selling, general and administrative 467 403 350 — 1,220 Acquisition-related transaction and integration costs 1 (5 ) 14 — 10 Development activity expenses — 61 93 — 154 Total operating costs and expenses 13,622 4,740 491 (118 ) 18,735 Gain on postretirement benefits curtailment — 21 — — 21 Operating (Loss)/Income (3,598 ) 49 (491 ) — (4,040 ) Other Income/(Expense) Equity in losses of consolidated subsidiaries (86 ) (29 ) (2,799 ) 2,914 — Equity in earnings of unconsolidated affiliates 8 37 — (9 ) 36 Impairment charge on investment — (25 ) (31 ) — (56 ) Other income, net 4 29 — — 33 Loss on sale of equity-method investment — — (14 ) — (14 ) Net gain on debt extinguishment — 56 19 — 75 Interest expense (18 ) (564 ) (546 ) — (1,128 ) Total other expense (92 ) (496 ) (3,371 ) 2,905 (1,054 ) Loss Before Income Taxes (3,690 ) (447 ) (3,862 ) 2,905 (5,094 ) Income tax (benefit)/expense (1,104 ) (96 ) 2,489 53 1,342 Net Loss (2,586 ) (351 ) (6,351 ) 2,852 (6,436 ) Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — (23 ) 31 (62 ) (54 ) Net Loss Attributable to NRG Energy, Inc. $ (2,586 ) $ (328 ) $ (6,382 ) $ 2,914 $ (6,382 ) (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS For the Year Ended December 31, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Operating Revenues Total operating revenues $ 9,974 $ 6,287 $ — $ (393 ) $ 15,868 Operating Costs and Expenses Cost of operations 7,909 4,206 4 (325 ) 11,794 Depreciation and amortization 801 706 16 — 1,523 Impairment losses — 119 — (22 ) 97 Selling, general and administrative 333 390 304 — 1,027 Acquisition-related transactions and integration costs 3 15 66 — 84 Development activity expense — 35 56 — 91 Total operating costs and expenses 9,046 5,471 446 (347 ) 14,616 Gain on sale of assets — 19 — — 19 Operating Income/(Loss) 928 835 (446 ) (46 ) 1,271 Other Income/(Expense) Equity in earnings of consolidated subsidiaries 317 219 775 (1,311 ) — Equity in earnings of unconsolidated affiliates 13 33 — (8 ) 38 Impairment losses on investments — — — — — Other income, net 7 14 3 (2 ) 22 Gain on sale of equity-method investment — 18 — — 18 Loss on debt extinguishment — (9 ) (86 ) — (95 ) Interest expense (19 ) (525 ) (575 ) — (1,119 ) Total other income/(expense) 318 (250 ) 117 (1,321 ) (1,136 ) Income/(Loss) Before Income Taxes 1,246 585 (329 ) (1,367 ) 135 Income tax expense/(benefit) 322 159 (478 ) — 3 Net Income $ 924 $ 426 $ 149 $ (1,367 ) $ 132 Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests — 57 15 (74 ) (2 ) Net Income Attributable to NRG Energy, Inc. $ 924 $ 369 $ 134 $ (1,293 ) $ 134 (a) All significant intercompany transactions have been eliminated in consolidation. Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) Operating Revenues Total operating revenues $ 8,223 $ 3,211 $ — $ (139 ) $ 11,295 Operating Costs and Expenses Cost of operations 6,150 2,113 — (133 ) 8,130 Depreciation and amortization 837 407 12 — 1,256 Impairment losses 459 — — — 459 Selling, general and administrative 446 221 234 (6 ) 895 Acquisition-related transaction and integration costs — 70 58 — 128 Development activity expenses — 34 50 — 84 Total operating costs and expenses 7,892 2,845 354 (139 ) 10,952 Operating Income/(Loss) 331 366 (354 ) — 343 Other (Expense)/Income Equity in (losses)/earnings of consolidated subsidiaries (67 ) (14 ) 221 (140 ) — Equity in (losses)/earnings of unconsolidated affiliates (11 ) 22 — (4 ) 7 Impairment losses on investment — (99 ) — — (99 ) Other income/(loss), net 6 11 (2 ) (2 ) 13 Loss on debt extinguishment — (12 ) (38 ) — (50 ) Interest expense (24 ) (318 ) (506 ) — (848 ) Total other expense (96 ) (410 ) (325 ) (146 ) (977 ) Income/(Loss) Before Income Taxes 235 (44 ) (679 ) (146 ) (634 ) Income tax expense/(benefit) 114 (89 ) (307 ) — (282 ) Net Income/(Loss) 121 45 (372 ) (146 ) (352 ) Less: Net income attributable to noncontrolling interest — 27 13 (6 ) 34 Net Income/(Loss) Attributable to NRG Energy, Inc $ 121 $ 18 $ (385 ) $ (140 ) $ (386 ) (a) All significant intercompany transactions have been eliminated in consolidation.
Condensed Consolidating Statements of Comprehensive Income	NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) For the Year Ended December 31, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Net Loss $ (2,586 ) $ (351 ) $ (6,351 ) $ 2,852 $ (6,436 ) Other Comprehensive (Loss)/Income, net of tax Unrealized (loss)/gain on derivatives, net (9 ) (13 ) 48 (41 ) (15 ) Foreign currency translation adjustments, net — (7 ) (4 ) — (11 ) Available-for-sale securities, net — (1 ) 18 — 17 Defined benefit plan, net (22 ) (15 ) 47 — 10 Other comprehensive (loss)/income (31 ) (36 ) 109 (41 ) 1 Comprehensive Loss (2,617 ) (387 ) (6,242 ) 2,811 (6,435 ) Less: Comprehensive (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests — (42 ) 31 (62 ) (73 ) Comprehensive Loss Attributable to NRG Energy, Inc. (2,617 ) (345 ) (6,273 ) 2,873 (6,362 ) Dividends for preferred shares — — 20 — 20 Comprehensive Loss Available for Common Stockholders $ (2,617 ) $ (345 ) $ (6,293 ) $ 2,873 $ (6,382 ) (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS) For the Year Ended December 31, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Net Income $ 924 $ 426 $ 149 $ (1,367 ) $ 132 Other Comprehensive (Loss)/Income, net of tax Unrealized loss on derivatives, net (49 ) (89 ) (215 ) 308 (45 ) Foreign currency translation adjustments, net — (12 ) 4 — (8 ) Available-for-sale securities, net — 1 (8 ) — (7 ) Defined benefit plan, net 5 (104 ) (30 ) — (129 ) Other comprehensive loss (44 ) (204 ) (249 ) 308 (189 ) Comprehensive Income/(Loss) 880 222 (100 ) (1,059 ) (57 ) Less: Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests — 67 15 (74 ) 8 Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. 880 155 (115 ) (985 ) (65 ) Dividends for preferred shares — — 56 — 56 Comprehensive Income/(Loss) Available for Common Stockholders $ 880 $ 155 $ (171 ) $ (985 ) $ (121 ) (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME For the Year Ended December 31, 2013 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Net Income/(Loss) $ 121 $ 45 $ (372 ) $ (146 ) $ (352 ) Other Comprehensive Income/(Loss), net of tax Unrealized (loss)/income on derivatives, net (71 ) 50 120 (91 ) 8 Foreign currency translation adjustments, net — (20 ) (4 ) — (24 ) Available-for-sale securities, net — — 3 — 3 Defined benefit plan, net 75 63 30 — 168 Other comprehensive income 4 93 149 (91 ) 155 Comprehensive Income/(Loss) 125 138 (223 ) (237 ) (197 ) Less: Comprehensive income attributable to noncontrolling interest — 27 13 (6 ) 34 Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. 125 111 (236 ) (231 ) (231 ) Dividends for preferred shares — — 9 — 9 Comprehensive Income/(Loss) Available for Common Stockholders $ 125 $ 111 $ (245 ) $ (231 ) $ (240 ) (a) All significant intercompany transactions have been eliminated in consolidation.
Condensed Consolidating Balance Sheets	NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2015 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) ASSETS Current Assets Cash and cash equivalents $ — $ 825 $ 693 $ — $ 1,518 Funds deposited by counterparties 55 51 — — 106 Restricted cash 5 409 — — 414 Accounts receivable - trade, net 851 304 2 — 1,157 Accounts receivable - Affiliate 395 260 571 (1,222 ) 4 Inventory 570 682 — — 1,252 Derivative instruments 1,202 871 — (158 ) 1,915 Cash collateral paid in support of energy risk management activities 474 94 — — 568 Renewable energy grant receivable — 13 — — 13 Current assets held-for-sale — 6 — — 6 Prepayments and other current assets 93 274 71 — 438 Total current assets 3,645 3,789 1,337 (1,380 ) 7,391 Net Property, Plant and Equipment 4,767 13,773 219 (27 ) 18,732 Other Assets Investment in subsidiaries 842 2,244 11,039 (14,125 ) — Equity investments in affiliates (14 ) 1,160 1 (102 ) 1,045 Notes receivable, less current portion — 46 7 — 53 Goodwill 697 302 — — 999 Intangible assets, net 763 1,551 2 (6 ) 2,310 Nuclear decommissioning trust fund 561 — — — 561 Deferred income taxes (6 ) 815 (642 ) — 167 Derivative instruments 153 184 — (32 ) 305 Non-current assets held for sale — 105 — — 105 Other non-current assets 80 749 385 — 1,214 Total other assets 3,076 7,156 10,792 (14,265 ) 6,759 Total Assets $ 11,488 $ 24,718 $ 12,348 $ (15,672 ) $ 32,882 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Current portion of long-term debt and capital leases $ 2 $ 460 $ 19 $ — $ 481 Accounts payable 553 277 39 — 869 Accounts payable - affiliate 151 2,000 (929 ) (1,222 ) — Derivative instruments 1,130 749 — (158 ) 1,721 Cash collateral received in support of energy risk management activities 55 51 — — 106 Accrued interest expense 5 91 147 (1 ) 242 Other accrued expenses 122 151 295 — 568 Current liabilities held-for-sale — 2 — — 2 Other current liabilities 192 187 7 — 386 Total current liabilities 2,210 3,968 (422 ) (1,381 ) 4,375 Other Liabilities Long-term debt and capital leases 302 10,496 8,185 — 18,983 Nuclear decommissioning reserve 326 — — — 326 Nuclear decommissioning trust liability 283 — — — 283 Postretirement and other benefit obligations 236 200 152 — 588 Deferred income taxes 179 (1,088 ) 928 — 19 Derivative instruments 301 224 — (32 ) 493 Out-of-market contracts 95 1,051 — — 1,146 Non-current liabilities held-for-sale — 4 — — 4 Other non-current liabilities 318 535 47 — 900 Total non-current liabilities 2,040 11,422 9,312 (32 ) 22,742 Total Liabilities 4,250 15,390 8,890 (1,413 ) 27,117 2.822% Preferred Stock — — 302 — 302 Redeemable noncontrolling interest in subsidiaries — 29 — — 29 Stockholders' Equity 7,238 9,299 3,156 (14,259 ) 5,434 Total Liabilities and Stockholders' Equity $ 11,488 $ 24,718 $ 12,348 $ (15,672 ) $ 32,882 (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) ASSETS Current Assets Cash and cash equivalents $ 18 $ 1,455 $ 643 $ — $ 2,116 Funds deposited by counterparties 9 63 — — 72 Restricted cash 5 451 1 — 457 Accounts receivable - trade, net 924 392 6 — 1,322 Inventory 537 710 — — 1,247 Derivative instruments 1,657 1,209 — (441 ) 2,425 Cash collateral paid in support of energy risk management activities 114 73 — — 187 Accounts receivable - affiliate 7,449 1,988 (5,991 ) (3,437 ) 9 Renewable energy grant receivable — 134 1 — 135 Prepayments and other current assets 94 269 75 — 438 Total current assets 10,807 6,744 (5,265 ) (3,878 ) 8,408 Net Property, Plant and Equipment 8,344 13,877 171 (25 ) 22,367 Other Assets Investment in subsidiaries 140 2,293 23,410 (25,843 ) — Equity investments in affiliates (18 ) 891 — (102 ) 771 Notes receivable, less current portion 1 60 109 (98 ) 72 Goodwill 1,921 653 — — 2,574 Intangible assets, net 765 1,806 2 (6 ) 2,567 Nuclear decommissioning trust fund 585 — — — 585 Derivative instruments 242 288 1 (51 ) 480 Deferred income taxes (247 ) 722 1,105 — 1,580 Non-current assets held for sale — 17 — — 17 Other non-current assets 108 520 417 — 1,045 Total other assets 3,497 7,250 25,044 (26,100 ) 9,691 Total Assets $ 22,648 $ 27,871 $ 19,950 $ (30,003 ) $ 40,466 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Current portion of long-term debt and capital leases $ 1 $ 444 $ 127 $ (98 ) $ 474 Accounts payable 598 416 46 — 1,060 Accounts payable - affiliate 1,588 2,447 (598 ) (3,437 ) — Derivative instruments 1,532 963 — (441 ) 2,054 Cash collateral received in support of energy risk management activities 9 63 — — 72 Accrued expenses and other current liabilities 283 498 418 — 1,199 Total current liabilities 4,011 4,831 (7 ) (3,976 ) 4,859 Other Liabilities Long-term debt and capital leases 302 11,123 8,276 — 19,701 Nuclear decommissioning reserve 310 — — — 310 Nuclear decommissioning trust liability 333 — — — 333 Postretirement and other benefit obligations 277 234 216 — 727 Deferred income taxes 1,043 (1,012 ) (10 ) — 21 Derivative instruments 248 241 — (51 ) 438 Out-of-market commodity contracts 111 1,133 — — 1,244 Other non-current liabilities 188 561 98 — 847 Total non-current liabilities 2,812 12,280 8,580 (51 ) 23,621 Total Liabilities 6,823 17,111 8,573 (4,027 ) 28,480 2.822% Preferred Stock — — 291 — 291 Redeemable noncontrolling interest in subsidiaries — 19 — — 19 Stockholders' Equity 15,825 10,741 11,086 (25,976 ) 11,676 Total Liabilities and Stockholders' Equity $ 22,648 $ 27,871 $ 19,950 $ (30,003 ) $ 40,466 (a) All significant intercompany transactions have been eliminated in consolidation.
Condensed Consolidating Statements of Cash Flows	Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. (Note Issuer) Eliminations (a) Consolidated Balance (In millions) Cash Flows from Operating Activities Net Loss (2,586 ) (351 ) (6,351 ) 2,852 (6,436 ) Adjustments to reconcile net loss to net cash provided by operating activities: Distributions from unconsolidated affiliates 3 91 — (21 ) 73 Equity in losses of unconsolidated affiliates (8 ) (37 ) — 9 (36 ) Depreciation and amortization 787 759 20 — 1,566 Provision for bad debts 58 3 3 — 64 Amortization of nuclear fuel 45 — — — 45 Amortization of financing costs and debt discount/premiums — (37 ) 26 — (11 ) Adjustment to gain on debt extinguishment — (56 ) (19 ) — (75 ) Amortization of intangibles and out-of-market contracts 52 29 — — 81 Amortization of unearned equity compensation — — 41 — 41 Gain on post retirement benefits curtailment and sales of assets — (21 ) 14 — (7 ) Impairment losses 4,655 400 31 — 5,086 Changes in derivative instruments 264 (31 ) — — 233 Changes in collateral deposits supporting energy risk management activities (360 ) (21 ) — — (381 ) Changes in deferred income taxes and liability for uncertain tax benefits (1,092 ) (237 ) 2,655 — 1,326 Changes in nuclear decommissioning trust liability (2 ) — — — (2 ) Cash used by changes in other working capital (8,744 ) (950 ) 12,276 (2,840 ) (258 ) Net Cash (Used)/Provided by Operating Activities (6,928 ) (459 ) 8,696 — 1,309 Cash Flows from Investing Activities Proceeds from intercompany loans to subsidiaries 7,183 1,258 — (8,441 ) — Acquisition of 2015 Drop Down Assets, net of cash acquired — (698 ) — 698 — Acquisition of businesses, net of cash acquired — (31 ) — — (31 ) Capital expenditures (316 ) (908 ) (59 ) — (1,283 ) (Increase)/decrease in restricted cash, net (1 ) 9 — — 8 Decrease in restricted cash - U.S. DOE projects — 34 1 — 35 Decrease in notes receivable — 18 — — 18 Proceeds from renewable energy grants — 82 — — 82 Purchases of emission allowances, net of proceeds 41 — — — 41 Investments in nuclear decommissioning trust securities (629 ) — — — (629 ) Proceeds from sales of nuclear decommissioning trust fund securities 631 — — — 631 Proceeds from sale of assets, net — 1 26 — 27 Investments in unconsolidated affiliates 1 (357 ) (39 ) — (395 ) Other — 11 — — 11 Net Cash Provided/(Used) by Investing Activities 6,910 (581 ) (71 ) (7,743 ) (1,485 ) Cash Flows from Financing Activities Payments from intercompany loans — — (8,441 ) 8,441 — Acquisition of 2015 Drop Down Assets, net of cash acquired — — 698 (698 ) — Payment of dividends to preferred and common stockholders — — (201 ) — (201 ) Net receipts from settlement of acquired derivatives that include financing elements — 196 — — 196 Payment for treasury stock — — (437 ) — (437 ) Sale proceeds and other contributions from noncontrolling interests in subsidiaries — 647 — — 647 Proceeds from issuance of common stock — — 1 — 1 Proceeds from issuance of long-term debt — 953 51 — 1,004 Payment of debt issuance and hedging costs — (21 ) — — (21 ) Payments for short and long-term debt — (1,353 ) (246 ) — (1,599 ) Other — (22 ) — — (22 ) Net Cash (Used)/Provided by Financing Activities — 400 (8,575 ) 7,743 (432 ) Effect of exchange rate changes on cash and cash equivalents — 10 — — 10 Net (Decrease)/Increase in Cash and Cash Equivalents (18 ) (630 ) 50 — (598 ) Cash and Cash Equivalents at Beginning of Period 18 1,455 643 — 2,116 Cash and Cash Equivalents at End of Period $ — $ 825 $ 693 $ — $ 1,518 (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2014 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) Cash Flows from Operating Activities Net Income 924 426 149 (1,367 ) 132 Adjustments to reconcile net loss to net cash provided by operating activities: Distributions from unconsolidated affiliates — 87 — — 87 Equity in losses of unconsolidated affiliates (13 ) (33 ) — 8 (38 ) Depreciation and amortization 801 706 16 — 1,523 Provision for bad debts 64 — — — 64 Amortization of nuclear fuel 46 — — — 46 Amortization of financing costs and debt discount/premiums — (40 ) 28 — (12 ) Adjustment to loss on debt extinguishment — 8 17 — 25 Amortization of intangibles and out-of-market contracts 65 (1 ) — — 64 Amortization of unearned equity compensation — — 42 — 42 Gain on sale of assets, net — (4 ) — — (4 ) Impairment losses — 119 — (22 ) 97 Changes in derivative instruments (149 ) 88 — — (61 ) Changes in deferred income taxes and liability for uncertain tax benefits 242 (115 ) (281 ) — (154 ) Changes in nuclear decommissioning trust liability 19 — — — 19 Cash used by changes in other working capital 787 (973 ) (4,723 ) 4,589 (320 ) Net Cash Provided/(Used) by Operating Activities 2,786 268 (4,752 ) 3,208 1,510 Cash Flows from Investing Activities Intercompany loans to subsidiaries (2,523 ) (685 ) 3,208 — — Acquisition of businesses, net of cash acquired — (25 ) (2,911 ) — (2,936 ) Capital expenditures (252 ) (619 ) (38 ) — (909 ) Decrease in restricted cash, net — 57 — — 57 (Increase) in restricted cash - U.S. DOE projects — (209 ) 3 — (206 ) Decrease in notes receivable — 25 — — 25 Proceeds from renewable energy grants — 916 — — 916 Purchases of emission allowances, net of proceeds (16 ) — — — (16 ) Investments in nuclear decommissioning trust fund securities (619 ) — — — (619 ) Proceeds from sales of nuclear decommissioning trust fund securities 600 — — — 600 Proceeds from sale of assets, net — — 203 — 203 Investments in unconsolidated affiliates — (25 ) (78 ) — (103 ) Other — 85 — — 85 Net Cash (Used)/Provided by Investing Activities (2,810 ) (480 ) 387 — (2,903 ) Cash Flows from Financing Activities Proceeds from intercompany loans — — 3,208 (3,208 ) — Payment of dividends to preferred stockholders — — (196 ) — (196 ) Net receipts from acquired derivatives that include financing elements — 9 — — 9 Payment for treasury stock — — (39 ) — (39 ) Sales proceeds from sale of noncontrolling interest in subsidiaries — 819 — — 819 Proceeds from issuance of common stock — — 21 — 21 Proceeds from issuance of long-term debt — 1,182 3,381 — 4,563 Payment of debt issuance and hedging costs — (39 ) (28 ) — (67 ) Payments of short and long-term debt — (1,160 ) (2,667 ) — (3,827 ) Other (14 ) (4 ) — — (18 ) Net Cash (Used)/Provided by Financing Activities (14 ) 807 3,680 (3,208 ) 1,265 Effect of exchange rate changes on cash and cash equivalents — (10 ) — — (10 ) Net (Decrease)/Increase in Cash and Cash Equivalents (38 ) 585 (685 ) — (138 ) Cash and Cash Equivalents at Beginning of Period 56 870 1,328 — 2,254 Cash and Cash Equivalents at End of Period $ 18 $ 1,455 $ 643 $ — $ 2,116 (a) All significant intercompany transactions have been eliminated in consolidation. NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2013 Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc. Eliminations (a) Consolidated Balance (In millions) Cash Flows from Operating Activities Net Income/(Loss) 121 45 (372 ) (146 ) (352 ) Adjustments to reconcile net loss to net cash provided by operating activities: Distributions from unconsolidated affiliates 51 26 — — 77 Equity in losses of unconsolidated affiliates 11 (22 ) — 4 (7 ) Depreciation and amortization 837 407 12 — 1,256 Provision for bad debts 67 — — — 67 Amortization of nuclear fuel 36 — — — 36 Amortization of financing costs and debt discount/premiums — (9 ) (24 ) — (33 ) Adjustment for debt extinguishment — (27 ) 12 — (15 ) Amortization of intangibles and out-of-market contracts 100 (51 ) — — 49 Amortization of unearned equity compensation — — 38 — 38 Gain on sale of assets, net — (3 ) — — (3 ) Impairment losses 459 99 — — 558 Changes in derivative instruments 197 (33 ) — — 164 Changes in deferred income taxes and liability for uncertain tax benefits (58 ) 292 (301 ) — (67 ) Changes in nuclear decommissioning trust liability 15 — — — 15 Cash used by changes in other working capital 482 (941 ) (1,911 ) 1,857 (513 ) Net Cash Provided/(Used) by Operating Activities 2,318 (217 ) (2,546 ) 1,715 1,270 Cash Flows from Investing Activities Intercompany loans to subsidiaries (1,722 ) 7 1,715 — — Acquisition of business, net of cash acquired — (179 ) (315 ) — (494 ) Capital expenditures (528 ) (1,413 ) (46 ) — (1,987 ) (Increase)/decrease in restricted cash (1 ) (22 ) 1 — (22 ) (Increase)/decrease in restricted cash - U.S. DOE projects — (31 ) 5 — (26 ) Decrease/(increase) in notes receivable 2 (7 ) (6 ) — (11 ) Proceeds from renewable energy grants — 55 — — 55 Purchases of emission allowances, net of proceeds 5 — — — 5 Investments in nuclear decommissioning trust fund securities (514 ) — — — (514 ) Proceeds from sales of nuclear decommissioning trust fund securities 488 — — — 488 Proceeds from sale of assets, net 13 — — — 13 Other (4 ) (11 ) (20 ) — (35 ) Net Cash Used by Investing Activities (2,261 ) (1,601 ) 1,334 — (2,528 ) Cash Flows from Financing Activities Proceeds from intercompany loans — — 1,715 (1,715 ) — Payment for dividends to preferred stockholders — — (154 ) — (154 ) Net (payments for)/receipts from acquired derivatives that include financing elements (79 ) 346 — — 267 Payment for treasury stock — — (25 ) — (25 ) Sales proceeds from sale of noncontrolling interest in subsidiary — 531 — — 531 Proceeds from issuance of common stock — — 16 — 16 Proceeds from issuance of long-term debt — 1,292 485 — 1,777 Payment of debt issuance and hedging costs — (21 ) (29 ) — (50 ) Payments of short and long-term debt — (716 ) (219 ) — (935 ) Net Cash (Used)/Provided by Financing Activities (79 ) 1,432 1,789 (1,715 ) 1,427 Effect of exchange rate changes on cash and cash equivalents — (2 ) — — (2 ) Net Increase/(Decrease) in Cash and Cash Equivalents (22 ) (388 ) 577 — 167 Cash and Cash Equivalents at Beginning of Period 78 1,258 751 — 2,087 Cash and Cash Equivalents at End of Period $ 56 $ 870 $ 1,328 $ — $ 2,254 (a) All significant intercompany transactions have been eliminated in consolidation.

VALUATION AND QUALIFYING ACCOUN

VALUATION AND QUALIFYING ACCOUNTS (Tables)	12 Months Ended
	Dec. 31, 2015
Valuation and Qualifying Accounts Disclosure
Schedule of Valuation and Qualifying Accounts Disclosure	SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2015 , 2014 , and 2013 Balance at Beginning of Period Charged to Costs and Expenses Charged to Other Accounts Deductions Balance at End of Period (In millions) Allowance for doubtful accounts, deducted from accounts receivable Year Ended December 31, 2015 $ 23 $ 62 $ — $ (64 ) (a) 21 Year Ended December 31, 2014 40 64 — (81 ) (a) 23 Year Ended December 31, 2013 32 66 — (58 ) (a) 40 Income tax valuation allowance, deducted from deferred tax assets Year Ended December 31, 2015 $ 265 $ 3,039 $ 271 $ — 3,575 Year Ended December 31, 2014 291 — (10 ) (16 ) 265 Year Ended December 31, 2013 191 32 68 — 291 (a) Represents principally net amounts charged as uncollectible.

Nature of Business (Details)

Nature of Business (Details)	12 Months Ended
	Dec. 31, 2015facilitycustomerMW
Power Generation Facilities
Generation capacity (in MW)	49,287	[1]
Shawville [Member]
Power Generation Facilities
Generation capacity (in MW)	597
Active
Power Generation Facilities
Generation capacity (in MW)	51,978	[1]
Power Generation Capacity, Megawatts attributed to noncontrolling interest	(2,691)	[1]
Wind Farms | Active
Power Generation Facilities
Number generation facilities | facility	36
Utility-Scale Solar | Active
Power Generation Facilities
Number generation facilities | facility	16
Natural Gas | Active
Power Generation Facilities
Generation capacity (in MW)	24,635	[1],[2]
Natural Gas | Active | Coolwater [Member]
Power Generation Facilities
Generation capacity (in MW)	636	[1]
Natural Gas | Active | Gulf Coast [Member]
Power Generation Facilities
Generation capacity (in MW)	463	[1]
Natural Gas | Active | SD Jets Kearny 1 [Member]
Power Generation Facilities
Generation capacity (in MW)	16	[1]
Natural Gas | Active | Glen Gardner [Member]
Power Generation Facilities
Generation capacity (in MW)	160	[1]
Natural Gas | Active | Gilbert [Member]
Power Generation Facilities
Generation capacity (in MW)	98	[1]
Natural Gas | Active | El Segundo [Member]
Power Generation Facilities
Generation capacity (in MW)	335	[1]
Natural Gas | Active | SD Jets Kearny 2A-2D [Member]
Power Generation Facilities
Generation capacity (in MW)	60	[1]
Coal | Active
Power Generation Facilities
Generation capacity (in MW)	15,841	[1],[3]
Coal | Active | Will County [Member]
Power Generation Facilities
Generation capacity (in MW)	251	[1]
Coal | Active | Shawville [Member]
Power Generation Facilities
Generation capacity (in MW)	597	[1]
Coal | Active | Big Cajun Unit 2 [Member]
Power Generation Facilities
Generation capacity (in MW)	575	[1]
Coal | Active | Dunkirk [Member]
Power Generation Facilities
Generation capacity (in MW)	75	[1]
Coal | Active | Portland [Member]
Power Generation Facilities
Generation capacity (in MW)	401	[1]
Oil | Active
Power Generation Facilities
Generation capacity (in MW)	5,771	[1],[4]
Oil | Active | Werner [Member]
Power Generation Facilities
Generation capacity (in MW)	212	[1]
Nuclear fuel | Active
Power Generation Facilities
Generation capacity (in MW)	1,176	[1]
Fossil Fuel | Active
Power Generation Facilities
Number generation facilities | facility	90
Renewables [Member] | Wind Farms | Active
Power Generation Facilities
Generation capacity (in MW)	3,066	[1]
Renewables [Member] | Utility-Scale Solar | Active
Power Generation Facilities
Generation capacity (in MW)	1,327	[1]
Renewables [Member] | Distributed Solar | Active
Power Generation Facilities
Generation capacity (in MW)	162	[1]
Recurring Customer [Member]
Power Generation Facilities
Number of residential, small business, commercial and industrial customers (in millions) | customer	2,770,000
Discrete Customer [Member]
Power Generation Facilities
Number of residential, small business, commercial and industrial customers (in millions) | customer	624,000
NRG Renew (c)
Power Generation Facilities
Generation capacity (in MW)	1,328	[1],[5]
NRG Renew (c) | Active
Power Generation Facilities
Generation capacity (in MW)	1,966	[1],[5]
Power Generation Capacity, Megawatts attributed to noncontrolling interest	(638)	[1],[5]
NRG Renew (c) | Natural Gas | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[2],[5]
NRG Renew (c) | Coal | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[3],[5]
NRG Renew (c) | Oil | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[4],[5]
NRG Renew (c) | Nuclear fuel | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[5]
NRG Renew (c) | Renewables [Member] | Wind Farms | Active
Power Generation Facilities
Generation capacity (in MW)	1,061	[1],[5]
NRG Renew (c) | Renewables [Member] | Utility-Scale Solar | Active
Power Generation Facilities
Generation capacity (in MW)	845	[1],[5]
NRG Renew (c) | Renewables [Member] | Distributed Solar | Active
Power Generation Facilities
Generation capacity (in MW)	60	[1],[5]
NRG Yield [Member]
Power Generation Facilities
Generation capacity (in MW)	2,512	[1],[6]
NRG Yield [Member] | Active
Power Generation Facilities
Generation capacity (in MW)	4,565	[1],[6]
Power Generation Capacity, Megawatts attributed to noncontrolling interest	(2,053)	[1],[6]
NRG Yield [Member] | Natural Gas | Active
Power Generation Facilities
Generation capacity (in MW)	1,879	[1],[2],[6]
NRG Yield [Member] | Coal | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[3],[6]
NRG Yield [Member] | Oil | Active
Power Generation Facilities
Generation capacity (in MW)	190	[1],[4],[6]
NRG Yield [Member] | Nuclear fuel | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[6]
NRG Yield [Member] | Renewables [Member] | Wind Farms | Active
Power Generation Facilities
Generation capacity (in MW)	2,005	[1],[6]
NRG Yield [Member] | Renewables [Member] | Utility-Scale Solar | Active
Power Generation Facilities
Generation capacity (in MW)	482	[1],[6]
NRG Yield [Member] | Renewables [Member] | Distributed Solar | Active
Power Generation Facilities
Generation capacity (in MW)	9	[1],[6]
Gulf Coast [Member]
Power Generation Facilities
Generation capacity (in MW)	14,941	[1]
Gulf Coast [Member] | Active
Power Generation Facilities
Generation capacity (in MW)	14,941	[1]
Power Generation Capacity, Megawatts attributed to noncontrolling interest	0	[1]
Gulf Coast [Member] | Natural Gas | Active
Power Generation Facilities
Generation capacity (in MW)	8,651	[1],[2]
Gulf Coast [Member] | Coal | Active
Power Generation Facilities
Generation capacity (in MW)	5,114	[1],[3]
Gulf Coast [Member] | Oil | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[4]
Gulf Coast [Member] | Nuclear fuel | Active
Power Generation Facilities
Generation capacity (in MW)	1,176	[1]
Gulf Coast [Member] | Renewables [Member] | Wind Farms | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
Gulf Coast [Member] | Renewables [Member] | Utility-Scale Solar | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
Gulf Coast [Member] | Renewables [Member] | Distributed Solar | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
International [Member]
Power Generation Facilities
Generation capacity (in MW)	749	[1]
International [Member] | Active
Power Generation Facilities
Generation capacity (in MW)	749	[1]
Power Generation Capacity, Megawatts attributed to noncontrolling interest	0	[1]
International [Member] | Natural Gas | Active
Power Generation Facilities
Generation capacity (in MW)	144	[1],[2]
International [Member] | Coal | Active
Power Generation Facilities
Generation capacity (in MW)	605	[1],[3]
International [Member] | Oil | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[4]
International [Member] | Nuclear fuel | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
International [Member] | Renewables [Member] | Wind Farms | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
International [Member] | Renewables [Member] | Utility-Scale Solar | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
International [Member] | Renewables [Member] | Distributed Solar | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
UNITED STATES
Power Generation Facilities
Generation capacity (in MW)	48,538	[1]
UNITED STATES | Active
Power Generation Facilities
Generation capacity (in MW)	51,229	[1]
Power Generation Capacity, Megawatts attributed to noncontrolling interest	(2,691)	[1]
UNITED STATES | Natural Gas | Active
Power Generation Facilities
Generation capacity (in MW)	24,491	[1],[2]
UNITED STATES | Coal | Active
Power Generation Facilities
Generation capacity (in MW)	15,236	[1],[3]
UNITED STATES | Oil | Active
Power Generation Facilities
Generation capacity (in MW)	5,771	[1],[4]
UNITED STATES | Nuclear fuel | Active
Power Generation Facilities
Generation capacity (in MW)	1,176	[1]
UNITED STATES | Renewables [Member] | Wind Farms | Active
Power Generation Facilities
Generation capacity (in MW)	3,066	[1]
UNITED STATES | Renewables [Member] | Utility-Scale Solar | Active
Power Generation Facilities
Generation capacity (in MW)	1,327	[1]
UNITED STATES | Renewables [Member] | Distributed Solar | Active
Power Generation Facilities
Generation capacity (in MW)	162	[1]
Home Solar [Member]
Power Generation Facilities
Generation capacity (in MW)	93	[1],[7]
Home Solar [Member] | Active
Power Generation Facilities
Generation capacity (in MW)	93	[1],[7]
Power Generation Capacity, Megawatts attributed to noncontrolling interest	0	[1],[7]
Home Solar [Member] | Natural Gas | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[2],[7]
Home Solar [Member] | Coal | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[3],[7]
Home Solar [Member] | Oil | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[4],[7]
Home Solar [Member] | Nuclear fuel | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[7]
Home Solar [Member] | Renewables [Member] | Wind Farms | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[7]
Home Solar [Member] | Renewables [Member] | Utility-Scale Solar | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[7]
Home Solar [Member] | Renewables [Member] | Distributed Solar | Active
Power Generation Facilities
Generation capacity (in MW)	93	[1],[7]
West
Power Generation Facilities
Generation capacity (in MW)	6,085	[1]
West | Active
Power Generation Facilities
Generation capacity (in MW)	6,085	[1]
Power Generation Capacity, Megawatts attributed to noncontrolling interest	0	[1]
West | Natural Gas | Active
Power Generation Facilities
Generation capacity (in MW)	6,085	[1],[2]
West | Coal | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[3]
West | Oil | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1],[4]
West | Nuclear fuel | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
West | Renewables [Member] | Wind Farms | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
West | Renewables [Member] | Utility-Scale Solar | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
West | Renewables [Member] | Distributed Solar | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
East
Power Generation Facilities
Generation capacity (in MW)	23,579	[1]
East | Active
Power Generation Facilities
Generation capacity (in MW)	23,579	[1]
Power Generation Capacity, Megawatts attributed to noncontrolling interest	0	[1]
East | Natural Gas | Active
Power Generation Facilities
Generation capacity (in MW)	7,876	[1],[2]
East | Coal | Active
Power Generation Facilities
Generation capacity (in MW)	10,122	[1],[3]
East | Oil | Active
Power Generation Facilities
Generation capacity (in MW)	5,581	[1],[4]
East | Nuclear fuel | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
East | Renewables [Member] | Wind Farms | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
East | Renewables [Member] | Utility-Scale Solar | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
East | Renewables [Member] | Distributed Solar | Active
Power Generation Facilities
Generation capacity (in MW)	0	[1]
Approximation [Member]
Power Generation Facilities
Generation capacity (in MW)	50,000
[1]	Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.
[2]	Natural gas generation portfolio does not include: 463 MW related to Osceola, which was mothballed on January 1, 2015; 636 MW related to Coolwater, which was retired on January 1, 2015; 16 MW related to SD Jets Kearny 1, which was deactivated in March 2015; 160 MW related to Glen Gardner, which was retired on May 1, 2015; 98 MW related to Gilbert, which was retired on May 1, 2015; 335 MW related to El Segundo 4, which was deactivated on December 31, 2015; and 60 MW related to SD Jets Kearny 2A-2D, which were deactivated on December 31, 2015.
[3]	Coal generation portfolio does not include: 251 MW related to Will County, which was retired on April 15, 2015; 597 MW related to Shawville, which was mothballed on May 31, 2015; 575 MW related to Big Cajun Unit 2, which was converted to natural gas in July 2015; 401 MW related to Portland, which was deactivated on December 1, 2015; and 75 MW related to Dunkirk 2, which was mothballed on December 31, 2015.
[4]	Oil generation portfolio does not include 212 MW related to Werner, which was retired on May 1, 2015.
[5]	Includes Distributed Solar capacity from assets held by DGPV Holdco, a partnership between NRG Renew DG Holdings LLC and NRG Yield, Inc.
[6]	Does not include NRG Yield, Inc.'s thermal converted (MWt) capacity, which is part of the NRG Yield operating segment.
[7]	Includes the aggregate production capacity of installed and activated residential solar energy systems. Also includes capacity from operating portfolios of residential solar assets held by RPV Holdco, a partnership between NRG Home Solar and NRG Yield, Inc.

Nature of Business (Details 2 -

Nature of Business (Details 2 - Yield IPO) $ in Millions	Jul. 30, 2014USD ($)shares	Dec. 31, 2015shares	Dec. 31, 2014shares
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Common stock, shares outstanding		314,190,042	336,662,624
Class A Common Stock | NRG Yield, Inc.
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Shares, Issued	12,075,000
Proceeds from Issuance or Sale of Equity | $	$ 630
Public Shareholders [Member] | NRG Yield, Inc.
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Common Stock, Voting Interest		0.449
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		53.30%
NRG | NRG Yield, Inc.
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Common Stock, Voting Interest		0.551
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		46.70%

Summary of Significant Accoun68

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary of Significant Accounting Policies Disclosure
Redeemable Noncontrolling Interest, Equity, Other, Carrying Amount	$ 29	$ 19	$ 2
Redeemable Noncontrolling Interest, Cash Contributions from Noncontrolling Interest Holders	27	36
Inventory Write-down	$ 19
Funds Deposited by Counterparties
Number of months beyond which company can not predict the holding of collateral (in months)	12 months
Project Development Costs and Capitalized Interest
Amount of interest capitalized	$ 30	29	64
Income Taxes
Unrecognized tax benefits, more-likely-than-not threshold percentage	50.00%
Revenue Recognition
Energy revenues from resales of purchased power	$ 165	387	166
Unbilled revenues	309	341	356
Leases [Abstract]
Operating Leases, Income Statement, Contingent Revenue	777	544	260
Gross Receipts and Sales Taxes
Gross Receipts Tax	110	108	88
Cost of Energy for Retail Operations
Transmission and distribution charges not yet billed	85	86	90
Foreign Currency Translation and Transaction Gains and Losses
Cumulative translation adjustment	(10)	1	15
Tax Equity Arrangements [Abstract]
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest	(17)	(19)
Marketing and Advertising Expense
Marketing and advertising expense	307	208	195
Advertising Expense	$ 135	$ 87	$ 69
South Texas Project
Property, Plant and Equipment
Ownership Interest (as a percent)	44.00%
Current Debt Service Payment [Member]
Summary of Significant Accounting Policies Disclosure
Restricted Cash and Cash Equivalents	$ 45
Operating Expense [Member]
Summary of Significant Accounting Policies Disclosure
Restricted Cash and Cash Equivalents	61
Distributions [Member]
Summary of Significant Accounting Policies Disclosure
Restricted Cash and Cash Equivalents	21
Reserves [Member]
Summary of Significant Accounting Policies Disclosure
Restricted Cash and Cash Equivalents	$ 287

Business Acquisitions and Dis69

Business Acquisitions and Dispositions Business Acquisitions and Dispositions (Desert Sunlight) (Details) $ in Millions		3 Months Ended
		Jun. 30, 2015USD ($)MW	Dec. 31, 2015MW
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		49,287
Desert Sunlight [Member]
Business Acquisition [Line Items]
Percentage of Ownership		25.00%
Power Generation Capacity, Megawatts		550
Payments to Acquire Businesses, Gross | $		$ 285
[1]	Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.

Business Acquisitions and Dis70

Business Acquisitions and Dispositions Business Acquisitions and Dispositions - Alta Wind (Details 2) $ in Millions		Aug. 13, 2014USD ($)	Jul. 30, 2014USD ($)shares	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)	Aug. 12, 2014USD ($)MW	Aug. 05, 2014USD ($)
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW	[1]			49,287
Long-term Debt				$ 19,620	$ 20,366
Alta Wind Portfolio [Member]
Business Acquisition [Line Items]
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts | MW						947
Payments to Acquire Businesses, Gross		$ 923
Business Acquisitions, Consideration Transferred, Purchase Price						$ 870
Business Acquisition, Consideration Transferred, Working Capital						$ 53
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents				22	22
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Assets					49
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Other Assets				(2)
Business Acquisition, Purchase Price Allocation, Other Assets, Adjusted				47
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment					1,304
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment				6
Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment, Adjusted				1,310
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles					1,177
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Intangibles				(6)
Business Acquisition, Purchase Price Allocation, Intangible Assets, Other than Goodwill, Adjusted				1,171
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets					2,552
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Assets				(2)
Business Acquisition, Purchase Price Allocation, Assets Acquired, Adjusted				2,550
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt					1,591
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Noncurrent Liabilities Longterm Debt				0
Business Acquisition, Purchase Price Allocation, Noncurrent Liabilities, Long-term Debt, Adjusted				1,591
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current and Non-Current Liabilities					38
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Current and Noncurrent Liabilities				(2)
Business Acquisition, Purchase Price Allocation, Current and Non-current Liabilities, Adjusted				36
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities					1,629
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Financial Liabilities				(2)
Business Acquisition, Purchase Price Allocation, Liabilities Assumed, Adjusted				1,627
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net					$ 923
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Net Assets Acquired				0
Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net Adjusted				$ 923
Alta Wind I - V Lease financing arrangement [Member]
Business Acquisition [Line Items]
Remaining Lease Term		21 years
Alta Wind X and Alta Wind XI, due 2020 [Member]
Business Acquisition [Line Items]
Remaining Lease Term		22 years
NRG Yield, Inc. | Common Class A [Member]
Business Acquisition [Line Items]
Shares, Issued | shares			12,075,000
Proceeds from Issuance or Sale of Equity			$ 630
NRG Yield Operating LLC [Member]
Business Acquisition [Line Items]
Long-term Debt							$ 500
Debt Instrument, Interest Rate, Stated Percentage							5.375%
[1]	Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.

Business Acquisitions and Dis71

Business Acquisitions and Dispositions Business Acquisitions and Dispositions - Dominion (Details 4) $ in Millions	Mar. 31, 2014USD ($)customer	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Goodwill		$ 999	$ 2,574
Business Acquisition, Goodwill, Expected Tax Deductible Amount		$ 620	$ 831
Dominion [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 192
Business Acquisitions, Consideration Transferred, Purchase Price	165
Business Acquisition, Consideration Transferred, Working Capital	27
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables	40
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other	14
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Derivative Assets	21
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	47
Goodwill	91
Business Acquisition, Goodwill, Expected Tax Deductible Amount	$ 8
Scenario, Plan [Member] | Dominion [Member]
Business Acquisition [Line Items]
Business Acquisition, Customers Acquired | customer	540,000
Customer Relationships | Dominion [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles	$ 64
Trade Names | Dominion [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill	$ 9

Business Acquisitions and Dis72

Business Acquisitions and Dispositions Business Acquisitions and Dispositions - EME 1 (Details 5) $ in Millions		Apr. 02, 2014USD ($)MWshares	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Nov. 24, 2015	Jun. 30, 2014	Apr. 30, 2014MW	Apr. 01, 2014USD ($)
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW	[1]			49,287
Payments to Acquire Businesses, Net of Cash Acquired				$ 31	$ 2,936	$ 494
Equity Method Investment, Ownership Percentage				50.00%
Edison Mission Energy [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW		8,000
Business Combination, Consideration Transferred		$ 3,500
Business Combination, Estimated Consideration Transferred, Estimated Liabilities Incurred		700
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt		$ 1,200								$ 1,249
Sunrise Facility [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW									586
Mission Del Sol [Member]
Business Acquisition [Line Items]
Percentage of Ownership								100.00%
Through 2034 [Member]
Business Acquisition [Line Items]
Repayments of Long-term Capital Lease Obligations			$ 405
Common Stock | Edison Mission Energy [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares		12,671,977
EME [Member]
Business Acquisition [Line Items]
Environmental Capital Expenditures, Estimated Total			$ 350
Cogeneration facilities [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage							50.00%
Mission Del Sol [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage							50.00%
[1]	Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.

Business Acquisitions and Dis73

Business Acquisitions and Dispositions Business Acquisitions and Dispositions - EME 2 (Details 6) - USD ($) $ in Millions	Apr. 02, 2014	Dec. 31, 2014	Dec. 31, 2015	Apr. 01, 2014
Business Acquisition [Line Items]
Goodwill		$ 2,574	$ 999
Edison Mission Energy [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 3,500
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents				$ 1,422
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Assets				724
Business Combination, Provisional Information, Initial Accounting Incomplete, Current Assets		72
Business Acquisition, Purchase Price Allocation, Other Assets, Adjusted				796
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment				2,438
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment		(3)
Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment, Adjusted				2,435
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles				172
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Intangibles		0
Business Acquisition, Purchase Price Allocation, Intangible Assets, Other than Goodwill, Adjusted				172
Goodwill				334
Goodwill, Purchase Accounting Adjustments		(56)
Goodwill, Adjusted				278
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets				773
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Noncurrent Assets		0
Business Acquisition, Purchase Price Allocation, Noncurrent Assets, Adjusted				773
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets				5,863
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Financial Assets		13
Business Acquisition, Purchase Price Allocation, Assets Acquired, Adjusted				5,876
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current and Non-Current Liabilities				629
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Current and Noncurrent Liabilities		13
Business Acquisition, Purchase Price Allocation, Current and Non-current Liabilities, Adjusted				642
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Out-of-market Contracts and Leases				159
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Out of Market Contracts and Leases		0
Business Acquisition, Purchase Price Allocation, Out of Market Contracts and Leases, Adjusted				159
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	$ 1,200			1,249
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Noncurrent Liabilities Longterm Debt		0
Business Acquisition, Purchase Price Allocation, Noncurrent Liabilities, Long-term Debt, Adjusted				1,249
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities				2,037
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Financial Liabilities		13
Business Acquisition, Purchase Price Allocation, Liabilities Assumed, Adjusted				2,050
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value				352
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Noncontrolling Interest		0
Business Acquisition, Purchase Price Allocation, Noncontrolling Interest, Adjusted				352
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest				3,474
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Net Assets Acquired		$ 0
Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net Adjusted				$ 3,474

Business Acquisitions and Dis74

Business Acquisitions and Dispositions Business Acquisitions and Dispositions - 2013 Acquisitions (Details 8) $ in Millions		Dec. 31, 2013USD ($)	Aug. 07, 2013USD ($)MW	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Business Acquisition [Line Items]
Goodwill				$ 999	$ 2,574
Payments to Acquire Businesses, Net of Cash Acquired				$ 31	2,936	$ 494
Power Generation Capacity, Megawatts | MW	[1]			49,287
Total current assets				$ 7,391	$ 8,408
Energy Systems Company [Member]
Business Acquisition [Line Items]
Percentage of Ownership					100.00%
Payments to Acquire Businesses, Gross		$ 120
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment					$ 60
Goodwill					1
Gregory Power Partners, L.P. [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment			$ 248
Payments to Acquire Businesses, Net of Cash Acquired			245
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents			$ 32
Power Generation Capacity, Megawatts | MW			388
Steam and Chilled Water Capacity, Megawatts Thermal Equivalent | MW			160
Total current assets			$ 13
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities			$ 16
Customer Relationships | Energy Systems Company [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles					$ 59
[1]	Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.

Business Acquisitions and Dis75

Business Acquisitions and Dispositions Business Acquisitions and Dispositions - 2016 and 2015 Dispositions (Details) $ in Millions		Nov. 25, 2015USD ($)	Nov. 10, 2015USD ($)	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Nov. 24, 2015MW	Nov. 09, 2015MW
Equity Method Investment, Ownership Percentage				50.00%
Power Generation Capacity, Megawatts | MW	[1]			49,287
Impairment losses				$ 5,030	$ 97	$ 459
Disposal Group, Including Discontinued Operation, Other Assets, Current				6	0
Disposal Group, Including Discontinued Operation, Assets, Noncurrent				105	17
Disposal Group, Including Discontinued Operation, Liabilities, Current				2	0
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent				$ 4	$ 0
Altenex [Member]
Equity Method Investment, Ownership Percentage				32.00%
Seward Generating Station [Member]
Equity Method Investment, Ownership Percentage							100.00%
Power Generation Capacity, Megawatts | MW							525
Shelby County Energy Center, LLC [Member]
Equity Method Investment, Ownership Percentage								100.00%
Power Generation Capacity, Megawatts | MW								352
Altenex [Member]
Proceeds from Sale of Equity Method Investments				$ 26
Equity Method Investment, Realized Gain (Loss) on Disposal				14
Seward Generating Station [Member]
Proceeds from Sale of Equity Method Investments		$ 75
Impairment losses				134
Disposal Group, Including Discontinued Operation, Other Assets, Current				5
Disposal Group, Including Discontinued Operation, Assets, Noncurrent				83
Disposal Group, Including Discontinued Operation, Liabilities, Current				1
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent				4
Shelby County Energy Center, LLC [Member]
Proceeds from Sale of Equity Method Investments			$ 46
Disposal Group, Including Discontinued Operation, Other Assets, Current				1
Disposal Group, Including Discontinued Operation, Assets, Noncurrent				22
Disposal Group, Including Discontinued Operation, Liabilities, Current				$ 1
[1]	Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.

Business Acquisitions and Dis76

Business Acquisitions and Dispositions Business Acquisitions and Dispositions (2014 Dispositions - Sabine & Petra Nova) (Details) $ in Millions		Dec. 03, 2014USD ($)	Jul. 07, 2014USD ($)	Sep. 30, 2014USD ($)MW	Dec. 31, 2015USD ($)MW	Feb. 01, 2016USD ($)	Dec. 31, 2014USD ($)	Dec. 02, 2014MW	Jul. 03, 2014
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW	[1]				49,287
Long-term Debt					$ 19,620		$ 20,366
Petra Nova Parish Holdings [Member]
Business Acquisition [Line Items]
Percentage of Ownership Sold of Subsidiary									50.00%
Capital Contribution to Equity Method Investment			$ 35
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates			$ 76
Capital Contributions From Partners in Equity Method Investment				$ 300
Percentage of Ownership				50.00%
Sabine CoGen, LP [Member]
Business Acquisition [Line Items]
Percentage of Ownership Sold of Subsidiary								50.00%
Power Generation Capacity, Megawatts | MW								105
Proceeds from Sale of Equity Method Investments		$ 35
Equity Method Investment, Realized Gain (Loss) on Disposal					$ 18
Petra Nova Parish Holdings [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW				75
Department of Energy [Member]
Business Acquisition [Line Items]
Amount guaranteed to borrow by US DOE				$ 167
JBIC and Mizuho [Member]
Business Acquisition [Line Items]
Long-term Debt				250
NEXI Covered Loan [Member]
Business Acquisition [Line Items]
Long-term Debt				$ 75
Debt Instrument, Basis Spread on Variable Rate				1.75%
JBIC [Member]
Business Acquisition [Line Items]
Long-term Debt				$ 175
Debt Instrument, Basis Spread on Variable Rate				0.50%
Debt Instrument, Incremental Escalation On Basis Spread, Percentage				1.50%
Design and Engineering Phase [Member] | Department of Energy [Member]
Business Acquisition [Line Items]
Long-term Debt				$ 7
Construction Phase [Member] | Department of Energy [Member]
Business Acquisition [Line Items]
Long-term Debt				$ 106
Subsequent Event [Member] | Department of Energy [Member]
Business Acquisition [Line Items]
Additional US DOE funding						$ 23
[1]	Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.

Business Acquisitions and Dis77

Business Acquisitions and Dispositions - NRG Yield Acquisitions (Details 1)		Dec. 31, 2015USD ($)MW	Nov. 02, 2015USD ($)MW	Jan. 02, 2015USD ($)	Dec. 31, 2014USD ($)	Jun. 30, 2014USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Generation capacity (in MW) | MW	[1]	49,287
Long-term Debt		$ 19,620,000,000			$ 20,366,000,000
ROFO Assets [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Percentage of Ownership Sold of Subsidiary			75.00%
Number of Facilities			12
Generation capacity (in MW) | MW			814
Consideration Paid for Sale of Assets Under Common Control			$ 209,000,000	$ 489,000,000		$ 357,000,000
Consideration Paid for Sale of Assets Under Common Control, net of Working Capital Adjustments			207,000,000
Long-term Debt			193,000,000	737,000,000		612,000,000
Working Capital Adjustment [Member] | ROFO Assets [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Consideration Paid for Sale of Assets Under Common Control			$ 2,000,000	$ 9,000,000		8,000,000
Base Purchase Price [Member] | ROFO Assets [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Consideration Paid for Sale of Assets Under Common Control						$ 349,000,000
Financial Institutions [Member] | ROFO Assets [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value		$ 159,000,000
[1]	Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.

Fair Value of Financial Instr78

Fair Value of Financial Instruments (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Liabilities
Long-term debt, including current portion (b)		$ 19,620	$ 20,366
Level 2
Liabilities
Long-term debt, including current portion (b)	[1]	18,263	20,361
Level 3
Assets
Notes receivable (a)	[2]	73	91
Carrying Amount
Assets
Notes receivable (a)	[2]	73	91
Liabilities
Long-term debt, including current portion (b)	[1]	$ 19,620	$ 20,366
[1]	Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets.
[2]	Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets.

Fair Value of Financial Instr79

Fair Value of Financial Instruments (Recurring FV Measurements - Details 2) - USD ($) $ in Millions		Dec. 31, 2015		Dec. 31, 2014
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets		$ 2,220		$ 2,905
Derivative liabilities		2,214		2,492
Long-term Debt		19,620		20,366
Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets		2,220		2,902
Derivative liabilities		2,086		2,327
Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets				2
Derivative liabilities		128		165
Equity Contract [Member]
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets				1
Level 2
Investment in available-for-sale securities (classified within other non-current assets):
Long-term Debt	[1]	18,263		20,361
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes receivable (a)	[2]	73		91
Fair Value, Measurements, Recurring
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		17		18
Available-for-sale Securities		9		30
Other		14	[3]	32	[4]
Financial Instruments, Owned, US Government and Agency Obligations, at Fair Value		1		1
Total assets		2,822		3,571
Total liabilities		2,214		2,492
Fair Value, Measurements, Recurring | Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets		2,220		2,902
Derivative liabilities		2,086		2,327
Fair Value, Measurements, Recurring | Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets				2
Derivative liabilities		128		165
Fair Value, Measurements, Recurring | Equity Contract [Member]
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets				1
Fair Value, Measurements, Recurring | Cash and cash equivalents
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		6		14
Fair Value, Measurements, Recurring | U.S. government and federal agency obligations
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		55		47
Fair Value, Measurements, Recurring | Federal agency mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		59		74
Fair Value, Measurements, Recurring | Commercial mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		25		25
Fair Value, Measurements, Recurring | Corporate debt securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		81		78
Fair Value, Measurements, Recurring | Equity securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		334		344
Fair Value, Measurements, Recurring | Foreign government fixed income securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		1		3
Fair Value, Measurements, Recurring | Level 1
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		0		0
Available-for-sale Securities		9		30
Other		14	[3]	21	[4]
Financial Instruments, Owned, US Government and Agency Obligations, at Fair Value		1		1
Total assets		986		1,480
Total liabilities		868		1,004
Fair Value, Measurements, Recurring | Level 1 | Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets		622		1,078
Derivative liabilities		868		1,004
Fair Value, Measurements, Recurring | Level 1 | Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets				0
Derivative liabilities		0		0
Fair Value, Measurements, Recurring | Level 1 | Equity Contract [Member]
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets				0
Fair Value, Measurements, Recurring | Level 1 | Cash and cash equivalents
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		6		14
Fair Value, Measurements, Recurring | Level 1 | U.S. government and federal agency obligations
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		54		44
Fair Value, Measurements, Recurring | Level 1 | Federal agency mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		0		0
Fair Value, Measurements, Recurring | Level 1 | Commercial mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		0		0
Fair Value, Measurements, Recurring | Level 1 | Corporate debt securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		0		0
Fair Value, Measurements, Recurring | Level 1 | Equity securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		280		292
Fair Value, Measurements, Recurring | Level 1 | Foreign government fixed income securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		0		0
Fair Value, Measurements, Recurring | Level 2
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		0		0
Available-for-sale Securities		0		0
Other		0	[3]	0	[4]
Financial Instruments, Owned, US Government and Agency Obligations, at Fair Value		0		0
Total assets		1,616		1,700
Total liabilities		1,164		1,258
Fair Value, Measurements, Recurring | Level 2 | Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets		1,449		1,515
Derivative liabilities		1,036		1,093
Fair Value, Measurements, Recurring | Level 2 | Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets				2
Derivative liabilities		128		165
Fair Value, Measurements, Recurring | Level 2 | Equity Contract [Member]
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets				0
Fair Value, Measurements, Recurring | Level 2 | Cash and cash equivalents
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		0		0
Fair Value, Measurements, Recurring | Level 2 | U.S. government and federal agency obligations
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		1		3
Fair Value, Measurements, Recurring | Level 2 | Federal agency mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		59		74
Fair Value, Measurements, Recurring | Level 2 | Commercial mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		25		25
Fair Value, Measurements, Recurring | Level 2 | Corporate debt securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		81		78
Fair Value, Measurements, Recurring | Level 2 | Equity securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		0		0
Fair Value, Measurements, Recurring | Level 2 | Foreign government fixed income securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		1		3
Fair Value, Measurements, Recurring | Level 3
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities		17		18
Available-for-sale Securities		0		0
Other		0	[3]	11	[4]
Financial Instruments, Owned, US Government and Agency Obligations, at Fair Value		0		0
Total assets		220		391
Total liabilities		182		230
Fair Value, Measurements, Recurring | Level 3 | Commodity contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets		149		309
Derivative liabilities		182		230
Fair Value, Measurements, Recurring | Level 3 | Interest rate contracts
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets				0
Derivative liabilities		0		0
Fair Value, Measurements, Recurring | Level 3 | Equity Contract [Member]
Investment in available-for-sale securities (classified within other non-current assets):
Derivative assets				1
Fair Value, Measurements, Recurring | Level 3 | Cash and cash equivalents
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		0		0
Fair Value, Measurements, Recurring | Level 3 | U.S. government and federal agency obligations
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		0		0
Fair Value, Measurements, Recurring | Level 3 | Federal agency mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		0		0
Fair Value, Measurements, Recurring | Level 3 | Commercial mortgage-backed securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		0		0
Fair Value, Measurements, Recurring | Level 3 | Corporate debt securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		0		0
Fair Value, Measurements, Recurring | Level 3 | Equity securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		54		52
Fair Value, Measurements, Recurring | Level 3 | Foreign government fixed income securities
Investment in available-for-sale securities (classified within other non-current assets):
Trust fund investments		$ 0		$ 0
[1]	Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets.
[2]	Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets.
[3]	Consists primarily of mutual funds held in a rabbi trust for non-qualified deferred compensation plans for some key and highly compensated employees and a total return swap that does not meet the definition of a derivative.
[4]	of mutual funds held in a rabbi trusts for non-qualified deferred compensation plans for

Fair Value of Financial Instr80

Fair Value of Financial Instruments (Level 3 Inputs Recon - Details 3) $ / T in Millions, $ / MWh in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2015USD ($)$ / T$ / MWh		Dec. 31, 2014USD ($)$ / T$ / MWh
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		$ 2,220		$ 2,905
Total losses realized/unrealized:
Derivative Liability, Fair Value, Gross Liability		2,214		2,492
Level 3
Reconciliation of the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements
Balance at the beginning of the period		161		95
Total losses realized/unrealized:
Included in OCI				2
Included in earnings		(112)		(23)
Included in nuclear decommissioning obligations		(2)		(5)
Purchases		(15)		51
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Contracts Acquired				39
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Sales				(1)
Transfers into Level 3	[1]	3
Transfers out of Level 3	[1]	3
Balance at the end of the period		38		161
(Losses)/gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of end of period		(30)		20
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability Transfers into Level 3	[2]			2
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Transfers out of Level 3	[2]			1
Derivative [Member] | Level 3
Reconciliation of the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements
Balance at the beginning of the period		80	[3]	13	[4]
Total losses realized/unrealized:
Included in OCI	[4]			0
Included in earnings		(100)	[3]	(24)	[4]
Included in nuclear decommissioning obligations		0	[3]	0	[4]
Purchases		(19)	[3]	49	[4]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Contracts Acquired	[3]			39
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Sales	[4]			0
Transfers into Level 3	[1],[3]	3
Transfers out of Level 3	[1],[3]	3
Balance at the end of the period	[3]	(33)		80
(Losses)/gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of end of period		(30)	[3]	20	[4]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability Transfers into Level 3	[2],[4]			2
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Transfers out of Level 3	[2],[4]			1
Trust Fund Investment [Member] | Level 3
Reconciliation of the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements
Balance at the beginning of the period		52		56
Total losses realized/unrealized:
Included in OCI				0
Included in earnings		0		0
Included in nuclear decommissioning obligations		(2)		(5)
Purchases		4		2
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Contracts Acquired				0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Sales				(1)
Transfers into Level 3	[1]	0
Transfers out of Level 3	[1]	0
Balance at the end of the period		54		52
(Losses)/gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of end of period		0		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability Transfers into Level 3	[2]			0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Transfers out of Level 3	[2]			0
Other Financial Instrument [Member] | Level 3
Reconciliation of the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements
Balance at the beginning of the period		11		10
Total losses realized/unrealized:
Included in OCI				0
Included in earnings		(11)		1
Included in nuclear decommissioning obligations		0		0
Purchases		0		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Contracts Acquired				0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Sales				0
Transfers into Level 3	[1]	0
Transfers out of Level 3	[1]	0
Balance at the end of the period		0		11
(Losses)/gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of end of period		0		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability Transfers into Level 3	[2]			0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Transfers out of Level 3	[2]			0
Debt Securities [Member] | Level 3
Reconciliation of the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements
Balance at the beginning of the period		18		16
Total losses realized/unrealized:
Included in OCI				2
Included in earnings		(1)		0
Included in nuclear decommissioning obligations		0		0
Purchases		0		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Contracts Acquired				0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Sales				0
Transfers into Level 3	[1]	0
Transfers out of Level 3	[1]	0
Balance at the end of the period		17		18
(Losses)/gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of end of period		0		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability Transfers into Level 3	[2]			0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset and Liability, Transfers out of Level 3	[2]			0
Commodity contracts
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		2,220		2,902
Total losses realized/unrealized:
Derivative Liability, Fair Value, Gross Liability		2,086		2,327
Commodity contracts | Fair Value, Measurements, Recurring [Member]
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		2,220		2,902
Total losses realized/unrealized:
Derivative Liability, Fair Value, Gross Liability		2,086		2,327
Commodity contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		149		309
Total losses realized/unrealized:
Derivative Liability, Fair Value, Gross Liability		182		230
Commodity contracts | Coal Contract [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		0		3
Total losses realized/unrealized:
Derivative Liability, Fair Value, Gross Liability		12		1
Commodity contracts | Financial Transmission Rights [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		63		111
Total losses realized/unrealized:
Derivative Liability, Fair Value, Gross Liability		70		75
Commodity contracts | Power Contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Asset and Liabilities, Measured on Recurring Basis Unobservable Input, Changes
Derivative Asset, Fair Value, Gross Asset		86		195
Total losses realized/unrealized:
Derivative Liability, Fair Value, Gross Liability		$ 100		$ 154
Maximum [Member] | Commodity contracts | Coal Contract [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Total losses realized/unrealized:
Derivative, Forward Price | $ / T		45		56
Maximum [Member] | Commodity contracts | Financial Transmission Rights [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Total losses realized/unrealized:
Derivative, Auction Price | $ / MWh		87		30
Maximum [Member] | Commodity contracts | Power Contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Total losses realized/unrealized:
Derivative, Forward Price | $ / MWh		92		92
Weighted Average [Member] | Commodity contracts | Coal Contract [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Total losses realized/unrealized:
Derivative, Forward Price | $ / T		35		54
Weighted Average [Member] | Commodity contracts | Financial Transmission Rights [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Total losses realized/unrealized:
Derivative, Auction Price | $ / MWh		0		0
Weighted Average [Member] | Commodity contracts | Power Contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Total losses realized/unrealized:
Derivative, Forward Price | $ / MWh		27		47
Minimum [Member] | Commodity contracts | Coal Contract [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Total losses realized/unrealized:
Derivative, Forward Price | $ / T		28		53
Minimum [Member] | Commodity contracts | Financial Transmission Rights [Member] | Fair Value, Measurements, Recurring [Member] | Level 3
Total losses realized/unrealized:
Derivative, Auction Price | $ / MWh		(98)		(29)
Minimum [Member] | Commodity contracts | Power Contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Total losses realized/unrealized:
Derivative, Forward Price | $ / MWh		10		15
[1]	Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2.
[2]	Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2.
[3]	Consists of derivatives assets and liabilities, net.
[4]	Consists of derivatives assets and liabilities, net.

Fair Value of Financial Instr81

Fair Value of Financial Instruments Fair Value of Financial Instruments (Derivative Fair Value Measurement - Details 4) $ / T in Millions, $ / MWh in Millions, $ in Millions	Dec. 31, 2015USD ($)$ / T$ / MWh	Dec. 31, 2014USD ($)$ / T$ / MWh
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Collateral, Right to Reclaim Cash	$ 568	$ 187
Derivative Asset, Fair Value Determined Using Valuation Techniques, Percentage	7.00%
Derivative Asset, Fair Value, Gross Asset	$ 2,220	2,905
Derivative Liability, Fair Value, Gross Liability	$ 2,214	2,492
Derivative Liability, Fair Value Determined Using Valuation Techniques, Percentage	8.00%
Fair Value Assets, Measured on Recurring Basis, Valuation Techniques, Impact of Credit Reserve to Fair Value	$ 5	2
Cash collateral received in support of energy risk management activities	106	72
Fair Value Assets Measured On Recurring Basis Valuation Techniques Impact Of Credit Reserve To Fair Value Included In Oci Derivative Contracts	2
Fair Value Assets, Measured on Recurring Basis, Valuation Techniques, Impact of Credit Reserve to Fair Value Included in Operating Revenues and Cost of Operations, Derivative Contracts	3
Commodity contracts
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Collateral, Right to Reclaim Cash	271	27
Derivative Asset, Fair Value, Gross Asset	2,220	2,902
Derivative Liability, Fair Value, Gross Liability	2,086	2,327
Cash collateral received in support of energy risk management activities	113	72
Commodity contracts | Fair Value, Measurements, Recurring [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	2,220	2,902
Derivative Liability, Fair Value, Gross Liability	2,086	2,327
Commodity contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	149	309
Derivative Liability, Fair Value, Gross Liability	182	230
Power Contracts | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	86	195
Derivative Liability, Fair Value, Gross Liability	$ 100	$ 154
Power Contracts | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Minimum [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Forward Price | $ / MWh	10	15
Power Contracts | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Maximum [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Forward Price | $ / MWh	92	92
Power Contracts | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Weighted Average [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Forward Price | $ / MWh	27	47
Coal Contract [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 0	$ 3
Derivative Liability, Fair Value, Gross Liability	$ 12	$ 1
Coal Contract [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Minimum [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Forward Price | $ / T	28	53
Coal Contract [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Maximum [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Forward Price | $ / T	45	56
Coal Contract [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Weighted Average [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Forward Price | $ / T	35	54
Financial Transmission Rights [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 63	$ 111
Derivative Liability, Fair Value, Gross Liability	$ 70	$ 75
Financial Transmission Rights [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Minimum [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Auction Price | $ / MWh	(98)	(29)
Financial Transmission Rights [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Maximum [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Auction Price | $ / MWh	87	30
Financial Transmission Rights [Member] | Commodity contracts | Fair Value, Measurements, Recurring [Member] | Weighted Average [Member] | Level 3
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Auction Price | $ / MWh	0	0

Fair Value of Financial Instr82

Fair Value of Financial Instruments (Credit Risk - Details 5) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Fair Value Meaurements and Concentration of Credit Risk
Counterparty credit exposure, excluding credit risk exposure under certain long term agreements		$ 969
Counterparty credit exposure, collateral held (cash and letters of credit) against positions		240
Counterparty credit exposure, net		$ 733
Company's exposure before collateral expected to roll off by the end of 2015 (as a percent)		97.00%
Net exposure (as a percent)	[1]	100.00%
Counterparty credit risk exposure to certain counterparties, threshold (as a percent)		10.00%
Aggregate counterparty credit risk exposure for counterparties representing exposure above threshold percentage		$ 247
Estimated counterparty credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations and solar power purchase agreements for the next 5 years		$ 3,700
Period of estimated counterparty credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations and solar power purchase agreements (in years)		5 years
Provision for bad debts		$ 64	$ 64	$ 67
Investment grade
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	[1]	96.00%
External Credit Rating Not Rated [Member]
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	[1]	2.00%
External Credit Rating, Non Investment Grade [Member]
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	[1]	2.00%
Financial institutions
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	[1]	47.00%
Utilities, energy merchants, marketers and other
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	[1]	36.00%
ISOs
Derivative Fair Value Meaurements and Concentration of Credit Risk
Net exposure (as a percent)	[1]	17.00%
NRG Yield, Inc.
Derivative Fair Value Meaurements and Concentration of Credit Risk
Estimated counterparty credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations and solar power purchase agreements for the next 5 years		$ 2,700
[1]	Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.

Accounting for Derivative Ins83

Accounting for Derivative Instruments and Hedging Activities (Details) bbl in Millions, T in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)MWhMMBTUTbbl	Dec. 31, 2014USD ($)MWhMMBTUTbbl
Fair value of the derivative instrument
Derivative assets	$ 2,220	$ 2,905
Derivative liabilities	2,214	2,492
Derivatives Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	0	2
Derivative liabilities	110	129
Derivatives Not Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	2,220	2,903
Derivative liabilities	2,104	2,363
Interest rate contracts current | Derivatives Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	0	0
Derivative liabilities	42	55
Interest rate contracts current | Derivatives Not Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	0	0
Derivative liabilities	5	8
Interest rate contracts long-term | Derivatives Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	0	2
Derivative liabilities	68	74
Interest rate contracts long-term | Derivatives Not Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	0	0
Derivative liabilities	13	28
Commodity contracts current | Derivatives Not Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	1,915	2,425
Derivative liabilities	1,674	1,991
Commodity contracts long-term | Derivatives Not Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	305	477
Derivative liabilities	412	336
Equity Contract [Member]
Fair value of the derivative instrument
Derivative assets		1
Equity Contract [Member] | Derivatives Not Designated as Cash Flow Hedges
Fair value of the derivative instrument
Derivative assets	0	1
Derivative liabilities	$ 0	$ 0
Emissions [Member] | Short Ton
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Nonmonetary Notional Amount, Mass | T	1	2
Equity [Member] | Shares [Member]
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Notional Amount	$ 1	$ 2
Interest [Member] | Dollars
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Notional Amount	$ 2,326	$ 3,440
Coal [Member] | Short Ton
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Nonmonetary Notional Amount, Mass | T	35	57
Natural Gas [Member] | MMbtu
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	(293)	58
Oil [Member] | Barrel
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Nonmonetary Notional Amount, Volume | bbl	1	1
Power [Member] | MWh
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	74	56
Short [Member] | MW/Day [Member] | Capacity [Member]
Volumetric Underlying Derivative Transactions [Abstract]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	(1)	0

Accounting for Derivative Ins84

Accounting for Derivative Instruments and Hedging Activities (Details 2) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets	$ 2,220	$ 2,905
Cash Collateral (Held)	(106)	(72)
Gross Amounts of Recognized Derivative Liabilities	(2,214)	(2,492)
Cash collateral paid in support of energy risk management activities	568	187
Gross Amounts of Recognized Assets / Liabilities	6	413
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	158	(45)
Net Amount	164	368
Commodity contracts
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets	2,220	2,902
Derivative Instruments	(1,616)	(2,155)
Cash Collateral (Held)	(113)	(72)
Net Amount	491	675
Gross Amounts of Recognized Derivative Liabilities	(2,086)	(2,327)
Derivative Instruments	1,616	2,155
Cash collateral paid in support of energy risk management activities	271	27
Net Amount	(199)	(145)
Gross Amounts of Recognized Assets / Liabilities	134	575
Derivative Instruments	0	0
Cash Collateral (Held) / Posted	158	(45)
Net Amount	292	530
Interest rate contracts
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets		2
Derivative Instruments		(2)
Cash Collateral (Held)		0
Net Amount		0
Gross Amounts of Recognized Derivative Liabilities	(128)	(165)
Derivative Instruments	0	2
Cash collateral paid in support of energy risk management activities	0	0
Net Amount	$ (128)	(163)
Gross Amounts of Recognized Assets / Liabilities		(163)
Derivative Instruments		0
Cash Collateral (Held) / Posted		0
Net Amount		(163)
Equity Contract [Member]
Offsetting of Derivatives by Counterparty Master Agreement Level and Collateral Received or Paid
Derivative assets		1
Derivative Instruments		0
Cash Collateral (Held)		0
Net Amount		$ 1

Accounting for Derivative Ins85

Accounting for Derivative Instruments and Hedging Activities (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 15	$ 13	$ (31)
Accumulated Other Comprehensive Income
Accumulated OCI beginning balance	(68)	(23)	(31)
Mark-to-market of cash flow hedge accounting contracts	(48)	(58)	39
Accumulated OCI ending balance, net of tax	(101)	(68)	(23)
Accumulated OCI ending balance, tax	16	35	14
Losses expected to be realized from OCI during the next 12 months, net of $3 tax	(18)
Gains/(losses) expected to be realized from OCI during the next 12 months, tax	3	0
Unrealized mark-to-market results
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	(275)	(15)	(105)
Reversal of acquired gain positions related to economic hedges	(106)	(333)	(357)
Net unrealized gains on open positions related to economic hedges	9	361	177
Losses on ineffectiveness associated with open positions treated as cash flow hedges	0	0	0
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(372)	13	(285)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(46)	1	(50)
Reversal of Previously Unrecognized Unrealized Gain Loss Acquired as Part of Acquisition Trading Activity	(14)	(32)	0
Net unrealized (losses)/gains on open positions related to trading activity	(16)	45	7
Total unrealized mark-to-market (losses)/gains for trading activity	(76)	14	(43)
Total unrealized (losses)/gains	(448)	27	(328)
Impact of derivative instruments to statement of operations
Total unrealized (losses)/gains	(448)	27	(328)
Credit Risk Related Contingent Features
Collateral required for contracts with adequate assurance clauses in net liability positions	204
Collateral required for contracts with credit rating contingent features	34
Collateral due on net liability position that has not been called by a certain marginable agreement counterparty	3
Energy commodities
Derivative
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	1	0	(51)
Accumulated Other Comprehensive Income
Accumulated OCI beginning balance	(1)	(1)	41
Mark-to-market of cash flow hedge accounting contracts	0	0	9
Accumulated OCI ending balance, net of tax	0	(1)	(1)
Losses expected to be realized from OCI during the next 12 months, net of $3 tax	0
Unrealized mark-to-market results
Total unrealized (losses)/gains	(448)	27	(328)
Impact of derivative instruments to statement of operations
Total unrealized (losses)/gains	(448)	27	(328)
Energy commodities | Unrealized (losses)/gains included in operating revenues
Unrealized mark-to-market results
Total unrealized (losses)/gains	(320)	515	(621)
Impact of derivative instruments to statement of operations
Total unrealized (losses)/gains	(320)	515	(621)
Energy commodities | Unrealized (losses)/gains included in cost of operations
Unrealized mark-to-market results
Total unrealized (losses)/gains	(128)	(488)	293
Impact of derivative instruments to statement of operations
Total unrealized (losses)/gains	(128)	(488)	293
Interest rate contracts
Derivative
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	14	13	20
Accumulated Other Comprehensive Income
Accumulated OCI beginning balance	(67)	(22)	(72)
Mark-to-market of cash flow hedge accounting contracts	(48)	(58)	30
Accumulated OCI ending balance, net of tax	(101)	(67)	(22)
Losses expected to be realized from OCI during the next 12 months, net of $3 tax	(18)
Unrealized mark-to-market results
Total unrealized (losses)/gains	17	(31)	15
Impact of derivative instruments to statement of operations
Total unrealized (losses)/gains	$ 17	(31)	15
NRG Solar Dandan [Member] | Interest rate contracts
Discontinuation of Cash Flow Hedge [Abstract]
Loss previously deferred in OCI recognized in earnings resulting from discontinued cash flow hedge accounting		$ 6
CVSR | Interest rate contracts
Discontinuation of Cash Flow Hedge [Abstract]
Loss previously deferred in OCI recognized in earnings resulting from discontinued cash flow hedge accounting			$ 5

Nuclear Decommissioning Trust86

Nuclear Decommissioning Trust Fund (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Nuclear decommissioning trust fund disclosure
Fair Value	$ 561	$ 585
Unrealized Gains	202	218
Unrealized Losses	3	2
Proceeds from sales of available-for-sale securities and the related realized gains and losses
Realized gains	21	29	$ 25
Realized losses	(14)	(8)	(8)
Proceeds from sale of securities	$ (631)	$ (600)	$ (488)
Cash and Cash Equivalents [Domain]
Nuclear decommissioning trust fund disclosure
Weighted- average maturities (in years)	0 years	0 years
Cash and cash equivalents
Nuclear decommissioning trust fund disclosure
Fair Value	$ 6	$ 14
Unrealized Gains	0	0
Unrealized Losses	0	0
U.S. government and federal agency obligations
Nuclear decommissioning trust fund disclosure
Fair Value	55	47
Unrealized Gains	1	2
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	11 years	11 years
Federal agency mortgage-backed securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 59	$ 74
Unrealized Gains	1	2
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	25 years	25 years
Commercial mortgage-backed securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 25	$ 25
Unrealized Gains	0	0
Unrealized Losses	$ 2	$ 1
Weighted- average maturities (in years)	28 years	30 years
Corporate debt securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 81	$ 78
Unrealized Gains	1	2
Unrealized Losses	$ 1	$ 1
Weighted- average maturities (in years)	10 years	11 years
Equity securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 334	$ 344
Unrealized Gains	199	211
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	0 years	0 years
Foreign government fixed income securities
Nuclear decommissioning trust fund disclosure
Fair Value	$ 1	$ 3
Unrealized Gains	0	1
Unrealized Losses	$ 0	$ 0
Weighted- average maturities (in years)	9 years	16 years
South Texas Project
Nuclear decommissioning trust fund disclosure
Ownership Interest (as a percent)	44.00%

Inventory (Details)

Inventory (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Inventory Disclosure [Abstract]
Inventory Write-down	$ 19
Fuel oil	312	$ 375
Coal/Lignite	471	414
Natural gas	12	16
Spare parts	437	424
Other	20	18
Total Inventory	$ 1,252	$ 1,247

Notes Receivable (Details)

Notes Receivable (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Notes Receivable
Notes receivable, current	[1]	$ 20	$ 19
Notes receivable, noncurrent		53	72
Other non-affiliates
Notes Receivable
Notes receivable (a)		$ 73	$ 91
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjExY2M4MDRjNjI5MjQ4ZmVhMTMxZWFiZTYwOTNjYmY3fFRleHRTZWxlY3Rpb246QkM4QzJDM0YyQTBFRjFGNzVBMUZCNzkyQ0YzREU1REMM}

Property, Plant and Equipment89

Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment
Total property, plant and equipment	$ 25,536	$ 30,257
Construction in Progress, Gross	627	770
Accumulated depreciation	(6,804)	(7,890)
Net property, plant and equipment	18,732	22,367
Facilities and equipment
Property, Plant and Equipment
Total property, plant and equipment	22,676	27,457
Land and improvements
Property, Plant and Equipment
Total property, plant and equipment	1,226	1,194
Nuclear fuel
Property, Plant and Equipment
Total property, plant and equipment	$ 545	490
Depreciable lives (in years)	5 years
Office furnishings and equipment
Property, Plant and Equipment
Total property, plant and equipment	$ 462	$ 346
Minimum [Member] | Facilities and equipment
Property, Plant and Equipment
Depreciable lives (in years)	1 year
Minimum [Member] | Office furnishings and equipment
Property, Plant and Equipment
Depreciable lives (in years)	2 years
Maximum [Member] | Facilities and equipment
Property, Plant and Equipment
Depreciable lives (in years)	40 years
Maximum [Member] | Office furnishings and equipment
Property, Plant and Equipment
Depreciable lives (in years)	10 years

Asset Impairments (Details)

Asset Impairments (Details) $ in Millions		Nov. 25, 2015USD ($)	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)MW	Sep. 30, 2014USD ($)MW	Dec. 31, 2013USD ($)	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)MW	Dec. 31, 2013USD ($)
Asset Impairments
Impairment losses							$ 5,030	$ 97	$ 459
Other than Temporary Impairment Losses, Investments							$ 56	$ 0	$ 99
Power Generation Capacity, Megawatts | MW	[1]		49,287				49,287
Indian River
Asset Impairments
Impairment losses						$ 459
Limestone [Member]
Asset Impairments
Impairment losses			$ 1,514
W.A. Parish [Member]
Asset Impairments
Impairment losses			$ 1,295
Huntley [Member]
Asset Impairments
Impairment losses							$ 132
Dunkirk [Member]
Asset Impairments
Impairment losses							160
Gregory Power Partners, L.P. [Member]
Asset Impairments
Impairment losses							176
Coolwater [Member]
Asset Impairments
Impairment losses				$ 22
Power Generation Capacity, Megawatts | MW				636				636
Osceola facility [Member]
Asset Impairments
Impairment losses					$ 60
Power Generation Capacity, Megawatts | MW					463
Solar Panels [Member]
Asset Impairments
Impairment losses					$ 10		$ 29
Gladstone Power Station (b)
Asset Impairments
Impairment losses						$ 92
Power Generation Capacity, Megawatts | MW			1,613				1,613
Noncontrolling Interest, Ownership Percentage by Parent						37.50%			37.50%
Seward Generating Station [Member]
Asset Impairments
Proceeds from Sale of Equity Method Investments		$ 75
Impairment losses							$ 134
[1]	Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.

Goodwill and Other Intangible91

Goodwill and Other Intangibles (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares		Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)	Dec. 31, 2011USD ($)	Dec. 31, 2010USD ($)	Dec. 31, 2006USD ($)	Apr. 02, 2014USD ($)	Dec. 14, 2012USD ($)
Goodwill and Other Intangibles
Goodwill	$ 999		$ 2,574
Goodwill, Impairment Loss	1,500
Goodwill deductible for U.S. income tax purposes	620		831
Components of NRG's intangible assets subject to amortization
Gross amount at the beginning of the period	3,969		3,117
Purchases	137		182
Acquisition of businesses			1,541
Usage	95		(34)
Write-off of fully amortized balances	154		(843)
Impairment of Intangible Assets, Finite-lived	(11)
Other	11		6
Gross amount at the end of the period	3,835		3,969	$ 3,117
Less accumulated amortization	(1,525)	[1]	(1,402)
Net carrying amount	2,310		2,567
Amortization of intangible assets	277		268	279
Estimated amortization related to NRG's finite-lived intangible assets
Estimated intangible assets amortization, 2016	275
Estimated intangible assets amortization, 2017	189
Estimated intangible assets amortization, 2018	170
Estimated intangible assets amortization, 2019	148
Estimated intangible assets amortization, 2020	129
Emission allowances held-for-sale and included in other non current assets	22
Estimated amortization related to NRG's out-of-market contracts
Off-market Lease, Unfavorable	1,146		1,244
Texas Genco
Goodwill and Other Intangibles
Goodwill in connection with acquisition							$ 1,700
Green Mountain Energy
Goodwill and Other Intangibles
Goodwill in connection with acquisition						$ 144
Energy Plus
Goodwill and Other Intangibles
Goodwill in connection with acquisition					$ 29
EME [Member]
Goodwill and Other Intangibles
Goodwill in connection with acquisition			278
Emission Allowances [Member]
Components of NRG's intangible assets subject to amortization
Gross amount at the beginning of the period	1,018		871
Purchases	77		141
Acquisition of businesses			12
Usage	33		0
Write-off of fully amortized balances	154		0
Impairment of Intangible Assets, Finite-lived	0
Other	(12)		6
Gross amount at the end of the period	920		1,018	871
Less accumulated amortization	(502)	[1]	(557)
Net carrying amount	418		461
Amortization of intangible assets	99		124	104
Estimated amortization related to NRG's finite-lived intangible assets
Estimated intangible assets amortization, 2016	112
Estimated intangible assets amortization, 2017	53
Estimated intangible assets amortization, 2018	48
Estimated intangible assets amortization, 2019	32
Estimated intangible assets amortization, 2020	17
Energy Supply
Components of NRG's intangible assets subject to amortization
Gross amount at the beginning of the period	54		54
Purchases	0		0
Acquisition of businesses			0
Usage	0		0
Write-off of fully amortized balances	0		0
Impairment of Intangible Assets, Finite-lived	0
Other	0		0
Gross amount at the end of the period	54		54	54
Less accumulated amortization	(47)	[1]	(42)
Net carrying amount	7		12
Amortization of intangible assets	5		6	6
Estimated amortization related to NRG's finite-lived intangible assets
Estimated intangible assets amortization, 2016	7
Estimated intangible assets amortization, 2017	0
Estimated intangible assets amortization, 2018	0
Estimated intangible assets amortization, 2019	0
Estimated intangible assets amortization, 2020	0
Fuel
Components of NRG's intangible assets subject to amortization
Gross amount at the beginning of the period	72		72
Purchases	0		0
Acquisition of businesses			0
Usage	0		0
Write-off of fully amortized balances	0		0
Impairment of Intangible Assets, Finite-lived	0
Other	0		0
Gross amount at the end of the period	72		72	72
Less accumulated amortization	(65)	[1]	(63)
Net carrying amount	7		9
Amortization of intangible assets	2		2	2
Estimated amortization related to NRG's finite-lived intangible assets
Estimated intangible assets amortization, 2016	2
Estimated intangible assets amortization, 2017	1
Estimated intangible assets amortization, 2018	0
Estimated intangible assets amortization, 2019	0
Estimated intangible assets amortization, 2020	0
Customer
Components of NRG's intangible assets subject to amortization
Gross amount at the beginning of the period	16		859
Purchases	0		0
Acquisition of businesses			0
Usage	0		0
Write-off of fully amortized balances	0		843
Impairment of Intangible Assets, Finite-lived	0
Other	0		0
Gross amount at the end of the period	16		16	859
Less accumulated amortization	(6)	[1]	(4)
Net carrying amount	10		12
Amortization of intangible assets	2		0	53
Estimated amortization related to NRG's finite-lived intangible assets
Estimated intangible assets amortization, 2016	1
Estimated intangible assets amortization, 2017	1
Estimated intangible assets amortization, 2018	1
Estimated intangible assets amortization, 2019	1
Estimated intangible assets amortization, 2020	1
Customer Relationships
Components of NRG's intangible assets subject to amortization
Gross amount at the beginning of the period	831		743
Purchases	3		8
Acquisition of businesses			80
Usage	0		0
Write-off of fully amortized balances	0		0
Impairment of Intangible Assets, Finite-lived	0
Other	0		0
Gross amount at the end of the period	834		831	743
Less accumulated amortization	(624)	[1]	(557)
Net carrying amount	210		274
Amortization of intangible assets	67		70	72
Estimated amortization related to NRG's finite-lived intangible assets
Estimated intangible assets amortization, 2016	48
Estimated intangible assets amortization, 2017	33
Estimated intangible assets amortization, 2018	20
Estimated intangible assets amortization, 2019	16
Estimated intangible assets amortization, 2020	14
Marketing Partnerships
Components of NRG's intangible assets subject to amortization
Gross amount at the beginning of the period	88		88
Purchases	0		0
Acquisition of businesses			0
Usage	0		0
Write-off of fully amortized balances	0		0
Impairment of Intangible Assets, Finite-lived	0
Other	0		0
Gross amount at the end of the period	88		88	88
Less accumulated amortization	(41)	[1]	(27)
Net carrying amount	47		61
Amortization of intangible assets	14		15	8
Estimated amortization related to NRG's finite-lived intangible assets
Estimated intangible assets amortization, 2016	9
Estimated intangible assets amortization, 2017	5
Estimated intangible assets amortization, 2018	5
Estimated intangible assets amortization, 2019	4
Estimated intangible assets amortization, 2020	4
Trade Names
Components of NRG's intangible assets subject to amortization
Gross amount at the beginning of the period	353		318
Purchases	0		0
Acquisition of businesses			35
Usage	0		0
Write-off of fully amortized balances	0		0
Impairment of Intangible Assets, Finite-lived	(6)
Other	5		0
Gross amount at the end of the period	342		353	318
Less accumulated amortization	(137)	[1]	(114)
Net carrying amount	205		239
Amortization of intangible assets	23		21	29
Estimated amortization related to NRG's finite-lived intangible assets
Estimated intangible assets amortization, 2016	23
Estimated intangible assets amortization, 2017	23
Estimated intangible assets amortization, 2018	23
Estimated intangible assets amortization, 2019	23
Estimated intangible assets amortization, 2020	23
PPA [Member]
Components of NRG's intangible assets subject to amortization
Gross amount at the beginning of the period	1,269		14
Purchases	0		0
Acquisition of businesses			1,252
Usage	0		0
Write-off of fully amortized balances	0		0
Impairment of Intangible Assets, Finite-lived	0
Other	6		(3)
Gross amount at the end of the period	1,263		1,269	14
Less accumulated amortization	(75)	[1]	(25)
Net carrying amount	1,188		1,244
Amortization of intangible assets	50		24	1
Estimated amortization related to NRG's finite-lived intangible assets
Estimated intangible assets amortization, 2016	63
Estimated intangible assets amortization, 2017	63
Estimated intangible assets amortization, 2018	63
Estimated intangible assets amortization, 2019	63
Estimated intangible assets amortization, 2020	63
Other
Components of NRG's intangible assets subject to amortization
Gross amount at the beginning of the period	268		98
Purchases	57		33
Acquisition of businesses			162
Usage	62		34
Write-off of fully amortized balances	0		0
Impairment of Intangible Assets, Finite-lived	(5)
Other	12		(9)
Gross amount at the end of the period	246		268	98
Less accumulated amortization	(28)	[1]	(13)
Net carrying amount	218		255
Amortization of intangible assets	15		$ 6	$ 4
Estimated amortization related to NRG's finite-lived intangible assets
Estimated intangible assets amortization, 2016	10
Estimated intangible assets amortization, 2017	10
Estimated intangible assets amortization, 2018	10
Estimated intangible assets amortization, 2019	9
Estimated intangible assets amortization, 2020	7
Leases | EME [Member]
Estimated amortization related to NRG's out-of-market contracts
Off-market Lease, Unfavorable								$ 159
Leases | GenOn Energy
Estimated amortization related to NRG's out-of-market contracts
Off-market Lease, Unfavorable									$ 790
Gas Transportation | GenOn Energy
Estimated amortization related to NRG's out-of-market contracts
Off-market Lease, Unfavorable									$ 327
Out of Market Contracts
Estimated amortization related to NRG's out-of-market contracts
Estimated out-of-market amortization, 2016	105
Estimated out-of-market amortization, 2017	100
Estimated out-of-market amortization, 2018	95
Estimated out-of-market amortization, 2019	93
Estimated out-of-market amortization, 2020	93
Out of Market Contracts | Power Contracts
Estimated amortization related to NRG's out-of-market contracts
Estimated out-of-market amortization, 2016	16
Estimated out-of-market amortization, 2017	16
Estimated out-of-market amortization, 2018	16
Estimated out-of-market amortization, 2019	17
Estimated out-of-market amortization, 2020	17
Out of Market Contracts | Leases
Estimated amortization related to NRG's out-of-market contracts
Estimated out-of-market amortization, 2016	47
Estimated out-of-market amortization, 2017	47
Estimated out-of-market amortization, 2018	47
Estimated out-of-market amortization, 2019	47
Estimated out-of-market amortization, 2020	47
Out of Market Contracts | Gas Transportation
Estimated amortization related to NRG's out-of-market contracts
Estimated out-of-market amortization, 2016	42
Estimated out-of-market amortization, 2017	37
Estimated out-of-market amortization, 2018	32
Estimated out-of-market amortization, 2019	29
Estimated out-of-market amortization, 2020	$ 29
Texas [Member]
Goodwill and Other Intangibles
Reporting Unit, Percentage of Carrying Amount in Excess of Fair Value	0.76
Goodwill, Impairment Loss	$ 1,400
Home Solar [Member]
Goodwill and Other Intangibles
Goodwill, Impairment Loss	125
Goal Zero [Member]
Goodwill and Other Intangibles
Goodwill, Impairment Loss	$ 36
Non-Qualified Stock Options [Member]
Goodwill and Other Intangibles
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number | shares	2,071,913		2,533,177
Estimated amortization related to NRG's out-of-market contracts
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price | $ / shares	$ 32.27		$ 30.95
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	3 years		2 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value	$ 0		$ 9
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period | shares	(59,617)
Share-based Compensation Arrangements by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price | $ / shares	$ 35.28
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period | shares	(401,647)
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price | $ / shares	$ 23.23
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number | shares	2,071,913
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price | $ / shares	$ 32.27
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value	$ 0
[1]	Adjusted for write-off of fully amortized emissions allowances of $154 million.

Debt and Capital Leases (Debt S

Debt and Capital Leases (Debt Schedule)(Details) - USD ($) $ in Millions		9 Months Ended	12 Months Ended
		Sep. 30, 2015	Dec. 31, 2015		Jun. 30, 2015	Dec. 31, 2014	Apr. 21, 2014	Mar. 31, 2014	Jan. 27, 2014	Jun. 30, 2002
Debt Instrument
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months			$ 484
Long-term Debt			19,620			$ 20,366
Subtotal			19,636			20,374
Current portion of long-term debt and capital leases			481			474
Deferred Finance Costs, Net	[1]		172			199
Long-term debt and capital leases			$ 18,983			19,701
Debt Instrument, Description of Variable Rate Basis			3 month LIBOR
Total premium/(discount)			$ 140			234
Long-term Debt, Maturities, Repayments of Principal in Year Two			1,153
Long-term Debt, Maturities, Repayments of Principal in Year Three			4,008
Long-term Debt, Maturities, Repayments of Principal in Year Four			1,052
Long-term Debt, Maturities, Repayments of Principal in Year Five			2,288
Long-term Debt, Maturities, Repayments of Principal after Year Five			10,511
Long-term Debt, excluding Unamortized Discount (Premium), net			19,496
Recourse Debt
Debt Instrument
Long-term Debt			8,584			8,800
Non Recourse Debt
Debt Instrument
Long-term Debt			11,036			11,566
Senior notes, due 2018 | Recourse Debt
Debt Instrument
Long-term Debt			$ 1,039			1,130
Debt Instrument, Interest Rate, Stated Percentage	[2]		7.625%
Senior notes, due 2020 | Recourse Debt
Debt Instrument
Long-term Debt			$ 1,058			1,063
Debt Instrument, Interest Rate, Stated Percentage	[2]		8.25%
Senior notes, due 2021 | Recourse Debt
Debt Instrument
Long-term Debt			$ 1,128			1,128
Debt Instrument, Interest Rate, Stated Percentage	[2]		7.875%
Senior Notes Due In 2022 [Member] | Recourse Debt
Debt Instrument
Long-term Debt			$ 1,100			1,100
Debt Instrument, Interest Rate, Stated Percentage			6.25%	[2]					6.25%
Senior notes, due 2023 | Recourse Debt
Debt Instrument
Long-term Debt			$ 936			990
Debt Instrument, Interest Rate, Stated Percentage	[2]		6.625%
Senior Notes 2024 [Member] | Recourse Debt
Debt Instrument
Long-term Debt			$ 904			1,000
Debt Instrument, Interest Rate, Stated Percentage			6.25%	[2]			6.25%
Term loan facility, due 2018
Debt Instrument
Unamortized discount on debt instruments	[1]		$ 3			4
Term loan facility, due 2018 | Recourse Debt
Debt Instrument
Long-term Debt			$ 1,964			1,983
Debt Instrument, Description of Variable Rate Basis	[2]		LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]		2.00%
Tax Exempt Bonds | Recourse Debt
Debt Instrument
Long-term Debt			$ 455			406
GenOn Senior Notes [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			1,956			2,133
GenOn senior notes, due 2018
Debt Instrument
Unamortized premium on debt instruments	[3]		59			83
GenOn senior notes, due 2018 | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 708			757
Debt Instrument, Interest Rate, Stated Percentage	[2]		9.50%
GenOn senior notes, due 2020
Debt Instrument
Unamortized premium on debt instruments	[3]		$ 44			60
GenOn senior notes, due 2020 | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 534			610
Debt Instrument, Interest Rate, Stated Percentage	[2]		9.875%
GenOn Americas Generation Senior Notes Due in 2021 [Member]
Debt Instrument
Unamortized premium on debt instruments	[3]		$ 32			46
GenOn Americas Generation Senior Notes Due in 2021 [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 398			496
Debt Instrument, Interest Rate, Stated Percentage	[2]		8.50%
GenOn Americas Generation senior notes, due 2031
Debt Instrument
Unamortized premium on debt instruments	[3]		$ 25			33
GenOn Americas Generation senior notes, due 2031 | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 354			433
Debt Instrument, Interest Rate, Stated Percentage	[2]		9.125%
GenOn Americas Generation senior notes | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 752			929
GenOn Other [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			56			60
Genon [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			2,764			3,122
5.375% Senior Notes due in 2024 [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			500			500
NRG Yield Revolving Credit Facility [Member]
Debt Instrument
Long-term Debt			306			0
3.5% Convertible Notes due 2019 [Member]
Debt Instrument
Long-term Debt			330			326
Unamortized discount on debt instruments			(15)			(19)
Debt Instrument, Interest Rate, Stated Percentage								3.50%
3.25% Convertible Notes due 2020 [Member]
Debt Instrument
Long-term Debt			266			0
Unamortized discount on debt instruments			(21)			0
Debt Instrument, Interest Rate, Stated Percentage					3.25%
GenOn Senior Notes Due in 2017 [Member]
Debt Instrument
Unamortized premium on debt instruments	[3]		23			41
GenOn Senior Notes Due in 2017 [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 714			766
Debt Instrument, Interest Rate, Stated Percentage	[2]		7.875%
El Segundo Energy Center, due 2023 | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 485			506
Debt Instrument, Description of Variable Rate Basis	[2]		LIBOR
Marsh Landing, due 2017 and 2023
Debt Instrument
Debt Instrument, Description of Variable Rate Basis		1 - month LIBOR
Marsh Landing, due 2017 and 2023 | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 418			464
Debt Instrument, Description of Variable Rate Basis	[2]		LIBOR
Alta Wind I - V Lease financing arrangement [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 1,002			1,036
Debt instrument, interest rate, stated percentage, low end of the range (as a percent)	[2]		5.696%
Debt instrument, interest rate, stated percentage, high end of the range (as a percent)	[2]		7.015%
Alta Wind X [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 0			300
Debt Instrument, Description of Variable Rate Basis	[2]		LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]		2.00%
Alta Wind XI [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 0			191
Debt Instrument, Description of Variable Rate Basis	[2]		LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]		2.00%
Walnut Creek Energy, LLC, due in 2023 [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis		1 - month LIBOR
Walnut Creek Energy, LLC, due in 2023 [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 351			391
Debt Instrument, Description of Variable Rate Basis	[2]		LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]		1.625%
Revolving Credit Facility [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis		1 - month LIBOR
Tapestry Wind LLC due in 2021 [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 181			192
Debt Instrument, Description of Variable Rate Basis	[2]		LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]		1.625%
Laredo Ridge [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 104			108
Alpine Financing Agreement, due 2022 [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			154			163
NRG Energy Center Minneapolis LLC Senior Secured Notes [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 108			121
Debt Instrument, Description of Variable Rate Basis	[2]		LIBOR
Debt instrument, interest rate, stated percentage, low end of the range (as a percent)	[2]		5.95%
Debt instrument, interest rate, stated percentage, high end of the range (as a percent)	[2]		7.25%
Debt instrument, interest rate over variable rate (as a percent)	[2]		3.125%
Viento Funding II, Inc., due in 2023 [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis		6 - month LIBOR	6 month LIBOR
Viento Funding II, Inc., due in 2023 [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 189			196
Debt Instrument, Description of Variable Rate Basis	[2]		LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]		2.75%
NRG Yield - Other [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 469			489
NRG Yield, Inc. [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			4,863			4,983
Ivanpah, due 2033 and 2038 | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 1,149			1,183
Debt instrument, interest rate, stated percentage, low end of the range (as a percent)	[2]		0.437%
Debt instrument, interest rate, stated percentage, high end of the range (as a percent)	[2]		4.256%
Agua Caliente, due 2037 | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 879			898
Debt instrument, interest rate, stated percentage, low end of the range (as a percent)	[2]		2.395%
Debt instrument, interest rate, stated percentage, high end of the range (as a percent)	[2]		3.633%
CVSR, due 2037 | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 793			815
Debt instrument, interest rate, stated percentage, low end of the range (as a percent)			2.30%
Debt instrument, interest rate, stated percentage, high end of the range (as a percent)			3.80%
NRG Solar Dandan [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 98			54
Peaker bonds, due 2019
Debt Instrument
Unamortized discount on debt instruments	[4]		4			6
Debt Instrument, Interest Rate, Stated Percentage										6.67%
Peaker bonds, due 2019 | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 72			100
Debt Instrument, Description of Variable Rate Basis	[2]		LIBOR
Debt instrument, interest rate over variable rate (as a percent)	[2]		1.07%
Cedro Hill Wind LLC, due in 2025 [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			$ 103			111
NRG Other | Non Recourse Debt
Debt Instrument
Long-term Debt			315			300
NRG Energy [Member] | Non Recourse Debt
Debt Instrument
Long-term Debt			3,409			3,461
Home Solar [Member]
Debt Instrument
Capital Lease Obligations			13			0
Chalk Point capital lease, due 2015
Debt Instrument
Capital Lease Obligations			$ 0			5
Debt Instrument, Interest Rate, Stated Percentage	[2]		8.19%
Other (capital leases)
Debt Instrument
Capital Lease Obligations			$ 3			$ 3
7.625% Senior notes, due 2019 | Recourse Debt
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage			7.625%
8.50% Senior notes, due 2019 | Recourse Debt
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[2]		8.50%
Alpine Financing Agreement [Member] | Non Recourse Debt
Debt Instrument
Debt Instrument, Description of Variable Rate Basis	[2]		LIBOR
Minimum [Member] | El Segundo Energy Center, due 2023 | Non Recourse Debt
Debt Instrument
Debt instrument, interest rate over variable rate (as a percent)	[2]		2.25%
Minimum [Member] | Marsh Landing, due 2017 and 2023 | Non Recourse Debt
Debt Instrument
Debt instrument, interest rate over variable rate (as a percent)	[2]		1.75%
Minimum [Member] | Alpine Financing Agreement [Member] | Non Recourse Debt
Debt Instrument
Debt instrument, interest rate over variable rate (as a percent)	[2]		1.75%
Maximum [Member] | El Segundo Energy Center, due 2023 | Non Recourse Debt
Debt Instrument
Debt instrument, interest rate over variable rate (as a percent)	[2]		2.88%
Maximum [Member] | Marsh Landing, due 2017 and 2023 | Non Recourse Debt
Debt Instrument
Debt instrument, interest rate over variable rate (as a percent)	[2]		1.88%
Maximum [Member] | Alpine Financing Agreement [Member] | Non Recourse Debt
Debt Instrument
Debt instrument, interest rate over variable rate (as a percent)	[2]		2.50%
Current Liabilities [Member] | Term loan facility, due 2018
Debt Instrument
Debt Instrument, Unamortized Discount Relating to Current Maturities	[3]		$ 1
Current Liabilities [Member] | Peaker bonds, due 2019
Debt Instrument
Unamortized discount on debt instruments			$ 2
[1]	Discount of $1 million is related to current maturities in 2015 and 2014.
[2]	As of December 31, 2015, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Marsh Landing term loan, Walnut Creek loan, and Yield Operating LLC Revolving Credit facility, which are 1 month LIBOR plus x%
[3]	Premiums for long-term debt acquired in the GenOn acquisition represent adjustments to record the debt at fair value in connection with the acquisition.
[4]	Discount of $2 million are related to current maturities in 2015 and 2014

Debt and Capital Leases (NRG Re

Debt and Capital Leases (NRG Recourse Debt 1 Repurchase/Redemption - Details 2) - USD ($)		Apr. 21, 2014	Jan. 27, 2014	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013	Jun. 30, 2014
Debt Instrument
Loss on debt extinguishment				$ (75,000,000)		$ 95,000,000	$ 50,000,000
Senior notes, due 2020
Debt Instrument
Debt Instrument, Principal Amount Repurchased				(246,000,000)		(1,400,000,000)
Debt Instrument, Repurchase Amount				$ (231,000,000)		$ (1,500,000,000)
Recourse Debt | Senior notes, due 2020
Debt Instrument
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed				96.50%
Debt instrument, interest rate, stated percentage (as a percent)	[1]			8.25%
Loss on debt extinguishment				$ 0
Debt Instrument, Principal Amount Repurchased				$ (5,000,000)
Recourse Debt | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed				(84.725%)
Proceeds from Issuance of Senior Long-term Debt		$ 1,000,000,000
Debt instrument, interest rate, stated percentage (as a percent)		6.25%		6.25%	[1]
Loss on debt extinguishment				$ (14,000,000)
Debt Instrument, Principal Amount Repurchased				$ (95,000,000)
Recourse Debt | Senior notes, due 2022
Debt Instrument
Proceeds from Issuance of Senior Long-term Debt			$ 1,100,000,000
Debt instrument, interest rate, stated percentage (as a percent)			6.25%	6.25%	[1]
Recourse Debt | 8.50% Senior notes, due 2019
Debt Instrument
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed						105.764%
Debt instrument, interest rate, stated percentage (as a percent)	[1]			8.50%
Long-term Debt, Gross								$ 225,000,000
Loss on debt extinguishment						$ (45,000,000)
Debt Instrument, Principal Amount Repurchased						(607)
Recourse Debt | Senior notes, due 2020
Debt Instrument
Loss on debt extinguishment				$ (19,000,000)		(86,000,000)
Debt Instrument, Principal Amount Repurchased				$ (246,000,000)		$ (1,407)
Recourse Debt | Senior notes, due 2018
Debt Instrument
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed				(102.232%)
Debt instrument, interest rate, stated percentage (as a percent)	[1]			7.625%
Loss on debt extinguishment				$ 2,000,000
Debt Instrument, Principal Amount Repurchased				$ (92,000,000)
Recourse Debt | 7.625% Senior notes, due 2019
Debt Instrument
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed						104.169%
Debt instrument, interest rate, stated percentage (as a percent)				7.625%
Loss on debt extinguishment						$ (41,000,000)
Debt Instrument, Principal Amount Repurchased						$ (800)
Recourse Debt | Senior notes, due 2023
Debt Instrument
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed				(85.972%)
Debt instrument, interest rate, stated percentage (as a percent)	[1]			6.625%
Loss on debt extinguishment				$ (7,000,000)
Debt Instrument, Principal Amount Repurchased				$ (54,000,000)
[1]	As of December 31, 2015, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Marsh Landing term loan, Walnut Creek loan, and Yield Operating LLC Revolving Credit facility, which are 1 month LIBOR plus x%

Debt and Capital Leases Debt an

Debt and Capital Leases Debt and Capital Leases (NRG Recourse Debt 2 - Senior Notes OS) (Details 3)		12 Months Ended
		Dec. 31, 2015		Apr. 21, 2014	Jan. 27, 2014
Recourse Debt [Member]
Debt Instrument
Debt Instrument, Call Feature		Generally, if an event of default occurs, the Trustee or the Holders of at least 25% in principal amount of the then outstanding series of Senior Notes may declare all of the Senior Notes of such series to be due and payable immediately.
Recourse Debt [Member] | Senior notes, due 2020
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[1]	8.25%
Recourse Debt [Member] | 7.625% Senior notes, due 2019
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage		7.625%
Recourse Debt [Member] | Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage		6.25%	[1]		6.25%
Recourse Debt [Member] | Senior notes, due 2021
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[1]	7.875%
Recourse Debt [Member] | Senior Notes Due in 2023 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[1]	6.625%
Recourse Debt [Member] | Senior notes, due 2018
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage	[1]	7.625%
Debt Instrument, Redemption, Description		Prior to maturity, NRG may redeem all or a portion of the 2018 Senior Notes at a redemption price equal to 100% of the principal amount of the notes redeemed plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note or (ii) the excess of the present value of the principal amount at maturity plus all required interest payments due on the note through the maturity date discounted at a Treasury rate plus 0.50%.
Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Interest Rate, Stated Percentage		6.25%	[1]	6.25%
Redemption Period After 1 September 2015 [Member] | Senior notes, due 2020
Debt Instrument
Debt Instrument, Redemption Price, Percentage		104.125%
Redemption Period From 15 July 2018 to 14 July 2019 [Member] | Recourse Debt [Member] | Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		103.125%
Redemption Period From 1 May 2019 to 30 April 2020 [Member] | Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		103.125%
Redemption Period From 15 September 2017 to 14 September 2018 [Member] | Senior Notes Due in 2023 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		103.313%
Redemption Period From 15 May 2016 To 14 May 2017 [Member] | Recourse Debt [Member] | Senior notes, due 2021
Debt Instrument
Debt Instrument, Redemption Price, Percentage		103.938%
Redemption Period From 15 May 2017 To 14 May 2018 [Member] | Recourse Debt [Member] | Senior notes, due 2021
Debt Instrument
Debt Instrument, Redemption Price, Percentage		102.625%
Redemption Period From 15 May 2018 To 14 May 2019 [Member] | Recourse Debt [Member] | Senior notes, due 2021
Debt Instrument
Debt Instrument, Redemption Price, Percentage		101.313%
Redemption Period From 15 May 2019 And Thereafter [Member] | Recourse Debt [Member] | Senior notes, due 2021
Debt Instrument
Debt Instrument, Redemption Price, Percentage		100.00%
Redemption Period Beginning With 15 September 2020 [Member] | Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		100.00%
Redemption Period Prior To 15 July 2017 [Member] | Recourse Debt [Member] | Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		At any time prior to July 15, 2017, NRG may redeem up to 35% of the aggregate principal amount of the 2022 Senior Notes, at a redemption price equal to 106.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings.
Redemption Period Prior To 15 July 2018 [Member] | Recourse Debt [Member] | Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		At any time prior to July 15, 2018, NRG may redeem all or a part of the 2022 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.125% of the note, plus interest payments due on the note from the date of redemption through July 15, 2018, computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%.
Redemption Period Prior To 1 May 2017 [Member] | Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		At any time prior to May 1, 2017, NRG may redeem up to 35% of the aggregate principal amount of the 2024 Senior Notes, at a redemption price equal to 106.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an amount equal to the net cash proceeds of certain equity offerings.
Redemption Period Prior To 1 May 2019 [Member] | Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		At any time prior to May 1, 2019, NRG may redeem all or a part of the 2024 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.125% of the note, plus interest payments due on the note from the date of redemption through May 1, 2019 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%.
Redemption Period From 15 September 1018 to 14 September 2019 [Member] | Senior Notes Due in 2023 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		102.208%
Redemption Period From 15 September 2019 to 14 September 2020 [Member] | Senior Notes Due in 2023 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		101.104%
Redemption Period Beginning With 15 September 2020 [Member] | Senior Notes Due in 2023 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		100.00%
Redemption Period From 15 July 2019 to 14 July 2020 [Member] | Recourse Debt [Member] | Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		101.563%
Redemption Period From 15 July 2020 And Thereafter [Member] | Recourse Debt [Member] | Senior Notes Due In 2022 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		100.00%
Redemption Period Prior To 15 May 2016 [Member] | Recourse Debt [Member] | 7.625% Senior notes, due 2019
Debt Instrument
Debt Instrument, Redemption, Description		Prior to May 15, 2016, NRG may redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.875% of the principal amount. Prior to May 15, 2016, NRG may redeem all or a portion of the 2021 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.938% of the note, plus interest payments due on the note from the date of redemption through May 15, 2016, discounted at a Treasury rate plus 0.50%.
Redemption Period Prior to September 15, 2017 [Member] | Recourse Debt [Member] | Senior Notes Due in 2023 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		Prior to September 15, 2017, NRG may redeem all or a portion of the 2023 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.313% of the note, plus interest payments due on the note from the date of redemption through September 15, 2017, discounted at a Treasury rate plus 0.50%.
Redemption Period From 1 May 2020 to 30 April 2021 [Member] | Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		102.083%
Redemption Period From 1 May 2021 to 30 April 2022 [Member] | Recourse Debt [Member] | Senior Notes 2024 [Member]
Debt Instrument
Debt Instrument, Redemption Price, Percentage		101.042%
Redemption Period After 1 September 2016 [Member] | Senior notes, due 2020
Debt Instrument
Debt Instrument, Redemption Price, Percentage		102.75%
Redemption Period After 1 September 2017 [Member] | Senior notes, due 2020
Debt Instrument
Debt Instrument, Redemption Price, Percentage		101.375%
Redemption Period After 1 September 2018 [Member] | Senior notes, due 2020
Debt Instrument
Debt Instrument, Redemption Price, Percentage		100.00%
[1]	As of December 31, 2015, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Marsh Landing term loan, Walnut Creek loan, and Yield Operating LLC Revolving Credit facility, which are 1 month LIBOR plus x%

Debt and Capital Leases Debt 95

Debt and Capital Leases Debt and Capital Leases (NRG Recourse Debt 3 - Sr Cr Facility- TaxExempt Bonds) (Details 4) - USD ($)		Jun. 04, 2013	Jun. 04, 2013	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument
Long-term Debt					$ 19,620,000,000	$ 20,366,000,000
Debt Instrument, Description of Variable Rate Basis					3 month LIBOR
Term Loan Facility | Term loan facility, due 2018
Debt Instrument
Proceeds from Issuance of Senior Long-term Debt		$ 450,000,000
Debt Instrument, Discount on Issuance		0.995	$ 0.995
Debt Instrument, Description of Variable Rate Basis			LIBOR	LIBOR
Debt Instrument, Basis Spread on Variable Rate			2.50%	2.00%
Debt Instrument, Periodic Payment As Percentage Of Original Principal Amount						0.25%
Revolving Credit Facility [Member] | Term loan facility, due 2018
Debt Instrument
Debt Instrument, Description of Variable Rate Basis				LIBOR
Debt Instrument, Basis Spread on Variable Rate				2.25%
Credit Facility, Maximum Borrowing Capacity, Amendment		211,000,000	$ 211,000,000
Line of Credit Facility, Maximum Borrowing Capacity		$ 2,500,000,000	$ 2,500,000,000
Letters of Credit Outstanding, Amount					$ 1,100,000,000
Line of Credit Facility, Remaining Borrowing Capacity					$ 1,400,000,000
Letters of Credit Commitment Fees					0.50%
Recourse Debt [Member]
Debt Instrument
Long-term Debt					$ 8,584,000,000	$ 8,800,000,000
Recourse Debt [Member] | Indian River Power LLC Tax Exempt Bonds Due 2040 [Member]
Debt Instrument
Long-term Debt					$ 57,000,000	57,000,000
Debt Instrument, Interest Rate, Stated Percentage					0.00%
Recourse Debt [Member] | Term loan facility, due 2018
Debt Instrument
Long-term Debt					$ 1,964,000,000	1,983,000,000
Debt Instrument, Description of Variable Rate Basis	[1]				LIBOR
Debt Instrument, Basis Spread on Variable Rate	[1]				2.00%
Recourse Debt [Member] | Indian River Power LLC Tax Exempt Bonds Due 2045 [Member]
Debt Instrument
Long-term Debt					$ 190,000,000	190,000,000
Debt Instrument, Interest Rate, Stated Percentage					0.00%
Recourse Debt [Member] | Dunkirk Power LLC Tax Exempt Bonds Due 2042 [Member]
Debt Instrument
Long-term Debt					$ 59,000,000	59,000,000
Debt Instrument, Interest Rate, Stated Percentage					0.00%
Recourse Debt [Member] | Fort Bend County, tax exempt bonds, due 2045 [Member]
Debt Instrument
Long-term Debt					$ 22,000,000	10,000,000
Debt Instrument, Interest Rate, Stated Percentage					0.00%
Recourse Debt [Member] | Fort Bend County, tax exempt bonds, due 2038 [Member]
Debt Instrument
Long-term Debt					$ 54,000,000	54,000,000
Debt Instrument, Interest Rate, Stated Percentage					0.00%
Recourse Debt [Member] | Fort Bend County, tax exempt bonds, due 2042 [Member]
Debt Instrument
Long-term Debt					$ 73,000,000	36,000,000
Debt Instrument, Interest Rate, Stated Percentage					0.00%
Recourse Debt [Member] | Tax Exempt Bonds
Debt Instrument
Long-term Debt					$ 455,000,000	$ 406,000,000
[1]	As of December 31, 2015, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Marsh Landing term loan, Walnut Creek loan, and Yield Operating LLC Revolving Credit facility, which are 1 month LIBOR plus x%

Debt and Capital Leases (NRG No

Debt and Capital Leases (NRG Non-Recourse Debt 1 - GenOn Sr Notes) (Details 5) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument
Long-term Debt		$ 19,620	$ 20,366
Amount of Restricted Net Assets for Consolidated and Unconsolidated Subsidiaries		5,600
Net gain/(loss) on debt extinguishment		75	(95)	$ (50)
GenOn Senior Notes [Member]
Debt Instrument
Debt Instrument, Principal Amount Repurchased		(119)
Debt Instrument, Repurchase Amount		$ (108)
Redemption Period From October 15, 2015 to October 14, 2016 [Member] | GenOn senior notes, due 2020
Debt Instrument
Debt Instrument, Redemption Price, Percentage		104.938%
Redemption Period Prior To 15 January 2018 [Member] | GenOn senior notes, due 2018
Debt Instrument
Debt Instrument, Redemption, Description		Prior to maturity, GenOn may redeem the senior notes due 2018, in whole or in part, at a redemption price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the following: the present value of 100% of the note, plus interest payments due on the note through maturity, discounted at a Treasury rate plus 0.50% over the principal amount of the note.
Redemption Period From October 15, 2016 to October 14, 2017 [Member] | GenOn senior notes, due 2020
Debt Instrument
Debt Instrument, Redemption Price, Percentage		103.292%
Redemption Period From October 15, 2017 to October 14, 2018 [Member] | GenOn senior notes, due 2020
Debt Instrument
Debt Instrument, Redemption Price, Percentage		101.646%
Redemption Period Beginning with October 15, 2018 [Member] | GenOn senior notes, due 2020
Debt Instrument
Debt Instrument, Redemption Price, Percentage		100.00%
Redemption Period Prior to Maturity [Member] | GenOn Senior Notes Due in 2017 [Member]
Debt Instrument
Debt Instrument, Redemption, Description		Prior to maturity, GenOn may redeem all or a part of the GenOn Senior Notes due 2017 at a redemption price equal to 100% of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the following: the present value of 100% of the note, plus interest payments due on the note through maturity, discounted at a Treasury rate plus 0.50% over the principal amount of the note
GenOn Energy
Debt Instrument
Restricted Payments Limit		$ 250
Other Restricted Assets		277
Non Recourse Debt
Debt Instrument
Long-term Debt		11,036	11,566
Non Recourse Debt | GenOn Senior Notes [Member]
Debt Instrument
Long-term Debt		1,956	2,133
Net gain/(loss) on debt extinguishment		23
Debt Instrument, Principal Amount Repurchased		(119)
Non Recourse Debt | GenOn senior notes, due 2018
Debt Instrument
Long-term Debt		$ 708	757
Debt Instrument, Interest Rate, Stated Percentage	[1]	9.50%
Net gain/(loss) on debt extinguishment		$ 5
Debt Instrument, Principal Amount Repurchased		$ (25)
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed		(90.95%)
Non Recourse Debt | GenOn senior notes, due 2020
Debt Instrument
Long-term Debt		$ 534	610
Debt Instrument, Interest Rate, Stated Percentage	[1]	9.875%
Net gain/(loss) on debt extinguishment		$ 15
Debt Instrument, Principal Amount Repurchased		$ (61)
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed		(83.847%)
Non Recourse Debt | GenOn Senior Notes Due in 2017 [Member]
Debt Instrument
Long-term Debt		$ 714	$ 766
Debt Instrument, Interest Rate, Stated Percentage	[1]	7.875%
Net gain/(loss) on debt extinguishment		$ 3
Debt Instrument, Principal Amount Repurchased		$ (33)
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed		(95.172%)
[1]	As of December 31, 2015, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Marsh Landing term loan, Walnut Creek loan, and Yield Operating LLC Revolving Credit facility, which are 1 month LIBOR plus x%

Debt and Capital Leases Debt 97

Debt and Capital Leases Debt and Capital Leases (NRG Non-Recourse Debt 2 - GAG Sr Notes) (Details 6) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument
Long-term Debt		$ 19,620	$ 20,366
Net gain/(loss) on debt extinguishment		$ 75	(95)	$ (50)
GenOn Americas Generation Senior Notes Due in 2021 [Member] | Redemption Period Prior to Maturity [Member]
Debt Instrument
Debt Instrument, Redemption, Description		Prior to maturity, GenOn Americas Generation may redeem all or a part of the senior notes due 2021 and 2031 at a redemption price equal to 100% of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) the discounted present value of the then-remaining scheduled payments of principal and interest on the outstanding notes, discounted at a Treasury rate plus 0.375%, less the unpaid principal amount; and (ii) zero.
GenOn Americas Generation senior notes
Debt Instrument
Debt Instrument, Principal Amount Repurchased		$ (155)
Debt Instrument, Repurchase Amount		(128)
Non Recourse Debt [Member]
Debt Instrument
Long-term Debt		11,036	11,566
Non Recourse Debt [Member] | GenOn Americas Generation Senior Notes Due in 2021 [Member]
Debt Instrument
Debt Instrument, Principal Amount Repurchased		(84)
Long-term Debt		$ 398	496
Debt Instrument, Interest Rate, Stated Percentage	[1]	8.50%
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed		(84.91%)
Net gain/(loss) on debt extinguishment		$ 20
Non Recourse Debt [Member] | GenOn Americas Generation senior notes, due 2031
Debt Instrument
Debt Instrument, Principal Amount Repurchased		(71)
Long-term Debt		$ 354	433
Debt Instrument, Interest Rate, Stated Percentage	[1]	9.125%
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed		(77.018%)
Net gain/(loss) on debt extinguishment		$ 22
Non Recourse Debt [Member] | GenOn Americas Generation senior notes
Debt Instrument
Debt Instrument, Principal Amount Repurchased		(155)
Long-term Debt		752	$ 929
Net gain/(loss) on debt extinguishment		$ 42
[1]	As of December 31, 2015, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Marsh Landing term loan, Walnut Creek loan, and Yield Operating LLC Revolving Credit facility, which are 1 month LIBOR plus x%

Debt and Capital Leases Debt 98

Debt and Capital Leases Debt and Capital Leases (NRG Non-Recourse Debt 3 - Yield Notes) (Details 7)	Aug. 05, 2014USD ($)	Jun. 30, 2015USD ($)$ / shares	Sep. 30, 2014	Mar. 31, 2014USD ($)$ / shares	Dec. 31, 2015USD ($)
NRG Yield Revolving Credit Facility [Member]
Debt Instrument
Line of Credit Facility, Maximum Borrowing Capacity		$ 450,000,000
Credit Facility, Maximum Borrowing Capacity, Amendment		495,000,000
Line of Credit Facility, Fair Value of Amount Outstanding					$ 306,000,000
3.25% Convertible Notes due 2020 [Member]
Debt Instrument
Debt Instrument, Face Amount		1,000
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt		$ 23,000,000
Debt Instrument, Convertible, Conversion Price | $ / shares		$ 27.50
Debt Instrument, Convertible, Conversion Ratio		36.3636
Debt Instrument, Interest Rate, Stated Percentage		3.25%
Convertible Debt		$ 287,500,000
3.5% Convertible Notes due 2019 [Member]
Debt Instrument
Debt Instrument, Face Amount		$ 1,000		$ 1,000
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt				$ 23,000,000
Debt Instrument, Convertible, Conversion Price | $ / shares				$ 46.55
Debt Instrument, Convertible, Conversion Ratio				21.4822
Debt Instrument, Interest Rate, Stated Percentage				3.50%
Convertible Debt				$ 345,000,000
Letter of Credit [Member] | NRG Yield Revolving Credit Facility [Member]
Debt Instrument
Letters of Credit Outstanding, Amount					$ 56,000,000
NRG Yield, Inc. [Member] | Non Recourse Debt [Member] | 5.375% Senior Notes due in 2024 [Member]
Debt Instrument
Proceeds from Issuance of Senior Long-term Debt	$ 500,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.375%
Adjusted Conversion Ratio [Member] | 3.5% Convertible Notes due 2019 [Member]
Debt Instrument
Debt Instrument, Convertible, Conversion Ratio			42.9644

Debt and Capital Leases (NRG 99

Debt and Capital Leases (NRG Non-Recourse Debt 4 - Project Financings) (Details 8) - USD ($) $ in Millions

Jun. 30, 2015

May. 29, 2015

Aug. 05, 2014

Jun. 30, 2002

Jun. 30, 2015

Sep. 30, 2015

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Jan. 29, 2016

Feb. 21, 2014

Debt Instrument

Long-term Debt

$ 19,620

$ 20,366

Sales proceeds and other contributions from noncontrolling interests in subsidiaries

$ 647

819

$ 531

Fees Incurred for Termination of Interest Rate Swaps

$ 17

Debt Instrument, Description of Variable Rate Basis

3 month LIBOR

Net gain/(loss) on debt extinguishment

$ 75

(95)

(50)

High Lonesome Mesa, LLC, due in 2017 [Member]

Debt Instrument

Long-term Debt

$ 57

West Holdings Credit Agreement due 2023 Tranche A [Member]

Debt Instrument

Proceeds from Issuance of Debt

$ 5

West Holdings Credit Agreement due 2023 Tranche A [Member] | May 29, 2015 to Aug 31, 2017 [Member]

Debt Instrument

Debt Instrument, Basis Spread on Variable Rate

1.625%

West Holdings Credit Agreement Tranche B [Member]

Debt Instrument

Long-term Debt

$ 59

West Holdings Credit Agreement due 2023 Tranche B [Member] | May 29, 2015 to Aug 31, 2017 [Member]

Debt Instrument

Debt Instrument, Basis Spread on Variable Rate

2.25%

El Segundo Energy Center, due 2023

Debt Instrument

Net gain/(loss) on debt extinguishment

$ (7)

West Holdings Credit Agreement Tranche A [Member]

Debt Instrument

Long-term Debt

$ 426

West Holdings PPA [Member]

Debt Instrument

Letters of Credit Outstanding, Amount

33

West Holdings Working Capital Facility [Member]

Debt Instrument

Letters of Credit Outstanding, Amount

1

Support Debt Service Requirements [Member]

Debt Instrument

Letters of Credit Outstanding, Amount

48

Peaker bonds, due 2019

Debt Instrument

Proceeds from Issuance of Debt

$ 325

Debt Instrument, Interest Rate, Stated Percentage

6.67%

Debt Instrument, Repurchased Face Amount

$ 30

Debt Instrument, Repurchase Amount

$ 35

Proceeds from Contributions from Parent

13

29

Long-term Line of Credit

76

Non Recourse Debt [Member]

Debt Instrument

Long-term Debt

11,036

11,566

Non Recourse Debt [Member] | 5.375% Senior Notes due in 2024 [Member]

Debt Instrument

Long-term Debt

500

500

Non Recourse Debt [Member] | Alta Wind I - V Lease financing arrangement [Member]

Debt Instrument

Long-term Debt

1,002

1,036

Non Recourse Debt [Member] | NRG Solar Dandan [Member]

Debt Instrument

Long-term Debt

98

54

Non Recourse Debt [Member] | El Segundo Energy Center, due 2023

Debt Instrument

Long-term Debt

$ 485

506

Debt Instrument, Description of Variable Rate Basis

[1]

LIBOR

Non Recourse Debt [Member] | Peaker bonds, due 2019

Debt Instrument

Long-term Debt

$ 72

$ 100

Debt Instrument, Description of Variable Rate Basis

[1]

LIBOR

Debt Instrument, Basis Spread on Variable Rate

[1]

1.07%

Construction Loans [Member] | NRG Solar Dandan [Member]

Debt Instrument

Long-term Debt

$ 81

$ 81

Letters of Credit Outstanding, Amount

5

Debt Instrument, Interest Rate, Stated Percentage

1.25%

Letters of Credit, Issued Amount

$ 5

Construction Loans [Member] | NRG Solar Dandan [Member] | London Interbank Offered Rate (LIBOR) [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

LIBOR

Debt Instrument, Basis Spread on Variable Rate

2.25%

Debt Instrument, Interest Rate, Increase (Decrease)

0.25%

Term Loan Facility | NRG Solar Dandan [Member]

Debt Instrument

Long-term Debt

$ 79

Letters of Credit, Issued Amount

4

Cash Grant Loan [Member] | NRG Solar Dandan [Member]

Debt Instrument

Long-term Debt

17

$ 23

$ 23

Cash Grant Loan [Member] | NRG Solar Dandan [Member] | London Interbank Offered Rate (LIBOR) [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

Debt Instrument, Basis Spread on Variable Rate

1.75%

Working Capital Facility [Member] | El Segundo Energy Center, due 2023

Debt Instrument

Credit Facility, Maximum Borrowing Capacity, Amendment

$ (9)

Alta X and XI TE Holdco [Member]

Debt Instrument

Sales proceeds and other contributions from noncontrolling interests in subsidiaries

$ 119

NRG Yield, Inc. [Member] | Non Recourse Debt [Member] | 5.375% Senior Notes due in 2024 [Member]

Debt Instrument

Proceeds from Issuance of Senior Long-term Debt

$ 500

Debt Instrument, Interest Rate, Stated Percentage

5.375%

Alta Wind Holdings [Member] | Leasing Arrangement [Member] | Alta Wind I [Member]

Debt Instrument

Long-term Debt

$ 252

Debt Instrument, Interest Rate, Stated Percentage

7.015%

Debt Instrument, Maturity Date

Dec. 30, 2034

Alta Wind Holdings [Member] | Leasing Arrangement [Member] | Alta Wind II [Member]

Debt Instrument

Long-term Debt

$ 198

Debt Instrument, Interest Rate, Stated Percentage

5.6961%

Debt Instrument, Maturity Date

Dec. 30, 2034

Alta Wind Holdings [Member] | Leasing Arrangement [Member] | Alta Wind III [Member]

Debt Instrument

Long-term Debt

$ 206

Debt Instrument, Interest Rate, Stated Percentage

6.067%

Debt Instrument, Maturity Date

Dec. 30, 2034

Alta Wind Holdings [Member] | Leasing Arrangement [Member] | Alta Wind IV [Member]

Debt Instrument

Long-term Debt

$ 133

Debt Instrument, Interest Rate, Stated Percentage

5.938%

Debt Instrument, Maturity Date

Dec. 30, 2034

Alta Wind Holdings [Member] | Leasing Arrangement [Member] | Alta Wind V [Member]

Debt Instrument

Long-term Debt

$ 213

Debt Instrument, Interest Rate, Stated Percentage

6.071%

Debt Instrument, Maturity Date

Jun. 30, 2035

Alta Wind Holdings [Member] | Leasing Arrangement [Member] | Alta Wind I - V Lease financing arrangement [Member]

Debt Instrument

Long-term Debt

$ 1,002

Alta Wind Holdings [Member] | Letter of Credit [Member] | Alta Wind I [Member]

Debt Instrument

Long-term Debt

$ 16

Debt Instrument, Interest Rate, Stated Percentage

3.25%

Debt Instrument, Maturity Date

Jan. 5, 2021

Alta Wind Holdings [Member] | Letter of Credit [Member] | Alta Wind II [Member]

Debt Instrument

Long-term Debt

$ 28

Debt Instrument, Interest Rate, Stated Percentage

2.75%

Alta Wind Holdings [Member] | Letter of Credit [Member] | Alta Wind III [Member]

Debt Instrument

Long-term Debt

$ 28

Debt Instrument, Interest Rate, Stated Percentage

2.75%

Debt Instrument, Maturity Date

Apr. 13, 2018

Alta Wind Holdings [Member] | Letter of Credit [Member] | Alta Wind IV [Member]

Debt Instrument

Long-term Debt

$ 19

Debt Instrument, Interest Rate, Stated Percentage

2.75%

Debt Instrument, Maturity Date

Aug. 24, 2018

Alta Wind Holdings [Member] | Letter of Credit [Member] | Alta Wind V [Member]

Debt Instrument

Long-term Debt

$ 31

Debt Instrument, Interest Rate, Stated Percentage

2.75%

Debt Instrument, Maturity Date

Oct. 24, 2018

Alta Wind Holdings [Member] | Letter of Credit [Member] | Alta Wind I - V Lease financing arrangement [Member]

Debt Instrument

Long-term Debt

$ 122

May 29, 2015 to Aug 31, 2017 [Member] | West Holdings Credit Agreement due 2023 Tranche A [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

May 29, 2015 to Aug 31, 2017 [Member] | West Holdings Credit Agreement due 2023 Tranche B [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

September 1, 2017 to August 31, 2020 [Member] | West Holdings Credit Agreement due 2023 Tranche A [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

Debt Instrument, Basis Spread on Variable Rate

1.75%

September 1, 2017 to August 31, 2020 [Member] | West Holdings Credit Agreement due 2023 Tranche B [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

Debt Instrument, Basis Spread on Variable Rate

2.375%

September 1, 2020 through maturity [Member] | West Holdings Credit Agreement due 2023 Tranche A [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

Debt Instrument, Basis Spread on Variable Rate

1.875%

September 1, 2020 through maturity [Member] | West Holdings Credit Agreement due 2023 Tranche B [Member]

Debt Instrument

Debt Instrument, Description of Variable Rate Basis

LIBOR

Debt Instrument, Basis Spread on Variable Rate

2.50%

Until 5th anniversary of term conversion date [Member] | Construction Loans [Member] | NRG Solar Dandan [Member]

Debt Instrument

Letters Of Credit, Availability Fee, Percentage Of Applicable Margin

0.00%

From 5th anniversary of term conversion date [Member] | Construction Loans [Member] | NRG Solar Dandan [Member]

Debt Instrument

Letters Of Credit, Availability Fee, Percentage Of Applicable Margin

0.00%

[1]

As of December 31, 2015, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Marsh Landing term loan, Walnut Creek loan, and Yield Operating LLC Revolving Credit facility, which are 1 month LIBOR plus x%

Debt and Capital Leases (Intere

Debt and Capital Leases (Interest Rate Swaps) (Details 9) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument
Long-term Debt		$ 19,620,000,000	$ 20,366,000,000
Debt Instrument, Description of Variable Rate Basis		3 month LIBOR
Interest Rate Swap
Debt Instrument
Derivative, Notional Amount		$ 2,326,000,000
EME [Member] | Interest Rate Swap
Debt Instrument
Derivative, Notional Amount		$ 1,053,000,000
NRG Peaker Finance Co. LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		100.00%
Debt Instrument, Description of Variable Rate Basis		3 month LIBOR
Debt instrument, interest rate over variable rate (as a percent)		1.07%
NRG Peaker Finance Co. LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate		6.673%
Derivative, Notional Amount		$ 76,000,000
NRG West Holdings LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		75.00%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
NRG West Holdings LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate		2.417%
Derivative, Notional Amount		$ 358,000,000
NRG Solar Roadrunner LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		75.00%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
NRG Solar Roadrunner LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate		4.313%
Derivative, Notional Amount		$ 30,000,000
NRG Solar Avra Valley LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		85.00%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
NRG Solar Avra Valley LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate		2.333%
Derivative, Notional Amount		$ 51,000,000
Alta Wind Holdings [Member] | Interest Rate Swap
Debt Instrument
Derivative, Notional Amount		$ 19,000,000
Maturity - June 14, 2020 | South Trent Wind LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		75.00%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Maturity - June 14, 2020 | South Trent Wind LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate		3.265%
Derivative, Notional Amount		$ 46,000,000
Maturity - June 14, 2028 | South Trent Wind LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		75.00%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Maturity - June 14, 2028 | South Trent Wind LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate		4.95%
Derivative, Notional Amount		$ 21,000,000
Maturity - December 31, 2029 [Member] | NRG Solar Alpine LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		85.00%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Maturity - December 31, 2029 [Member] | NRG Solar Alpine LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate		2.744%
Derivative, Notional Amount		$ 122,000,000
Maturity - June 30, 2025 [Member] | NRG Solar Alpine LLC
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		85.00%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Maturity - June 30, 2025 [Member] | NRG Solar Alpine LLC | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate		2.421%
Derivative, Notional Amount		$ 9,000,000
Maturity - June 30, 2023 | GenOn Marsh Landing
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		75.00%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Maturity - June 30, 2023 | GenOn Marsh Landing | Interest Rate Swap
Debt Instrument
Derivative, Fixed Interest Rate		3.244%
Derivative, Notional Amount		$ 387,000,000
NRG Other
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		75.00%
NRG Other | Interest Rate Swap
Debt Instrument
Derivative, Notional Amount		$ 154,000,000
Cedro Hill Wind LLC, due in 2025 [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		90.00%
Derivative, Fixed Interest Rate		4.29%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Derivative, Notional Amount		$ 93,000,000
Crofton Bluffs [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		75.00%
Derivative, Fixed Interest Rate		2.748%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Derivative, Notional Amount		$ 21,000,000
Laredo Ridge Wind, LLC, due in 2026 [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		75.00%
Derivative, Fixed Interest Rate		2.31%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Derivative, Notional Amount		$ 83,000,000
Tapestry Wind LLC due in 2021 [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		75.00%
Derivative, Fixed Interest Rate		2.21%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Derivative, Notional Amount		$ 163,000,000
Tapestry Wind LLC due in 2029 [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		50.00%
Derivative, Fixed Interest Rate		3.57%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Derivative, Notional Amount		$ 60,000,000
Viento Funding II, Inc., due in 2023 [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis	6 - month LIBOR	6 month LIBOR
Viento Funding II, Inc., due in 2023 [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		90.00%
Debt Instrument, Description of Variable Rate Basis		6-mo. LIBOR
Derivative, Notional Amount		$ 170,000,000
Viento Funding II, Inc., due in 2028 [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		90.00%
Derivative, Fixed Interest Rate		4.985%
Debt Instrument, Description of Variable Rate Basis		6-mo. LIBOR
Derivative, Notional Amount		$ 65,000,000
High Lonesome Mesa, LLC, due in 2017 [Member]
Debt Instrument
Long-term Debt		$ 57,000,000
Walnut Creek Energy, LLC, due in 2023 [Member]
Debt Instrument
Debt Instrument, Description of Variable Rate Basis	1 - month LIBOR
Walnut Creek Energy, LLC, due in 2023 [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		75.00%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Derivative, Notional Amount		$ 311,000,000
WCEP Holdings, LLC, due in 2023 [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		90.00%
Derivative, Fixed Interest Rate		4.003%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Derivative, Notional Amount		$ 46,000,000
Alta Wind Asset Management [Member] | Alta Wind Holdings [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		100.00%
Derivative, Fixed Interest Rate		2.47%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Derivative, Notional Amount		$ 19,000,000
Broken Bow Wind [Member] | EME [Member] | Interest Rate Swap
Debt Instrument
Percentage of Debt Hedged by Interest Rate Derivatives		75.00%
Derivative, Fixed Interest Rate		2.96%
Debt Instrument, Description of Variable Rate Basis		3-mo. LIBOR
Derivative, Notional Amount		$ 41,000,000
NRG Yield Revolving Credit Facility [Member]
Debt Instrument
Long-term Debt		306,000,000	$ 0
Line of Credit Facility, Cash drawn		$ 0

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at the beginning of the period	$ 763
Asset Retirement Obligation, Revision of Estimate	122
Additions	18
Costs Incurred, Asset Retirement Obligation Incurred for Acquisition	2
Spending for current obligations	(11)
Accretion — Expense	35
Accretion — Nuclear decommissioning	16
Balance at the ending of the period	$ 945

Benefit Plans and Other Post102

Benefit Plans and Other Postretirement Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair value of plan assets for pension and other post retirement benefit
Litigation Settlement, Amount			$ 12
Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Curtailments		$ 0	0
Annual periodic pension cost
Service cost benefits earned		(32)	(30)	$ (30)
Interest cost on benefit obligation		53	53	47
Expected return on plan assets		(62)	(62)	(55)
Amortization of unrecognized net loss/(gain)		2	(6)	9
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments		0	0	(1)
Net periodic benefit cost		25	15	30
Pension and other post retirement benefit obligations
Benefit obligation at January 1	$ 1,196	1,305	1,060
Obligations resulting from the EME acquisition		0	43
Service cost		32	30	30
Interest cost		53	53	47
Plan amendments		0	0
Actuarial (gain)/loss		(120)	174
Employee and retiree contributions		0	0
Benefit payments		74	55
Benefit obligation at December 31		1,196	1,305	1,060
Fair value of plan assets for pension and other post retirement benefit
Fair value of plan assets at January 1	916	988	880
Actual return on plan assets		(26)	85
Employee and retiree contributions		0	0
Employer contributions		28	78
Benefit payments		74	55
Fair value of plan assets at December 31		916	988	880
Funded status at December 31 — excess of obligation over assets		(280)	(317)
Other Postretirement Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		(5)	(17)	0
Defined Benefit Plan, Curtailments		25	0
Annual periodic pension cost
Service cost benefits earned		(3)	(3)	(4)
Interest cost on benefit obligation		9	9	9
Amortization of unrecognized net loss/(gain)		1	0	0
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments		(14)	0	0
Net periodic benefit cost		(6)	(5)	13
Pension and other post retirement benefit obligations
Benefit obligation at January 1	178	238	191
Obligations resulting from the EME acquisition		0	16
Service cost		3	3	4
Interest cost		9	9	9
Plan amendments		(6)	(18)
Actuarial (gain)/loss		(31)	46
Employee and retiree contributions		2	3
Benefit payments		12	12
Benefit obligation at December 31		178	238	191
Fair value of plan assets for pension and other post retirement benefit
Fair value of plan assets at January 1	0	0	0
Actual return on plan assets		0	0
Employee and retiree contributions		2	3
Employer contributions		10	9
Benefit payments		12	12
Fair value of plan assets at December 31		0	0	$ 0
Funded status at December 31 — excess of obligation over assets		$ (178)	$ (238)
Scenario, Plan [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Expected contribution to the Company's pension plans in 2014	$ 33

Benefit Plans and Other Post103

Benefit Plans and Other Postretirement Benefits (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Service Cost	$ 32	$ 30	$ 30
Amounts recognized in balance sheet
Current liabilities	0	0
Non-current liabilities	280	317
Amounts recognized in accumulated OCI
Net loss/(gain)	68	101
Prior service cost/(credit)	3	4
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Net actuarial (gain)/loss	(31)	152
Amortization of net actuarial (gain)/loss	(2)	6	(9)
Prior service (credit)/cost	(1)	0
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	0	0
Defined Benefit Plan, Curtailments	0	0
Defined Benefit Plan, Curtailment Recognized in OCI	0	0
Total recognized in other comprehensive loss	34	(158)
Total recognized in net periodic pension (credit)/cost and other comprehensive (income)/loss	(8)	173
Estimated unrecognized loss for NRG's pension plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year	2
Significant components of NRG's domestic pension plan
Projected benefit obligation	1,196	1,305	1,060
Accumulated benefit obligation	1,115	1,172
Fair value of plan assets	916	988	880
Interest cost on benefit obligation	53	53	47
Defined Benefit Plan, Expected Return on Plan Assets	62	62	55
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	0	0	1
Defined Benefit Plan, Net Periodic Benefit Cost	25	15	30
Other Postretirement Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Service Cost	3	3	4
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(5)	(17)	0
Amounts recognized in balance sheet
Current liabilities	12	10
Non-current liabilities	166	228
Amounts recognized in accumulated OCI
Net loss/(gain)	(9)	34
Prior service cost/(credit)	(9)	(7)
Other changes in plan assets and benefit obligations recognized in other comprehensive income
Net actuarial (gain)/loss	(31)	46
Amortization of net actuarial (gain)/loss	(1)	0	0
Prior service (credit)/cost	(7)	(18)
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	5	17
Defined Benefit Plan, Curtailments	25	0
Defined Benefit Plan, Curtailment Recognized in OCI	(11)	0
Total recognized in other comprehensive loss	45	(45)
Total recognized in net periodic pension (credit)/cost and other comprehensive (income)/loss	(37)	40
Significant components of NRG's domestic pension plan
Projected benefit obligation	178	238	191
Fair value of plan assets	0	0	0
Defined Benefit Plan, Future Amortization of Gain (Loss)	1
Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit)	2
Interest cost on benefit obligation	9	9	9
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	14	0	0
Defined Benefit Plan, Net Periodic Benefit Cost	$ (6)	$ (5)	$ 13

Benefit Plans and Other Post104

Benefit Plans and Other Postretirement Benefits (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Benefit Obligation	$ 1,196	$ 1,305	$ 1,060
Fair values of the Company's pension plan assets	916	988	880
Defined Benefit Plan, Business Combinations and Acquisitions, Benefit Obligation	0	43
Defined Benefit Plan, Service Cost	32	30	30
Interest cost on benefit obligation	53	53	47
Defined Benefit Plan, Plan Amendments	0	0
Defined Benefit Plan, Actuarial Gain (Loss)	(120)	174
Defined Benefit Plan, Contributions by Plan Participants	0	0
Defined Benefit Plan, Contributions by Employer	28	78
Defined Benefit Plan, Benefits Paid	(74)	(55)
Defined Benefit Plan, Curtailments	0	0
Defined Benefit Plan, Actual Return on Plan Assets	(26)	85
Defined Benefit Plan, Funded Status of Plan	(280)	(317)
Pension Benefits | Level 1
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	6	4
Pension Benefits | Level 2
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	910	984
Pension Benefits | Common/collective trust investment — U.S. equity
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	255	287
Pension Benefits | Common/collective trust investment — U.S. equity | Level 1
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	0	0
Pension Benefits | Common/collective trust investment — U.S. equity | Level 2
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	255	287
Pension Benefits | Common/collective trust investment — non-U.S. equity
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	147	149
Pension Benefits | Common/collective trust investment — non-U.S. equity | Level 1
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	0	0
Pension Benefits | Common/collective trust investment — non-U.S. equity | Level 2
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	147	149
Pension Benefits | Common Trust Investment Global Equity [Member]
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	90	96
Pension Benefits | Common Trust Investment Global Equity [Member] | Level 1
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	0	0
Pension Benefits | Common Trust Investment Global Equity [Member] | Level 2
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	90	96
Pension Benefits | Common/collective trust investment — fixed income
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	400	431
Pension Benefits | Common/collective trust investment — fixed income | Level 1
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	0	0
Pension Benefits | Common/collective trust investment — fixed income | Level 2
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	400	431
Pension Benefits | Partnership [Member]
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	18	21
Pension Benefits | Partnership [Member] | Level 1
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	0	0
Pension Benefits | Partnership [Member] | Level 2
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	18	21
Pension Benefits | Short-term investment fund
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	6	4
Pension Benefits | Short-term investment fund | Level 1
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	6	4
Pension Benefits | Short-term investment fund | Level 2
Benefit Plans and Other Postretirement Benefits
Fair values of the Company's pension plan assets	0	0
Other Postretirement Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Benefit Obligation	178	238	191
Fair values of the Company's pension plan assets	0	0	0
Defined Benefit Plan, Business Combinations and Acquisitions, Benefit Obligation	0	16
Defined Benefit Plan, Service Cost	3	3	4
Interest cost on benefit obligation	9	9	$ 9
Defined Benefit Plan, Plan Amendments	(6)	(18)
Defined Benefit Plan, Actuarial Gain (Loss)	(31)	46
Defined Benefit Plan, Contributions by Plan Participants	2	3
Defined Benefit Plan, Contributions by Employer	10	9
Defined Benefit Plan, Benefits Paid	(12)	(12)
Defined Benefit Plan, Curtailments	(25)	0
Defined Benefit Plan, Actual Return on Plan Assets	0	0
Defined Benefit Plan, Funded Status of Plan	$ (178)	$ (238)

Benefit Plans and Other Post105

Benefit Plans and Other Postretirement Benefits (Details 4)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Minimum [Member]
Significant assumptions used to calculate NRG's benefit expense
Aon Hewitt above median yield curve discount rate (in years)	6 months
Maximum [Member]
Significant assumptions used to calculate NRG's benefit expense
Aon Hewitt above median yield curve discount rate (in years)	99 years
Pension Benefits
Significant assumptions used to calculate NRG's benefit obligations
Discount rate	4.52%	4.16%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	3.00%	3.45%
Significant assumptions used to calculate NRG's benefit expense
Discount rate	4.16%	4.99%	4.16%
Expected return on plan assets	6.36%	6.81%	7.12%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.45%	3.65%	3.57%
Other Postretirement Benefits
Significant assumptions used to calculate NRG's benefit obligations
Discount rate	4.55%	4.20%
Significant assumptions used to calculate NRG's benefit expense
Discount rate	4.20%	5.06%	4.31%
Expected return on plan assets	0.00%	0.00%	0.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	0.00%	0.00%	0.00%
Common/collective trust investment — U.S. equity | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Target Plan Asset Allocations	27.00%
Common/collective trust investment — non-U.S. equity | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Target Plan Asset Allocations	15.00%
Common Trust Investment Global Equity [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Target Plan Asset Allocations	10.00%
Emerging Market Equities [Member] | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Target Plan Asset Allocations	3.00%
Common/collective trust investment — fixed income | Pension Benefits
Benefit Plans and Other Postretirement Benefits
Defined Benefit Plan, Target Plan Asset Allocations	45.00%
Net Period Benefit Cost/Credit [Member] | Other Postretirement Benefits
Target allocations
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate	2,023	2,019	2,019
Postretirement Benefit Obligation [Member] | Other Postretirement Benefits
Target allocations
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate	2,025	2,023
Before age 65 [Member] | Net Period Benefit Cost/Credit [Member] | Other Postretirement Benefits
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	8.60%	8.50%	8.30%
Before age 65 [Member] | Postretirement Benefit Obligation [Member] | Other Postretirement Benefits
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	7.25%	8.60%
Age 65 and after [Member] | Net Period Benefit Cost/Credit [Member] | Other Postretirement Benefits
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	5.00%	5.50%	5.30%
Age 65 and after [Member] | Postretirement Benefit Obligation [Member] | Other Postretirement Benefits
Significant assumptions used to calculate NRG's benefit expense
Health care trend rate	5.00%	5.00%

Benefit Plans and Other Post106

Benefit Plans and Other Postretirement Benefits (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
One-percentage-point change in assumed health care cost trend rates
Effect on total service and interest cost components, 1-Percentage-Point Increase	$ 1
Effect on total service and interest cost components, 1-Percentage-Point Decrease	1
Effect on postretirement benefit obligation, 1-Percentage-Point Increase	13
Effect on postretirement benefit obligation, 1-Percentage-Point Decrease	11
Company's contributions to 401(k) plans
Company contributions to defined contribution plans	$ 53	$ 47	$ 34
South Texas Project
STP Defined Benefit Plans
Ownership interest in STP (as a percent)	44.00%
Percentage of contribution to the retirement plan obligation reimbursed	44.00%
Amount reimbursed to STPNOC towards defined benefit plans	$ 9	14
Expected reimbursement of contribution to retirement plan obligations to STPNOC in 2014	7
Pension Benefits
NRG's expected future benefit payments
Expected future benefit payments, 2014	60
Expected future benefit payments, 2015	64
Expected future benefit payments, 2016	67
Expected future benefit payments, 2017	71
Expected future benefit payments, 2018	75
Expected future benefit payments, 2019-2023	409
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(280)	(317)
Net periodic benefit costs	25	15	30
Total recognized in other comprehensive loss	34	(158)
Pension Benefits | South Texas Project
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(63)	(71)
Net periodic benefit costs	10	6
Total recognized in other comprehensive loss	(8)	37
Other Postretirement Benefits
NRG's expected future benefit payments
Expected future benefit payments, 2014	12
Expected future benefit payments, 2015	9
Expected future benefit payments, 2016	10
Expected future benefit payments, 2017	10
Expected future benefit payments, 2018	10
Expected future benefit payments, 2019-2023	52
Medicare prescription drug reimbursements
Expected Medicare prescription drug reimbursements, 2014	0
Expected Medicare prescription drug reimbursements, 2015	0
Expected Medicare prescription drug reimbursements, 2016	0
Expected Medicare prescription drug reimbursements, 2017	0
Expected Medicare prescription drug reimbursements, 2018	0
Expected Medicare prescription drug reimbursements, 2019-2023	1
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(178)	(238)
Net periodic benefit costs	(6)	(5)	$ 13
Total recognized in other comprehensive loss	45	(45)
Other Postretirement Benefits | South Texas Project
Recognized amount in statement of financial position, statement of operations and accumulated OCI related to STP
Funded status — STPNOC benefit plans	(26)	(30)
Net periodic benefit costs	(8)	3
Total recognized in other comprehensive loss	$ 6	$ (29)

Capital Structure (Rollforward

Capital Structure (Rollforward - Details 1) - shares	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Capital Structure
Preferred stock, shares authorized		10,000,000	10,000,000	10,000,000	10,000,000
Common stock, shares authorized		500,000,000	500,000,000	500,000,000	500,000,000
3.625% convertible perpetual preferred stock, shares issued		250,000	250,000	250,000	250,000
3.625% convertible perpetual preferred stock, shares outstanding		250,000	250,000	250,000	250,000
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, common shares issued		415,506,176
Beginning balance, treasury shares		(78,843,552)
Beginning balance, common shares outstanding		336,662,624
Ending balance, common shares issued		416,939,950	415,506,176
Ending balance, treasury shares		(102,749,908)	(78,843,552)
Ending balance, common shares outstanding		314,190,042	336,662,624
Common Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, common shares issued	399,112,616	415,506,176	401,126,780
Beginning balance, common shares outstanding	322,606,898	336,662,624	323,779,252
Shares issued under ESPP	130,482	283,139	128,336
Shares issued from LTIP	2,014,164	1,433,774	1,707,419
Stock Repurchased During Period, Shares	972,292	24,189,495	1,624,360
Ending balance, common shares issued		416,939,950	415,506,176
Ending balance, common shares outstanding		314,190,042	336,662,624
Treasury Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Beginning balance, treasury shares	76,505,718	78,843,552	77,347,528
Shares issued under ESPP	130,482	283,139	128,336
Shares issued from LTIP		0	0
Stock Repurchased During Period, Shares	972,292	24,189,495	1,624,360
Ending balance, treasury shares		102,749,908	78,843,552
EME [Member]
Increase (Decrease) in Stockholders' Equity (in shares)
Stock Issued through GenOn acquisition			12,671,977
EME [Member] | Common Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Stock Issued through GenOn acquisition			12,671,977
EME [Member] | Treasury Stock
Increase (Decrease) in Stockholders' Equity (in shares)
Stock Issued through GenOn acquisition			0

Capital Structure (Common Stock

Capital Structure (Common Stock - Details 2) - USD ($) $ / shares in Units, $ in Millions		Aug. 15, 2012	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Sep. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Common Stock, Capital Shares Reserved for Future Issuance				33,979,967													33,979,967			33,979,967
Common Stock, Dividends, Per Share, Cash Paid		$ 0.12		$ 0.00145	$ 0.00145	$ 0.00145	$ 0.00145	$ 0.00140	$ 0.00140	$ 0.00140	$ 0.00120	$ 0.00120	$ 0.00120	$ 0.00120	$ 0.00090
Dividends Per Common Share																	$ 0.58	$ 0.54	$ 0.45
Common Stock, Dividends, Proposed Annual Percentage Increase				4.00%				17.00%									4.00%	17.00%		4.00%
Eligible compensation (as a percent)																	10.00%
Exercise price as a percentage of fair value (as a percent)																	85.00%
Treasury stock reserved for issuance under the ESPP (in shares)				1,276,913													1,276,913			1,276,913
Commissions per Share																				$ 0.015
Common Stock
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Common stock issued to employee from treasury stock (in shares)																130,482	283,139	128,336
Stock Repurchased During Period, Shares																(972,292)	(24,189,495)	(1,624,360)
Scenario, Plan [Member]
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Dividends Per Common Share																	$ 0.0058	$ 0.56	$ 0.48
Subsequent Event [Member]
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Dividends Payable, Date Declared				Jan. 18, 2016
Dividends Per Common Share				$ 0.00145
Dividends Payable, Date to be Paid				Feb. 16, 2016
Subsequent Event [Member] | Common Stock
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Common stock issued to employee from treasury stock (in shares)			299,127
Subsequent Event [Member] | Scenario, Plan [Member]
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Common Stock, Dividends, Proposed Annual Amount, Per Share																	$ 0.0058
Preferred Stock
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Common Stock, Capital Shares Reserved for Future Issuance				16,000,000													16,000,000			16,000,000
Long-term incentive plans
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Common Stock, Capital Shares Reserved for Future Issuance				17,979,967													17,979,967			17,979,967
Capital Allocation Plan [Member]
Employee Stock Purchase Plan and 2013 Capital Allocation Plan
Stock Repurchase Program, Authorized Amount					$ 481
Stock Repurchased During Period, Shares				5,558,920	11,104,184	4,379,907	3,146,484	1,624,360												25,813,855
Treasury Stock Acquired, Average Cost Per Share	[1]			$ 15.03	$ 15.06	$ 24.53	$ 25.15	$ 26.95
Stock Repurchased During Period, Value				$ 84	$ 167	$ 107	$ 79	$ 44												$ 481
[1]	The average price paid per share and amounts paid for shares purchased exclude the commissions of $0.015 per share paid in connection with the share repurchase.

Capital Structure (Preferred St

Capital Structure (Preferred Stock - Details 3) - USD ($)	2 Months Ended	12 Months Ended
	Feb. 23, 2020	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 23, 2014	Dec. 31, 2012	Aug. 11, 2005
Capital Structure
2.822% convertible perpetual preferred stock; $0.01 par value; 250,000 shares issued and outstanding		$ 302,000,000	$ 291,000,000	$ 249,000,000
Preferred Stock, Accretion of Redemption Discount		$ 11,000,000
Temporary Equity, Shares Authorized		10,000,000	10,000,000	10,000,000		10,000,000
Loss on Extinguishment of Preferred Stock			$ 42,000,000
Consent Fees Paid, Preferred Stock		$ 0	$ 5,000,000	$ 0
Redeemable Preferred Stock, Fair Value					$ 291,000,000
Common stock, shares authorized		500,000,000	500,000,000	500,000,000		500,000,000
3.625% convertible perpetual preferred stock, shares issued		250,000	250,000	250,000		250,000
3.625% convertible perpetual preferred stock, shares outstanding		250,000	250,000	250,000		250,000
Preferred Stock Instrument, Interest Rate, Stated Percentage		282.20%			362.50%
Convertible Preferred Stock [Member]
Capital Structure
Preferred Stock, Shares Issued							250,000
Preferred Stock, Dividend Rate, Percentage				3.625%
Preferred Stock, Dividend Rate Amended, Percentage		2.822%	2.822%
Liquidation preference (in dollars per share)		$ 1,378
Dividends on preferred stock per share per year		$ 28.22
Convertible perpetual preferred stock, terms of conversion		Holders tendering the 2.822% Preferred Stock for conversion shall be entitled to receive, for each share of 2.822% Preferred Stock converted, $1,378 in cash and a number of shares of NRG common stock equal in value to the product of (a) the greater of (i) the difference between the average closing share price of NRG common stock on each of the twenty consecutive scheduled trading days starting on the date thirty exchange business days immediately prior to the conversion date, or the Market Price, and $40.71 and (ii) zero, times (b) 50.7743. The number of shares of NRG common stock to be delivered under the conversion feature is limited to 16,000,000 shares. If upon conversion, the Market Price is less than $27.14, then the Holder will deliver to NRG cash or a number of shares of NRG common stock equal in value to the product of (i) $27.14 minus the Market Price, times (ii) 50.7743.
Redemption price as a percentage of liquidation preference (as a percent)		100.00%
Convertible Preferred Stock [Member] | Forecast
Capital Structure
Preferred stock, conversion period (in days)	90 days

Investments Accounted for by110

Investments Accounted for by the Equity Method and Variable Interest Entities (Details)		Jul. 07, 2014USD ($)	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)	Sep. 30, 2014MW	Jul. 03, 2014	Dec. 31, 2009MW
Investments Accounted for by the Equity Method
Power Generation Capacity, Megawatts | MW	[1]		49,287
Economic interest in equity method investments (as a percent)			50.00%
Equity investments in affiliates			$ 1,045,000,000	$ 771,000,000
Undistributed earnings by equity investment			$ 55,000,000	$ 76,000,000
GenConn Energy LLC (a)
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)			50.00%
Equity investments in affiliates			$ 110,000,000
Petra Nova Parish Holdings [Member]
Investments Accounted for by the Equity Method
Power Generation Capacity, Megawatts | MW					75
Sherbino I Wind Farm LLC
Investments Accounted for by the Equity Method
Power Generation Capacity, Megawatts | MW							150
Economic interest in equity method investments (as a percent)							50.00%
Equity investments in affiliates			$ 80,000,000
Gladstone Power Station (b)
Investments Accounted for by the Equity Method
Power Generation Capacity, Megawatts | MW			1,613
Economic interest in equity method investments (as a percent)			37.50%
Equity investments in affiliates			$ 149,000,000
United States | Avenal Solar Holdings LLC (a)
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	[2]		50.00%
Equity investments in affiliates	[2]		$ (9,000,000)
United States | Community Wind North, LLC [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)			99.00%
Equity investments in affiliates			$ 57,000,000
United States | Desert Sunlight [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	[2]		25.00%
Equity investments in affiliates	[2]		$ 291,000,000
United States | Elkhorn Ridge Wind, LLC [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	[2]		66.70%
Equity investments in affiliates	[2]		$ 96,000,000
United States | GenConn Energy LLC (a)
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	[2]		50.00%
Equity investments in affiliates	[2]		$ 110,000,000
United States | Midway-Sunset Cogeneration Company [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)			50.00%
Equity investments in affiliates			$ 25,000,000
United States | Petra Nova Parish Holdings [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)			50.00%
Equity investments in affiliates			$ 136,000,000
United States | Saguaro Power Company
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)			50.00%
Equity investments in affiliates			$ (20,000,000)
United States | San Juan Mesa Wind Project, LLC [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	[2]		75.00%
Equity investments in affiliates	[2]		$ 80,000,000
United States | Sherbino I Wind Farm LLC
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)			50.00%
Equity investments in affiliates			$ 80,000,000
United States | Watson Cogeneration Company [Member]
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)			49.00%
Equity investments in affiliates			$ 36,000,000
United States | Various [Member]
Investments Accounted for by the Equity Method
Equity investments in affiliates			$ 14,000,000
Australia | Gladstone Power Station (b)
Investments Accounted for by the Equity Method
Economic interest in equity method investments (as a percent)	[3]		37.50%
Equity investments in affiliates	[3]		$ 149,000,000
Petra Nova Parish Holdings [Member]
Investments Accounted for by the Equity Method
Percentage of Ownership					50.00%
Percentage of Ownership Sold of Subsidiary						50.00%
Capital Contribution to Equity Method Investment		$ 35,000,000
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		$ 76,000,000
[1]	Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.
[2]	Equity method investments owned by NRG Yield
[3]	Gladstone Power Station is located in Australia

Investments Accounted for by111

Investments Accounted for by the Equity Method and Variable Interest Entities Investments Accounted for by the Equity Method and Variable Interest Entities (VIEs - Details 2) $ in Millions		1 Months Ended
		Apr. 30, 2009	Dec. 31, 2008	Dec. 31, 2015USD ($)MWfacility	Dec. 31, 2014USD ($)	Sep. 17, 2013USD ($)	Dec. 31, 2009MW
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
Equity investments in affiliates				$ 1,045	$ 771
Long-term Debt				19,620	20,366
Working Capital Facility, Amount Drawn				$ 14
Power Generation Capacity, Megawatts | MW	[1]			49,287
GenConn Energy LLC (a)
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
Number of Peaking Facilities to be Constructed | facility				2
Power Generation Capacity of Peaking Facility to be Constructed | MW				190
Equity investments in affiliates				$ 110
Sherbino I Wind Farm LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage							50.00%
Equity investments in affiliates				80
Power Generation Capacity, Megawatts | MW							150
GenConn Working Capital Facility [Member] | GenConn Energy LLC (a)
Schedule of Equity Method Investments [Line Items]
Length of Revolving Working Capital, Loan and Letter of Credit Facility		5 years
Non Recourse Debt [Member]
Schedule of Equity Method Investments [Line Items]
Long-term Debt				11,036	$ 11,566
Non Recourse Debt [Member] | GenConn Facility [Member] | GenConn Energy LLC (a)
Schedule of Equity Method Investments [Line Items]
Long-term Debt				220		$ 237
Debt Instrument, Interest Rate, Stated Percentage						4.73%
Non Recourse Debt [Member] | GenConn Working Capital Facility [Member] | GenConn Energy LLC (a)
Schedule of Equity Method Investments [Line Items]
Long-term Debt						$ 35
Debt Instrument, Interest Rate, Stated Percentage						1.875%
Non Recourse Debt [Member] | Sherbino I Wind Farm LLC Term Loan Facility [Member] | Sherbino I Wind Farm LLC
Schedule of Equity Method Investments [Line Items]
Length of Term Loan Facility			15 years
Long-term Line of Credit				$ 87
[1]	Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.

Investments Accounted for by112

Investments Accounted for by the Equity Method and Variable Interest Entities Investments Accounted for by the Equity Method and Variable Interest Entities (Other Equity Inv - Details 3) $ in Millions		3 Months Ended	12 Months Ended
		Dec. 31, 2013USD ($)	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Power Generation Capacity, Megawatts | MW	[1]		49,287
Impairment losses			$ 5,030	$ 97	$ 459
Equity investments in affiliates			1,045	$ 771
Equity Method Investment, Summarized Financial Information, Current Assets			84
Equity Method Investments, Summarized Financial Data, Property, Plant and Equipment			1,807
Equity Method Investments, Summarized Financial Information, Other long-term assets			863
Equity Method Investment, Summarized Financial Information, Assets			2,754
Equity Method Investment, Summarized Financial Information, Current Liabilities			56
Equity Method Investments, Summarized Financial Information, Long Term Debt			366
Equity Method Investments, Summarized Financial Information, Other long-term liabilities			179
Equity Method Investment, Summarized Financial Information, Liabilities			601
Equity Method Investment, Summarized Financial Information, Noncontrolling Interest			493
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net			$ 1,660
Gladstone Power Station (b)
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			37.50%
Power Generation Capacity, Megawatts | MW			1,613
Impairment losses		$ 92
Equity investments in affiliates			$ 149
[1]	Includes 90 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.

Segment Reporting (Details)

Segment Reporting (Details)	3 Months Ended										12 Months Ended
	Dec. 31, 2015USD ($)		Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)		Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)customer		Dec. 31, 2014USD ($)customer		Dec. 31, 2013USD ($)customer		Nov. 02, 2015USD ($)
Income Statement
Operating revenues	$ 3,011,000,000		$ 4,434,000,000	$ 3,400,000,000	$ 3,829,000,000	$ 4,192,000,000		$ 4,569,000,000	$ 3,621,000,000	$ 3,486,000,000	$ 14,674,000,000	[1]	$ 15,868,000,000	[2]	$ 11,295,000,000	[3]
Operating expenses											11,975,000,000		12,821,000,000		9,025,000,000
Depreciation and amortization											1,566,000,000		1,523,000,000		1,256,000,000
Impairment of Long-Lived Assets Held-for-use											5,030,000,000		97,000,000		459,000,000
Acquisition-related transaction and integration costs											10,000,000		84,000,000		128,000,000
Research and Development Expense											154,000,000		91,000,000		84,000,000
Costs and Expenses											18,735,000,000		14,616,000,000		10,952,000,000
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											21,000,000		19,000,000		0
Operating Income (Loss)	(4,727,000,000)		379,000,000	232,000,000	76,000,000	453,000,000		549,000,000	89,000,000	180,000,000	(4,040,000,000)		1,271,000,000		343,000,000
Equity in earnings/(losses) of unconsolidated affiliates											36,000,000		38,000,000		7,000,000
Impairment losses on investments											(56,000,000)		0		(99,000,000)
Other income, net											33,000,000		22,000,000		13,000,000
(Loss)/gain on sale of equity-method investment											(14,000,000)		18,000,000		0
Net gain/(loss) on debt extinguishment											75,000,000		(95,000,000)		(50,000,000)
Interest expense											(1,128,000,000)		(1,119,000,000)		(848,000,000)
Income/(loss) before income taxes											(5,094,000,000)		135,000,000		(634,000,000)
Income tax expense/(benefit)											1,342,000,000		3,000,000		(282,000,000)
Net (Loss)/Income	(6,358,000,000)		67,000,000	(9,000,000)	(136,000,000)	97,000,000		182,000,000	(80,000,000)	(67,000,000)	(6,436,000,000)		132,000,000		(352,000,000)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	(44,000,000)		1,000,000	5,000,000	(16,000,000)	(22,000,000)		14,000,000	17,000,000	(11,000,000)	(54,000,000)		(2,000,000)		34,000,000
Net (loss)/income attributable to NRG Energy, Inc.	(6,314,000,000)		$ 66,000,000	$ (14,000,000)	$ (120,000,000)	119,000,000		$ 168,000,000	$ (97,000,000)	$ (56,000,000)	(6,382,000,000)		134,000,000		(386,000,000)
Operating revenues include inter-segment sales and net derivative gains and losses of:											1,218,000,000		1,949,000,000		2,308,000,000
Balance sheet
Equity investments in affiliates	1,045,000,000					771,000,000					1,045,000,000		771,000,000
Capital expenditures	1,267,000,000	[4]				984,000,000	[5]				1,267,000,000	[4]	984,000,000	[5]
Goodwill	999,000,000					2,574,000,000					999,000,000		2,574,000,000
Total assets	32,882,000,000					40,466,000,000					32,882,000,000		40,466,000,000
Retail
Income Statement
Operating revenues											9,142,000,000	[1]	11,024,000,000	[2]	8,638,000,000	[3]
Operating expenses											7,811,000,000		8,894,000,000		7,235,000,000
Depreciation and amortization											907,000,000		966,000,000		930,000,000
Impairment of Long-Lived Assets Held-for-use											4,827,000,000		87,000,000		459,000,000
Acquisition-related transaction and integration costs											0		1,000,000		0
Research and Development Expense											24,000,000		13,000,000		14,000,000
Costs and Expenses											13,569,000,000		9,961,000,000		8,638,000,000
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											21,000,000		19,000,000
Operating Income (Loss)											(4,406,000,000)		1,082,000,000		0
Equity in earnings/(losses) of unconsolidated affiliates											7,000,000		23,000,000		(6,000,000)
Impairment losses on investments											14,000,000				0
Other income, net											40,000,000		35,000,000		32,000,000
(Loss)/gain on sale of equity-method investment											0		18,000,000
Net gain/(loss) on debt extinguishment											0		0		0
Interest expense											98,000,000		95,000,000		107,000,000
Income/(loss) before income taxes											(4,471,000,000)		1,063,000,000		(81,000,000)
Income tax expense/(benefit)											1,000,000		1,000,000		0
Net (Loss)/Income											(4,472,000,000)		1,062,000,000		(81,000,000)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests											0		(1,000,000)		0
Net (loss)/income attributable to NRG Energy, Inc.											(4,472,000,000)		1,063,000,000		(81,000,000)
Operating revenues include inter-segment sales and net derivative gains and losses of:											947,000,000		1,820,000,000		2,055,000,000
Balance sheet
Equity investments in affiliates	185,000,000					141,000,000					185,000,000		141,000,000
Capital expenditures	798,000,000	[4]				611,000,000	[5]				798,000,000	[4]	611,000,000	[5]
Goodwill	536,000,000					1,746,000,000					536,000,000		1,746,000,000
Total assets	$ 17,139,000,000					28,317,000,000					17,139,000,000		28,317,000,000
NRG Home Retail [Member]
Income Statement
Operating revenues											5,389,000,000	[1]	5,503,000,000	[2]	4,341,000,000	[3]
Operating expenses											4,577,000,000		5,240,000,000		3,814,000,000
Depreciation and amortization											123,000,000		122,000,000		141,000,000
Impairment of Long-Lived Assets Held-for-use											36,000,000		0		0
Acquisition-related transaction and integration costs											1,000,000		3,000,000		0
Research and Development Expense											0		0		0
Costs and Expenses											4,737,000,000		5,365,000,000		3,955,000,000
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											0		0
Operating Income (Loss)											652,000,000		138,000,000		386,000,000
Equity in earnings/(losses) of unconsolidated affiliates											0		0		0
Impairment losses on investments											0				0
Other income, net											0		0		0
(Loss)/gain on sale of equity-method investment											0		0
Net gain/(loss) on debt extinguishment											0		0		0
Interest expense											0		1,000,000		2,000,000
Income/(loss) before income taxes											652,000,000		137,000,000		384,000,000
Income tax expense/(benefit)											0		0		0
Net (Loss)/Income											652,000,000		137,000,000		384,000,000
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests											0		0		0
Net (loss)/income attributable to NRG Energy, Inc.											652,000,000		137,000,000		384,000,000
Operating revenues include inter-segment sales and net derivative gains and losses of:											$ 6,000,000		7,000,000		5,000,000
Balance sheet
Equity investments in affiliates						0							0
Capital expenditures	$ 30,000,000	[4]				34,000,000	[5]				$ 30,000,000	[4]	34,000,000	[5]
Goodwill	340,000,000					387,000,000					340,000,000		387,000,000
Total assets	1,876,000,000					6,049,000,000					1,876,000,000		6,049,000,000
Home Solar [Member]
Income Statement
Operating revenues											32,000,000	[1]	42,000,000	[2]	4,000,000	[3]
Operating expenses											204,000,000		108,000,000		0
Depreciation and amortization											25,000,000		6,000,000		4,000,000
Impairment of Long-Lived Assets Held-for-use											132,000,000		0		0
Acquisition-related transaction and integration costs											(8,000,000)		0		0
Research and Development Expense											0		0		9,000,000
Costs and Expenses											353,000,000		114,000,000		13,000,000
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											0		0
Operating Income (Loss)											(321,000,000)		(72,000,000)		(9,000,000)
Equity in earnings/(losses) of unconsolidated affiliates											0		0		0
Impairment losses on investments											0				0
Other income, net											0		0		0
(Loss)/gain on sale of equity-method investment											0		0
Net gain/(loss) on debt extinguishment											0		0		0
Interest expense											3,000,000		1,000,000		0
Income/(loss) before income taxes											(324,000,000)		(73,000,000)		(9,000,000)
Income tax expense/(benefit)											0		0		0
Net (Loss)/Income											(324,000,000)		(73,000,000)		(9,000,000)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests											(20,000,000)		(19,000,000)		0
Net (loss)/income attributable to NRG Energy, Inc.											(304,000,000)		(54,000,000)		(9,000,000)
Operating revenues include inter-segment sales and net derivative gains and losses of:											1,000,000		0		0
Balance sheet
Equity investments in affiliates	0					0					0		0
Capital expenditures	144,000,000	[4]				113,000,000	[5]				144,000,000	[4]	113,000,000	[5]
Goodwill	0					98,000,000					0		98,000,000
Total assets	413,000,000					222,000,000					413,000,000		222,000,000
NRG Renew [Member]
Income Statement
Operating revenues											474,000,000	[1]	427,000,000	[2],[6]	214,000,000	[3]
Operating expenses											218,000,000		183,000,000	[6]	77,000,000
Depreciation and amortization											212,000,000		195,000,000	[6]	86,000,000
Impairment of Long-Lived Assets Held-for-use											13,000,000		32,000,000	[6]	0
Acquisition-related transaction and integration costs											0		0	[6]	0
Research and Development Expense											70,000,000		42,000,000	[6]	34,000,000
Costs and Expenses											513,000,000		452,000,000	[6]	197,000,000
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											0		0	[6]
Operating Income (Loss)											(39,000,000)		(25,000,000)	[6]	17,000,000
Equity in earnings/(losses) of unconsolidated affiliates											$ 1,000,000		(4,000,000)	[6]	(7,000,000)
Impairment losses on investments															0
Other income, net											$ 4,000,000		5,000,000	[6]	2,000,000
(Loss)/gain on sale of equity-method investment											0		0	[6]
Net gain/(loss) on debt extinguishment											0		(1,000,000)	[6]	0
Interest expense											108,000,000		122,000,000	[6]	52,000,000
Income/(loss) before income taxes											(142,000,000)		(147,000,000)	[6]	(40,000,000)
Income tax expense/(benefit)											(18,000,000)		0	[6]	0
Net (Loss)/Income											(124,000,000)		(147,000,000)	[6]	(40,000,000)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests											6,000,000		2,000,000	[6]	22,000,000
Net (loss)/income attributable to NRG Energy, Inc.											(130,000,000)		(149,000,000)	[6]	(62,000,000)
Operating revenues include inter-segment sales and net derivative gains and losses of:											23,000,000		25,000,000		14,000,000
Balance sheet
Equity investments in affiliates	134,000,000					148,000,000	[6]				134,000,000		148,000,000	[6]
Capital expenditures	163,000,000	[4]				160,000,000	[5],[6]				163,000,000	[4]	160,000,000	[5],[6]
Goodwill	12,000,000					12,000,000	[6]				12,000,000		12,000,000	[6]
Total assets	5,954,000,000					6,481,000,000	[6]				5,954,000,000		6,481,000,000	[6]
NRG Yield
Income Statement
Operating revenues											869,000,000	[1]	746,000,000	[2]	387,000,000	[3]
Operating expenses											324,000,000		274,000,000		155,000,000
Depreciation and amortization											265,000,000		202,000,000		74,000,000
Impairment of Long-Lived Assets Held-for-use											0		0		0
Acquisition-related transaction and integration costs											3,000,000		4,000,000		0
Research and Development Expense											0		0		0
Costs and Expenses											592,000,000		480,000,000		229,000,000
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											0		0
Operating Income (Loss)											277,000,000		266,000,000		158,000,000
Equity in earnings/(losses) of unconsolidated affiliates											35,000,000		25,000,000		22,000,000
Impairment losses on investments											0				0
Other income, net											2,000,000		3,000,000		3,000,000
(Loss)/gain on sale of equity-method investment											0		0
Net gain/(loss) on debt extinguishment											(9,000,000)		0		0
Interest expense											238,000,000		191,000,000		52,000,000
Income/(loss) before income taxes											67,000,000		103,000,000		131,000,000
Income tax expense/(benefit)											12,000,000		4,000,000		8,000,000
Net (Loss)/Income											55,000,000		99,000,000		123,000,000
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests											19,000,000		16,000,000		13,000,000
Net (loss)/income attributable to NRG Energy, Inc.											36,000,000		83,000,000		110,000,000
Operating revenues include inter-segment sales and net derivative gains and losses of:											29,000,000		12,000,000		7,000,000
Balance sheet
Equity investments in affiliates	798,000,000					410,000,000					798,000,000		410,000,000
Capital expenditures	30,000,000	[4]				13,000,000	[5]				30,000,000	[4]	13,000,000	[5]
Goodwill	0					0					0		0
Total assets	7,775,000,000					7,860,000,000					7,775,000,000		7,860,000,000
Corporate
Income Statement
Operating revenues											(14,000,000)	[1]	75,000,000	[2]	19,000,000	[3]
Operating expenses											61,000,000		72,000,000		41,000,000
Depreciation and amortization											34,000,000		32,000,000		21,000,000
Impairment of Long-Lived Assets Held-for-use											0		0		0
Acquisition-related transaction and integration costs											14,000,000		76,000,000		128,000,000
Research and Development Expense											60,000,000		36,000,000		27,000,000
Costs and Expenses											169,000,000		216,000,000		217,000,000
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											0		0
Operating Income (Loss)											(183,000,000)		(141,000,000)		(198,000,000)
Equity in earnings/(losses) of unconsolidated affiliates											0		3,000,000		0
Impairment losses on investments											42,000,000				99,000,000
Other income, net											84,000,000		78,000,000		77,000,000
(Loss)/gain on sale of equity-method investment											(14,000,000)		0
Net gain/(loss) on debt extinguishment											84,000,000		(94,000,000)		(50,000,000)
Interest expense											776,000,000		806,000,000		735,000,000
Income/(loss) before income taxes											(847,000,000)		(960,000,000)		(1,005,000,000)
Income tax expense/(benefit)											1,347,000,000		(2,000,000)		(290,000,000)
Net (Loss)/Income											(2,194,000,000)		(958,000,000)		(715,000,000)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests											(17,000,000)		24,000,000		14,000,000
Net (loss)/income attributable to NRG Energy, Inc.											(2,177,000,000)		(982,000,000)		(729,000,000)
Operating revenues include inter-segment sales and net derivative gains and losses of:											212,000,000		85,000,000		227,000,000
Balance sheet
Equity investments in affiliates	276,000,000					174,000,000					276,000,000		174,000,000
Capital expenditures	102,000,000	[4]				53,000,000	[5]				102,000,000	[4]	53,000,000	[5]
Goodwill	111,000,000					331,000,000					111,000,000		331,000,000
Total assets	19,576,000,000					30,727,000,000					19,576,000,000		30,727,000,000
Eliminations
Income Statement
Operating revenues											(1,218,000,000)	[1]	(1,949,000,000)	[2],[6]	(2,308,000,000)	[3]
Operating expenses											(1,220,000,000)		(1,950,000,000)	[6]	(2,297,000,000)
Depreciation and amortization											0		0	[6]	0
Impairment of Long-Lived Assets Held-for-use											22,000,000		(22,000,000)	[6]	0
Acquisition-related transaction and integration costs											0		0	[6]	0
Research and Development Expense											0		0	[6]	0
Costs and Expenses											(1,198,000,000)		(1,972,000,000)	[6]	(2,297,000,000)
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal											0		0	[6]
Operating Income (Loss)											(20,000,000)		23,000,000	[6]	(11,000,000)
Equity in earnings/(losses) of unconsolidated affiliates											(7,000,000)		(9,000,000)	[6]	(2,000,000)
Impairment losses on investments											0				0
Other income, net											(97,000,000)		(99,000,000)	[6]	(101,000,000)
(Loss)/gain on sale of equity-method investment											0		0	[6]
Net gain/(loss) on debt extinguishment											0		0	[6]	0
Interest expense											(95,000,000)		(97,000,000)	[6]	(100,000,000)
Income/(loss) before income taxes											(29,000,000)		12,000,000	[6]	(14,000,000)
Income tax expense/(benefit)											0		0	[6]	0
Net (Loss)/Income											(29,000,000)		12,000,000	[6]	(14,000,000)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests											(42,000,000)		(24,000,000)	[6]	(15,000,000)
Net (loss)/income attributable to NRG Energy, Inc.											13,000,000		36,000,000	[6]	1,000,000
Operating revenues include inter-segment sales and net derivative gains and losses of:											0		0		$ 0
Balance sheet
Equity investments in affiliates	(348,000,000)					(102,000,000)	[6]				(348,000,000)		(102,000,000)	[6]
Capital expenditures	0	[4]				0	[5],[6]				0	[4]	0	[5],[6]
Goodwill	0					0	[6]				0		0	[6]
Total assets	$ (19,851,000,000)					$ (39,190,000,000)	[6]				$ (19,851,000,000)		$ (39,190,000,000)	[6]
Customers
Segment Reporting Information
Concentration Risk, Number of Customers Accouting for More Than Ten Percent of Revenues | customer											0		0		0
Threshold percentage of the Company's consolidated revenues attributable to a customer											10.00%		10.00%		10.00%
ROFO Assets [Member]
Segment Reporting Information
Percentage of Ownership Sold of Subsidiary																	75.00%
Balance sheet
Number of Facilities																	12
[1]	(a) Operating revenues include inter-segment sales and net derivative gains and losses of:$947 $6 $1 $23 $29 $212 $— $1,218
[2]	(c) Operating revenues include inter-segment sales and net derivative gains and losses of:$1,820 $7 $— $25 $12 $85 $— $1,949
[3]	(f) Operating revenues include inter-segment sales and net derivative gains and losses of:$2,055 $5 $— $14 $7 $227 $— $2,308
[4]	Includes accruals
[5]	Includes accruals.
[6]	Includes an impairment loss resulting from the intercompany sale of solar panels at current market rates. The use of these long-lived assets is anticipated to generate sufficient cash flows to recover the historical cost of the assets and accordingly, the impairment loss was eliminated and the assets remain at historical cost in consolidation.

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Numerator:
Net (loss)/income attributable to NRG Energy, Inc.	$ (6,314)	$ 66	$ (14)	$ (120)	$ 119	$ 168	$ (97)	$ (56)	$ (6,382)	$ 134	$ (386)
Dividends, Preferred Stock, Cash									20	9	(9)
Dividends, Preferred Stock									20	56	9
Other Preferred Stock Dividends and Adjustments									0	47	0
(Loss)/Income Available for Common Stockholders	$ (6,319)	$ 61	$ (19)	$ (125)	$ 70	$ 166	$ (100)	$ (58)	$ (6,402)	$ 78	$ (395)
Denominator (Basic EPS):
Weighted average number of common shares outstanding	315	331	333	336	338	338	337	324	329	334	323
Basic earnings per share:
(Loss)/Earnings per weighted average common share — basic	$ (20.08)	$ 0.18	$ (0.06)	$ (0.37)	$ 0.21	$ 0.49	$ (0.30)	$ (0.18)	$ (19.46)	$ 0.23	$ (1.22)
Denominator (Diluted EPS):
Incremental shares attributable to the issuance of equity compensation (treasury stock method)									0	5	0
Total dilutive shares	315	332	333	336	342	343	337	324	329	339	323
Diluted earnings per share:
(Loss)/Earnings per weighted average common share — diluted	$ (20.08)	$ 0.18	$ (0.06)	$ (0.37)	$ 0.20	$ 0.48	$ (0.30)	$ (0.18)	$ (19.46)	$ 0.23	$ (1.22)
Preferred Stock [Member]
Numerator:
Dividends, Preferred Stock										$ 9
Redeemable Preferred Stock [Member]
Numerator:
Other Preferred Stock Dividends and Adjustments										$ (47)

Income Taxes (Provision - Detai

Income Taxes (Provision - Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current
State	$ 6	$ 8	$ 11
Total — current	6	8	11
Deferred
U.S. Federal	1,020	(50)	(207)
State	315	41	(57)
Foreign	1	4	(29)
Total — deferred	1,336	(5)	(293)
Income tax expense/(benefit)	$ 1,342	$ 3	$ (282)
Effective income tax rate (as a percent)	(26.30%)	2.20%	44.50%
Domestic and foreign components of income from continuing operations before income tax expense
U.S.	$ (5,105)	$ 126	$ (549)
Foreign	11	9	(85)
Income/(loss) before income taxes	$ 5,094	$ (135)	$ 634
U.S. federal statutory rate (as a percent)	35.00%	35.00%	35.00%
Reconciliation of the U.S. federal statutory rate to NRG's effective rate from continuing operations
Income/(loss) before income taxes	$ 5,094	$ (135)	$ 634
Tax at 35%	(1,783)	47	(222)
State taxes	(218)	9	19
Foreign operations	1	1	5
Federal and state tax credits, excluding PTCs	(5)	(1)	(36)
Valuation allowance	3,039	6	(5)
Expiration/utilization of capital losses	0	0	10
Reversal of valuation allowance on expired/utilized capital losses	0	0	(10)
Impact of non-taxable equity earnings	(10)	(11)	(14)
Book goodwill impairment	(340)	0	0
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	(3)	(2)	(3)
Production tax credit	(33)	(48)	(14)
Recognition of uncertain tax benefits	(15)	(30)	(11)
Effective Income Tax Rate Reconciliation, Tax Expense Attributable to Partnerships	12	4	8
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	19	22	(21)
Other	(2)	6	12
Income tax expense/(benefit)	$ 1,342	$ 3	$ (282)
Effective income tax rate (as a percent)	(26.30%)	2.20%	44.50%

Earnings Per Share Earnings Per

Earnings Per Share Earnings Per Share (Details 2) (Details) - shares shares in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		22	17	25
Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	[1]	16	16	16
Stock Compensation Plan [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		6	1	9
Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Preferred Stock, Dividend Rate Amended, Percentage		2.822%	2.822%
Preferred Stock, Dividend Rate, Percentage				3.625%
[1]	At December 31, 2013, the redeemable perpetual preferred stock had an interest rate of 3.625%.

Income Taxes (Deferred Taxes Re

Income Taxes (Deferred Taxes Rec - Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Deferred tax assets and valuation allowance
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation, Tax Credit, Investment, Amount	$ 5	$ 1	$ 36
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Amount	33	48	$ 14
Deferred tax liabilities:
Deferred Tax Liabilities, Emissions Allowances	31	25
Difference between book and tax basis of property	0	127
Derivatives, net	22	320
Goodwill	0	202
Cumulative translation adjustments	2	8
Investment in projects	(838)	(849)
Intangibles amortization (excluding goodwill)	0	99
Other	0	2
Total deferred tax liabilities	893	1,632
Deferred tax assets:
Deferred compensation, pension, accrued vacation and other reserves	255	266
Discount/premium on notes	68	99
Deferred Tax Assets, Property, Plant and Equipment	1,210	0
Deferred Tax Assets, Goodwill and Intangible Assets	39	0
Differences between book and tax basis of contracts	516	531
Pension and other postretirement benefits	218	157
Equity compensation	50	77
Bad debt reserve	6	9
U.S. capital loss carryforwards	1	0
U.S. Federal net operating loss carryforwards	1,373	1,523
Foreign net operating loss carryforwards	59	65
State net operating loss carryforwards	230	302
Foreign capital loss carryforwards	1	1
Deferred financing costs	6	23
Federal and state tax credit carryforwards	439	357
Federal benefit on state uncertain tax positions	17	17
Deferred Tax Assets, Intangibles	90	0
Deferred Tax Assets, Inventory	27	29
Deferred Tax Assets, Other	11	0
Total deferred tax assets	4,616	3,456
Valuation allowance	(3,575)	(265)
Total deferred tax assets, net of valuation allowance	1,041	3,191
Net deferred tax asset	148	1,559
NRG's net deferred tax position
Net deferred tax asset — noncurrent	167	1,580
Deferred Tax Liabilities, Net, Noncurrent	$ (19)	$ (21)

Income Taxes (DTA, Val Allowanc

Income Taxes (DTA, Val Allowance, and Tax Pay/Rec - Details 3) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Taxes receivable and payable
Deferred Tax Assets, Other	$ 11	$ 0
Deferred Tax Assets, Net of Valuation Allowance	148	1,500
Deferred Tax Assets, Valuation Allowance	3,575	265
Current taxes payable	5
Current taxes receivable	42
Foreign net operating loss carryforwards	59	65
Foreign capital loss carryforwards	1	$ 1
Domestic Tax Authority
Taxes receivable and payable
Operating Loss Carryforwards	1,400
State and Local Jurisdiction
Taxes receivable and payable
Deferred Tax Assets, Valuation Allowance	542
Operating Loss Carryforwards	230
Foreign Tax Authority
Taxes receivable and payable
Operating Loss Carryforwards	59
Federal Tax Authority [Member]
Taxes receivable and payable
Deferred Tax Assets, Valuation Allowance	2,973
Federal Cash Grant [Member]
Taxes receivable and payable
Current taxes receivable	13
Current Tax Refunds [Member]
Taxes receivable and payable
Current taxes receivable	$ 29

Income Taxes (Uncertain Tax Ben

Income Taxes (Uncertain Tax Benefits) (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Uncertain tax benefits
Liability for Uncertain Tax Positions, Noncurrent	$ 35	$ 53
Unrecognized Tax Benefits, Income Tax Penalties Expense	5
Net interest accrued on uncertain tax positions	2
Accrued interest and penalties related to unrecognized tax benefits	3	5
Uncertain tax benefits reconciliation
Balance as of January 1	71	115
Increase due to current year positions	4	0
Increase due to prior year positions	0	10
Decrease due to prior year positions	25	27
Unrecognized Tax Benefits, Increase Resulting from Acquisition	(18)	(27)
Uncertain tax benefits as of December 31	$ 32	$ 71

Stock-Based Compensation Stock-

Stock-Based Compensation Stock-Based Compensation (Intro) (Details) - shares	Dec. 31, 2015	Dec. 31, 2014
NRG LTIP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	22,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	6,240,648	6,184,157
NRG GenOn LTIP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	5,558,390	5,558,390
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	1,671,633	2,150,019

Stock-Based Compensation (NQSO

Stock-Based Compensation (NQSO - Details 2) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Non-Qualified Stock Options [Member]
Stock-Based Compensation
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	[1]	0 years
NQSO activity and changes
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		3 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term		10 years
Outstanding at the beginning of the period (in shares)		2,533,177
Forfeited (in shares)		0	0	0
Exercised (in shares)		401,647
Outstanding at the end of the period (in shares)		2,071,913	2,533,177
Exercisable at the end of the period (in shares)		2,071,913
Weighted Average Exercise Price at the beginning of the period (in dollars per share)		$ 30.95
Forfeited - Weighted Average Exercise Price (in dollars per share)		35.28
Exercised - Weighted Average Exercise Price (in dollars per share)		23.23
Weighted Average Exercise Price at the end of the period (in dollars per share)		32.27	$ 30.95
Exercisable - Weighted Average Exercise Price (in dollars per share)		$ 32.27
Options Outstanding - Weighted Average Remaining Contractual Term (in years)		3 years
Options Exercisable - Weighted Average Remaining Contractual Term (in years)		3 years	2 years
Options Outstanding - Aggregate Intrinsic Value		$ 0	$ 9
Options Exercisable - Aggregate Intrinsic Value		0
Weighted average grant date fair value of options granted, the total intrinsic value of options exercised, and the cash received from exercises of options
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value		2	7	$ 19
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options		$ 9	$ 21	$ 33
NRG GenOn LTIP [Member]
Share-based Compensation [Abstract]
Common stock authorized for issuance under the LTIP (in shares)		5,558,390	5,558,390
Common stock remaining available for grants under NRG's LTIP (in shares)		1,671,633	2,150,019
NRG LTIP [Member]
Share-based Compensation [Abstract]
Common stock authorized for issuance under the LTIP (in shares)		22,000,000
Common stock remaining available for grants under NRG's LTIP (in shares)		6,240,648	6,184,157
[1]	All NQSOs and PUs granted under the Company's LTIP were fully vested as of December 31, 2015.

Stock-Based Compensation (RSU -

Stock-Based Compensation (RSU - Details 2) - Restricted Stock Units (RSUs) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock-Based Compensation
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		1 year 9 months 14 days
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		2,261,996	2,674,626
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 27.59	$ 26.15
Granted (in units)		741,351
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 27.31	$ 29.90	$ 23.37
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period		(266,802)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 27.98
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period		887,179
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		$ 23.31
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value		$ 10	$ 26	$ 22
Subsequent Event [Member]
Stock-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	200,366

Stock-Based Compensation (DSU -

Stock-Based Compensation (DSU - Details 3) - Deferred Stock Units - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock-Based Compensation
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	0 years
Balance outstanding at the beginning of the period (in units)	384,663
Granted (in units)	70,929
Granted, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)	$ 25.14	$ 35.63	$ 23.18
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	28,014
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 24.78
Balance outstanding at the end of the period (in units)	427,578	384,663
Balance outstanding at the beginning of the period, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)	$ 21.21
Balance outstanding at the end of the period, Weighted Average Grant-Date Fair Value per Unit (in dollars per unit)	$ 21.88	$ 21.21
Aggregate intrinsic value for DSUs outstanding	$ 5	$ 10	$ 7
Aggregate intrinsic values for DSUs converted to common stock during the period	$ 0	$ 1	$ 12

Stock-Based Compensation Sto124

Stock-Based Compensation Stock-Based Compensation (MSUs - Details 4) - Market Stock Unit [Member] - $ / shares	1 Months Ended	12 Months Ended
	Jan. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock-Based Compensation
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		1 year 5 months 8 days
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award		For 2014 and future awards, the number of shares of NRG common stock to be paid (if any) as of the vesting date for each MSU will depend on the TSR. The number of shares of common stock to be paid as of the vesting date for each MSU is equal to: (i) three quarters of one share of common stock if the TSR has decreased by no more than 25% of the value of the common stock on the date of grant; (ii) one share of common stock, if the TSR equals the value of the common stock on the date of grant; and (iii) two shares of common stock if the TSR is 200% or greater of the value of the common stock on the date of grant. If the TSR is less than 75% of the value of the common stock on the date of grant, no common stock will be paid. If the TSR is between 75% and 200%, shares awarded are interpolated. The value of the common stock on the date of grant is based on the 20-day average of the common stock closing price.	MSUs are restricted grants where the quantity of shares increases and decreases alongside the Company's Total Shareholder Return, or TSR. Each MSU represents the potential to receive NRG common stock after the completion of the performance period, typically three years of service from the date of grant. For awards prior to 2014, the number of shares of NRG common stock to be paid (if any) as of the vesting date for each MSU will depend on the TSR. The number of shares of common stock to be paid as of the vesting date for each MSU is equal to: (i) one half of one share of common stock if the TSR has decreased by no more than 50% of the value of the common stock on the date of grant; (ii) one share of common stock, if the TSR equals the value of the common stock on the date of grant; and (iii) two shares of common stock if the TSR is 200% or greater of the value of the common stock on the date of grant. If the TSR is less than 50% of the value of the common stock on the date of grant, no common stock will be paid. If the TSR is between 50% and 200%, shares awarded are interpolated. The value of the common stock on the date of grant is based on the 20-day average of the common stock closing price.
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		1,980,157	2,304,569
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 29.54	$ 26.13
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		1,108,410
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 26.68	$ 31.90	$ 27.46
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period		1,230,410
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		$ 21.86
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period		202,412
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 29.44
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum		24.10%	23.62%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum		25.20%	27.43%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Minimum		0.25%	0.76%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Maximum		1.07%	1.21%
Minimum [Member]
Stock-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term		1 year	3 years
Maximum [Member]
Stock-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term		3 years	4 years
Subsequent Event [Member]
Stock-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(1,239,829)

Stock-Based Compensation Sto125

Stock-Based Compensation Stock-Based Compensation (PSUs & Supplemental - Details 5) $ in Millions		12 Months Ended
		Dec. 31, 2015USD ($)TypesOfAwards	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Stock-Based Compensation
Share-based Compensation Arrangement by Share-based Payment Award, Number of Types of Awards | TypesOfAwards		5
Payments Related to Tax Withholding for Share-based Compensation		$ 21	$ 16	$ 13
Allocated Share-based Compensation Expense		41	42	40
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		38
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense		$ (12)	(8)	(6)
Non-Qualified Stock Options [Member]
Stock-Based Compensation
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	[1]	0 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		3 years
Allocated Share-based Compensation Expense	[1]	$ 0	1	4
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	[1]	$ 0
Performance Stock Units [Member]
Stock-Based Compensation
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	[1]	0 years
Allocated Share-based Compensation Expense	[1]	$ 0	0	2
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	[1]	$ 0
Restricted Stock Units (RSUs)
Stock-Based Compensation
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		1 year 9 months 14 days
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		3 years
Allocated Share-based Compensation Expense		$ 23	20	18
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		$ 26
Deferred Stock Units
Stock-Based Compensation
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		0 years
Allocated Share-based Compensation Expense		$ 2	2	2
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		$ 0
Market Stock Unit [Member]
Stock-Based Compensation
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		1 year 5 months 8 days
Allocated Share-based Compensation Expense		$ 16	$ 19	$ 14
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		$ 12
[1]	All NQSOs and PUs granted under the Company's LTIP were fully vested as of December 31, 2015.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transactions
Revenues from Related Parties Included in Operating Revenues	$ 8	$ 12	$ 11
Management Fees Revenue	11	10	10
Gladstone
Related Party Transactions
Revenues from Related Parties Included in Operating Revenues	4	6	6
GenConn
Related Party Transactions
Revenues from Related Parties Included in Operating Revenues	$ 4	$ 6	$ 5

Commitments and Contingencie127

Commitments and Contingencies (Operating Leases) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Coal, Gas and Transportation Commitments
Off-market Lease, Unfavorable		$ 1,146	$ 1,244
Lease expense		100	106	$ 88
Coal, Gas and Transportation Commitments
Coal, Gas and Transportation Commitments
Purchases		2,600	$ 3,500	2,800
EME [Member]
Coal, Gas and Transportation Commitments
Off-market Lease, Unfavorable		159
Lease expense		$ 14
Dickerson Morgantown [Member]
Coal, Gas and Transportation Commitments
Leased Interest		100.00%
GenOn Mid-Atlantic
Coal, Gas and Transportation Commitments
Off-market Lease, Unfavorable				$ 604
Lease expense		$ 43
Future commitments under coal, gas and transportation contractual agreements
2,016		150
2,017		144
2,018		105
2,019		139
2,020		105
Thereafter		442
Total		1,085
REMA [Member]
Coal, Gas and Transportation Commitments
Lease expense		29
Future commitments under coal, gas and transportation contractual agreements
2,016		61
2,017		63
2,018		55
2,019		65
2,020		56
Thereafter		278
Total		$ 578
Shawville [Member]
Coal, Gas and Transportation Commitments
Leased Interest		100.00%
Keystone, Shelocta, PA
Coal, Gas and Transportation Commitments
Leased Interest		16.45%
Conemaugh, New Florence, PA
Coal, Gas and Transportation Commitments
Leased Interest		16.67%
Other Leased Property [Member]
Future commitments under coal, gas and transportation contractual agreements
2,016		$ 104
2,017		79
2,018		72
2,019		61
2,020		56
Thereafter		410
Total	[1]	782
Powerton and Joliet [Member]
Future commitments under coal, gas and transportation contractual agreements
2,016		26
2,017		1
2,018		1
2,019		1
2,020		1
Thereafter		237
Total		267
REMA [Member] | Keystone Conemaugh
Coal, Gas and Transportation Commitments
Off-market Lease, Unfavorable		$ 186
[1]	Amounts in the table exclude future sublease income of $17 million associated with long-term leases for office locations in Texas.

Commitments and Contingencie128

Commitments and Contingencies (Commitments) (Details 2) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies
Nuclear Insurance Financial Protection Pool, Maximum Assessment, Adminstrative Fee, As a Percent		5.00%
Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals		$ 17
Minimum purchase commitment
2,016		50
2,017		17
2,018		2
2,019		1
2,020		0
Thereafter		0
Total	[1]	$ 70
Maximum remaining term under individual purchased power contract (in years)		5 years
Lignite Contract with Texas Westmoreland Coal Co.
Obligation guaranteed by NRG Energy, Inc		$ 2,878	$ 3,380
Lignite Contract with Texas Westmoreland Coal Co. | Letters of Credit Posted by NRG
Lignite Contract with Texas Westmoreland Coal Co.
Surety Bond in Support of Guarantee		31.5
Lignite Contract with Texas Westmoreland Coal Co. | Corporate Guarantee of Bond Obligation
Lignite Contract with Texas Westmoreland Coal Co.
Obligation guaranteed by NRG Energy, Inc		$ 76
Lignite Contract with Texas Westmoreland Coal Co. | Texas Westmoreland Coal Co.
Lignite Contract with Texas Westmoreland Coal Co.
Mining period for which option to extend can be done		P5Y
Bond obligation imposed by Railroad Commission of Texas		$ 107.5
Coal, Gas and Transportation Commitments
Commitments and Contingencies
Purchases		2,600	$ 3,500	$ 2,800
Minimum purchase commitment
2,016		887
2,017		295
2,018		261
2,019		169
2,020		174
Thereafter		549
Total		$ 2,335
[1]	As of December 31, 2015, the maximum remaining term under any individual purchased power contract is five years.

Commitments and Contingencie129

Commitments and Contingencies (Texas, Nuclear) (Details 3) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Loss Contingencies [Line Items]
Nuclear insurance liability limit per incident	$ 13,500,000
Required nuclear liability insurance	375,000
Nuclear financial protection pool mandated by the Price-Anderson Act	13,500,000
Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident	127,000
Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident	$ 19,000
44% maximum assessment	44.00%
Nuclear Insurance Financial Protection Pool Nuclear Operator Maximum Annual Assessment	$ 8,000
Maximum liability per nuclear incident	112,000
Mutual property insurance additional blanket policy property coverage	1,000,000
Nuclear property insurance coverage limit per individual insured	1,500,000
Mutual Lost Revenue Insurance Maximum Weekly Recovery	3,000
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss	$ 1,980
Multiplier that the industry mutual insurance company may assess against insureds premium	10
The number of months a nuclear industry mutual insurance company will respond to retrospective premium adjustments	24 months
Number of years board of directors of industry mutual insurance company can adjust policy after policy expires	6 years
Nuclear Event [Member]
Loss Contingencies [Line Items]
Total nuclear property insurance coverage	$ 2,750,000
Mutual Lost Revenue Insurance Maximum Weekly Recovery	274,000
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss	215,600
Non-nuclear Event [Member]
Loss Contingencies [Line Items]
Total nuclear property insurance coverage	1,500,000
Mutual Lost Revenue Insurance Maximum Weekly Recovery	184,000
Accidental outage weekly recovery limit for loss revenues from a nuclear industry mutual insurance company in the event of insurable loss	$ 144,000

Commitments and Contigencies (C

Commitments and Contigencies (Contingencies) (Details 4) - USD ($)	1 Months Ended	3 Months Ended	12 Months Ended
	Jun. 30, 2013	Sep. 30, 2010	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Loss Contingencies
Off-market Lease, Unfavorable			$ 1,146,000,000	$ 1,244,000,000
Loss Contingency, Settlement Agreement, Consideration				$ 12,000,000
Midwest Generation New Source Review [Member]
Louisiana Generating, LLC
Civil Penalties		$ 37,500
Notice of Intent to File Citizens Suit [Member]
Louisiana Generating, LLC
Civil Penalties	$ 100,000
GenOn Mid-Atlantic
Loss Contingencies
Off-market Lease, Unfavorable					$ 604,000,000
Keystone Conemaugh | REMA [Member]
Loss Contingencies
Off-market Lease, Unfavorable			$ 186,000,000
Telephone Consumer Protection Act Purported Class Actions [Member]
Louisiana Generating, LLC
Loss Contingency, Damages Sought			1,500
El Segundo Environmental Liability [Member]
Louisiana Generating, LLC
Civil Penalties			$ 150,000
Additional Civil Penalties			$ 50,000
CDWR and SDGE v Sunrise Power [Member]
Louisiana Generating, LLC
Loss Contingency, Damages Sought			1.2
Remaining Term			70 months

Regulatory Matters (Details)

Regulatory Matters (Details) $ in Millions	1 Months Ended
	May. 31, 2010orders	Dec. 20, 2013USD ($)	Jul. 05, 2012USD ($)owners	Dec. 31, 2011USD ($)
Regulatory Assets [Line Items]
Number of significant orders issued by FERC | orders	2
SECA charges owed by BP Energy				$ 22
Regulatory Charges Settled by Third Party			$ 24
Number of PJM Transmission Owners Who Filed Motion | owners			3
Regulatory Charges Settled by Third Party, Additional			$ 1
Genon [Member]
Regulatory Assets [Line Items]
Regulatory payments sought		$ 22

Environmental Matters (Details)

Environmental Matters (Details) $ in Millions	Dec. 31, 2015USD ($)
Environmental Capital Expenditures, Estimated	$ 350
Genon [Member]
Environmental Capital Expenditures, Estimated	68
Midwest Generation [Member]
Environmental Capital Expenditures, Estimated	$ 263

Cash Flow Information (Details)

Cash Flow Information (Details) - USD ($)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Significant Noncash Transactions
Interest paid, net of amount capitalized		$ 1,172,000,000	$ 1,067,000,000	$ 836,000,000
Income taxes paid	[1]	16,000,000	(6,000,000)	(60,000,000)
Consent Fees Paid, Preferred Stock		0	5,000,000	0
(Decrease)/additions to fixed assets for accrued capital expenditures		(24,000,000)	87,000,000	405,000,000
Decrease to fixed assets for accrued grants and related tax impact		0	711,000,000	681,000,000
Income Taxes Paid		17,000,000	15,000,000	28,000,000
Income tax refunds received		1,000,000	21,000,000	87,000,000
EME [Member]
Other Significant Noncash Transactions
Issuance of shares for GenOn acquisition		$ 0	$ (401,000,000)	$ 0
[1]	In 2015, the net income taxes paid reflect $17 million in income taxes paid and $1 million in income tax refunds. In 2014, the net income taxes refunded are net of $15 million income taxes paid and $21 million income tax refunds. In 2013, the net income taxes refunded are net of $28 million income taxes paid and $87 million income tax refunds.

Guarantees (Details)

Guarantees (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Guarantees [Abstract]
Fair value of guarantees	$ 3.6
Guarantor Obligations
Guarantees By Remaining Maturity, Under 1 Year	1,805
Guarantees By Remaining Maturity, 1-3 Years	93
Guarantees By Remaining Maturity, 3-5 Years	257
Guarantees By Remaining Maturity, Over 5 Years	723
Guarantees by Remaining Maturity, Total	2,878	$ 3,380
Letters of credit and surety bonds
Guarantor Obligations
Guarantees By Remaining Maturity, Under 1 Year	1,805
Guarantees By Remaining Maturity, 1-3 Years	92
Guarantees By Remaining Maturity, 3-5 Years	0
Guarantees By Remaining Maturity, Over 5 Years	2
Guarantees by Remaining Maturity, Total	$ 1,899	1,914
Letters of credit and surety bonds, maximum expiration period (in years)	1 year
Asset sales guarantee obligations
Guarantor Obligations
Guarantees By Remaining Maturity, Under 1 Year	$ 0
Guarantees By Remaining Maturity, 1-3 Years	0
Guarantees By Remaining Maturity, 3-5 Years	257
Guarantees By Remaining Maturity, Over 5 Years	0
Guarantees by Remaining Maturity, Total	257	292
Other guarantees
Guarantor Obligations
Guarantees By Remaining Maturity, Under 1 Year	0
Guarantees By Remaining Maturity, 1-3 Years	1
Guarantees By Remaining Maturity, 3-5 Years	0
Guarantees By Remaining Maturity, Over 5 Years	721
Guarantees by Remaining Maturity, Total	$ 722	$ 1,174

Jointly Owned Plants (Details)

Jointly Owned Plants (Details) $ in Millions	Dec. 31, 2015USD ($)
South Texas Project
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	44.00%
Property, Plant and Equipment	$ 3,246
Accumulated Depreciation	1,599
Construction in Progress	$ 38
Big Cajun II Unit 3, New Roads, LA
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	58.00%
Property, Plant and Equipment	$ 206
Accumulated Depreciation	114
Construction in Progress	$ 0
Cedar Bayou Unit 4, Baytown, TX
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	50.00%
Property, Plant and Equipment	$ 211
Accumulated Depreciation	57
Construction in Progress	$ 0
Keystone, Shelocta, PA
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	3.70%
Property, Plant and Equipment	$ 97
Accumulated Depreciation	44
Construction in Progress	$ 0
Conemaugh, New Florence, PA
Jointly Owned Utility Plant Interests
Ownership Interest (as a percent)	3.72%
Property, Plant and Equipment	$ 101
Accumulated Depreciation	46
Construction in Progress	$ 1

Unaudited Quarterly Financia136

Unaudited Quarterly Financial Data (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 3,011	$ 4,434	$ 3,400	$ 3,829	$ 4,192	$ 4,569	$ 3,621	$ 3,486	$ 14,674	[1]	$ 15,868	[2]	$ 11,295	[3]
Operating Income (Loss)	(4,727)	379	232	76	453	549	89	180	(4,040)		1,271		343
Net (Loss)/Income	(6,358)	67	(9)	(136)	97	182	(80)	(67)	(6,436)		132		(352)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	(44)	1	5	(16)	(22)	14	17	(11)	(54)		(2)		34
Net (loss)/income attributable to NRG Energy, Inc.	(6,314)	66	(14)	(120)	119	168	(97)	(56)	(6,382)		134		(386)
Net Income (Loss) Available to Common Stockholders, Basic	$ (6,319)	$ 61	$ (19)	$ (125)	$ 70	$ 166	$ (100)	$ (58)	$ (6,402)		$ 78		$ (395)
Weighted average number of common shares outstanding — basic	315	331	333	336	338	338	337	324	329		334		323
Net (Loss)/Income per Weighted Average Common Share — Basic	$ (20.08)	$ 0.18	$ (0.06)	$ (0.37)	$ 0.21	$ 0.49	$ (0.30)	$ (0.18)	$ (19.46)		$ 0.23		$ (1.22)
Weighted average number of common shares outstanding — diluted	315	332	333	336	342	343	337	324	329		339		323
Net (Loss)/Income per Weighted Average Common Share — Diluted	$ (20.08)	$ 0.18	$ (0.06)	$ (0.37)	$ 0.20	$ 0.48	$ (0.30)	$ (0.18)	$ (19.46)		$ 0.23		$ (1.22)
[1]	(a) Operating revenues include inter-segment sales and net derivative gains and losses of:$947 $6 $1 $23 $29 $212 $— $1,218
[2]	(c) Operating revenues include inter-segment sales and net derivative gains and losses of:$1,820 $7 $— $25 $12 $85 $— $1,949
[3]	(f) Operating revenues include inter-segment sales and net derivative gains and losses of:$2,055 $5 $— $14 $7 $227 $— $2,308

Condensed Consolidating Fina137

Condensed Consolidating Financial Information (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument
Long-term Debt	$ 19,620	$ 20,366
Recourse Debt
Debt Instrument
Long-term Debt	8,584	$ 8,800
Senior Notes [Member] | Recourse Debt
Debt Instrument
Long-term Debt	$ 6,200

Condensed Consolidating Fina138

Condensed Consolidating Financial Information (Statements of Operations) (Details 2) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Operating Revenues
Total operating revenues	$ 3,011	$ 4,434	$ 3,400	$ 3,829	$ 4,192	$ 4,569	$ 3,621	$ 3,486	$ 14,674	[1]	$ 15,868	[2]	$ 11,295	[3]
Total operating revenues
Cost of operations									10,755		11,794		8,130
Depreciation and amortization									1,566		1,523		1,256
Impairment losses									5,030		97		459
Selling, general and administrative									1,220		1,027		895
Acquisition related transactions and integration costs									10		84		128
Research and Development Expense									154		91		84
Total operating costs and expenses									18,735		14,616		10,952
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									21		19		0
Operating Income (Loss)	(4,727)	379	232	76	453	549	89	180	(4,040)		1,271		343
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries									0		0		0
Equity in earnings of unconsolidated affiliates									36		38		7
Impairment losses on investments									(56)		0		(99)
Other income, net									33		22		13
(Loss)/gain on sale of equity-method investment									(14)		18		0
Loss on debt extinguishment									75		(95)		(50)
Interest expense									(1,128)		(1,119)		(848)
Total other expense									(1,054)		(1,136)		(977)
Income/(loss) before income taxes									(5,094)		135		(634)
Income tax expense/(benefit)									1,342		3		(282)
Net (Loss)/Income	(6,358)	67	(9)	(136)	97	182	(80)	(67)	(6,436)		132		(352)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	(44)	1	5	(16)	(22)	14	17	(11)	(54)		(2)		34
Net (loss)/income attributable to NRG Energy, Inc.	$ (6,314)	$ 66	$ (14)	$ (120)	$ 119	$ 168	$ (97)	$ (56)	(6,382)		134		(386)
Guarantor Subsidiaries
Operating Revenues
Total operating revenues									10,024		9,974		8,223
Total operating revenues
Cost of operations									7,712		7,909		6,150
Depreciation and amortization									787		801		837
Impairment losses									4,655		0		459
Selling, general and administrative									467		333		446
Acquisition related transactions and integration costs									1		3		0
Research and Development Expense									0		0		0
Total operating costs and expenses									13,622		9,046		7,892
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									0		0
Operating Income (Loss)									(3,598)		928		331
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries									(86)		317		(67)
Equity in earnings of unconsolidated affiliates									8		13		(11)
Impairment losses on investments									0		0		0
Other income, net									4		7		6
(Loss)/gain on sale of equity-method investment									0		0
Loss on debt extinguishment									0		0		0
Interest expense									(18)		(19)		(24)
Total other expense									(92)		318		(96)
Income/(loss) before income taxes									(3,690)		1,246		235
Income tax expense/(benefit)									(1,104)		322		114
Net (Loss)/Income									(2,586)		924		121
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									0		0		0
Net (loss)/income attributable to NRG Energy, Inc.									(2,586)		924		121
Non-Guarantor Subsidiaries
Operating Revenues
Total operating revenues									4,768		6,287		3,211
Total operating revenues
Cost of operations									3,147		4,206		2,113
Depreciation and amortization									759		706		407
Impairment losses									375		119		0
Selling, general and administrative									403		390		221
Acquisition related transactions and integration costs									(5)		15		70
Research and Development Expense									61		35		34
Total operating costs and expenses									4,740		5,471		2,845
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									21		19
Operating Income (Loss)									49		835		366
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries									(29)		219		(14)
Equity in earnings of unconsolidated affiliates									37		33		22
Impairment losses on investments									(25)		0		(99)
Other income, net									29		14		11
(Loss)/gain on sale of equity-method investment									0		18
Loss on debt extinguishment									56		(9)		(12)
Interest expense									(564)		(525)		(318)
Total other expense									(496)		(250)		(410)
Income/(loss) before income taxes									(447)		585		(44)
Income tax expense/(benefit)									(96)		159		(89)
Net (Loss)/Income									(351)		426		45
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									(23)		57		27
Net (loss)/income attributable to NRG Energy, Inc.									(328)		369		18
NRG Energy, Inc.
Operating Revenues
Total operating revenues									0		0		0
Total operating revenues
Cost of operations									14		4		0
Depreciation and amortization									20		16		12
Impairment losses									0		0		0
Selling, general and administrative									350		304		234
Acquisition related transactions and integration costs									14		66		58
Research and Development Expense									93		56		50
Total operating costs and expenses									491		446		354
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									0		0
Operating Income (Loss)									(491)		(446)		(354)
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries									(2,799)		775		221
Equity in earnings of unconsolidated affiliates									0		0		0
Impairment losses on investments									(31)		0		0
Other income, net									0		3		(2)
(Loss)/gain on sale of equity-method investment									(14)		0
Loss on debt extinguishment									19		(86)		(38)
Interest expense									(546)		(575)		(506)
Total other expense									(3,371)		117		(325)
Income/(loss) before income taxes									(3,862)		(329)		(679)
Income tax expense/(benefit)									2,489		(478)		(307)
Net (Loss)/Income									(6,351)		149		(372)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									31		15		13
Net (loss)/income attributable to NRG Energy, Inc.									(6,382)		134		(385)
Eliminations
Operating Revenues
Total operating revenues									(118)	[4]	(393)	[5]	(139)	[6]
Total operating revenues
Cost of operations									(118)	[4]	(325)	[5]	(133)	[6]
Depreciation and amortization									0	[4],[7]	0	[5],[8]	0	[6],[9]
Impairment losses									0	[4]	(22)	[5]	0	[5]
Selling, general and administrative									0	[4]	0	[5]	(6)	[6]
Acquisition related transactions and integration costs									0	[4]	0	[5]	0	[6]
Research and Development Expense									0	[4]	0	[5]	0	[6]
Total operating costs and expenses									(118)	[4]	(347)	[5]	(139)	[6]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									0	[4]	0	[5]
Operating Income (Loss)									0	[4]	(46)	[5]	0	[6]
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries									2,914	[4]	(1,311)	[5]	(140)	[6]
Equity in earnings of unconsolidated affiliates									(9)	[4],[7]	(8)	[5],[8]	(4)	[6],[9]
Impairment losses on investments									0	[4]	0	[5]	0	[6]
Other income, net									0	[4]	(2)	[5]	(2)	[6]
(Loss)/gain on sale of equity-method investment									0	[4]	0	[5]
Loss on debt extinguishment									0	[4]	0	[5]	0	[6]
Interest expense									0	[4]	0	[5]	0	[6]
Total other expense									2,905	[4]	(1,321)	[5]	(146)	[6]
Income/(loss) before income taxes									2,905	[4]	(1,367)	[5]	(146)	[6]
Income tax expense/(benefit)									53	[4]	0	[5]	0	[6]
Net (Loss)/Income									2,852	[4],[7]	(1,367)	[5],[8]	(146)	[6],[9]
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									(62)	[4]	(74)	[5]	(6)	[6],[10]
Net (loss)/income attributable to NRG Energy, Inc.									$ 2,914	[4]	$ (1,293)	[5]	$ (140)	[6]
[1]	(a) Operating revenues include inter-segment sales and net derivative gains and losses of:$947 $6 $1 $23 $29 $212 $— $1,218
[2]	(c) Operating revenues include inter-segment sales and net derivative gains and losses of:$1,820 $7 $— $25 $12 $85 $— $1,949
[3]	(f) Operating revenues include inter-segment sales and net derivative gains and losses of:$2,055 $5 $— $14 $7 $227 $— $2,308
[4]	All significant intercompany transactions have been eliminated in consolidation.
[5]	All significant intercompany transactions have been eliminated in consolidation.
[6]	All significant intercompany transactions have been eliminated in consolidation.
[7]	All significant intercompany transactions have been eliminated in consolidation.
[8]	All significant intercompany transactions have been eliminated in consolidation.
[9]	All significant intercompany transactions have been eliminated in consolidation.
[10]	All significant intercompany transactions have been eliminated in consolidation.

Condensed Consolidating Fina139

Condensed Consolidating Financial Information (Statements of Comprehensive Income) (Details 3) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Net (Loss)/Income	$ (6,358)	$ 67	$ (9)	$ (136)	$ 97	$ 182	$ (80)	$ (67)	$ (6,436)		$ 132		$ (352)
Unrealized (loss)/gain on derivatives, net									(15)		(45)		8
Foreign currency translation adjustments, net									(11)		(8)		(24)
Available-for-sale securities, net									17		(7)		3
Defined benefit plan, net									10		(129)		168
Other comprehensive income/(loss)									1		(189)		155
Comprehensive income/(loss)									(6,435)		(57)		(197)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests	$ (44)	$ 1	$ 5	$ (16)	$ (22)	$ 14	$ 17	$ (11)	(54)		(2)		34
Less: Comprehensive income/(loss) attributable to noncontrolling interest									(73)		8		34
Comprehensive income/(loss) attributable to NRG Energy, Inc.									(6,362)		(65)		(231)
Dividends for preferred shares									20		56		9
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders									(6,382)		(121)		(240)
Guarantor Subsidiaries
Net (Loss)/Income									(2,586)		924		121
Unrealized (loss)/gain on derivatives, net									(9)		(49)		(71)
Foreign currency translation adjustments, net									0		0		0
Available-for-sale securities, net									0		0		0
Defined benefit plan, net									22		(5)		(75)
Other comprehensive income/(loss)									(31)		(44)		4
Comprehensive income/(loss)									(2,617)		880		125
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									0		0		0
Less: Comprehensive income/(loss) attributable to noncontrolling interest									0		0
Comprehensive income/(loss) attributable to NRG Energy, Inc.									(2,617)		880		125
Dividends for preferred shares									0		0		0
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders									(2,617)		880		125
Non-Guarantor Subsidiaries
Net (Loss)/Income									(351)		426		45
Unrealized (loss)/gain on derivatives, net									(13)		(89)		50
Foreign currency translation adjustments, net									(7)		(12)		(20)
Available-for-sale securities, net									(1)		1		0
Defined benefit plan, net									15		104		(63)
Other comprehensive income/(loss)									(36)		(204)		93
Comprehensive income/(loss)									(387)		222		138
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									(23)		57		27
Less: Comprehensive income/(loss) attributable to noncontrolling interest									(42)		67
Comprehensive income/(loss) attributable to NRG Energy, Inc.									(345)		155		111
Dividends for preferred shares									0		0		0
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders									(345)		155		111
NRG Energy, Inc.
Net (Loss)/Income									(6,351)		149		(372)
Unrealized (loss)/gain on derivatives, net									48		(215)		120
Foreign currency translation adjustments, net									(4)		4		(4)
Available-for-sale securities, net									18		(8)		3
Defined benefit plan, net									(47)		30		(30)
Other comprehensive income/(loss)									109		(249)		149
Comprehensive income/(loss)									(6,242)		(100)		(223)
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									31		15		13
Less: Comprehensive income/(loss) attributable to noncontrolling interest									31		15
Comprehensive income/(loss) attributable to NRG Energy, Inc.									(6,273)		(115)		(236)
Dividends for preferred shares									20		56		9
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders									(6,293)		(171)		(245)
Eliminations
Net (Loss)/Income									2,852	[1],[2]	(1,367)	[3],[4]	(146)	[5],[6]
Unrealized (loss)/gain on derivatives, net									(41)	[7]	308	[8]	(91)	[9]
Foreign currency translation adjustments, net									0	[7]	0	[8]	0	[9]
Available-for-sale securities, net									0	[7]	0	[8]	0	[9]
Defined benefit plan, net									0	[7]	0	[8]	0	[9]
Other comprehensive income/(loss)									(41)	[7]	308	[8]	(91)	[9]
Comprehensive income/(loss)									2,811	[7]	(1,059)	[8]	(237)	[9]
Less: Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests									(62)	[1]	(74)	[3]	(6)	[5],[9]
Less: Comprehensive income/(loss) attributable to noncontrolling interest									(62)	[7]	(74)	[8]
Comprehensive income/(loss) attributable to NRG Energy, Inc.									2,873	[7]	(985)	[8]	(231)	[9]
Dividends for preferred shares									0	[7]	0	[8]	0	[9]
Comprehensive (loss)/income, Net of Tax, Available for Common Stockholders									$ 2,873	[7]	$ (985)	[8]	$ (231)	[9]
[1]	All significant intercompany transactions have been eliminated in consolidation.
[2]	All significant intercompany transactions have been eliminated in consolidation.
[3]	All significant intercompany transactions have been eliminated in consolidation.
[4]	All significant intercompany transactions have been eliminated in consolidation.
[5]	All significant intercompany transactions have been eliminated in consolidation.
[6]	All significant intercompany transactions have been eliminated in consolidation.
[7]	All significant intercompany transactions have been eliminated in consolidation.
[8]	All significant intercompany transactions have been eliminated in consolidation.
[9]	All significant intercompany transactions have been eliminated in consolidation.

Condensed Consolidating Fina140

Condensed Consolidating Financial Information (Balance Sheets) (Details 4) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Current Assets
Cash and cash equivalents		$ 1,518		$ 2,116		$ 2,254		$ 2,087
Funds deposited by counterparties		106		72
Restricted cash		414		457
Accounts receivable - trade, net		1,157		1,322
Inventory		1,252		1,247
Derivative instruments		1,915		2,425
Derivative, Collateral, Right to Reclaim Cash		568		187
Renewable energy grant receivable		13		135
Disposal Group, Including Discontinued Operation, Other Assets, Current		6		0
Prepaid Expense and Other Assets, Current Less Accounts Receivable Affiliate		438		438
Due from Affiliate, Current		4		9
Total current assets		7,391		8,408
Net Property, Plant and Equipment		18,732		22,367
Other Assets
Investment in subsidiaries		0		0
Equity investments in affiliates		1,045		771
Notes receivable, less current portion		53		72
Goodwill		999		2,574
Intangible assets, net		2,310		2,567
Nuclear decommissioning trust fund		561		585
Deferred income taxes		167		1,580
Derivative instruments		305		480
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent		105		17
Other non-current assets		1,214		1,045
Total other assets		6,759		9,691
Total assets		32,882		40,466
Current Liabilities
Current portion of long-term debt and capital leases		481		474
Accounts payable		869		1,060
Accounts payable - affiliate		0		0
Derivative instruments		1,721		2,054
Deferred Tax Liabilities, Net, Current				0
Cash collateral received in support of energy risk management activities		106		72
Accrued Expenses and Other Current Liabilities				1,199
Accrued interest expense		242		252
Other accrued expenses		568		553
Disposal Group, Including Discontinued Operation, Liabilities, Current		2		0
Other current liabilities		386		394
Total current liabilities		4,375		4,859
Other Liabilities
Long-term debt and capital leases		18,983		19,701
Nuclear decommissioning reserve		326		310
Nuclear decommissioning trust liability		283		333
Postretirement and other benefit obligations		588		727
Deferred income taxes		19		21
Derivative instruments		493		438
Out-of-market contracts, net of accumulated amortization of $0 and $562		1,146		1,244
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent		4		0
Other non-current liabilities		900		847
Total non-current liabilities		22,742		23,621
Total Liabilities		27,117		28,480
Redeemable noncontrolling interest in subsidiaries		302		291		249
Redeemable Noncontrolling Interest, Equity, Other, Carrying Amount		29		19		2
Stockholders' Equity		5,434		11,676		10,467		10,269
Total Liabilities and Stockholders' Equity		32,882		40,466
Guarantor Subsidiaries
Current Assets
Cash and cash equivalents		0		18		56		78
Funds deposited by counterparties		55		9
Restricted cash		5		5
Accounts receivable - trade, net		851		924
Inventory		570		537
Derivative instruments		1,202		1,657
Derivative, Collateral, Right to Reclaim Cash		474		114
Renewable energy grant receivable		0		0
Disposal Group, Including Discontinued Operation, Other Assets, Current		0		0
Prepaid Expense and Other Assets, Current Less Accounts Receivable Affiliate		93		94
Due from Affiliate, Current		395		7,449
Total current assets		3,645		10,807
Net Property, Plant and Equipment		4,767		8,344
Other Assets
Investment in subsidiaries		842		140
Equity investments in affiliates		(14)		(18)
Notes receivable, less current portion		0		1
Goodwill		697		1,921
Intangible assets, net		763		765
Nuclear decommissioning trust fund		561		585
Deferred income taxes		(6)		(247)
Derivative instruments		153		242
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent		0		0
Other non-current assets		80		108
Total other assets		3,076		3,497
Total assets		11,488		22,648
Current Liabilities
Current portion of long-term debt and capital leases		2		1
Accounts payable		553		598
Accounts payable - affiliate		151		1,588
Derivative instruments		1,130		$ 1,532
Deferred Tax Liabilities, Net, Current
Cash collateral received in support of energy risk management activities		55		$ 9
Accrued Expenses and Other Current Liabilities				283
Accrued interest expense		5
Other accrued expenses		122
Disposal Group, Including Discontinued Operation, Liabilities, Current		0
Other current liabilities		192
Total current liabilities		2,210		4,011
Other Liabilities
Long-term debt and capital leases		302		302
Nuclear decommissioning reserve		326		310
Nuclear decommissioning trust liability		283		333
Postretirement and other benefit obligations		236		277
Deferred income taxes		179		1,043
Derivative instruments		301		248
Out-of-market contracts, net of accumulated amortization of $0 and $562		95		111
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent		0
Other non-current liabilities		318		188
Total non-current liabilities		2,040		2,812
Total Liabilities		4,250		6,823
Redeemable noncontrolling interest in subsidiaries		0		0
Redeemable Noncontrolling Interest, Equity, Other, Carrying Amount		0		0
Stockholders' Equity		7,238		15,825
Total Liabilities and Stockholders' Equity		11,488		22,648
Non-Guarantor Subsidiaries
Current Assets
Cash and cash equivalents		825		1,455		870		1,258
Funds deposited by counterparties		51		63
Restricted cash		409		451
Accounts receivable - trade, net		304		392
Inventory		682		710
Derivative instruments		871		1,209
Derivative, Collateral, Right to Reclaim Cash		94		73
Renewable energy grant receivable		13		134
Disposal Group, Including Discontinued Operation, Other Assets, Current		6		0
Prepaid Expense and Other Assets, Current Less Accounts Receivable Affiliate		274		269
Due from Affiliate, Current		260		1,988
Total current assets		3,789		6,744
Net Property, Plant and Equipment		13,773		13,877
Other Assets
Investment in subsidiaries		2,244		2,293
Equity investments in affiliates		1,160		891
Notes receivable, less current portion		46		60
Goodwill		302		653
Intangible assets, net		1,551		1,806
Nuclear decommissioning trust fund		0		0
Deferred income taxes		815		722
Derivative instruments		184		288
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent		105		17
Other non-current assets		749		520
Total other assets		7,156		7,250
Total assets		24,718		27,871
Current Liabilities
Current portion of long-term debt and capital leases		460		444
Accounts payable		277		416
Accounts payable - affiliate		2,000		2,447
Derivative instruments		749		963
Deferred Tax Liabilities, Net, Current				0
Cash collateral received in support of energy risk management activities		51		63
Accrued Expenses and Other Current Liabilities				498
Accrued interest expense		91
Other accrued expenses		151
Disposal Group, Including Discontinued Operation, Liabilities, Current		2
Other current liabilities		187
Total current liabilities		3,968		4,831
Other Liabilities
Long-term debt and capital leases		10,496		11,123
Nuclear decommissioning reserve		0		0
Nuclear decommissioning trust liability		0		0
Postretirement and other benefit obligations		200		234
Deferred income taxes		(1,088)		(1,012)
Derivative instruments		224		241
Out-of-market contracts, net of accumulated amortization of $0 and $562		1,051		1,133
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent		4
Other non-current liabilities		535		561
Total non-current liabilities		11,422		12,280
Total Liabilities		15,390		17,111
Redeemable noncontrolling interest in subsidiaries		0		0
Redeemable Noncontrolling Interest, Equity, Other, Carrying Amount		29		19
Stockholders' Equity		9,299		10,741
Total Liabilities and Stockholders' Equity		24,718		27,871
NRG Energy, Inc.
Current Assets
Cash and cash equivalents		693		643		1,328		751
Funds deposited by counterparties		0		0
Restricted cash		0		1
Accounts receivable - trade, net		2		6
Inventory		0		0
Derivative instruments		0		0
Derivative, Collateral, Right to Reclaim Cash		0		0
Renewable energy grant receivable		0		1
Disposal Group, Including Discontinued Operation, Other Assets, Current		0		0
Prepaid Expense and Other Assets, Current Less Accounts Receivable Affiliate		71		75
Due from Affiliate, Current		571		(5,991)
Total current assets		1,337		(5,265)
Net Property, Plant and Equipment		219		171
Other Assets
Investment in subsidiaries		11,039		23,410
Equity investments in affiliates		1		0
Notes receivable, less current portion		7		109
Goodwill		0		0
Intangible assets, net		2		2
Nuclear decommissioning trust fund		0		0
Deferred income taxes		(642)		1,105
Derivative instruments		0		1
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent		0		0
Other non-current assets		385		417
Total other assets		10,792		25,044
Total assets		12,348		19,950
Current Liabilities
Current portion of long-term debt and capital leases		19		127
Accounts payable		39		46
Accounts payable - affiliate		(929)		(598)
Derivative instruments		0		$ 0
Deferred Tax Liabilities, Net, Current
Cash collateral received in support of energy risk management activities		0		$ 0
Accrued Expenses and Other Current Liabilities				418
Accrued interest expense		147
Other accrued expenses		295
Disposal Group, Including Discontinued Operation, Liabilities, Current		0
Other current liabilities		7
Total current liabilities		(422)		(7)
Other Liabilities
Long-term debt and capital leases		8,185		8,276
Nuclear decommissioning reserve		0		0
Nuclear decommissioning trust liability		0		0
Postretirement and other benefit obligations		152		216
Deferred income taxes		928		(10)
Derivative instruments		0		0
Out-of-market contracts, net of accumulated amortization of $0 and $562		0		0
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent		0
Other non-current liabilities		47		98
Total non-current liabilities		9,312		8,580
Total Liabilities		8,890		8,573
Redeemable noncontrolling interest in subsidiaries		302		291
Redeemable Noncontrolling Interest, Equity, Other, Carrying Amount		0		0
Stockholders' Equity		3,156		11,086
Total Liabilities and Stockholders' Equity		12,348		19,950
Eliminations
Current Assets
Cash and cash equivalents		0	[1],[2]	0	[2],[3],[4]	$ 0	[4],[5]	$ 0	[5]
Funds deposited by counterparties		0	[1]	0	[3]
Restricted cash		0	[1]	0	[3]
Accounts receivable - trade, net		0	[1]	0	[3]
Inventory		0	[1]	0	[3]
Derivative instruments		(158)	[1]	(441)	[3]
Derivative, Collateral, Right to Reclaim Cash		0	[1]	0	[3]
Renewable energy grant receivable		0	[1]	0	[3]
Disposal Group, Including Discontinued Operation, Other Assets, Current		0	[1]	0	[3]
Prepaid Expense and Other Assets, Current Less Accounts Receivable Affiliate		0	[1]	0	[3]
Due from Affiliate, Current		(1,222)	[1]	(3,437)	[3]
Total current assets		(1,380)	[1]	(3,878)	[3]
Net Property, Plant and Equipment		(27)	[1]	(25)	[3]
Other Assets
Investment in subsidiaries		(14,125)	[1]	(25,843)	[3]
Equity investments in affiliates		(102)	[1]	(102)	[3]
Notes receivable, less current portion		0	[1]	(98)	[3]
Goodwill		0	[1]	0	[3]
Intangible assets, net		(6)	[1]	(6)	[3]
Nuclear decommissioning trust fund		0	[1]	0	[3]
Deferred income taxes		0	[1]	0	[3]
Derivative instruments		(32)	[1]	(51)	[3]
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent		0	[1]	0	[3]
Other non-current assets		0	[1]	0	[3]
Total other assets		(14,265)	[1]	(26,100)	[3]
Total assets		(15,672)	[1]	(30,003)	[3]
Current Liabilities
Current portion of long-term debt and capital leases		0	[1]	(98)	[3]
Accounts payable		0	[1]	0	[3]
Accounts payable - affiliate		(1,222)	[1]	(3,437)	[3]
Derivative instruments		(158)	[1]	(441)	[3]
Deferred Tax Liabilities, Net, Current	[3]			0
Cash collateral received in support of energy risk management activities		0	[1]	0	[3]
Accrued Expenses and Other Current Liabilities	[3]			0
Accrued interest expense	[1]	(1)
Other accrued expenses	[1]	0
Disposal Group, Including Discontinued Operation, Liabilities, Current	[1]	0
Other current liabilities	[1]	0
Total current liabilities		(1,381)	[1]	(3,976)	[3]
Other Liabilities
Long-term debt and capital leases		0	[1]	0	[3]
Nuclear decommissioning reserve		0	[1]	0	[3]
Nuclear decommissioning trust liability		0	[1]	0	[3]
Postretirement and other benefit obligations		0	[1]	0	[3]
Deferred income taxes		0	[1]	0	[3]
Derivative instruments		(32)	[1]	(51)	[3]
Out-of-market contracts, net of accumulated amortization of $0 and $562		0	[1]	0	[3]
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent	[1]	0
Other non-current liabilities		0	[1]	0	[3]
Total non-current liabilities		(32)	[1]	(51)	[3]
Total Liabilities		(1,413)	[1]	(4,027)	[3]
Redeemable noncontrolling interest in subsidiaries		0	[1]	0	[3]
Redeemable Noncontrolling Interest, Equity, Other, Carrying Amount		0	[1]	0	[3]
Stockholders' Equity		(14,259)	[1]	(25,976)	[3]
Total Liabilities and Stockholders' Equity		$ (15,672)	[1]	$ (30,003)	[3]
Convertible Preferred Stock [Member]
Condensed Financial Statements
Preferred Stock, Dividend Rate Amended, Percentage		2.822%		2.822%
[1]	All significant intercompany transactions have been eliminated in consolidation.
[2]	All significant intercompany transactions have been eliminated in consolidation.
[3]	All significant intercompany transactions have been eliminated in consolidation.
[4]	All significant intercompany transactions have been eliminated in consolidation.
[5]	All significant intercompany transactions have been eliminated in consolidation.

Condensed Consolidating Fina141

Condensed Consolidating Financial Information (Statements of Cash Flows) (Details 5) - USD ($) $ in Millions		3 Months Ended												12 Months Ended
		Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015		Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Cash Flows from Operating Activities
Net (Loss)/Income		$ (6,358)		$ 67	$ (9)	$ (136)		$ 97		$ 182	$ (80)	$ (67)		$ (6,436)		$ 132		$ (352)
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Proceeds from Equity Method Investment, Dividends or Distributions														73		87		77
Equity in earnings of unconsolidated affiliates														(36)		(38)		(7)
Depreciation and amortization														1,566		1,523		1,256
Provision for bad debts														64		64		67
Amortization of nuclear fuel														45		46		36
Amortization of Financing Costs and Discounts														(11)		(12)		(33)
Gains Losses on Extinguishment of Debt, Non Cash Portion														(75)		25		(15)
Amortization of Intangibles and Out of Market Contracts														81		64		49
Share-based Compensation														41		42		38
Gain on post retirement benefits curtailment and sales of assets														(7)		(4)		(3)
Changes in nuclear decommissioning trust liability														(2)		19		15
Impairment Charges and Asset Write Downs														5,086		97		558
Changes in Derivatives														233		(61)		164
Changes in Collateral Deposits Supporting Energy Risk Management Activities														(381)		146		(47)
Increase (Decrease) in Income Taxes														1,326		(154)		(67)
Other assets and liabilities														(258)		(320)		(513)
Net Cash Provided by Operating Activities														1,309		1,510		1,270
Cash Flows from Investing Activities
Intercompany Loans to Receipts from Subsidiaries														0		0		0
Payments to Acquire Business Two, Net of Cash Acquired														0
Acquisition of businesses, net of cash acquired														(31)		(2,936)		(494)
Capital expenditures														(1,283)		(909)		(1,987)
Decrease/(increase) in restricted cash, net														8		57		(22)
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects														35		(206)		(26)
(Increase)/decrease in notes receivable														18		25		(11)
Proceeds from Renewable Energy Grants														82		916		55
Purchases of emission allowances, net of proceeds														41		(16)		5
Payments to Acquire Available-for-sale Securities														(629)		(619)		(514)
Proceeds from sales of nuclear decommissioning trust fund securities														631		600		488
Proceeds/(purchases) from sale of assets, net														27		203		13
(Investments in)/proceeds from sales of unconsolidated affiliates, net														(395)		(103)		0
Other														11		85		(35)
Net Cash Used by Investing Activities														(1,485)		(2,903)		(2,528)
Cash Flows from Financing Activities
(Payments)/proceeds from intercompany loans														0		0		0
Payments to Acquire Business Three, Net of Cash Acquired														0
Payment of intercompany dividends														(201)
Payment of dividends to preferred and common stockholders														(201)		(196)		(154)
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements														196		9		267
Payment for treasury stock														(437)		(39)		(25)
Sales proceeds and other contributions from noncontrolling interests in subsidiaries														647		819		531
Proceeds from issuance of common stock, net of issuance costs														(1)		(21)		(16)
Proceeds from issuance of long-term debt														(1,004)		(4,563)		(1,777)
Payment of debt issuance and hedging costs														(21)		(67)		(50)
Payments for short and long-term debt														(1,599)		(3,827)		(935)
Proceeds from (Payments for) Other Financing Activities														(22)		(18)		0
Net Cash Provided by Financing Activities														(432)		1,265		1,427
Effect of exchange rate changes on cash and cash equivalents														10		(10)		(2)
Net Increase/(Decrease) in Cash and Cash Equivalents														(598)		(138)		167
Cash and Cash Equivalents at Beginning of Period						2,116						2,254		2,116		2,254		2,087
Cash and Cash Equivalents at End of Period		1,518						2,116						1,518		2,116		2,254
Guarantor Subsidiaries
Cash Flows from Operating Activities
Net (Loss)/Income														(2,586)		924		121
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Proceeds from Equity Method Investment, Dividends or Distributions														3		0		51
Equity in earnings of unconsolidated affiliates														(8)		(13)		11
Depreciation and amortization														787		801		837
Provision for bad debts														58		64		67
Amortization of nuclear fuel														45		46		36
Amortization of Financing Costs and Discounts														0		0		0
Gains Losses on Extinguishment of Debt, Non Cash Portion														0		0		0
Amortization of Intangibles and Out of Market Contracts														52		65		100
Share-based Compensation														0		0		0
Gain on post retirement benefits curtailment and sales of assets														0		0		0
Changes in nuclear decommissioning trust liability														(2)		19		15
Impairment Charges and Asset Write Downs														4,655		0		459
Changes in Derivatives														264		(149)		197
Changes in Collateral Deposits Supporting Energy Risk Management Activities														(360)
Increase (Decrease) in Income Taxes														(1,092)		242		(58)
Other assets and liabilities														(8,744)		787		482
Net Cash Provided by Operating Activities														(6,928)		2,786		2,318
Cash Flows from Investing Activities
Intercompany Loans to Receipts from Subsidiaries														7,183		(2,523)		(1,722)
Payments to Acquire Business Two, Net of Cash Acquired														0
Acquisition of businesses, net of cash acquired														0		0		0
Capital expenditures														(316)		(252)		(528)
Decrease/(increase) in restricted cash, net														(1)		0		(1)
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects														0		0		0
(Increase)/decrease in notes receivable														0		0		2
Proceeds from Renewable Energy Grants														0		0		0
Purchases of emission allowances, net of proceeds														41		(16)		5
Payments to Acquire Available-for-sale Securities														(629)		(619)		(514)
Proceeds from sales of nuclear decommissioning trust fund securities														631		600		488
Proceeds/(purchases) from sale of assets, net														0		0		13
(Investments in)/proceeds from sales of unconsolidated affiliates, net														1		0
Other														0		0		(4)
Net Cash Used by Investing Activities														6,910		(2,810)		(2,261)
Cash Flows from Financing Activities
(Payments)/proceeds from intercompany loans														0		0		0
Payments to Acquire Business Three, Net of Cash Acquired														0
Payment of intercompany dividends														0
Payment of dividends to preferred and common stockholders																0		0
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements														0		0		(79)
Payment for treasury stock														0		0		0
Sales proceeds and other contributions from noncontrolling interests in subsidiaries														0		0		0
Proceeds from issuance of common stock, net of issuance costs														0		0		0
Proceeds from issuance of long-term debt														0		0		0
Payment of debt issuance and hedging costs														0		0		0
Payments for short and long-term debt														0		0		0
Proceeds from (Payments for) Other Financing Activities														0		(14)
Net Cash Provided by Financing Activities														0		(14)		(79)
Effect of exchange rate changes on cash and cash equivalents														0		0		0
Net Increase/(Decrease) in Cash and Cash Equivalents														(18)		(38)		(22)
Cash and Cash Equivalents at Beginning of Period						18						56		18		56		78
Cash and Cash Equivalents at End of Period		0						18						0		18		56
Non-Guarantor Subsidiaries
Cash Flows from Operating Activities
Net (Loss)/Income														(351)		426		45
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Proceeds from Equity Method Investment, Dividends or Distributions														91		87		26
Equity in earnings of unconsolidated affiliates														(37)		(33)		(22)
Depreciation and amortization														759		706		407
Provision for bad debts														3		0		0
Amortization of nuclear fuel														0		0		0
Amortization of Financing Costs and Discounts														(37)		(40)		(9)
Gains Losses on Extinguishment of Debt, Non Cash Portion														(56)		8		(27)
Amortization of Intangibles and Out of Market Contracts														29		(1)		(51)
Share-based Compensation														0		0		0
Gain on post retirement benefits curtailment and sales of assets														(21)		(4)		(3)
Changes in nuclear decommissioning trust liability														0		0		0
Impairment Charges and Asset Write Downs														400		119		99
Changes in Derivatives														(31)		88		(33)
Changes in Collateral Deposits Supporting Energy Risk Management Activities														(21)
Increase (Decrease) in Income Taxes														(237)		(115)		292
Other assets and liabilities														(950)		(973)		(941)
Net Cash Provided by Operating Activities														(459)		268		(217)
Cash Flows from Investing Activities
Intercompany Loans to Receipts from Subsidiaries														1,258		(685)		7
Payments to Acquire Business Two, Net of Cash Acquired														(698)
Acquisition of businesses, net of cash acquired														(31)		(25)		(179)
Capital expenditures														(908)		(619)		(1,413)
Decrease/(increase) in restricted cash, net														9		57		(22)
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects														34		(209)		(31)
(Increase)/decrease in notes receivable														18		25		(7)
Proceeds from Renewable Energy Grants														82		916		55
Purchases of emission allowances, net of proceeds														0		0		0
Payments to Acquire Available-for-sale Securities														0		0		0
Proceeds from sales of nuclear decommissioning trust fund securities														0		0		0
Proceeds/(purchases) from sale of assets, net														1		0		0
(Investments in)/proceeds from sales of unconsolidated affiliates, net														(357)		(25)
Other														11		85		(11)
Net Cash Used by Investing Activities														(581)		(480)		(1,601)
Cash Flows from Financing Activities
(Payments)/proceeds from intercompany loans														0		0		0
Payments to Acquire Business Three, Net of Cash Acquired														0
Payment of intercompany dividends														0
Payment of dividends to preferred and common stockholders																0		0
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements														196		9		346
Payment for treasury stock														0		0		0
Sales proceeds and other contributions from noncontrolling interests in subsidiaries														647		819		531
Proceeds from issuance of common stock, net of issuance costs														0		0		0
Proceeds from issuance of long-term debt														(953)		(1,182)		(1,292)
Payment of debt issuance and hedging costs														(21)		(39)		(21)
Payments for short and long-term debt														(1,353)		(1,160)		(716)
Proceeds from (Payments for) Other Financing Activities														(22)		(4)
Net Cash Provided by Financing Activities														400		807		1,432
Effect of exchange rate changes on cash and cash equivalents														10		(10)		(2)
Net Increase/(Decrease) in Cash and Cash Equivalents														(630)		585		(388)
Cash and Cash Equivalents at Beginning of Period						1,455						870		1,455		870		1,258
Cash and Cash Equivalents at End of Period		825						1,455						825		1,455		870
NRG Energy, Inc.
Cash Flows from Operating Activities
Net (Loss)/Income														(6,351)		149		(372)
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Proceeds from Equity Method Investment, Dividends or Distributions														0		0		0
Equity in earnings of unconsolidated affiliates														0		0		0
Depreciation and amortization														20		16		12
Provision for bad debts														3		0		0
Amortization of nuclear fuel														0		0		0
Amortization of Financing Costs and Discounts														26		28		(24)
Gains Losses on Extinguishment of Debt, Non Cash Portion														(19)		17		12
Amortization of Intangibles and Out of Market Contracts														0		0		0
Share-based Compensation														41		42		38
Gain on post retirement benefits curtailment and sales of assets														14		0		0
Changes in nuclear decommissioning trust liability														0		0		0
Impairment Charges and Asset Write Downs														31		0		0
Changes in Derivatives														0		0		0
Changes in Collateral Deposits Supporting Energy Risk Management Activities														0
Increase (Decrease) in Income Taxes														2,655		(281)		(301)
Other assets and liabilities														12,276		(4,723)		(1,911)
Net Cash Provided by Operating Activities														8,696		(4,752)		(2,546)
Cash Flows from Investing Activities
Intercompany Loans to Receipts from Subsidiaries														0		3,208		1,715
Payments to Acquire Business Two, Net of Cash Acquired														0
Acquisition of businesses, net of cash acquired														0		(2,911)		(315)
Capital expenditures														(59)		(38)		(46)
Decrease/(increase) in restricted cash, net														0		0		1
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects														1		3		5
(Increase)/decrease in notes receivable														0		0		(6)
Proceeds from Renewable Energy Grants														0		0		0
Purchases of emission allowances, net of proceeds														0		0		0
Payments to Acquire Available-for-sale Securities														0		0		0
Proceeds from sales of nuclear decommissioning trust fund securities														0		0		0
Proceeds/(purchases) from sale of assets, net														26		203		0
(Investments in)/proceeds from sales of unconsolidated affiliates, net														(39)		(78)
Other														0		0		(20)
Net Cash Used by Investing Activities														(71)		387		1,334
Cash Flows from Financing Activities
(Payments)/proceeds from intercompany loans														(8,441)		3,208		1,715
Payments to Acquire Business Three, Net of Cash Acquired														698
Payment of intercompany dividends														(201)
Payment of dividends to preferred and common stockholders																(196)		(154)
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements														0		0		0
Payment for treasury stock														(437)		(39)		(25)
Sales proceeds and other contributions from noncontrolling interests in subsidiaries														0		0		0
Proceeds from issuance of common stock, net of issuance costs														(1)		(21)		(16)
Proceeds from issuance of long-term debt														(51)		(3,381)		(485)
Payment of debt issuance and hedging costs														0		(28)		(29)
Payments for short and long-term debt														(246)		(2,667)		(219)
Proceeds from (Payments for) Other Financing Activities														0		0
Net Cash Provided by Financing Activities														(8,575)		3,680		1,789
Effect of exchange rate changes on cash and cash equivalents														0		0		0
Net Increase/(Decrease) in Cash and Cash Equivalents														50		(685)		577
Cash and Cash Equivalents at Beginning of Period						643						1,328		643		1,328		751
Cash and Cash Equivalents at End of Period		693						643						693		643		1,328
Eliminations
Cash Flows from Operating Activities
Net (Loss)/Income														2,852	[1],[2]	(1,367)	[3],[4]	(146)	[5],[6]
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Proceeds from Equity Method Investment, Dividends or Distributions														(21)	[2]	0		0	[6]
Equity in earnings of unconsolidated affiliates														9	[1],[2]	8	[3],[4]	4	[5],[6]
Depreciation and amortization														0	[1],[2]	0	[3],[4]	0	[5],[6]
Provision for bad debts														0	[2]	0	[4]	0	[6]
Amortization of nuclear fuel														0	[2]	0	[4]	0	[6]
Amortization of Financing Costs and Discounts														0	[2]	0	[4]	0	[6]
Gains Losses on Extinguishment of Debt, Non Cash Portion														0	[2]	0	[4]	0	[6]
Amortization of Intangibles and Out of Market Contracts														0	[2]	0	[4]	0	[6]
Share-based Compensation														0	[2]	0	[4]	0	[6]
Gain on post retirement benefits curtailment and sales of assets														0	[2]	0	[4]	0	[6]
Changes in nuclear decommissioning trust liability														0	[2]	0	[4]	0	[6]
Impairment Charges and Asset Write Downs														0	[2]	(22)	[4]	0	[6]
Changes in Derivatives														0	[2]	0	[4]	0	[6]
Changes in Collateral Deposits Supporting Energy Risk Management Activities	[2]													0
Increase (Decrease) in Income Taxes														0	[2]	0	[4]	0	[6]
Other assets and liabilities														(2,840)	[2]	4,589	[4]	1,857	[6]
Net Cash Provided by Operating Activities														0	[2]	3,208	[4]	1,715	[6]
Cash Flows from Investing Activities
Intercompany Loans to Receipts from Subsidiaries														(8,441)	[2]	0	[4]	0	[6]
Payments to Acquire Business Two, Net of Cash Acquired	[2]													698
Acquisition of businesses, net of cash acquired														0	[2]	0	[4]	0	[6]
Capital expenditures														0	[2]	0	[4]	0	[6]
Decrease/(increase) in restricted cash, net														0	[2]	0	[4]	0	[6]
Increase Decrease in Restricted Cash to Support Equity Requirements for U.S. DOE Funded Projects														0	[2]	0	[4]	0	[6]
(Increase)/decrease in notes receivable														0	[2]	0	[4]	0	[6]
Proceeds from Renewable Energy Grants														0	[2]	0	[4]	0	[6]
Purchases of emission allowances, net of proceeds														0	[2]	0	[4]	0	[6]
Payments to Acquire Available-for-sale Securities														0	[2]	0	[4]	0	[6]
Proceeds from sales of nuclear decommissioning trust fund securities														0	[2]	0	[4]	0	[6]
Proceeds/(purchases) from sale of assets, net														0	[2]	0	[4]	0	[6]
(Investments in)/proceeds from sales of unconsolidated affiliates, net														0	[2]	0	[4]
Other														0	[2]	0	[4]	0	[6]
Net Cash Used by Investing Activities														(7,743)	[2]	0	[4]	0	[6]
Cash Flows from Financing Activities
(Payments)/proceeds from intercompany loans														8,441	[2]	(3,208)	[4]	(1,715)	[6]
Payments to Acquire Business Three, Net of Cash Acquired	[2]													(698)
Payment of intercompany dividends	[2]													0
Payment of dividends to preferred and common stockholders																0	[4]	0	[6]
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements														0	[2]	0	[4]	0	[6]
Payment for treasury stock														0	[2]	0	[4]	0	[6]
Sales proceeds and other contributions from noncontrolling interests in subsidiaries														0	[2]	0	[4]	0	[6]
Proceeds from issuance of common stock, net of issuance costs														0	[2]	0	[4]	0	[6]
Proceeds from issuance of long-term debt														0	[2]	0	[4]	0	[6]
Payment of debt issuance and hedging costs														0	[2]	0	[4]	0	[6]
Payments for short and long-term debt														0	[2]	0	[4]	0	[6]
Proceeds from (Payments for) Other Financing Activities														0	[2]	0	[4]
Net Cash Provided by Financing Activities														7,743	[2]	(3,208)	[4]	(1,715)	[6]
Effect of exchange rate changes on cash and cash equivalents														0	[2]	0	[4]	0	[6]
Net Increase/(Decrease) in Cash and Cash Equivalents														0	[2]	0	[4]	0	[6]
Cash and Cash Equivalents at Beginning of Period						$ 0	[2],[4],[7]					$ 0	[4],[6]	0	[2],[4],[7]	0	[4],[6]	0	[6]
Cash and Cash Equivalents at End of Period		$ 0	[2],[8]					$ 0	[2],[4],[7]					$ 0	[2],[8]	$ 0	[2],[4],[7]	$ 0	[4],[6]
[1]	All significant intercompany transactions have been eliminated in consolidation.
[2]	All significant intercompany transactions have been eliminated in consolidation.
[3]	All significant intercompany transactions have been eliminated in consolidation.
[4]	All significant intercompany transactions have been eliminated in consolidation.
[5]	All significant intercompany transactions have been eliminated in consolidation.
[6]	All significant intercompany transactions have been eliminated in consolidation.
[7]	All significant intercompany transactions have been eliminated in consolidation.
[8]	All significant intercompany transactions have been eliminated in consolidation.

VALUATION AND QUALIFYING ACC142

VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in Valuation and Qualifying Accounts
Balance at Beginning of Period		$ 2
Balance at End of Period		5	$ 2
Allowance for doubtful accounts, deducted from accounts receivable
Changes in Valuation and Qualifying Accounts
Balance at Beginning of Period		23	40	$ 32
Charged to Costs and Expenses		62	64	66
Charged to Other Accounts		0	0	0
Deductions	[1]	64	81	58
Balance at End of Period		21	23	40
Income tax valuation allowance, deducted from deferred tax assets
Changes in Valuation and Qualifying Accounts
Balance at Beginning of Period		265	291	191
Charged to Costs and Expenses		3,039	0	32
Charged to Other Accounts		271	(10)	68
Deductions		0	16	0
Balance at End of Period		$ 3,575	$ 265	$ 291
[1]	Represents principally net amounts charged as uncollectible.