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$ 231

$ 269

$ 288

$ 221

$ 1,009

$ 1,035

$ 968

Operating Costs and Expenses

326

308

323

334

303

185

Total operating costs and expenses

726

813

642

124

283

222

326

Other income, net

(3)

(9)

Interest expense

(306)

(284)

(267)

Total other expense, net

(234)

(221)

(242)

(1)

Less: Pre-acquisition net income (loss) of Drop Down Assets

(98)

(2)

(23)

(4)

Net (Loss) Income Excluding Pre-acquisition Net Income (Loss) of Drop Down Assets

(31)

Less: Net (loss) income attributable to noncontrolling interests

(15)

(51)

Net income attributable to NRG Yield, Inc.

$ (70)

$ 29

$ 28

$ (3)

(16)

Earnings Per Share Attributable to NRG Yield, Inc. Class A and Class C Common Stockholders

Earnings Per Share, Basic

$ (0.71)

$ 0.30

$ 0.29

$ (0.03)

Dividends Per Class A Common Share

$ 0.288

$ 0.28

$ 0.27

$ 0.26

Noncontrolling Interest [Member]

Less: Pre-acquisition net income (loss) of Drop Down Assets

(4)

Net (Loss) Income Excluding Pre-acquisition Net Income (Loss) of Drop Down Assets

(15)

(51)

$ 39

Net income attributable to NRG Yield, Inc.

$ (6)

$ 20

Earnings Per Share Attributable to NRG Yield, Inc. Class A and Class C Common Stockholders

Weighted average number of common shares outstanding — basic and diluted

Weighted Average Number of Shares Outstanding, Diluted

Weighted Average Number of Shares Outstanding, Basic

(Loss) Earnings per weighted average common share — basic and diluted

$ (0.16)

$ 0.58

$ 0.40

^[1]

Dividends Per Class A Common Share

$ (0.71)

$ 0.27

$ 0.26

$ (0.03)

$ 1.098

$ 0.945

$ 1.015

Net income attributable to NRG Yield, Inc.

$ (10)

$ 37

Earnings Per Share Attributable to NRG Yield, Inc. Class A and Class C Common Stockholders

Weighted average number of common shares outstanding — basic and diluted

Weighted Average Number of Shares Outstanding, Diluted

Weighted Average Number of Shares Outstanding, Basic

(Loss) Earnings per weighted average common share — basic and diluted

$ (0.16)

$ 0.58

Dividends Per Class A Common Share

$ (0.71)

$ 0.29

$ 0.28

$ (0.03)

$ 1.098

$ 0.945

$ 0.625

[1]	Net (loss) income attributable to NRG Yield, Inc. and basic and diluted (loss) earnings per share might not recalculate due to presenting values in millions rather than whole dollars.

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Comprehensive Income (Loss), net of tax
Net Income	$ (23)	$ 2	$ 72
Unrealized gain (loss) on derivatives, net of income tax (expense) benefit of ($7), $0, and $10	0	0	(21)
Mark-to-market of cash flow hedge accounting contracts	10	13	(7)
Other comprehensive income (loss)	10	13	(7)
Comprehensive (Loss) Income	(13)	15	65
Less: Pre-acquisition net income (loss) of Drop Down Assets	8	(4)	0
Less: Comprehensive (loss) income attributable to noncontrolling interests	(5)	(37)	50
Comprehensive (Loss) Income Attributable to NRG Yield, Inc.	$ (16)	$ 56	$ 15

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Unrealized gain/loss on derivatives, income tax benefit/(expense)	$ (2)	$ 0	$ 10

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	$ 148	$ 322
Restricted cash	168	176
Accounts receivable — trade	95	95
Inventory	39	39
Notes receivable — current	13	16
Prepayments and other current assets	19	22
Total current assets	482	670
Property, plant and equipment
Property, plant and equipment, net	5,204	5,554
Other Assets
Equity investments in affiliates	1,178	1,152
Intangible assets, net	1,228	1,303
Deferred income taxes	128	216
Other non-current assets	63	67
Total other assets	2,597	2,738
Total Assets	8,283	8,962
Current Liabilities
Current portion of long-term debt	306	323
Accounts payable	27	23
Accounts payable — affiliate	48	40
Derivative instruments	17	33
Accrued expenses and other current liabilities	88	86
Total current liabilities	486	505
Other Liabilities
Long-term debt	5,531	5,726
Due to Related Parties, Noncurrent	0	9
Derivative instruments	31	46
Other non-current liabilities	97	77
Total non-current liabilities	5,659	5,858
Total Liabilities	6,145	6,363
Stockholders' Equity
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued	0	0
Common Stock, Value, Issued	1	1
Additional Paid in Capital	1,843	1,879
Accumulated deficit	(69)	(2)
Accumulated other comprehensive loss	(28)	(28)
Noncontrolling interest	391	749
Total Stockholders' Equity	2,138	2,599
Total Liabilities and Stockholders’ Equity	$ 8,283	$ 8,962

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016	Jul. 22, 2013
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	10,000,000	10,000,000	10,000,000
Preferred Stock, Shares Issued	0	0

Consolidated Statements Of Cash Flows $ in Millions	12 Months Ended
Consolidated Statements Of Cash Flows $ in Millions	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Cash Flows from Operating Activities
Net Income	$ (23)	$ 2	$ 72
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of unconsolidated affiliates	71	60	31
Distributions from unconsolidated affiliates	72	58	60
Depreciation and amortization	334	303	303
Amortization of financing costs and debt discounts	25	20	16
Amortization of intangibles and out-of-market contracts	70	76	55
Loss on debt extinguishment	3	0	9
Change in deferred income taxes	72	(1)	12
Impairment losses	44	185	1
Changes in derivative instruments	(16)	(15)	(44)
Loss on disposal of asset components	(16)	(6)	(3)
Changes in prepaid and accrued capacity payments	4	8	12
Changes in other working capital	(6)	11	(19)
Net Cash Provided by Operating Activities	516	577	425
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired	0	0	(37)
Acquisition of Drop Down Assets, net of cash acquired	250	77	698
Capital expenditures	(31)	(20)	(29)
Cash receipts from notes receivable	(17)	(17)	(17)
Return of investment from unconsolidated affiliates	47	28	42
Investments in unconsolidated affiliates	(73)	(83)	(402)
Other	7	4	9
Net Cash Used in Investing Activities	(283)	(131)	(1,098)
Cash Flows from Financing Activities
Net contributions from noncontrolling interests	13	5	122
Net distributions and return of capital to NRG prior to the acquisition of Drop Down Assets	(20)	(184)	(79)
Proceeds from the issuance of common stock	34	0	599
Payments of dividends and distributions	(202)	(173)	(139)
Proceeds from the revolving credit facility	55	60	551
Payments for the revolving credit facility	0	(366)	(245)
Proceeds from issuance of long-term debt	41	740	293
Payments of debt issuance costs	(4)	(15)	(13)
Payments for long-term debt	(332)	(269)	(735)
Net Cash Provided by Financing Activities	(415)	(202)	354
Net (Decrease) Increase in Cash and Cash Equivalents	(182)	244	(319)
Cash, Cash Equivalents and Restricted Cash at End of Period	148	322	111
Interest paid, net of amount capitalized	(297)	(271)	(279)
Additions to fixed assets for accrued capital expenditures	4	3	3
Decrease to fixed assets for deferred tax asset	0	0	19
Non-cash adjustment for change in tax basis of assets	(20)	44	38
Non-cash return of capital and distributions to NRG, net of contributions	2	(65)	9
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	$ 316	$ 498	$ 254

Consolidated Statements of Stockholders Equity - USD ($)	Total	Preferred Stock [Member]	Common Stock	Additional Paid-in Capital [Member]	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest [Member]
Statement of Stockholders' Equity
Total Stockholders' Equity \| Scenario, Previously Reported [Member]	$ 2,844,000,000	$ 0	$ 0	$ 1,240,000,000	$ 3,000,000	$ (9,000,000)	$ 1,610,000,000
Total Stockholders' Equity	2,906,000,000	0	0	1,240,000,000	3,000,000	(9,000,000)	1,672,000,000
Net Assets Acquired, Drop Down Assets	62,000,000	0	0	0	0	0	62,000,000
Net Income Excluding Pre-acquisition Net (Loss) Income of Drop Down Assets	72,000,000	0	0	0	33,000,000	0	39,000,000
Less: Pre-acquisition net income (loss) of Drop Down Assets	0
Unrealized gain/(loss) on derivatives	(7,000,000)	0	0	0	0	(18,000,000)	11,000,000
Gross Payment to Acquire Business under Common Control	(698,000,000)	0	0	0	0	0	(698,000,000)
Payment to Acquire Business under Common Control	(698,000,000)
Net contributions from noncontrolling interests	122,000,000	0	0	0	0	0	122,000,000
Noncontrolling Interest, Increase from Business Combination	74,000,000	0	0	0	0	0	74,000,000
Non-cash return of capital and distributions to NRG, net of contributions	(9,000,000)	0	0	0	0	0	(9,000,000)
Payment of capital distributions and returns of capital, net of capital contributions	(79,000,000)	0	0	0	0	0	(79,000,000)
Share-based Compensation	1,000,000	0	0	1,000,000	0	0	0
Proceeds from the issuance of common stock	599,000,000	0	1,000,000	598,000,000	0	0	0
Non-cash adjustment for change in tax basis of assets	38,000,000	0	0	38,000,000	0	0	0
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt	23,000,000	0	0	23,000,000	0	0	0
Payments of Ordinary Dividends, Common Stock	(139,000,000)	0	0	(45,000,000)	(24,000,000)	0	(70,000,000)
Total Stockholders' Equity	2,903,000,000	0	1,000,000	1,855,000,000	12,000,000	(27,000,000)	1,062,000,000
Net Income Excluding Pre-acquisition Net (Loss) Income of Drop Down Assets	6,000,000	0	0	0	57,000,000	0	(51,000,000)
Less: Pre-acquisition net income (loss) of Drop Down Assets	(4,000,000)	0	0	0	0	0	(4,000,000)
Unrealized gain/(loss) on derivatives	13,000,000	0	0	0	0	(1,000,000)	14,000,000
Payment to Acquire Business under Common Control	(77,000,000)	0	0	0	0	0	(77,000,000)
Net contributions from noncontrolling interests	5,000,000	0	0	0	0	0	5,000,000
Non-cash return of capital and distributions to NRG, net of contributions	65,000,000	0	0	0	0	0	65,000,000
Payment of capital distributions and returns of capital, net of capital contributions	(184,000,000)	0	0	0	0	0	(184,000,000)
Share-based Compensation	1,000,000	0	0	1,000,000	0	0	0
Proceeds from the issuance of common stock	0
Non-cash adjustment for change in tax basis of assets	44,000,000	0	0	44,000,000	0	0	0
Payments of Ordinary Dividends, Common Stock	(173,000,000)	0	0	(21,000,000)	(71,000,000)	0	(81,000,000)
Total Stockholders' Equity \| Scenario, Previously Reported [Member]	2,539,000,000
Total Stockholders' Equity	2,599,000,000	0	1,000,000	1,879,000,000	(2,000,000)	(28,000,000)	749,000,000
Net Income Excluding Pre-acquisition Net (Loss) Income of Drop Down Assets	(31,000,000)	0	0	0	(16,000,000)	0	(15,000,000)
Less: Pre-acquisition net income (loss) of Drop Down Assets	8,000,000	0	0	0	0	0	8,000,000
Unrealized gain/(loss) on derivatives	10,000,000	0	0	0	0	0	10,000,000
Income Tax Effects Allocated Directly to Equity, Cumulative Effect of Change in Accounting Principle	5,000,000	0	0	0	5,000,000	0	0
Payment to Acquire Business under Common Control	(250,000,000)	0	0	0	0	0	(250,000,000)
Business Combination, Contingent Consideration, Liability	(8,000,000)	0	0	0	0	0	(8,000,000)
Net contributions from noncontrolling interests	13,000,000
Proceeds from Noncontrolling Interests	11,000,000	0	0	0	0	0	11,000,000
Non-cash return of capital and distributions to NRG, net of contributions	(2,000,000)	0	0	0	0	0	(2,000,000)
Payment of capital distributions and returns of capital, net of capital contributions	(18,000,000)	0	0	0	0	0	(18,000,000)
Share-based Compensation	2,000,000	0	0	2,000,000	0	0	0
Proceeds from the issuance of common stock	34,000,000	0	0	34,000,000	0	0	0
Non-cash adjustment for change in tax basis of assets	(20,000,000)	0	0	(20,000,000)	0	0	0
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt	23,000,000
Payments of Ordinary Dividends, Common Stock	(202,000,000)	0	0	(52,000,000)	(56,000,000)	0	(94,000,000)
Total Stockholders' Equity	$ 2,138,000,000	$ 0	$ 1,000,000	$ 1,843,000,000	$ (69,000,000)	$ (28,000,000)	$ 391,000,000

Schedule 1 - Yield, Inc,'s Financial Statements NRG Yield PL - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Expenses	$ 326	$ 308	$ 323
Interest Expense	(306)	(284)	(267)
Total other expense, net	(234)	(221)	(242)
Income Before Income Taxes	49	1	84
Net Income	(23)	2	72
Income tax expense (benefit)	72	(1)	12
Less: Net (loss) income attributable to noncontrolling interests	(15)	(51)	39
Less: Pre-acquisition net income (loss) of Drop Down Assets	8	(4)	0
Net income attributable to NRG Yield, Inc.	(16)	57	33
NRG Yield, Inc. [Member]
Operating Expenses	1	2	2
Equity in Earnings of Consolidated Subsidiaries	62	15	95
Interest Expense	(12)	(12)	(9)
Total other expense, net	50	3	86
Income Before Income Taxes	49	1	84
Net Income	(23)	2	72
Income tax expense (benefit)	72	(1)	12
Less: Net (loss) income attributable to noncontrolling interests	(15)	(51)	39
Less: Pre-acquisition net income (loss) of Drop Down Assets	8	(4)	0
Net income attributable to NRG Yield, Inc.	$ (16)	$ 57	$ 33

Schedule 1 - Yield, Inc,'s Financial Statements NRG Yield BS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Cash and cash equivalents	$ 148,000	$ 322,000
Deferred Tax Assets, Gross	128,000	216,000
Total Assets	8,283,000	8,962,000
Long-term Debt	5,914,000	6,149,000
Other non-current liabilities	97,000	77,000
Total Liabilities	6,145,000	6,363,000
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued	0	0
Common Stock, Value, Issued	1,000	1,000
Additional Paid in Capital	1,843,000	1,879,000
Accumulated deficit	(69,000)	(2,000)
Accumulated other comprehensive loss	(28,000)	(28,000)
Noncontrolling interest	391,000	749,000
Total Stockholders' Equity	2,138,000	2,599,000
Total Liabilities and Stockholders’ Equity	$ 8,283,000	$ 8,962,000
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	10,000,000	10,000,000
Preferred Stock, Shares Issued	0	0
NRG Yield, Inc. [Member]
Cash and cash equivalents	$ 2,000	$ 1,000
Investments in subsidiaries	2,008,000	2,364,000
Notes Receivable, Related Parties	618,000	618,000
Deferred Tax Assets, Gross	128,000	216,000
Total Assets	2,756,000	3,199,000
Other Liabilities, Current	2,000	2,000
Long-term Debt	610,000	598,000
Other non-current liabilities	6,000	0
Total Liabilities	618,000	600,000
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued	0	0
Common Stock, Value, Issued	1,000	1,000
Additional Paid in Capital	1,843,000	1,879,000
Accumulated deficit	(69,000)	(2,000)
Accumulated other comprehensive loss	(28,000)	(28,000)
Noncontrolling interest	391,000	749,000
Total Stockholders' Equity	2,138,000	2,599,000
Total Liabilities and Stockholders’ Equity	$ 2,756,000	$ 3,199,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	10,000,000	10,000,000
Preferred Stock, Shares Issued	0	0
NRG Yield, Inc. [Member] \| Common Class A [Member]
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	500,000,000	500,000,000
Common Stock, Shares, Issued	34,586,250	34,586,250
NRG Yield, Inc. [Member] \| Common Class B [Member]
Common Stock, Shares Authorized	500,000,000	500,000,000
Common Stock, Shares, Issued	42,738,750	42,738,750
NRG Yield, Inc. [Member] \| Common Class C [Member]
Common Stock, Shares Authorized	500,000,000	500,000,000
Common Stock, Shares, Issued	64,717,087	62,784,250
NRG Yield, Inc. [Member] \| Common Class D [Member]
Common Stock, Shares Authorized	500,000,000	500,000,000
Common Stock, Shares, Issued	42,738,750	42,738,750
NRG Yield [Member]
Cash and cash equivalents	$ 2,000	$ 1,000

Schedule 1 - Yield, Inc,'s Financial Statements NRG Yield CF - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Income	$ 283,000	$ 222,000	$ 326,000
Net Cash Provided by (Used in) Operating Activities	516,000	577,000	425,000
Proceeds from Issuance of Long-term Debt	41,000	740,000	293,000
Net Cash Used in Investing Activities	(283,000)	(131,000)	(1,098,000)
Proceeds from the issuance of common stock	34,000	0	599,000
Payments of Ordinary Dividends, Common Stock	(202,000)	(173,000)	(139,000)
Net Cash Provided by Financing Activities	(415,000)	(202,000)	354,000
Cash and cash equivalents	148,000	322,000	111,000
NRG Yield [Member]
Net Cash Provided by (Used in) Operating Activities	0	(5,000)	2,000
Investment in consolidated subsidiaries	(33,000)	5,000	(600,000)
Proceeds from Issuance of Long-term Debt	0	0	288,000
Increase (Decrease) in Notes Receivable, Related Parties	0	0	(281,000)
Net Cash Used in Investing Activities	(33,000)	5,000	(881,000)
Proceeds from the issuance of common stock	34,000	0	599,000
Payments of Financing Costs	0	0	(7,000)
Proceeds from Contributions from Affiliates	108,000	92,000	69,000
Payments of Ordinary Dividends, Common Stock	(108,000)	(92,000)	(69,000)
Net Cash Provided by Financing Activities	34,000	0	880,000
Net Increase (Decrease) in Cash and Cash Equivalents	1,000	0	1,000
Cash and cash equivalents	$ 2,000	$ 1,000	$ 1,000	$ 0

Schedule 1 - Yield, Inc,'s Financial Statements Footnotes - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Nature of Business [Line Items]
Payments of Capital Distribution	$ 20	$ 184	$ 79
Sale of Stock, Number of Shares Issued in Transaction	1,921,866
Proceeds from the issuance of common stock	$ 34	0	599
NRG Yield [Member]
Nature of Business [Line Items]
Proceeds from the issuance of common stock	34	0	599
NRG Yield LLC [Member] \| NRG Yield, Inc. [Member]
Nature of Business [Line Items]
Payments of Capital Distribution	$ 108	$ 92	$ 69

Nature of Business

12 Months Ended

Dec. 31, 2017

Nature of Business Disclosure [Abstract]

Nature of Business

The Company was formed by NRG as a Delaware corporation on December 20, 2012 and closed its initial public offering on July 22, 2013. In connection with its initial public offering, the Company's shares of Class A common stock began trading on the New York Stock Exchange under the symbol “NYLD.”

The Company is the sole managing member of NRG Yield LLC and operates and controls all of its business and affairs and consolidates the financial results of NRG Yield LLC and its subsidiaries. NRG Yield LLC is a holding company for the companies that directly and indirectly own and operate the Company's business. As a result of the current ownership of the Class B common stock and Class D common stock, NRG continues at the present time to control the Company, and the Company in turn, as the sole managing member of NRG Yield LLC, controls NRG Yield LLC and its subsidiaries.

The following table represents the structure of the Company as of December 31, 2017:

On July 12, 2017, NRG announced that it had adopted and initiated a three-year, three-part improvement plan, or the NRG Transformation Plan. As part of the NRG Transformation Plan, NRG announced that it is exploring strategic alternatives for its renewables platform and its interest in the Company. NRG, through its holdings of Class B common stock and Class D common stock, has a 55.1% voting interest in the Company and receives distributions from NRG Yield LLC through its ownership of Class B units and Class D units.

On February 6, 2018, Global Infrastructure Partners, or GIP, entered into a purchase and sale agreement with NRG, or the NRG Transaction, for the acquisition of NRG's full ownership interests in the Company and NRG's renewable development and operations platform. The NRG Transaction is subject to certain closing conditions, including customary legal and regulatory approvals. The Company expects the NRG Transaction to close in the second half of 2018. NRG is the Company's controlling stockholder and the Company has been highly dependent on NRG for, among other things, growth opportunities and management and administration services. See Part I, Item 1A, Risk Factors for risks related to the Strategic Sponsorship with GIP and the Company's relationship with NRG.

As of December 31, 2017, the Company's operating assets are comprised of the following projects:



Projects	Percentage Ownership		Net Capacity (MW) ^(a)	Offtake Counterparty	Expiration
Conventional
El Segundo	100	%	550	Southern California Edison	2023
GenConn Devon	50	%	95	Connecticut Light & Power	2040
GenConn Middletown	50	%	95	Connecticut Light & Power	2041
Marsh Landing	100	%	720	Pacific Gas and Electric	2023
Walnut Creek	100	%	485	Southern California Edison	2023
			1,945
Utility Scale Solar
Agua Caliente	16	%	46	Pacific Gas and Electric	2039
Alpine	100	%	66	Pacific Gas and Electric	2033
Avenal	50	%	23	Pacific Gas and Electric	2031
Avra Valley	100	%	26	Tucson Electric Power	2032
Blythe	100	%	21	Southern California Edison	2029
Borrego	100	%	26	San Diego Gas and Electric	2038
CVSR	100	%	250	Pacific Gas and Electric	2038
Desert Sunlight 250	25	%	63	Southern California Edison	2034
Desert Sunlight 300	25	%	75	Pacific Gas and Electric	2039
Kansas South	100	%	20	Pacific Gas and Electric	2033
Roadrunner	100	%	20	El Paso Electric	2031
TA High Desert	100	%	20	Southern California Edison	2033
Utah Solar Portfolio^(b)(e)	50	%	265	PacifiCorp	2036
			921
Distributed Solar
Apple I LLC Projects	100	%	9	Various	2032
AZ DG Solar Projects	100	%	5	Various	2025-2033
SPP Projects	100	%	25	Various	2026-2037
Other DG Projects	100	%	13	Various	2023-2039
			52
Wind
Alta I	100	%	150	Southern California Edison	2035
Alta II	100	%	150	Southern California Edison	2035
Alta III	100	%	150	Southern California Edison	2035
Alta IV	100	%	102	Southern California Edison	2035
Alta V	100	%	168	Southern California Edison	2035
Alta X^(b)	100	%	137	Southern California Edison	2038
Alta XI ^(b)	100	%	90	Southern California Edison	2038
Buffalo Bear	100	%	19	Western Farmers Electric Co-operative	2033
Crosswinds ^(b)(f)	99	%	21	Corn Belt Power Cooperative	2027
Elbow Creek ^(b)(f)	100	%	122	NRG Power Marketing LLC	2022
Elkhorn Ridge ^(b)(f)	66.7	%	54	Nebraska Public Power District	2029
Forward ^(b)(f)	100	%	29	Constellation NewEnergy, Inc.	2022
Goat Wind ^(b)(f)	100	%	150	Dow Pipeline Company	2025
Hardin ^(b)(f)	99	%	15	Interstate Power and Light Company	2027



Projects	Percentage Ownership		Net Capacity (MW) ^(a)	Offtake Counterparty	Expiration
Laredo Ridge	100	%	80	Nebraska Public Power District	2031
Lookout ^(b)(f)	100	%	38	Southern Maryland Electric Cooperative	2030
Odin ^(b)(f)	99.9	%	20	Missouri River Energy Services	2028
Pinnacle	100	%	55	Maryland Department of General Services and University System of Maryland	2031
San Juan Mesa ^(b)(f)	75	%	90	Southwestern Public Service Company	2025
Sleeping Bear ^(b)(f)	100	%	95	Public Service Company of Oklahoma	2032
South Trent	100	%	101	AEP Energy Partners	2029
Spanish Fork ^(b)(f)	100	%	19	PacifiCorp	2028
Spring Canyon II ^(b)	90.1	%	29	Platte River Power Authority	2039
Spring Canyon III ^(b)	90.1	%	25	Platte River Power Authority	2039
Taloga	100	%	130	Oklahoma Gas & Electric	2031
Wildorado ^(b)(f)	100	%	161	Southwestern Public Service Company	2027
			2,200
Thermal
NRG Energy Center Dover LLC	100	%	103	NRG Power Marketing LLC	2018
Thermal generation	100	%	20	Various	Various
			123
Total net generation capacity^(c)			5,241

Thermal equivalent MWt^(d)	100	%	1,319	Various	Various

^(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of December 31, 2017.

^(b) Projects are part of tax equity arrangements.

^(c) The Company's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. The Company's generation capacity including this noncontrolling interest was 5,247.

^(d)For thermal energy, net capacity represents MWt for steam or chilled water and excludes 134 MWt available under the right-to-use provisions contained in agreements between two of the Company's thermal facilities and certain of its customers.

^(e) Represents interests in Four Brothers Solar, LLC, Granite Mountain Holdings, LLC, and Iron Springs Holdings, LLC, all acquired as part of the March 2017 Drop Down Assets acquisition (ownership percentage is based upon cash to be distributed).

^(f) Projects are part of NRG Wind TE Holdco portfolio.

In addition to the facilities owned or leased in the table above, the Company entered into partnerships to own or purchase solar power generation projects, as well as other ancillary related assets from a related party via intermediate funds. The Company does not consolidate these partnerships and accounts for them as equity method investments. The Company's net interest in these projects is 247 MW based on cash to be distributed as of December 31, 2017. For further discussions, refer to Note 5, Investments Accounted for by the Equity Method and Variable Interest Entities to the Consolidated Financial Statements.

Substantially all of the Company's generation assets are under long-term contractual arrangements for the output or capacity from these assets. The thermal assets are comprised of district energy systems and combined heat and power plants that produce steam, hot water and/or chilled water and, in some instances, electricity at a central plant. Certain district energy systems are subject to rate regulation by state public utility commissions (although they may negotiate certain rates) while the other district energy systems have rates determined by negotiated bilateral contracts.

As described in Note 15, Related Party Transactions to the Consolidated Financial Statements, the Company has a management services agreement with NRG for various services, including human resources, accounting, tax, legal, information systems, treasury, and risk management.

Stockholders' equity represents the equity associated with the Class A and Class C common stockholders, the equity associated with the Class B and Class D common stockholder, NRG, and the third-party interests under certain tax equity arrangements are classified as noncontrolling interest.

During the years ending December 31, 2017 and 2016, the Company completed four acquisitions of Drop Down Assets from NRG. The accounting guidance requires retrospective combination of the entities for all periods presented as if the combination has been in effect from the beginning of the financial statement period or from the date the entities were under common control (if later than the beginning of the financial statement period). For further discussion, see Note 3, Business Acquisitions to the Consolidated Financial Statements.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The Company's consolidated financial statements have been prepared in accordance with GAAP. The ASC is the source of authoritative 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 GAAP for SEC registrants.

The consolidated financial statements include the Company's accounts and operations and those of its subsidiaries in which it 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, the Company 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 variable interest entity, or VIE, should be consolidated.

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. Cash and cash equivalents held at project subsidiaries was $124 million and $111 million as of December 31, 2017 and 2016, respectively.

Restricted Cash

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets that sum to the total of the same such amounts shown in the statements of cash flows.



	Year Ended December 31,
	2017		2016		2015
	(In millions)
Cash and cash equivalents	$	148	$	322	$	111
Restricted cash	168		176		143
Cash, cash equivalents and restricted cash shown in the statement of cash flows	316		498		254

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 as of December 31, 2017, approximately $25 million is designated for current debt service payments, $25 million is designated to fund operating expenses and $36 million is designated for distributions to the Company, with the remaining $82 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 on the balance sheet at the invoiced amount adjusted for any write-offs and the allowance for doubtful accounts. The allowance for doubtful accounts is reviewed periodically based on amounts past due and significance. The allowance for doubtful accounts was immaterial as of December 31, 2017 and 2016.

Inventory

Inventory consists principally of spare parts and fuel oil. Spare parts inventory is valued at weighted average cost, unless evidence indicates that the weighted average cost will not be recovered with a normal profit in the ordinary course of business. Fuel oil inventory is valued at the lower of weighted average cost or market. The Company removes fuel inventories as they are used in the production of steam, chilled water or electricity. Spare parts inventory are removed when they are used for repairs, maintenance or capital projects.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, in the case of third party 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 for more information on acquired 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 is computed using the straight-line method 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. For further discussion of the Company's property, plant and equipment refer to Note 4, Property, Plant and Equipment to the Consolidated Financial Statements.

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 indicated 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 appraisals, sales prices of similar assets and present value techniques. For further discussion of the Company's long-lived asset impairments, refer to Note 9, Asset Impairments to the Consolidated Financial Statements.

Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-Equity Method and Joint Ventures, which requires that a loss in value of an investment that is an other-than-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.

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. Debt issuance costs related to the long term debt are presented as a direct deduction from the carrying amount of the related debt in both the current and prior periods. Debt issuance costs related to the senior secured revolving credit facility line of credit are recorded as a non-current asset on the balance sheet and are amortized over the term of the credit facility.

Intangible Assets

Intangible assets represent contractual rights held by the Company. The Company recognizes specifically identifiable intangible assets including power purchase agreements, leasehold improvements, customer relationships, customer contracts, and development rights when specific rights and contracts are acquired. These intangible assets are amortized primarily on a straight-line basis. For further discussion of the Company's intangible assets, refer to Note 8, Intangible Assets to the Consolidated Financial Statements.

Notes Receivable

Notes receivable consist of receivables related to the financing of required network upgrades. The notes issued with respect to network upgrades will be repaid within a 5-year period following the date each facility reached commercial operations.

Income Taxes

The Company accounts for income taxes using the liability method in accordance with ASC 740, Income Taxes, or 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.

The Company 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.

The Company reports some of its 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. The Company measures its 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, including the impact of the Tax Cuts and Jobs Act, the Company considered the profit before tax generated in recent years. A valuation allowance is recorded to reduce the net deferred tax assets to an amount that is more-likely-than-not to be realized.

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 740 and as discussed further in Note 14, Income Taxes, changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax expense.

NRG Yield, Inc. is included in certain NRG consolidated unitary state tax return filings which is reflected in NRG Yield, Inc.'s state effective tax rate. If NRG Yield, Inc. filed under a separate standalone methodology, there would be an additional state tax expense of approximately $1 million as of December 31, 2017 due to a change in the NRG Yield, Inc. state effective tax rate.

Revenue Recognition

Thermal Revenues

Steam and chilled water revenue is recognized based on customer usage as determined by meter readings taken at month-end. Some locations read customer meters throughout the month, and recognize estimated revenue for the period between meter read date and month-end. The Thermal Business subsidiaries collect and remit state and local taxes associated with sales to their customers, as required by governmental authorities. These taxes are presented on a net basis in the income statement.

Power Purchase Agreements, or PPAs

The majority of the Company’s revenues are obtained through PPAs or other contractual agreements, which are accounted for as operating leases under ASC 840. 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. 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.

Certain of these leases have no minimum lease payments and all of the rental income under these leases is recorded as contingent rent on an actual basis when the electricity is delivered. The contingent rental income recognized in the years ended December 31, 2017, 2016, and 2015 was $559 million, $583 million, and $443 million, respectively. These balances include intercompany revenue for Elbow Creek of $8 million for each of the years ended December 31, 2017 and 2016, as further discussed in Note 15 Related Party Transactions.

Derivative Financial Instruments

The Company accounts for derivative financial instruments under ASC 815, Derivatives and Hedging, or 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.

The Company's primary derivative instruments are power purchase or sale contracts used to mitigate variability in earnings due to fluctuations in market prices, fuels purchase contracts used to control customer reimbursable fuel cost, and interest rate instruments used to mitigate variability in earnings due to fluctuations in interest rates. On an ongoing basis, the Company 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 item is delivered unless the transaction being hedged is 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.

Concentrations of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of accounts receivable, notes receivable and derivative instruments, which are concentrated within entities engaged in the energy and financial industry. These industry concentrations may impact the 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. In addition, many of the Company's projects have only one customer. 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 6, Fair Value of Financial Instruments for a further discussion of derivative concentrations and Note 13, Segment Reporting, for concentration of counterparties.

Fair Value of Financial Instruments

The carrying amount of cash and cash equivalents, restricted cash, accounts receivable, accounts receivable - affiliate, accounts payable, current portion of account payable - affiliate, and accrued expenses and other current liabilities approximate fair value because of the short-term maturity of these instruments. See Note 6, Fair Value of Financial Instruments, for a further discussion of fair value of financial instruments.

Asset Retirement Obligations

Asset retirement obligations, or AROs, are accounted for 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, the asset retirement cost is capitalized 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. The Company's AROs are primarily related to the future dismantlement of equipment on leased property and environmental obligations related to site closures and fuel storage facilities. The Company records AROs as part of other non-current liabilities on its balance sheet.

The following table represents the balance of ARO obligations as of December 31, 2017 and 2016, along with the additions and accretion related to the Company's ARO obligations for the year ended December 31, 2017:



	(In millions)
Balance as of December 31, 2016	$	49
Revisions in estimates for current obligations/Additions	2
Accretion — expense	4
Balance as of December 31, 2017	$	55

Guarantees

The Company enters into various contracts that include indemnification and guarantee provisions as a routine part of its business activities. Examples of these contracts include operation and maintenance agreements, service agreements, commercial sales arrangements 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. Because many of the guarantees and indemnities the Company 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 agreed upon in the contracts mentioned above. For those guarantees and indemnities that do not limit the liability exposure, the Company may not be able to estimate what the liability would be, until a claim is made for payment or performance, due to the contingent nature of these contracts.

Investments Accounted for by the Equity Method

The Company has investments in various energy projects accounted for by the equity method, several of which are VIEs, where the Company is not a primary beneficiary, as described in Note 5, Investments Accounted for by the Equity Method and Variable Interest Entities. The equity method of accounting is applied to these investments in affiliates because the ownership structure prevents the Company 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 the investments is reflected as equity in earnings of unconsolidated affiliates. Distributions from equity method investments that represent earnings 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.

Sale Leaseback Arrangements

The Company 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.

Business Combinations

The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805. For third party acquisitions, 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. For acquisitions that relate to entities under common control, ASC 805 requires retrospective combination of the entities for all periods presented as if the combination has been in effect from the beginning of the financial statement period of from the date the entities were under common control (if later than the beginning of the financial statement period). The difference between the cash paid and historical value of the entities' equity is recorded as a distribution/contribution from/to NRG with the offset to noncontrolling interest. Transaction costs are expensed as incurred.

Use of Estimates

The preparation of consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions. These estimates and assumptions impact the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the consolidated financial statements. They also impact the reported amounts of net earnings during the reporting periods. Actual results could be different from these estimates.

In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, environmental liabilities, acquisition accounting and legal costs incurred in connection with recorded loss contingencies, among others. In addition, estimates are used to test long-lived assets 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.

Tax Equity Arrangements

Certain portions of the Company’s noncontrolling interests in subsidiaries represent 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 wind facilities eligible for certain tax credits. Additionally, certain portions of the Company’s investments in unconsolidated affiliates reflect the Company’s interests in tax equity arrangements, that are not consolidated by the Company, that have been entered into to finance the cost of distributed solar energy systems under operating leases or PPAs 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 investment in unconsolidated affiliates 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 interests and investment in unconsolidated affiliates represent the amounts the investors 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 interests and investment in unconsolidated affiliates 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.

Reclassifications

Certain prior year amounts have been reclassified for comparative purposes.

Recent Accounting Developments - Adopted in 2017

ASU 2018-02 — In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220), Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, or ASU No. 2018-02. Prior to ASU 2018-02, GAAP required the remeasurement of deferred tax assets and liabilities as a result of a change in tax laws or rates to be presented in net income from continuing operations, even in situations in which the related income tax effects of items in accumulated other comprehensive income were originally recognized in other comprehensive income. As a result, such items, referred to as stranded tax effects, did not reflect the appropriate tax rate. Under ASU No. 2018-02, entities are permitted, but not required, to reclassify from accumulated other comprehensive income to retained earnings those stranded tax effects resulting from the Tax Act. ASU No. 2018-02 is effective for all entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Company adopted the new standard effective December 31, 2017. As a result of the adoption, the Company reclassified $5 million from accumulated other comprehensive loss to retained earnings in the consolidated balance sheets as of December 31, 2017.

ASU 2017-12 — In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815), Targeted Improvements to Accounting for Hedging Activities, or ASU No. 2017-12. ASU No. 2017-12 amends ASU No. 2016-15. The amendments of ASU No. 2016-15 were issued to simplify the application of hedge accounting guidance and more closely aligning financial reporting for hedging relationships with economic results of an entity's risk management activities. The issues addressed by ASU No. 2017-12 include but are not limited to alignment of risk management activities and financial reporting, risk component hedging, accounting for the hedged item in fair value hedges of interest rate risk, recognition and presentation of the effects of hedging instruments, amounts excluded from the assessment of hedge effectiveness, and other simplifications of hedge accounting guidance. The amendments of ASU No. 2017-12 are effective for fiscal years beginning after December 15, 2018, and interim periods therein. Early adoption is permitted in any interim period and the effect of the adoption should be reflected as of the beginning of the fiscal year of adoption. The Company early adopted ASU No. 2017-12 during the fourth quarter 2017. The adoption of ASU No. 2017-12 did not have a material impact on our consolidated results of operations, cash flows, and statement of financial position.

ASU 2016-18 — In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230), Restricted Cash, or ASU No. 2016-18. The amendments of ASU No. 2016-18 require an entity to include amounts generally described as restricted cash and restricted cash equivalents with cash and cash equivalents when reconciling the beginning of period and end of period total amounts on the statement of cash flows. The amendments of ASU No. 2016-18 are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted and the adoption of ASU No. 2016-18 will be applied retrospectively. The Company early adopted ASU No. 2016-18 during the second quarter of 2017. Net cash flows used in investing activities for the year ended December 31, 2016 decreased by $33 million. The sum of Company's cash and cash equivalents and restricted cash reported within the consolidated balance sheet as of December 31, 2016 equals the beginning balances of cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows for the year ended December 31, 2017. The sum of Company's cash and cash equivalents and restricted cash reported within the consolidated balance sheet as of December 31, 2017 equals to the ending balances of cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows for the year ended December 31, 2017.

Recent Accounting Developments - Not Yet Adopted

ASU 2016-02 — In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or Topic 842, with the objective to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and to improve financial reporting by expanding the related disclosures. The guidance in Topic 842 provides that a lessee that may have previously accounted for a lease as an operating lease under current GAAP should recognize the assets and liabilities that arise from a lease on the balance sheet. In addition, Topic 842 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The Company will adopt the standard effective January 1, 2019 and expects to elect certain of the practical expedients permitted, including the expedient that permits the Company to retain its existing lease assessment and classification. The Company is currently working through an adoption plan and evaluating the anticipated impact on the Company's results of operations, cash flows and financial position. While the Company is currently evaluating the impact the new guidance will have on its financial position and results of operations, the Company expects to recognize lease liabilities and right of use assets. The extent of the increase to assets and liabilities associated with these amounts remains to be determined pending the Company’s review of its existing lease contracts and service contracts which may contain embedded leases. While this review is still in process, the Company believes the adoption of Topic 842 may be material to its financial statements. The Company is continuing to monitor potential changes to Topic 842 that have been proposed by the FASB and will assess any necessary changes to the implementation as the guidance is updated.

ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or Topic 606, which was further amended through various updates issued by the FASB thereafter. The amendments of ASU No. 2014-09 completed the joint effort between the FASB and the IASB, to develop a common revenue standard for GAAP and IFRS, and to improve financial reporting. The guidance under Topic 606 provides that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for the goods or services provided and establishes a five step model to be applied by an entity in evaluating its contracts with customers. The Company has elected the practical expedient available under Topic 606 for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice such that the entity has a right to the consideration in an amount that corresponds directly with the value to the customer for performance completed to date by the entity. The majority of the Company's revenues are obtained through PPAs, which are currently accounted for as operating leases. In connection with the implementation of Topic 842, as described above, the Company expects to elect certain of the practical expedients permitted, including the expedient that permits the Company to retain its existing lease assessment and classification. The Company adopted the standard effective January 1, 2018 under the modified retrospective transition method. As leases are excluded from the scope of Topic 606, the adoption of Topic 606 at the date of initial application will not have a material impact on the Company's financial statements. The adoption of Topic 606 also includes additional disclosure requirements beginning in the first quarter of 2018. As a significant portion of the Company’s revenue is generated through operating leases, the majority of the new required disclosures will not be relevant or material to the Company.

Business Acquisitions

12 Months Ended

Dec. 31, 2017

Business Acquisition

Business Acquisitions

2017 Acquisitions

November 2017 Drop Down Assets — On November 1, 2017, the Company acquired a 38 MW solar portfolio primarily comprised of assets from NRG's Solar Power Partners (SPP) funds and other projects developed by NRG, for cash consideration of $74 million, including working capital adjustments of $3 million, plus assumed non-recourse debt of $26 million.

The purchase price for the November 2017 Drop Down Assets was funded with cash on hand. The assets and liabilities transferred to the Company relate to interests under common control by NRG and were recorded at historical cost in accordance with ASC 805-50, Business Combinations - Related Issues. The difference between the cash paid and historical value of the entities' equity was recorded as a contribution from NRG and increased the balance of its noncontrolling interest. Because the transaction constituted a transfer of net assets under common control, the guidance requires retrospective combination of the entities for all periods presented as if the combination has been in effect since the inception of common control.

The following is a summary of assets and liabilities transferred in connection with the acquisition of the November 2017 Drop Down Assets as of November 1, 2017:



	(In millions)
Assets:
Current assets	$	7
Property, plant and equipment	83
Non-current assets	12
Total assets	102
Liabilities:
Debt (Current and non-current) ^(a)	23
Other current and non-current liabilities	3
Total liabilities assumed	26
Net assets acquired	$	76

^(a) Net of $3 million of net debt issuance costs.

The following tables present a summary of the Company's historical information combining the financial information for the November 2017 Drop Down Assets transferred in connection with the acquisition:



	Year ended December 31, 2016						Year ended December 31, 2015
	As Previously Reported^(a)		November 2017 Drop Down Assets		As Currently Reported		As Previously Reported^(a)		November 2017 Drop Down Assets		As Currently Reported
(In millions)
Total operating revenues	$	1,021	$	14	$	1,035	$	953	$	15	$	968
Operating income	218		4		222		320		6		326
Net income	2		—		2		70		2		72

^(a) As previously reported in the May 9, 2017 Form 8-K filed in connection with the March 2017 Drop Down completed on March 27, 2017.



	As of December 31, 2016
(In millions)	As Previously Reported^(a)		November 2017 Drop Down Assets		As Currently Reported
Assets:
Current assets	$	656	$	14	$	670
Property, plant and equipment	5,460		94		5,554
Non-current assets	2,720		18		2,738
Total assets	8,836		126		8,962
Liabilities:
Debt	5,987		62		6,049
Other current and non-current liabilities	310		4		314
Total liabilities	6,297		66		6,363
Net assets	$	2,539	$	60	$	2,599

^(a) As previously reported in the May 9, 2017 Form 8-K filed in connection with the March 2017 Drop Down completed on March 27, 2017.

Since the acquisition date, the November 2017 Drop Down Assets have contributed $1 million in operating revenues to the Company.

August 2017 Drop Down Assets — On August 1, 2017, the Company acquired the remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, from NRG for total cash consideration of $44 million, including working capital adjustment of $3 million. The purchase agreement also included potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning in 2027, which were estimated and accrued as contingent consideration in the amount of $8 million as of September 30, 2017.

The Company originally acquired 75% of NRG Wind TE Holdco on November 3, 2015, or November 2015 Drop Down Assets, which were consolidated with 25% of the net assets recorded as noncontrolling interest. The assets and liabilities transferred to the Company related to interests under common control by NRG and were recorded at historical cost in accordance with ASC 805-50, Business Combination - Related Issues. As the Company had reflected NRG's 25% ownership of NRG Wind TE Holdco in noncontrolling interest, the difference between the cash paid of $44 million, net of the contingent consideration of $8 million, and the historical value of the remaining 25% of $87 million as of July 31, 2017, was recorded as an adjustment to NRG's noncontrolling interest. Since the transaction constituted a transfer of entities under common control, the accounting guidance requires retrospective combination of the entities for all periods presented as if the combination has been in effect from the beginning of the financial statement period or from the date the entities were under common control (if later than the beginning of the financial statement period).

The Class A interests of NRG Wind TE Holdco are owned by a tax equity investor, or TE Investor, who receives 99% of allocations of taxable income and other items until the flip point, which occurs when the TE Investor obtains a specified return on its initial investment, at which time the allocations to the TE Investor change to 8.53%. The Company generally receives 100% of CAFD until the flip point, at which time the allocations to the Company of CAFD change to 91.47%. If the flip point has not occurred by a specified date, 100% of CAFD is allocated to the TE Investor until the flip point occurs. NRG Wind TE Holdco is a VIE and the Company is the primary beneficiary, through its position as managing member, and consolidates NRG Wind TE Holdco.

March 2017 Drop Down Assets — On March 27, 2017, the Company acquired the following interests from NRG: (i) Agua Caliente Borrower 2 LLC, which owns a 16% interest (approximately 31% of NRG's 51% interest) in the Agua Caliente solar farm, one of the ROFO Assets, representing ownership of approximately 46 net MW of capacity and (ii) NRG's interests in the Utah Solar Portfolio. Agua Caliente is located in Yuma County, AZ and sells power subject to a 25-year PPA with Pacific Gas and Electric, with 22 years remaining on that contract. The seven utility-scale solar farms in the Utah Solar Portfolio are owned by the following entities: Four Brothers Capital, LLC, Iron Springs Capital, LLC, and Granite Mountain Capital, LLC. These utility-scale solar farms achieved commercial operations in 2016, sell power subject to 20-year PPAs with PacifiCorp, a subsidiary of Berkshire Hathaway and are part of a tax equity structure with Dominion Solar Projects III, Inc., or Dominion, through which the Company is entitled to receive 50% of cash to be distributed, as further described below. The Company paid cash consideration of $132 million, including $2 million of working capital. The acquisition of the March 2017 Drop Down Assets was funded with cash on hand. The Company recorded the acquired interests as equity method investments. The Company also assumed non-recourse debt of $41 million and $287 million on Agua Caliente Borrower 2 LLC and the Utah Solar Portfolio, respectively, as further described in Note 10, Long-term Debt, as well as its pro-rata share of non-recourse project-level debt of Agua Caliente Solar LLC.

The assets and liabilities transferred to the Company relate to interests under common control by NRG and were recorded at historical cost in accordance with ASC 805-50, Business Combination - Related Issues. The difference between the cash paid and the historical value of the entities' equity of $8 million was recorded as an adjustment to NRG's noncontrolling interest. Since the transaction constituted a transfer of entities under common control, the accounting guidance requires retrospective combination of the entities for all periods presented as if the combination has been in effect from the beginning of the financial statement period or from the date the entities were under common control (if later than the beginning of the financial statement period). Accordingly, in connection with the retrospective adjustment of prior periods, the Company adjusted its financial statements to reflect its results of operations, financial position and cash flows as if it recorded its interests in the Agua Caliente Borrower 2 LLC on January 1, 2016, and its interests in the Utah Solar Portfolio on November 2, 2016.

The following is a summary of assets and liabilities transferred in connection with the acquisition of the March 2017 Drop Down Assets as of March 27, 2017:



	(In millions)
Assets:
Cash	$	6
Equity investment in projects	456
Total assets acquired	462
Liabilities:
Debt (Current and non-current) ^(a)	320
Other current and non-current liabilities	3
Total liabilities assumed	323
Net assets acquired	$	139

^(a) Net of $8 million of debt issuance costs.

2016 Acquisitions

CVSR Drop Down — Prior to September 1, 2016, the Company had a 48.95% interest in CVSR, which was accounted for as an equity method investment. On September 1, 2016, the Company acquired from NRG the remaining 51.05% interest of CVSR Holdco LLC, which indirectly owns the CVSR solar facility, or the CVSR Drop Down, for total cash consideration of $78.5 million, plus an immaterial working capital adjustment. The acquisition was funded with cash on hand. The Company also assumed additional debt of $496 million, which represents 51.05% of the CVSR project level debt and 51.05% of the notes issued under the CVSR Holdco Financing Agreement, as of the closing date. The acquisition was funded with cash on hand.

The assets and liabilities transferred to the Company relate to interests under common control by NRG and were recorded at historical cost in accordance with ASC 805-50, Business Combinations - Related Issues. The difference between the cash paid and historical value of the CVSR Drop Down of $112 million, as well as $6 million of AOCL, was recorded as a distribution to NRG with the offset to noncontrolling interest. Because the transaction constituted a transfer of net assets under common control, the guidance requires retrospective combination of the entities for all periods presented as if the combination has been in effect since the inception of common control. In connection with the retrospective adjustment of prior periods, the Company now consolidates CVSR and 100% of its debt, consisting of $771 million of project level debt and $200 million of notes issued under the CVSR Holdco Financing Agreement as of September 1, 2016. In addition, the Company has removed the equity method investment from all prior periods and adjusted its financial statements to reflect its results of operations, financial position and cash flows as if it had consolidated CVSR from the beginning of the financial statement period.

2015 Acquisitions

November 2015 Drop Down Assets from NRG — On November 3, 2015, the Company acquired the November 2015 Drop Down Assets, a portfolio of 12 wind facilities totaling 814 net MW, from NRG for cash consideration of $207 million. The Company was 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).

The Company funded the acquisition with borrowings from its revolving credit facility. The assets and liabilities transferred to the Company relate to interests under common control by NRG and were recorded at historical cost. The difference between the cash paid and historical value of the entities' equity was recorded as a distribution from NRG with the offset to noncontrolling interest.

Desert Sunlight — On June 29, 2015, the Company 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. Power generated by the facilities is sold to Southern California Edison and Pacific Gas and Electric under long-term PPAs with approximately 20 years and 25 years of remaining contract life, respectively. The Company accounts for its 25% investment as an equity method investment.

Spring Canyon — On May 7, 2015, the Company acquired a 90.1% interest in Spring Canyon II, a 32 MW wind facility, and Spring Canyon III, a 28 MW wind facility, each located in Logan County, Colorado, from Invenergy Wind Global LLC. The purchase price was funded with cash on hand. Power generated by Spring Canyon II and Spring Canyon III is sold to Platte River Power Authority under long-term PPAs, each with approximately 24 years of remaining contract life.

University of Bridgeport Fuel Cell — On April 30, 2015, the Company completed the acquisition of the University of Bridgeport Fuel Cell project in Bridgeport, Connecticut from FuelCell Energy, Inc. The project added an additional 1.4 MW of thermal capacity to the Company's portfolio, with a 12-year contract, with the option for a 7-year extension. The acquisition is reflected in the Company's Thermal segment.

January 2015 Drop Down Assets from NRG — On January 2, 2015, the Company acquired the following projects from NRG: (i) Laredo Ridge, an 80 MW wind facility located in Petersburg, Nebraska, (ii) Tapestry, which includes Buffalo Bear, a 19 MW wind facility in Buffalo, Oklahoma; Taloga, a 130 MW wind facility in Putnam, Oklahoma; and Pinnacle, a 55 MW wind facility in Keyser, West Virginia, and (iii) Walnut Creek, a 485 MW natural gas facility located in City of Industry, California, for total cash consideration of $489 million, including $9 million for working capital, plus assumed project-level debt of $737 million. The Company funded the acquisition with cash on hand and drawings under its revolving credit facility. The assets and liabilities transferred to the Company relate to interests under common control by NRG and were recorded at historical cost. The difference between the cash paid and the historical value of the entities' equity of $61 million, as well as $23 million of AOCL, was recorded as a distribution to NRG and reduced the balance of its noncontrolling interest.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure

The Company’s major classes of property, plant, and equipment were as follows:



	December 31, 2017			December 31, 2016			Depreciable Lives
	(In millions)
Facilities and equipment	$	6,289		$	6,339		2 - 45 Years
Land and improvements	166			167
Construction in progress ^(a)	34			24
Total property, plant and equipment	6,489			6,530
Accumulated depreciation	(1,285		)	(976		)
Net property, plant and equipment	$	5,204		$	5,554

^(a) As of December 31, 2017 and 2016, construction in progress includes $24 million and $20 million of capital expenditures that relate to prepaid long-term service agreements in the Conventional segment, respectively.

The Company recorded long-lived asset impairments during the years ended December 31, 2017 and 2016, as further described in Note 9, Asset Impairments.

Investments Accounted for by the Equity Method and Variable Interest Entities

12 Months Ended

Dec. 31, 2017

Equity Method Investments and Joint Ventures [Abstract]

Investments Accounted for by the Equity Method and Variable Interest Entities

Equity Method Investments

The following table summarizes the Company's equity method investments as of December 31, 2017:



Name	Economic Interest	Investment Balance
		(In millions)
Utah Solar Portfolio^(a)	50%	$345
Desert Sunlight	25%	272
GenConn^(b)	50%	102
Agua Caliente Borrower 2	16%	92
Elkhorn Ridge^(c)	66.7%	73
San Juan Mesa^(c)	75%	66
NRG DGPV Holdco 1 LLC ^(d)	95%	76
NRG DGPV Holdco 2 LLC ^(d)	95%	61
NRG DGPV Holdco 3 LLC ^(d)	99%	39
NRG RPV Holdco 1 LLC^(d)	95%	58
Avenal	50%	(6)
Total equity investments in affiliates		$1,178

^(a) Economic interest based on cash to be distributed. Four Brothers Solar, LLC, Granite Mountain Holdings, LLC and Iron Springs Holdings, LLC are tax equity structures and VIEs. The related allocations are described below.

^(b) GenConn is a variable interest entity.

^(c)San Juan Mesa and Elkhorn Ridge are part of the Wind TE Holdco tax equity structure, as described below. San Juan Mesa and Elkhorn Ridge are owned 75% and 66.7%, respectively, by Wind TE Holdco. The Company owns 100% of the Class B interests in Wind TE Holdco.

^(d)Economic interest based on cash to be distributed. NRG DGPV Holdco 1 LLC, NRG DGPV Holdco 2 LLC, NRG DGPV Holdco 3 LLC and NRG RPV Holdco 1 LLC are tax equity structures and VIEs. The related allocations are described below.

As of December 31, 2017 and 2016, the Company had $57 million and $51 million, respectively, of undistributed earnings from its equity method investments.

The Company acquired its interest in Desert Sunlight on June 30, 2015, for $285 million, which resulted in a difference between the purchase price and the basis of the acquired assets and liabilities of $171 million. The difference is attributable to the fair value of the property, plant and equipment and power purchase agreements. In addition, the difference between the basis of the acquired assets and liabilities and the purchase price for the Utah Solar Portfolio (Four Brothers Solar, LLC, Granite Mountain Holdings, LLC and Iron Springs Holdings, LLC) of $106 million is attributable to the fair value of the property, plant and equipment. The Company is amortizing the related basis differences to equity in earnings (losses) over the related useful life of the underlying assets acquired.

Non-recourse project-level debt of unconsolidated affiliates

The Company's pro-rata share of non-recourse debt held by unconsolidated affiliates was $777 million as of December 31, 2017.

The following tables present summarized financial information for the Company's significant equity method investments:



	Year Ended December 31,
	2017			2016				2015
Income Statement Data:	(In millions)
GenConn
Operating revenues	$	71		$	72			$	78
Operating income	36			38				40
Net income	26			26				28
Desert Sunlight
Operating revenues	207			211				206
Operating income	127			129				124
Net income	80			80				73
Utah Solar Portfolio ^(a)
Operating revenues	75			13				—
Operating income (loss)	18			(6		)		(1		)
Net income (loss)	18			(6		)		(1		)
DGPV entities ^(b)
Operating revenues	37			14				1
Operating income	7			2				—
Net loss	(3		)	—				—
RPV Holdco
Operating revenues	16			13				4
Operating income	3			2				(6		)
Net income (loss)	$	3		$	2			$	(6	)
				As of December 31,
				2017				2016
Balance Sheet Data:				(In millions)
GenConn
Current assets				$	38			$	36
Non-current assets				374				389
Current liabilities				18				16
Non-current liabilities				189				196
Desert Sunlight
Current assets				133				281
Non-current assets				1,350				1,401
Current liabilities				64				64
Non-current liabilities				1,003				1,043
Utah Solar Portfolio ^(a)
Current assets				13				20
Non-current assets				1,090				1,105
Current liabilities				5				14
Non-current liabilities				24				38
DGPV entities ^(b)
Current assets				74				44
Non-current assets				671				562
Current liabilities				83				112
Non-current liabilities				216				23
Redeemable Noncontrolling Interest				44				28
RPV Holdco
Current assets				3				15
Non-current assets				183				191
Current liabilities				—				11
Non-current liabilities				7				7
Redeemable Noncontrolling Interest				$	16		—	$	—

^(a) Utah Solar Portfolio was acquired by NRG on November 2, 2016.

^(b) Includes DGPV Holdco 1, DGPV Holdco 2 and DGPV Holdco 3.

Variable Interest Entities, or VIEs

Entities that are Consolidated

NRG Wind TE Holdco — As described in Note 3, Business Acquisitions, on August 1, 2017, the Company acquired from NRG the remaining 25% interest in NRG Wind TE Holdco. NRG Wind TE Holdco is a VIE and the Company is the primary beneficiary through its position as managing member and consolidates NRG Wind TE Holdco. The Class A interests of NRG Wind TE Holdco are owned by a tax equity investor, or TE Investor, who receives 99% of allocations of taxable income and other items until the flip point, which occurs when the TE Investor obtains a specified return on its initial investment, at which time the allocations to the TE Investor change to 8.53%. The Company generally receives 100% of CAFD until the flip point, at which time the allocations to the Company of CAFD change to 91.47%. If the flip point has not occurred by a specified date, 100% of CAFD is allocated to the TE Investor until the flip point occurs. The Company utilizes the HLBV method to determine the net income or loss allocated to the TE Investor noncontrolling interest.

Alta TE Holdco — On June 30, 2015, the Company sold an economic interest in Alta TE Holdco to a financial institution in order to monetize certain cash and tax attributes, primarily PTCs. The financial institution, or Alta Investor, receives 99% of allocations of taxable income and other items until the flip point, which occurs when the Alta Investor obtains a specified return on its initial investment, at which time the allocations to the Alta Investor change to 5%. The Company receives 94.34% until the flip point, at which time the allocations to the Company of CAFD will change to 97.12%, unless the flip point will not have occurred by a specified date, which would result in 100% of CAFD allocated to the Alta Investor until the flip point occurs. Alta TE Holdco is a VIE and the Company is the primary beneficiary through its position as managing member, and therefore consolidates Alta TE Holdco, with the Alta Investor's interest shown as noncontrolling interest. The Company utilizes the HLBV method to determine the net income or loss allocated to the noncontrolling interest.

Spring Canyon — The Company holds a 90.1% of the Class B interests in Spring Canyon II, a 32 MW wind facility, and Spring Canyon III, a 28 MW wind facility, each located in Logan County, Colorado, and Invenergy Wind Global LLC owns 9.9% of the Class B interests. The projects are financed with a partnership flip tax-equity structure with a financial institution, who owns the Class A interests, to monetize certain cash and tax attributes, primarily PTCs. Until the flip point, the Class A member receives a variable percentage of cash distributions based on the projects’ production level during the prior year. The Class A member received 34.81% of the cash distributions and the Company and Invenergy received 65.19% during the period ended December 31, 2017. After the flip point, cash distributions are allocated 5% to the Class A member and 95% to the Company and Invenergy. Spring Canyon is a VIE and the Company is the primary beneficiary through its position as managing member, and therefore consolidates Spring Canyon. The Class A member and Invenergy's interests are shown as noncontrolling interest. The Company utilizes the HLBV method to determine the net income or loss allocated to the Class A member. Net income or loss attributable to the Class B interests is allocated to Invenergy's noncontrolling interest based on its 9.9% ownership interest.

Summarized financial information for the Company's consolidated VIEs consisted of the following as of December 31, 2017:



(In millions)	NRG Wind TE Holdco		Alta TE Holdco		Spring Canyon
Other current and non-current assets	$	172	$	17	$	2
Property, plant and equipment	376		436		95
Intangible assets	2		262		—
Total assets	550		715		97
Current and non-current liabilities	197		9		5
Total liabilities	197		9		5
Noncontrolling interest	9		93		60
Net assets less noncontrolling interests	$	344	$	613	$	32

Entities that are not Consolidated

The Company has interests in entities that are considered VIEs under ASC 810, Consolidation, but for which it is not considered the primary beneficiary. The Company accounts for its interests in these entities under the equity method of accounting.

Utah Solar Portfolio Assets — As described in Note 3, Business Acquisitions, as part of the March 2017 Drop Down Assets acquisition, the Company acquired from NRG 100% of the Class A equity interests in the Utah Solar Portfolio, comprised of Four Brothers Solar, LLC, Granite Mountain Holdings, LLC, and Iron Springs Holdings, LLC. The Class B interests of the Utah Solar Portfolio are owned by a tax equity investor, or TE Investor, who receives 99% of allocations of taxable income and other items until the flip point, which occurs when the TE Investor obtains a specified return on its initial investment, at which time the allocations to the TE Investor change to 50%. The Company generally receives 50% of distributable cash throughout the term of the tax-equity arrangements. The three entities comprising the Utah Solar Portfolio are VIEs. As the Company is not the primary beneficiary, the Company uses the equity method of accounting to account for its interests in the Utah Solar Portfolio. The Company utilizes the HLBV method to determine its share of the income or losses in the investees.

NRG DGPV Holdco 1 LLC — The Company and NRG are parties to the NRG DGPV Holdco 1 LLC partnership, or DGPV Holdco 1, the purpose of which is to own or purchase solar power generation projects and other ancillary related assets from NRG Renew LLC or its subsidiaries via intermediate funds. The Company owns approximately 47 MW of distributed solar capacity, based on cash to be distributed, with a weighted average contract life of 18 years. Under this partnership, the Company committed to fund up to $100 million of capital.

NRG DGPV Holdco 2 LLC — The Company and NRG are parties to the NRG DGPV Holdco 2 LLC partnership, or DGPV Holdco 2, the purpose of which is to own or hold solar power generation projects as well as other ancillary related assets from NRG Renew LLC or its subsidiaries. The Company owns approximately 113 MW of distributed solar capacity, based on cash to be distributed, with a weighted average contract life of 21 years. Under this partnership, the Company committed to fund up to $60 million of capital.

NRG DGPV Holdco 3 LLC — On September 26, 2017, the Company entered into an additional partnership with NRG by forming NRG DGPV Holdco 3 LLC, or DGPV Holdco 3, in which the Company would invest up to $50 million in an operating portfolio of distributed solar assets, primarily comprised of community solar projects, developed by NRG. The Company owns approximately 43 MW of distributed solar capacity, based on cash to be distributed, with a weighted average contract life of approximately 20 years as of December 31, 2017.

The Company's maximum exposure to loss is limited to its equity investment in DGPV Holdco 1, DGPV Holdco 2 and DGPV Holdco 3, which was $176 million on a combined basis.

NRG RPV Holdco 1 LLC — The Company and NRG are parties to the NRG RPV Holdco 1 LLC partnership, or RPV Holdco, the purpose of which is to hold operating portfolios of residential solar assets developed by NRG's residential solar business, including: (i) an existing, unlevered portfolio of over 2,200 leases across nine states representing approximately 14 MW, based on cash to be distributed, with a weighted average remaining lease term of approximately 15 years that was acquired outside of the partnership; and (ii) a tax equity-financed portfolio of approximately 5,400 leases representing approximately 30 MW, based on cash to be distributed, with a weighted average remaining lease term for the existing and new leases of approximately 18 years. The Company has fully funded the partnership as of December 31, 2017.

The Company's maximum exposure to loss is limited to its equity investment, which was $58 million as of December 31, 2017.

Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

The following table presents 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, 2017			As of December 31, 2016
		Fair Value ^(a)		Fair Value ^(a)		Fair Value ^(a)
(In millions)		Level 2		Level 1		Level 2
Derivative assets:
Commodity contracts		$	1	$	1	$	1
Interest rate contracts		1		—		1
Total assets		$	2	1		2
Derivative liabilities:
Commodity contracts		$	1	—		1
Interest rate contracts		47		—		78
Total liabilities		$	48	$	—	$	79

^(a) There were no derivative assets or liabilities classified Level 1 as of December 31, 2017. There were no derivative assets or liabilities classified Level 3 as of December 31, 2017 and 2016.

Fair Value of Financial Instruments

For cash and cash equivalents, restricted cash, accounts receivable — affiliate, accounts receivable, accounts payable, current portion of accounts payable — affiliate, accrued expenses and other liabilities, 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 amounts and fair values of the Company’s recorded financial instruments not carried at fair market value are as follows:



	As of December 31, 2017				As of December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable, including current portion	$	13	$	13	$	30	$	30
Liabilities:
Long-term debt, including current portion	$	5,897	$	5,930	$	6,122	$	6,121

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.


•	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.


•	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.

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.

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. The following table presents the level within the fair value hierarchy for long-term debt, including current portion as of December 31, 2017 and 2016:



	As of December 31, 2017				As of December 31, 2016
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	1,502	$	4,428	$	1,455	$	4,666

Recurring Fair Value Measurements

The Company records its derivative assets and liabilities at fair market value on its consolidated balance sheet. The following table presents 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, 2017			As of December 31, 2016
		Fair Value ^(a)		Fair Value ^(a)		Fair Value ^(a)
(In millions)		Level 2		Level 1		Level 2
Derivative assets:
Commodity contracts		$	1	$	1	$	1
Interest rate contracts		1		—		1
Total assets		$	2	1		2
Derivative liabilities:
Commodity contracts		$	1	—		1
Interest rate contracts		47		—		78
Total liabilities		$	48	$	—	$	79

^(a) There were no derivative assets or liabilities classified Level 1 as of December 31, 2017. There were no derivative assets or liabilities classified Level 3 as of December 31, 2017 and 2016.

Derivative Fair Value Measurements

The Company's contracts are non-exchange-traded and valued using prices provided by external sources. For the Company’s energy markets, management receives quotes from multiple sources. To the extent that multiple quotes are received, the prices reflect the average of the bid-ask mid-point prices obtained from all sources believed to provide the most liquid market for the commodity.

The fair value of each contract is discounted using a risk free interest rate. In addition, a credit reserve is applied to reflect credit risk, which for interest rate swaps, is calculated based on credit default swaps utilizing the bilateral method. 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 the liabilities or that a market participant would be willing to pay for the assets. As of December 31, 2017, the credit reserve resulted in a $1 million increase in fair value in interest expense. It is possible that future market prices could vary from those used in recording assets and liabilities and such variations could be material.

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) 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.

Counterparty credit exposure includes credit risk exposure under certain long-term agreements, including solar and other PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company estimates the exposure related to 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, 2017, credit risk exposure to these counterparties attributable to the Company's ownership interests was approximately $2.7 billion for the next five years. The majority of these power contracts are with utilities 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 the Company is unable to predict.

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

Accounting for Derivative Instruments and Hedging Activities Disclosure [Abstract]

Accounting for Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2017

Accounting for Derivative Instruments and Hedging Activities

ASC 815 requires the Company 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. The Company may elect to designate certain derivatives as cash flow hedges, if certain conditions are met, and defer the change in fair value of the derivatives to accumulated OCI/OCL, until the hedged transactions occur and are recognized in 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 the Company's energy related commodity contracts and interest rate swaps.

Energy-Related Commodities

To manage the commodity price risk associated with its competitive supply activities and the price risk associated with wholesale power sales, the Company may enter into derivative hedging instruments, namely, forward contracts that commit the Company to sell energy commodities or purchase fuels/electricity in the future. The objectives for entering into derivatives contracts designated as hedges include fixing the price for a portion of anticipated future electricity sales and fixing the price of a portion of anticipated fuel/electricity purchases for the operation of its subsidiaries. As of December 31, 2017, the Company had forward contracts for the purchase of fuel commodities relating to the forecasted usage of the Company’s district energy centers extending through 2020 and electricity contracts to supply retail power to the Company's district energy centers extending through 2020. At December 31, 2017, these contracts were not designated as cash flow or fair value hedges.

Also, as of December 31, 2017, the Company 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:


•	Power tolling contracts through 2039, and


•	Natural gas transportation contracts through 2028.

Interest Rate Swaps

The Company is exposed to changes in interest rates through the issuance of variable rate debt. In order to manage interest rate risk, it enters into interest rate swap agreements.

As of December 31, 2017, the Company had interest rate derivative instruments on non-recourse debt extending through 2036, a portion of which are designated as cash flow hedges.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of the Company's open derivative transactions broken out by commodity as of December 31, 2017 and 2016:



		Total Volume
		December 31, 2017		December 31, 2016
Commodity	Units	(In millions)
Natural Gas	MMBtu	2		3
Interest	Dollars	$	1,940	$	2,090

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 ^(a)				Derivative Liabilities
	December 31, 2017		December 31, 2016		December 31, 2017		December 31, 2016
	(In millions)
Derivatives Designated as Cash Flow Hedges:
Interest rate contracts current	$	—	$	—	$	4	$	26
Interest rate contracts long-term	1		1		9		39
Total Derivatives Designated as Cash Flow Hedges	1		1		13		65
Derivatives Not Designated as Cash Flow Hedges:
Interest rate contracts current	—		—		12		6
Interest rate contracts long-term	—		—		22		7
Commodity contracts current	1		2		1		1
Total Derivatives Not Designated as Cash Flow Hedges	1		2		35		14
Total Derivatives	$	2	$	3	$	48	$	79

^(a) Derivative Asset balances classified as current are included within the prepayments and other current assets line item of the Consolidated Balance Sheet. Derivative Asset balances classified as long-term are included within the other non-current assets line item of the Consolidated Balance Sheet.

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. As of December 31, 2017 and 2016, there was no outstanding collateral paid or received. The following tables summarize the offsetting of derivatives by counterparty master agreement level:



	Gross Amounts Not Offset in the Statement of Financial Position
As of December 31, 2017	Gross Amounts of Recognized Assets/Liabilities			Derivative Instruments			Net Amount
Commodity contracts:	(In millions)
Derivative assets	$	1		$	—		$	1
Derivative liabilities	(1		)	—			(1		)
Total commodity contracts	—			—			—
Interest rate contracts:
Derivative assets	1			(1		)	—
Derivative liabilities	(47		)	1			(46		)
Total interest rate contracts	(46		)	—			(46		)
Total derivative instruments	$	(46	)	$	—		$	(46	)



	Gross Amounts Not Offset in the Statement of Financial Position
As of December 31, 2016	Gross Amounts of Recognized Assets/Liabilities			Derivative Instruments			Net Amount
Commodity contracts:	(In millions)
Derivative assets	$	2		$	—		$	2
Derivative liabilities	(1		)	—			(1		)
Total commodity contracts	1			—			1
Interest rate contracts:
Derivative assets	1			(1		)	—
Derivative liabilities	(78		)	1			(77		)
Total interest rate contracts	(77		)	—			(77		)
Total derivative instruments	$	(76	)	$	—		$	(76	)

Accumulated Other Comprehensive Loss

The following table summarizes the effects on the Company’s accumulated OCL balance attributable to interest rate swaps designated as cash flow hedge derivatives, net of tax:



	Year ended December 31,
	2017			2016			2015
	(In millions)
Accumulated OCL beginning balance	$	(70	)	$	(83	)	$	(76	)
Reclassified from accumulated OCL to income due to realization of previously deferred amounts	10			13			14
Mark-to-market of cash flow hedge accounting contracts	—			—			(21		)
Accumulated OCL ending balance, net of income tax benefit of $9, $16 and $16, respectively	$	(60	)	$	(70	)	$	(83	)
Accumulated OCL attributable to noncontrolling interests	(32		)	(42		)	(56		)
Accumulated OCL attributable to NRG Yield, Inc.	$	(28	)	$	(28	)	$	(27	)
Losses expected to be realized from OCL during the next 12 months, net of income tax benefit of $2	$	13

Amounts reclassified from accumulated OCL into income are recorded to interest expense.

Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of December 31, 2016, the Company's regression analysis for Viento Funding II interest rate swaps, while positively correlated, did not meet the required threshold for cash flow hedge accounting. As a result, the Company de-designated the Viento Funding II cash flow hedges as of December 31, 2016, and will prospectively mark these derivatives to market through the income statement.

The Company's regression analysis for Marsh Landing, Walnut Creek and Avra Valley interest rate swaps, while positively correlated, no longer contain matching terms for cash flow hedge accounting. As a result, the Company voluntarily de-designated the Marsh Landing, Walnut Creek and Avra Valley cash flow hedges as of April 28, 2017, and will prospectively mark these derivatives to market through the income statement.

Impact of Derivative Instruments on the Statements of Income

The Company has interest rate derivative instruments that are not designated as cash flow hedges. The effect of interest rate hedges is recorded to interest expense. For the years ended December 31, 2017, 2016 and 2015 the impact to the consolidated statements of income was a gain of $7 million, loss of $2 million and a gain of $17 million, respectively.

A portion of the Company’s derivative commodity contracts relates to its Thermal Business for the purchase of fuel/electricity commodities based on the forecasted usage of the thermal district energy centers. Realized gains and losses on these contracts are reflected in the costs that are permitted to be billed to customers through the related customer contracts or tariffs and, accordingly, no gains or losses are reflected in the consolidated statements of income for these contracts.

In 2015, commodity contracts also hedged the forecasted sale of power for the Elbow Creek until the start of the PPA with NRG Power Marketing LLC, or Power Marketing, with effective date of November 1, 2015. The effect of these commodity hedges was recorded to operating revenues. For the year ended December 31, 2015, the impact to the consolidated statements of income was an unrealized loss of $2 million.

See Note 6, Fair Value of Financial Instruments, for a discussion regarding concentration of credit risk.

Intangible Assets

12 Months Ended

Dec. 31, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets

Intangible Assets — The Company's intangible assets as of December 31, 2017 and 2016 primarily reflect intangible assets established from its business acquisitions and are comprised of the following:


•	PPAs — Established predominantly with the acquisitions of the Alta Wind Portfolio, Walnut Creek, Tapestry and Laredo Ridge, these represent the fair value of the PPAs acquired. These are amortized, generally on a straight-line basis, over the term of the PPA.


•	Leasehold Rights — Established with the acquisition of the Alta Wind Portfolio, this represents the fair value of contractual rights to receive royalty payments equal to a percentage of PPA revenue from certain projects. These are amortized on a straight-line basis.


•	Customer relationships — Established with the acquisition of NRG Energy Center Phoenix and NRG Energy Center Omaha, these intangibles represent the fair value at the acquisition date of the businesses' customer base. The customer relationships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.


•	Customer contracts — Established with the acquisition of NRG Energy Center Phoenix, these intangibles represent the fair value at the acquisition date of contracts that primarily provide chilled water, steam and electricity to its customers. These contracts are amortized to revenues based on expected volumes.


•	Emission Allowances — These intangibles primarily consist of SO₂ and NOx emission allowances established with the El Segundo and Walnut Creek acquisitions. These emission allowances are held-for-use and are amortized to cost of operations, with NOx allowances amortized on a straight-line basis and SO₂ allowances amortized based on units of production.


•	Development rights — Arising primarily from the acquisition of solar businesses in 2010 and 2011, these intangibles are amortized to depreciation and amortization expense on a straight-line basis over the estimated life of the related project portfolio.


•	Other — Consists primarily of the acquisition date fair value of the contractual rights to a ground lease for South Trent and to utilize certain interconnection facilities for Blythe, as well as land rights acquired in connection with the acquisition of Elbow Creek.

The following tables summarize the components of intangible assets subject to amortization:



Year ended December 31, 2017	PPAs			Leasehold Rights			Customer Relationships			Customer Contracts			Emission Allowances			Development Rights			Other			Total
(In millions)
January 1, 2017	$	1,286		$	86		$	66		$	15		$	9		$	3		$	6		$	1,471
Asset impairments^(a)	(6		)	—			—			—			—			—			—			(6		)
December 31, 2017	1,280			86			66			15			9			3			6			1,465
Less accumulated amortization	(205		)	(13		)	(5		)	(8		)	(3		)	(1		)	(2		)	(237		)
Net carrying amount	$	1,075		$	73		$	61		$	7		$	6		$	2		$	4		$	1,228

^(a) $6 million of asset impairments relate to one of the November 2017 Drop Down Assets that was recorded by NRG during the quarter ended September 30, 2017, as further described in Note 9, Asset Impairments.



Year ended December 31, 2016	PPAs			Leasehold Rights			Customer Relationships			Customer Contracts			Emission Allowances			Development Rights			Other			Total
(In millions)
January 1, 2016	$	1,286		$	86		$	66		$	15		$	15		$	3		$	6		$	1,477
Other	—			—			—			—			(6		)	—			—			(6		)
December 31, 2016	1,286			86			66			15			9			3			6			1,471
Less accumulated amortization	(143		)	(9		)	(4		)	(7		)	(2		)	(1		)	(2		)	(168		)
Net carrying amount	$	1,143		$	77		$	62		$	8		$	7		$	2		$	4		$	1,303

The Company recorded amortization expense of $71 million during each of years ended December 31, 2017 and 2016, and $56 million during the year ended December 31, 2015. Of these amounts, $70 million for each of the years ended December 31, 2017 and 2016, and $55 million for the year ended December 31, 2015, were recorded to contract amortization expense and reduced operating revenues in the consolidated statements of operations. The Company estimates the future amortization expense for its intangibles to be $71 million for the next five years through 2022.

Out-of-market contracts — The out-of-market contract liability represents the out-of-market value of the PPAs for the Blythe solar project and Spring Canyon wind projects and the out-of-market value of the land lease for Alta Wind XI, LLC, as of their respective acquisition dates. The Blythe solar project's liability of $7 million was recorded to other non-current liabilities on the consolidated balance sheet and is amortized to revenue in the consolidated statements of income on a units-of-production basis over the twenty-year term of the agreement. Spring Canyon's liability of $3 million was recorded to other non-current liabilities and is amortized to revenue on a straight-line basis over the twenty-five year term of the agreement. The Alta Wind XI, LLC's liability of $5 million was recorded to other non-current liabilities and is amortized as a reduction to cost of operations on a straight-line basis over the thirty-four year term of the land lease. At December 31, 2017, accumulated amortization of out-of-market contracts was $4 million and amortization expense was $1 million for each of the years ended December 31, 2017 and 2016.

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

Asset Impairments Asset Impairments (Notes)	12 Months Ended
Asset Impairments Asset Impairments (Notes)	Dec. 31, 2017
Asset Impairments [Abstract]
Asset Impairment Charges [Text Block]	Asset Impairments During the quarter ended December 31, 2017, as the Company updated its estimated cash flows in connection with the preparation and review of the Company's annual budget, the Company determined that the cash flows for Elbow Creek, located in Texas, and the Forward project, located in Pennsylvania, were below the carrying value of the related assets, primarily driven by continued declining merchant power prices in post-contract periods, and that the assets were considered impaired. The fair value of the facilities 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 measurement and include key inputs, such as forecasted power prices, operations and maintenance expense, and discount rates. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets and recorded impairment losses of $26 million and $5 million for Elbow Creek and Forward, respectively. Additionally, during the quarter ended September 30, 2017, in connection with the preparation of the model for sale of the November 2017 Drop Down Assets, it was identified that undiscounted cash flows were lower than the book value of certain SPP funds and NRG recorded an impairment expense of $13 million, $8 million of which relates to property, plant, and equipment and $5 million to PPAs, as described in Note 8, Intangible Assets. In accordance with the guidance for transfer of assets under common control, the impairment is reflected in the pre-acquisition net income of Drop Down Assets of the Company's consolidated statements of operations for the period ended December 31, 2017. During the fourth quarter of 2016, as the Company updated its estimated cash flows in connection with the preparation and review of the Company's annual budget, the Company determined that the cash flows for the Elbow Creek and Goat Wind projects and the Forward project were below the carrying value of the related assets, primarily driven by declining merchant power prices in post-contract periods, and that the assets were considered impaired. These projects were acquired in connection with the acquisition of the November 2015 Drop Down Assets and were recorded as part of the Renewables segment of the Company. The projects were recorded at historical cost at acquisition date as they were related to interests under common control by NRG. The fair value of the facilities 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 measurement and include key inputs, such as forecasted power prices, operations and maintenance expense, and discount rates. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets and recorded impairment losses of $117 million, $60 million and $6 million for Elbow Creek, Goat Wind, and Forward, respectively. Other Impairments — During the fourth quarters of 2016 and 2015, NRG recorded impairment losses of approximately $2 million and $1 million, respectively, related to the projects that were part of the November 2017 Drop Down Assets. Since the acquisition by the Company of the November 2017 Drop Down Assets related to transfer of assets under common control, these impairments were reflected in the Company's consolidated statements of operations for the periods ending December 31, 2016 and 2015.

Long-term Debt

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Earnings (Loss) Per Share Disclosure [Abstract]

The Company's borrowings, including short term and long term portions consisted of the following:



	December 31, 2017			December 31, 2016			Interest rate % ^(a)		Letters of Credit Outstanding at December 31, 2017
	(In millions, except rates)
2026 Senior Notes	$	350		$	350		5.000
2024 Senior Notes	500			500			5.375
2020 Convertible Notes	288			288			3.250
2019 Convertible Notes	345			345			3.500
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 ^(b)	55			—			L+2.500		$	74
Project-level debt:
Agua Caliente Borrower 2, due 2038	41			—			5.430		17
Alpine, due 2022	135			145			L+1.750		16
Alta Wind I - V lease financing arrangements, due 2034 and 2035	926			965			5.696 - 7.015		119
CVSR, due 2037	746			771			2.339 - 3.775		—
CVSR Holdco Notes, due 2037	194			199			4.680		13
El Segundo Energy Center, due 2023	400			443			L+1.75 - L+2.375		102
Energy Center Minneapolis, due 2025	83			96			5.950	%	—
Energy Center Minneapolis Series D Notes, due 2031	125			125			3.550		—
Laredo Ridge, due 2028	95			100			L+1.875		10
Marsh Landing, due 2023	318			370			L+1.875		22
Tapestry, due 2021	162			172			L+1.625		20
Utah Solar Portfolio, due 2022	278			287			various		13
Viento, due 2023	163			178			L+3.00		27
Walnut Creek, due 2023	267			310			L+1.625		41
Other	443			505			various		38
Subtotal project-level debt	4,376			4,666
Total debt	5,914			6,149
Less current maturities	(306		)	(323		)
Less net debt issuance costs	(60		)	(73		)
Less discounts^(c)	$	(17	)	$	(27	)
Total long-term debt	$	5,531		$	5,726

^(a) As of December 31, 2017, L+ equals 3 month LIBOR plus x%, except for Viento, due 2023 where L+ equals 6 month LIBOR plus 3.00%.

^(b) Applicable rate is determined by the borrower leverage ratio, as defined in the credit agreement.

^(c) Discounts relate to the 2019 Convertible Notes and 2020 Convertible Notes.

The financing arrangements listed above contain certain covenants, including financial covenants that the Company is required to be in compliance with during the term of the respective arrangement. As of December 31, 2017, the Company was in compliance with all of the required covenants.

NRG Yield Operating LLC 2026 Senior Notes

On August 18, 2016, NRG Yield Operating LLC issued $350 million of senior unsecured notes, or the 2026 Senior Notes. The 2026 Senior Notes bear interest at 5.00% and mature on September 15, 2026. Interest on the notes is payable semi-annually on March 15 and September 15 of each year. The 2026 Senior Notes are senior unsecured obligations of NRG Yield Operating LLC and are guaranteed by NRG Yield LLC, and by certain of NRG Yield Operating LLC’s wholly owned current and future subsidiaries. A portion of the proceeds of the 2026 Senior Notes were used to repay the Company's revolving credit facility during 2016, as described below.

2020 Convertible Senior Notes

The Company has outstanding $288 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 the Company’s 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 a 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. 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 guaranteed by NRG Yield Operating LLC and NRG Yield LLC.

The Company separately accounts for the liability (debt) and equity (conversion option) components of the 2020 Convertible Notes and recognized $23 million as the value for the equity component in 2015 with the offset to debt discount. The debt discount is amortized to interest expense using the effective interest method through June 2020.

As of December 31, 2017, the 2020 Convertible Notes were trading at approximately 98.8% of their face value, resulting in a total market value of $284 million compared to a carrying value of $276 million. The actual conversion value of the 2020 Convertible Notes is based on the product of the conversion rate and the market price of the Company's Class C common stock, as defined in the 2020 Convertible Notes indenture. As of December 31, 2017, the Company's Class C common stock closed at $18.90 per share, resulting in a pro forma conversion value for the 2020 Convertible Notes of approximately $198 million.

2019 Convertible Senior Notes

The Company has outstanding $345 million aggregate principal amount of 3.50% Convertible Notes due 2019, or the 2019 Convertible Notes. The 2019 Convertible Notes were convertible, under certain circumstances, into the Company’s Class A common stock, cash or a combination thereof at a conversion rate was of approximately 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. 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 guaranteed by NRG Yield Operating LLC and NRG Yield LLC.

The Company separately accounts for the liability (debt) and equity (conversion option) components of the 2019 Convertible Notes and recognized $23 million as the value for the equity component in 2014 with the offset to debt discount. The debt discount is amortized to interest expense using the effective interest method through February 2019.

As of December 31, 2017, the 2019 Convertible Notes were trading at approximately 100.9% of their face value, resulting in a total market value of $348 million compared to a carrying value of $340 million. The actual conversion value of the 2019 Convertible Notes is based on the product of the conversion rate and the market price of the Company's Class A common stock, as defined in the Convertible Debt indenture. As of December 31, 2017, the Company's Class A common stock closed at $18.85 per share, resulting in a pro forma conversion value for the Convertible Notes of approximately $279 million.

During each year ended December 31, 2017 and 2016, the Company recorded the following expenses in relation to the 2020 and 2019 Convertible Notes on a combined basis at the effective rates of 5.10% and 5.00%, respectively:



(In millions)
Interest expense^(a)	$	21
Debt discount amortization	9
Debt issuance costs amortization	3
	$	33

^(a)Interest expense is calculated using coupon rate of 3.25% and 3.5% for 2020 and 2019 Convertible Notes, respectively.

NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility

The Company borrowed $55 million from the revolving credit facility during the year ended December 31, 2017 for general corporate needs as well as to fund dividend payments.

The Company used its proceeds of $97.5 million from the CVSR Holdco Financing Arrangement, a portion of its proceeds from the issuance of the 2026 Senior Notes, as well as its cash on hand to repay the outstanding borrowings under the revolving credit facility during the year ended December 31, 2016.

On February 6, 2018, NRG Yield Operating LLC and NRG Yield LLC amended the revolving credit facility to modify the "change of control" provisions to permit the consummation of the NRG Transaction, and also to permit NRG Yield Operating LLC, NRG Yield LLC and certain subsidiaries to incur up to $1.5 billion of unsecured indebtedness in order to repurchase or make other required cash payments, in each case if applicable, with respect to NRG Yield Operating LLC’s outstanding senior notes and NRG Yield's outstanding convertible notes in connection with the NRG Transaction.

Project - level Debt

November 2017 Drop Down Assets Debt

As part of the November 2017 Drop Down acquisition, the Company assumed non-recourse debt of $26 million relating to certain SPP funds. The assumed debt consisted of the following: a) a term loan under a credit agreement with a bank, with a maturity date of December 31, 2038 and interest rate of 4.69%. The credit agreement includes a letter of credit supporting debt service requirements and a letter of credit in support of the PPA; b) and financing obligation in connection with a sale-leaseback transaction with a bank for a period through March 31, 2032. The company will accrete the financing obligation over the lease term based on the lease's implicit interest rate of 8%.

Agua Caliente Borrower 2, due 2038

On February 17, 2017, Agua Caliente Borrower 1 LLC, an indirect subsidiary of NRG, and Agua Caliente Borrower 2 LLC, issued $130 million of senior secured notes under the Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC financing agreement, or Agua Caliente Holdco Financing Agreement, that bear interest at 5.43% and mature on December 31, 2038. As described in Note 3, Business Acquisitions, on March 27, 2017, the Company acquired Agua Caliente Borrower 2 LLC from NRG as part of the March 2017 Drop Down Assets acquisition and assumed NRG's portion of senior secured notes under the Agua Caliente Holdco Financing Agreement. Agua Caliente Borrower 2 LLC holds $41 million of the Agua Caliente Holdco debt as of December 31, 2017. The debt is joint and several with respect to Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC and is secured by the equity interests of each borrower in the Agua Caliente solar facility.

Utah Solar Portfolio, due 2022

As part of the March 2017 Drop Down Assets acquisition, the Company assumed non-recourse debt of $287 million relating to the Utah Solar Portfolio at an interest rate of LIBOR plus 2.625%. The debt matures on December 16, 2022. The $287 million consisted of $222 million outstanding at the time of NRG's acquisition of the Utah Solar Portfolio on November 2, 2016, and additional borrowings of $65 million, net of debt issuance costs, incurred during 2016. The Company holds $278 million of the Utah Solar Portfolio debt as of December 31, 2017.

Thermal Financing

On October 31, 2016, NRG Energy Center Minneapolis LLC, a subsidiary of the Company, received proceeds of $125 million from the issuance of 3.55% Series D notes due October 31, 2031, or the Series D Notes, and entered into a shelf facility for the anticipated issuance of an additional $70 million of Series E notes at a 4.80% fixed rate. The Series D Notes will be secured by substantially all of the assets of NRG Energy Center Minneapolis LLC. NRG Thermal LLC has guaranteed the indebtedness and its guarantee is secured by a pledge of the equity interests in all of NRG Thermal LLC’s subsidiaries. NRG Energy Center Minneapolis LLC distributed the proceeds of the Series D Notes to NRG Thermal LLC, which in turn distributed the proceeds to NRG Yield Operating LLC to be utilized for general corporate purposes, including potential acquisitions.

On March 16, 2017, NRG Energy Center Minneapolis LLC, a subsidiary of NRG Thermal LLC, amended the shelf facility of its existing Thermal financing arrangement to allow for the issuance of an additional $10 million of Series F notes at a 4.60% interest rate, or Series F Notes, increasing the total principal amount of notes available for issuance under the shelf facility to $80 million. The Series E and Series F Notes will be secured by substantially all of the assets of NRG Energy Center Minneapolis LLC. NRG Thermal LLC has guaranteed the indebtedness and its guarantee is secured by a pledge of the equity interests in all of NRG Thermal LLC’s subsidiaries.

CVSR Holdco Notes, due 2037

On July 15, 2016, CVSR Holdco, the indirect owner of the CVSR solar facility, issued $200 million of senior secured notes under the CVSR Holdco Financing Agreement, or 2037 CVSR Holdco Notes, that bear interest at 4.68% and mature on March 31, 2037. Net proceeds were distributed to the Company and NRG based on their respective ownership as of July 15, 2016, and, accordingly, the Company received net proceeds of $97.5 million.

As described in Note 3, Business Acquisitions, on September 1, 2016, the Company acquired the remaining 51.05% of CVSR, and assumed additional debt of $496 million, which represents 51.05% of the CVSR project level debt and 51.05% of the 2037 CVSR Holdco Notes. In connection with the retrospective adjustment of prior periods, as described in Note 1, Nature of Business, the Company now consolidates CVSR and 100% of its debt, consisting of $771 million of project level debt and $200 million of 2037 CVSR Holdco Notes as of September 1, 2016.

Interest Rate Swaps — Project Financings

Many of the Company's project subsidiaries entered into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. These swaps amortize in proportion to their respective loans and are floating for fixed where the project subsidiary pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value and will receive quarterly the equivalent of a floating interest payment based on the same notional value. All interest rate swap payments by the project subsidiary and its counterparty are made quarterly and the LIBOR is determined in advance of each interest period.

The following table summarizes the swaps, some of which are forward starting as indicated, related to the Company's project level debt as of December 31, 2017:



	% of Principal		Fixed Interest Rate		Floating Interest Rate	Notional Amount at December 31, 2017 (In millions)		Effective Date	Maturity Date
Alpine	85	%	various		3-Month LIBOR	$	115	various	various
Avra Valley	85	%	2.333	%	3-Month LIBOR	46		November 30, 2012	November 30, 2030
AWAM	100	%	2.47	%	3-Month LIBOR	17		May 22, 2013	May 15, 2031
Blythe	75	%	3.563	%	3-Month LIBOR	13		June 25, 2010	June 25, 2028
Borrego	75	%	1.125	%	3-Month LIBOR	5		April 3, 2013	June 30, 2020
El Segundo	75	%	various		3-Month LIBOR	340		various	various
Kansas South	75	%	2.368	%	6-Month LIBOR	21		June 28, 2013	December 31, 2030
Laredo Ridge	75	%	2.31	%	3-Month LIBOR	75		March 31, 2011	March 31, 2026
Marsh Landing	75	%	3.244	%	3-Month LIBOR	295		June 28, 2013	June 30, 2023
Roadrunner	75	%	4.313	%	3-Month LIBOR	26		September 30, 2011	December 31, 2029
South Trent	75	%	3.265	%	3-Month LIBOR	40		June 15, 2010	June 14, 2020
South Trent	75	%	4.95	%	3-Month LIBOR	21		June 30, 2020	June 14, 2028
Tapestry	75	%	2.21	%	3-Month LIBOR	146		December 30, 2011	December 21, 2021
Tapestry	50	%	3.57	%	3-Month LIBOR	60		December 21, 2021	December 21, 2029
Utah Solar Portfolio	80	%	various		1-Month LIBOR	223		various	September 30, 2036
Viento Funding II	90	%	various		6-Month LIBOR	148		various	various
Viento Funding II	90	%	4.985	%	6-Month LIBOR	65		July 11, 2023	June 30, 2028
Walnut Creek Energy	75	%	various		3-Month LIBOR	239		June 28, 2013	May 31, 2023
WCEP Holdings	90	%	4.003	%	3-Month LIBOR	45		June 28, 2013	May 31, 2023
Total						$	1,940

Annual Maturities

Annual payments based on the maturities of the Company's debt, for the years ending after December 31, 2017, are as follows:



	(In millions)
2018	$	306
2019	722
2020	657
2021	455
2022	653
Thereafter	3,121
Total	$	5,914

Long-Term Debt

For a discussion of NRG Yield Inc.’s financing arrangements, see Note 10, Long-term Debt, to the Company's consolidated financial statements.

Earnings Per Share

12 Months Ended

Dec. 31, 2017

Earnings Per Share

(Loss) Earnings Per Share

Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding. Shares issued during the year are weighted for the portion of the year that they were outstanding. Diluted earnings per share is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period.

The number of shares and per share amounts for the period ended December 31, 2015 have been retrospectively restated to reflect the Recapitalization as further described in Note 12, Stockholders' Equity.

The reconciliation of the Company's basic and diluted (loss) earnings per share is shown in the following table:



	Year Ended December 31, 2017						Year Ended December 31, 2016				Year Ended December 31, 2015
(In millions, except per share data) ^(a)	Common Class A			Common Class C			Common Class A		Common Class C		Common Class A		Common Class C
Basic and diluted (loss) earnings per share attributable to NRG Yield, Inc. common stockholders
Net (loss) income attributable to NRG Yield, Inc.	$	(6	)	$	(10	)	$	20	$	37	$	14	$	19
Weighted average number of common shares outstanding — basic and diluted	35			64			35		63		35		49
(Loss) Earnings per weighted average common share — basic and diluted	$	(0.16	)	$	(0.16	)	$	0.58	$	0.58	$	0.40	$	0.40

^(a)Net (loss) income attributable to NRG Yield, Inc. and basic and diluted (loss) earnings per share might not recalculate due to presenting values in millions rather than whole dollars.

The following table summarizes the Company's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted earnings per share:



	Year Ended December 31,
	2017	2016	2015
	(In millions of shares)
2019 Convertible Notes - Common Class A	15	15	15
2020 Convertible Notes - Common Class C	10	10	5

Stockholders' Equity

12 Months Ended

Dec. 31, 2017

Stockholders' Equity Attributable to Parent [Abstract]

Stockholders' Equity

On July 22, 2013, in connection with its initial public offering, the Company authorized 500,000,000 shares of Class A common stock, of which 22,511,250 were issued to the public and became outstanding. In addition, the Company authorized 500,000,000 shares of Class B common stock, of which 42,738,750 were issued to NRG concurrently with the initial public offering and became outstanding. The Company utilized proceeds from the issuance of the Class A common stock to acquire a controlling interest in NRG Yield LLC from NRG. Each share of the Class A common stock and the Class B common stock entitles the holder to one vote on all matters.

In 2014, the Company issued 12,075,000 shares of Class A common stock and used the proceeds to acquire 12,075,000 additional Class A units of NRG Yield LLC.

Recapitalization

On May 5, 2015, the Company's stockholders approved amendments to the Company's certificate of incorporation that adjusted the Company’s capital structure by creating two new classes of capital stock, Class C common stock and Class D common stock, and distributed shares of Class C and Class D common stock to holders of the Company's outstanding Class A and Class B common stock, respectively, through a stock split. The Recapitalization became effective on May 14, 2015.

The Company also retrospectively adjusted all prior period share and per share amounts in the consolidated financial statements for the effect of the stock dividend, so that all periods are comparable.

Class C Common Stock Issuance

On June 29, 2015, the Company closed on its offering of 28,198,000 shares of Class C common stock, which included 3,678,000 shares of Class C common stock purchased by the underwriters through the exercise of an over-allotment option. Net proceeds to the Company from the sale of the Class C common stock were $599 million, net of underwriting discounts and commissions of $21 million. The Company utilized the proceeds of the offering to acquire 28,198,000 additional Class C units of NRG Yield LLC.

At-the-Market Equity Offering Program, or the ATM Program

NRG Yield, Inc. is party to an equity distribution agreement with Barclays Capital Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC and RBC Capital Markets, LLC, as sales agents. Pursuant to the terms of the equity distribution agreement, NRG Yield, Inc. may offer and sell shares of its Class C common stock par value $0.01 per share, from time to time through the sales agents up to an aggregate sales price of $150 million through an at-the-market equity offering program, or the ATM Program. NRG Yield, Inc. may also sell shares of its Class C common stock to any of the sales agents, as principals for its own account, at a price agreed upon at the time of sale.

As of December 31, 2017, Yield, Inc. issued 1,921,866 shares of Class C common stock under the ATM Program for gross proceeds of $35 million and incurred commission fees of $346 thousand. At December 31, 2017, approximately $115 million of Class C common stock remains available for issuance under the ATM Program.

As a result of the Company's sale of shares of Class C common stock under the ATM Program, the public shareholders of Class A and Class C common stock increased their economic and voting interests in NRG Yield, Inc. to 53.7%, and 44.9%, respectively, as of December 31, 2017.

Dividends to Class A and Class C common stockholders

The following table lists the dividends paid on the Company's Class A and Class C common stock during the year ended December 31, 2017:



	Fourth Quarter 2017		Third Quarter 2017		Second Quarter 2017		First Quarter 2017
Dividends per Class A share	$	0.288	$	0.28	$	0.27	$	0.26
Dividends per Class C share	$	0.288	$	0.28	$	0.27	$	0.26

Dividends on the Class A and Class C common stock are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations. The Company expects that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.

On February 15, 2018, the Company declared a quarterly dividend on its Class A and Class C common stock of $0.298 per share payable on March 15, 2018, to stockholders of record as of March 1, 2018.

The Company also authorized 10,000,000 shares of preferred stock, par value $0.01 per share. None of the shares of preferred stock have been issued.

Distributions/Contributions to/from NRG

The following table lists the distributions paid to NRG during the year ended December 31, 2017:



	Fourth Quarter 2017		Third Quarter 2017		Second Quarter 2017		First Quarter 2017
Distributions per Class B unit	$	0.288	$	0.28	$	0.27	$	0.26
Distributions per Class D unit	$	0.288	$	0.28	$	0.27	$	0.26

The portion of the distributions paid by NRG Yield LLC to NRG is recorded as a reduction to the Company's noncontrolling interest balance. The portion of the distributions paid by NRG Yield LLC to the Company was utilized to fund the dividends to the Class A and Class C common stockholders described above.

On February 15, 2018, NRG Yield LLC declared a quarterly distribution on its Class B and Class D common stock of $0.298 per unit payable to NRG on March 15, 2018.

During 2017, 2016, and 2015, the Company acquired the Drop Down Assets from NRG, as described in Note 3, Business Acquisitions. The difference between the cash paid and historical value of the acquired Drop Down Assets was recorded as a distribution to/contribution from NRG with the offset to noncontrolling interest. As the projects were owned by NRG prior to the Drop Down Assets acquisitions, the pre-acquisition income (loss) of such projects are recorded as attributable to NRG's noncontrolling interest. Prior to the date of acquisition, certain of the projects made distributions to NRG and NRG made contributions into certain projects. These amounts are reflected within the Company’s statement of stockholders’ equity as changes in the noncontrolling interest balance.

Segment Reporting

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment



	Year ended December 31, 2017
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	336		$	501		$	172		$	—		$	1,009
Cost of operations	77			133			116			—			326
Depreciation and amortization	103			210			21			—			334
Impairment losses	—			44			—			—			44
General and administrative	—			—			—			19			19
Acquisition-related transaction and integration costs	—			—			—			3			3
Operating income (loss)	156			114			35			(22		)	283
Equity in earnings of unconsolidated affiliates	12			59			—			—			71
Other income, net	1			2			—			1			4
Loss on debt extinguishment	—			(3		)	—			—			(3		)
Interest expense	(49		)	(163		)	(10		)	(84		)	(306		)
Income (loss) before income taxes	120			9			25			(105		)	49
Income tax expense	—			—			—			72			72
Net Income (Loss)	$	120		$	9		$	25		$	(177	)	$	(23	)
Balance Sheet
Equity investment in affiliates	$	102		$	1,076		$	—		$	—		$	1,178
Capital expenditures ^(a)	15			4			16			—			35
Total Assets	$	1,897		$	5,811		$	422		$	153		$	8,283



	Year ended December 31, 2016
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	333		$	532		$	170		$	—		$	1,035
Cost of operations	66			128			114			—			308
Depreciation and amortization	80			203			20			—			303
Impairment losses	—			185			—			—			185
General and administrative	—			—			—			16			16
Acquisition-related transaction and integration costs	—			—			—			1			1
Operating income (loss)	187			16			36			(17		)	222
Equity in earnings of unconsolidated affiliates	13			47			—			—			60
Other income, net	1			2			—			—			3
Interest expense	(48		)	(151		)	(7		)	(78		)	(284		)
Income (loss) before income taxes	153			(86		)	29			(95		)	1
Income tax benefit	—			—			—			(1		)	(1		)
Net Income (Loss)	$	153		$	(86	)	$	29		$	(94	)	$	2
Balance Sheet
Equity investments in affiliates	$	106		$	1,046		$	—		$	—		$	1,152
Capital expenditures ^(a)	7			2			14			—			23
Total Assets	$	1,993		$	6,114		$	426		$	429		$	8,962



	Year ended December 31, 2015
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	336		$	458		$	174		$	—		$	968
Cost of operations	59			138			126			—			323
Depreciation and amortization	81			203			19			—			303
Impairment losses	—			1			—			—			1
General and administrative	—			—			—			12			12
Acquisition-related transaction and integration costs	—			—			—			3			3
Operating income (loss)	196			116			29			(15		)	326
Equity in earnings of unconsolidated affiliates	14			17			—			—			31
Other income, net	1			2			—			—			3
Loss on debt extinguishment	(7		)	(2		)	—			—			(9		)
Interest expense	(48		)	(151		)	(7		)	(61		)	(267		)
Income (loss) before income taxes	156			(18		)	22			(76		)	84
Income tax expense	—			—			—			12			12
Net Income (Loss)	$	156		$	(18	)	$	22		$	(88	)	$	72

Segment Reporting

The Company’s segment structure reflects how management currently operates and allocates resources. The Company's businesses are segregated based on conventional power generation, renewable businesses which consist of solar and wind, and the thermal and chilled water business. The Corporate segment reflects the Company's corporate costs. The Company'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, and CAFD, as well as economic gross margin and net income (loss).

The Company generated more than 10% of its revenues from the following customers for the years ended December 31, 2017, 2016 and 2015:



	2017		2016		2015
Customer	Conventional (%)	Renewables (%)	Conventional (%)	Renewables (%)	Conventional (%)	Renewables (%)
SCE	21%	20%	21%	21%	22%	17%
PG&E	12%	11%	12%	11%	12%	12%



	Year ended December 31, 2017
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	336		$	501		$	172		$	—		$	1,009
Cost of operations	77			133			116			—			326
Depreciation and amortization	103			210			21			—			334
Impairment losses	—			44			—			—			44
General and administrative	—			—			—			19			19
Acquisition-related transaction and integration costs	—			—			—			3			3
Operating income (loss)	156			114			35			(22		)	283
Equity in earnings of unconsolidated affiliates	12			59			—			—			71
Other income, net	1			2			—			1			4
Loss on debt extinguishment	—			(3		)	—			—			(3		)
Interest expense	(49		)	(163		)	(10		)	(84		)	(306		)
Income (loss) before income taxes	120			9			25			(105		)	49
Income tax expense	—			—			—			72			72
Net Income (Loss)	$	120		$	9		$	25		$	(177	)	$	(23	)
Balance Sheet
Equity investment in affiliates	$	102		$	1,076		$	—		$	—		$	1,178
Capital expenditures ^(a)	15			4			16			—			35
Total Assets	$	1,897		$	5,811		$	422		$	153		$	8,283

^(a) Includes accruals.



	Year ended December 31, 2016
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	333		$	532		$	170		$	—		$	1,035
Cost of operations	66			128			114			—			308
Depreciation and amortization	80			203			20			—			303
Impairment losses	—			185			—			—			185
General and administrative	—			—			—			16			16
Acquisition-related transaction and integration costs	—			—			—			1			1
Operating income (loss)	187			16			36			(17		)	222
Equity in earnings of unconsolidated affiliates	13			47			—			—			60
Other income, net	1			2			—			—			3
Interest expense	(48		)	(151		)	(7		)	(78		)	(284		)
Income (loss) before income taxes	153			(86		)	29			(95		)	1
Income tax benefit	—			—			—			(1		)	(1		)
Net Income (Loss)	$	153		$	(86	)	$	29		$	(94	)	$	2
Balance Sheet
Equity investments in affiliates	$	106		$	1,046		$	—		$	—		$	1,152
Capital expenditures ^(a)	7			2			14			—			23
Total Assets	$	1,993		$	6,114		$	426		$	429		$	8,962

^(a) Includes accruals.



	Year ended December 31, 2015
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	336		$	458		$	174		$	—		$	968
Cost of operations	59			138			126			—			323
Depreciation and amortization	81			203			19			—			303
Impairment losses	—			1			—			—			1
General and administrative	—			—			—			12			12
Acquisition-related transaction and integration costs	—			—			—			3			3
Operating income (loss)	196			116			29			(15		)	326
Equity in earnings of unconsolidated affiliates	14			17			—			—			31
Other income, net	1			2			—			—			3
Loss on debt extinguishment	(7		)	(2		)	—			—			(9		)
Interest expense	(48		)	(151		)	(7		)	(61		)	(267		)
Income (loss) before income taxes	156			(18		)	22			(76		)	84
Income tax expense	—			—			—			12			12
Net Income (Loss)	$	156		$	(18	)	$	22		$	(88	)	$	72

Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Effective Tax Rate

The income tax provision consisted of the following amounts:



	Year Ended December 31,
	2017			2016			2015
	(In millions, except percentages)
Current
U.S. Federal	$	—		$	—		$	—
State	—			—			—
Total — current	—			—			—
Deferred
U.S. Federal	75			(1		)	10
State	(3		)	—			2
Total — deferred	72			(1		)	12
Total income tax expense (benefit)	$	72		$	(1	)	$	12

A reconciliation of the U.S. federal statutory rate of 35% to the Company's effective rate is as follows:



	Year Ended December 31,
	2017			2016			2015
	(In millions, except percentages)
Income Before Income Taxes	$	49		$	1		$	84
Tax at 35%	17			—			29
State taxes, net of federal benefit	(3		)	—			2
Tax Cuts and Jobs Act - tax rate change	68			—			—
Investment tax credits	(1		)	(1		)	(1		)
Impact of non-taxable partnership earnings	(9		)	(1		)	(17		)
Production tax credits, including prior year true-up	(1		)	4			(4		)
Other	1			(3		)	3
Income tax expense (benefit)	$	72		$	(1	)	$	12
Effective income tax rate	147		%	(100		)%	14		%

For the year ended December 31, 2017, the overall effective tax rate was different than the statutory rate of 35% primarily due to tax expense recorded from the revaluation of the existing net deferred tax asset pursuant to the reduction in the corporate income tax rate to 21% in accordance with the Tax Cuts and Jobs Act. In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, which addresses how a company may recognize provisional amounts for the effect of the changes related to the Tax Act. Consistent with that guidance, the Company recognized provisional amounts based upon our interpretation of the tax laws and estimates which require significant judgments.

For the years ended December 31, 2016 and 2015, the overall effective tax rate was different than the statutory rate of 35% primarily due to taxable earnings allocated to NRG resulting from its interest in NRG Yield LLC and production and investment tax credits generated from certain wind and solar assets, respectively.

The Company currently owns 53.7% of NRG Yield LLC and consolidates the results due to its controlling interest. The Company records NRG's 46.3% ownership as noncontrolling interest in the financial statements. For tax purposes, NRG Yield LLC is treated as a partnership; therefore, the Company and NRG each record their respective share of taxable income or loss.

The temporary differences, which gave rise to the Company's deferred tax assets, consisted of the following:



	As of December 31,
	2017			2016
	(In millions)
Deferred tax liabilities:
Investment in projects	$	70		$	19
Total deferred tax liabilities	70			19
Deferred tax assets:
Production tax credits carryforwards	7			5
Investment tax credits	1			1
U.S. Federal net operating loss carryforwards	183			226
Capital loss carryforwards	10			16
State net operating loss carryforwards	7			3
Total deferred tax assets	208			251
Valuation allowance	$	(10	)	$	(16	)
Total deferred tax assets, net of valuation allowance	$	198		$	235
Net deferred noncurrent tax asset	$	128		$	216

The primary driver for the decrease in the net deferred tax asset from $216 million to $128 million is the revaluation of the ending balance utilizing a 21% corporate income tax rate pursuant to the Tax Cuts and Jobs Act as of December 22, 2017.

Tax Receivable and Payable

As of December 31, 2017, the Company has no current or long term tax receivable or payable to be recorded.

Deferred Tax Assets and Valuation Allowance

Net deferred tax balance — As of December 31, 2017 and 2016, NRG recorded a net deferred tax asset of $138 million and $232 million, respectively. 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. The Company considered the profit before tax generated in recent years, as well as projections of future earnings and estimates of taxable income in arriving at this conclusion. The Company believes that $10 million, a deferred tax asset, expected to generate a capital loss, for which there are no existing capital gains or available tax planning strategies to utilize the asset in the future may not be realized, resulting in the recording of a valuation allowance.

NOL carryforwards — At December 31, 2017, the Company had domestic NOLs carryforwards for federal income tax purposes of $183 million and cumulative state NOLs of $7 million tax-effected.

Uncertain Tax Positions

The Company had no identified uncertain tax positions that require evaluation as of December 31, 2017.

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions Disclosure	In addition to the transactions and relationships described elsewhere in the notes to the consolidated financial statements, certain subsidiaries of NRG provide services to the Company's project entities. Amounts due to NRG subsidiaries are recorded as accounts payable — affiliate and amounts due to the Company from NRG subsidiaries are recorded as accounts receivable — affiliate in the Company's balance sheet. The disclosures below summarize the Company's material related party transactions with NRG and its subsidiaries that are included in the Company's operating revenues and operating costs. Power Hedge Contracts by and between Renewable Entities and NRG Texas Power LLC Certain NRG Wind TE Holdco entities, which are subsidiaries in the Renewables segment, entered into power hedge contracts with NRG Texas Power LLC, a subsidiary of NRG, and generated $16 million of revenue during the year ended December 31, 2015. Effective October 2015, Elbow Creek entered into a PPA with NRG Power Marketing LLC, or NRG Power Marketing, a wholly-owned subsidiary of NRG, as further described below, and the hedge agreement between Elbow Creek and NRG Texas Power LLC was terminated. Power Purchase Agreements (PPAs) between the Company and NRG Power Marketing Elbow Creek and Dover are parties to PPAs with NRG Power Marketing and generate revenue under the PPAs, which are recorded to operating revenues in the Company's consolidated statements of operations. For the years ended December 31, 2017 and 2016, Elbow Creek generated revenues of $8 million each year, and Dover generated revenues of $4 million and $5 million, respectively. Energy Marketing Services Agreement by and between Thermal entities and NRG Power Marketing NRG Energy Center Dover LLC, NRG Energy Center Minneapolis, NRG Energy Center Phoenix LLC, and NRG Energy Center Paxton LLC, or Thermal entities, are parties to Energy Marketing Services Agreements with NRG Power Marketing, a wholly-owned subsidiary of NRG. Under the agreements, NRG Power Marketing procures fuel and fuel transportation for the operation of Thermal entities. The Thermal entities purchased a total of $9 million of natural gas during each of the years ended December 31, 2017 and 2016. During the year ended December 31, 2015 total purchases of natural gas under the agreement were $13 million. Operation and Maintenance (O&M) Services Agreements by and between Company's subsidiaries and NRG Certain of the Company's subsidiaries are party to O&M Services Agreements with NRG, pursuant to which NRG subsidiaries provide necessary and appropriate services to operate and maintain the subsidiaries' plant operations, businesses and thermal facilities. NRG is reimbursed for the provided services, as well as for all reasonable and related expenses and expenditures, and payments to third parties for services and materials rendered to or on behalf of the parties to the agreements. NRG is not entitled to any management fee or mark-up under the agreements. The fees incurred under this agreement were $39 million for the year ended December 31, 2017, and $36 million for each year ended December 31, 2016 and 2015. The Company had $13 million due to NRG for the services performed during the year ended December 31, 2017 under the O&M Agreements, $5 million of which was paid off as of March 1, 2018. The Company had $22 million due to NRG for the services performed during the year ended December 31, 2016 under the O&M Agreements. O&M Services Agreements by and between GenConn and NRG GenConn incurs fees under two O&M agreements with wholly-owned subsidiaries of NRG. The fees incurred under the agreements were $5 million each year for the years ended December 31, 2017 and 2016, and $4 million for the year ended December 31, 2015. Administrative Services Agreement by and between Marsh Landing and NRG West Coast LLC On December 19, 2016, Marsh Landing entered into an administrative services agreement with NRG West Coast LLC, a wholly owned subsidiary of NRG. The administrative services agreement was previously between Marsh Landing and GenOn Energy Services, LLC, a wholly-owned subsidiary of NRG and was subsequently assigned to and assumed by NRG West Coast LLC. The Company reimbursed costs under this agreement of approximately $15 million, $14 million and $13 million for the years ended December 31, 2017, 2016 and 2015, respectively. There was a balance of $1 million due to NRG West Coast LLC in accounts payable — affiliate as of December 31, 2017 and 2016. Administrative Services Agreements by and between the Company and NRG Renew Operation & Maintenance LLC Various wholly-owned subsidiaries of the Company in the Renewables segment are party to administrative services agreements with NRG Renew Operation & Maintenance LLC, or RENOM, a wholly-owned subsidiary of NRG, which provides O&M services to these subsidiaries. The Company incurred total expenses for these services in the amount of $23 million, $13 million and $7 million for the years ended December 31, 2017, 2016 and 2015, respectively. There was a balance of $5 million due to RENOM as of December 31, 2017 and 2016. Management Services Agreement by and between the Company and NRG NRG provides the Company with various operational, management, and administrative services, which include human resources, accounting, tax, legal, information systems, treasury, and risk management, as set forth in the Management Services Agreement. As of December 31, 2017, the base management fee was approximately $8.5 million per year, subject to an inflation-based adjustment annually, at an inflation factor based on the year-over-year U.S. consumer price index. The fee is also subject to adjustments following the consummation of future acquisitions and as a result of a change in the scope of services provided under the Management Services Agreement. During the year ended December 31, 2017, the fee was increased by approximately $1 million per year, primarily due to the acquisition of the March 2017, August 2017 and November 2017 Drop Down Assets, as further described in Note 3, Business Acquisitions. In addition to the base management fee, the Company is also responsible for any expenses that are directly incurred and paid for by NRG on behalf of the Company. Costs incurred under this agreement were approximately $10 million for each of the years ended December 31, 2017 and 2016, and $8 million for the year ended December 31, 2015. There was a balance of $4 million in accounts payable — affiliate due to NRG as of December 31, 2017, which the Company paid off in January 2018. EPC Agreement by and between NECP and NRG On October 31, 2016, NRG Business Services LLC, a subsidiary of NRG, and NECP, a wholly owned subsidiary of the Company, entered into an EPC agreement for the construction of a 73 MWt district energy system for NECP to provide 150 kpph of steam, 6,750 tons of chilled water and 7.5 MW of emergency backup power service to UPMC Mercy. The initial term of the energy services agreement with UPMC Mercy will be for a period of twenty years from the service commencement date. Pursuant to the terms of the EPC agreement, NECP agreed to pay NRG Business Services LLC $79 million, subject to adjustment based upon certain conditions in the EPC agreement, upon substantial completion of the project. The project is expected to reach COD in the first half of 2018. As of December 31, 2017, the parties made a number of amendments to the EPC Agreement, based on customer change orders, to increase the capacity of the district energy system from 73 MWt to 80 MWt, which also increased the payment from $79 million to $88 million.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Operating Lease Commitments

The Company leases certain facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2048. The effects of these scheduled rent increases, leasehold incentives, and rent concessions are recognized 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 $17 million, $15 million, and $10 million for the years ended December 31, 2017, 2016 and 2015, respectively.

The Company's future minimum lease commitments under operating leases are $9 million for each of the years ending December 31, 2018 through 2022, and $151 million thereafter.



Period	(In millions)

Gas and Transportation Commitments

The Company has entered into contractual arrangements to procure power, fuel and associated transportation services. For the years ended December 31, 2017, 2016 and 2015, the Company purchased $34 million, $32 million and $40 million, respectively, under such arrangements. As further described in Note 15, Related Party Transactions, these purchases include intercompany transactions between certain Thermal entities and NRG Power Marketing under the Energy Marketing Services Agreements in the amount of $9 million for each of the years ended December 31, 2017 and 2016. Total intercompany purchases of natural gas under the agreement were $13 million for the year ended December 31, 2015.

As of December 31, 2017, the Company's commitments under such outstanding agreements are estimated as follows:



Period	(In millions)
2018	$	11
2019	5
2020	3
2021	3
2022	3
Thereafter	16
Total	$	41

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. The Company 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. As applicable, the Company has established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management assesses such matters based on current information and makes a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. The Company is unable to predict the outcome of the legal proceedings below 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, the Company 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 the Company's consolidated financial position, results of operations, or cash flows.

Braun v. NRG Yield, Inc. — On April 19, 2016, plaintiffs filed a putative class action lawsuit against NRG Yield, Inc., the current and former members of its board of directors individually, and other parties in California Superior Court in Kern County, CA. Plaintiffs allege various violations of the Securities Act due to the defendants’ alleged failure to disclose material facts related to low wind production prior to NRG Yield, Inc.'s June 22, 2015 Class C common stock offering. Plaintiffs seek compensatory damages, rescission, attorney’s fees and costs. The defendants filed objections and a motion challenging jurisdiction on October 18, 2016. On December 1, 2017, the parties agreed to a stipulation which provides the plaintiffs' opposition is due on March 6, 2018 and the defendants' reply is due on May 4, 2018.

Ahmed v. NRG Energy, Inc. and the NRG Yield Board of Directors — On September 15, 2016, plaintiffs filed a putative class action lawsuit against NRG Energy, Inc., the directors of NRG Yield, Inc., and other parties in the Delaware Chancery Court. The complaint alleges that the defendants breached their respective fiduciary duties with regard to the recapitalization of NRG Yield, Inc. common stock in 2015. The plaintiffs generally seek economic damages, attorney’s fees and injunctive relief. The defendants filed a motion to dismiss the lawsuit on December 21, 2016. Plaintiffs filed their objection to the motion to dismiss on February 15, 2017. The defendants' reply was filed on March 24, 2017. The court heard oral argument on the defendants' motion to dismiss on June 20, 2017. On September 7, 2017, the court requested additional briefing which the parties provided on September 21, 2017. On December 11, 2017, the court dismissed the lawsuit with prejudice, thereby ending the case.

GenOn Noteholders' Lawsuit — On December 13, 2016, certain indenture trustees for an ad hoc group of holders, or the Noteholders, of the GenOn Energy, Inc., or GenOn, 7.875% Senior Notes due 2017, 9.500% Notes due 2018, and 9.875% Notes due 2020, and the GenOn Americas Generation, LLC 8.50% Senior Notes due 2021 and 9.125% Senior Notes due 2031, along with certain of the Noteholders, filed a complaint in the Superior Court of the State of Delaware against NRG and GenOn alleging certain claims related to the Services Agreement between NRG and GenOn. On April 30, 2017, the Noteholders filed an amended complaint that asserts additional claims of fraudulent transfer, insider preference and breach of fiduciary duties. In addition to NRG and GenOn, the amended complaint names NRG Yield LLC and certain current and former officers and directors of GenOn as defendants. The plaintiffs, among other things, generally seek return of all monies paid under the Services Agreement and any other damages that the court deems appropriate. On April 28, 2017, the bondholders filed an amended complaint adding the GenOn directors and officers as defendants and asserting claims that they breached certain fiduciary duties. Plaintiffs specifically allege that the transfer of Marsh Landing to NRG Yield LLC constituted a fraudulent transfer. On June 12, 2017, certain GenOn entities, NRG and certain holders of the GenOn and GenOn Americas Generation, LLC senior notes entered into a restructuring support and lock-up agreement. On December 14, 2017, a settlement agreement was entered into between GenOn and NRG which should ultimately resolve this lawsuit.

Commitments, Contingencies and Guarantees

See Note 14, Income Taxes, and Note 16, Commitments and Contingencies, to the Company's consolidated financial statements for a detailed discussion of NRG Yield, Inc.’s commitments and contingencies.

Unaudited Quarterly Financial Data

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Unaudited Quarterly Financial Data

Unaudited Quarterly Data

Refer to Note 2, Summary of Significant Accounting Policies, and Note 3, Business Acquisitions, for a description of the effect of unusual or infrequently occurring events during the quarterly periods. Below is summarized unaudited quarterly financial data, which includes the results of the November 2017 Drop Down Assets Acquisition and its impact on every quarter of the 2017 and 2016 results, which were recast to include the November 2017 Drop Down Assets, where applicable:



	Quarter Ended
	December 31,			September 30,			June 30,		March 31,
	2017
	(In millions, except per share data)
Operating Revenues	$	231		$	269		$	288	$	221

Operating Revenues (as previously reported)	N/A			265			284		218
Change	N/A			4			4		3

Operating Income	19			85			124		55

Operating Income (as previously reported)	N/A			95			122		54
Change	N/A			(10		)	2		1

Net (Loss) Income	(98		)	30			47		(2		)

Net Income (Loss) (as previously reported)	N/A			41			45		(1		)
Change	N/A			(11		)	2		(1		)

Net (Loss) Income Attributable to NRG Yield, Inc.	$	(70	)	$	29		$	28	$	(3	)
Weighted average number of Class A common shares outstanding — basic	35			35			35		35
Weighted average number of Class A common shares outstanding — diluted	35			49			49		35
Weighted average number of Class C common shares outstanding — basic	65			64			63		63
Weighted average number of Class C common shares outstanding — diluted	65			75			74		63
(Loss) Earnings per Weighted Average Class A and Class C Common Share - Basic	(0.71		)	0.30			0.29		(0.03		)
(Loss) Earnings per Weighted Average Class A Common Share - Diluted	(0.71		)	0.27			0.26		(0.03		)
(Loss) Earnings per Weighted Average Class C Common Share - Diluted	$	(0.71	)	$	0.29		$	0.28	$	(0.03	)



	Quarter Ended
	December 31,			September 30,		June 30,		March 31,
	2016
	(In millions, except per share data)
Operating Revenues	$	235		$	276	$	287	$	237

Operating Revenues (as previously reported)	232			272		283		234
Change	3			4		4		3

Operating (Loss) Income	(100		)	119		130		73

Operating (Loss) Income (as previously reported)	(99		)	117		128		72
Change	(1		)	2		2		1

Net (Loss) Income	(115		)	51		65		1

Net (Loss) Income (as previously reported)	(114		)	50		64		2
(Change)	(1		)	1		1		(1		)

Net (Loss) Income Attributable to NRG Yield, Inc.	$	(13	)	$	33	$	32	$	5
Weighted average number of Class A common shares outstanding — basic	35			35		35		35
Weighted average number of Class A common shares outstanding — diluted	35			49		49		35
Weighted average number of Class C common shares outstanding — basic	63			63		63		63
Weighted average number of Class C common shares outstanding — diluted	63			73		73		63
(Loss) Earnings per Weighted Average Class A and Class C Common Share - Basic	(0.14		)	0.34		0.33		0.05
(Loss) Earnings per Weighted Average Class A Common Share - Diluted	(0.14		)	0.30		0.29		0.05
(Loss) Earnings per Weighted Average Class C Common Share - Diluted	$	(0.14	)	$	0.32	$	0.31	$	0.05

Yield, Inc. (Parent) Footnotes (Notes)

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

Background and Basis of Presentation

Background

Effective May 14, 2015, the Company 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. The stock split is referred to as the Recapitalization and all references to share or per share amounts in the accompanying consolidated financial statements and applicable disclosures have been retrospectively adjusted to reflect the Recapitalization. Following the Recapitalization, the Company's Class A common stock continued trading on the New York Stock Exchange under the new ticker symbol "NYLD.A" and the Class C common stock began trading under the ticker symbol "NYLD".

NRG, through its holdings of Class B common stock and Class D common stock, has a 55.1% voting interest in the Company and receives distributions from NRG Yield LLC through its ownership of Class B units and Class D units. The holders of the Company's issued and outstanding shares of Class A common stock and Class C common stock are entitled to dividends as declared and have 44.9% of the voting power in the Company.

The Company is the sole managing member of NRG Yield LLC and operates and controls all of its business and affairs and consolidates the financial results of NRG Yield LLC and its subsidiaries. NRG Yield LLC is a holding company for the companies that directly and indirectly own and operate the Company's business. As of December 31, 2017, the Company and NRG have 53.7% and 46.3% economic interests in NRG Yield LLC, respectively. As a result of the current ownership of the Class B common stock and Class D common stock, NRG continues at the present time to control the Company, and the Company in turn, as the sole managing member of NRG Yield LLC, controls NRG Yield LLC and its subsidiaries.

Basis of Presentation

The condensed parent-only company financial statements have been prepared in accordance with Rule 12-04 of Regulation S-X, as the restricted net assets of NRG Yield, Inc.’s subsidiaries exceed 25% of the consolidated net assets of NRG Yield, Inc. The parent's 100% investment in its subsidiaries has been recorded using the equity basis of accounting in the accompanying condensed parent-only financial statements. These statements should be read in conjunction with the consolidated financial statements and notes thereto of NRG Yield, Inc.

Commitments and Contingencies

The Company's borrowings, including short term and long term portions consisted of the following:



	December 31, 2017			December 31, 2016			Interest rate % ^(a)		Letters of Credit Outstanding at December 31, 2017
	(In millions, except rates)
2026 Senior Notes	$	350		$	350		5.000
2024 Senior Notes	500			500			5.375
2020 Convertible Notes	288			288			3.250
2019 Convertible Notes	345			345			3.500
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 ^(b)	55			—			L+2.500		$	74
Project-level debt:
Agua Caliente Borrower 2, due 2038	41			—			5.430		17
Alpine, due 2022	135			145			L+1.750		16
Alta Wind I - V lease financing arrangements, due 2034 and 2035	926			965			5.696 - 7.015		119
CVSR, due 2037	746			771			2.339 - 3.775		—
CVSR Holdco Notes, due 2037	194			199			4.680		13
El Segundo Energy Center, due 2023	400			443			L+1.75 - L+2.375		102
Energy Center Minneapolis, due 2025	83			96			5.950	%	—
Energy Center Minneapolis Series D Notes, due 2031	125			125			3.550		—
Laredo Ridge, due 2028	95			100			L+1.875		10
Marsh Landing, due 2023	318			370			L+1.875		22
Tapestry, due 2021	162			172			L+1.625		20
Utah Solar Portfolio, due 2022	278			287			various		13
Viento, due 2023	163			178			L+3.00		27
Walnut Creek, due 2023	267			310			L+1.625		41
Other	443			505			various		38
Subtotal project-level debt	4,376			4,666
Total debt	5,914			6,149
Less current maturities	(306		)	(323		)
Less net debt issuance costs	(60		)	(73		)
Less discounts^(c)	$	(17	)	$	(27	)
Total long-term debt	$	5,531		$	5,726

^(a) As of December 31, 2017, L+ equals 3 month LIBOR plus x%, except for Viento, due 2023 where L+ equals 6 month LIBOR plus 3.00%.

^(b) Applicable rate is determined by the borrower leverage ratio, as defined in the credit agreement.

^(c) Discounts relate to the 2019 Convertible Notes and 2020 Convertible Notes.

NRG Yield Operating LLC 2026 Senior Notes

2020 Convertible Senior Notes

2019 Convertible Senior Notes



(In millions)
Interest expense^(a)	$	21
Debt discount amortization	9
Debt issuance costs amortization	3
	$	33

^(a)Interest expense is calculated using coupon rate of 3.25% and 3.5% for 2020 and 2019 Convertible Notes, respectively.

NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility

The Company borrowed $55 million from the revolving credit facility during the year ended December 31, 2017 for general corporate needs as well as to fund dividend payments.

Project - level Debt

November 2017 Drop Down Assets Debt

Agua Caliente Borrower 2, due 2038

Utah Solar Portfolio, due 2022

Thermal Financing

CVSR Holdco Notes, due 2037

Interest Rate Swaps — Project Financings

The following table summarizes the swaps, some of which are forward starting as indicated, related to the Company's project level debt as of December 31, 2017:



	% of Principal		Fixed Interest Rate		Floating Interest Rate	Notional Amount at December 31, 2017 (In millions)		Effective Date	Maturity Date
Alpine	85	%	various		3-Month LIBOR	$	115	various	various
Avra Valley	85	%	2.333	%	3-Month LIBOR	46		November 30, 2012	November 30, 2030
AWAM	100	%	2.47	%	3-Month LIBOR	17		May 22, 2013	May 15, 2031
Blythe	75	%	3.563	%	3-Month LIBOR	13		June 25, 2010	June 25, 2028
Borrego	75	%	1.125	%	3-Month LIBOR	5		April 3, 2013	June 30, 2020
El Segundo	75	%	various		3-Month LIBOR	340		various	various
Kansas South	75	%	2.368	%	6-Month LIBOR	21		June 28, 2013	December 31, 2030
Laredo Ridge	75	%	2.31	%	3-Month LIBOR	75		March 31, 2011	March 31, 2026
Marsh Landing	75	%	3.244	%	3-Month LIBOR	295		June 28, 2013	June 30, 2023
Roadrunner	75	%	4.313	%	3-Month LIBOR	26		September 30, 2011	December 31, 2029
South Trent	75	%	3.265	%	3-Month LIBOR	40		June 15, 2010	June 14, 2020
South Trent	75	%	4.95	%	3-Month LIBOR	21		June 30, 2020	June 14, 2028
Tapestry	75	%	2.21	%	3-Month LIBOR	146		December 30, 2011	December 21, 2021
Tapestry	50	%	3.57	%	3-Month LIBOR	60		December 21, 2021	December 21, 2029
Utah Solar Portfolio	80	%	various		1-Month LIBOR	223		various	September 30, 2036
Viento Funding II	90	%	various		6-Month LIBOR	148		various	various
Viento Funding II	90	%	4.985	%	6-Month LIBOR	65		July 11, 2023	June 30, 2028
Walnut Creek Energy	75	%	various		3-Month LIBOR	239		June 28, 2013	May 31, 2023
WCEP Holdings	90	%	4.003	%	3-Month LIBOR	45		June 28, 2013	May 31, 2023
Total						$	1,940

Annual Maturities

Annual payments based on the maturities of the Company's debt, for the years ending after December 31, 2017, are as follows:



	(In millions)
2018	$	306
2019	722
2020	657
2021	455
2022	653
Thereafter	3,121
Total	$	5,914

Long-Term Debt

For a discussion of NRG Yield Inc.’s financing arrangements, see Note 10, Long-term Debt, to the Company's consolidated financial statements.

Operating Lease Commitments

The Company's future minimum lease commitments under operating leases are $9 million for each of the years ending December 31, 2018 through 2022, and $151 million thereafter.



Period	(In millions)

Gas and Transportation Commitments

As of December 31, 2017, the Company's commitments under such outstanding agreements are estimated as follows:



Period	(In millions)
2018	$	11
2019	5
2020	3
2021	3
2022	3
Thereafter	16
Total	$	41

Contingencies

Commitments, Contingencies and Guarantees

Dividends [Text Block]

Dividends

Cash distributions paid to NRG Yield, Inc. by its subsidiary, NRG Yield LLC, were $108 million, $92 million, and $69 million for the years ended December 31, 2017, 2016, and 2015, respectively.

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation

Principles of Consolidation

Cash and Cash Equivalents

Restricted Cash



	Year Ended December 31,
	2017		2016		2015
	(In millions)
Cash and cash equivalents	$	148	$	322	$	111
Restricted cash	168		176		143
Cash, cash equivalents and restricted cash shown in the statement of cash flows	316		498		254

Trade Receivables and Allowance for Doubtful Accounts

Notes Receivable

Trade Receivables and Allowance for Doubtful Accounts

Inventory

Property, Plant and Equipment

The Company 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.

Revenue Recognition

Thermal Revenues

Power Purchase Agreements, or PPAs

Derivative Financial Instruments


•	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.

Concentrations of Credit Risk

Fair Value of Financial Instruments

Asset Retirement Obligations



	(In millions)
Balance as of December 31, 2016	$	49
Revisions in estimates for current obligations/Additions	2
Accretion — expense	4
Balance as of December 31, 2017	$	55

Guarantees

Investments Accounted for by the Equity Method

Leases

Sale Leaseback Arrangements

Business Combinations

Use of Estimates

Tax Equity Arrangements

Reclassifications

Certain prior year amounts have been reclassified for comparative purposes.

Recent Accounting Developments

Recent Accounting Developments - Not Yet Adopted

Segment Reporting Segment Reporting (Policies)	12 Months Ended
Segment Reporting Segment Reporting (Policies)	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Reporting, Policy [Policy Text Block]	The Company’s segment structure reflects how management currently operates and allocates resources. The Company's businesses are segregated based on conventional power generation, renewable businesses which consist of solar and wind, and the thermal and chilled water business. The Corporate segment reflects the Company's corporate costs. The Company'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, and CAFD, as well as economic gross margin and net income (loss).

Nature of Business Nature of Business (Tables)

12 Months Ended

Dec. 31, 2017

Nature of Business Disclosure [Abstract]

IPO of NRG Yield

The following table represents the structure of the Company as of December 31, 2017:

The Company's operating assets are comprised of the following projects:

he Company's operating assets are comprised of the following projects:



Projects	Percentage Ownership		Net Capacity (MW) ^(a)	Offtake Counterparty	Expiration
Conventional
El Segundo	100	%	550	Southern California Edison	2023
GenConn Devon	50	%	95	Connecticut Light & Power	2040
GenConn Middletown	50	%	95	Connecticut Light & Power	2041
Marsh Landing	100	%	720	Pacific Gas and Electric	2023
Walnut Creek	100	%	485	Southern California Edison	2023
			1,945
Utility Scale Solar
Agua Caliente	16	%	46	Pacific Gas and Electric	2039
Alpine	100	%	66	Pacific Gas and Electric	2033
Avenal	50	%	23	Pacific Gas and Electric	2031
Avra Valley	100	%	26	Tucson Electric Power	2032
Blythe	100	%	21	Southern California Edison	2029
Borrego	100	%	26	San Diego Gas and Electric	2038
CVSR	100	%	250	Pacific Gas and Electric	2038
Desert Sunlight 250	25	%	63	Southern California Edison	2034
Desert Sunlight 300	25	%	75	Pacific Gas and Electric	2039
Kansas South	100	%	20	Pacific Gas and Electric	2033
Roadrunner	100	%	20	El Paso Electric	2031
TA High Desert	100	%	20	Southern California Edison	2033
Utah Solar Portfolio^(b)(e)	50	%	265	PacifiCorp	2036
			921
Distributed Solar
Apple I LLC Projects	100	%	9	Various	2032
AZ DG Solar Projects	100	%	5	Various	2025-2033
SPP Projects	100	%	25	Various	2026-2037
Other DG Projects	100	%	13	Various	2023-2039
			52
Wind
Alta I	100	%	150	Southern California Edison	2035
Alta II	100	%	150	Southern California Edison	2035
Alta III	100	%	150	Southern California Edison	2035
Alta IV	100	%	102	Southern California Edison	2035
Alta V	100	%	168	Southern California Edison	2035
Alta X^(b)	100	%	137	Southern California Edison	2038
Alta XI ^(b)	100	%	90	Southern California Edison	2038
Buffalo Bear	100	%	19	Western Farmers Electric Co-operative	2033
Crosswinds ^(b)(f)	99	%	21	Corn Belt Power Cooperative	2027
Elbow Creek ^(b)(f)	100	%	122	NRG Power Marketing LLC	2022
Elkhorn Ridge ^(b)(f)	66.7	%	54	Nebraska Public Power District	2029
Forward ^(b)(f)	100	%	29	Constellation NewEnergy, Inc.	2022
Goat Wind ^(b)(f)	100	%	150	Dow Pipeline Company	2025
Hardin ^(b)(f)	99	%	15	Interstate Power and Light Company	2027



Projects	Percentage Ownership		Net Capacity (MW) ^(a)	Offtake Counterparty	Expiration
Laredo Ridge	100	%	80	Nebraska Public Power District	2031
Lookout ^(b)(f)	100	%	38	Southern Maryland Electric Cooperative	2030
Odin ^(b)(f)	99.9	%	20	Missouri River Energy Services	2028
Pinnacle	100	%	55	Maryland Department of General Services and University System of Maryland	2031
San Juan Mesa ^(b)(f)	75	%	90	Southwestern Public Service Company	2025
Sleeping Bear ^(b)(f)	100	%	95	Public Service Company of Oklahoma	2032
South Trent	100	%	101	AEP Energy Partners	2029
Spanish Fork ^(b)(f)	100	%	19	PacifiCorp	2028
Spring Canyon II ^(b)	90.1	%	29	Platte River Power Authority	2039
Spring Canyon III ^(b)	90.1	%	25	Platte River Power Authority	2039
Taloga	100	%	130	Oklahoma Gas & Electric	2031
Wildorado ^(b)(f)	100	%	161	Southwestern Public Service Company	2027
			2,200
Thermal
NRG Energy Center Dover LLC	100	%	103	NRG Power Marketing LLC	2018
Thermal generation	100	%	20	Various	Various
			123
Total net generation capacity^(c)			5,241

Thermal equivalent MWt^(d)	100	%	1,319	Various	Various

^(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of December 31, 2017.

^(b) Projects are part of tax equity arrangements.

^(f) Projects are part of NRG Wind TE Holdco portfolio.

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Reconciliation of Cash and Cash Equivalents and Restricted Cash and Funds Deposited to Cash Flow [Table Text Block]



	Year Ended December 31,
	2017		2016		2015
	(In millions)
Cash and cash equivalents	$	148	$	322	$	111
Restricted cash	168		176		143
Cash, cash equivalents and restricted cash shown in the statement of cash flows	316		498		254

Schedule of Asset Retirement Obligations [Table Text Block]



	(In millions)
Balance as of December 31, 2016	$	49
Revisions in estimates for current obligations/Additions	2
Accretion — expense	4
Balance as of December 31, 2017	$	55

Business Acquisitions Business Acquisitions (Tables)

12 Months Ended

Dec. 31, 2017

November 2017 Drop Down Assets [Member]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The following is a summary of assets and liabilities transferred in connection with the acquisition of the November 2017 Drop Down Assets as of November 1, 2017:



	(In millions)
Assets:
Current assets	$	7
Property, plant and equipment	83
Non-current assets	12
Total assets	102
Liabilities:
Debt (Current and non-current) ^(a)	23
Other current and non-current liabilities	3
Total liabilities assumed	26
Net assets acquired	$	76

^(a) Net of $3 million of net debt issuance costs.

Business Acquisition, Pro Forma Information [Table Text Block]



	Year ended December 31, 2016						Year ended December 31, 2015
	As Previously Reported^(a)		November 2017 Drop Down Assets		As Currently Reported		As Previously Reported^(a)		November 2017 Drop Down Assets		As Currently Reported
(In millions)
Total operating revenues	$	1,021	$	14	$	1,035	$	953	$	15	$	968
Operating income	218		4		222		320		6		326
Net income	2		—		2		70		2		72

^(a) As previously reported in the May 9, 2017 Form 8-K filed in connection with the March 2017 Drop Down completed on March 27, 2017.



	As of December 31, 2016
(In millions)	As Previously Reported^(a)		November 2017 Drop Down Assets		As Currently Reported
Assets:
Current assets	$	656	$	14	$	670
Property, plant and equipment	5,460		94		5,554
Non-current assets	2,720		18		2,738
Total assets	8,836		126		8,962
Liabilities:
Debt	5,987		62		6,049
Other current and non-current liabilities	310		4		314
Total liabilities	6,297		66		6,363
Net assets	$	2,539	$	60	$	2,599

^(a) As previously reported in the May 9, 2017 Form 8-K filed in connection with the March 2017 Drop Down completed on March 27, 2017.

March 2017 Drop Down Assets [Member]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The following is a summary of assets and liabilities transferred in connection with the acquisition of the March 2017 Drop Down Assets as of March 27, 2017:



	(In millions)
Assets:
Cash	$	6
Equity investment in projects	456
Total assets acquired	462
Liabilities:
Debt (Current and non-current) ^(a)	320
Other current and non-current liabilities	3
Total liabilities assumed	323
Net assets acquired	$	139

^(a) Net of $8 million of debt issuance costs.

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

The Company’s major classes of property, plant, and equipment were as follows:



	December 31, 2017			December 31, 2016			Depreciable Lives
	(In millions)
Facilities and equipment	$	6,289		$	6,339		2 - 45 Years
Land and improvements	166			167
Construction in progress ^(a)	34			24
Total property, plant and equipment	6,489			6,530
Accumulated depreciation	(1,285		)	(976		)
Net property, plant and equipment	$	5,204		$	5,554

Investments Accounted for by the Equity Method and Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2017

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Variable Interest Entities [Table Text Block]

Summarized financial information for the Company's consolidated VIEs consisted of the following as of December 31, 2017:



(In millions)	NRG Wind TE Holdco		Alta TE Holdco		Spring Canyon
Other current and non-current assets	$	172	$	17	$	2
Property, plant and equipment	376		436		95
Intangible assets	2		262		—
Total assets	550		715		97
Current and non-current liabilities	197		9		5
Total liabilities	197		9		5
Noncontrolling interest	9		93		60
Net assets less noncontrolling interests	$	344	$	613	$	32

Schedule of Equity Method Investments [Line Items]

Summarized financial information of equity method investment

The following table summarizes the Company's equity method investments as of December 31, 2017:



Name	Economic Interest	Investment Balance
		(In millions)
Utah Solar Portfolio^(a)	50%	$345
Desert Sunlight	25%	272
GenConn^(b)	50%	102
Agua Caliente Borrower 2	16%	92
Elkhorn Ridge^(c)	66.7%	73
San Juan Mesa^(c)	75%	66
NRG DGPV Holdco 1 LLC ^(d)	95%	76
NRG DGPV Holdco 2 LLC ^(d)	95%	61
NRG DGPV Holdco 3 LLC ^(d)	99%	39
NRG RPV Holdco 1 LLC^(d)	95%	58
Avenal	50%	(6)
Total equity investments in affiliates		$1,178

^(b) GenConn is a variable interest entity.

Entities that are not consolidated [Member]

Schedule of Equity Method Investments [Line Items]

Summarized financial information of equity method investment

The following tables present summarized financial information for the Company's significant equity method investments:



	Year Ended December 31,
	2017			2016				2015
Income Statement Data:	(In millions)
GenConn
Operating revenues	$	71		$	72			$	78
Operating income	36			38				40
Net income	26			26				28
Desert Sunlight
Operating revenues	207			211				206
Operating income	127			129				124
Net income	80			80				73
Utah Solar Portfolio ^(a)
Operating revenues	75			13				—
Operating income (loss)	18			(6		)		(1		)
Net income (loss)	18			(6		)		(1		)
DGPV entities ^(b)
Operating revenues	37			14				1
Operating income	7			2				—
Net loss	(3		)	—				—
RPV Holdco
Operating revenues	16			13				4
Operating income	3			2				(6		)
Net income (loss)	$	3		$	2			$	(6	)
				As of December 31,
				2017				2016
Balance Sheet Data:				(In millions)
GenConn
Current assets				$	38			$	36
Non-current assets				374				389
Current liabilities				18				16
Non-current liabilities				189				196
Desert Sunlight
Current assets				133				281
Non-current assets				1,350				1,401
Current liabilities				64				64
Non-current liabilities				1,003				1,043
Utah Solar Portfolio ^(a)
Current assets				13				20
Non-current assets				1,090				1,105
Current liabilities				5				14
Non-current liabilities				24				38
DGPV entities ^(b)
Current assets				74				44
Non-current assets				671				562
Current liabilities				83				112
Non-current liabilities				216				23
Redeemable Noncontrolling Interest				44				28
RPV Holdco
Current assets				3				15
Non-current assets				183				191
Current liabilities				—				11
Non-current liabilities				7				7
Redeemable Noncontrolling Interest				$	16		—	$	—

^(a) Utah Solar Portfolio was acquired by NRG on November 2, 2016.

^(b) Includes DGPV Holdco 1, DGPV Holdco 2 and DGPV Holdco 3.

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

Estimated carrying values and fair values of the Company's recorded financial instruments

Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

The estimated carrying amounts and fair values of the Company’s recorded financial instruments not carried at fair market value are as follows:



	As of December 31, 2017				As of December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable, including current portion	$	13	$	13	$	30	$	30
Liabilities:
Long-term debt, including current portion	$	5,897	$	5,930	$	6,122	$	6,121

Fair Value, Option, Quantitative Disclosures [Table Text Block]

The following table presents the level within the fair value hierarchy for long-term debt, including current portion as of December 31, 2017 and 2016:



	As of December 31, 2017				As of December 31, 2016
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	1,502	$	4,428	$	1,455	$	4,666

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]



	As of December 31, 2017			As of December 31, 2016
		Fair Value ^(a)		Fair Value ^(a)		Fair Value ^(a)
(In millions)		Level 2		Level 1		Level 2
Derivative assets:
Commodity contracts		$	1	$	1	$	1
Interest rate contracts		1		—		1
Total assets		$	2	1		2
Derivative liabilities:
Commodity contracts		$	1	—		1
Interest rate contracts		47		—		78
Total liabilities		$	48	$	—	$	79

^(a) There were no derivative assets or liabilities classified Level 1 as of December 31, 2017. There were no derivative assets or liabilities classified Level 3 as of December 31, 2017 and 2016.

Tabular disclosure of the application of the fair value option for measurement and reporting of eligible financial assets and liabilities (as defined), as well as certain other eligible items (as defined) included in the statement of financial position, whether such option is elected for a single eligible item or a group of similar eligible items and is in addition to other disclosures concerning fair value which the company may be required to provide. Such disclosure might be expected to include: (1) for items included in the statement of financial position: (a) for each line item in the statement of financial position that includes an item or items for which the fair value option has been elected, provide the aggregate carrying amount of ineligible items included in each line item in the balance sheet, if any; (b) the difference between the aggregate fair value and the aggregate unpaid principal balance (assuming contractual principal amounts and fair value option elected) of: (i) loans and long-term receivables (other than securities otherwise reported at fair value) and (ii) long-term debt instruments; (c) for loans held as assets for which the fair value option has been elected: (i) the aggregate fair value of loans that are 90 days or more past due, (ii) if the policy is to recognize interest income separately from other changes in fair value, the aggregate fair value of loans in nonaccrual status, and (iii) the difference between the aggregate fair value and the aggregate unpaid principal balance for loans that are 90 days or more past due, in nonaccrual status, or both; (2) for items included in the income statement: (a) the amounts of gains and losses from fair value changes included in earnings and in which line in the income statement those gains and losses are reported whether or not combined with gains and losses from items required to be accounted for at fair value; (b) for loans and other receivables held as assets, the estimated amount of gains or losses included in earnings attributable to changes in instrument-specific credit risk; (c) for liabilities with fair values that have been significantly affected during the reporting period by changes in the instrument-specific credit risk, the estimated amount of gains and losses from fair value changes included in earnings that are attributable to changes in the instrument-specific credit risk; and (3) certain other disclosures as required or determined to be provided.

Accounting for Derivative Instruments and Hedging Activities Disclosure [Abstract]

Accounting for Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2017

Net notional volume buy/(sell) of NRG Yield's open derivative transactions broken out by commodity

The following table summarizes the net notional volume buy/(sell) of the Company's open derivative transactions broken out by commodity as of December 31, 2017 and 2016:



		Total Volume
		December 31, 2017		December 31, 2016
Commodity	Units	(In millions)
Natural Gas	MMBtu	2		3
Interest	Dollars	$	1,940	$	2,090

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 ^(a)				Derivative Liabilities
	December 31, 2017		December 31, 2016		December 31, 2017		December 31, 2016
	(In millions)
Derivatives Designated as Cash Flow Hedges:
Interest rate contracts current	$	—	$	—	$	4	$	26
Interest rate contracts long-term	1		1		9		39
Total Derivatives Designated as Cash Flow Hedges	1		1		13		65
Derivatives Not Designated as Cash Flow Hedges:
Interest rate contracts current	—		—		12		6
Interest rate contracts long-term	—		—		22		7
Commodity contracts current	1		2		1		1
Total Derivatives Not Designated as Cash Flow Hedges	1		2		35		14
Total Derivatives	$	2	$	3	$	48	$	79

Offsetting of derivatives by counterparty master agreement level and collateral received or paid

The following tables summarize the offsetting of derivatives by counterparty master agreement level:



	Gross Amounts Not Offset in the Statement of Financial Position
As of December 31, 2017	Gross Amounts of Recognized Assets/Liabilities			Derivative Instruments			Net Amount
Commodity contracts:	(In millions)
Derivative assets	$	1		$	—		$	1
Derivative liabilities	(1		)	—			(1		)
Total commodity contracts	—			—			—
Interest rate contracts:
Derivative assets	1			(1		)	—
Derivative liabilities	(47		)	1			(46		)
Total interest rate contracts	(46		)	—			(46		)
Total derivative instruments	$	(46	)	$	—		$	(46	)

Effects of NRG Yield's accumulated OCI balance attributable to interest rate swaps designated as cash flow hedge derivatives, net of tax

The following table summarizes the effects on the Company’s accumulated OCL balance attributable to interest rate swaps designated as cash flow hedge derivatives, net of tax:



	Year ended December 31,
	2017			2016			2015
	(In millions)
Accumulated OCL beginning balance	$	(70	)	$	(83	)	$	(76	)
Reclassified from accumulated OCL to income due to realization of previously deferred amounts	10			13			14
Mark-to-market of cash flow hedge accounting contracts	—			—			(21		)
Accumulated OCL ending balance, net of income tax benefit of $9, $16 and $16, respectively	$	(60	)	$	(70	)	$	(83	)
Accumulated OCL attributable to noncontrolling interests	(32		)	(42		)	(56		)
Accumulated OCL attributable to NRG Yield, Inc.	$	(28	)	$	(28	)	$	(27	)
Losses expected to be realized from OCL during the next 12 months, net of income tax benefit of $2	$	13

Amounts reclassified from accumulated OCL into income are recorded to interest expense.

Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Summary of the components of the Company's intangible assets subject to amortization

The following tables summarize the components of intangible assets subject to amortization:



Year ended December 31, 2017	PPAs			Leasehold Rights			Customer Relationships			Customer Contracts			Emission Allowances			Development Rights			Other			Total
(In millions)
January 1, 2017	$	1,286		$	86		$	66		$	15		$	9		$	3		$	6		$	1,471
Asset impairments^(a)	(6		)	—			—			—			—			—			—			(6		)
December 31, 2017	1,280			86			66			15			9			3			6			1,465
Less accumulated amortization	(205		)	(13		)	(5		)	(8		)	(3		)	(1		)	(2		)	(237		)
Net carrying amount	$	1,075		$	73		$	61		$	7		$	6		$	2		$	4		$	1,228



Year ended December 31, 2016	PPAs			Leasehold Rights			Customer Relationships			Customer Contracts			Emission Allowances			Development Rights			Other			Total
(In millions)
January 1, 2016	$	1,286		$	86		$	66		$	15		$	15		$	3		$	6		$	1,477
Other	—			—			—			—			(6		)	—			—			(6		)
December 31, 2016	1,286			86			66			15			9			3			6			1,471
Less accumulated amortization	(143		)	(9		)	(4		)	(7		)	(2		)	(1		)	(2		)	(168		)
Net carrying amount	$	1,143		$	77		$	62		$	8		$	7		$	2		$	4		$	1,303

Long-term Debt (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Schedule of Effective Interest Rate [Table Text Block]



(In millions)
Interest expense^(a)	$	21
Debt discount amortization	9
Debt issuance costs amortization	3
	$	33

Schedule of long-term debt

The Company's borrowings, including short term and long term portions consisted of the following:



	December 31, 2017			December 31, 2016			Interest rate % ^(a)		Letters of Credit Outstanding at December 31, 2017
	(In millions, except rates)
2026 Senior Notes	$	350		$	350		5.000
2024 Senior Notes	500			500			5.375
2020 Convertible Notes	288			288			3.250
2019 Convertible Notes	345			345			3.500
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 ^(b)	55			—			L+2.500		$	74
Project-level debt:
Agua Caliente Borrower 2, due 2038	41			—			5.430		17
Alpine, due 2022	135			145			L+1.750		16
Alta Wind I - V lease financing arrangements, due 2034 and 2035	926			965			5.696 - 7.015		119
CVSR, due 2037	746			771			2.339 - 3.775		—
CVSR Holdco Notes, due 2037	194			199			4.680		13
El Segundo Energy Center, due 2023	400			443			L+1.75 - L+2.375		102
Energy Center Minneapolis, due 2025	83			96			5.950	%	—
Energy Center Minneapolis Series D Notes, due 2031	125			125			3.550		—
Laredo Ridge, due 2028	95			100			L+1.875		10
Marsh Landing, due 2023	318			370			L+1.875		22
Tapestry, due 2021	162			172			L+1.625		20
Utah Solar Portfolio, due 2022	278			287			various		13
Viento, due 2023	163			178			L+3.00		27
Walnut Creek, due 2023	267			310			L+1.625		41
Other	443			505			various		38
Subtotal project-level debt	4,376			4,666
Total debt	5,914			6,149
Less current maturities	(306		)	(323		)
Less net debt issuance costs	(60		)	(73		)
Less discounts^(c)	$	(17	)	$	(27	)
Total long-term debt	$	5,531		$	5,726

^(a)

Summary of swaps related to the Company's project level debt

he following table summarizes the swaps, some of which are forward starting as indicated, related to the Company's project level debt as of December 31, 2017:



	% of Principal		Fixed Interest Rate		Floating Interest Rate	Notional Amount at December 31, 2017 (In millions)		Effective Date	Maturity Date
Alpine	85	%	various		3-Month LIBOR	$	115	various	various
Avra Valley	85	%	2.333	%	3-Month LIBOR	46		November 30, 2012	November 30, 2030
AWAM	100	%	2.47	%	3-Month LIBOR	17		May 22, 2013	May 15, 2031
Blythe	75	%	3.563	%	3-Month LIBOR	13		June 25, 2010	June 25, 2028
Borrego	75	%	1.125	%	3-Month LIBOR	5		April 3, 2013	June 30, 2020
El Segundo	75	%	various		3-Month LIBOR	340		various	various
Kansas South	75	%	2.368	%	6-Month LIBOR	21		June 28, 2013	December 31, 2030
Laredo Ridge	75	%	2.31	%	3-Month LIBOR	75		March 31, 2011	March 31, 2026
Marsh Landing	75	%	3.244	%	3-Month LIBOR	295		June 28, 2013	June 30, 2023
Roadrunner	75	%	4.313	%	3-Month LIBOR	26		September 30, 2011	December 31, 2029
South Trent	75	%	3.265	%	3-Month LIBOR	40		June 15, 2010	June 14, 2020
South Trent	75	%	4.95	%	3-Month LIBOR	21		June 30, 2020	June 14, 2028
Tapestry	75	%	2.21	%	3-Month LIBOR	146		December 30, 2011	December 21, 2021
Tapestry	50	%	3.57	%	3-Month LIBOR	60		December 21, 2021	December 21, 2029
Utah Solar Portfolio	80	%	various		1-Month LIBOR	223		various	September 30, 2036
Viento Funding II	90	%	various		6-Month LIBOR	148		various	various
Viento Funding II	90	%	4.985	%	6-Month LIBOR	65		July 11, 2023	June 30, 2028
Walnut Creek Energy	75	%	various		3-Month LIBOR	239		June 28, 2013	May 31, 2023
WCEP Holdings	90	%	4.003	%	3-Month LIBOR	45		June 28, 2013	May 31, 2023
Total						$	1,940

Schedule of annual payments based on the maturities of NRG Yield's debt

nnual payments based on the maturities of the Company's debt, for the years ending after December 31, 2017, are as follows:



	(In millions)
2018	$	306
2019	722
2020	657
2021	455
2022	653
Thereafter	3,121
Total	$	5,914

Earnings (Loss) Per Share Disclosure [Abstract]

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5579240-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41620-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2017

Reconciliation of NRG's basic earnings per share to diluted earnings per share

The reconciliation of the Company's basic and diluted (loss) earnings per share is shown in the following table:



	Year Ended December 31, 2017						Year Ended December 31, 2016				Year Ended December 31, 2015
(In millions, except per share data) ^(a)	Common Class A			Common Class C			Common Class A		Common Class C		Common Class A		Common Class C
Basic and diluted (loss) earnings per share attributable to NRG Yield, Inc. common stockholders
Net (loss) income attributable to NRG Yield, Inc.	$	(6	)	$	(10	)	$	20	$	37	$	14	$	19
Weighted average number of common shares outstanding — basic and diluted	35			64			35		63		35		49
(Loss) Earnings per weighted average common share — basic and diluted	$	(0.16	)	$	(0.16	)	$	0.58	$	0.58	$	0.40	$	0.40

Stockholders' Equity Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2017

Stockholders' Equity Attributable to Parent [Abstract]

Schedule of Distributions Paid [Table Text Block]

The following table lists the distributions paid to NRG during the year ended December 31, 2017:



	Fourth Quarter 2017		Third Quarter 2017		Second Quarter 2017		First Quarter 2017
Distributions per Class B unit	$	0.288	$	0.28	$	0.27	$	0.26
Distributions per Class D unit	$	0.288	$	0.28	$	0.27	$	0.26

Schedule of Dividends Paid [Table Text Block]

The following table lists the dividends paid on the Company's Class A and Class C common stock during the year ended December 31, 2017:



	Fourth Quarter 2017		Third Quarter 2017		Second Quarter 2017		First Quarter 2017
Dividends per Class A share	$	0.288	$	0.28	$	0.27	$	0.26
Dividends per Class C share	$	0.288	$	0.28	$	0.27	$	0.26

Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Segment Reporting [Abstract]

Schedule of Revenue by Major Customers by Reporting Segments [Table Text Block]

The Company generated more than 10% of its revenues from the following customers for the years ended December 31, 2017, 2016 and 2015:



	2017		2016		2015
Customer	Conventional (%)	Renewables (%)	Conventional (%)	Renewables (%)	Conventional (%)	Renewables (%)
SCE	21%	20%	21%	21%	22%	17%
PG&E	12%	11%	12%	11%	12%	12%

Schedule of Segment Reporting Information, by Segment



	Year ended December 31, 2017
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	336		$	501		$	172		$	—		$	1,009
Cost of operations	77			133			116			—			326
Depreciation and amortization	103			210			21			—			334
Impairment losses	—			44			—			—			44
General and administrative	—			—			—			19			19
Acquisition-related transaction and integration costs	—			—			—			3			3
Operating income (loss)	156			114			35			(22		)	283
Equity in earnings of unconsolidated affiliates	12			59			—			—			71
Other income, net	1			2			—			1			4
Loss on debt extinguishment	—			(3		)	—			—			(3		)
Interest expense	(49		)	(163		)	(10		)	(84		)	(306		)
Income (loss) before income taxes	120			9			25			(105		)	49
Income tax expense	—			—			—			72			72
Net Income (Loss)	$	120		$	9		$	25		$	(177	)	$	(23	)
Balance Sheet
Equity investment in affiliates	$	102		$	1,076		$	—		$	—		$	1,178
Capital expenditures ^(a)	15			4			16			—			35
Total Assets	$	1,897		$	5,811		$	422		$	153		$	8,283



	Year ended December 31, 2016
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	333		$	532		$	170		$	—		$	1,035
Cost of operations	66			128			114			—			308
Depreciation and amortization	80			203			20			—			303
Impairment losses	—			185			—			—			185
General and administrative	—			—			—			16			16
Acquisition-related transaction and integration costs	—			—			—			1			1
Operating income (loss)	187			16			36			(17		)	222
Equity in earnings of unconsolidated affiliates	13			47			—			—			60
Other income, net	1			2			—			—			3
Interest expense	(48		)	(151		)	(7		)	(78		)	(284		)
Income (loss) before income taxes	153			(86		)	29			(95		)	1
Income tax benefit	—			—			—			(1		)	(1		)
Net Income (Loss)	$	153		$	(86	)	$	29		$	(94	)	$	2
Balance Sheet
Equity investments in affiliates	$	106		$	1,046		$	—		$	—		$	1,152
Capital expenditures ^(a)	7			2			14			—			23
Total Assets	$	1,993		$	6,114		$	426		$	429		$	8,962



	Year ended December 31, 2015
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	336		$	458		$	174		$	—		$	968
Cost of operations	59			138			126			—			323
Depreciation and amortization	81			203			19			—			303
Impairment losses	—			1			—			—			1
General and administrative	—			—			—			12			12
Acquisition-related transaction and integration costs	—			—			—			3			3
Operating income (loss)	196			116			29			(15		)	326
Equity in earnings of unconsolidated affiliates	14			17			—			—			31
Other income, net	1			2			—			—			3
Loss on debt extinguishment	(7		)	(2		)	—			—			(9		)
Interest expense	(48		)	(151		)	(7		)	(61		)	(267		)
Income (loss) before income taxes	156			(18		)	22			(76		)	84
Income tax expense	—			—			—			12			12
Net Income (Loss)	$	156		$	(18	)	$	22		$	(88	)	$	72

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income tax provision from continuing operations

The income tax provision consisted of the following amounts:



	Year Ended December 31,
	2017			2016			2015
	(In millions, except percentages)
Current
U.S. Federal	$	—		$	—		$	—
State	—			—			—
Total — current	—			—			—
Deferred
U.S. Federal	75			(1		)	10
State	(3		)	—			2
Total — deferred	72			(1		)	12
Total income tax expense (benefit)	$	72		$	(1	)	$	12

Reconciliation of the U.S. federal statutory rate to the Company's effective rate

A reconciliation of the U.S. federal statutory rate of 35% to the Company's effective rate is as follows:



	Year Ended December 31,
	2017			2016			2015
	(In millions, except percentages)
Income Before Income Taxes	$	49		$	1		$	84
Tax at 35%	17			—			29
State taxes, net of federal benefit	(3		)	—			2
Tax Cuts and Jobs Act - tax rate change	68			—			—
Investment tax credits	(1		)	(1		)	(1		)
Impact of non-taxable partnership earnings	(9		)	(1		)	(17		)
Production tax credits, including prior year true-up	(1		)	4			(4		)
Other	1			(3		)	3
Income tax expense (benefit)	$	72		$	(1	)	$	12
Effective income tax rate	147		%	(100		)%	14		%

Company's deferred tax assets and liabilities

The temporary differences, which gave rise to the Company's deferred tax assets, consisted of the following:



	As of December 31,
	2017			2016
	(In millions)
Deferred tax liabilities:
Investment in projects	$	70		$	19
Total deferred tax liabilities	70			19
Deferred tax assets:
Production tax credits carryforwards	7			5
Investment tax credits	1			1
U.S. Federal net operating loss carryforwards	183			226
Capital loss carryforwards	10			16
State net operating loss carryforwards	7			3
Total deferred tax assets	208			251
Valuation allowance	$	(10	)	$	(16	)
Total deferred tax assets, net of valuation allowance	$	198		$	235
Net deferred noncurrent tax asset	$	128		$	216

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Long-term Purchase Commitment [Table Text Block]

As of December 31, 2017, the Company's commitments under such outstanding agreements are estimated as follows:



Period	(In millions)
2018	$	11
2019	5
2020	3
2021	3
2022	3
Thereafter	16
Total	$	41

Future minimum lease commitments under operating leases

The Company's future minimum lease commitments under operating leases are $9 million for each of the years ending December 31, 2018 through 2022, and $151 million thereafter.



Period	(In millions)

Unaudited Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Summary of Unaudited Quarterly Financial Data

ummarized unaudited quarterly financial data, which includes the results of the November 2017 Drop Down Assets Acquisition and its impact on every quarter of the 2017 and 2016 results, which were recast to include the November 2017 Drop Down Assets, where applicable:



	Quarter Ended
	December 31,			September 30,			June 30,		March 31,
	2017
	(In millions, except per share data)
Operating Revenues	$	231		$	269		$	288	$	221

Operating Revenues (as previously reported)	N/A			265			284		218
Change	N/A			4			4		3

Operating Income	19			85			124		55

Operating Income (as previously reported)	N/A			95			122		54
Change	N/A			(10		)	2		1

Net (Loss) Income	(98		)	30			47		(2		)

Net Income (Loss) (as previously reported)	N/A			41			45		(1		)
Change	N/A			(11		)	2		(1		)

Net (Loss) Income Attributable to NRG Yield, Inc.	$	(70	)	$	29		$	28	$	(3	)
Weighted average number of Class A common shares outstanding — basic	35			35			35		35
Weighted average number of Class A common shares outstanding — diluted	35			49			49		35
Weighted average number of Class C common shares outstanding — basic	65			64			63		63
Weighted average number of Class C common shares outstanding — diluted	65			75			74		63
(Loss) Earnings per Weighted Average Class A and Class C Common Share - Basic	(0.71		)	0.30			0.29		(0.03		)
(Loss) Earnings per Weighted Average Class A Common Share - Diluted	(0.71		)	0.27			0.26		(0.03		)
(Loss) Earnings per Weighted Average Class C Common Share - Diluted	$	(0.71	)	$	0.29		$	0.28	$	(0.03	)



	Quarter Ended
	December 31,			September 30,		June 30,		March 31,
	2016
	(In millions, except per share data)
Operating Revenues	$	235		$	276	$	287	$	237

Operating Revenues (as previously reported)	232			272		283		234
Change	3			4		4		3

Operating (Loss) Income	(100		)	119		130		73

Operating (Loss) Income (as previously reported)	(99		)	117		128		72
Change	(1		)	2		2		1

Net (Loss) Income	(115		)	51		65		1

Net (Loss) Income (as previously reported)	(114		)	50		64		2
(Change)	(1		)	1		1		(1		)

Net (Loss) Income Attributable to NRG Yield, Inc.	$	(13	)	$	33	$	32	$	5
Weighted average number of Class A common shares outstanding — basic	35			35		35		35
Weighted average number of Class A common shares outstanding — diluted	35			49		49		35
Weighted average number of Class C common shares outstanding — basic	63			63		63		63
Weighted average number of Class C common shares outstanding — diluted	63			73		73		63
(Loss) Earnings per Weighted Average Class A and Class C Common Share - Basic	(0.14		)	0.34		0.33		0.05
(Loss) Earnings per Weighted Average Class A Common Share - Diluted	(0.14		)	0.30		0.29		0.05
(Loss) Earnings per Weighted Average Class C Common Share - Diluted	$	(0.14	)	$	0.32	$	0.31	$	0.05

Nature of Business (Details)

12 Months Ended

Dec. 31, 2017

Megawatts Thermal Equivalent, Available Under right-to-use Provisions

5,241

^[1],[2]

134

Power Generation Capacity, Megawatts, including portion attributable to noncontrolling interest

5,247

^[1],[2]

Conventional Generation [Member]

1,945

^[1]

Utility-Scale Solar

921

^[1]

Distributed Solar

^[1]

2,200

^[1]

Thermal [Member]

100.00%

Steam and Chilled Water Capacity, Megawatts Thermal Equivalent

123

^[1]

1,319

^[2]

NRG Energy Center Dover [Member]

100.00%

NRG Yield, Inc. [Member]

Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Voting Interest

44.90%

Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest

53.70%

Thermal [Member] | Thermal [Member]

NRG Yield LLC | NRG Yield, Inc. [Member]

^[1]

Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Voting Interest

44.90%

Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest

53.70%

NRG Yield LLC | NRG

Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Voting Interest

55.10%

Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest

46.30%

GenConn Middletown [Member] | Conventional Generation [Member]

50.00%

GenConn Devon [Member] | Conventional Generation [Member]

^[1]

50.00%

Marsh Landing | Conventional Generation [Member]

^[1]

100.00%

El Segundo [Member] | Conventional Generation [Member]

720

^[1]

100.00%

Walnut Creek [Member] | Conventional Generation [Member]

550

^[1]

100.00%

Agua Caliente [Member] | Utility-Scale Solar

485

16.00%

Alpine [Member] | Utility-Scale Solar

^[1]

100.00%

Avenal [Member] | Utility-Scale Solar

^[1]

50.00%

Avra Valley [Member] | Utility-Scale Solar

^[1]

100.00%

NRG Solar Blythe LLC [Member] | Utility-Scale Solar

^[1]

100.00%

Borrego [Member] | Utility-Scale Solar

^[1]

100.00%

NRG Solar Roadrunner LLC [Member] | Utility-Scale Solar

^[1]

100.00%

CVSR [Member] | Utility-Scale Solar

^[1]

100.00%

RE Kansas South [Member] | Utility-Scale Solar

250

^[1]

100.00%

TA - High Desert LLC [Member] | Utility-Scale Solar

^[1]

100.00%

Utah Portfolio [Member] | Utility-Scale Solar

^[1]

50.00%

Desert Sunlight [Member] | Utility-Scale Solar

265

^[1],[3],[4]

AZ DG Solar Projects | Distributed Solar

25.00%

100.00%

PFMG DG Solar Projects | Distributed Solar

^[1]

100.00%

SPP Projects [Member] | Distributed Solar

^[1]

100.00%

Other DG Assets [Member] | Distributed Solar

^[1]

100.00%

Alta I [Member] | Wind Farms [Member]

^[1]

100.00%

Alta II [Member] | Wind Farms [Member]

150

^[1]

100.00%

Alta III [Member] | Wind Farms [Member]

150

^[1]

100.00%

Alta IV [Member] | Wind Farms [Member]

150

^[1]

100.00%

Alta V [Member] | Wind Farms [Member]

102

^[1]

100.00%

Alta X [Member] | Wind Farms [Member]

168

^[1]

100.00%

^[5]

Alta XI [Member] | Wind Farms [Member]

137

^[1],[5]

100.00%

^[5]

South Trent | Wind Farms [Member]

^[1],[5]

100.00%

Spanish Fork [Member] | Wind Farms [Member]

101

^[1]

100.00%

Laredo Ridge [Member] | Wind Farms [Member]

^[1],[3],[6]

100.00%

Lookout [Member] | Wind Farms [Member]

^[1]

100.00%

Odin Wind Farm [Member] | Wind Farms [Member]

^[1],[3],[6]

99.90%

Taloga [Member] | Wind Farms [Member]

^[1],[3],[6]

100.00%

Pinnacle [Member] | Wind Farms [Member]

130

100.00%

San Juan Mesa Wind Project, LLC [Member] | Wind Farms [Member]

^[1]

75.00%

Sleeping Bear [Member] | Wind Farms [Member]

^[1],[3],[6]

100.00%

Buffalo Bear [Member] | Wind Farms [Member]

^[1],[3],[6]

100.00%

Crosswinds [Member] | Wind Farms [Member]

^[1]

99.00%

Elbow Creek [Member] | Wind Farms [Member]

^[1],[3]

100.00%

Forward [Member] | Wind Farms [Member]

122

^[1],[3],[6]

100.00%

Goat Wind [Member] | Wind Farms [Member]

^[1],[3],[6]

100.00%

Elkhorn Ridge Wind, LLC [Member] | Wind Farms [Member]

150

^[1],[3],[6]

66.70%

Hardin [Member] | Wind Farms [Member]

^[1],[3],[6]

99.00%

Spring Canyon [Member] | Wind Farms [Member]

^[1],[3],[6]

Power Generation Capacity, Megawatts attributed to noncontrolling interest

Spring Canyon II [Member] | Wind Farms [Member]

90.10%

Spring Canyon III [Member] | Wind Farms [Member]

^[1],[3]

90.10%

Wildorado [Member] | Wind Farms [Member]

^[1],[3]

100.00%

NRG Energy Center Dover [Member] | Thermal [Member]

161

^[1],[3],[6]

Southern California Edison [Member] | Desert Sunlight [Member] | Utility-Scale Solar

103

^[1]

Pacific Gas and Electric [Member] | Desert Sunlight [Member] | Utility-Scale Solar

^[1]

Unconsolidated Solar Partnerships [Member]

^[1]

247

[1]	(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of December 31, 2017.
[2]	For thermal energy, net capacity represents MWt for steam or chilled water and excludes 134 MWt available under the right-to-use provisions contained in agreements between two of the Company's thermal facilities and certain of its customers.
[3]	(b) Projects are part of tax equity arrangements.
[4]	Represents interests in Four Brothers Solar, LLC, Granite Mountain Holdings, LLC, and Iron Springs Holdings, LLC, all acquired as part of the March 2017 Drop Down Assets acquisition (ownership percentage is based upon cash to be distributed).
[5]	c) The Company's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. The Company's generation capacity including this noncontrolling interest was 5,247.
[6]	Projects are part of NRG Wind TE Holdco portfolio

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary of Significant Accounting Policies [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification		$ 33
Cash and cash equivalents	$ 148	322	$ 111
Restricted cash	168	176	143
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	316	498	254	$ 573
Asset Retirement Obligation, Accretion Expense	$ 4
Income Taxes, Threshold Percentage	50.00%
Contingent Rental Income Associated with PPAs	$ 559	583	$ 443
Asset Retirement Obligation	55	49
Deferred Tax Assets, Net	128	216
Asset Retirement Obligation, Revision of Estimate	2
Project Level Subsidiaries [Member]
Summary of Significant Accounting Policies [Line Items]
Other Cash Equivalents, at Carrying Value	124	111
Long-Term Debt, Current [Member]
Summary of Significant Accounting Policies [Line Items]
Restricted Cash and Cash Equivalents	25
Operating Expense [Member]
Summary of Significant Accounting Policies [Line Items]
Restricted Cash and Cash Equivalents	25
Cash Distribution [Member]
Summary of Significant Accounting Policies [Line Items]
Restricted Cash and Cash Equivalents	36
Reserves [Member]
Summary of Significant Accounting Policies [Line Items]
Restricted Cash and Cash Equivalents	82
NRG [Member] \| Elbow Creek [Member]
Summary of Significant Accounting Policies [Line Items]
Revenue from Related Parties	$ 8	$ 8

Business Acquisitions Business Acquisitions - November 2017 Drop Down Assets (Details)
$ in Millions

2 Months Ended

3 Months Ended

12 Months Ended

Nov. 02, 2017

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2017

USD ($)

Sep. 30, 2017

USD ($)

Jun. 30, 2017

USD ($)

Mar. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Sep. 30, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 31, 2016

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Nov. 01, 2017

USD ($)

Dec. 31, 2014

USD ($)

$ 482

$ 670

$ 482

$ 670

231

$ 269

$ 288

$ 221

235

$ 276

$ 287

$ 237

1,009

1,035

$ 968

$ 19

124

(100)

119

130

$ 283

222

326

^[1],[2]

5,241

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

$ 60

(98)

(2)

(115)

(23)

5,204

5,554

5,204

5,554

2,597

2,738

2,597

2,738

Debt, Long-term and Short-term, Combined Amount

8,283

8,962

8,283

8,962

6,049

Other Liabilities

314

Total Stockholders' Equity

6,145

6,363

6,145

6,363

2,138

2,599

2,138

2,599

2,903

$ 2,906

November 2017 Drop Down Assets [Member]

Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets

$ 7

Business Combination, Consideration Transferred

$ 74

Business Acquisition, Consideration Transferred, Working Capital

$ 3

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment

$ 3

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets

102

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net

$ 76

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

Debt, Long-term and Short-term, Combined Amount

126

Other Liabilities

Total Stockholders' Equity

Scenario, Previously Reported [Member]

656

265

284

218

232

272

283

234

1,021

953

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

122

(99)

117

128

218

320

$ 41

$ 45

$ (1)

(114)

$ 50

$ 64

$ 2

$ 70

5,460

2,720

Debt, Long-term and Short-term, Combined Amount

8,836

5,987

Other Liabilities

310

Total Stockholders' Equity

6,297

$ 2,539

$ 2,844

[1]	(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of December 31, 2017.
[2]	For thermal energy, net capacity represents MWt for steam or chilled water and excludes 134 MWt available under the right-to-use provisions contained in agreements between two of the Company's thermal facilities and certain of its customers.

Business Acquisitions Business Acquisitions - August 2017 Drop Down Assets (Details) - USD ($) $ in Millions	Aug. 02, 2017	Dec. 31, 2017	Aug. 01, 2017
August 2017 Drop Down Assets [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 44
Business Acquisition, Consideration Transferred, Working Capital			$ 3
Business Combination, Contingent Consideration, Liability		$ 8
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net			$ 87
August 2017 Drop Down Assets [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			25.00%

Business Acquisitions Business Acquisitions - March 2017 Drop Down Assets (Details)
$ in Millions

Mar. 27, 2017

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

^[1],[2]

5,241

$ 60

$ 73

March 2017 Drop Down Assets [Member]

$ 1,178

$ 1,152

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents

$ 6

Business Combination, Consideration Transferred

132

Business Acquisition, Consideration Transferred, Working Capital

Business Combination, Separately Recognized Transactions, Net Gains and Losses

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets

456

462

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities

320

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities

323

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net

$ 139

Utah Portfolio [Member]

Remaining Power Purchase Agreement term

20 years

Business Acquisition, Consideration Transferred, Working Capital

50.00%

$ 106

Non-Recourse Debt

$ 287

Agua Caliente Borrower 2 [Member]

Percentage of NRG's Ownership

16.00%

31.00%

Power Purchase Agreement Period

25 years

Remaining Power Purchase Agreement term

22 years

Non-Recourse Debt

$ 41

NRG [Member] | Utah Portfolio [Member]

$ 92

50.00%

NRG [Member] | Agua Caliente Borrower 2 [Member]

$ 345

51.00%

[1]	(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of December 31, 2017.
[2]	For thermal energy, net capacity represents MWt for steam or chilled water and excludes 134 MWt available under the right-to-use provisions contained in agreements between two of the Company's thermal facilities and certain of its customers.

Business Acquisitions Business Acquisitions - CVSR (Details) - USD ($) $ in Millions	Sep. 02, 2016	Dec. 31, 2017	Dec. 31, 2016	Sep. 01, 2016	Aug. 31, 2016
Business Acquisition [Line Items]
Long-term Debt		$ 5,914.0	$ 6,149.0
CVSR [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage					48.95%
Business Acquisition, Percentage of Voting Interests Acquired				51.05%
Payments to Acquire Businesses, Gross	$ 78.5
Business Combination, Separately Recognized Transactions, Net Gains and Losses	112.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt				$ 496.0
Business Combination, Consideration Transferred	$ 6.0
CVSR Financing Agreement [Member]
Business Acquisition [Line Items]
Long-term Debt		746.0	771.0
CVSR Financing Agreement [Member] \| CVSR [Member]
Business Acquisition [Line Items]
Long-term Debt				771.0
CVSR Holdco due 2037 [Member]
Business Acquisition [Line Items]
Long-term Debt		$ 194.0	$ 199.0
CVSR Holdco due 2037 [Member] \| CVSR [Member]
Business Acquisition [Line Items]
Long-term Debt				$ 200.0

Business Acquisitions Business Acquisitions - November 2015 Drop Down Assets (Details)

Feb. 19, 2016

USD ($)

Dec. 31, 2017

Nov. 03, 2015

USD ($)

Nov. 02, 2015

USD ($)

November 2015 Drop Down Assets [Member]

^[1],[2]

5,241

Payments to Acquire Businesses, Gross

Number of Facilities

$ 207,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt

$ 193,000,000

Wind Farms [Member] | November 2015 Drop Down Assets [Member]

^[1]

2,200

Financial Institutions [Member] | November 2015 Drop Down Assets [Member]

814

Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value

$ 159,000,000

Pre-Flip Point [Member] | November 2015 Drop Down Assets [Member]

Post-Flip Point [Member] | November 2015 Drop Down Assets [Member]

100.00%

Pre-determined Date Through Flip Point If Flip Has Not Occured [Member] | Financial Institutions [Member] | November 2015 Drop Down Assets [Member]

91.47%

100.00%

[1]	(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of December 31, 2017.
[2]	For thermal energy, net capacity represents MWt for steam or chilled water and excludes 134 MWt available under the right-to-use provisions contained in agreements between two of the Company's thermal facilities and certain of its customers.

Business Acquisitions Business Acquisitions - Desert Sunlight/Spring Canyon/Fuel Cell (Details)

Jun. 30, 2015

May 08, 2015

Apr. 30, 2015

Dec. 31, 2017

Jun. 29, 2015

project

May 07, 2015

Utility-Scale Solar [Member]

^[1],[2]

5,241

^[1]

921

Wind Farms [Member] | Spring Canyon [Member]

^[1]

2,200

Business Acquisition, Percentage of Voting Interests Acquired

90.10%

Wind Farms [Member] | Spring Canyon II [Member]

Wind Farms [Member] | Spring Canyon III [Member]

Thermal [Member]

^[1]

123

Number of Facilities | project

Desert Sunlight [Member] | Utility-Scale Solar [Member]

550

Supply Commitment [Member] | Spring Canyon [Member]

25.00%

Weighted average remaining amortization period (in years)

24 years

Supply Commitment [Member] | UB Fuel Cell [Member]

Weighted average remaining amortization period (in years)

12 years

Supply Commitment [Member] | Southern California Edison [Member] | Desert Sunlight [Member]

Weighted average remaining amortization period (in years)

20 years

Supply Commitment [Member] | Pacific Gas and Electric [Member] | Desert Sunlight [Member]

Weighted average remaining amortization period (in years)

25 years

UB Fuel Cell [Member] | Thermal [Member]

1.4

[1]	(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of December 31, 2017.
[2]	For thermal energy, net capacity represents MWt for steam or chilled water and excludes 134 MWt available under the right-to-use provisions contained in agreements between two of the Company's thermal facilities and certain of its customers.

Business Acquisitions Business Acquisitions - January 2015 Drop Down Assets (Details)
$ in Millions

Jan. 02, 2015

USD ($)

Dec. 31, 2017

Nov. 02, 2015

January 2015 Drop Down Assets [Member]

^[1],[2]

5,241

Business Combination, Consideration Transferred | $

$ 489

Business Acquisition, Consideration Transferred, Working Capital | $

Business Combination, Consideration Transferred, Liabilities Incurred | $

737

Business Combination, Separately Recognized Transactions, Net Gains and Losses | $

AOCI Including Portion Attributable to Noncontrolling Interest, before Tax | $

$ 23

Wind Farms [Member] | November 2015 Drop Down Assets [Member]

^[1]

2,200

Wind Farms [Member] | Laredo Ridge [Member]

814

Wind Farms [Member] | Buffalo Bear [Member]

^[1]

Wind Farms [Member] | Taloga [Member]

^[1]

Wind Farms [Member] | Pinnacle [Member]

130

Conventional Generation [Member]

^[1]

Conventional Generation [Member] | Walnut Creek [Member]

^[1]

1,945

Schedule of Equity Method Investments [Line Items]

485

[1]	(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of December 31, 2017.
[2]	For thermal energy, net capacity represents MWt for steam or chilled water and excludes 134 MWt available under the right-to-use provisions contained in agreements between two of the Company's thermal facilities and certain of its customers.

Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment
Property, plant and equipment, gross	$ 6,489	$ 6,530
Under construction	34	24
Less accumulated depreciation	(1,285)	(976)
Property, Plant and Equipment, Net	5,204	5,554
Prepaid Long Term Service Agreement	24	20
Support Equipment and Facilities [Member]
Property, Plant and Equipment
Property, plant and equipment, gross	6,289	6,339
Land and improvements
Property, Plant and Equipment
Property, plant and equipment, gross	$ 166	$ 167
Minimum [Member] \| Support Equipment and Facilities [Member]
Property, Plant and Equipment
Property, plant and equipment, useful life	2 years
Maximum [Member] \| Support Equipment and Facilities [Member]
Property, Plant and Equipment
Property, plant and equipment, useful life	45 years

Investments Accounted for by the Equity Method and Variable Interest Entities Investments Accounted for by the Equity Method and Variable Interest Entities - Summary Table (Details) - USD ($)
$ in Millions

12 Months Ended

Jun. 29, 2015

Dec. 31, 2017

Mar. 27, 2017

Dec. 31, 2016

Retained Earnings, Undistributed Earnings from Equity Method Investees

$ 1,178

$ 1,152

$ 57

Utah Portfolio [Member]

Schedule of Equity Method Investments [Line Items]

Business Acquisition, Consideration Transferred, Working Capital

50.00%

$ 106

Schedule of Equity Method Investments [Line Items]

Payments to Acquire Equity Method Investments

$ 272

$ 285

Business Acquisition, Consideration Transferred, Working Capital

$ 171

GCE Holding LLC [Member]

Schedule of Equity Method Investments [Line Items]

^[1]

50.00%

Retained Earnings, Undistributed Earnings from Equity Method Investees

^[1]

$ 102

$ 51

Elkhorn Ridge Wind, LLC [Member]

Schedule of Equity Method Investments [Line Items]

66.70%

^[2]

66.70%

San Juan Mesa Wind Project, LLC [Member]

^[2]

$ 73

Schedule of Equity Method Investments [Line Items]

75.00%

^[2]

75.00%

NRG DGPV Holdco 1 [Member]

^[2]

$ 66

Schedule of Equity Method Investments [Line Items]

^[3]

95.00%

NRG DGPV Holdco 2 [Member]

^[3]

$ 76

Schedule of Equity Method Investments [Line Items]

Payments to Acquire Interest in Subsidiaries and Affiliates

^[3]

95.00%

^[3]

$ 61

NRG DGPV Holdco 3 [Member]

Schedule of Equity Method Investments [Line Items]

Payments to Acquire Interest in Subsidiaries and Affiliates

^[3]

99.00%

$ 39

NRG RPV Holdco [Member]

Schedule of Equity Method Investments [Line Items]

95.00%

Schedule of Equity Method Investments [Line Items]

^[3]

$ 58

Avenal [Member]

50.00%

Utility-Scale Solar [Member] | Desert Sunlight [Member]

$ (6)

Schedule of Equity Method Investments [Line Items]

NRG [Member] | Utah Portfolio [Member]

25.00%

Schedule of Equity Method Investments [Line Items]

50.00%

Schedule of Equity Method Investments [Line Items]

$ 345

[1]	GenConn is a variable interest entity.
[2]	San Juan Mesa and Elkhorn Ridge are part of the Wind TE Holdco tax equity structure, as described below. San Juan Mesa and Elkhorn Ridge are owned 75% and 66.7%, respectively, by Wind TE Holdco. The Company owns 100% of the Class B interests in Wind TE Holdco.
[3]	NRG DGPV Holdco 1 LLC, NRG DGPV Holdco 2 LLC, NRG DGPV Holdco 3 LLC and NRG RPV Holdco 1 LLC are tax equity structures and VIEs. The related allocations are described below.

Investments Accounted for by the Equity Method and Variable Interest Entities Investments Accounted for by the Equity Method and Variable Interest Entities - Debt held by not consolidated entities (Details)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 27, 2017

Dec. 31, 2017

USD ($)

Sep. 30, 2017

USD ($)

Jun. 30, 2017

USD ($)

Mar. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Sep. 30, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 31, 2016

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Jul. 15, 2016

Pro-Rate Share of Debt Held by Unconsolidated Affiliates

$ 777

^[1],[2]

5,241

$ 5,914

$ 6,149

$ 5,914

$ 6,149

1,178

1,152

1,178

1,152

231

$ 269

$ 288

$ 221

235

$ 276

$ 287

$ 237

1,009

1,035

$ 968

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

124

(100)

119

130

283

222

326

(98)

$ 30

$ 47

$ (2)

(115)

$ 51

$ 65

$ 1

(23)

482

670

482

670

486

505

486

505

Agua Caliente Borrower 2 [Member]

$ 5,659

5,858

$ 5,659

5,858

Schedule of Equity Method Investments [Line Items]

16.00%

Power Purchase Agreement Period

25 years

Schedule of Equity Method Investments [Line Items]

$ 92

Avenal [Member]

50.00%

Schedule of Equity Method Investments [Line Items]

$ (6)

GCE Holding LLC [Member]

^[3]

50.00%

^[3]

$ 102

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

374

389

374

389

$ 189

196

$ 189

196

Schedule of Equity Method Investments [Line Items]

550

$ 272

207

211

206

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

127

129

124

$ 73

133

281

133

281

1,350

1,401

1,350

1,401

NRG DGPV Holdco 3 [Member]

$ 1,003

1,043

$ 1,003

1,043

Schedule of Equity Method Investments [Line Items]

Desert Sunlight [Member] | Desert Sunlight [Member]

Schedule of Equity Method Investments [Line Items]

CVSR Financing Agreement [Member]

1,100

Schedule of Equity Method Investments [Line Items]

4.68%

Schedule of Equity Method Investments [Line Items]

$ 746

$ 771

$ 746

$ 771

[1]	(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of December 31, 2017.
[2]	For thermal energy, net capacity represents MWt for steam or chilled water and excludes 134 MWt available under the right-to-use provisions contained in agreements between two of the Company's thermal facilities and certain of its customers.
[3]	GenConn is a variable interest entity.

Investments Accounted for by the Equity Method and Variable Interest Entities Investments Accounted for by the Equity Method and Variable Interest Entities - VIEs that are consolidated (Details)

12 Months Ended

Dec. 31, 2017

USD ($)

Aug. 01, 2017

Dec. 31, 2016

USD ($)

Nov. 03, 2015

Nov. 02, 2015

USD ($)

May 07, 2015

$ 2,597,000,000

$ 2,738,000,000

Proceeds from Noncontrolling Interests

^[1],[2]

5,241

$ 11,000,000

5,204,000,000

5,554,000,000

8,283,000,000

8,962,000,000

August 2017 Drop Down Assets [Member]

$ 6,145,000,000

$ 6,363,000,000

Schedule of Equity Method Investments [Line Items]

Business Acquisition, Percentage of Voting Interests Acquired

25.00%

November 2015 Drop Down Assets [Member]

Schedule of Equity Method Investments [Line Items]

Number of Facilities

Schedule of Equity Method Investments [Line Items]

Wind Farms [Member] | November 2015 Drop Down Assets [Member]

^[1]

2,200

Schedule of Equity Method Investments [Line Items]

Wind Farms [Member] | Spring Canyon [Member]

814

Schedule of Equity Method Investments [Line Items]

Business Acquisition, Percentage of Voting Interests Acquired

90.10%

Wind Farms [Member] | Spring Canyon II [Member]

Schedule of Equity Method Investments [Line Items]

Wind Farms [Member] | Spring Canyon III [Member]

Schedule of Equity Method Investments [Line Items]

Financial Institutions [Member] | November 2015 Drop Down Assets [Member]

Schedule of Equity Method Investments [Line Items]

Taxable Income Allocation, Pre-Flip

99.00%

Taxable Income Allocation, Post-Flip

8.53%

Pre-Flip Point [Member] | November 2015 Drop Down Assets [Member]

Schedule of Equity Method Investments [Line Items]

Post-Flip Point [Member] | November 2015 Drop Down Assets [Member]

100.00%

Schedule of Equity Method Investments [Line Items]

Pre-determined Date Through Flip Point If Flip Has Not Occured [Member] | Financial Institutions [Member] | November 2015 Drop Down Assets [Member]

91.47%

Schedule of Equity Method Investments [Line Items]

November 2015 Drop Down Assets [Member]

100.00%

Schedule of Equity Method Investments [Line Items]

$ 172,000,000

Intangible Assets, Net (Excluding Goodwill)

376,000,000

2,000,000

550,000,000

Noncontrolling Interest in Variable Interest Entity

197,000,000

9,000,000

Net Assets

344,000,000

Alta X and XI TE Holdco [Member]

Schedule of Equity Method Investments [Line Items]

17,000,000

Intangible Assets, Net (Excluding Goodwill)

436,000,000

262,000,000

715,000,000

Noncontrolling Interest in Variable Interest Entity

9,000,000

93,000,000

Net Assets

$ 613,000,000

Alta X and XI TE Holdco [Member] | Financial Institutions [Member]

Schedule of Equity Method Investments [Line Items]

Taxable Income Allocation, Pre-Flip

99.00%

Taxable Income Allocation, Post-Flip

5.00%

Alta X and XI TE Holdco [Member] | Post-Flip Point [Member]

Schedule of Equity Method Investments [Line Items]

Alta X and XI TE Holdco [Member] | Pre-determined Date Through Flip Point If Flip Has Not Occured [Member] | Financial Institutions [Member]

97.12%

Schedule of Equity Method Investments [Line Items]

Alta X and XI TE Holdco [Member] | Second Year through Flip Point [Member]

100.00%

Schedule of Equity Method Investments [Line Items]

Schedule of Equity Method Investments [Line Items]

94.34%

Spring Canyon [Member]

$ 2,000,000

Intangible Assets, Net (Excluding Goodwill)

95,000,000

97,000,000

Noncontrolling Interest in Variable Interest Entity

5,000,000

60,000,000

Net Assets

$ 32,000,000

Spring Canyon [Member] | Pre-Flip Point [Member]

Schedule of Equity Method Investments [Line Items]

Spring Canyon [Member] | Pre-Flip Point [Member] | Financial Institutions [Member]

65.19%

Schedule of Equity Method Investments [Line Items]

Spring Canyon [Member] | Post-Flip Point [Member]

34.81%

Schedule of Equity Method Investments [Line Items]

Spring Canyon [Member] | Post-Flip Point [Member] | Financial Institutions [Member]

95.00%

Schedule of Equity Method Investments [Line Items]

Schedule of Equity Method Investments [Line Items]

5.00%

[1]	(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of December 31, 2017.
[2]	For thermal energy, net capacity represents MWt for steam or chilled water and excludes 134 MWt available under the right-to-use provisions contained in agreements between two of the Company's thermal facilities and certain of its customers.

Investments Accounted for by the Equity Method and Variable Interest Entities Investments Accounted for by the Equity Method and Variable Interest Entities - VIEs that are not consolidated (Details)
$ in Millions

3 Months Ended

12 Months Ended

May 08, 2015

Dec. 31, 2017

USD ($)

generatingunit

Sep. 30, 2017

USD ($)

Jun. 30, 2017

USD ($)

Mar. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Sep. 30, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 31, 2016

USD ($)

Dec. 31, 2017

USD ($)

generatingunit

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Oct. 12, 2017

USD ($)

Mar. 27, 2017

USD ($)

Jun. 29, 2015

USD ($)

$ 482

$ 670

$ 482

$ 670

231

$ 269

$ 288

$ 221

235

$ 276

$ 287

$ 237

1,009

1,035

$ 968

$ 1,178

1,152

$ 1,178

1,152

^[1],[2]

5,241

$ 486

505

$ 486

505

5,659

5,858

5,659

5,858

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

124

(100)

119

130

283

222

326

$ (98)

$ 30

$ 47

$ (2)

(115)

$ 51

$ 65

$ 1

$ (23)

NRG DGPV Holdco 1 [Member]

Schedule of Equity Method Investments [Line Items]

^[3]

95.00%

Schedule of Equity Method Investments [Line Items]

^[3]

$ 76

GCE Holding LLC [Member]

^[4]

102

374

389

374

389

$ 189

196

189

196

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

$ 26

NRG DGPV Holdco 2 [Member]

Schedule of Equity Method Investments [Line Items]

Payments to Acquire Interest in Subsidiaries and Affiliates

^[3]

95.00%

^[3]

$ 61

NRG DGPV Holdco 3 [Member]

21 years

Schedule of Equity Method Investments [Line Items]

Payments to Acquire Interest in Subsidiaries and Affiliates

^[3]

99.00%

$ 39

Schedule of Equity Method Investments [Line Items]

20 years

NRG DGPV Holdco [Member]

^[5]

$ 74

^[5]

^[3]

176

^[5]

671

562

671

562

^[5]

112

^[5]

216

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

^[5]

^[5]

(3)

Redeemable Noncontrolling Interest, Equity, Carrying Amount

^[5]

$ 44

NRG RPV Holdco [Member]

Schedule of Equity Method Investments [Line Items]

95.00%

$ 3

^[3]

183

191

183

191

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

(6)

(6)

Redeemable Noncontrolling Interest, Equity, Carrying Amount

Schedule of Equity Method Investments [Line Items]

Business Acquisition, Consideration Transferred, Working Capital

$ 171

133

281

133

281

207

211

206

$ 272

550

$ 1,350

1,401

$ 1,350

1,401

1,003

1,043

1,003

1,043

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

127

129

124

Utah Portfolio [Member]

Schedule of Equity Method Investments [Line Items]

Business Acquisition, Consideration Transferred, Working Capital

$ 106

^[6]

^[6]

^[6]

1,090

1,105

1,090

1,105

^[6]

^[6]

$ 24

$ 38

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

^[6]

(6)

(1)

^[6]

$ 18

$ (6)

$ (1)

Tax Equity Financed Portfolio of Leases - Commercial PV 1 [Member] | NRG DGPV Holdco 1 [Member]

50.00%

Schedule of Equity Method Investments [Line Items]

Tax Equity Financed Portfolio of Leases - Commercial PV 1 [Member] | NRG DGPV Holdco 2 [Member]

18 years

Schedule of Equity Method Investments [Line Items]

Existing Portfolio of Leases [Member] | NRG RPV Holdco [Member]

113

Schedule of Equity Method Investments [Line Items]

Number of Solar Leases in Portfolio | generatingunit

2,200

Tax Equity Financed Portfolio of Leases [Member] | NRG RPV Holdco [Member]

15 years

Schedule of Equity Method Investments [Line Items]

Number of Solar Leases in Portfolio | generatingunit

5,400

Maximum [Member] | Tax Equity Financed Portfolio of Leases [Member] | NRG DGPV Holdco 1 [Member]

Schedule of Equity Method Investments [Line Items]

Maximum [Member] | Tax Equity Financed Portfolio of Leases [Member] | NRG DGPV Holdco 2 [Member]

$ 100

Schedule of Equity Method Investments [Line Items]

Maximum [Member] | Tax Equity Financed Portfolio of Leases [Member] | NRG DGPV Holdco 3 [Member]

$ 60

Schedule of Equity Method Investments [Line Items]

Maximum [Member] | Tax Equity Financed Portfolio of Leases [Member] | NRG RPV Holdco [Member]

$ 50

Schedule of Equity Method Investments [Line Items]

Capital Unit, Class A [Member] | Utah Portfolio [Member]

18 years

Schedule of Equity Method Investments [Line Items]

Financial Institutions [Member] | Capital Unit, Class B [Member] | Utah Portfolio [Member]

100.00%

Schedule of Equity Method Investments [Line Items]

Taxable Income Allocation, Pre-Flip

99.00%

Taxable Income Allocation, Post-Flip

50.00%

[1]	(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of December 31, 2017.
[2]	For thermal energy, net capacity represents MWt for steam or chilled water and excludes 134 MWt available under the right-to-use provisions contained in agreements between two of the Company's thermal facilities and certain of its customers.
[3]	NRG DGPV Holdco 1 LLC, NRG DGPV Holdco 2 LLC, NRG DGPV Holdco 3 LLC and NRG RPV Holdco 1 LLC are tax equity structures and VIEs. The related allocations are described below.
[4]	GenConn is a variable interest entity.
[5]	Includes DGPV Holdco 1, DGPV Holdco 2 and DGPV Holdco 3.
[6]	Utah Solar Portfolio was acquired by NRG on November 2, 2016.

Fair Value of Financial Instruments Fair Value of Financial Instruments - Balance Sheet Grouping (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financing Receivable, Net	$ 13	$ 30
Long-term Debt and Capital Lease Obligations, Including Current Maturities	5,930	6,121
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financing Receivable, Net	13	30
Long-term Debt and Capital Lease Obligations, Including Current Maturities	5,897	6,122
Fair Value, Inputs, Level 2 [Member] \| Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt and Capital Lease Obligations, Including Current Maturities	1,502	1,455
Fair Value, Inputs, Level 3 [Member] \| Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt and Capital Lease Obligations, Including Current Maturities	$ 4,428	$ 4,666

Fair Value of Financial Instruments Fair Value of Financial Instruments - Recurring Fair Value Measurements (Details) - USD ($)

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

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

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

$ 0

^[1]

2,000,000

$ 3,000,000

Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3

48,000,000

79,000,000

Fair Value, Assets, Level 1 to Level 2 Transfers, Amount

Fair Value, Assets, Level 2 to Level 1 Transfers, Amount

Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount

Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount

Fair Value, Inputs, Level 1 [Member]

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

Fair Value, Inputs, Level 2 [Member]

1,000,000

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

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]

2,000,000

^[2]

2,000,000

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

Derivative Assets (Liabilities), at Fair Value, Net

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]

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

Derivative Assets (Liabilities), at Fair Value, Net

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]

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

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

^[2]

48,000,000

79,000,000

Commodity contracts

1,000,000

2,000,000

Commodity contracts | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]

1,000,000

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

1,000,000

Commodity contracts | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]

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

1,000,000

Interest Rate Contract [Member]

1,000,000

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

1,000,000

Interest Rate Contract [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]

47,000,000

78,000,000

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

Interest Rate Contract [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]

^[2]

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

1,000,000

$ 47,000,000

$ 78,000,000

[1]	(a) Derivative Asset balances classified as current are included within the prepayments and other current assets line item of the Consolidated Balance Sheet. Derivative Asset balances classified as long-term are included within the other non-current assets line item of the Consolidated Balance Sheet.
[2]	There were no derivative assets or liabilities classified Level 3 as of December 31, 2017 and 2016.

Fair Value of Financial Instruments Fair Value of Financial Instruments - Derivative FV Measurement and Credit Risk (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Assets, Measured on Recurring Basis, Valuation Techniques, Impact of Credit Reserve to Fair Value	$ 1
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$ 2,700
Estimated Counterparty Credit Risk Exposure to Certain Counterparties, Period	5 years

Accounting for Derivative Instruments and Hedging Activities Accounting for Derivative Instruments and Hedging Activities - FV of Derivatives (Details) - USD ($)
$ in Millions

Dec. 31, 2017

Dec. 31, 2016

$ 48

$ 79

Derivative, Collateral, Obligation to Return Cash

^[1]

Derivative, Collateral, Right to Reclaim Cash

Fair Value of Gross Derivative Assets/(Liabilities), Net

(46)

(76)

Derivative Asset Fair Value Gross Liability Net Of Derivative Liability Fair Value Gross Asset

Derivative Asset, Fair Value, Amount Offset Against Collateral Net Of Derivative Liability, Fair Value, Amount Offset Against Collateral

(46)

(76)

Natural Gas [Member] | MMbtu [Member]

Derivative, Notional Amount

Interest [Member] | Dollars

Derivative, Notional Amount

1,940

2,090

Derivatives Designated as Cash Flow Hedges

Derivatives Not Designated as Cash Flow Hedges

^[1]

^[1]

Commodity contracts

Derivative Asset, Fair Value, Gross Liability

Derivative instruments — affiliate

Derivative Liability, Fair Value, Gross Asset

Derivative Liability

Fair Value of Gross Derivative Assets/(Liabilities), Net

Derivative Asset Fair Value Gross Liability Net Of Derivative Liability Fair Value Gross Asset

Derivative Asset, Fair Value, Amount Offset Against Collateral Net Of Derivative Liability, Fair Value, Amount Offset Against Collateral

Interest rate contracts current | Derivatives Designated as Cash Flow Hedges

Interest rate contracts current | Derivatives Not Designated as Cash Flow Hedges

^[1]

Interest rate contracts long-term | Derivatives Designated as Cash Flow Hedges

^[1]

Interest rate contracts long-term | Derivatives Not Designated as Cash Flow Hedges

^[1]

Commodity contracts current | Derivatives Not Designated as Cash Flow Hedges

^[1]

Interest Rate Contract [Member]

^[1]

Derivative Asset, Fair Value, Gross Liability

Derivative instruments — affiliate

Derivative Liability, Fair Value, Gross Asset

Derivative Liability

Fair Value of Gross Derivative Assets/(Liabilities), Net

(46)

(77)

Derivative Asset Fair Value Gross Liability Net Of Derivative Liability Fair Value Gross Asset

Derivative Asset, Fair Value, Amount Offset Against Collateral Net Of Derivative Liability, Fair Value, Amount Offset Against Collateral

$ (46)

$ (77)

[1]

(a) Derivative Asset balances classified as current are included within the prepayments and other current assets line item of the Consolidated Balance Sheet. Derivative Asset balances classified as long-term are included within the other non-current assets line item of the Consolidated Balance Sheet.

Accounting for Derivative Instruments and Hedging Activities Accounting for Derivative Instruments and Hedging Activities - AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2016	Jun. 30, 2016	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Loss	$ (60)	$ (70)	$ (83)			$ (76)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	10	13	14
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	0	0	(21)
Accumulated other comprehensive loss	(28)	(28)	(27)	$ (28)
Loss expected to be realized from OCI during the next 12 months, net of tax	13
Accumulated Other Comprehensive Income (Loss), Cumulative Change in Gain (Loss) from Cash Flow Hedges, Tax Amount	9	$ 16	16
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months, Tax	2
Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Loss			$ (56)
Accumulated other comprehensive loss	$ (32)				$ (42)

Accounting for Derivative Instruments and Hedging Activities Accounting for Derivative Instruments and Hedging Activities - Impact of Statement of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain/(loss) on derivatives	$ 10	$ 13	$ (7)
Interest Rate Contract [Member] \| Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain/(loss) on derivatives	$ 7	$ 2	(17)
Commodity contracts \| Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain/(loss) on derivatives			$ 2

Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Finite-Lived Intangible Assets
Gross amount at the end of the period	$ 1,465	$ 1,471	$ 1,477
Impairment of Intangible Assets, Finite-lived	(6)
Finite-Lived Intangible Assets, Other Changes		(6)
Gross amount at the beginning of the period	1,471	1,477
Less accumulated amortization	(237)	(168)
Net carrying amount	1,228	1,303
Amortization of Intangible Assets	$ 71	71	56
Finite-Lived Intangible Asset, Useful Life	20 years
Contra Revenue Intangibles Amortization	$ 70	70	55
Accumulated Amortization of Out of Market Contracts	4
Estimated amortization related to the Company's finite-lived intangible assets
Estimated intangible assets amortization, 2016	71
Estimated intangible assets amortization, 2017	71
Estimated intangible assets amortization, 2018	71
Estimated intangible assets amortization, 2019	71
Estimated intangible assets amortization, 2020	71
Customer Contracts
Finite-Lived Intangible Assets
Gross amount at the end of the period	15	15	15
Impairment of Intangible Assets, Finite-lived	0
Finite-Lived Intangible Assets, Other Changes		0
Gross amount at the beginning of the period	15	15
Less accumulated amortization	(8)	(7)
Net carrying amount	7	8
Customer Relationships
Finite-Lived Intangible Assets
Gross amount at the end of the period	66	66	66
Impairment of Intangible Assets, Finite-lived	0
Finite-Lived Intangible Assets, Other Changes		0
Gross amount at the beginning of the period	66	66
Less accumulated amortization	(5)	(4)
Net carrying amount	61	62
Supply Commitment Arrangement [Domain]
Finite-Lived Intangible Assets
Gross amount at the end of the period	1,280	1,286	1,286
Impairment of Intangible Assets, Finite-lived	(6)
Finite-Lived Intangible Assets, Other Changes		0
Gross amount at the beginning of the period	1,286	1,286
Less accumulated amortization	(205)	(143)
Net carrying amount	1,075	1,143
Other Intangible Assets [Member]
Finite-Lived Intangible Assets
Gross amount at the end of the period	6	6	6
Impairment of Intangible Assets, Finite-lived	0
Finite-Lived Intangible Assets, Other Changes		0
Gross amount at the beginning of the period	6	6
Less accumulated amortization	(2)	(2)
Net carrying amount	4	4
Emission Allowances [Member]
Finite-Lived Intangible Assets
Gross amount at the end of the period	9	9	15
Impairment of Intangible Assets, Finite-lived	0
Finite-Lived Intangible Assets, Other Changes		(6)
Gross amount at the beginning of the period	9	15
Less accumulated amortization	(3)	(2)
Net carrying amount	6	7
Research and Development Expense [Member]
Finite-Lived Intangible Assets
Gross amount at the end of the period	3	3	3
Impairment of Intangible Assets, Finite-lived	0
Finite-Lived Intangible Assets, Other Changes		0
Gross amount at the beginning of the period	3	3
Less accumulated amortization	(1)	(1)
Net carrying amount	2	2
Leasehold Rights [Member]
Finite-Lived Intangible Assets
Gross amount at the end of the period	86	86	$ 86
Impairment of Intangible Assets, Finite-lived	0
Finite-Lived Intangible Assets, Other Changes		0
Gross amount at the beginning of the period	86	86
Less accumulated amortization	(13)	(9)
Net carrying amount	73	77
Out of Market Contracts [Member]
Finite-Lived Intangible Assets
Amortization	1	$ 1
NRG Solar Blythe LLC [Member]
Finite-Lived Intangible Assets
Out of Market Contracts	7
Spring Canyon [Member]
Finite-Lived Intangible Assets
Out of Market Contracts	$ 3
Finite-Lived Intangible Asset, Useful Life	25 years
Alta Wind XI [Member]
Finite-Lived Intangible Assets
Out of Market Contracts	$ 5

Asset Impairments Asset Impairments(Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment losses	$ 44	$ 185	$ 1
Elbow Creek [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment losses	26	117
Goat Wind [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment losses		60
Forward [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment losses	5	6
November 2017 Drop Down Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment losses	13	$ 2	$ 1
Property, Plant and Equipment [Member] \| November 2017 Drop Down Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment losses	8
Finite-Lived Intangible Assets [Member] \| November 2017 Drop Down Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment losses	$ 5

Long-term Debt Long-term Debt - Summary Table (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Mar. 27, 2017

Oct. 31, 2016

Jul. 15, 2016

Mar. 31, 2014

$ 5,914

$ 6,149

Long-term Debt, Excluding Current Maturities

5,531

5,726

Debt Instrument, Unamortized Discount

^[1]

(17)

(27)

Pro-Rate Share of Debt Held by Unconsolidated Affiliates

777

Current portion of long-term debt

306

323

Other Debt [Member]

443

505

Project [Domain]

3.25% Convertible Notes due 2020 [Member]

4,376

4,666

$ 288

288

3.5% Convertible Notes due 2019 [Member]

3.25%

$ 345

345

$ 345

Convertible Debt [Member]

3.50%

Interest Expense at Effective Rate

$ 33

5.375% Senior Notes due in 2024 [Member]

5.375%

5.00% Senior Notes due in 2026 [Member]

$ 500

500

5.00%

NRG Yield Revolving Credit Facility [Member]

$ 350

350

Debt Instrument, Description of Variable Rate Basis

1 month LIBOR

2.50%

Agua Caliente Borrower 2 [Member]

$ 55

$ 41

Alpine Financing Agreement, due 2022 [Member]

5.43%

Debt Instrument, Description of Variable Rate Basis

3-Month LIBOR

Alta Wind I-V, lease financing arrangement, due 2034 and 2035 [Member]

$ 135

145

West Holdings Credit Agreement [Member]

926

965

NRG Energy Center Minneapolis LLC Senior Secured Notes [Member]

400

443

$ 83

NRG Energy Center Minneapolis Series D Notes [Member]

5.95%

$ 125

125

Laredo Ridge Wind, LLC, due in 2026 [Member]

3.55%

Debt Instrument, Description of Variable Rate Basis

3-Month LIBOR

1.875%

Marsh Landing Term Loan Facility [Member]

$ 95

100

Tapestry Wind LLC due in 2021 [Member]

$ 318

370

Debt Instrument, Description of Variable Rate Basis

3-Month LIBOR

1.625%

Utah Solar Portfolio, due 2022 [Member]

$ 162

172

Debt Instrument, Description of Variable Rate Basis

1 month LIBOR

2.625%

Viento Funding II, Inc., due in 2023 [Member]

$ 278

287

$ 287

Debt Instrument, Description of Variable Rate Basis

3-Month LIBOR

2.75%

Walnut Creek Energy, LLC, due in 2023 [Member]

$ 163

178

Debt Instrument, Description of Variable Rate Basis

1 month LIBOR

1.625%

Marsh Landing Tranche B due 2023 [Member]

$ 267

$ 310

Debt Instrument, Description of Variable Rate Basis

3-Month LIBOR

NRG Energy Center Minneapolis LLC Senior Secured Notes, due 2025 [Member]

1.875%

CVSR Financing Agreement [Member]

7.25%

$ 746

$ 771

CVSR Holdco due 2037 [Member]

4.68%

$ 194

$ 199

Letter of Credit [Member] | NRG Yield Revolving Credit Facility [Member]

4.68%

Letter of Credit [Member] | Agua Caliente Borrower 2 [Member]

$ 74

Letter of Credit [Member] | Alpine Financing Agreement, due 2022 [Member]

Letter of Credit [Member] | Alta Wind I-V, lease financing arrangement, due 2034 and 2035 [Member]

Letter of Credit [Member] | West Holdings Credit Agreement [Member]

119

Letter of Credit [Member] | NRG Energy Center Minneapolis LLC Senior Secured Notes [Member]

102

Letter of Credit [Member] | NRG Energy Center Minneapolis Series D Notes [Member]

Letter of Credit [Member] | Laredo Ridge Wind, LLC, due in 2026 [Member]

Letter of Credit [Member] | Marsh Landing Term Loan Facility [Member]

Letter of Credit [Member] | Tapestry Wind LLC due in 2021 [Member]

Letter of Credit [Member] | Utah Solar Portfolio, due 2022 [Member]

Letter of Credit [Member] | Viento Funding II, Inc., due in 2023 [Member]

Letter of Credit [Member] | Walnut Creek Energy, LLC, due in 2023 [Member]

Letter of Credit [Member] | CVSR Financing Agreement [Member]

Letter of Credit [Member] | CVSR Holdco due 2037 [Member]

Minimum [Member] | Alpine [Member]

$ 13

Minimum [Member] | Alpine Financing Agreement [Member]

Minimum [Member] | West Holdings Credit Agreement [Member]

1.75%

Debt Instrument, Description of Variable Rate Basis

1 month LIBOR

Minimum [Member] | West Holdings Credit Agreement due 2023 Tranche A [Member]

Minimum [Member] | Alta Wind I - V Lease financing arrangement [Member]

1.625%

Minimum [Member] | West Holdings Credit Agreement due 2023 Tranche B [Member]

5.696%

Minimum [Member] | CVSR Financing Agreement [Member]

2.25%

Maximum [Member] | Alpine [Member]

2.339%

Maximum [Member] | Alpine Financing Agreement [Member]

Maximum [Member] | West Holdings Credit Agreement [Member]

Maximum [Member] | Alta Wind I - V Lease financing arrangement [Member]

Maximum [Member] | CVSR Financing Agreement [Member]

7.015%

3.775%

[1]	c) Discounts relate to the 2019 Convertible Notes and 2020 Convertible Notes.

Long-term Debt Long-term Debt - Corporate Debt (Details)

12 Months Ended

Aug. 18, 2016

USD ($)

Jul. 15, 2016

USD ($)

Jun. 30, 2015

May 15, 2015

Dec. 31, 2017

USD ($)

$ / shares

Dec. 31, 2015

USD ($)

Dec. 31, 2016

USD ($)

Jun. 29, 2015

USD ($)

$ / shares

Mar. 31, 2014

USD ($)

Feb. 11, 2014

USD ($)

Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt

$ 23,000,000

3.25% Convertible Notes due 2020 [Member]

5,914,000,000

$ 6,149,000,000

Convertible Debt

$ 276,000,000

$ 288,000,000

Debt Instrument, Convertible, Conversion Price | $ / shares

3.25%

$ 27.50

Debt Instrument, Convertible, Conversion Ratio

36.3636

Debt Instrument, Face Amount

$ 1,000

Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt

$ 23,000,000

Percent of face value

98.75%

Long-term Debt, Fair Value

$ 284,000,000

Conversion Value of Convertible Debt

288,000,000

$ 198,000,000

3.5% Convertible Notes due 2019 [Member]

Debt Instrument, Interest Rate, Effective Percentage

5.00%

Convertible Debt

$ 340,000,000

Debt Instrument, Convertible, Conversion Ratio

3.50%

42.9644

Percent of face value

100.88%

Long-term Debt, Fair Value

$ 348,000,000

Conversion Value of Convertible Debt

345,000,000

$ 345,000,000

$ 279,000,000

5.00% Senior Notes due in 2026 [Member]

Proceeds from Issuance of Unsecured Debt

$ 350,000,000

5.00%

Convertible Debt [Member]

$ 350,000,000

350,000,000

Amortization of Debt Discount (Premium)

Interest Expense, Debt

^[1]

21,000,000

9,000,000

Amortization of Financing Costs

3,000,000

Interest Expense at Effective Rate

$ 33,000,000

Debt Instrument, Face Amount

$ 1,000

5.375% Senior Notes due in 2024 [Member]

5.375%

NRG Yield Revolving Credit Facility [Member]

$ 500,000,000

500,000,000

Proceeds from Issuance of Debt

55,000,000

55,000,000

CVSR Financing Agreement [Member]

4.68%

Proceeds from Issuance of Debt

746,000,000

$ 771,000,000

$ 200,000,000

Proceeds from Debt, Net of Issuance Costs

$ 97,500,000

Letter of Credit [Member] | NRG Yield Revolving Credit Facility [Member]

Letter of Credit [Member] | CVSR Financing Agreement [Member]

74,000,000

$ 0

Common Stock Closing Price | $ / shares

$ 18.90

Common Stock Closing Price | $ / shares

$ 18.85

[1]	(a) Interest expense is calculated using coupon rate of 3.25% and 3.5% for 2020 and 2019 Convertible Notes, respectively.

Long-term Debt Long-term Debt - 2017 Drop Down Assets (Details) - USD ($) $ in Millions	2 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Nov. 01, 2017	Mar. 27, 2017	Feb. 17, 2017	Nov. 02, 2016
Debt Instrument [Line Items]
Long-term Debt	$ 6,149	$ 5,914
November 2017 Drop Down Assets [Member]
Debt Instrument [Line Items]
Long-term Debt			$ 26
Debt Instrument, Interest Rate, Stated Percentage		4.69%
Debt Instrument, Interest Rate, Effective Percentage		8.00%
Agua Caliente Borrower 1, due 2038 [Member]
Debt Instrument [Line Items]
Long-term Debt					$ 130
Agua Caliente Borrower 2 [Member]
Debt Instrument [Line Items]
Long-term Debt	0	$ 41
Debt Instrument, Interest Rate, Stated Percentage		5.43%
Utah Solar Portfolio, due 2022 [Member]
Debt Instrument [Line Items]
Long-term Debt	287	$ 278		$ 287
Debt Instrument, Basis Spread on Variable Rate		2.625%
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt						$ 222
Proceeds from Issuance of Debt	$ 65

Long-term Debt Long-term Debt - Thermal/CVSR (Details) - USD ($) $ in Millions	Oct. 31, 2016	Jul. 15, 2016	Dec. 31, 2017	Mar. 16, 2017	Dec. 31, 2016	Sep. 01, 2016
Debt Instrument [Line Items]
Long-term Debt			$ 5,914		$ 6,149
NRG Energy Center Minneapolis Series D Notes [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$ 125
Debt Instrument, Interest Rate, Stated Percentage	3.55%		3.55%
Long-term Debt			$ 125		125
NRG Energy Center Minneapolis Series F Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.80%		4.60%
Line of Credit Facility, Maximum Borrowing Capacity	$ 70		$ 80
Credit Facility, Maximum Borrowing Capacity, Amendment				$ 10
CVSR Financing Agreement [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Debt		$ 200
Debt Instrument, Interest Rate, Stated Percentage		4.68%
Long-term Debt			$ 746		771
CVSR Holdco due 2037 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.68%
Long-term Debt			$ 194		$ 199
CVSR [Member]
Debt Instrument [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired						51.05%
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt						$ 496
CVSR [Member] \| CVSR Financing Agreement [Member]
Debt Instrument [Line Items]
Long-term Debt						771
CVSR [Member] \| CVSR Holdco due 2037 [Member]
Debt Instrument [Line Items]
Long-term Debt						$ 200

Long-term Debt Long-term Debt - Avenal/Lease financing arrangements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term Debt	$ 5,914	$ 6,149
NRG Yield Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	1 month LIBOR
Debt Instrument, Basis Spread on Variable Rate	2.50%
Long-term Debt	$ 55	$ 0
Avenal [Member]
Debt Instrument [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Utility-Scale Solar [Member] \| Avenal [Member]
Debt Instrument [Line Items]
Equity Method Investment, Ownership Percentage	50.00%

Long-term Debt Long-term Debt - Swaps/Maturities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Debt Instrument [Line Items]
2016	$ 306
2017	722
2018	657
2019	455
2020	653
Thereafter	3,121
Long-term Debt, Gross	5,914
Interest Rate Swap [Member]
Debt Instrument [Line Items]
Derivative, Notional Amount	$ 1,940
Interest Rate Swap [Member] \| NRG Solar Alpine LLC [Member] \| Maturity - December 31, 2029 [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	85.00%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 115
Interest Rate Swap [Member] \| NRG Solar Avra Valley [Member] \| Maturity - November 30, 2030 [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	85.00%
Derivative, Fixed Interest Rate	2.333%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 46
Interest Rate Swap [Member] \| NRG Solar Blythe LLC [Member] \| Maturity - June 25, 2028 [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Derivative, Fixed Interest Rate	3.563%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 13
Interest Rate Swap [Member] \| Borrego [Member] \| Maturity - December 31, 2029 [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Derivative, Fixed Interest Rate	1.125%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 5
Interest Rate Swap [Member] \| NRG West Holdings LLC [Member] \| Maturity - June 30, 2023 [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 340
Interest Rate Swap [Member] \| Kansas South [Member] \| Maturity - June 30, 2023 [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Derivative, Fixed Interest Rate	2.368%
Debt Instrument, Description of Variable Rate Basis	6-Month LIBOR
Derivative, Notional Amount	$ 21
Interest Rate Swap [Member] \| Laredo Ridge [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Derivative, Fixed Interest Rate	2.31%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 75
Interest Rate Swap [Member] \| Marsh Landing [Member] \| Maturity - June 30, 2023 [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Derivative, Fixed Interest Rate	3.244%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 295
Interest Rate Swap [Member] \| NRG Solar Roadrunner LLC [Member] \| Maturity - December 31, 2029 [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Derivative, Fixed Interest Rate	4.313%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 26
Interest Rate Swap [Member] \| South Trent Wind LLC [Member] \| Maturity - June14, 2020 [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Derivative, Fixed Interest Rate	3.265%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 40
Interest Rate Swap [Member] \| South Trent Wind LLC [Member] \| Maturity - June 14, 2028 [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Derivative, Fixed Interest Rate	4.95%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 21
Interest Rate Swap [Member] \| Tapestry Wind [Member] \| Maturity - December 21, 2021 [Member] [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Derivative, Fixed Interest Rate	2.21%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 146
Interest Rate Swap [Member] \| Tapestry Wind [Member] \| Maturity - December 21, 2029 [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	50.00%
Derivative, Fixed Interest Rate	3.57%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 60
Alta Wind Asset Management, due 2031 [Member] \| Interest Rate Swap [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	100.00%
Derivative, Fixed Interest Rate	2.47%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 17
Utah Solar Portfolio, due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	1 month LIBOR
Utah Solar Portfolio, due 2022 [Member] \| Interest Rate Swap [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	80.00%
Debt Instrument, Description of Variable Rate Basis	1-Month LIBOR
Derivative, Notional Amount	$ 223
Viento Funding II, Inc., due in 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Viento Funding II, Inc., due in 2023 [Member] \| Interest Rate Swap [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	90.00%
Debt Instrument, Description of Variable Rate Basis	6-Month LIBOR
Derivative, Notional Amount	$ 148
Viento Funding II, Inc., due in 2023 [Member] \| Interest Rate Swap [Member] \| Maturity - June 30, 2028 [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	90.00%
Derivative, Fixed Interest Rate	4.985%
Debt Instrument, Description of Variable Rate Basis	6-Month LIBOR
Derivative, Notional Amount	$ 65
Walnut Creek [Member] \| Interest Rate Swap [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 239
WCEP Holdings, LLC, due in 2023 [Member] \| Interest Rate Swap [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	90.00%
Derivative, Fixed Interest Rate	4.003%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 45

Earnings Per Share (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

3 Months Ended

5 Months Ended

12 Months Ended

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2013

^[1]

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

Weighted Average Number of Shares Outstanding, Diluted

Numerator:

$ (70)

$ 29

$ 28

$ (3)

$ (13)

$ 33

$ 32

$ 5

$ (16)

$ 57

$ 33

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

Weighted Average Number of Shares Outstanding, Diluted

Numerator:

Weighted average number of common shares outstanding — basic and diluted

$ 14

$ (6)

$ 20

Denominator:

Basic and diluted loss per share:

(Loss) Earnings per weighted average common share — basic and diluted

$ (0.16)

$ 0.58

$ 0.40

^[1]

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

Weighted Average Number of Shares Outstanding, Diluted

Numerator:

Weighted average number of common shares outstanding — basic and diluted

$ 19

$ (10)

$ 37

Denominator:

Basic and diluted loss per share:

(Loss) Earnings per weighted average common share — basic and diluted

$ 0.40

$ (0.16)

$ 0.58

3.5% Convertible Notes due 2019 [Member] | Common Class A [Member]

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount

3.25% Convertible Notes due 2020 [Member] | Common Class C [Member]

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount

[1]	Net (loss) income attributable to NRG Yield, Inc. and basic and diluted (loss) earnings per share might not recalculate due to presenting values in millions rather than whole dollars.

Stockholders' Equity Stockholders' Equity (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended				12 Months Ended
	Jun. 29, 2015	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jul. 22, 2013
Statement of Stockholders' Equity
Distribution Made to Limited Liability Company (LLC) Member, Distributions Paid, Per Unit		$ 0.288
Common Stock, Par or Stated Value Per Share		$ 0.01				$ 0.01	$ 0.01
ATM Program, Maximum Dollar Value of Shares to Be Issued		$ 150,000				$ 150,000
Sale of Stock, Number of Shares Issued in Transaction	28,198,000					1,921,866
Proceeds from Issuance of Common Stock, Before Commission Fees						$ 35,000
Proceeds from the issuance of common stock						34,000	$ 0	$ 599,000
Investment Banking, Advisory, Brokerage, and Underwriting Fees and Commissions						346
ATM program, dollar value of shares remaining		$ 115,000				$ 115,000
Dividends Payable, Date Declared						Feb. 15, 2018
Common Stock, Dividends, Per Share, Declared						$ 0.298
Dividends Payable, Date to be Paid						Mar. 15, 2018
Dividends Payable, Date of Record						Mar. 01, 2018
Preferred Stock, Shares Authorized		10,000,000				10,000,000	10,000,000		10,000,000
Preferred Stock, Par or Stated Value Per Share		$ 0.01				$ 0.01	$ 0.01		$ 0.01
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued		$ 0				$ 0	$ 0
Common Class B [Member]
Statement of Stockholders' Equity
Distribution Made to Limited Liability Company (LLC) Member, Distributions Paid, Per Unit			$ 0.28	$ 0.27	$ 0.26
Common Class C [Member]
Statement of Stockholders' Equity
Proceeds from the issuance of common stock	$ 599,000
Investment Banking, Advisory, Brokerage, and Underwriting Fees and Commissions	$ 21,000
NRG Yield, Inc. [Member]
Statement of Stockholders' Equity
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest						53.70%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Voting Interest						44.90%
NRG Yield, Inc. [Member]
Statement of Stockholders' Equity
Preferred Stock, Shares Authorized		10,000,000				10,000,000	10,000,000
Preferred Stock, Par or Stated Value Per Share		$ 0.01				$ 0.01	$ 0.01
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued		$ 0				$ 0	$ 0
NRG Yield, Inc. [Member] \| Common Class A [Member]
Statement of Stockholders' Equity
Common Stock, Par or Stated Value Per Share		$ 0.01				$ 0.01	$ 0.01
Over-Allotment Option [Member] \| NRG Yield, Inc. [Member] \| Common Class C [Member]
Statement of Stockholders' Equity
Sale of Stock, Number of Shares Issued in Transaction	3,678,000

Segment Reporting (Details) - USD ($)
$ in Millions

3 Months Ended

5 Months Ended

12 Months Ended

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2013

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ 231

$ 269

$ 288

$ 221

$ 235

$ 276

$ 287

$ 237

$ 1,009

$ 1,035

$ 968

326

308

323

334

303

185

124

(100)

119

130

283

222

326

(3)

(9)

(306)

(284)

(267)

(1)

(98)

$ 30

$ 47

$ (2)

(115)

$ 51

$ 65

$ 1

(23)

1,178

1,152

1,178

1,152

^[1]

^[2]

^[1]

^[2]

8,283

8,962

8,283

8,962

Conventional Generation

336

333

336

103

156

187

196

(7)

(49)

(48)

120

153

156

120

153

102

106

102

106

^[1]

^[2]

^[1]

^[2]

1,897

1,993

1,897

1,993

Renewables

501

532

458

133

128

138

210

203

185

114

116

(3)

(2)

(163)

(151)

(86)

(18)

(86)

1,076

1,046

1,076

1,046

^[1]

^[2]

^[1]

^[2]

5,811

6,114

5,811

6,114

Thermal [Member]

172

170

174

116

114

126

(10)

(7)

^[1]

^[2]

^[1]

^[2]

422

426

422

426

Corporate

(22)

(17)

(15)

(84)

(78)

(61)

(105)

(95)

(76)

(1)

(177)

(94)

$ (88)

^[1]

^[2]

^[1]

^[2]

Affiliated Entity [Member]

$ 153

$ 429

$ 153

$ 429

Southern California Edison [Member] | Conventional Generation

$ 8

Southern California Edison [Member] | Renewables

21.00%

22.00%

PG&E [Member] | Conventional Generation

20.00%

21.00%

17.00%

PG&E [Member] | Renewables

12.00%

Weighted Average Number of Shares Outstanding, Diluted

11.00%

12.00%

[1]	Includes accruals.
[2]	Includes accruals.

Income Taxes (Provision) (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Provision) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2011
Current
U.S. Federal	$ 0	$ 0	$ 0
Current State and Local Tax Expense (Benefit)	0	0		$ 0
Total — current	0	0	0
Deferred
U.S. Federal	75	(1)	10
State	(3)	0	2
Total — deferred	72	(1)	12
Income tax expense (benefit)	$ 72	$ (1)	$ 12
Effective tax rate (as a percent)	147.00%	(100.00%)	14.00%
U.S. federal statutory rate (as a percent)	35.00%
Reconciliation of the U.S. federal statutory rate to the Company's effective rate from continuing operations
Income Before Income Taxes	$ 49	$ 1	$ 84
Tax at 35%	17	0	29
State taxes, net of federal benefit	3	0	(2)
Investment tax credits	(1)	(1)	(1)
Impact of non-taxable partnership earnings	(9)	(1)	(17)
Production tax credits, including prior year true-up	(1)	4	4
Change in state effective tax rate	68	0	0
Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Amount	$ 1	$ (3)	$ 3
NRG \| NRG Yield LLC
Reconciliation of the U.S. federal statutory rate to the Company's effective rate from continuing operations
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	46.30%
NRG Yield, Inc. [Member]
Reconciliation of the U.S. federal statutory rate to the Company's effective rate from continuing operations
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	53.70%
NRG Yield, Inc. [Member] \| NRG Yield LLC
Reconciliation of the U.S. federal statutory rate to the Company's effective rate from continuing operations
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	53.70%

Income Taxes (Deferred) (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Deferred Tax Liabilities, Gross [Abstract]
Total deferred tax assets, net of valuation allowance	$ 70,000,000	$ 19,000,000
Deferred Tax Liabilities, Gross	70,000,000	19,000,000
Deferred Tax Assets, Gross [Abstract]
Production tax credits carryforwards	7,000,000	5,000,000
Investment tax credits	1,000,000	1,000,000
U.S. Federal net operating loss carryforwards	183,000,000	226,000,000
Deferred Tax Assets, Capital Loss Carryforwards	10,000,000	16,000,000
State net operating loss carryforwards	7,000,000	3,000,000
Total deferred tax assets	208,000,000	251,000,000
Deferred Tax Assets, Valuation Allowance	10,000,000	16,000,000
Deferred Tax Assets, Net of Valuation Allowance	198,000,000	235,000,000
Deferred Tax Assets, Net	128,000,000	216,000,000
Deferred Tax Assets, Net, Excluding Valuation Allowance	$ 138,000,000	232,000,000
Unrecognized Tax Benefits		$ 0

Related Party Transactions (Details) - USD ($)	2 Months Ended	5 Months Ended	12 Months Ended
Related Party Transactions (Details) - USD ($)	Feb. 28, 2018	Dec. 31, 2013	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 05, 2017	Oct. 31, 2016
Related Party Transaction
General and administrative			$ 19,000,000	$ 16,000,000	$ 12,000,000
Accounts payable — affiliate			48,000,000	40,000,000
Affiliated Entity [Member]
Related Party Transaction
General and administrative		$ 8,000,000
NRG [Member] \| Operations and Maintenance services [Member]
Related Party Transaction
Due to Affiliate			13,000,000	22,000,000
Related Party Transaction, Expenses from Transactions with Related Party			39,000,000	36,000,000	36
NRG Repowering Holdings LLC [Member]
Related Party Transaction
coal, gas purchases				9,000,000	13,000,000
Cost of Natural Gas Purchases			9,000,000	9
NRG RENOM [Member]
Related Party Transaction
Due to Affiliate			5,000,000	5
Related Party Transaction, Expenses from Transactions with Related Party			23,000,000	13,000,000	7,000,000
NRG Wind TE Holdco [Member] \| NRG [Member]
Related Party Transaction
Revenue from Related Parties					16,000,000
NRG Yield [Member] \| NRG [Member]
Related Party Transaction
Management Services Fee, Increase				1,000,000
General and administrative			10,000,000	10
NRG Yield [Member] \| NRG [Member] \| Scenario, Plan [Member]
Related Party Transaction
Management Services Fee, Annual			8,500,000
NRG Energy Center Dover [Member] \| NRG [Member]
Related Party Transaction
Revenue from Related Parties			4,000,000	5,000,000
NRG Yield, Inc. [Member] \| NRG [Member]
Related Party Transaction
Due to Affiliate			4,000,000
GCE Holding LLC [Member] \| NRG [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party					4,000,000
GCE Holding LLC [Member] \| NRG [Member] \| Operations and Maintenance services [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party			5,000,000	5
Marsh Landing [Member] \| NRG [Member]
Related Party Transaction
Due to Affiliate			1,000,000	1
Related Party Transaction, Expenses from Transactions with Related Party			15,000,000	14,000,000	$ 13,000,000
Elbow Creek [Member] \| NRG [Member]
Related Party Transaction
Revenue from Related Parties			$ 8,000,000	$ 8,000,000
NECP [Member] \| NRG [Member]
Related Party Transaction
Related Party Transaction, Amount to be Paid Upon Completion of Project						$ 88,000,000	$ 79,000,000
Subsequent Event [Member] \| NRG [Member] \| Operations and Maintenance services [Member]
Related Party Transaction
Repayments of Accounts Payable, Affiliate	$ 5,000,000

Commitments and Contingencies (Details) - USD ($)	12 Months Ended
Commitments and Contingencies (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Long-term Purchase Commitment [Line Items]
Operating Leases, Rent Expense	$ 17,000,000	$ 15,000,000	$ 10,000,000
Operating Leases, Future Minimum Payments Due, Next Twelve Months	9,000,000
Operating Leases, Future Minimum Payments, Due in Two Years	9,000,000
Operating Leases, Future Minimum Payments, Due in Three Years	9,000,000
Operating Leases, Future Minimum Payments, Due in Four Years	9,000,000
Operating Leases, Future Minimum Payments, Due in Five Years	9,000,000
Operating Leases, Future Minimum Payments, Due Thereafter	151,000,000
Operating Leases, Future Minimum Payments Due	209,000,000
Utilities Operating Expense, Purchased Power under Long-term Contracts	34,000,000	32,000,000	40,000,000
Purchase Obligation, Due in Next Twelve Months	11,000,000
Unrecorded Unconditional Purchase Obligation, Due within Two Years	5,000,000
Unrecorded Unconditional Purchase Obligation, Due within Three Years	3,000,000
Unrecorded Unconditional Purchase Obligation, Due within Four Years	3,000,000
Unrecorded Unconditional Purchase Obligation, Due within Five Years	3,000,000
Unrecorded Unconditional Purchase Obligation, Due after Five Years	16,000,000
Purchase Obligation	41,000,000
NRG Repowering Holdings LLC [Member]
Long-term Purchase Commitment [Line Items]
coal, gas purchases		9,000,000	$ 13,000,000
Cost of Natural Gas Purchases	$ 9,000,000	$ 9

Unaudited Quarterly Financial Data (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

3 Months Ended

5 Months Ended

12 Months Ended

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2013

^[1]

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Net Income/(Loss) per Weighted Average Common Share - Basic (in dollars per share)

$ (0.71)

$ 0.30

$ 0.29

$ (0.03)

$ (0.14)

$ 0.34

$ 0.33

$ 0.05

Weighted Average Number of Shares Outstanding, Basic

$ (70)

$ 29

$ 28

$ (3)

$ (13)

$ 33

$ 32

$ 5

$ (16)

$ 57

$ 33

(98)

(2)

$ (115)

$ 51

$ 65

$ 1

(23)

124

(100)

119

130

283

222

326

Scenario, Previously Reported [Member]

$ 231

269

288

221

235

276

287

237

$ 1,009

1,035

968

(1)

(114)

122

(99)

117

128

218

320

Operating Revenues [Member]

265

284

218

232

272

283

234

$ 1,021

$ 953

Quarterly Financial Information, Quarterly Charges and Credits, Amount Reconciling to Previously Reported Results

Operating Income (Loss) [Member]

Quarterly Financial Information, Quarterly Charges and Credits, Amount Reconciling to Previously Reported Results

(10)

(1)

Net Income (Loss) [Member]

Quarterly Financial Information, Quarterly Charges and Credits, Amount Reconciling to Previously Reported Results

$ (11)

$ 2

$ (1)

$ 1

$ (1)

Weighted Average Number of Shares Outstanding, Diluted

Weighted average number of common shares outstanding — basic and diluted

Weighted Average Number of Shares Outstanding, Basic

$ 14

$ (6)

$ 20

$ (0.71)

$ 0.27

$ 0.26

$ (0.03)

$ (0.14)

$ 0.30

$ 0.29

$ 0.05

Weighted Average Number of Shares Outstanding, Diluted

Weighted average number of common shares outstanding — basic and diluted

Weighted Average Number of Shares Outstanding, Basic

$ 19

$ (10)

$ 37