8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): May 9, 2017

NRG YIELD, INC.

(Exact name of Registrant as specified in its charter)

Delaware	001-36002	46-1777204
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

804 Carnegie Center, Princeton, New Jersey 08540

(Address of principal executive offices, including zip code)

(609) 524-4500

(Registrant’s telephone number, including area code)

N/A

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o  Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o  Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o  Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o  Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company     o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Item 8.01. Other Events.

On March 27, 2017, NRG Yield Operating LLC, a subsidiary of NRG Yield, Inc. (the “Company”), through certain of its wholly owned subsidiaries, acquired the following interests from certain wholly owned subsidiaries of NRG Energy, Inc. (“NRG”): (i) Agua Caliente Borrower 2 LLC, which owns a 16% interest in the Agua Caliente solar farm, and (ii) NRG's interests in seven utility-scale solar farms located in Utah that were part of NRG's November 2, 2016 acquisition of projects from SunEdison.  Collectively, the acquired interests are referred to as the “March 2017 Drop Down Assets.” 

Accordingly, as reflected in Exhibits 99.1, 99.2 and 99.3 to this Current Report on Form 8-K, the Company has recast certain information within its Annual Report on Form 10-K for the year ended December 31, 2016 as filed with the Securities and Exchange Commission on February 28, 2017 (the "Original Annual Report") to reflect the acquisition of the March 2017 Drop Down Assets for all periods presented in the following sections:

• Part II, Item 6. Selected Financial Data.

• Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

• Part IV, Item 15. Exhibits, Financial Statement Schedules.

As this Current Report on Form 8-K is being filed only for the purpose described above and only affects the Items specified above, the other information in the Original Annual Report remains unchanged. No attempt has been made in this Current Report on Form 8-K to modify or update disclosures in the Original Annual Report except for within the Items noted above. Other than as required to recast certain information as described above and as set forth in Exhibits 99.1, 99.2 and 99.3, this Current Report on Form 8-K does not reflect events occurring after the filing of the Original Annual Report or modify or update any related disclosures. Information within the Original Annual Report not affected by this Current Report on Form 8-K is unchanged and reflects the disclosure made at the time of the filing of the Original Annual Report. Accordingly, this Current Report on Form 8-K should be read in conjunction with the Original Annual Report.

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Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

Exhibit No.	Document
23.1	Consent of KPMG LLP.
99.1	Recast 2016 Form 10-K – Part II, Item 6. Selected Financial Data.
99.2	Recast 2016 Form 10-K – Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
99.3	Recast 2016 Form 10-K – Part IV, Item 15. Exhibits, Financial Statement Schedules.
101 INS	XBRL Instance Document.
101 SCH	XBRL Taxonomy Extension Schema.
101 CAL	XBRL Taxonomy Extension Calculation Linkbase.
101 DEF	XRBL Taxonomy Extension Definition Linkbase.
101 LAB	XBRL Taxonomy Extension Label Linkbase.
101 PRE	XBRL Taxonomy Extension Presentation Linkbase.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

NRG Yield, Inc.
(Registrant)
By:	/s/ Brian E. Curci
	Brian E. Curci
	Corporate Secretary

Dated:  May 9, 2017

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EXHIBIT INDEX

Exhibit No.	Document
23.1	Consent of KPMG LLP.
99.1	Recast 2016 Form 10-K – Part II, Item 6. Selected Financial Data.
99.2	Recast 2016 Form 10-K – Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
99.3	Recast 2016 Form 10-K – Part IV, Item 15. Exhibits, Financial Statement Schedules.
101 INS	XBRL Instance Document.
101 SCH	XBRL Taxonomy Extension Schema.
101 CAL	XBRL Taxonomy Extension Calculation Linkbase.
101 DEF	XRBL Taxonomy Extension Definition Linkbase.
101 LAB	XBRL Taxonomy Extension Label Linkbase.
101 PRE	XBRL Taxonomy Extension Presentation Linkbase.

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EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

NRG Yield, Inc.

We consent to the incorporation by reference in the registration statements No. 333-206061 on Form S-8, No. 333-190071 on Form S-8, No. 333-212096 on Form S-3, No. 333-205140 on Form S-3 and No. 333-204589 on Form S-3 of NRG Yield, Inc. of our report dated May 9, 2017, with respect to the consolidated balance sheets of NRG Yield, Inc. as of December 31, 2016 and 2015, and the related consolidated statements of operations, stockholders’ equity, cash flows, and comprehensive income for each of the years in the three-year period ended December 31, 2016, which report appears in the Current Report on Form 8-K of NRG Yield, Inc. dated May 9, 2017.

(signed) KPMG LLP

Philadelphia, Pennsylvania

May 9, 2017

EX-99.1

Exhibit 99.1

Item 6 — Selected Financial Data

The following table presents the Company's historical selected financial data, which has been recast to include the Drop Down Assets, as if the transfers had taken place from the beginning of the financial statements period, or from the date the respective entities were under common control (if later than the beginning of the financial statements period). Collectively, Drop Down Assets include the following: the June 2014 Drop Down Assets, January 2015 Drop Down Assets, November 2015 Drop Down Assets, CVSR Drop Down and March 2017 Drop Down Assets. The acquisitions are further described in Item 15 —Note 3,Business Acquisitions to the Consolidated Financial Statements. Additionally, for all periods prior to the initial public offering, the data below reflects the Company's accounting predecessor, or NRG Yield, the financial statements of which were prepared on a ''carve-out'' basis from NRG and are intended to represent the financial results of the contracted renewable energy and conventional generation and thermal infrastructure assets in the U.S. that were acquired by NRG Yield LLC on July 22, 2013. For all periods subsequent to the initial public offering, the data below reflects the Company's consolidated financial results.

This historical data should be read in conjunction with the Consolidated Financial Statements and the related notes thereto in Item — 15 and Item — 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

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	Fiscal year ended December 31,
(In millions, except per share data)	2016			2015			2014			2013			2012
Statement of Income Data:
Operating Revenues
Total operating revenues	$	1,021		$	953		$	828		$	434		$	186
Operating Costs and Expenses
Cost of operations	306			321			277			154			118
Depreciation and amortization	297			297			233			92			39
Impairment losses	183			—			—			—			—
General and administrative	16			12			8			7			7
Acquisition-related transaction and integration costs	1			3			4			—			—
Total operating costs and expenses	803			633			522			253			164
Operating Income	218			320			306			181			22
Other Income (Expense)
Equity in earnings of unconsolidated affiliates	60			31			22			27			26
Other income, net	3			3			6			4			3
Loss on debt extinguishment	—			(9		)	(1		)	—			—
Interest expense	(280		)	(263		)	(216		)	(72		)	(29		)
Total other expense, net	(217		)	(238		)	(189		)	(41		)	—
Income Before Income Taxes	1			82			117			140			22
Income tax (benefit) expense	(1		)	12			4			8			10
Net Income	2			70			113			132			$	12
Less: Pre-acquisition net income (loss) of Drop Down Assets	27			(5		)	49			23
Net (Loss) Income Excluding Pre-acquisition Net Income (Loss) of Drop Down Assets	(25		)	75			64			109
Less: Predecessor income prior to initial public offering on July 22, 2013	—			—			—			54
Less: Net (loss) income attributable to noncontrolling interests	(82		)	42			48			42
Net Income Attributable to NRG Yield, Inc.	$	57		$	33		$	16		$	13
Earnings Per Share Attributable to NRG Yield, Inc. Class A and Class C Common Stockholders
Earnings per Weighted Average Class A and Class C Common Share - Basic and Diluted	$	0.58		$	0.40		$	0.30		$	0.29		N/A
Dividends per Class A common share (a)	$	0.945		$	1.015		$	1.42		$	0.23		N/A
Dividends per Class C common share (a)	$	0.945		$	0.625		N/A			N/A			N/A
Other Financial Data:
Capital expenditures	$	20		$	29		$	60		$	782		$	1,398
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	569		$	422		$	362		$	168		$	57
Investing activities	(165		)	(1,108		)	(741		)	(979		)	(1,435		)
Financing activities	(193		)	368			749			848			1,376
Balance Sheet Data (at period end):
Cash and cash equivalents	$	322		$	111		$	429		$	59		$	22
Property, plant and equipment, net	5,460			5,878			6,009			3,388			3,392
Total assets	8,836			8,789			8,906			4,822			3,874
Long-term debt, including current maturities	5,987			5,593			5,731			2,849			1,880
Total liabilities	6,297			5,951			6,062			3,129			2,449
Total stockholders' equity	$	2,539		$	2,838		$	2,844		$	1,693		$	1,425

^(a)The Company began paying dividends on Class A common stock after the initial public offering on July 22, 2013. The Company began paying dividends on Class C common stock after the Recapitalization on May 14, 2015.

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EX-99.2

Exhibit 99.2

Item 7 — Management's Discussion and Analysis of Financial Condition and the Results of Operations

The following discussion analyzes the Company's historical financial condition and results of operations, which were recast to include the effect of the Drop Down Assets acquired on June 30, 2014, January 2, 2015, November 3, 2015, September 1, 2016, and March 27, 2017. As further discussed in Item 15 — Note 1, Nature of Business, to the Consolidated Financial Statements, the purchases of these assets were accounted for in accordance with ASC 805-50, Business Combinations - Related Issues, whereas the assets and liabilities transferred to the Company relate to interests under common control by NRG and, accordingly, were recorded at historical cost. The difference between the cash proceeds and historical value of the net assets was recorded as a distribution to/from NRG and offset to the noncontrolling interest. In accordance with GAAP guidance, the Company prepared its consolidated financial statements to reflect the transfers as if they had taken place from the beginning of the financial statements period, or from the date the entities were under common control (if later than the beginning of the financial statements period). The financial statements reflect the transfers as if they had taken place on January 1, 2014 for Kansas South, TA High Desert, CVSR Drop Down, and Agua Caliente Borrower 2 LLC, which is part of the March 2017 Drop Down Assets; April 1, 2014 for the January 2015 Drop Down Assets and the majority of the November 2015 Drop Down Assets, which represents the date these entities were acquired by NRG; and November 2, 2016 for the Utah Solar Portfolio that is part of the March 2017 Drop Down Assets and was acquired by NRG on November 2, 2016. The Company reduces net income attributable to its Class A and Class C common stockholders by the pre-acquisition net income for the Drop Down Assets, as it was not available to the stockholders.

As you read this discussion and analysis, refer to the Company's Consolidated Statements of Operations to this Form 10-K, which present the results of operations for the years ended December 31, 2016, 2015, and 2014. Also refer to Item 1 — Business and Item 1A — Risk Factors, which include detailed discussions of various items impacting the Company's business, results of operations and financial condition.

The discussion and analysis below has been organized as follows:

• Executive Summary, including a description of the business and significant events that are important to understanding the results of operations and financial condition;

• Results of operations, including an explanation of significant differences between the periods in the specific line items of the consolidated statements of operations;

• Financial condition addressing liquidity position, sources and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements;

• Known trends that may affect the Company’s results of operations and financial condition in the future; and

• Critical accounting policies which are most important to both the portrayal of the Company's financial condition and results of operations, and which require management's most difficult, subjective or complex judgment.

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Executive Summary

Introduction and Overview

The Company is a dividend growth-oriented company formed to serve as the primary vehicle through which NRG owns, operates and acquires contracted renewable and conventional generation and thermal infrastructure assets. The Company believes it is well positioned to be a premier company for investors seeking stable and growing dividend income from a diversified portfolio of lower-risk high-quality assets.

The Company owns a diversified portfolio of contracted renewable and conventional generation and thermal infrastructure assets in the U.S. The Company’s contracted generation portfolio collectively represents4,874 net MW. Each of these assets sells substantially all of its output pursuant to long-term offtake agreements with creditworthy counterparties. The average remaining contract duration of these offtake agreements was approximately16 years as of December 31, 2016, based on CAFD. The Company also owns thermal infrastructure assets with an aggregate steam and chilled water capacity of 1,319 net MWt and electric generation capacity of 123 net MW. These thermal infrastructure assets provide steam, hot water and/or chilled water, and in some instances electricity, to commercial businesses, universities, hospitals and governmental units in multiple locations, principally through long-term contracts or pursuant to rates regulated by state utility commissions.

Significant Events During the Year Ended December 31, 2016

• During the fourth quarter of 2016, the Company recorded asset impairment losses of $117 million, $60 million, and $6 million for Elbow Creek, Goat Wind and Forward, respectively. For further discussion, refer to Management’s discussion of the results of operations for the years ended December 31, 2016 and 2015 andCritical Accounting Policies in this Item 7 below, as well as Item 15 — Note 9, Asset Impairments, to the Consolidated Financial Statements.

• 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 notes at a 4.80% fixed rate. In the first quarter of 2017, NRG Energy Center Minneapolis LLC expects to amend its existing note purchase and private shelf agreement to permit the issuance of $10 million of notes, which if issued, will be utilized in addition to the existing, authorized $70 million of notes to make payments with respect to the EPC agreement discussed below.

• Additionally, 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 quarter of 2018. On January 5, 2017, the parties amended the EPC Agreement, based on a customer change order, to increase the capacity of the district energy system from 73 MWt to 80 MWt, which also increased the payment from $79 million to $87 million.

• On September 1, 2016, as discussed in Item 15 — Note 3, Business Acquisitions, to the Consolidated Financial Statements, the Company acquired the remaining 51.05% interest of CVSR Holdco LLC from NRG for total cash consideration of $78.5 million. 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. 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.

• 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. A portion of the proceeds of the 2026 Senior Notes were used to repay the Company's revolving credit facility. For further discussion, refer to Item 15 — Note 10, Long-term Debt, to the Consolidated Financial Statements.

• On August 9, 2016, NRG Yield, Inc. established a $150,000,000 at-the-market equity offering program, or ATM Program, as described in Sources of Liquidity in this Item 7 below. As of December 31, 2016, no shares were issued under the ATM Program.

• On July 15, 2016, CVSR Holdco, issued $200 million of senior secured notes that bear interest at 4.68% and mature on March 31, 2037.  The proceeds were utilized, along with $28 million of cash on hand, to reduce borrowings under the

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Company’s revolving credit facility. For further discussion, refer to Item 15 — Note 10, Long-term Debt, to the Consolidated Financial Statements.

Environmental Matters and Regulatory Matters

Details of environmental matters and regulatory matters are presented in Item 1 — Business, Regulatory Matters and Item 1A— Risk Factors. Details of some of this information relate to costs that may impact the Company's financial results.

Trends Affecting Results of Operations and Future Business Performance

Wind and Solar Resource Availability

The availability of the wind and solar resources affects the financial performance of the wind and solar facilities, which may impact the Company’s overall financial performance. Due to the variable nature of the wind and solar resources, the Company cannot predict the availability of the wind and solar resources and the potential variances from expected performance levels from quarter to quarter. To the extent the wind and solar resources are not available at expected levels, it could have a negative impact on the Company’s financial performance for such periods.

CapitalMarket Conditions

The capital markets in general are often subject to volatility that is unrelated to the operating performance of particular companies. The Company’s growth strategy depends on its ability to identify and acquire additional conventional and renewable facilities from NRG and unaffiliated third parties, which will require access to debt and equity financing to complete such acquisitions or replenish capital for future acquisitions. Any broad market fluctuations may affect the Company’s ability to access such capital through debt or equity financings. The Company believes that improved capital market conditions may allow it to access capital in 2017.

Operational Matters

Walnut Creek Forced Outage

In July and August 2016, Walnut Creek experienced two unrelated outages causing damage to a circuit breaker and a compressor resulting in forced outages on Units 2 and 4, respectively.  The Company has undertaken a root cause analysis and is reviewing what is covered by insurance.  Unit 2 returned to service on August 10, 2016 and Unit 4 returned to service on September 15, 2016.

El Segundo Forced Outage

In January 2017, the El Segundo Energy Center began a forced outage on Units 5 and 6 due to increasing vibrations on successive operations at Unit 5. In consultation with the Company’s operations and maintenance service provider, a subsidiary of NRG Energy Inc., the Company elected to replace the rotor on Unit 5. Both Unit 5 and 6 returned to service on February 24, 2017. The Company is reviewing the warranty coverage with the original equipment manufacturer as well as available insurance coverage.

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Consolidated Results of Operations

2016 compared to 2015

The following table provides selected financial information:

	Year ended December 31,
(In millions)	2016			2015			Change
Operating Revenues
Energy and capacity revenues	$	1,089		$	1,009		$	80
Contract amortization	(68		)	(54		)	(14		)
Mark-to-market economic hedging activities	—			(2		)	2
Total operating revenues	1,021			953			68
Operating Costs and Expenses
Cost of fuels	61			71			(10		)
Emissions credit amortization	6			—			6
Operations and maintenance	174			178			(4		)
Other costs of operations	65			72			(7		)
Depreciation and amortization	297			297			—
Impairment losses	183			—			183
General and administrative	16			12			4
Acquisition-related transaction and integration costs	1			3			(2		)
Total operating costs and expenses	803			633			170
Operating Income	218			320			(102		)
Other Income (Expense)
Equity in earnings of unconsolidated affiliates	60			31			29
Other income, net	3			3			—
Loss on debt extinguishment	—			(9		)	9
Interest expense	(280		)	(263		)	(17		)
Total other expense, net	(217		)	(238		)	21
Income Before Income Taxes	1			82			(81		)
Income tax (benefit) expense	(1		)	12			(13		)
Net Income	2			70			(68		)
Less: Pre-acquisition net income (loss) of Drop Down Assets	27			(5		)	32
Net (Loss) Income Excluding Pre-acquisition Net Income of Drop Down Assets	(25		)	75			(100		)
Less: Net (loss) income attributable to noncontrolling interests	(82		)	42			(124		)
Net Income Attributable to NRG Yield, Inc.	$	57		$	33		$	24

	Year ended December 31,
Business metrics:	2016	2015
Renewables MWh generated/sold (in thousands) (a)	7,236	6,412
Conventional MWh generated (in thousands) (a)(b)	1,697	2,487
Thermal MWt sold (in thousands)	1,966	1,946
Thermal MWh sold (in thousands) (c)	71	297

^(a) Volumes do not include the MWh generated/sold by the Company's equity method investments.

^(b) Volumes generated are not sold as the Conventional facilities sell capacity rather than energy.

^(c) MWh sold do not include 204 MWh generated by NRG Dover, a subsidiary of the Company, under the PPA with NRG Power Marketing during the year ended December 31, 2016, as further described in Item 15 — Note 15, Related Party Transactions, to the Consolidated Financial Statements.

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Management’s discussion of the results of operations for the years ended December 31, 2016 and 2015

Gross Margin

The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, contract and emission credit amortization and mark-to-market for economic hedging activities.

Economic Gross Margin

In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.  Economic gross margin should be viewed as a supplement to and not a substitute for the Company' presentation of gross margin, which is the most directly comparable GAAP measure.  Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as energy and capacity revenue less cost of fuels. Economic gross margin excludes the following components from GAAP gross margin: contract amortization, mark-to-market results, emissions credit amortization and (losses) gains on economic hedging activities. Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled.

The below tables present the composition of gross margin, as well as the reconciliation to economic gross margin for the years ended December 31, 2016 and 2015:

	Conventional			Renewables			Thermal			Total
(In millions)
Year ended December 31, 2016
Energy and capacity revenues	$	338		$	579		$	172		$	1,089
Cost of fuels	(1		)	—			(60		)	(61		)
Contract amortization	(5		)	(61		)	(2		)	(68		)
Emissions credit amortization	(6		)	—			—			(6		)
Gross margin	326			518			110			954
Contract amortization	5			61			2			68
Emissions credit amortization	6			—			—			6
Economic gross margin	$	337		$	579		$	112		$	1,028
Year ended December 31, 2015
Energy and capacity revenues	$	341		$	492		$	176		$	1,009
Cost of fuels	(1		)	(1		)	(69		)	(71		)
Contract amortization	(5		)	(47		)	(2		)	(54		)
Mark-to-market for economic hedging activities	—			(2		)	—			(2		)
Gross margin	335			442			105			882
Contract amortization	5			47			2			54
Mark-to-market for economic hedging activities	—			2			—			2
Economic gross margin	$	340		$	491		$	107		$	938

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Gross margin increased by $72 million and economic gross margin increased by $90 million during the year ended December 31, 2016, compared to the same period in 2015, primarily due to:

(In millions)
Renewables:
26% increase in volume generated at the Alta wind projects, as well as a 7% increase in generation at other Wind projects. Additionally, there was an increase of $4 million in economic gross margin due to the acquisition of Spring Canyon in May 2015	$	61
Increase in average price per MWh due to higher pricing in the Alta X and XI PPAs which were effective in January 2016, compared with merchant prices in 2015	27
Thermal:
Higher sales volume in 2016 as a result of milder weather in 2015, as well as the completion of a project for a new customer in the second half of the year	5
Conventional:
Lower revenues at Walnut Creek as a result of forced outages in 2016, partially offset by higher revenues at El Segundo in 2016 as a result of forced outages in 2015	(3		)
Increase in economic gross margin	$	90
Higher contract amortization primarily for the Alta X and XI PPAs, which began in January 2016	(14		)
Emissions credit amortization of NOx allowances at Walnut Creek and El Segundo in compliance with amendments to the Regional Clean Air Incentives Market program	(6		)
Unrealized losses on forward contracts prior to the start of the PPA for Elbow Creek which began October 2015	2
Increase in gross margin	$	72

Operations and Maintenance Expense

	Conventional		Renewables		Thermal		Total
(In millions)
Year ended December 31, 2016	$	32	$	94	$	48	$	174
Year ended December 31, 2015	30		97		51		178

Operations and maintenance expense decreased by $4 million during the year ended December 31, 2016, compared to the same period in 2015, due to:

	(In millions)
Increase in Conventional segment primarily due to Walnut Creek forced outages in 2016, compared to the forced outages at El Segundo in 2015	$	2
Decrease in Renewables segment primarily due to insurance proceeds received at Wildorado in 2016 in connection with a 2014 wind outage claim	(3		)
Decrease in Thermal segment primarily due to acceleration of maintenance work on thermal facilities into 2015	(3		)
	$	(4	)

Other Costs of Operations

Other costs of operations decreased by $7 million during the year ended December 31, 2016, compared to the same period in 2015, primarily due to lower assessments for property taxes at Alta X and XI and NRG Wind TE Holdco.

General and Administrative Expenses

General and administrative expenses increased by $4 million for the year ended December 31, 2016 compared to the same period in 2015, primarily due to new executive compensation in 2016, and an increase in base management fee for the Management Services Agreement with NRG in connection with the acquisition of the Drop Down Assets.

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Impairment Losses

For the year ended December 31, 2016, the Company recorded impairment losses of $183 million, due to the impairments of property, plant and equipment for Elbow Creek, Goat Wind, and Forward, as further described in Item 15 — Note 9, Asset Impairments, to the Consolidated Financial Statements, as well as in Critical Accounting Policies and Estimates in this Item 7 below. Because the projects were acquired from NRG and related to interests under common control by NRG, the property, plant and equipment for these assets was recorded at historical cost of $298 million rather than estimated fair value of $132 million at the acquisition date. The three projects were acquired as part of the November 2015 Drop Down Assets.  As discussed in Item 15 — Note 3, Business Acquisitions, the historical cost for November 2015 Drop Down Assets was $369 million for the net assets, which was higher than the fair value paid of $207 million.  The difference between the historical cost of net assets and the fair value paid for the November 2015 Drop Down Assets was recorded to noncontrolling interest on the Company’s consolidated balance sheet.

Loss on Debt Extinguishment

A loss on debt extinguishment of $9 million was recorded for the year ended December 31, 2015, driven by the refinancing of the El Segundo credit facility and the termination of the interest rate swaps for Alta Wind X and XI in connection with the sale of an economic interest in Alta TE Holdco to a financial institution, as further described in Item 15 —Note 5, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Consolidated Financial Statements.

Equity in Earnings of Unconsolidated Affiliates

Equity in earnings of unconsolidated affiliates increased by $29 million during the year ended December 31, 2016, compared to the same period in 2015, primarily due to an increase in equity earnings from the Utah Solar Portfolio, which reflects the allocation of earnings using the hypothetical liquidation at book value (HLBV), an increase in equity earnings from Desert Sunlight, which was acquired in June 2015, and increases from DGPV Holdco 1 and RPV Holdco, partially offset by losses from Elkhorn Ridge.

Interest Expense

Interest expense increased by $17 million during the year ended December 31, 2016 compared to the same period in 2015 due to:

	(In millions)
Amortization of the fair value of interest rate swaps primarily acquired with the January 2015 Drop Down Assets and November 2015 Drop Down Assets	$	10
Issuance of the 2020 Convertible Notes in the second quarter of 2015 and amortization of the related discount and debt issuance costs	8
Issuance of 2026 Senior Notes in August 2016	7
Utah Solar Portfolio debt assumed in connection with March 2017 Drop Down Assets	6
Issuance of 2037 CVSR Holdco Notes in July 2016	4
Higher revolving credit facility borrowings in 2016	2
Repricing of project-level financing arrangements and lower principal balances	(20		)
	$	17

Income Tax Expense

For the year ended December 31, 2016, the Company recorded an income tax benefit of $1 million on pretax income of $1 million. For the same period in 2015, the Company recorded income tax expense of $12 million on pretax income of $82 million. 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 NRG's interest in NRG Yield LLC and PTCs and ITCs generated from certain wind and solar assets, respectively.

Income Attributable to Noncontrolling Interests

For the year ended December 31, 2016, the Company had income of $29 million attributable to NRG's interest in the Company and a loss of $111 million attributable to noncontrolling interests with respect to its tax equity financing arrangements and the application of the HLBV method, which was primarily related to the impairment losses described above.

7

For the year ended December 31, 2015, the Company had income of $56 million attributable to NRG's interest in the Company and a loss of $14 million attributable to noncontrolling interests with respect to its tax equity financing arrangements and the application of the HLBV method.

8

Consolidated Results of Operations

2015 compared to 2014

The following table provides selected financial information:

	Year ended December 31,
(In millions)	2015			2014			Change
Operating Revenues
Energy and capacity revenues	$	1,009		$	855		$	154
Contract amortization	(54		)	(29		)	(25		)
Mark-to-market economic hedging activities	(2		)	2			(4		)
Total operating revenues	953			828			125
Operating Costs and Expenses
Cost of fuels	71			89			(18		)
Operations and maintenance	178			140			38
Other costs of operations	72			48			24
Depreciation and amortization	297			233			64
General and administrative — affiliate	12			8			4
Acquisition-related transaction and integration costs	3			4			(1		)
Total operating costs and expenses	633			522			111
Operating Income	320			306			14
Other Income (Expense)
Equity in earnings of unconsolidated affiliates	31			22			9
Other income, net	3			6			(3		)
Loss on debt extinguishment	(9		)	(1		)	(8		)
Interest expense	(263		)	(216		)	(47		)
Total other expense, net	(238		)	(189		)	(49		)
Income Before Income Taxes	82			117			(35		)
Income tax expense	12			4			8
Net Income	70			113			(43		)
Less: Pre-acquisition net (loss) income of Drop Down Assets	(5		)	49			(54		)
Net Income Excluding Pre-acquisition Net (Loss) Income of Drop Down Assets	75			64			11
Less: Net income attributable to noncontrolling interests	42			48			(6		)
Net Income Attributable to NRG Yield, Inc.	$	33		$	16		$	17

	Year ended December 31,
Business metrics:	2015	2014
Renewables MWh generated/sold (in thousands) (a)	6,412	4,659
Conventional MWh generated (in thousands) (a)(b)	2,487	2,130
Thermal MWt sold (in thousands)	1,946	2,060
Thermal MWh sold (in thousands)	297	205

^(a) Volumes do not include the MWh generated/sold by the Company's equity method investments.

^(b) Volumes generated are not sold as the Conventional facilities sell capacity rather than energy.

9

Management’s discussion of the results of operations for the years ended December 31, 2015 and 2014

As described in Item 15 — Note 3, Business Acquisitions, to the Consolidated Financial Statements, the Company completed the following acquisitions from NRG during the year ended December 31, 2015:

• On November 3, 2015, the Company acquired 75% of the Class B interests of NRG Wind TE Holdco, or the November 2015 Drop Down Assets, which owns a portfolio of 12 wind facilities totaling 814 net MW, from NRG for total cash consideration of $209 million. In February 2016, NRG made a final working capital payment of $2 million, reducing total cash consideration to $207 million.

• On January 2, 2015, the Company acquired the Laredo Ridge, Tapestry, and Walnut Creek projects, or the January 2015 Drop Down Assets, for total cash consideration of $489 million, plus assumed project-level debt of $737 million.

The January 2015 Drop Down Assets and the November 2015 Drop Down Assets (other than Elbow Creek) were originally acquired by NRG from EME on April 1, 2014, and are collectively referred to as "EME Assets" throughout this discussion. The Company prepared its consolidated financial statements for the periods ending December 31, 2015 and 2014 to reflect the acquisitions as if they had taken place from the date the entities were under common control, which was April 1, 2014 for the EME Assets. Accordingly, the results presented herein reflect the Company's ownership of the EME Assets for the full year ended December 31, 2015, compared to the nine months from April 1, 2014, through December 31, 2014.

Gross Margin

The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, contract and emission credit amortization and mark-to-market for economic hedging activities.

Economic Gross Margin

In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.  Economic gross margin should be viewed as a supplement to and not a substitute for the Company' presentation of gross margin, which is the most directly comparable GAAP measure.  Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as energy and capacity revenue less cost of fuels. Economic gross margin excludes the following components from GAAP gross margin: contract amortization, mark-to-market results, emissions credit amortization and (losses) gains on economic hedging activities. Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled.

10

The following tables present the composition of gross margin, as well as the reconciliation to economic gross margin for the years ended December 31, 2015 and 2014:

	Conventional			Renewables			Thermal			Total
(In millions)
Year ended December 31, 2015
Energy and capacity revenues	$	341		$	492		$	176		$	1,009
Cost of fuels	(1		)	(1		)	(69		)	(71		)
Contract amortization	(5		)	(47		)	(2		)	(54		)
Mark-to-market for economic hedging activities	—			(2		)	—			(2		)
Gross margin	$	335		$	442		$	105		$	882
Contract amortization	5			47			2			54
Mark-to-market for economic hedging activities	—			2			—			2
Economic gross margin	$	340		$	491		$	107		$	938
Year ended December 31, 2014
Energy and capacity revenues	$	321		$	337		$	197		$	855
Cost of fuels	(2		)	(1		)	(86		)	(89		)
Contract amortization	(4		)	(23		)	(2		)	(29		)
Mark-to-market for economic hedging activities	—			2			—			2
Gross margin	$	315		$	315		$	109		$	739
Contract amortization	4			23			2			29
Mark-to-market for economic hedging activities	—			(2		)	—			(2		)
Economic gross margin	$	319		$	336		$	111		$	766

Gross margin increased by $143 million and economic gross marginincreased by $172 million during the year ended December 31, 2015, compared to the same period in 2014, driven by:

Renewables:	(In millions)
Acquisitions of the Alta Wind Portfolio in August 2014 and Spring Canyon in May 2015	$	126
Acquisition of EME Assets (Wind)	31
Other	(2		)
Conventional:
Acquisition of EME Assets (Walnut Creek)	25
Forced outage at El Segundo in the first half of 2015	(4		)
Thermal:
Milder weather conditions in 2015 compared to 2014	(4		)
Increase in economic gross margin	$	172
Higher contract amortization primarily due to the amortization of the PPAs acquired in the acquisition of the Alta Wind Portfolio in August 2014	(25		)
Unrealized losses in 2015 and unrealized gains in 2014 on forward contracts with an NRG subsidiary hedging the forecasted sale of power from Elbow Creek, prior to the start of the PPA	(4		)
Increase in gross margin	$	143

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Operations and Maintenance Expense

	Conventional		Renewables		Thermal		Total
(In millions)
Year ended December 31, 2015	$	30	$	97	$	51	$	178
Year ended December 31, 2014	30		63		47		140

Operations and maintenance expense increased by $38 million during the year ended December 31, 2015, compared to the same period in 2014, driven by:

	(In millions)
Acquisition of the Alta Wind Portfolio in August 2014 and Spring Canyon in May 2015	$	21
Acquisition of EME Assets, primarily in the Renewables segment	16
Other	1
	$	38

Other Costs of Operations

Other costs of operations increased by $24 million during the year ended December 31, 2015, compared to the same period in 2014, primarily due to an increase in property taxes resulting from the acquisitions of the Alta Wind Portfolio in August 2014, and the EME Assets in April 2014.

Depreciation and Amortization

Depreciation and amortization increased by $64 million during the year ended December 31, 2015, compared to the same period in 2014, primarily due to the acquisitions of the Alta Wind Portfolio in August 2014 and the EME Assets in April 2014.

Equity in Earnings of Unconsolidated Affiliates

Equity in earnings of unconsolidated affiliates increased by $9 million during the year ended December 31, 2015, compared to the same period in 2014, primarily due to the acquisition of Desert Sunlight in June 2015 as well as the Elkhorn Ridge and San Juan Mesa projects, acquired as part of the EME Assets.

Interest Expense

Interest expense increased by $47 million during the year ended December 31, 2015, compared to the same period in 2014, due to:

	(In millions)
Acquisition of Alta Wind Portfolio in August 2014	$	32
Issuance of the Senior Notes due 2024 in the third quarter of 2014, 2020 Convertible Notes in the second quarter of 2015, and the 2019 Convertible Notes in the first quarter of 2014	31
Acquisition of EME Assets in April 2014	3
Repricing of project-level financing arrangements and principal repayments	(9		)
Changes in the fair value of interest rate swaps	(10		)
	$	47

Income Tax Expense

For the year ended December 31, 2015, the Company recorded income tax expense of $12 million on pretax income of $82 million. For the same period in 2014, the Company recorded income tax expense of $4 million on pretax income of $117 million. For the years ended December 31, 2015 and 2014, the overall effective tax rate was different than the statutory rate of 35% primarily due to taxable earnings allocated to NRG resulting from NRG's interest in NRG Yield LLC and PTCs and ITCs generated from certain wind and solar assets, respectively.

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Income Attributable to Noncontrolling Interests

For the year ended December 31, 2015, the Company had income of $56 million attributable to NRG's interest in the Company and a loss of $14 million attributable to noncontrolling interests with respect to its tax equity financing arrangements and the application of the HLBV method. For the year ended December 31, 2014, the Company had income of $48 million attributable to NRG's interest in the Company.

Liquidity and Capital Resources

The Company's principal liquidity requirements are to meet its financial commitments, finance current operations, fund capital expenditures, including acquisitions from time to time, service debt and pay dividends. As a normal part of the Company's business, depending on market conditions, the Company will from time to time consider opportunities to repay, redeem, repurchase or refinance its indebtedness. Changes in the Company's operating plans, lower than anticipated sales, increased expenses, acquisitions or other events may cause the Company to seek additional debt or equity financing in future periods. There can be no guarantee that financing will be available on acceptable terms or at all. Debt financing, if available, could impose additional cash payment obligations and additional covenants and operating restrictions.

Liquidity Position

As of December 31, 2016 and 2015, the Company's liquidity was approximately $922 million and $375 million, respectively, comprised of cash, restricted cash, and availability under the Company's revolving credit facility. The Company's liquidity includes $165 million and $131 million of restricted cash balances as of December 31, 2016 and 2015, respectively. Restricted cash consists primarily of funds to satisfy the requirements of certain debt arrangements and funds held within the Company's projects that are restricted in their use. The Company's various financing arrangements are described in Item 15 —Note 10, Long-term Debt, to the Consolidated Financial Statements. As of December 31, 2016, there were no outstanding borrowings and the Company had $60 million of letters of credit outstanding under the revolving credit facility.

Management believes that the Company's liquidity position, cash flows from operations and availability under its revolving credit facility will be adequate to meet the Company's financial commitments; debt service obligations; growth, operating and maintenance capital expenditures; and to fund dividends to holders of the Company's Class A common stock and Class C common stock. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.

Credit Ratings

Credit rating agencies rate a firm's public debt securities. These ratings are utilized by the debt markets in evaluating a firm's credit risk. Ratings influence the price paid to issue new debt securities by indicating to the market the Company's ability to pay principal, interest and preferred dividends. Rating agencies evaluate a firm's industry, cash flow, leverage, liquidity, and hedge profile, among other factors, in their credit analysis of a firm's credit risk.

The following table summarizes the credit ratings for the Company and its Senior Notes as of December 31, 2016. The ratings outlook is stable.

	S&P	Moody's
NRG Yield, Inc.	BB	Ba2
5.375% Senior Notes, due 2024	BB	Ba2
5.000% Senior Notes, due 2026	BB	Ba2

Sources of Liquidity

The Company's principal sources of liquidity include cash on hand, cash generated from operations, borrowings under new and existing financing arrangements and the issuance of additional equity and debt securities as appropriate given market conditions. As described in Item 15 —Note 10, Long-term Debt, to the Consolidated Financial Statements, and above in Significant Events During the Year Ended December 31, 2016, the Company's financing arrangements consist of the revolving credit facility, the 2019 Convertible Notes, the 2020 Convertible Notes, the 2024 Senior Notes, the 2026 Senior Notes, the ATM Program and project-level financings for its various assets.

At-the-Market Equity Offering Program

On August 9, 2016, NRG Yield, Inc. entered into an equity distribution agreement, or EDA, 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

13

of the EDA, 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, as NRG Yield, Inc.’s sales agents for the offer and sale of the shares, up to an aggregate sales price of $150,000,000 through an at-the-market equity offering program, or 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, 2016, no shares were issued under the ATM Program.

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 notes. In the first quarter of 2017, NRG Energy Center Minneapolis LLC anticipates amending the shelf facility to allow for the issuance of an additional $10 million of notes, increasing the total principal amount of notes available for issuance under the shelf facility to $80 million. The Series D Notes are, and the additional notes, if issued, 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, who in turn distributed the proceeds to Yield Operating LLC to be utilized for general corporate purposes, including potential acquisitions.

Uses of Liquidity

The Company's requirements for liquidity and capital resources, other than for operating its facilities, are categorized as: (i) debt service obligations, as described more fully in Item 15 —Note 10, Long-term Debt, to the Consolidated Financial Statements; (ii) capital expenditures; (iii) acquisitions and investments; and (iv) cash dividends to investors.

14

Debt Service Obligations

Principal payments on debt as of December 31, 2016 are due in the following periods:

Description	2017		2018		2019		2020		2021		There-after		Total
	(In millions)
NRG Yield, Inc. Convertible Notes, due 2019	$	—	$	—	$	345	$	—	$	—	$	—	$	345
NRG Yield, Inc. Convertible Notes, due 2020	—		—		—		288		—		—		288
NRG Yield Operating LLC Senior Notes, due 2024	—		—		—		—		—		500		500
NRG Yield Operating LLC Senior Notes, due 2026	—		—		—		—		—		350		350
Total Corporate-level debt	—		—		345		288		—		850		1,483
Project-level debt:
Alta Wind I, lease financing arrangement, due 2034	11		11		12		12		12		184		242
Alta Wind II, lease financing arrangement, due 2034	8		8		8		9		9		149		191
Alta Wind III, lease financing arrangement, due 2034	8		8		8		9		9		156		198
Alta Wind IV, lease financing arrangement, due 2034	5		5		5		6		6		101		128
Alta Wind V, lease financing arrangement, due 2035	8		8		8		9		9		164		206
Alta Realty Investments, due 2031	1		2		2		1		2		23		31
Alta Wind Asset Management, due 2031	1		1		1		1		1		13		18
Alpine, due 2022	9		8		8		8		8		104		145
Avra Valley, due 2031	3		3		3		4		3		41		57
Blythe, due 2028	2		1		2		1		1		12		19
Borrego, due 2025 and 2038	3		3		3		3		3		54		69
CVSR, due 2037	25		26		24		21		23		652		771
CVSR Holdco Notes, due 2037	5		6		6		6		7		169		199
El Segundo Energy Center, due 2023	43		48		49		53		57		193		443
Energy Center Minneapolis, due 2017 and 2025	13		7		11		11		11		43		96
Energy Center Minneapolis Series D Notes, due 2031	—		—		—		—		—		125		125
Kansas South, due 2031	2		2		2		2		2		20		30
Laredo Ridge, due 2028	5		5		5		6		6		73		100
Marsh Landing, due 2017 and 2023	52		55		57		60		62		84		370
PFMG and related subsidiaries financing agreement, due 2030	1		1		2		1		1		21		27
Roadrunner, due 2031	3		3		3		2		3		23		37
South Trent Wind, due 2020	4		4		4		45		—		—		57
TA High Desert, due 2020 and 2032	3		3		3		3		3		34		49
Tapestry, due 2021	10		11		11		11		129		—		172
Utah Solar Portfolio, due 2022	9		12		14		13		13		226		287
Viento, due 2023	13		16		18		16		16		99		178
Walnut Creek, due 2023	43		45		47		49		52		74		310
WCEP Holdings, due 2023	1		2		4		4		4		31		46
Total project-level debt	291		304		320		366		452		2,868		4,601
Total debt	$	291	$	304	$	665	$	654	$	452	$	3,718	$	6,084

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Capital Expenditures

The Company's capital spending program is mainly focused on maintenance capital expenditures, consisting of costs to maintain the assets currently operating, such as costs to replace or refurbish assets during routine maintenance, and growth capital expenditures consisting of costs to construct new assets, costs to complete the construction of assets where construction is in process, and capital expenditures related to acquiring additional thermal customers. The Company develops annual capital spending plans based on projected requirements for maintenance and growth capital. For the years ended December 31, 2016, 2015, and 2014, the Company used approximately $20 million, $29 million, and $60 million, respectively, to fund capital expenditures, includingmaintenance capital expenditures of $16 million,$20 million, and $8 million, respectively.Growth capital expenditures in 2016 were in primarily in the Thermal segment and relate to servicing new customers in district energy centers. Growth capital expenditures in 2015 and 2014 primarily related to the construction of the Company’s solar generating assets, Marsh Landing and El Segundo.

Acquisitions and Investments

The Company intends to acquire generation and thermal infrastructure assets developed and constructed by NRG in the future, as well as generation and thermal infrastructure assets from third parties where the Company believes its knowledge of the market and operating expertise provides a competitive advantage, and to utilize such acquisitions as a means to grow its CAFD. 

On March 27, 2017, as discussed in Item 15 — Note 3, Business Acquisitions, 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 NRG ROFO assets, representing ownership of approximately 46 net MW of capacity, and (ii) NRG's interests in seven utility-scale solar farms located in Utah, which are part of a tax equity structure with Dominion Solar Projects III, Inc., or Dominion, from which the Company would receive 50% of cash to be distributed. The Company paid cash consideration of $130 million, plus $1 million of working capital and assumed non-recourse project debt. The purchase price for the acquisition was funded with cash on hand.

On September 1, 2016, as discussed in Item 15 — Note 3, Business Acquisitions, to the Consolidated Financial Statements, the Company acquired the remaining 51.05% interest of CVSR Holdco LLC from NRG for total cash consideration of $78.5 million. 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. In connection with the retrospective adjustment of prior periods, the Company now consolidates CVSR and 100% of debt, or $771 million of CVSR project level debt and $200 million of notes issued under the CVSR Holdco Financing Agreement as of September 1, 2016.

During the year ended December 31, 2016, the Company invested $80 million in distributed and residential solar investment partnerships with NRG, as further described in Item 15 — Note 5, Investments Accounting for by the Equity Method and Variable Interest Entities. 

Cash Dividends to Investors

The Company intends to use the amount of cash that it receives from its distributions from NRG Yield LLC to pay quarterly dividends to the holders of its Class A common stock and Class C common stock. NRG Yield LLC intends to distribute to its unit holders in the form of a quarterly distribution all of the CAFD that is generated each quarter less reserves for the prudent conduct of the business, including among others, maintenance capital expenditures to maintain the operating capacity of the assets. CAFD is defined as net income before interest expense, income taxes, depreciation and amortization, plus cash distributions from unconsolidated affiliates, cash receipts from notes receivable, less cash distributions to noncontrolling interests, maintenance capital expenditures, pro-rata EBITDA from unconsolidated affiliates, cash interest paid, income taxes paid, principal amortization of indebtedness and changes in prepaid and accrued capacity payments. Dividends on the Class A common stock 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.

16

The following table lists the dividends paid on the Company's Class A common stock and Class C common stock during the year ended December 31, 2016:

	Fourth Quarter 2016		Third Quarter 2016		Second Quarter 2016		First Quarter 2016
Dividends per Class A share	$	0.25	$	0.24	$	0.23	$	0.225
Dividends per Class C share	$	0.25	$	0.24	$	0.23	$	0.225

On February 15, 2017, the Company declared a quarterly dividend on its Class A and Class C common stock of $0.26 per share payable on March 15, 2017, to stockholders of record as of March 1, 2017.

17

Cash Flow Discussion

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

The following table reflects the changes in cash flows for the year ended December 31, 2016 compared to 2015:

Year ended December 31,	2016			2015			Change
(In millions)
Net cash provided by operating activities	$	569		$	422		$	147
Net cash used in investing activities	(165		)	(1,108		)	943
Net cash (used in) provided by financing activities	(193		)	368			(561		)

Net Cash Provided By Operating Activities

Changes to net cash provided by operating activities were driven by:	(In millions)
Increase in operating income adjusted for non-cash items driven by higher revenues mainly in the Renewables segment in 2016 compared to 2015	$	125
Changes in working capital driven primarily by the timing of accounts receivable collections in 2015 compared to 2016	24
Lower distributions from unconsolidated affiliates	(2		)
	$	147

Net Cash Used In Investing Activities

Changes to net cash used in investing activities were driven by:	(In millions)
Higher payments for the acquisition of the January 2015 and November 2015 Drop Down Assets in 2015 compared to the payments made for the CVSR Drop Down in 2016	$	621
Higher net investments in unconsolidated affiliates in 2015, primarily due to investment in Desert Sunlight	305
Payments to acquire businesses, net of cash acquired, in 2015	37
Decrease in capital expenditures primarily due to the completion of a project in the Thermal segment in 2015, as well as lower maintenance capital expenditures in 2016	9
Receipt of insurance proceeds in 2016 in the Renewables segment	4
Higher restricted cash balances in 2016, primarily driven by higher revenues in the Renewables segment in the third and fourth quarters of 2016, which in turn provided more cash available for distribution by certain projects	(33		)
	$	943

Net Cash (Used In) Provided By Financing Activities

Changes in net cash (used in) provided by financing activities were driven by:	(In millions)
Proceeds from sale of an economic interest in Alta TE Holdco in 2015, as further described in Item 15 — Note 5, Investments Accounted for by the Equity Method and Variable Interest Entities, compared to lower net contributions from tax equity investors in 2016	$	(117	)
Higher payments of distributions to NRG related to NRG's 25% ownership of NRG Wind TE Holdco and distributions made to NRG from Drop Down Assets prior to the acquisition dates	(104		)
Proceeds from Class C equity offering on June 29, 2015	(599		)
Net repayments of $306 million under the revolving credit facility in 2016 compared to the net borrowings of $306 million in 2015	(612		)
Issuance of the Series D Notes in October 2016, 2026 Senior Notes in August 2016, CVSR Holdco Notes, due 2037 in July 2016, and Utah Solar Portfolio debt, due 2022 in December 2016, partially offset by lower debt principal payments throughout 2016, compared to 2015	907
Increase in dividends paid to common stockholders, as declared dividends increased 16.3% from 2015 to 2016	(34		)
Higher debt issuance costs paid in 2016	(2		)
	$	(561	)

18

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

The following table reflects the changes in cash flows for the year ended December 31, 2015 compared to 2014:

Year ended December 31,	2015			2014			Change
(In millions)
Net cash provided by operating activities	$	422		$	362		$	60
Net cash used in investing activities	(1,108		)	(741		)	(367		)
Net cash provided by financing activities	368			749			(381		)

Net Cash Provided By Operating Activities

Changes to net cash provided by operating activities were driven by:	(In millions)
Increase in operating income adjusted for non-cash items	$	19
Higher distributions from unconsolidated affiliates for the year ending December 31, 2015 compared to the same period in 2014	39
Changes in working capital primarily driven by timing of capacity payments	2
	$	60

Net Cash Used In Investing Activities

Changes to net cash used in investing activities were driven by:	(In millions)
Payments to acquire businesses, net of cash acquired (primarily the Alta acquisition in 2014)	$	864
Higher payments made to acquire Drop Down Assets in 2015 compared to payments made in 2014	(387		)
Decrease in capital expenditures due to several projects being placed in service in early 2014	31
Changes in restricted cash primarily due to cash transfers in connection with higher debt principal payments in 2015	(26		)
Proceeds from renewable energy grants in 2014	(422		)
Increase in net investments in unconsolidated affiliates in 2015 compared to 2014, primarily due to the investment in Desert Sunlight made in 2015	(362		)
Receipt of indemnity from supplier for CVSR	(57		)
Other	(8		)
	$	(367	)

Net Cash Provided By Financing Activities

Changes in net cash provided by financing activities were driven by:	(In millions)
Lower payments of dividends and returns of capital to NRG, partially offset by contributions from NRG in 2014	$	255
Lower contributions from tax equity investors in 2015	(68		)
Lower net proceeds from Class C equity offering on June 29, 2015 compared to the net proceeds from Class A equity offering on July 29, 2014	(31		)
Increase in dividends paid to common stockholders	(38		)
Lower net proceeds from the revolving credit facility in 2015 compared to 2014	(194		)
A decrease in proceeds from long-term debt, as well as an increase in debt payments, in 2015 compared to 2014	(328		)
Decrease in debt issuance costs due to lower borrowing in 2015	23
	$	(381	)

19

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740

As of December 31, 2016, the Company has a cumulative federal NOL carry forward balance of $648 million for financial statement purposes, which will begin expiring in 2033, and does not anticipate any federal income tax payments for 2017. As a result of the Company's tax position, and based on current forecasts, the Company does not anticipate significant income tax payments for state and local jurisdictions in 2017. Based on the Company's current and expected NOL balances generated primarily by accelerated tax depreciation of its property, plant and equipment, the Company does not expect to pay significant federal income tax for a period of approximately ten years.

The Company has no uncertain tax benefits.

Off-Balance Sheet Arrangements

Obligations under Certain Guarantee Contracts

The Company may enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties.

Retained or Contingent Interests

The Company does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of December 31, 2016, the Company has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method. NRG DGPV Holdco 1 LLC, NRG DGPV Holdco 2 LLC, NRG RPV Holdco 1 LLC, GenConn, and the Utah Solar Portfolio are variable interest entities for which the Company is not the primary beneficiary.

The Company's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $589 million as of December 31, 2016. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to the Company. See also Item 15 — Note 5, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Consolidated Financial Statements.

Contractual Obligations and Commercial Commitments

The Company has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs. The following table summarizes the Company's contractual obligations. See Item 15 — Note 10, Long-term Debtand Note 16, Commitments and Contingencies, to the Consolidated Financial Statements for additional discussion.

	By Remaining Maturity at December 31,
	2016										2015
Contractual Cash Obligations	Under 1 Year		1-3 Years		3-5 Years		Over 5 Years		Total		Total
	(In millions)
Long-term debt (including estimated interest)	$	578	$	1,491	$	1,528	$	4,655	$	8,252	$	7,016
Operating leases	9		19		18		152		198		219
Fuel purchase and transportation obligations	13		7		6		19		45		48
Other liabilities (a)	14		22		21		72		129		105
Total	$	614	$	1,539	$	1,573	$	4,898	$	8,624	$	7,388

^(a) Includes water right agreements, service and maintenance agreements, and LTSA commitments.

20

Fair Value of Derivative Instruments

The Company may enter into fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at certain generation facilities. In addition, in order to mitigate interest rate risk associated with the issuance of variable rate debt, the Company enters into interest rate swap agreements.

The tables below disclose the activities of non-exchange traded contracts accounted for at fair value in accordance with ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at December 31, 2016, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at December 31, 2016. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Item 15 —Note 6, Fair Value of Financial Instruments, to the Consolidated Financial Statements.

Derivative Activity (Losses)/Gains	(In millions)
Fair value of contracts as of December 31, 2015	$	(100	)
Contracts realized or otherwise settled during the period	37
Changes in fair value	(10		)
Fair value of contracts as of December 31, 2016	$	(73	)

	Fair value of contracts as of December 31, 2016
	Maturity
Fair Value Hierarchy Losses	1 Year or Less			Greater Than 1 Year to 3 Years			Greater Than 3 Years to 5 Years			Greater Than 5 Years			Total Fair Value
	(In millions)
Level 1	$	1		$	—		$	—		$	—		$	1
Level 2	(31		)	(30		)	(10		)	(3		)	(74		)
Total	$	(30	)	$	(30	)	$	(10	)	$	(3	)	$	(73	)

The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. As discussed below in Quantitative and Qualitative Disclosures about Market Risk -Commodity Price Risk, NRG, on behalf of the Company, measures the sensitivity of the portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the net open position.

Critical Accounting Policies and Estimates

The Company's discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.

On an ongoing basis, the Company evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. Actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.

The Company's significant accounting policies are summarized in Item 15 — Note 2, Summary of Significant Accounting Policies, to the Consolidated Financial Statements. The Company identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain. The Company's critical accounting policies include income taxes and valuation allowance for deferred tax assets, impairment of long lived assets and other intangible assets and acquisition accounting.

21

Accounting Policy	Judgments/Uncertainties Affecting Application
Income Taxes and Valuation Allowance for Deferred Tax Assets	Ability to withstand legal challenges of tax authority decisions or appeals
	Anticipated future decisions of tax authorities
	Application of tax statutes and regulations to transactions
	Ability to utilize tax benefits through carry backs to prior periods and carry forwards to future periods
Impairment of Long Lived Assets	Recoverability of investments through future operations
	Regulatory and political environments and requirements
	Estimated useful lives of assets
	Operational limitations and environmental obligations
	Estimates of future cash flows
	Estimates of fair value
	Judgment about triggering events
Acquisition Accounting	Identification of intangible assets acquired
	Inputs for fair value of assets and liabilities acquired
	Application of various methodologies

Income Taxes and Valuation Allowance for Deferred Tax Assets

As of December 31, 2016, the Company had a valuation allowance of $16 million related to a deferred tax asset expected to result in a capital loss for which no existing capital gains or tax planning strategies to utilize the asset in the future are available. Other than for this expected capital loss, 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 realization of deferred tax assets is primarily dependent upon earnings in federal and various state and local jurisdictions.

The Company's operating entities, as former subsidiaries of NRG, continue to be under audit for multiple years by taxing authorities in other jurisdictions. Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws. The project-level entities, as former subsidiaries of NRG, are subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and local jurisdictions. The Company is subject to U.S. federal, state and local income tax examinations for all years beginning in 2013.

Evaluation of Assets for Impairment and Other-Than-Temporary Decline in Value

In accordance with ASC 360, Property, Plant, and Equipment, or ASC 360, property, plant and equipment and certain intangible assets are evaluated for impairment whenever indicators of impairment exist. Examples of such indicators or events are:

• Significant decrease in the market price of a long-lived asset;

• Significant adverse change in the manner an asset is being used or its physical condition;

• Adverse business climate;

• Accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset;

• Current-period loss combined with a history of losses or the projection of future losses; and

• Change in the Company's intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.

22

Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power pool prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. The fair value may be determined by factoring in the probability weighting of different courses of action available to the Company as appropriate. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. The Company uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel costs and operating costs. However, actual future market prices and project costs could vary from the assumptions used in the Company's estimates, and the impact of such variations could be material.

Annually, during the fourth quarter, the Company revises its views of power prices, including the Company's fundamental view for long-term power prices, forecasted generation and operating and capital expenditures, in connection with the preparation of its annual budget.

The Company recorded certain long-lived asset impairments in 2016, as described in Item 15 — Note 9, Asset Impairments, to the Consolidated Financial Statements, with respect to several wind projects that were acquired in connection with the acquisition of the November 2015 Drop Down Assets. Because the projects were acquired from NRG, they were recorded at historical cost rather than fair value. The historical cost of the assets was higher than its fair value at the date the interests under common control were acquired, as described in Item 15 — Note 3, Business Acquisitions, to the Consolidated Financial Statements.

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 located in Texas and the Forward project in Pennsylvania were below the carrying value (historical cost transferred under common control) of the related assets, primarily driven by 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 utilizes estimates of discounted future cash flows, which 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.

The Company is also required to evaluate its equity method investments to determine whether or not they are impaired. ASC 323, Investments - Equity Method and Joint Ventures, or ASC 323, provides the accounting requirements for these investments. The standard for determining whether an impairment must be recorded under ASC 323 is whether the value is considered to be an other-than-temporary decline in value. The evaluation and measurement of impairments under ASC 323 involves the same uncertainties as described for long-lived assets that the Company owns directly and accounts for in accordance with ASC 360. Similarly, the estimates that the Company makes with respect to its equity method investments are subjective, and the impact of variations in these estimates could be material. Additionally, if the projects in which the Company holds these investments recognize an impairment under the provisions of ASC 360, the Company would record its proportionate share of that impairment loss and would evaluate its investment for an other-than-temporary decline in value under ASC 323.

Certain of the Company’s projects have useful lives that extend well beyond the contract period and therefore, management’s view of long-term power prices in the post-contract periods may have a significant impact on the expected future cash flows for these projects.  Accordingly, if management’s view of long-term power prices in certain markets continues to decrease, it is possible that some of the Company’s other long-lived assets may be impaired.

23

Acquisition Accounting

The Company applies ASC 805, Business Combinations, when accounting for the acquisition of a business, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The Company completes the accounting for an acquisition when the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. The allocation of the purchase price may be modified up to one year from the date of the acquisition as more information is obtained about the fair value of assets acquired and liabilities assumed. Consideration is measured based on fair value of the assets transferred to the seller.

Significant judgment is required in determining the acquisition date fair value of the assets acquired and liabilities assumed, predominantly with respect to property, plant and equipment, power purchase agreements, asset retirement obligations and other contractual arrangements. Evaluations include numerous inputs including forecasted cash flows that incorporate the specific attributes of each asset including age, useful life, equipment condition and technology, as well as current replacement costs for similar assets. Other key inputs that require judgment include discount rates, comparable market transactions, estimated useful lives and probability of future transactions. The Company evaluates all available information, as well as all appropriate methodologies when determining the fair value of assets acquired and liabilities assumed in a business combination. In addition, once the appropriate fair values are determined, the Company must determine the remaining useful life for property, plant and equipment and the amortization period and method of amortization for each finite-lived intangible asset.

The Company must apply ASC 805-50, Business Combinations - Related Issues, when it acquires an interest from NRG. The assets and liabilities transferred to the Company related to interests under common control by NRG must be recorded at historical cost, with the difference between the amount paid and the historical value of the related equity recorded as a distribution to or contribution from NRG with the offset to noncontrolling interest. Economics may change in the years subsequent to NRG’s construction or acquisition of certain assets, and although the Company may acquire these assets from NRG based on a different valuation, the Company must record the assets at historical cost. These changes in economics may impact the amount that the Company pays for the assets but will not alter the carrying amount. Accordingly, significant changes in the economics related to these assets may trigger a requirement for impairment testing.

Recent Accounting Developments

See Item 15 — Note 2, Summary of Significant Accounting Policies, to the Consolidated Financial Statements for a discussion of recent accounting developments.

24

EX-99.3

Exhibit 99.3

PART IV

Item 15 — Exhibits, Financial Statement Schedules

(a)(1) Financial Statements

The following consolidated financial statements of NRG Yield, Inc. and related notes thereto, together with the reports thereon of KPMG LLP, are included herein:

Consolidated Statements of Income — Years ended December 31, 2016, 2015 and 2014

Consolidated Statements of Comprehensive Income — Years ended December 31, 2016, 2015 and 2014

Consolidated Balance Sheets — As of December 31, 2016 and 2015

Consolidated Statements of Cash Flows — Years ended December 31, 2016, 2015 and 2014

Consolidated Statements of Stockholders' Equity — Years ended December 31, 2016, 2015 and 2014

Notes to Consolidated Financial Statements

(a)(2) Financial Statement Schedules

The following schedules of NRG Yield, Inc. are filed as part of Item 15 of this report and should be read in conjunction with the Consolidated Financial Statements:

NRG Yield, Inc. Financial Statements for the years ended December 31, 2016, 2015 and 2014, are included in NRG Yield, Inc.'s Annual Report on Form 10-K pursuant to the requirements of Rule 5-04(c) of Regulation S-X

Schedule II — Valuation and Qualifying Accounts

All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted    

(a)(3) Exhibits: See Exhibit Index submitted as a separate section of this report

(b) Exhibits

See Exhibit Index submitted as a separate section of this report

(c) Not applicable

1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

NRG Yield, Inc.:

We have audited the accompanying consolidated balance sheets of NRG Yield, Inc. and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive (loss) income, stockholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2016. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule “Schedule I. Condensed Financial Information of Registrant.” These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NRG Yield, Inc. and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), NRG Yield, Inc.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2017 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

(signed) KPMG LLP

Philadelphia, PA

May 9, 2017

2

NRG YIELD, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year ended December 31,
(In millions, except per share amounts)	2016 (a)			2015 (a)			2014 (a)
Operating Revenues
Total operating revenues	$	1,021		$	953		$	828
Operating Costs and Expenses
Cost of operations	306			321			277
Depreciation and amortization	297			297			233
Impairment losses	183			—			—
General and administrative	16			12			8
Acquisition-related transaction and integration costs	1			3			4
Total operating costs and expenses	803			633			522
Operating Income	218			320			306
Other Income (Expense)
Equity in earnings of unconsolidated affiliates	60			31			22
Other income, net	3			3			6
Loss on debt extinguishment	—			(9		)	(1		)
Interest expense	(280		)	(263		)	(216		)
Total other expense, net	(217		)	(238		)	(189		)
Income Before Income Taxes	1			82			117
Income tax (benefit) expense	(1		)	12			4
Net Income	2			70			113
Less: Pre-acquisition net income (loss) of Drop Down Assets	27			(5		)	49
Net (Loss) Income Excluding Pre-acquisition Net Income (Loss) of Drop Down Assets	(25		)	75			64
Less: Net (loss) income attributable to noncontrolling interests	(82		)	42			48
Net Income Attributable to NRG Yield, Inc.	$	57		$	33		$	16
Earnings Per Share Attributable to NRG Yield, Inc. Class A and Class C Common Stockholders
Weighted average number of Class A common shares outstanding - basic and diluted	35			35			28
Weighted average number of Class C common shares outstanding - basic and diluted	63			49			28
Earnings per Weighted Average Class A and Class C Common Share - Basic and Diluted	$	0.58		$	0.40		$	0.30
Dividends Per Class A Common Share	$	0.945		$	1.015		$	1.42
Dividends Per Class C Common Share	$	0.945		$	0.625		N/A

^(a)Retrospectively adjusted as discussed in Note 1, Nature of Business.

See accompanying notes to consolidated financial statements.

3

NRG YIELD, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year ended December 31,
	2016 (a)			2015 (a)			2014 (a)
(In millions)
Net Income	$	2		$	70		$	113
Other Comprehensive Income (Loss), net of tax
Unrealized gain (loss) on derivatives, net of income tax benefit of $0, $10, and $5	13			(7		)	(60		)
Other comprehensive income (loss)	13			(7		)	(60		)
Comprehensive Income	15			63			53
Less: Pre-acquisition net income (loss) of Drop Down Assets	27			(5		)	49
Less: Comprehensive (loss) income attributable to noncontrolling interests	(68		)	53			(3		)
Comprehensive Income Attributable to NRG Yield, Inc.	$	56		$	15		$	7

^(a)Retrospectively adjusted as discussed in Note 1, Nature of Business.

See accompanying notes to consolidated financial statements.

4

NRG YIELD, INC.

CONSOLIDATED BALANCE SHEETS

	December 31, 2016 (a)			December 31, 2015 (a)
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	322		$	111
Restricted cash	165			131
Accounts receivable — trade	92			101
Inventory	39			36
Derivative instruments	2			—
Notes receivable — current	16			17
Prepayments and other current assets	20			20
Total current assets	656			416
Property, plant and equipment, net	5,460			5,878
Other Assets
Equity investments in affiliates	1,152			797
Notes receivable — non-current	14			30
Intangible assets, net	1,286			1,362
Derivative instruments	1			—
Deferred income taxes	216			170
Other non-current assets	51			136
Total other assets	2,720			2,495
Total Assets	$	8,836		$	8,789
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt	$	291		$	264
Accounts payable — trade	23			23
Accounts payable — affiliate	40			86
Derivative instruments	32			39
Accrued expenses and other current liabilities	86			77
Total current liabilities	472			489
Other Liabilities
Long-term debt	5,696			5,329
Accounts payable — affiliate	9			—
Derivative instruments	44			61
Other non-current liabilities	76			72
Total non-current liabilities	5,825			5,462
Total Liabilities	6,297			5,951
Commitments and Contingencies
Stockholders' Equity
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued	—			—
Class A, Class B, Class C and Class D common stock, $0.01 par value; 3,000,000,000 shares authorized (Class A 500,000,000, Class B 500,000,000, Class C 1,000,000,000, Class D 1,000,000,000); 182,848,000 shares issued and outstanding (Class A 34,586,250, Class B 42,738,750, Class C 62,784,250, Class D 42,738,750) at December 31, 2016 and 2015	1			1
Additional paid-in capital	1,879			1,855
(Accumulated deficit) Retained earnings	(2		)	12
Accumulated other comprehensive loss	(28		)	(27		)
Noncontrolling interest	689			997
Total Stockholders' Equity	2,539			2,838
Total Liabilities and Stockholders' Equity	$	8,836		$	8,789

^(a)Retrospectively adjusted as discussed in Note 1, Nature of Business.

See accompanying notes to consolidated financial statements.

5

NRG YIELD, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended December 31,
	2016 (a)			2015 (a)			2014 (a)
Cash Flows from Operating Activities	(In millions)
Net income	$	2		$	70		$	113
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of unconsolidated affiliates	(60		)	(31		)	(22		)
Distributions from unconsolidated affiliates	58			60			21
Depreciation, amortization and ARO accretion	300			299			235
Amortization of financing costs and debt discounts	20			16			11
Amortization of intangibles and out-of-market contracts	75			54			28
Loss on debt extinguishment	—			9			1
Change in deferred income taxes	(1		)	12			4
Impairment losses	183			—			—
Changes in derivative instruments	(15		)	(43		)	(12		)
Loss on disposal of asset components	6			3			—
Cash provided by (used in) changes in other working capital:
Changes in prepaid and accrued capacity payments	(8		)	(12		)	—
Changes in other working capital	9			(15		)	(17		)
Net Cash Provided by Operating Activities	569			422			362
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired	—			(37		)	(901		)
Acquisition of Drop Down Assets, net of cash acquired	(77		)	(698		)	(311		)
Capital expenditures	(20		)	(29		)	(60		)
Receipt of indemnity from supplier	—			—			57
(Increase) decrease in restricted cash	(34		)	(1		)	25
Cash receipts from notes receivable	17			17			14
Proceeds from renewable energy grants	—			—			422
Return of investment from unconsolidated affiliates	28			42			4
Investments in unconsolidated affiliates	(83		)	(402		)	(2		)
Other	4			—			11
Net Cash Used in Investing Activities	(165		)	(1,108		)	(741		)
Cash Flows from Financing Activities
Contributions from tax equity investors, net of distributions	5			122			190
Capital contributions from NRG	—			—			2
Distributions and return of capital to NRG prior to the acquisition of Drop Down Assets	(170		)	(76		)	(333		)
Proceeds from the issuance of common stock	—			599			630
Payments of dividends and distributions	(183		)	(139		)	(101		)
Proceeds from the revolving credit facility	60			551			500
Payments for the revolving credit facility	(366		)	(245		)	—
Proceeds from issuance of long-term debt	740			293			523
Payments of debt issuance costs	(15		)	(13		)	(36		)
Payments for long-term debt	(264		)	(724		)	(626		)
Net Cash (Used in) Provided by Financing Activities	(193		)	368			749
Net Increase (Decrease) in Cash and Cash Equivalents	211			(318		)	370
Cash and Cash Equivalents at Beginning of Period	111			429			59
Cash and Cash Equivalents at End of Period	$	322		$	111		$	429
Supplemental Disclosures
Interest paid, net of amount capitalized	$	(266	)	$	(274	)	$	(192	)
Non-cash investing and financing activities:
Additions (reductions) to fixed assets for accrued capital expenditures	3			1			(21		)
Decrease to fixed assets for accrued grants	—			—			34
Decrease to fixed assets for deferred tax asset	—			19			7
Non-cash adjustment for change in tax basis of assets	44			38			(14		)
Increase in debt due to accrued interest converted to debt	—			—			11
Non-cash return of capital and distributions to NRG, net of contributions	$	66		$	(13	)	$	1,058

^(a)Retrospectively adjusted as discussed in Note 1, Nature of Business.

See accompanying notes to consolidated financial statements.

6

NRG YIELD, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In millions)	Preferred Stock		Common Stock		Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interest			Total Stockholders' Equity
Balances at December 31, 2013 (a)	$	—	$	—	$	621		$	8		$	—		$	959		$	1,588
Members' equity - Acquired Drop Down Assets	—		—		—			—			—			105			105
Balances at December 31, 2013	$	—	$	—	$	621		$	8		$	—		$	1,064		$	1,693
Net income	—		—		—			16			—			48			64
Pre-acquisition net income of acquired Drop Down Assets	—		—		—			—			—			49			49
Unrealized loss on derivatives, net of tax	—		—		—			—			(9		)	(51		)	(60		)
Payment for June 2014 Drop Down Assets	—		—		—			—			—			(357		)	(357		)
Capital contributions from NRG, non-cash (b)	—		—		—			—			—			1,058			1,058
Distributions and returns of capital to NRG net of contributions	—		—		—			—			—			(331		)	(331		)
Capital contributions from tax equity investors	—		—		—			—			—			190			190
Proceeds from the issuance of Class A common stock	—		—		630			—			—			—			630
Non-cash adjustment for change in tax basis of property, plant and equipment	—		—		(14		)	—			—			—			(14		)
Equity portion of the 2019 Convertible Notes	—		—		23			—			—			—			23
Common stock dividends	—		—		(20		)	(21		)	—			(60		)	(101		)
Balances at December 31, 2014	$	—	$	—	$	1,240		$	3		$	(9	)	$	1,610		$	2,844
Net income	—		—		—			33			—			42			75
Pre-acquisition net loss of acquired Drop Down Assets	—		—		—			—			—			(5		)	(5		)
Unrealized loss on derivatives, net of tax	—		—		—			—			(18		)	11			(7		)
Payment for January 2015 and November 2015 Drop Down Assets	—		—		—			—			—			(698		)	(698		)
Capital contributions from tax equity investors	—		—		—			—			—			122			122
Noncontrolling interest acquired in Spring Canyon acquisition	—		—		—			—			—			74			74
Distributions and return of capital to NRG	—		—		—			—			—			(76		)	(76		)
Distributions and return of capital to NRG, net of contributions, non-cash	—		—		—			—			—			(13		)	(13		)
Stock-based compensation	—		—		1			—			—			—			1
Proceeds from the issuance of Class C Common Stock	—		1		598			—			—			—			599
Non-cash adjustment for change in tax basis of property, plant and equipment	—		—		38			—			—			—			38
Equity portion of the 2020 Convertible Notes	—		—		23			—			—			—			23
Common stock dividends	—		—		(45		)	(24		)	—			(70		)	(139		)
Balances as of December 31, 2015	$	—	1		$	1,855		$	12		$	(27	)	$	997		$	2,838
Net income (loss)	—		—		—			57			—			(82		)	(25		)
Pre-acquisition net income of acquired Drop Down Assets	—		—		—			—			—			27			27
Unrealized (loss) gain on derivatives, net of tax	—		—		—			—			(1		)	14			13
Payment for CVSR Drop Down Asset	—		—		—			—			—			(77		)	(77		)
Capital contributions from tax equity investors, net of distributions	—		—		—			—			—			5			5
Distributions and return of capital to NRG	—		—		—			—			—			(180		)	(180		)
Contributions from NRG, net of distributions and return of capital, non-cash	—		—		—			—			—			66			66
Stock-based compensation	—		—		1			—			—			—			1
Non-cash adjustment for change in tax basis of assets	—		—		44			—			—			—			44
Common stock dividends	—		—		(21		)	(71		)	—			(81		)	(173		)
Balances as of December 31, 2016	$	—	1		$	1,879		$	(2	)	$	(28	)	$	689		$	2,539

^(a) As previously reported in the Company's audited financial statements for the year ended December 31, 2016, included in the Company's 2016 Form 10-K.

^(b) Capital contributions from NRG, non-cash, primarily represent Drop Down Assets' equity transferred from NRG to the Company in accordance with guidance on business combinations between entities under common control, as further described in Note 1, Nature of Business.

See accompanying notes to consolidated financial statements.

7

NRG YIELD, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — 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.”

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, 2016, the Company and NRG have 53.3% and 46.7% 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.

The following table represents the structure of the Company as of December 31, 2016:

8

As of December 31, 2016, 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	2035
Desert Sunlight 300	25	%	75	Pacific Gas and Electric	2040
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 (e)	50	%	265	PacifiCorp	2036
			921
Distributed Solar
AZ DG Solar Projects	100	%	5	Various	2025 - 2033
PFMG DG Solar Projects	51	%	4	Various	2032
			9
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)	74.3	%	16	Corn Belt Power Cooperative	2027
Elbow Creek (b)	75	%	92	NRG Power Marketing LLC	2022
Elkhorn Ridge (b)	50.3	%	41	Nebraska Public Power District	2029
Forward (b)	75	%	22	Constellation NewEnergy, Inc.	2017
Goat Wind (b)	74.9	%	113	Dow Pipeline Company	2025
Hardin (b)	74.3	%	11	Interstate Power and Light Company	2027
Laredo Ridge	100	%	80	Nebraska Public Power District	2031
Lookout (b)	75	%	29	Southern Maryland Electric Cooperative	2030
Odin (b)	74.9	%	15	Missouri River Energy Services	2028
Pinnacle	100	%	55	Maryland Department of General Services and University System of Maryland	2031
San Juan Mesa (b)	56.3	%	68	Southwestern Public Service Company	2025
Sleeping Bear (b)	75	%	71	Public Service Company of Oklahoma	2032
South Trent	100	%	101	AEP Energy Partners	2029
Spanish Fork (b)	75	%	14	PacifiCorp	2028

9

Projects	Percentage Ownership		Net Capacity (MW) (a)	Offtake Counterparty	Expiration
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)	74.9	%	121	Southwestern Public Service Company	2027
			1,999
Thermal
Thermal equivalent MWt(c)	100	%	1,319	Various	Various
NRG Energy Center Dover LLC	100	%	103	NRG Power Marketing LLC	2018
Thermal generation	100	%	20	Various	Various
			1,442
Total net capacity (excluding equivalent MWt) (d)			4,997

^(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, 2016.

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

^(c) 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.

^(d) NRG Yield's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's generation capacity including this noncontrolling interest was 5,003 MWs.

^(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).

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 131 MW based on cash to be distributed. 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. Three out of the fourteen district energy systems are subject to rate regulation by state public utility commissions while the other district energy systems have rates determined by negotiated bilateral contracts.

As described in Note 15, Related Party Transactions, 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, 2016 and 2015, the Company completed three 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.

10

In addition, as further described in Note 3, Business Acquisitions, on March 27, 2017, the Company acquired the following interests from NRG, referred to as the March 2017 Drop Down Assets: (i) Agua Caliente Borrower 2 LLC, which owns a 16% interest in the Agua Caliente solar farm, one of the NRG ROFO assets and (ii) NRG's interests in seven utility-scale solar farms located in Utah that were part of NRG's November 2, 2016 acquisition of projects from SunEdison, or Utah Solar Portfolio. The Company paid total cash consideration of $130 million, plus a $1 million working capital adjustment, and assumed non-recourse debt of $328 million, which is consolidated, as well as its pro-rata share of non-recourse project-level debt of $135 million. The acquisition was funded with cash on hand. The acquisition of the March 2017 Drop Down Assets was accounted for as a transfer of entities under common control. 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 Aqua Caliente Borrower 2 LLC from the beginning of the financial statement period, and its interests in the Utah Solar Portfolio from November 2, 2016. The recast for the March 2017 Drop Down Assets did not affect the historical net income attributable to NRG Yield, Inc. weighted average number of shares outstanding, earnings per share or dividends.

Note 2 — 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 $110 million and $93 million as of December 31, 2016 and 2015, respectively.

Restricted Cash

Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use. Of these funds as of December 31, 2016, approximately $25 million is designated for current debt service payments, $13 million is designated to fund operating expenses and $37 million is designated for distributions to the Company, with the remaining $90 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, 2016 and 2015.

11

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.

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.

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 loan.

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.

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.

12

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, 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.

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, 2016, 2015, and 2014 was $553 million, $416 million, and $296 million, respectively.

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

13

• 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, 2016 and 2015, along with the additions and accretion related to the Company's ARO obligations for the year ended December 31, 2016:

	(In millions)
Balance as of December 31, 2015	$	43
Revisions in estimates for current obligations	2
Accretion — expense	3
Balance as of December 31, 2016	$	48

14

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, seven of which are VIEs, where the Company is not a primary beneficiary, and two of which are owned by a subsidiary that is consolidated as a VIE, 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.

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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 amount 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 amount of net earnings during the reporting period. 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

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 were issued to address the diversity in classification and presentation of changes in restricted cash and restricted cash equivalents on the statement of cash flows which is currently not addressed under Topic 230. The amendments of ASU No. 2016-18 would 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 should be applied retrospectively.  The Company is currently evaluating the impact of the standard on the Company’s statement of cash flows.

ASU 2016-16 — In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory, or ASU No. 2016-16.  The amendments of ASU No. 2016-16 were issued to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory.  Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party which has resulted in diversity in practice and increased complexity within financial reporting.  The amendments of ASU No. 2016-16 would require an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and do not require new disclosure requirements.  The amendments of ASU No. 2016-16 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. 2016-16 should be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption.  The Company is currently evaluating the impact of the standard on the Company’s results of operations, cash flows and financial position.

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ASU 2016-15 — In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments, or ASU No. 2016-15. The amendments of ASU No. 2016-15 were issued to address eight specific cash flow issues for which stakeholders have indicated to the FASB that a diversity in practice existed in how entities were presenting and classifying these items in the statement of cash flows. The issues addressed by ASU No. 2016-15 include but are not limited to the classification of debt prepayment and debt extinguishment costs, payments made for contingent consideration for a business combination, proceeds from the settlement of insurance proceeds, distributions received from equity method investees and separately identifiable cash flows and the application of the predominance principle. The amendments of ASU No. 2016-15 are effective for public entities for fiscal years beginning after December 15, 2017 and interim periods in those fiscal years. Early adoption is permitted, including adoption in an interim fiscal period with all amendments adopted in the same period. The adoption of ASU No. 2016-15 is required to be applied retrospectively. The Company is currently evaluating the impact of the standard on the Company's statement of cash flows.

ASU 2016-07 — In March 2016, the FASB issued ASU No. 2016-07, Investments - Equity Method and Joint Ventures (Topic 323), or ASU No. 2016-07. The amendments of ASU No. 2016-07 eliminate the requirement that when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations, and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. The amendments require that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting with no retroactive adjustment to the investment. In addition, ASU No. 2016-07 requires that an entity that has an available-for-sale equity security that becomes qualified for the equity method of accounting recognize through earnings the unrealized holding gain or loss in accumulated other comprehensive income at the date the investment becomes qualified for use of the equity method. The Company adopted this standard effective January 1, 2017. The adoption of ASU No. 2016-07 is required to be applied prospectively. The Company does not expect the standard to have a material impact on its results of operations, cash flows and financial position.

ASU 2016-02 — In 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 expects to adopt the standard effective January 1, 2019 utilizing the required modified retrospective approach for the earliest period presented. 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 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. As this review is still in process, it is currently not practicable to quantify the impact of adopting the ASU at this time.

ASU 2016-01 — In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, or ASU No. 2016-01. The amendments of ASU No. 2016-01 eliminate available-for-sale classification of equity investments and require that equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be generally measured at fair value with changes in fair value recognized in net income.  Further, the amendments require that financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset.  The guidance in ASU No. 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.

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ASU 2015-16 — In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, or ASU No. 2015-16. The amendments of ASU No. 2015-16 require that an acquirer recognize measurement period adjustments to the provisional amounts recognized in a business combination in the reporting period during which the adjustments are determined. Additionally, the amendments of ASU No. 2015-16 require the acquirer to record in the same period's financial statements the effect on earnings of changes in depreciation, amortization or other income effects, if any, as a result of the measurement period adjustment, calculated as if the accounting had been completed at the acquisition date as well as disclosing on either the face of the income statement or in the notes the portion of the amount recorded in current period earnings that would have been recorded in previous reporting periods. The guidance in ASU No. 2015-16 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amendments should be applied prospectively. The Company adopted ASU No. 2015-16 for the year ended December 31, 2016, and the adoption did not have a material impact on the Company's results of operations, cash flows and financial position.

ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU No. 2014-09, 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 expects to adopt the standard effective January 1, 2018 and apply the guidance retrospectively to contracts at the date of adoption. The Company will recognize the cumulative effect of applying Topic 606 at the date of initial application, as prescribed under the modified retrospective transition method. The Company also expects to elect 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. As leases are excluded from the scope of Topic 606, the Company expects the standard to have an immaterial impact on the Company's results of operations, cash flows and financial position; however, the Company continues to assess the impact in connection with its plan of adoption.

Note 3 — Business Acquisitions

2017 Acquisitions

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 NRG 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 $130 million, plus $1 million of working capital. The acquisition of the March 2017 Drop Down Assets was funded with cash on hand and is referred to as March 2017 Drop Down Assets. The Company recorded the acquired interests as equity method investments. The Company also assumed 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.

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).

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The following tables present the Company's historical information summary combining the financial information for the March 2017 Drop Down Assets transferred in connection with the acquisitions:

	As of December 31, 2016
	As Previously Reported		March 2017 Drop Down Assets		As Currently Reported
(In millions)
Current assets	$	645	$	11	$	656
Property, plant and equipment	5,460		—		5,460
Non-current assets	2,278		442		2,720
Total assets	8,383		453		8,836
Debt	5,708		279		5,987
Other current and non-current liabilities	305		5		310
Total liabilities	6,013		284		6,297
Net assets	$	2,370	$	169	$	2,539

	As of December 31, 2015
	As Previously Reported		March 2017 Drop Down Assets		As Currently Reported
(In millions)
Current assets	$	416	$	—	$	416
Property, plant and equipment	5,878		—		5,878
Non-current assets	2,395		100		2,495
Total assets	8,689		100		8,789
Debt	5,593		—		5,593
Other current and non-current liabilities	358		—		358
Total liabilities	5,951		—		5,951
Net assets	$	2,738	$	100	$	2,838

	Year ended December 31, 2016
	As Previously Reported			March 2017 Drop Down Assets		As Currently Reported
(In millions)
Total operating revenues	$	1,021		$	—	$	1,021
Operating income	218			—		218
Net (loss) income	(15		)	17		2

	Year ended December 31, 2015
	As Previously Reported		March 2017 Drop Down Assets		As Currently Reported
(In millions)
Total operating revenues	$	953	$	—	953
Operating income	320		—		320
Net income	65		5		70

	Year ended December 31, 2014
	As Previously Reported		March 2017 Drop Down Assets		As Currently Reported
(In millions)
Total operating revenues	$	828	$	—	$	828
Operating income	306		—		306
Net income	108		5		113

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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, 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 further described in Note 10, Long-term Debt. 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.

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 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 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. As of June 30, 2016, the Company's recast consolidated balance sheet included a net receivable of $67 million related to current litigation with SunPower pursuant to indemnities in the project. The agreement between NRG and the Company for the CVSR Drop Down acquisition specified that all amounts related to the litigation with SunPower were excluded from the acquisition. Accordingly, prior to close of the transaction, the net receivable was transferred to NRG as a net reduction to its ownership interest in CVSR.

The following is the summary of historical net liabilities assumed in connection with the CVSR Drop Down as of September 1, 2016:

	CVSR
	(In millions)
Current assets	$	95
Property, plant and equipment	826
Non-current assets	13
Total assets	934
Debt (a)	966
Other current and non-current liabilities	12
Total liabilities	978
Net liabilities assumed	(44		)
Accumulated other comprehensive loss	(25		)
Historical net liabilities assumed	$	(19	)

^(a) Net of deferred financing costs of $5 million.

The Company incurred and expensed acquisition-related transaction costs related to the acquisition of CVSR of $1 million for the year ended December 31, 2016. Since the acquisition date, CVSR has contributed $22 million in operating revenues and a $2 million in net loss to the Company.

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 $209 million, subject to working capital adjustments. In February 2016, NRG made a final working capital payment of $2 million, reducing total cash consideration to $207 million. The Company is 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

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the cash paid and historical value of the entities' equity was recorded as a distribution from NRG with the offset to noncontrolling interest.

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 75% of CAFD until the flip point, at which time the allocations to the Company of CAFD change to 68.60%. 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.

The following is a summary of assets and liabilities transferred in connection with the acquisition as of November 3, 2015:

	NRG Wind TE Holdco
	(In millions)
Current assets	$	30
Property, plant and equipment	669
Non-current assets	177
Total assets	876
Debt	193
Other current and non-current liabilities	32
Total liabilities	225
Less: noncontrolling interest	282
Net assets acquired	$	369

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.

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2014 Acquisitions

Alta Wind Portfolio Acquisition — OnAugust 12, 2014, the Company acquired 100% of the membership interests of Alta Wind Asset Management Holdings, LLC, Alta Wind Company, LLC, Alta Wind X Holding Company, LLC and Alta Wind XI Holding Company, LLC, which collectively own seven wind facilities that total 947 MW located in Tehachapi, California, and a portfolio of associated land leases, or the Alta Wind Portfolio. Power generated by the Alta Wind Portfolio is sold to Southern California Edison under long-term PPAs with 21 years of remaining contract life for Alta I-V. The Alta Wind X and XI PPAs began in 2016 with a term of 22 years and sold energy and renewable energy credits on a merchant basis during the years ending December 31, 2015 and 2014.

The purchase price for the Alta Wind Portfolio was $923 million, which consisted of a base purchase price of $870 million, as well as a payment for working capital of $53 million, plus the assumption of $1.6 billion of non-recourse project-level debt. In order to fund the purchase price, the Company completed an equity offering of 12,075,000 shares of its Class A common stock at an offering price of $54.00 per share on July 29, 2014, which resulted in net proceeds of $630 million, after underwriting discounts and expenses. In addition, on August 5, 2014, NRG Yield Operating LLC issued $500 million of Senior Notes, which bear interest at a rate of 5.375% and mature in August 2024.

The acquisition was recorded as a business combination under ASC 805-50, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The accounting for the business combination was completed as of August 11, 2015, at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of December 31, 2014, as well as adjustments made through August 11, 2015, when the allocation became final.

The purchase price of $923 million was allocated as follows:

	Acquisition Date Fair Value at December 31, 2014		Measurement period adjustments			Revised Acquisition Date
Assets	(In millions)
Cash	$	22	$	—		$	22
Current and non-current assets	49		(2		)	47
Property, plant and equipment	1,304		6			1,310
Intangible assets	1,177		(6		)	1,171
Total assets acquired	2,552		(2		)	2,550
Liabilities
Debt	1,591		—			1,591
Current and non-current liabilities	38		(2		)	36
Total liabilities assumed	1,629		(2		)	1,627
Net assets acquired	$	923	$	—		$	923

The Company incurred and expensed acquisition-related transaction costs related to the acquisition of the Alta Wind Portfolio of $2 million for the year ended December 31, 2014.

June 2014 Drop Down Assets —On June 30, 2014, the Company acquired from NRG: (i) El Segundo, a 550 MW fast-start, gas-fired facility located in Los Angeles County, California; (ii) TA High Desert, a 20 MW solar facility located in Los Angeles County, California; and (iii) Kansas South, a 20 MW solar facility located in Kings County, California. The Company paid total cash consideration of $357 million, which represents a base purchase price of $349 million and $8 million of working capital adjustments. In addition, the acquisition included the assumption of $612 million of project-level debt. 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. The difference between the cash proceeds and the historical value of the net assets was recorded as a distribution to NRG and reduced the balance of its noncontrolling interest. Since the transaction constituted a transfer of entities 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 beginning of the financial statements period or the inception of common control (if later than the beginning of the financial statements period). Accordingly, the Company prepared its consolidated financial statements to reflect the transfer as if it had taken place from the beginning of the financial statements period.

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Note 4 — Property, Plant and Equipment

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

	December 31, 2016			December 31, 2015			Depreciable Lives
	(In millions)
Facilities and equipment	$	6,215		$	6,480		2 - 40 Years
Land and improvements	171			171
Construction in progress (a)	25			9
Total property, plant and equipment	6,411			6,660
Accumulated depreciation	(951		)	(782		)
Net property, plant and equipment	$	5,460		$	5,878

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

Note 5 — 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, 2016:

Name	Economic Interest	Investment Balance
		(In millions)
Utah Solar Portfolio (a)	50%	$346
Desert Sunlight	25%	282
GenConn(b)	50%	106
Agua Caliente Borrower 2	16%	96
Elkhorn Ridge(c)	50.3%	85
San Juan Mesa(c)	56.3%	74
NRG DGPV Holdco 1 LLC (d)	95%	75
NRG DGPV Holdco 2 LLC (d)	95%	24
NRG RPV Holdco 1 LLC(d)	95%	71
Avenal	50%	(7)
Total equity investments in affiliates		$1,152

^(a) Economic interest based on cash to be distributed. Four Brothers Solar, LLC, Granite Mount Holdings, LLC and Iron Spring 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 75% 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, and NRG RPV Holdco 1 LLC are tax equity structures and VIEs. The related allocations are described below.

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As of December 31, 2016 and 2015, the Company had $51 million and $45 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 approximately $589 million as of December 31, 2016.

Agua Caliente Financing— As described in Note 3, Business Acquisitions, the Company acquired a 16% interest in the Agua Caliente solar facility through its acquisition of Agua Caliente Borrower 2 LLC. As of December 31, 2016, Agua Caliente Solar LLC, the direct owner of the Agua Caliente solar facility, had $849 million outstanding under the Agua Caliente financing agreement with the Federal Financing Bank, or FFB, borrowed to finance the costs of constructing the facility. The Company's pro-rata share of Agua Caliente Financing was approximately $136 million as of December 31, 2016.  Amounts borrowed under the Agua Caliente financing agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of 0.375%, mature in 2037 and are secured by the assets of Agua Caliente Solar LLC.  The loans provided by the FFB are guaranteed by the U.S. DOE. 

Avenal — The Company owns a 50% equity interest in Avenal, which consists of three solar PV projects in Kings County, California totaling approximately 45 MWs. Eurus Energy owns the remaining 50% of Avenal. Power generated by the projects is sold under a 20-year PPA. On September 22, 2010, Avenal entered into a $35 million promissory note facility with the Company. Amounts drawn under the promissory note facility accrue interest at 4.5% per annum. Also, on September 22, 2010, Avenal entered into a $209 million financing arrangement with a syndicate of banks, or the Avenal Facility. As of December 31, 2016 and 2015, Avenal had outstanding $134 million and $143 million, respectively, under the Avenal Facility.

Desert Sunlight —Desert Sunlight 250 and Desert Sunlight 300 each entered into three distinct tranches of debt. As of December 31, 2016 and 2015, Desert Sunlight had total debt outstanding of $1.1 billion under the three tranches.

GenConn — GenConn has a $237 million project note with an interest rate of 4.73% and a maturity date of July 2041 and a 5-year, $35 million working capital facility that matures in 2018 which can be used to issue letters of credit at an interest rate of 1.875% per annum. As of December 31, 2016 and 2015, $212 million and $220 million, respectively, were outstanding under the note. As of December 31, 2016, $14 million was drawn on the working capital facility. The note is secured by all of the GenConn assets. The Company's maximum exposure to loss is limited to its equity investment in GenConn, which was $106 million as of December 31, 2016.

NRG DGPV Holdco 2 LLC — On June 30, 2016, NRG DGPV4 Borrower LLC, a direct subsidiary of NRG DGPV Holdco 2 LLC entered into a financing agreement to fund the acquisition of projects by the tax equity fund.  As of December 31, 2016, there was $21 million outstanding under the facility.

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Summarized Financial Information

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

	Year Ended December 31,
	2016			2015			2014
Income Statement Data:	(In millions)
GenConn
Operating revenues	$	72		$	78		$	82
Operating income	38			40			40
Net income	26			28			28
Desert Sunlight
Operating revenues	$	211		$	206		134
Operating income	129			124			74
Net income	80			73			37
Utah Solar Portfolio (a)
Operating revenues	$	13		$	—		$	—
Operating loss	(6		)	(1		)	—
Net loss	(6		)	(1		)	—
				As of December 31,
				2016			2015
Balance Sheet Data:				(In millions)
GenConn
Current assets				$	36		$	36
Non-current assets				389			416
Current liabilities				16			16
Non-current liabilities				196			215
Desert Sunlight
Current assets				$	281		$	310
Non-current assets				1,401			1,435
Current liabilities				64			82
Non-current liabilities				1,043			1,086
Utah Solar Portfolio (a)
Current assets				$	20		$	11
Non-current assets				1,105			705
Current liabilities				14			229
Non-current liabilities				38			—

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

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Variable Interest Entities, or VIEs

Entities that are Consolidated

NRG Wind TE Holdco — On November 3, 2015, the Company acquired 75% of the Class B interests of NRG Wind TE Holdco, or the November 2015 Drop Down Assets, which owns a portfolio of 12 wind facilities totaling 814 net MW, from NRG for total cash consideration of $209 million, as described in Note 3, Business Acquisitions. In February 2016, NRG made a final working capital payment of $2 million, reducing total cash consideration to $207 million. NRG retained a 25% ownership of the Class B interest. 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 75% of CAFD until the flip point, at which time the allocations to the Company of CAFD change to 68.60%. 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. The Company utilizes the HLBV method to determine the net income or loss allocated to the TE Investor noncontrolling interest. Net income or loss attributable to the Class B interests is allocated to NRG's noncontrolling interest based on its 25% ownership 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 received 100% of CAFD through December 31, 2015, and subsequently will receive 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. The net proceeds of $119 million were reflected as noncontrolling interest in the Company's balance sheet.

Spring Canyon — On May 7, 2015, the Company acquired 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, from Invenergy Wind Global LLC. Invenergy owns 9.9% of the Class B interests. Prior to the acquisition date, the projects were 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 will receive 34.81% of the cash distributions based on the projects’ production level and the Company and Invenergy will receive 65.19%. 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.

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Summarized financial information for the Company's consolidated VIEs consisted of the following as of December 31, 2016:

(In millions)	NRG Wind TE Holdco		Alta TE Holdco		Spring Canyon
Other current and non-current assets	$	193	$	17	$	4
Property, plant and equipment	441		461		100
Intangible assets	2		274		—
Total assets	636		752		104
Current and non-current liabilities	209		9		6
Total liabilities	209		9		6
Noncontrolling interest	139		107		67
Net assets less noncontrolling interests	$	288	$	636	$	31

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 — As described in Note 3, Business Acquisitions, on March 27, 2017, 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. The Company’s maximum exposure to loss is limited to its equity method investments in the Utah Solar Portfolio, which was $346 million on a combined basis as of December 31, 2016.

NRG DGPV Holdco 1 LLC — On May 8, 2015, the Company and NRG entered into a partnership by forming NRG DGPV Holdco 1 LLC, 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, including: (i) a tax equity-financed portfolio of 10 recently completed community solar projects representing approximately 8 MW with a weighted average remaining PPA term of 19 years; (ii) a tax equity-financed portfolio of approximately 12 commercial photovoltaic systems representing approximately 37 MW with a weighted average remaining PPA term of 18 years; and (iii) a tax equity-financed portfolio of approximately 3 commercial photovoltaic systems representing approximately 1 MW with a weighted average remaining PPA term of 20 years. All of these investments relate to the Company's $100 million commitment to distributed solar projects in partnership with NRG.

NRG DGPV Holdco 2 LLC — On February 29, 2016,the Company and NRG entered into an additional partnership by forming NRG DGPV Holdco 2 LLC, or DGPV Holdco 2, to own or purchase solar power generation projects as well as other ancillary related assets from NRG Renew LLC or its subsidiaries, via intermediate funds including: (i) a tax equity-financed portfolio of 18 projects representing approximately 28 MW with a weighted average remaining PPA term of 21 years; and (ii) a tax equity-financed portfolio of 21 projects representing approximately 18 MW with a weighted average remaining PPA term of 20 years.  Under this partnership, the Company committed to fund up to $50 million of capital. 

The Company's maximum exposure to loss is limited to its equity investment in DGPV Holdco 1 and DGPV Holdco 2, which was $99 million on a combined basis, of which $14 million was payable to NRG, as of December 31, 2016.

NRG RPV Holdco 1 LLC — On April 9, 2015, the Company and NRG entered into a partnership by forming NRG RPV Holdco 1 LLC, or RPV Holdco, that holds 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 15 MW with a weighted average remaining lease term of approximately 19 years that was acquired outside of the partnership; and (ii) a tax equity-financed portfolio of approximately 5,400 leases representing approximately 31 MW, with a weighted average remaining lease term for the existing and new leases of approximately 19 years.

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In addition to the acquisition of the unlevered portfolio of leases, the Company had previously committed to fund up to $150 million of capital to invest in the tax equity financed portfolio. On February 29, 2016, the Company and NRG amended the RPV Holdco partnership agreement to reduce the aggregate commitment of $150 million to $100 million in connection with the formation of DGPV Holdco 2. On August 5, 2016, the Company and NRG amended the RPV Holdco partnership agreement to further reduce that capital commitment of $100 million to $60 million in connection with NRG’s change in business model approach in the residential solar business. As of December 31, 2016, the Company had contributed $59 million of this amount.

The Company's maximum exposure to loss is limited to its equity investment, which was $71 million as of December 31, 2016.

Note 6 — 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, 2016				As of December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable, including current portion	$	30	$	30	$	47	$	47
Liabilities:
Long-term debt, including current portion	$	6,057	$	6,056	$	5,656	$	5,538

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.

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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 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, 2016 and 2015:

	As of December 31, 2016				As of December 31, 2015
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	1,455	$	4,601	$	978	$	4,560

Recurring Fair Value Measurements

The Company records its derivative assets and liabilities at fair market value on its consolidated balance sheet. There were no asset positions as of December 31, 2015. 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, 2016		As of December 31, 2016		As of December 31, 2015
	Fair Value (a)		Fair Value (a)		Fair Value (a)
(In millions)	Level 1		Level 2		Level 2
Derivative assets:
Commodity contracts	$	1	$	1	$	—
Interest rate contracts	—		1		—
Total assets	$	1	$	2	$	—
Derivative liabilities:
Commodity contracts	$	—	$	1	$	2
Interest rate contracts	—		75		98
Total liabilities	$	—	$	76	$	100

^(a) There were no assets or liabilities classified as Level 1 as of December 31, 2015. There were no assets or liabilities classified Level 3 as of December 31, 2016 and 2015.

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, 2016, the credit reserve resulted in a $1 million increase in fair value in OCI. It is possible that future market prices could vary from those used in recording assets and liabilities and such variations could be material.

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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, 2016, credit risk exposure to these counterparties attributable to the Company's ownership interests was approximately $2.8 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.

Note 7 — 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 effective portion of the change in fair value of the derivatives to accumulated OCI/OCL, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings. For derivatives 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, 2016, 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 2018 and electricity contracts to supply retail power to the Company's district energy centers extending through 2020. At December 31, 2016, these contracts were not designated as cash flow or fair value hedges.

Also, as of December 31, 2016, 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, 2016, the Company had interest rate derivative instruments on non-recourse debt extending through 2036, most of which are designated as cash flow hedges.

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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, 2016 and 2015:

		Total Volume
		December 31, 2016		December 31, 2015
Commodity	Units	(In millions)
Natural Gas	MMBtu	3		4
Interest	Dollars	$	2,070	$	1,991

Fair Value of Derivative Instruments

There were no derivative asset positions on the balance sheet as of December 31, 2015. The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:

	Fair Value
	Derivative Assets		Derivative Liabilities
	December 31, 2016		December 31, 2016		December 31, 2015
	(In millions)
Derivatives Designated as Cash Flow Hedges:
Interest rate contracts current	$	—	$	26	$	34
Interest rate contracts long-term	1		39		56
Total Derivatives Designated as Cash Flow Hedges	1		65		90
Derivatives Not Designated as Cash Flow Hedges:
Interest rate contracts current	—		5		3
Interest rate contracts long-term	—		5		5
Commodity contracts current	2		1		2
Total Derivatives Not Designated as Cash Flow Hedges	2		11		10
Total Derivatives	$	3	$	76	$	100

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, 2016, there was no outstanding collateral paid or received. As of December 31, 2015, there were no offsetting amounts at the counterparty master agreement level or outstanding collateral paid or received. The following table summarizes the offsetting of derivatives by counterparty master agreement level as of December 31, 2016:

	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	(75		)	1			(74		)
Total interest rate contracts	(74		)	—			(74		)
Total derivative instruments	$	(73	)	$	—		$	(73	)

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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,
	2016			2015			2014
	(In millions)
Accumulated OCL beginning balance	$	(83	)	$	(76	)	$	(16	)
Reclassified from accumulated OCL to income due to realization of previously deferred amounts	13			14			14
Mark-to-market of cash flow hedge accounting contracts	—			(21		)	(74		)
Accumulated OCL ending balance, net of income tax benefit of $16, $16 and $6, respectively	$	(70	)	$	(83	)	$	(76	)
Accumulated OCL attributable to noncontrolling interests	(42		)	(56		)	(67		)
Accumulated OCL attributable to NRG Yield, Inc.	$	(28	)	$	(27	)	$	(9	)
Losses expected to be realized from OCL during the next 12 months, net of income tax benefit of $3	$	16

Amounts reclassified from accumulated OCL into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to interest expense. There was no ineffectiveness for the years ended December 31, 2016, 2015 and 2014.

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.

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, 2016, 2015 and 2014 the impact to the consolidated statements of income was a loss of $2 million, a gain of $16 million, and a loss of $22 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 and 2014, 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 years ended December 31, 2015 and 2014, the impact to the consolidated statements of income was an unrealized loss of $2 million and a gain of $2 million, respectively.

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

Note 8 — Intangible Assets

Intangible Assets — The Company's intangible assets as of December 31, 2016 and 2015 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 will be 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 will be amortized on a straight-line basis.

• Customer relationships — Established with the acquisition of NRG Energy Center Phoenix and NRG Energy Center

32

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 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, 2016	PPAs			Leasehold Rights			Customer Relationships			Customer Contracts			Emission Allowances			Development Rights			Other			Total
(In millions)
January 1, 2016	$	1,264		$	86		$	66		$	15		$	15		$	3		$	6		$	1,455
Other	—			—			—			—			(6		)	—			—			(6		)
December 31, 2016	1,264			86			66			15			9			3			6			1,449
Less accumulated amortization	(138		)	(9		)	(4		)	(7		)	(2		)	(1		)	(2		)	(163		)
Net carrying amount	$	1,126		$	77		$	62		$	8		$	7		$	2		$	4		$	1,286

Year ended December 31, 2015	PPAs			Leasehold Rights			Customer Relationships			Customer Contracts			Emission Allowances			Development Rights			Other			Total
(In millions)
January 1, 2015	$	1,270		$	86		$	66		$	15		$	16		$	3		$	6		$	1,462
Other	(6		)	—			—			—			(1		)	—			—			(7		)
December 31, 2015	1,264			86			66			15			15			3			6			1,455
Less accumulated amortization	(75		)	(5		)	(3		)	(6		)	(1		)	(1		)	(2		)	(93		)
Net carrying amount	$	1,189		$	81		$	63		$	9		$	14		$	2		$	4		$	1,362

The Company recorded amortization expense of $70 million, $55 million and $30 million during the years ended December 31, 2016, 2015 and 2014. Of these amounts, $69 million, $54 million and $29 million for the years ended December 31, 2016, 2015 and 2014, respectively, were recorded to contract amortization expense and reduced operating revenues in the consolidated statements of income. The Company estimates the future amortization expense for its intangibles to be $71 million for the next five years through 2021.

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 Holding Company, LLC, as of their respective acquisition dates. The Blythe solar project's liability of $4 million is 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 is 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 Holding Company, LLC's liability of $5 million is recorded to other non-current liabilities and is amortized to cost of operations on a straight-line basis over the term of the land lease. At December 31, 2016, accumulated amortization of out-of-market contracts was $3 million and amortization expense was $1 million for the years ended December 31, 2016 and 2015.

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Note 9 — Asset Impairments

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 located in Texas and the Forward project in Pennsylvania 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 in 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.

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Note 10 — Long-term Debt

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

	December 31, 2016			December 31, 2015			Interest rate % (a)	Letters of Credit Outstanding at December 31, 2016
	(In millions, except rates)
2026 Senior Notes	$	350		$	—		5.000
2024 Senior Notes	500			500			5.375
2020 Convertible Notes	271			266			3.250
2019 Convertible Notes	335			330			3.500
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 (b)	—			306			L+2.500	$	60
Project-level debt:
Alpine, due 2022	145			154			L+1.750	37
Alta Wind I, lease financing arrangement, due 2034	242			252			7.015	16
Alta Wind II, lease financing arrangement, due 2034	191			198			5.696	27
Alta Wind III, lease financing arrangement, due 2034	198			206			6.067	27
Alta Wind IV, lease financing arrangement, due 2034	128			133			5.938	19
Alta Wind V, lease financing arrangement, due 2035	206			213			6.071	30
Alta Realty Investments, due 2031	31			33			7.000	—
Alta Wind Asset Management, due 2031	18			19			L+2.375	—
Avra Valley, due 2031	57			60			L+1.750	3
Blythe, due 2028	19			21			L+1.625	6
Borrego, due 2025 and 2038	69			72			L+ 2.500/5.650	5
CVSR, due 2037	771			793			2.339 - 3.775	—
CVSR Holdco Notes, due 2037	199			—			4.680	13
El Segundo Energy Center, due 2023	443			485			L+1.625 - L+2.250	82
Energy Center Minneapolis, due 2017 and 2025	96			108			5.950 -7.250	—
Energy Center Minneapolis Series D Notes, due 2031	125			—			3.550	—
Kansas South, due 2031	30			33			L+2.000	4
Laredo Ridge, due 2028	100			104			L+1.875	10
Marsh Landing, due 2017 and 2023	370			418			L+1.750 - L+1.875	22
PFMG and related subsidiaries financing agreement, due 2030	27			29			6.000	—
Roadrunner, due 2031	37			40			L+1.625	5
South Trent Wind, due 2020	57			62			L+1.625	10
TA High Desert, due 2020 and 2032	49			52			L+2.500/5.150	8
Tapestry, due 2021	172			181			L+1.625	20
Utah Solar Portfolio, due 2022	287			—			L+2.625	13
Viento, due 2023	178			189			L+2.750	27
Walnut Creek, due 2023	310			351			L+1.625	41
WCEP Holdings, due 2023	46			46			L+3.000	—
Other	—			2			various	—
Subtotal project-level debt	4,601			4,254
Total debt	6,057			5,656
Less current maturities	(291		)	(264		)
Less deferred financing costs	(70		)	(63		)
Total long-term debt	$	5,696		$	5,329

^(a) As of December 31, 2016, L+ equals 3 month LIBOR plus x%, except for the Alpine term loan, Marsh Landing term loan, Walnut Creek term loan, Utah Solar Portfolio debt, and NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, where L+ equals 1 month LIBOR plus x% and Kansas South and Viento, where L+ equals 6 month LIBOR plus x%.

^(b) Net of discount of $16.5 million and $21.5 million as of December 31, 2016 and 2015, respectively.

^(c) Net of discount of $10 million and $15 million as of December 31, 2016 and 2015, respectively.

^(d) Applicable rate is determined by the Borrower Leverage Ratio, as defined in the credit agreement.

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 arrangement. As of December 31, 2016, the Company was in compliance with all of the required covenants.

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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, and interest payments will commence on March 15, 2017. 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, as described below.

NRG Yield Operating LLC 2024 Senior Notes

On August 5, 2014, NRG Yield Operating LLC issued $500 million of senior unsecured notes, or the 2024 Senior Notes. The 2024 Senior Notes bear interest at 5.375% and mature in August 2024. Interest on the notes is payable semi-annually on February 15 and August 15 of each year. The 2024 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.

2020 Convertible Senior Notes

The Company has outstanding $287.5 million aggregate principal amount of 3.25% Convertible Senior Notes due 2020, or the 2020 Convertible Notes.  The 2020 Convertible Notes are convertible, under certain circumstances, into 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. The 2020 Convertible Notes mature on June 1, 2020, unless earlier repurchased or converted in accordance with their terms. Prior to the close of business on the business day immediately preceding December 1, 2019, the 2020 Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the close of business on the second scheduled trading day immediately preceding the maturity date. The 2020 Convertible Notes are 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, 2016, the 2020 Convertible Notes were trading at approximately 97% of their face value, resulting in a total market value of $278 million compared to a carrying value of $271 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 Convertible Debt indenture. As of December 31, 2016, the Company's Class C common stock closed at $15.80 per share, resulting in a pro forma conversion value for the Convertible Notes of approximately $165 million.

During the years ended December 31, 2016 and 2015, the Company recorded the following expense in relation to the 2020 Convertible Notes at the effective rate of 5.10%:

(In millions)	2016		2015
Interest expense at 3.25% coupon rate	$	9	$	5
Debt discount amortization	4		2
Debt issuance costs amortization	1		1
	$	14	$	8

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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. Interest on the 2019 Convertible Notes is payable semi-annually in arrears on February 1 and August 1 of each year. 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, 2016, the 2019 Convertible Notes were trading at approximately 99.6% of their face value, resulting in a total market value of $344 million compared to a carrying value of $335 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, 2016, the Company's Class A common stock closed at $15.36 per share, resulting in a pro forma conversion value for the Convertible Notes of approximately $228 million.

During the years ended December 31, 2016 and 2015, the Company recorded the following expense in relation to the 2019 Convertible Notes at the effective rate of 5.00%:

(In millions)	2016		2015
Interest expense at 3.5% coupon rate	$	12	$	12
Debt discount amortization	5		4
Debt issuance costs amortization	2		2
	$	19	$	18

NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility

In connection with the Company's initial public offering of Class A common stock in July 2013, as further described in Note 1, Nature of Business, NRG Yield LLC and NRG Yield Operating LLC entered into a senior secured revolving credit facility, or the Yield Credit Facility, which was amended on June 26, 2015, to, among other things, increase the availability to $495 million. The Company's revolving credit facility can be used for cash or for the issuance of letters of credit.

During 2015, the Company borrowed $254 million from the revolving credit facility to finance the acquisition of the November 2015 Drop Down Assets as discussed in Note 3, Business Acquisitions, as well asfund dividend payments and tax equity contributions.

The Company borrowed $60 million from the revolving credit facility and repaid $366 million during the year endedDecember 31, 2016. The Company used its pro rata proceeds of $97.5 million from the CVSR Holdco Financing Arrangement in July 2016, a portion of its proceeds from the issuance of the 2026 Senior Notes in August 2015, as well as its cash on hand to repay the outstanding borrowings under the revolving credit facility.

As of December 31, 2016, there were no outstanding borrowings and the Company had $60 million of letters of credit outstanding under the revolving credit facility.

Project - level Debt

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 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. Agua Caliente Borrower 2 LLC owns a 16% interest in the Agua Caliente solar farm and holds $41 million of the Agua Caliente Holdco debt. 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.

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Concurrent with the February 2017 borrowing, the Company entered into a letter of credit commitment of $17 million and issued same to support the Company's debt service requirement obligations. The Company pays semi-annual related fees of 2.25% on the outstanding balance.

Utah Solar Portfolio, due 2022

As part of its March 2017 Drop Down Assets acquisition, the Company assumed non-recourse debt of $287 million relating to the Utah Solar Portfolio at 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 the NRG acquisition in November 2016, and additional borrowings of $65 million incurred during 2016. The Company also entered into letter agreements for a commitment of $13 million to support the Company's debt service requirement obligations. The Company pays an availability fee of 2.625% on the amount on a quarterly basis. On March 27, 2017, the letters of credit were amended, reducing the issued amount to $11 million.

Energy Center Minneapolis LLC Series D Notes

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 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.

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.

Avenal

On March 18, 2015, Avenal, one of the Company's equity method investments, amended its credit agreement to increase its borrowings by $43 million and to reduce the related interest rate from 6 month LIBOR plus an applicable margin of 2.25% to 6 month LIBOR plus 1.75% from March 18, 2015, through March 17, 2022, 6 month LIBOR plus 2.00% from March 18, 2022, through March 17, 2027, and 6 month LIBOR plus 2.25% from March 18, 2027, through the maturity date.  As a result of the credit agreement amendment, the Company received net proceeds of $20 million after fees from its 49.95% ownership in Avenal. Effective September 30, 2015, the Company increased its ownership to 50% by acquiring an additional 0.05% membership interest in Avenal.

Lease financing arrangements

Alta Wind Holdings (Alta Wind II - V) and Alta I (operating entities) have finance lease obligations issued under lease transactions whereby the respective operating entities sold and leased back undivided interests in specific assets of the project. The sale and related lease transactions are accounted for as financing arrangements as the operating entities have continued involvement with the property. The terms and conditions of each facility lease are substantially similar. Each operating entity makes rental payments as stipulated in the facility lease agreements on a semiannual basis every June 30 and December 30 through the final maturity dates. In addition, the operating entities have a credit agreement with a group of lenders that provides for the issuance of letters of credit to support certain operating and debt service obligations. Certain operations and maintenance, as well as rent reserve requirements are satisfied by letters of credit issued under the NRG Yield Operating agreement. As of December 31, 2016, $965 million was outstanding under the finance lease obligations, and $119 million of letters of credit were issued under the credit agreement and $23 million were issued under the Yield Credit Facility.

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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. In connection with the acquisition of the Alta Wind Portfolio in 2015, as described in Note 3, Business Acquisitions, the Company acquired thirty-one additional interest rate swaps, thirty of which were settled during 2015. During 2015, the Company acquired thirty-two additional interest rate swaps in connection with the January 2015 and November 2015 Drop Downs, as described in Note 3, Business Acquisitions.

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, 2016:

	% of Principal		Fixed Interest Rate		Floating Interest Rate	Notional Amount at December 31, 2016 (In millions)		Effective Date	Maturity Date
Alpine	85	%	2.744	%	3-Month LIBOR	$	115	various	December 31, 2029
Alpine	85	%	2.421	%	3-Month LIBOR	8		June 24, 2014	June 30, 2025
Avra Valley	85	%	2.333	%	3-Month LIBOR	49		November 30, 2012	November 30, 2030
AWAM	100	%	2.47	%	3-Month LIBOR	18		May 22, 2013	May 15, 2031
Blythe	75	%	3.563	%	3-Month LIBOR	14		June 25, 2010	June 25, 2028
Borrego	75	%	1.125	%	3-Month LIBOR	7		April 3, 2013	June 30, 2020
El Segundo	75	%	2.417	%	3-Month LIBOR	330		November 30, 2011	August 31, 2023
Kansas South	75	%	2.368	%	6-Month LIBOR	23		June 28, 2013	December 31, 2030
Laredo Ridge	75	%	2.31	%	3-Month LIBOR	79		March 31, 2011	March 31, 2026
Marsh Landing	75	%	3.244	%	3-Month LIBOR	342		June 28, 2013	June 30, 2023
Roadrunner	75	%	4.313	%	3-Month LIBOR	28		September 30, 2011	December 31, 2029
South Trent	75	%	3.265	%	3-Month LIBOR	43		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	155		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	231		December 15, 2016	September 30, 2036
Viento Funding II	90	%	various		6-Month LIBOR	160		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	276		June 28, 2013	May 31, 2023
WCEP Holdings	90	%	4.003	%	3-Month LIBOR	46		June 28, 2013	May 31, 2023
Total						$	2,070

Annual Maturities

Annual payments based on the maturities of the Company's debt, for the years ending after December 31, 2016, are as follows:

	(In millions)
2017	$	291
2018	304
2019	665
2020	654
2021	452
Thereafter	3,718
Total	$	6,084

Note 11 — 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

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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 prior periods presented below 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 earnings per share is shown in the following table:

	Year Ended December 31, 2016				Year Ended December 31, 2015				Year Ended December 31, 2014
(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 earnings per share attributable to NRG Yield, Inc. common stockholders
Net income attributable to NRG Yield, Inc.	$	20	$	37	$	14	$	19	$	8	$	8
Weighted average number of common shares outstanding — basic and diluted	35		63		35		49		28		28
Earnings per weighted average common share — basic and diluted	$	0.58	$	0.58	$	0.40	$	0.40	$	0.30	$	0.30

^(a) Net income attributable to NRG Yield, Inc. and basic and diluted 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,
	2016	2015	2014
	(In millions of shares)
2019 Convertible Notes - Common Class A	15	15	12
2020 Convertible Notes - Common Class C	10	5	—

Note 12 — 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 return for the issuance of these shares, the Company received $468 million, net of underwriting discounts and commissions of $27 million. 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 $395 million of the 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.

On July 29, 2014, the Company issued 12,075,000 shares of Class A common stock for net proceeds, after underwriting discount and expenses, of $630 million. The Company utilized the proceeds of the offering 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 Class C common stock and Class D common stock have the same rights and privileges and rank equally, share ratably and are identical in all respects to the shares of Class A common stock and Class B common stock, respectively, as to all matters, except that each share of Class C common stock and Class D common stock is entitled to 1/100th of a vote on all stockholder matters. The par value per share of the Company’s Class A common stock and Class B common stock remains unchanged at $0.01 per share after the effect of the stock split described above. Accordingly, the stock split was accounted for as a stock dividend. The Company recorded a transfer between retained earnings and common stock equal to the par value of each share of Class C common stock and Class D common stock that was issued. 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.

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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 and, as a result, it currently owns 53.3% of the economic interests of NRG Yield LLC, with NRG retaining 46.7% of the economic interests of NRG Yield LLC.

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, 2016:

	Fourth Quarter 2016		Third Quarter 2016		Second Quarter 2016		First Quarter 2016
Dividends per Class A share	$	0.25	$	0.24	$	0.23	$	0.225
Dividends per Class C share	$	0.25	$	0.24	$	0.23	$	0.225

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, 2017, the Company declared a quarterly dividend on its Class A and Class C common stock of $0.26 per share, payable on March 15, 2017, to stockholders of record as of March 1, 2017.

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 to NRG

The following table lists the distributions paid to NRG during the year ended December 31, 2016:

	Fourth Quarter 2016		Third Quarter 2016		Second Quarter 2016		First Quarter 2016
Distributions per Class B unit	$	0.25	$	0.24	$	0.23	$	0.225
Distributions per Class D unit	$	0.25	$	0.24	$	0.23	$	0.225

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, 2017, NRG Yield LLC declared a quarterly distribution on its Class B and Class D common stock of $0.26 per unit, payable to NRG on March 15, 2017.

During the first quarter of 2017 and the years ended December 31, 2016, 2015 and 2014, 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 March 2017 Drop Down Assets of $8 million was recorded as a contribution from NRG and increased the balance of its noncontrolling interest in 2017. 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 and reduced the balance of its noncontrolling interest in 2016. The difference between the cash paid and historical value of the January 2015 and November 2015 Drop Down Assets of $109 million, as well as $32 million of AOCL, was recorded as a contribution from NRG and increased the balance of its noncontrolling interest in 2015. The difference between the cash paid and historical value of the June 2014 Drop Down Assets of $113 million was recorded as a distribution to NRG and reduced the balance of its noncontrolling interest in 2014.  In addition, as the projects were owned by NRG prior to the Company’s acquisitions, the pre-acquisition earnings 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. In addition, NRG maintained a 25% ownership interest in the Class B interests of NRG Wind TE Holdco.  This 25% interest is also reflected within the Company’s noncontrolling interest balance.

41

Note 13 — 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, 2016, 2015 and 2014:

	2016		2015		2014
Customer	Conventional (%)	Renewables (%)	Conventional (%)	Renewables (%)	Conventional (%)	Renewables (%)
SCE	21%	21%	23%	17%	24%	7%
PG&E	12%	11%	13%	12%	15%	13%

	Year ended December 31, 2016
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	333		$	518		$	170		$	—		$	1,021
Cost of operations	66			126			114			—			306
Depreciation and amortization	80			197			20			—			297
Impairment losses	—			183			—			—			183
General and administrative	—			—			—			16			16
Acquisition-related transaction and integration costs	—			—			—			1			1
Operating income (loss)	187			12			36			(17		)	218
Equity in earnings of unconsolidated affiliates	13			47			—			—			60
Other income, net	1			2			—			—			3
Interest expense	(48		)	(147		)	(7		)	(78		)	(280		)
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 investment in affiliates	$	106		$	1,046		$	—		$	—		$	1,152
Capital expenditures (a)	7			2			14			—			23
Total Assets	$	1,993		$	5,988		$	426		$	429		$	8,836

^(a) Includes accruals.

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	Year ended December 31, 2015
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	336		$	443		$	174		$	—		$	953
Cost of operations	59			136			126			—			321
Depreciation and amortization	81			197			19			—			297
General and administrative	—			—			—			12			12
Acquisition-related transaction and integration costs	—			—			—			3			3
Operating income (loss)	196			110			29			(15		)	320
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		)	(147		)	(7		)	(61		)	(263		)
Income (loss) before income taxes	156			(20		)	22			(76		)	82
Income tax expense	—			—			—			12			12
Net Income (Loss)	$	156		$	(20	)	$	22		$	(88	)	$	70
Balance Sheet
Equity investments in affiliates	$	110		$	687		$	—		$	—		$	797
Capital expenditures (a)	4			6			20			—			30
Total Assets	$	2,102		$	6,070		$	428		$	189		$	8,789

^(a) Includes accruals.

	Year ended December 31, 2014
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	317		$	316		$	195		$	—		$	828
Cost of operations	55			83			139			—			277
Depreciation and amortization	82			133			18			—			233
General and administrative	—			—			—			8			8
Acquisition-related transaction and integration costs	—			—			—			4			4
Operating income (loss)	180			100			38			(12		)	306
Equity in earnings of unconsolidated affiliates	14			8			—			—			22
Other income, net	—			5			—			1			6
Loss on debt extinguishment	—			(1		)	—			—			(1		)
Interest expense	(53		)	(126		)	(7		)	(30		)	(216		)
Income (loss) before income taxes	141			(14		)	31			(41		)	117
Income tax expense	—			—			—			4			4
Net Income (Loss)	$	141		$	(14	)	$	31		$	(45	)	$	113

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Note 14 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following amounts:

	Year Ended December 31,
	2016			2015			2014
	(In millions, except percentages)
Current
U.S. Federal	$	—		$	—		$	—
State	—			—			—
Total — current	—			—			—
Deferred
U.S. Federal	(1		)	10			2
State	—			2			2
Total — deferred	(1		)	12			4
Total income tax (benefit) expense	$	(1	)	$	12		$	4
Effective tax rate	(100.0		)%	14.6		%	3.4		%

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

	Year Ended December 31,
	2016			2015			2014
	(In millions, except percentages)
Income Before Income Taxes	1			82			117
Tax at 35%	—			29			41
State taxes, net of federal benefit	—			2			1
Investment tax credits	(1		)	(1		)	—
Impact of non-taxable partnership earnings	(1		)	(17		)	(33		)
Production tax credits, including prior year true-up	4			(4		)	(6		)
Change in state effective tax rate	—			—			1
Other	(3		)	3			—
Income tax (benefit) expense	$	(1	)	$	12		$	4
Effective income tax rate	(100.0		)%	14.6		%	3.4		%

For the years ended December 31, 2016, 2015 and 2014, 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 53.3% of NRG Yield LLC and consolidates the results due to its controlling interest. The Company records NRG's 46.7% 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.

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

	As of December 31,
	2016			2015
	(In millions)
Deferred tax liabilities:
Investment in projects	$	3		$	27
Total deferred tax liabilities	3			27
Deferred tax assets:
Production tax credits carryforwards	5			10
Investment tax credits	1			1
U.S. Federal net operating loss carryforwards	226			181
State net operating loss carryforwards	3			5
Total deferred tax assets	235			197
Valuation allowance	$	(16	)	$	—
Total deferred tax assets, net of valuation allowance	$	219		$	197
Net deferred noncurrent tax asset	$	216		$	170

Tax Receivable and Payable

As of December 31, 2016, the Company had a domestic tax receivable of $6 million, which related to federal cash grants for the Borrego project. This amount is fully reserved pending further discussions with the US Treasury Department.

Deferred Tax Assets and Valuation Allowance

Net deferred tax balance — As of December 31, 2016 and 2015, NRG recorded a net deferred tax asset of $232 million and $170 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 $16 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, 2016, the Company had domestic NOLs carryforwards for federal income tax purposes of $226 million and cumulative state NOLs of $3 million tax-effected.

Uncertain Tax Positions

The Company had no identified uncertain tax positions that require evaluation as of December 31, 2016.

45

Note 15 — Related Party Transactions

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, operating costs and other income and expense.

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 and $12 million of revenues during the years ended December 31, 2015 and 2014, respectively. Included in the revenues for the years ended December 31, 2015, and 2014, are unrealized losses and gains, respectively, on forward contracts with NRG Texas Power LLC hedging the sale of power from Elbow Creek, extending through the end of 2015, as further described in Note 7, Accounting for Derivative Instruments and Hedging Activities. 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.

PPA by and between Elbow Creek and NRG

In October 2015, Elbow Creek, the Company's subsidiary in the Renewables segment, entered into a PPA with NRG Power Marketing for the sale of energy and environmental attributes with the effective date of November 1, 2015, and an expiration date of October 31, 2022. Elbow Creek generated $8 million of revenue during the year endedDecember 31, 2016.

PPA by and between NRG Energy Center Dover LLC and NRG

In February 2016, NRG Energy Center Dover LLC, or NRG Dover, a subsidiary of the Company, entered into a PPA with NRG Power Marketing for the sale of energy and environmental attributes with an effective date of February 1, 2016 and expiration date of December 31, 2018. NRG Dover generated $5 million of revenue during the year ended December 31, 2016. The agreement in place is in addition to the existing Power Sales and Services Agreement described further below.

Power Sales and Services Agreement by and between NRG Energy Center Dover LLC and NRG

NRG Dover is party to a Power Sales and Services Agreement with NRG Power Marketing. The agreement is automatically renewed on a month-to-month basis unless terminated by either party upon at least 30 day written notice. Under the agreement, NRG Power Marketing has the exclusive right to (i) manage, market and sell power, (ii) procure fuel and fuel transportation for operation of the Dover generating facility, to include for purposes other than generating power, (iii) procure transmission services required for the sale of power and (iv) procure and market emissions credits for operation of the Dover generating facility.

In addition, NRG Power Marketing has the exclusive right and obligation to direct the output from the generating facility, in accordance with and to meet the terms of any power sales contracts executed against the power generation of the Dover facility. Under the agreement, NRG Power Marketing pays NRG Dover gross receipts generated through sales, less costs incurred by NRG Power Marketing related to providing such services as transmission and delivery costs, as well as fuel costs. For the years ended December 31, 2016, 2015 and 2014, NRG Dover purchased approximately $1 million, $5 million and $10 million, respectively, of natural gas from NRG Power Marketing under the Power Sales and Services Agreement.

Energy Marketing Services Agreement by and between NRG Energy Center Minneapolis LLC and NRG

NRG Energy Center Minneapolis LLC, or NRG Minneapolis, a subsidiary of the Company is party to an Energy Marketing Services Agreement with NRG Power Marketing. The agreement commenced in August 2014 and is automatically renewed annually unless terminated by either party upon at least 90 day written notice prior to the end of any term. Under the agreement, NRG Power Marketing will procure fuel and fuel transportation for the operation of the Minneapolis generating facility. For the years ended December 31, 2016, 2015 and 2014, NRG Minneapolis purchased approximately $7 million, $8 million and $2 million, respectively, of natural gas from NRG Power Marketing.

46

Operations and Maintenance (O&M) Services Agreements by and between Thermal Entities and NRG

On October 1, 2014, NRG entered into Plant O&M Services Agreements with certain wholly-owned subsidiaries of the Company. NRG provides necessary and appropriate services to operate and maintain the subsidiaries' plant operations, businesses and thermal facilities. NRG is to be 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. Prior to October 1, 2014, NRG provided the same services to Thermal entities on an informal basis. For each of the years ended December 31, 2016 and 2015, total fees incurred under the agreements were $29 million. For the year ended December 31, 2014, total fees incurred were $27 million. There was a balance of $20 million and $29 million due to NRG in accounts payable — affiliate as of December 31, 2016, and 2015, respectively. As of December 31, 2016, $11 million of the balance was recorded in the current liabilities of the consolidated balance sheet and $9 million was recorded in non-current liabilities of the consolidated balance sheet.

O&MServices 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, $4 million and $6 million for the years ended December 31, 2016, 2015 and 2014, respectively.

O&MServices Agreements by and between El Segundo and NRG El Segundo Operations

El Segundo incurs fees under an O&M agreement with NRG El Segundo Operations, Inc., a wholly-owned subsidiary of NRG. Under the O&M agreement, NRG El Segundo Operations, Inc. manages, operates and maintains the El Segundo facility for an initial term of ten years following the commercial operations date. For each of the years ended December 31, 2016, 2015 and 2014, the costs incurred under the agreement were approximately $4 million. There was a balance of $1 million due to NRG El Segundo in accounts payable — affiliate as of December 31, 2016 and 2015.

Administrative Services Agreement by and between Marsh Landing and GenOn Energy Services, LLC and related Assignment and Assumption Agreement

Marsh Landing was a party to an administrative services agreement with GenOn Energy Services, LLC, a wholly owned subsidiary of NRG, through December 18, 2016. Under the agreement, GenOn Energy Services, LLC provided processing and invoice payment services on behalf of Marsh Landing. Marsh Landing reimbursed GenOn Energy Services, LLC for the amounts it paid. The Company reimbursed costs under this agreement of approximately $14 million for the year ended December 31, 2016, and $13 million for the years ended December 31, 2015 and 2014, respectively. For the year ended December 31, 2014, $2 million was capitalized. There was a balance of $1 million and $6 million due to GenOn Energy Services, LLC in accounts payable — affiliate as of December 31, 2016 and 2015, respectively.

Marsh Landing had the right to terminate the agreement for convenience upon thirty days prior written notice. In lieu of a termination of the agreement, Marsh Landing requested that GenOn Energy Services LLC enter into an assignment and assumption agreement with NRG West Coast LLC, a wholly owned subsidiary of NRG. The administrative services agreement was assigned to NRG West Coast LLC on December 19, 2016.

Administrative Services Agreement by and between CVSR and NRG

CVSR was a party to an administrative services agreement with NRG Energy Services, a wholly-owned subsidiary of NRG, which was subsequently assigned to NRG Renew Operations & Maintenance LLC, or RENOM, on July 15, 2015. The Company reimbursed a total of $4 million and $7 million to NRG Energy Services for the expenses incurred for the years ended December 31, 2015 and 2014, respectively. See below for further discussions of the costs incurred by CVSR under the administrative services agreement with RENOM in 2016.

Administrative Services Agreement by and between the Company and NRG Renew Operations & Maintenance LLC

Various wholly-owned subsidiaries of the Company in the Renewables segment are party to an administrative services agreement with RENOM, a wholly-owned subsidiary of NRG, which provides O&M services on behalf of these entities. The Company incurred total expenses for these services in the amount of $13 million and $7 million for the years ended December 31, 2016 and 2015, respectively. There was a balance of $5 million and $1 million due to RENOM as of December 31, 2016 and 2015, respectively.

47

O&MServices Agreements by and between Walnut Creek and NRG

Walnut Creek incurs fees under an O&M agreement with NRG Energy Services LLC, a wholly-owned subsidiary of NRG. Under the O&M agreement, NRG Energy Services LLC manages, operates and maintains the Walnut Creek facility and is reimbursed for the services provided. The Company incurred total expenses for these services in the amount of $3 million for each of the years ended December 31, 2016 and 2015 and $2 million for the year ended December 31, 2014.

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, 2016, the base management fee was approximately $7.5 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, 2016, the fee was increased by approximately $0.5 million per year, primarily due to the acquisition of the CVSR Drop Down. 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, $8 million, and $6 million for the years ended December 31, 2016, 2015, and 2014, respectively. There was a balance of $3 million in accounts payable — affiliate due to NRG as of December 31, 2016.

Administrative Services Agreements by and between Wind TE Holdco LLC and NRG

NRG Asset Services LLC, a wholly-owned subsidiary of NRG, provides support services to NRG Wind TE Holdco LLC project entities pursuant to various support services agreements. The agreements provide for administrative and support services and reimbursements of certain insurance, consultant and credit costs. For the years ended December 31, 2016, 2015 and 2014, the costs incurred under the agreements were $2 million, $3 million and $1 million, respectively.

Accounts Payable to NRG Repowering Holdings LLC

During 2013, NRG Repowering Holdings, LLC, a wholly-owned subsidiary of NRG, made payments to BA Leasing BSC, LLC, or BA Leasing, of $18 million, which were expected to be repaid with the proceeds of the cash grant received by BA Leasing with respect to the PFMG DG Solar Projects, in connection with a sale-leaseback arrangement between the PFMG DG Solar Projects and BA Leasing. As of December 31, 2014, PFMG DG Solar Projects had a corresponding receivable for the reimbursement of the cash grant from BA Leasing and related payable to NRG Repowering Holdings, LLC. In the first quarter of 2014, the PFMG DG Solar Projects received $11 million from BA Leasing and reduced the remaining receivable with an offset to the deferred liability recorded in connection with the sale - leaseback arrangement. The PFMG DG Solar Projects utilized the $11 million to repay NRG Repowering Holdings LLC. There was a balance of $7 million in accounts payable — affiliate as of December 31, 2015 which was settled in October 2016 with an offset to noncontrolling interest in the equity section of the consolidated balance sheet.

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 quarter of 2018. On January 5, 2017, the parties amended the EPC Agreement, based on a customer change order, to increase the capacity of the district energy system from 73 MWt to 80 MWt, which also increased the payment from $79 million to $87 million.

Note 16 — 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 $15 million, $10 million, and $9 million for the years ended December 31, 2016, 2015 and 2014, respectively.

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Future minimum lease commitments under operating leases for the years ending after December 31, 2016, are as follows:

Period	(In millions)
2017	$	9
2018	9
2019	10
2020	9
2021	9
Thereafter	152
Total	$	198

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, 2016, 2015 and 2014, the Company purchased $32 million, $40 million and $55 million, respectively, under such arrangements. As further described in Note 15, Related Party Transactions, these balances include intercompany purchases in the amount of $8 million, $13 million, and $12 million, respectively.

As of December 31, 2016, the Company's commitments under such outstanding agreements are estimated as follows:

Period	(In millions)
2017	$	13
2018	5
2019	2
2020	3
2021	3
Thereafter	19
Total	$	45

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. 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. On August 3, 2016, the court approved a stipulation entered into by the parties. The stipulation provided that the plaintiffs would file an amended complaint by August 19, 2016, which they did on August 18, 2016. The defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016. On February 24, 2017, the court approved the parties' stipulation which provides the plaintiffs' opposition is due on June 15, 2017 and defendants' reply is due on August 14, 2017.

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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. Oral argument is scheduled for June 20, 2017.

Note 17 — 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. Summarized unaudited quarterly financial data is as follows:

	Quarter Ended
	December 31,			September 30,		June 30,		March 31,
	2016
	(In millions, except per share data)
Operating Revenues	$	232		$	272	$	283	$	234
Operating (Loss) Income	(99		)	117		128		72
Net (Loss) Income (a)	(115		)	50		65		2
Net (Loss) Income (b)	(126		)	47		63		1
Change	11			3		2		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

^(a) The Company's unaudited quarterly financial data was recast for the effect of the March 2017 Drop Down Assets.

^(b) As previously reported.

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	Quarter Ended
	December 31,		September 30,		June 30,		March 31,
	2015
	(In millions, except per share data)
Operating Revenues	$	224	$	256	$	259	$	214
Operating Income	70		101		99		50
Net Income (Loss) (a)	12		35		44		(21		)
Net Income (Loss) (b)	12		32		42		(21		)
(Change)	—		3		2		—
Net Income (Loss) Attributable to NRG Yield, Inc.	11		17		10		(5		)
Weighted average number of Class A common shares outstanding - basic and diluted	35		35		35		35
Weighted average number of Class C common shares outstanding - basic and diluted	63		63		35		35
Earnings (Loss) per Weighted Average Class A and Class C Common Share - Basic and Diluted	$	0.12	$	0.18	$	0.15	$	(0.07	)

^(a) The Company's unaudited quarterly financial data was recast for the effect of the March 2017 Drop Down Assets.

^(b) As previously reported.

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     Schedule I

NRG Yield, Inc. (Parent)

Condensed Financial Information of Registrant

Condensed Statements of Income

	Year ended December 31,
(In millions)	2016 (a)			2015 (a)			2014 (a)
Total operating expense	$	2		$	2		$	—
Equity earnings in consolidated subsidiaries	15			93			122
Interest expense	(12		)	(9		)	(5		)
Total other (loss) income, net	3			84			117
Income Before Income Taxes	1			82			117
Income tax (benefit) expense	(1		)	12			4
Net Income	2			70			113
Less: Net (loss) income attributable to noncontrolling interests	(82		)	42			48
Less: Pre-acquisition net income (loss) of Drop Down Assets	27			(5		)	49
Net Income Attributable to NRG Yield, Inc.	$	57		$	33		$	16

^(a)Retrospectively adjusted as discussed in Note 1, Nature of Business.

See accompanying notes to condensed financial statements.

52

Schedule I

NRG Yield, Inc. (Parent)

Condensed Balance Sheets

	Year ended December 31,
	2016 (a)			2015 (a)
	(In millions)
Assets
Current Assets:
Cash and cash equivalents	$	1		$	1
Noncurrent Assets:
Investment in consolidated subsidiaries	2,304			2,640
Note receivable - Yield Operating	618			618
Deferred income taxes	216			170
Total Assets	3,139			3,429
Liabilities and Equity
Accounts payable — affiliate	—			4
Other current liabilities	2			1
Long-term debt	598			586
Total Liabilities	600			591
Stockholders' Equity:
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued	—			—
Class A, Class B, Class C and Class D common stock, $0.01 par value; 3,000,000,000 shares authorized (Class A 500,000,000, Class B 500,000,000, Class C 1,000,000,000, Class D 1,000,000,000); 182,848,000 shares issued and outstanding (Class A 34,586,250, Class B 42,738,750, Class C 62,784,250, Class D 42,738,750) at December 31, 2016 and 2015	1			1
Additional paid-in capital	1,879			1,855
(Accumulated deficit) Retained earnings	(2		)	12
Accumulated other comprehensive loss	(28		)	(27		)
Noncontrolling interest	689			997
Total Stockholders' Equity	2,539			2,838
Total Liabilities and Stockholders' Equity	$	3,139		$	3,429

^(a)Retrospectively adjusted as discussed in Note 1, Nature of Business.

See accompanying notes to condensed financial statements.

53

Schedule I

NRG Yield, Inc. (Parent)

Condensed Statements of Cash Flows

	Years ended December 31,
	2016 (a)			2015 (a)			2014 (a)
	(In millions)
Net Cash (Used in) Provided by Operating Activities	$	(5	)	$	2		$	(1	)
Cash Flows from Investing Activities
Investments in consolidated affiliates	5			(600		)	(630		)
Increase in notes receivable - affiliate	—			(281		)	(337		)
Net Cash Provided by (Used in) Investing Activities	5			(881		)	(967		)
Cash Flows from Financing Activities
Proceeds from issuance of debt	—			288			345
Proceeds from the issuance of common stock	—			599			630
Payment of debt issuance costs	—			(7		)	(7		)
Cash received from Yield LLC for the payment of dividends	92			69			41
Payment of dividends	(92		)	(69		)	(41		)
Net Cash Provided by Financing Activities	—			880			968
Net (Decrease) Increase in Cash and Cash Equivalents	—			1			—
Cash and Cash Equivalents at Beginning of Period	1			—			—
Cash and Cash Equivalents at End of Period	$	1		$	1		$	—

^(a)Retrospectively adjusted as discussed in Note 1, Nature of Business.

See accompanying notes to condensed financial statements.

54

Schedule I

NRG Yield, Inc. (Parent)

Notes to Condensed Financial Statements

Note 1 — Background and Basis of Presentation

Background

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.”

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, 2016, the Company and NRG have 53.3% and 46.7% 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.

As described in Note 3, Business Acquisitions to the Company's consolidated financial statements on March 27, 2017, the Company acquired the following interests from NRG, referred to as the March 2017 Drop Down Assets: (i) Agua Caliente Borrower 2 LLC, which owns a 16% interest in the Agua Caliente solar farm, one of the NRG ROFO assets and (ii) NRG's interests in seven utility-scale solar farms located in Utah that were part of NRG's November 2, 2016 acquisition of projects from SunEdison, or Utah Solar Portfolio. The Company paid total cash consideration of $130 million, plus a $1 million working capital adjustment, and assumed non-recourse debt of $328 million, which is consolidated, as well as its pro-rata share of non-recourse project-level debt of $135 million. The acquisition was funded with cash on hand. The acquisition of the March 2017 Drop Down Assets was accounted for as a transfer of entities under common control. 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 Aqua Caliente Borrower 2 LLC from the beginning of the financial statement period, and its interests in the Utah Solar Portfolio from November 2, 2016. The recast for the March 2017 Drop Down Assets did not affect the historical net income attributable to NRG Yield, Inc. weighted average number of shares outstanding, earnings per share or dividends.

Note 2 — 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.

Note 3 — 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.

55

Note 4 — Dividends

Cash distributions paid to NRG Yield, Inc. by its subsidiary, NRG Yield LLC, were $92 million, $69 million, and $41 million for the years ended December 31, 2016, 2015, and 2014, respectively.

56

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS

For the Year Ended December 31, 2016

	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Balance at End of Period
	(In millions)
Income tax valuation allowance, deducted from deferred tax assets
Year Ended December 31, 2016	$	—	$	—	$	16	$	16

57

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2016
Document And Entity Information [Abstract]
Entity Registrant Name	NRG YIELD, INC.
Entity Central Index Key	0001567683
Document Type	8-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false

XML

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions		3 Months Ended				12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Operating Revenues
Total operating revenues		$ 232	$ 272	$ 283	$ 234	$ 1,021	[1]	$ 953	[1]	$ 828	[1]
Operating Costs and Expenses
Cost of operations	[1]					306		321		277
Depreciation and amortization	[1]					297		297		233
Impairment losses	[1],[2]					183		0		0
General and administrative	[1]					16		12		8
Acquisition-related transaction and integration costs	[1]					1		3		4
Total operating costs and expenses	[1]					803		633		522
Operating Income		(99)	117	128	72	218	[1]	320	[1]	306	[1]
Other Income (Expense)
Equity in earnings of unconsolidated affiliates	[1],[2]					60		31		22
Other income, net	[1]					3		3		6
Gains (Losses) on Extinguishment of Debt	[1],[2]					0		(9)		(1)
Interest expense	[1]					(280)		(263)		(216)
Total other expense, net	[1]					(217)		(238)		(189)
Income Before Income Taxes	[1]					1		82		117
Income tax (benefit) expense	[1]					(1)		12		4
Net Income		(126)	47	63	1	2	[1],[2]	70	[1],[2],[3]	113	[1],[2],[3]
Less: Pre-acquisition net income (loss) of Drop Down Assets	[1],[3]					27		(5)		49
Net (Loss) Income Excluding Pre-acquisition Net Income (Loss) of Drop Down Assets	[1]					(25)		75		64
Less: Net (loss) income attributable to noncontrolling interests	[1]					(82)		42		48
Net income attributable to NRG Yield, Inc.		$ (13)	$ 33	$ 32	$ 5	57	[1]	33	[1]	16	[1]
Earnings Per Share Attributable to NRG Yield, Inc. Class A and Class C Common Stockholders
Earnings Per Share, Basic		$ (0.14)	$ 0.34	$ 0.33	$ 0.05
Dividends Per Class A Common Share		$ 0.25	$ 0.24	$ 0.23
Noncontrolling Interest [Member]
Other Income (Expense)
Less: Pre-acquisition net income (loss) of Drop Down Assets						27		(5)		49
Net (Loss) Income Excluding Pre-acquisition Net Income (Loss) of Drop Down Assets						(82)		42		$ 48
Common Class A [Member]
Other Income (Expense)
Net income attributable to NRG Yield, Inc.						$ 20		$ 14
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	[1]					35		35		28
Weighted Average Number of Shares Outstanding, Diluted		35	49	49	35
Weighted Average Number of Shares Outstanding, Basic		35	35	35	35
Earnings per weighted average common share — basic and diluted	[1],[4]					$ 0.58		$ 0.40		$ 0.30
Earnings Per Share, Diluted		$ (0.14)	$ 0.30	$ 0.29	$ 0.05
Dividends Per Class A Common Share					$ 0.225	$ 0.945	[1]	$ 1.015	[1]	$ 1.42	[1]
Common Class C [Member]
Other Income (Expense)
Net income attributable to NRG Yield, Inc.						$ 37		$ 19
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	[1]					63		49		28
Weighted Average Number of Shares Outstanding, Diluted		63	73	73	63
Weighted Average Number of Shares Outstanding, Basic		63	63	63	63
Earnings Per Share, Basic	[4]					$ 0.58		$ 0.40
Earnings Per Share, Diluted		$ (0.14)	$ 0.32	$ 0.31	$ 0.05
Dividends Per Class A Common Share	[1]					$ 0.945		$ 0.625

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[3] Retrospectively adjusted as discussed in Note 1, Nature of Business.

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

XML

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Other Comprehensive Income (Loss), net of tax
Net Income	[1],[2]	$ 2	$ 70	[3]	$ 113	[3]
Unrealized gain (loss) on derivatives, net of income tax benefit of $0, $10, and $5		0	(21)		(74)
Mark-to-market of cash flow hedge accounting contracts	[3]	13	(7)		(60)
Other comprehensive income (loss)	[3]	13	(7)		(60)
Comprehensive Income	[3]	15	63		53
Less: Pre-acquisition net income (loss) of Drop Down Assets	[1],[3]	27	(5)		49
Less: Comprehensive (loss) income attributable to noncontrolling interests	[3]	(68)	53		(3)
Comprehensive Income Attributable to NRG Yield, Inc.	[3]	$ 56	$ 15		$ 7

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[3] Retrospectively adjusted as discussed in Note 1, Nature of Business.

XML

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Unrealized gain/loss on derivatives, income tax benefit/(expense)	$ 0	$ 10	$ 5

XML

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	[1],[2]	$ 322	$ 111
Restricted cash	[1]	165	131
Accounts receivable — trade	[1]	92	101
Inventory	[1]	39	36
Derivative instruments	[1]	2	0
Notes receivable — current	[1]	16	17
Prepayments and other current assets	[1]	20	20
Total current assets	[1]	656	416
Property, plant and equipment
Under construction		25	9
Total property, plant and equipment		6,411	6,660
Less accumulated depreciation		(951)	(782)
Property, plant and equipment, net	[1]	5,460	5,878
Other Assets
Equity investments in affiliates	[1]	1,152	797
Notes receivable — non-current	[1]	14	30
Intangible assets, net	[1]	1,286	1,362
Derivative instruments	[1]	1	0
Deferred income taxes	[1]	216	170
Other non-current assets	[1]	51	136
Total other assets	[1]	2,720	2,495
Total Assets	[1]	8,836	8,789
Current Liabilities
Current portion of long-term debt	[1]	291	264
Accounts payable	[1]	23	23
Accounts payable — affiliate	[1]	40	86
Derivative instruments	[1]	32	39
Accrued expenses and other current liabilities	[1]	86	77
Total current liabilities	[1]	472	489
Other Liabilities
Long-term debt	[1]	5,696	5,329
Due to Related Parties, Noncurrent	[1]	9	0
Derivative instruments	[1]	44	61
Other non-current liabilities	[1]	76	72
Total non-current liabilities	[1]	5,825	5,462
Total Liabilities	[1]	6,297	5,951
Stockholders' Equity
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued	[1]	0	0
Common Stock, Value, Issued	[1]	1	1
Additional Paid in Capital	[1]	1,879	1,855
(Accumulated deficit) Retained earnings	[1]	(2)	12
Accumulated other comprehensive loss	[1]	(28)	(27)
Noncontrolling interest	[1]	689	997
Total Stockholders' Equity	[1]	2,539	2,838
Total Liabilities and Stockholders’ Equity	[1]	$ 8,836	$ 8,789

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015	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
Common Class A [Member]
Common Stock, Par or Stated Value Per Share	$ 0.01
Common Stock, Shares Authorized			500,000,000
Common Class B [Member]
Common Stock, Shares Authorized			500,000,000

XML

Consolidated Statements Of Cash Flows - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Cash Flows from Operating Activities
Net Income	[1],[2]	$ 2		$ 70	[3]	$ 113	[3]
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of unconsolidated affiliates	[1],[2]	60		31		22
Distributions from unconsolidated affiliates	[2]	58		60		21
Depreciation, amortization and ARO accretion	[2]	300		299		235
Amortization of financing costs and debt discounts	[2]	20		16		11
Amortization of intangibles and out-of-market contracts	[2]	75		54		28
Loss on debt extinguishment	[1],[2]	0		9		1
Change in deferred income taxes	[2]	(1)		12		4
Impairment losses	[1],[2]	183		0		0
Changes in derivative instruments	[2]	(15)		(43)		(12)
Loss on disposal of asset components	[2]	(6)		(3)		0
Changes in prepaid and accrued capacity payments	[2]	8		12		0
Changes in other working capital	[2]	9		(15)		(17)
Net Cash Provided by Operating Activities	[2]	569		422		362
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired	[2]	0		(37)		(901)
Acquisition of Drop Down Assets, net of cash acquired	[2]	77		698		311
Capital expenditures	[2]	(20)		(29)		(60)
Receipt of indemnity from supplier	[2]	0		0		57
(Increase) decrease in restricted cash	[2]	(34)		(1)		25
Cash receipts from notes receivable	[2]	(17)		(17)		(14)
Proceeds from renewable energy grants	[2]	0		0		422
Return of investment from unconsolidated affiliates	[2]	28		42		4
Investments in unconsolidated affiliates	[2]	(83)		(402)		(2)
Other	[2]	4		0		11
Net Cash Used in Investing Activities	[2]	(165)		(1,108)		(741)
Cash Flows from Financing Activities
Contributions from tax equity investors, net of distributions	[2]	5		122		190
Capital contributions from NRG	[2]	0		0		2
Distributions and return of capital to NRG prior to the acquisition of Drop Down Assets	[2]	(170)		(76)		(333)
Proceeds from the issuance of common stock	[2]	0		599		630
Payments of dividends and distributions	[2]	(183)		(139)		(101)
Proceeds from the revolving credit facility	[2]	60		551		500
Payments for the revolving credit facility	[2]	(366)		(245)		0
Proceeds from issuance of long-term debt	[2]	740		293		523
Payments of debt issuance costs	[2]	(15)		(13)		(36)
Payments for long-term debt	[2]	(264)		(724)		(626)
Net Cash Provided by Financing Activities	[2]	(193)		368		749
Net Increase (Decrease) in Cash and Cash Equivalents	[2]	211		(318)		370
Cash and Cash Equivalents at Beginning of Period	[2]	111	[4]	429		59
Cash and Cash Equivalents at End of Period	[2]	322	[4]	111	[4]	429
Interest paid, net of amount capitalized	[2]	(266)		(274)		(192)
Additions (reductions) to fixed assets for accrued capital expenditures	[2]	3		1		(21)
Decrease to fixed assets for accrued grants	[2]	0		0		(34)
Decrease to fixed assets for deferred tax asset	[2]	0		(19)		7
Non-cash adjustment for change in tax basis of assets	[2]	44		38		(14)
Increase in debt due to accrued interest converted to debt	[2]	0		0		11
Non-cash return of capital and distributions to NRG, net of contributions	[2]	$ 66		$ (13)		$ 1,058

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[3] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[4] Retrospectively adjusted as discussed in Note 1, Nature of Business.

XML

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]	[1]	$ 1,588,000,000		$ 0	$ 0	$ 621,000,000	$ 8,000,000	$ 0	$ 959,000,000
Total Stockholders' Equity		1,693,000,000				621,000,000	8,000,000	0	1,064,000,000
Noncontrolling Interest, Assets Acquired, Drop Down Assets		105,000,000		0	0	0	0	0	105,000,000
Net Income Excluding Pre-acquisition Net (Loss) Income of Drop Down Assets		64,000,000	[2]	0	0	0	16,000,000	0	48,000,000
Less: Pre-acquisition net income (loss) of Drop Down Assets		49,000,000	[2],[3]	0	0	0	0	0	49,000,000
Unrealized gain/(loss) on derivatives		(60,000,000)		0	0	0	0	(9,000,000)	(51,000,000)
Gross Payment to Acquire Business under Common Control		(357,000,000)		0	0	0	0	0	(357,000,000)
Payment to Acquire Business under Common Control	[4]	(311,000,000)
Contributions from tax equity investors, net of distributions		190,000,000	[4]	0	0	0	0	0	190,000,000
Non-cash return of capital and distributions to NRG, net of contributions		1,058,000,000	[4]	0	0	0	0	0	1,058,000,000
Payment of capital distributions and returns of capital, net of capital contributions		(331,000,000)		0	0	0	0	0	(331,000,000)
Proceeds from the issuance of common stock		630,000,000	[4]	0	0	630,000,000	0	0	0
Non-cash adjustment for change in tax basis of assets		(14,000,000)	[4]	0	0	(14,000,000)	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		(101,000,000)		0	0	(20,000,000)	(21,000,000)	0	(60,000,000)
Total Stockholders' Equity		2,844,000,000		0	0	1,240,000,000	3,000,000	(9,000,000)	1,610,000,000
Net Income Excluding Pre-acquisition Net (Loss) Income of Drop Down Assets		75,000,000	[2]	0	0	0	33,000,000	0	42,000,000
Less: Pre-acquisition net income (loss) of Drop Down Assets		(5,000,000)	[2],[3]	0	0	0	0	0	(5,000,000)
Unrealized gain/(loss) on derivatives		(7,000,000)		0	0	0	0	(18,000,000)	11,000,000
Payment to Acquire Business under Common Control		(698,000,000)	[4]	0	0	0	0	0	(698,000,000)
Contributions from tax equity investors, net of distributions		122,000,000	[4]	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		(13,000,000)	[4]	0	0	0	0	0	(13,000,000)
Payment of capital distributions and returns of capital, net of capital contributions		(76,000,000)		0	0	0	0	0	(76,000,000)
Share-based Compensation		1,000,000		0	0	1,000,000	0	0	0
Proceeds from the issuance of common stock		599,000,000	[4]	0	1,000,000	598,000,000	0	0	0
Non-cash adjustment for change in tax basis of assets		38,000,000	[4]	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		2,838,000,000	[5]	0	1,000,000	1,855,000,000	12,000,000	(27,000,000)	997,000,000
Net Income Excluding Pre-acquisition Net (Loss) Income of Drop Down Assets		(25,000,000)	[2]	0	0	0	57,000,000	0	(82,000,000)
Less: Pre-acquisition net income (loss) of Drop Down Assets		27,000,000	[2],[3]	0	0	0	0	0	27,000,000
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)	[4]	0	0	0	0	0	(77,000,000)
Contributions from tax equity investors, net of distributions		5,000,000	[4]	0	0	0	0	0	5,000,000
Non-cash return of capital and distributions to NRG, net of contributions		66,000,000	[4]	0	0	0	0	0	66,000,000
Payment of capital distributions and returns of capital, net of capital contributions		(180,000,000)		0	0	0	0	0	(180,000,000)
Share-based Compensation		1,000,000		0	0	1,000,000	0	0	0
Proceeds from the issuance of common stock	[4]	0
Non-cash adjustment for change in tax basis of assets		44,000,000	[4]	0	0	44,000,000	0	0	0
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt		23,000,000
Payments of Ordinary Dividends, Common Stock		(173,000,000)		0	0	(21,000,000)	(71,000,000)	0	(81,000,000)
Total Stockholders' Equity		$ 2,539,000,000	[5]	$ 0	$ 1,000,000	$ 1,879,000,000	$ (2,000,000)	$ (28,000,000)	$ 689,000,000

[1] As previously reported in the Company's audited financial statements for the year ended December 31, 2016, included in the Company's 2016 Form 10-K

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[3] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[4] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[5] Retrospectively adjusted as discussed in Note 1, Nature of Business.

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Schedule 1 - Yield, Inc,'s Financial Statements NRG Yield PL - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Operating Expenses		$ 306	$ 321		$ 277
Interest Expense	[1]	(280)	(263)		(216)
Total other expense, net	[1]	(217)	(238)		(189)
Income Before Income Taxes	[1]	1	82		117
Net Income	[1],[2]	2	70	[3]	113	[3]
Income tax (benefit) expense	[1]	(1)	12		4
Less: Net (loss) income attributable to noncontrolling interests	[1]	(82)	42		48
Less: Pre-acquisition net income (loss) of Drop Down Assets	[1],[3]	27	(5)		49
Net income attributable to NRG Yield, Inc.	[1]	57	33		16
NRG Yield, Inc. [Member]
Operating Expenses	[4]	2	2		0
Equity in Earnings of Consolidated Subsidiaries	[4]	15	93		122
Interest Expense	[4]	(12)	(9)		(5)
Total other expense, net	[4]	3	84		117
Income Before Income Taxes	[4]	1	82		117
Net Income	[4]	2	70		113
Income tax (benefit) expense	[4]	(1)	12		4
Less: Net (loss) income attributable to noncontrolling interests	[4]	(82)	42		48
Less: Pre-acquisition net income (loss) of Drop Down Assets	[4]	27	(5)		49
Net income attributable to NRG Yield, Inc.	[4]	$ 57	$ 33		$ 16

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[3] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[4] Retrospectively adjusted as discussed in Note 1, Nature of Business.

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Schedule 1 - Yield, Inc,'s Financial Statements NRG Yield BS - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Less: Pre-acquisition net income of Acquired ROFO assets	[1],[2]	$ 27,000	$ (5,000)
Income Before Income Taxes	[1]	1,000	82,000
Cash and cash equivalents	[3],[4]	322,000	111,000
Deferred Tax Assets, Gross	[3]	216,000	170,000
Total Assets	[3]	8,836,000	8,789,000
Debt (Current and non-current) (a)		6,057,000	5,656,000
Total Liabilities	[3]	6,297,000	5,951,000
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued	[3]	0	0
Common Stock, Value, Issued	[3]	1,000	1,000
Additional Paid in Capital	[3]	1,879,000	1,855,000
(Accumulated deficit) Retained earnings	[3]	(2,000)	12,000
Accumulated other comprehensive loss	[3]	(28,000)	(27,000)
Noncontrolling interest	[3]	689,000	997,000
Total Stockholders' Equity	[3]	2,539,000	2,838,000
Total Liabilities and Stockholders’ Equity	[3]	$ 8,836,000	$ 8,789,000
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
Common Class A [Member]
Common Stock, Par or Stated Value Per Share		$ 0.01
NRG Yield, Inc. [Member]
Less: Pre-acquisition net income of Acquired ROFO assets	[5]	$ 27,000	$ (5,000)
Income Before Income Taxes	[5]	1,000	82,000
Cash and cash equivalents	[6]	1,000	1,000
Investments in subsidiaries	[6]	2,304,000	2,640,000
Notes Receivable, Related Parties	[6]	618,000	618,000
Deferred Tax Assets, Gross	[6]	216,000	170,000
Total Assets	[6]	3,139,000	3,429,000
Deferred income taxes	[6]	0	4,000
Other Liabilities, Current	[6]	2,000	1,000
Debt (Current and non-current) (a)	[6]	598,000	586,000
Total Liabilities	[6]	600,000	591,000
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued	[6]	0	0
Common Stock, Value, Issued	[6]	1,000	1,000
Additional Paid in Capital	[6]	1,879,000	1,855,000
(Accumulated deficit) Retained earnings	[6]	(2,000)	12,000
Accumulated other comprehensive loss	[6]	(28,000)	(27,000)
Noncontrolling interest	[6]	689,000	997,000
Total Stockholders' Equity	[6]	2,539,000	2,838,000
Total Liabilities and Stockholders’ Equity	[6]	$ 3,139,000	$ 3,429,000
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		62,784,250	34,586,250
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	[7]	$ 1,000	$ 1,000

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[3] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[4] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[5] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[6] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[7] Retrospectively adjusted as discussed in Note 1, Nature of Business.

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Schedule 1 - Yield, Inc,'s Financial Statements NRG Yield CF $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($)		Dec. 31, 2015 USD ($)		Dec. 31, 2014 USD ($)
Operating income	$ 218,000	[1]	$ 320,000	[1]	$ 306,000	[1]
Net Cash Provided by (Used in) Operating Activities	569,000	[2]	422,000	[2]	362,000	[2]
Proceeds from Issuance of Long-term Debt	740,000	[2]	293,000	[2]	523,000	[2]
Net Cash Used in Investing Activities	(165,000)	[2]	(1,108,000)	[2]	(741,000)	[2]
Proceeds from the issuance of common stock	0	[2]	599,000	[2]	630,000	[2]
Payments of Ordinary Dividends, Common Stock	(173,000)		(139,000)		(101,000)
Net Cash Provided by Financing Activities	(193,000)	[2]	368,000	[2]	749,000	[2]
Net Increase (Decrease) in Cash and Cash Equivalents	211,000	[2]	(318,000)	[2]	370,000	[2]
Cash and cash equivalents	322,000	[2],[3]	111,000	[2],[3]	429,000	[2]
NRG Yield [Member]
Net Cash Provided by (Used in) Operating Activities	(5,000)	[4]	2,000	[4]	(1,000)	[4]
Investment in consolidated subsidiaries	5,000	[4]	(600,000)	[4]	(630,000)	[4]
Proceeds from Issuance of Long-term Debt	0	[4]	288,000	[4]	345,000	[4]
Increase (Decrease) in Notes Receivable, Related Parties	0	[4]	(281,000)	[4]	(337,000)	[4]
Net Cash Used in Investing Activities	5,000	[4]	(881,000)	[4]	(967,000)	[4]
Proceeds from the issuance of common stock	0	[4]	599,000	[4]	630,000	[4]
Payments of Financing Costs	0	[4]	(7,000)	[4]	(7,000)	[4]
Proceeds from Contributions from Affiliates	92,000	[4]	69,000	[4]	41,000	[4]
Payments of Ordinary Dividends, Common Stock	(92,000)	[4]	(69,000)	[4]	(41,000)	[4]
Net Cash Provided by Financing Activities	0	[4]	880,000	[4]	968,000	[4]
Net Increase (Decrease) in Cash and Cash Equivalents	0	[4]	1,000	[4]	0	[4]
Cash and cash equivalents	$ 1,000	[4]	$ 1,000	[4]	$ 0	[4]

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[3] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[4] Retrospectively adjusted as discussed in Note 1, Nature of Business.

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Schedule 1 - Yield, Inc,'s Financial Statements Footnotes - USD ($) $ in Millions					12 Months Ended
		Jun. 29, 2015	Jul. 29, 2014	Jul. 22, 2013	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Nature of Business [Line Items]
Payments of Capital Distribution	[1]				$ 170		$ 76		$ 333
Proceeds from the issuance of common stock				$ 468	0	[1]	599	[1]	630	[1]
NRG Yield [Member]
Nature of Business [Line Items]
Proceeds from the issuance of common stock	[2]				0		599		630
Common Class C [Member]
Nature of Business [Line Items]
Proceeds from the issuance of common stock		$ 599
NRG Yield LLC [Member] | NRG Yield, Inc. [Member]
Nature of Business [Line Items]
Payments of Capital Distribution					$ 92		$ 69		$ 41
Public Shareholders [Member] | Common Class A [Member]
Nature of Business [Line Items]
Sale of Stock, Number of Shares Issued in Transaction			12,075,000	22,511,250
Proceeds from the issuance of common stock			$ 630
NRG Yield [Member] | NRG Yield [Member]
Nature of Business [Line Items]
Sale of Stock, Number of Shares Issued in Transaction		28,198,000

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

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Nature of Business

12 Months Ended

Dec. 31, 2016

Nature of Business Disclosure [Abstract]

Nature of Business

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.”

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, 2016, the Company and NRG have 53.3% and 46.7% 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.

The following table represents the structure of the Company as of December 31, 2016:

As of December 31, 2016, 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	2035
Desert Sunlight 300	25	%	75	Pacific Gas and Electric	2040
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 (e)	50	%	265	PacifiCorp	2036
			921
Distributed Solar
AZ DG Solar Projects	100	%	5	Various	2025 - 2033
PFMG DG Solar Projects	51	%	4	Various	2032
			9
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)	74.3	%	16	Corn Belt Power Cooperative	2027
Elbow Creek (b)	75	%	92	NRG Power Marketing LLC	2022
Elkhorn Ridge (b)	50.3	%	41	Nebraska Public Power District	2029
Forward (b)	75	%	22	Constellation NewEnergy, Inc.	2017
Goat Wind (b)	74.9	%	113	Dow Pipeline Company	2025
Hardin (b)	74.3	%	11	Interstate Power and Light Company	2027
Laredo Ridge	100	%	80	Nebraska Public Power District	2031
Lookout (b)	75	%	29	Southern Maryland Electric Cooperative	2030
Odin (b)	74.9	%	15	Missouri River Energy Services	2028
Pinnacle	100	%	55	Maryland Department of General Services and University System of Maryland	2031
San Juan Mesa (b)	56.3	%	68	Southwestern Public Service Company	2025
Sleeping Bear (b)	75	%	71	Public Service Company of Oklahoma	2032
South Trent	100	%	101	AEP Energy Partners	2029
Spanish Fork (b)	75	%	14	PacifiCorp	2028

Projects	Percentage Ownership		Net Capacity (MW) (a)	Offtake Counterparty	Expiration
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)	74.9	%	121	Southwestern Public Service Company	2027
			1,999
Thermal
Thermal equivalent MWt(c)	100	%	1,319	Various	Various
NRG Energy Center Dover LLC	100	%	103	NRG Power Marketing LLC	2018
Thermal generation	100	%	20	Various	Various
			1,442
Total net capacity (excluding equivalent MWt) (d)			4,997

^(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, 2016.

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

^(c) 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.

^(d) NRG Yield's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's generation capacity including this noncontrolling interest was 5,003 MWs.

^(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).

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 131 MW based on cash to be distributed. 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. Three out of the fourteen district energy systems are subject to rate regulation by state public utility commissions while the other district energy systems have rates determined by negotiated bilateral contracts.

As described in Note 15, Related Party Transactions, 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, 2016 and 2015, the Company completed three 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.

In addition, as further described in Note 3, Business Acquisitions, on March 27, 2017, the Company acquired the following interests from NRG, referred to as the March 2017 Drop Down Assets: (i) Agua Caliente Borrower 2 LLC, which owns a 16% interest in the Agua Caliente solar farm, one of the NRG ROFO assets and (ii) NRG's interests in seven utility-scale solar farms located in Utah that were part of NRG's November 2, 2016 acquisition of projects from SunEdison, or Utah Solar Portfolio. The Company paid total cash consideration of $130 million, plus a $1 million working capital adjustment, and assumed non-recourse debt of $328 million, which is consolidated, as well as its pro-rata share of non-recourse project-level debt of $135 million. The acquisition was funded with cash on hand. The acquisition of the March 2017 Drop Down Assets was accounted for as a transfer of entities under common control. 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 Aqua Caliente Borrower 2 LLC from the beginning of the financial statement period, and its interests in the Utah Solar Portfolio from November 2, 2016. The recast for the March 2017 Drop Down Assets did not affect the historical net income attributable to NRG Yield, Inc. weighted average number of shares outstanding, earnings per share or dividends.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The Company's consolidated financial statements have been prepared in accordance with 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 $110 million and $93 million as of December 31, 2016 and 2015, respectively.

Restricted Cash

Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use. Of these funds as of December 31, 2016, approximately $25 million is designated for current debt service payments, $13 million is designated to fund operating expenses and $37 million is designated for distributions to the Company, with the remaining $90 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, 2016 and 2015.

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.

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.

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 loan.

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.

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, 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.

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, 2016, 2015, and 2014 was $553 million, $416 million, and $296 million, respectively.

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, 2016 and 2015, along with the additions and accretion related to the Company's ARO obligations for the year ended December 31, 2016:

	(In millions)
Balance as of December 31, 2015	$	43
Revisions in estimates for current obligations	2
Accretion — expense	3
Balance as of December 31, 2016	$	48

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, seven of which are VIEs, where the Company is not a primary beneficiary, and two of which are owned by a subsidiary that is consolidated as a VIE, 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 amount 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 amount of net earnings during the reporting period. 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

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 were issued to address the diversity in classification and presentation of changes in restricted cash and restricted cash equivalents on the statement of cash flows which is currently not addressed under Topic 230. The amendments of ASU No. 2016-18 would 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 should be applied retrospectively.  The Company is currently evaluating the impact of the standard on the Company’s statement of cash flows.

ASU 2016-16 — In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory, or ASU No. 2016-16.  The amendments of ASU No. 2016-16 were issued to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory.  Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party which has resulted in diversity in practice and increased complexity within financial reporting.  The amendments of ASU No. 2016-16 would require an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and do not require new disclosure requirements.  The amendments of ASU No. 2016-16 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. 2016-16 should be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption.  The Company is currently evaluating the impact of the standard on the Company’s results of operations, cash flows and financial position.

ASU 2016-15 — In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments, or ASU No. 2016-15. The amendments of ASU No. 2016-15 were issued to address eight specific cash flow issues for which stakeholders have indicated to the FASB that a diversity in practice existed in how entities were presenting and classifying these items in the statement of cash flows. The issues addressed by ASU No. 2016-15 include but are not limited to the classification of debt prepayment and debt extinguishment costs, payments made for contingent consideration for a business combination, proceeds from the settlement of insurance proceeds, distributions received from equity method investees and separately identifiable cash flows and the application of the predominance principle. The amendments of ASU No. 2016-15 are effective for public entities for fiscal years beginning after December 15, 2017 and interim periods in those fiscal years. Early adoption is permitted, including adoption in an interim fiscal period with all amendments adopted in the same period. The adoption of ASU No. 2016-15 is required to be applied retrospectively. The Company is currently evaluating the impact of the standard on the Company's statement of cash flows.

ASU 2016-07 — In March 2016, the FASB issued ASU No. 2016-07, Investments - Equity Method and Joint Ventures (Topic 323), or ASU No. 2016-07. The amendments of ASU No. 2016-07 eliminate the requirement that when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations, and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. The amendments require that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting with no retroactive adjustment to the investment. In addition, ASU No. 2016-07 requires that an entity that has an available-for-sale equity security that becomes qualified for the equity method of accounting recognize through earnings the unrealized holding gain or loss in accumulated other comprehensive income at the date the investment becomes qualified for use of the equity method. The Company adopted this standard effective January 1, 2017. The adoption of ASU No. 2016-07 is required to be applied prospectively. The Company does not expect the standard to have a material impact on its results of operations, cash flows and financial position.

ASU 2016-02 — In 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 expects to adopt the standard effective January 1, 2019 utilizing the required modified retrospective approach for the earliest period presented. 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 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. As this review is still in process, it is currently not practicable to quantify the impact of adopting the ASU at this time.

ASU 2016-01 — In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, or ASU No. 2016-01. The amendments of ASU No. 2016-01 eliminate available-for-sale classification of equity investments and require that equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be generally measured at fair value with changes in fair value recognized in net income.  Further, the amendments require that financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset.  The guidance in ASU No. 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.

ASU 2015-16 — In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, or ASU No. 2015-16. The amendments of ASU No. 2015-16 require that an acquirer recognize measurement period adjustments to the provisional amounts recognized in a business combination in the reporting period during which the adjustments are determined. Additionally, the amendments of ASU No. 2015-16 require the acquirer to record in the same period's financial statements the effect on earnings of changes in depreciation, amortization or other income effects, if any, as a result of the measurement period adjustment, calculated as if the accounting had been completed at the acquisition date as well as disclosing on either the face of the income statement or in the notes the portion of the amount recorded in current period earnings that would have been recorded in previous reporting periods. The guidance in ASU No. 2015-16 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amendments should be applied prospectively. The Company adopted ASU No. 2015-16 for the year ended December 31, 2016, and the adoption did not have a material impact on the Company's results of operations, cash flows and financial position.

ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU No. 2014-09, 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 expects to adopt the standard effective January 1, 2018 and apply the guidance retrospectively to contracts at the date of adoption. The Company will recognize the cumulative effect of applying Topic 606 at the date of initial application, as prescribed under the modified retrospective transition method. The Company also expects to elect 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. As leases are excluded from the scope of Topic 606, the Company expects the standard to have an immaterial impact on the Company's results of operations, cash flows and financial position; however, the Company continues to assess the impact in connection with its plan of adoption.

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Business Acquisitions

12 Months Ended

Dec. 31, 2016

Business Acquisition

Business Acquisitions

2017 Acquisitions

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 NRG 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 $130 million, plus $1 million of working capital. The acquisition of the March 2017 Drop Down Assets was funded with cash on hand and is referred to as March 2017 Drop Down Assets. The Company recorded the acquired interests as equity method investments. The Company also assumed 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.

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).

The following tables present the Company's historical information summary combining the financial information for the March 2017 Drop Down Assets transferred in connection with the acquisitions:

	As of December 31, 2016
	As Previously Reported		March 2017 Drop Down Assets		As Currently Reported
(In millions)
Current assets	$	645	$	11	$	656
Property, plant and equipment	5,460		—		5,460
Non-current assets	2,278		442		2,720
Total assets	8,383		453		8,836
Debt	5,708		279		5,987
Other current and non-current liabilities	305		5		310
Total liabilities	6,013		284		6,297
Net assets	$	2,370	$	169	$	2,539

	As of December 31, 2015
	As Previously Reported		March 2017 Drop Down Assets		As Currently Reported
(In millions)
Current assets	$	416	$	—	$	416
Property, plant and equipment	5,878		—		5,878
Non-current assets	2,395		100		2,495
Total assets	8,689		100		8,789
Debt	5,593		—		5,593
Other current and non-current liabilities	358		—		358
Total liabilities	5,951		—		5,951
Net assets	$	2,738	$	100	$	2,838

	Year ended December 31, 2016
	As Previously Reported			March 2017 Drop Down Assets		As Currently Reported
(In millions)
Total operating revenues	$	1,021		$	—	$	1,021
Operating income	218			—		218
Net (loss) income	(15		)	17		2

	Year ended December 31, 2015
	As Previously Reported		March 2017 Drop Down Assets		As Currently Reported
(In millions)
Total operating revenues	$	953	$	—	953
Operating income	320		—		320
Net income	65		5		70

	Year ended December 31, 2014
	As Previously Reported		March 2017 Drop Down Assets		As Currently Reported
(In millions)
Total operating revenues	$	828	$	—	$	828
Operating income	306		—		306
Net income	108		5		113

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, 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 further described in Note 10, Long-term Debt. 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.

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 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 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. As of June 30, 2016, the Company's recast consolidated balance sheet included a net receivable of $67 million related to current litigation with SunPower pursuant to indemnities in the project. The agreement between NRG and the Company for the CVSR Drop Down acquisition specified that all amounts related to the litigation with SunPower were excluded from the acquisition. Accordingly, prior to close of the transaction, the net receivable was transferred to NRG as a net reduction to its ownership interest in CVSR.

The following is the summary of historical net liabilities assumed in connection with the CVSR Drop Down as of September 1, 2016:

	CVSR
	(In millions)
Current assets	$	95
Property, plant and equipment	826
Non-current assets	13
Total assets	934
Debt (a)	966
Other current and non-current liabilities	12
Total liabilities	978
Net liabilities assumed	(44		)
Accumulated other comprehensive loss	(25		)
Historical net liabilities assumed	$	(19	)

^(a) Net of deferred financing costs of $5 million.

The Company incurred and expensed acquisition-related transaction costs related to the acquisition of CVSR of $1 million for the year ended December 31, 2016. Since the acquisition date, CVSR has contributed $22 million in operating revenues and a $2 million in net loss to the Company.

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 $209 million, subject to working capital adjustments. In February 2016, NRG made a final working capital payment of $2 million, reducing total cash consideration to $207 million. The Company is 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.

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 75% of CAFD until the flip point, at which time the allocations to the Company of CAFD change to 68.60%. 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.

The following is a summary of assets and liabilities transferred in connection with the acquisition as of November 3, 2015:

	NRG Wind TE Holdco
	(In millions)
Current assets	$	30
Property, plant and equipment	669
Non-current assets	177
Total assets	876
Debt	193
Other current and non-current liabilities	32
Total liabilities	225
Less: noncontrolling interest	282
Net assets acquired	$	369

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.

2014 Acquisitions

Alta Wind Portfolio Acquisition — OnAugust 12, 2014, the Company acquired 100% of the membership interests of Alta Wind Asset Management Holdings, LLC, Alta Wind Company, LLC, Alta Wind X Holding Company, LLC and Alta Wind XI Holding Company, LLC, which collectively own seven wind facilities that total 947 MW located in Tehachapi, California, and a portfolio of associated land leases, or the Alta Wind Portfolio. Power generated by the Alta Wind Portfolio is sold to Southern California Edison under long-term PPAs with 21 years of remaining contract life for Alta I-V. The Alta Wind X and XI PPAs began in 2016 with a term of 22 years and sold energy and renewable energy credits on a merchant basis during the years ending December 31, 2015 and 2014.

The purchase price for the Alta Wind Portfolio was $923 million, which consisted of a base purchase price of $870 million, as well as a payment for working capital of $53 million, plus the assumption of $1.6 billion of non-recourse project-level debt. In order to fund the purchase price, the Company completed an equity offering of 12,075,000 shares of its Class A common stock at an offering price of $54.00 per share on July 29, 2014, which resulted in net proceeds of $630 million, after underwriting discounts and expenses. In addition, on August 5, 2014, NRG Yield Operating LLC issued $500 million of Senior Notes, which bear interest at a rate of 5.375% and mature in August 2024.

The acquisition was recorded as a business combination under ASC 805-50, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The accounting for the business combination was completed as of August 11, 2015, at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of December 31, 2014, as well as adjustments made through August 11, 2015, when the allocation became final.

The purchase price of $923 million was allocated as follows:

	Acquisition Date Fair Value at December 31, 2014		Measurement period adjustments			Revised Acquisition Date
Assets	(In millions)
Cash	$	22	$	—		$	22
Current and non-current assets	49		(2		)	47
Property, plant and equipment	1,304		6			1,310
Intangible assets	1,177		(6		)	1,171
Total assets acquired	2,552		(2		)	2,550
Liabilities
Debt	1,591		—			1,591
Current and non-current liabilities	38		(2		)	36
Total liabilities assumed	1,629		(2		)	1,627
Net assets acquired	$	923	$	—		$	923

The Company incurred and expensed acquisition-related transaction costs related to the acquisition of the Alta Wind Portfolio of $2 million for the year ended December 31, 2014.

June 2014 Drop Down Assets —On June 30, 2014, the Company acquired from NRG: (i) El Segundo, a 550 MW fast-start, gas-fired facility located in Los Angeles County, California; (ii) TA High Desert, a 20 MW solar facility located in Los Angeles County, California; and (iii) Kansas South, a 20 MW solar facility located in Kings County, California. The Company paid total cash consideration of $357 million, which represents a base purchase price of $349 million and $8 million of working capital adjustments. In addition, the acquisition included the assumption of $612 million of project-level debt. 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. The difference between the cash proceeds and the historical value of the net assets was recorded as a distribution to NRG and reduced the balance of its noncontrolling interest. Since the transaction constituted a transfer of entities 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 beginning of the financial statements period or the inception of common control (if later than the beginning of the financial statements period). Accordingly, the Company prepared its consolidated financial statements to reflect the transfer as if it had taken place from the beginning of the financial statements period.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure

Property, Plant and Equipment

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

	December 31, 2016			December 31, 2015			Depreciable Lives
	(In millions)
Facilities and equipment	$	6,215		$	6,480		2 - 40 Years
Land and improvements	171			171
Construction in progress (a)	25			9
Total property, plant and equipment	6,411			6,660
Accumulated depreciation	(951		)	(782		)
Net property, plant and equipment	$	5,460		$	5,878

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

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Investments Accounted for by the Equity Method and Variable Interest Entities

12 Months Ended

Dec. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

Investments Accounted for by the Equity Method and Variable Interest Entities

Investments Accounted for by the Equity Method and Variable Interest Entities

Equity Method Investments

The following table summarizes the Company's equity method investments as of December 31, 2016:

Name	Economic Interest	Investment Balance
		(In millions)
Utah Solar Portfolio (a)	50%	$346
Desert Sunlight	25%	282
GenConn(b)	50%	106
Agua Caliente Borrower 2	16%	96
Elkhorn Ridge(c)	50.3%	85
San Juan Mesa(c)	56.3%	74
NRG DGPV Holdco 1 LLC (d)	95%	75
NRG DGPV Holdco 2 LLC (d)	95%	24
NRG RPV Holdco 1 LLC(d)	95%	71
Avenal	50%	(7)
Total equity investments in affiliates		$1,152

^(a) Economic interest based on cash to be distributed. Four Brothers Solar, LLC, Granite Mount Holdings, LLC and Iron Spring 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 75% 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, and NRG RPV Holdco 1 LLC are tax equity structures and VIEs. The related allocations are described below.

As of December 31, 2016 and 2015, the Company had $51 million and $45 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 approximately $589 million as of December 31, 2016.

Agua Caliente Financing— As described in Note 3, Business Acquisitions, the Company acquired a 16% interest in the Agua Caliente solar facility through its acquisition of Agua Caliente Borrower 2 LLC. As of December 31, 2016, Agua Caliente Solar LLC, the direct owner of the Agua Caliente solar facility, had $849 million outstanding under the Agua Caliente financing agreement with the Federal Financing Bank, or FFB, borrowed to finance the costs of constructing the facility. The Company's pro-rata share of Agua Caliente Financing was approximately $136 million as of December 31, 2016.  Amounts borrowed under the Agua Caliente financing agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of 0.375%, mature in 2037 and are secured by the assets of Agua Caliente Solar LLC.  The loans provided by the FFB are guaranteed by the U.S. DOE. 

Avenal — The Company owns a 50% equity interest in Avenal, which consists of three solar PV projects in Kings County, California totaling approximately 45 MWs. Eurus Energy owns the remaining 50% of Avenal. Power generated by the projects is sold under a 20-year PPA. On September 22, 2010, Avenal entered into a $35 million promissory note facility with the Company. Amounts drawn under the promissory note facility accrue interest at 4.5% per annum. Also, on September 22, 2010, Avenal entered into a $209 million financing arrangement with a syndicate of banks, or the Avenal Facility. As of December 31, 2016 and 2015, Avenal had outstanding $134 million and $143 million, respectively, under the Avenal Facility.

Desert Sunlight —Desert Sunlight 250 and Desert Sunlight 300 each entered into three distinct tranches of debt. As of December 31, 2016 and 2015, Desert Sunlight had total debt outstanding of $1.1 billion under the three tranches.

GenConn — GenConn has a $237 million project note with an interest rate of 4.73% and a maturity date of July 2041 and a 5-year, $35 million working capital facility that matures in 2018 which can be used to issue letters of credit at an interest rate of 1.875% per annum. As of December 31, 2016 and 2015, $212 million and $220 million, respectively, were outstanding under the note. As of December 31, 2016, $14 million was drawn on the working capital facility. The note is secured by all of the GenConn assets. The Company's maximum exposure to loss is limited to its equity investment in GenConn, which was $106 million as of December 31, 2016.

NRG DGPV Holdco 2 LLC — On June 30, 2016, NRG DGPV4 Borrower LLC, a direct subsidiary of NRG DGPV Holdco 2 LLC entered into a financing agreement to fund the acquisition of projects by the tax equity fund.  As of December 31, 2016, there was $21 million outstanding under the facility.

Summarized Financial Information

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

	Year Ended December 31,
	2016			2015			2014
Income Statement Data:	(In millions)
GenConn
Operating revenues	$	72		$	78		$	82
Operating income	38			40			40
Net income	26			28			28
Desert Sunlight
Operating revenues	$	211		$	206		134
Operating income	129			124			74
Net income	80			73			37
Utah Solar Portfolio (a)
Operating revenues	$	13		$	—		$	—
Operating loss	(6		)	(1		)	—
Net loss	(6		)	(1		)	—
				As of December 31,
				2016			2015
Balance Sheet Data:				(In millions)
GenConn
Current assets				$	36		$	36
Non-current assets				389			416
Current liabilities				16			16
Non-current liabilities				196			215
Desert Sunlight
Current assets				$	281		$	310
Non-current assets				1,401			1,435
Current liabilities				64			82
Non-current liabilities				1,043			1,086
Utah Solar Portfolio (a)
Current assets				$	20		$	11
Non-current assets				1,105			705
Current liabilities				14			229
Non-current liabilities				38			—

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

Variable Interest Entities, or VIEs

Entities that are Consolidated

NRG Wind TE Holdco — On November 3, 2015, the Company acquired 75% of the Class B interests of NRG Wind TE Holdco, or the November 2015 Drop Down Assets, which owns a portfolio of 12 wind facilities totaling 814 net MW, from NRG for total cash consideration of $209 million, as described in Note 3, Business Acquisitions. In February 2016, NRG made a final working capital payment of $2 million, reducing total cash consideration to $207 million. NRG retained a 25% ownership of the Class B interest. 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 75% of CAFD until the flip point, at which time the allocations to the Company of CAFD change to 68.60%. 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. The Company utilizes the HLBV method to determine the net income or loss allocated to the TE Investor noncontrolling interest. Net income or loss attributable to the Class B interests is allocated to NRG's noncontrolling interest based on its 25% ownership 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 received 100% of CAFD through December 31, 2015, and subsequently will receive 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. The net proceeds of $119 million were reflected as noncontrolling interest in the Company's balance sheet.

Spring Canyon — On May 7, 2015, the Company acquired 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, from Invenergy Wind Global LLC. Invenergy owns 9.9% of the Class B interests. Prior to the acquisition date, the projects were 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 will receive 34.81% of the cash distributions based on the projects’ production level and the Company and Invenergy will receive 65.19%. 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, 2016:

(In millions)	NRG Wind TE Holdco		Alta TE Holdco		Spring Canyon
Other current and non-current assets	$	193	$	17	$	4
Property, plant and equipment	441		461		100
Intangible assets	2		274		—
Total assets	636		752		104
Current and non-current liabilities	209		9		6
Total liabilities	209		9		6
Noncontrolling interest	139		107		67
Net assets less noncontrolling interests	$	288	$	636	$	31

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 — As described in Note 3, Business Acquisitions, on March 27, 2017, 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. The Company’s maximum exposure to loss is limited to its equity method investments in the Utah Solar Portfolio, which was $346 million on a combined basis as of December 31, 2016.

NRG DGPV Holdco 1 LLC — On May 8, 2015, the Company and NRG entered into a partnership by forming NRG DGPV Holdco 1 LLC, 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, including: (i) a tax equity-financed portfolio of 10 recently completed community solar projects representing approximately 8 MW with a weighted average remaining PPA term of 19 years; (ii) a tax equity-financed portfolio of approximately 12 commercial photovoltaic systems representing approximately 37 MW with a weighted average remaining PPA term of 18 years; and (iii) a tax equity-financed portfolio of approximately 3 commercial photovoltaic systems representing approximately 1 MW with a weighted average remaining PPA term of 20 years. All of these investments relate to the Company's $100 million commitment to distributed solar projects in partnership with NRG.

NRG DGPV Holdco 2 LLC — On February 29, 2016,the Company and NRG entered into an additional partnership by forming NRG DGPV Holdco 2 LLC, or DGPV Holdco 2, to own or purchase solar power generation projects as well as other ancillary related assets from NRG Renew LLC or its subsidiaries, via intermediate funds including: (i) a tax equity-financed portfolio of 18 projects representing approximately 28 MW with a weighted average remaining PPA term of 21 years; and (ii) a tax equity-financed portfolio of 21 projects representing approximately 18 MW with a weighted average remaining PPA term of 20 years.  Under this partnership, the Company committed to fund up to $50 million of capital. 

The Company's maximum exposure to loss is limited to its equity investment in DGPV Holdco 1 and DGPV Holdco 2, which was $99 million on a combined basis, of which $14 million was payable to NRG, as of December 31, 2016.

NRG RPV Holdco 1 LLC — On April 9, 2015, the Company and NRG entered into a partnership by forming NRG RPV Holdco 1 LLC, or RPV Holdco, that holds 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 15 MW with a weighted average remaining lease term of approximately 19 years that was acquired outside of the partnership; and (ii) a tax equity-financed portfolio of approximately 5,400 leases representing approximately 31 MW, with a weighted average remaining lease term for the existing and new leases of approximately 19 years.

In addition to the acquisition of the unlevered portfolio of leases, the Company had previously committed to fund up to $150 million of capital to invest in the tax equity financed portfolio. On February 29, 2016, the Company and NRG amended the RPV Holdco partnership agreement to reduce the aggregate commitment of $150 million to $100 million in connection with the formation of DGPV Holdco 2. On August 5, 2016, the Company and NRG amended the RPV Holdco partnership agreement to further reduce that capital commitment of $100 million to $60 million in connection with NRG’s change in business model approach in the residential solar business. As of December 31, 2016, the Company had contributed $59 million of this amount.

The Company's maximum exposure to loss is limited to its equity investment, which was $71 million as of December 31, 2016.

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Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2016

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, 2016		As of December 31, 2016		As of December 31, 2015
	Fair Value (a)		Fair Value (a)		Fair Value (a)
(In millions)	Level 1		Level 2		Level 2
Derivative assets:
Commodity contracts	$	1	$	1	$	—
Interest rate contracts	—		1		—
Total assets	$	1	$	2	$	—
Derivative liabilities:
Commodity contracts	$	—	$	1	$	2
Interest rate contracts	—		75		98
Total liabilities	$	—	$	76	$	100

^(a) There were no assets or liabilities classified as Level 1 as of December 31, 2015. There were no assets or liabilities classified Level 3 as of December 31, 2016 and 2015.

Fair Value of Financial Instruments

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, 2016				As of December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable, including current portion	$	30	$	30	$	47	$	47
Liabilities:
Long-term debt, including current portion	$	6,057	$	6,056	$	5,656	$	5,538

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 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, 2016 and 2015:

	As of December 31, 2016				As of December 31, 2015
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	1,455	$	4,601	$	978	$	4,560

Recurring Fair Value Measurements

The Company records its derivative assets and liabilities at fair market value on its consolidated balance sheet. There were no asset positions as of December 31, 2015. 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, 2016		As of December 31, 2016		As of December 31, 2015
	Fair Value (a)		Fair Value (a)		Fair Value (a)
(In millions)	Level 1		Level 2		Level 2
Derivative assets:
Commodity contracts	$	1	$	1	$	—
Interest rate contracts	—		1		—
Total assets	$	1	$	2	$	—
Derivative liabilities:
Commodity contracts	$	—	$	1	$	2
Interest rate contracts	—		75		98
Total liabilities	$	—	$	76	$	100

^(a) There were no assets or liabilities classified as Level 1 as of December 31, 2015. There were no assets or liabilities classified Level 3 as of December 31, 2016 and 2015.

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, 2016, the credit reserve resulted in a $1 million increase in fair value in OCI. 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, 2016, credit risk exposure to these counterparties attributable to the Company's ownership interests was approximately $2.8 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.

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Accounting for Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2016

Accounting for Derivative Instruments and Hedging Activities Disclosure [Abstract]

Accounting for Derivative Instruments and Hedging Activities

Accounting for Derivative Instruments and Hedging Activities

ASC 815 requires 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 effective portion of the change in fair value of the derivatives to accumulated OCI/OCL, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings. For derivatives 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, 2016, 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 2018 and electricity contracts to supply retail power to the Company's district energy centers extending through 2020. At December 31, 2016, these contracts were not designated as cash flow or fair value hedges.

Also, as of December 31, 2016, 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, 2016, the Company had interest rate derivative instruments on non-recourse debt extending through 2036, most 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, 2016 and 2015:

		Total Volume
		December 31, 2016		December 31, 2015
Commodity	Units	(In millions)
Natural Gas	MMBtu	3		4
Interest	Dollars	$	2,070	$	1,991

Fair Value of Derivative Instruments

There were no derivative asset positions on the balance sheet as of December 31, 2015. The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:

	Fair Value
	Derivative Assets		Derivative Liabilities
	December 31, 2016		December 31, 2016		December 31, 2015
	(In millions)
Derivatives Designated as Cash Flow Hedges:
Interest rate contracts current	$	—	$	26	$	34
Interest rate contracts long-term	1		39		56
Total Derivatives Designated as Cash Flow Hedges	1		65		90
Derivatives Not Designated as Cash Flow Hedges:
Interest rate contracts current	—		5		3
Interest rate contracts long-term	—		5		5
Commodity contracts current	2		1		2
Total Derivatives Not Designated as Cash Flow Hedges	2		11		10
Total Derivatives	$	3	$	76	$	100

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, 2016, there was no outstanding collateral paid or received. As of December 31, 2015, there were no offsetting amounts at the counterparty master agreement level or outstanding collateral paid or received. The following table summarizes the offsetting of derivatives by counterparty master agreement level as of December 31, 2016:

	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	(75		)	1			(74		)
Total interest rate contracts	(74		)	—			(74		)
Total derivative instruments	$	(73	)	$	—		$	(73	)

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,
	2016			2015			2014
	(In millions)
Accumulated OCL beginning balance	$	(83	)	$	(76	)	$	(16	)
Reclassified from accumulated OCL to income due to realization of previously deferred amounts	13			14			14
Mark-to-market of cash flow hedge accounting contracts	—			(21		)	(74		)
Accumulated OCL ending balance, net of income tax benefit of $16, $16 and $6, respectively	$	(70	)	$	(83	)	$	(76	)
Accumulated OCL attributable to noncontrolling interests	(42		)	(56		)	(67		)
Accumulated OCL attributable to NRG Yield, Inc.	$	(28	)	$	(27	)	$	(9	)
Losses expected to be realized from OCL during the next 12 months, net of income tax benefit of $3	$	16

Amounts reclassified from accumulated OCL into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to interest expense. There was no ineffectiveness for the years ended December 31, 2016, 2015 and 2014.

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.

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, 2016, 2015 and 2014 the impact to the consolidated statements of income was a loss of $2 million, a gain of $16 million, and a loss of $22 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 and 2014, 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 years ended December 31, 2015 and 2014, the impact to the consolidated statements of income was an unrealized loss of $2 million and a gain of $2 million, respectively.

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

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Intangible Assets

12 Months Ended

Dec. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets

Intangible Assets

Intangible Assets — The Company's intangible assets as of December 31, 2016 and 2015 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 will be 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 will be 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 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, 2016	PPAs			Leasehold Rights			Customer Relationships			Customer Contracts			Emission Allowances			Development Rights			Other			Total
(In millions)
January 1, 2016	$	1,264		$	86		$	66		$	15		$	15		$	3		$	6		$	1,455
Other	—			—			—			—			(6		)	—			—			(6		)
December 31, 2016	1,264			86			66			15			9			3			6			1,449
Less accumulated amortization	(138		)	(9		)	(4		)	(7		)	(2		)	(1		)	(2		)	(163		)
Net carrying amount	$	1,126		$	77		$	62		$	8		$	7		$	2		$	4		$	1,286

Year ended December 31, 2015	PPAs			Leasehold Rights			Customer Relationships			Customer Contracts			Emission Allowances			Development Rights			Other			Total
(In millions)
January 1, 2015	$	1,270		$	86		$	66		$	15		$	16		$	3		$	6		$	1,462
Other	(6		)	—			—			—			(1		)	—			—			(7		)
December 31, 2015	1,264			86			66			15			15			3			6			1,455
Less accumulated amortization	(75		)	(5		)	(3		)	(6		)	(1		)	(1		)	(2		)	(93		)
Net carrying amount	$	1,189		$	81		$	63		$	9		$	14		$	2		$	4		$	1,362

The Company recorded amortization expense of $70 million, $55 million and $30 million during the years ended December 31, 2016, 2015 and 2014. Of these amounts, $69 million, $54 million and $29 million for the years ended December 31, 2016, 2015 and 2014, respectively, were recorded to contract amortization expense and reduced operating revenues in the consolidated statements of income. The Company estimates the future amortization expense for its intangibles to be $71 million for the next five years through 2021.

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 Holding Company, LLC, as of their respective acquisition dates. The Blythe solar project's liability of $4 million is 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 is 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 Holding Company, LLC's liability of $5 million is recorded to other non-current liabilities and is amortized to cost of operations on a straight-line basis over the term of the land lease. At December 31, 2016, accumulated amortization of out-of-market contracts was $3 million and amortization expense was $1 million for the years ended December 31, 2016 and 2015.

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Asset Impairments Asset Impairments (Notes)

12 Months Ended

Dec. 31, 2016

Asset Impairments [Abstract]

Asset Impairment Charges [Text Block]

Asset Impairments

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 located in Texas and the Forward project in Pennsylvania 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 in 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.

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Long-term Debt

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Long-term Debt

Long-term Debt

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

	December 31, 2016			December 31, 2015			Interest rate % (a)	Letters of Credit Outstanding at December 31, 2016
	(In millions, except rates)
2026 Senior Notes	$	350		$	—		5.000
2024 Senior Notes	500			500			5.375
2020 Convertible Notes	271			266			3.250
2019 Convertible Notes	335			330			3.500
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 (b)	—			306			L+2.500	$	60
Project-level debt:
Alpine, due 2022	145			154			L+1.750	37
Alta Wind I, lease financing arrangement, due 2034	242			252			7.015	16
Alta Wind II, lease financing arrangement, due 2034	191			198			5.696	27
Alta Wind III, lease financing arrangement, due 2034	198			206			6.067	27
Alta Wind IV, lease financing arrangement, due 2034	128			133			5.938	19
Alta Wind V, lease financing arrangement, due 2035	206			213			6.071	30
Alta Realty Investments, due 2031	31			33			7.000	—
Alta Wind Asset Management, due 2031	18			19			L+2.375	—
Avra Valley, due 2031	57			60			L+1.750	3
Blythe, due 2028	19			21			L+1.625	6
Borrego, due 2025 and 2038	69			72			L+ 2.500/5.650	5
CVSR, due 2037	771			793			2.339 - 3.775	—
CVSR Holdco Notes, due 2037	199			—			4.680	13
El Segundo Energy Center, due 2023	443			485			L+1.625 - L+2.250	82
Energy Center Minneapolis, due 2017 and 2025	96			108			5.950 -7.250	—
Energy Center Minneapolis Series D Notes, due 2031	125			—			3.550	—
Kansas South, due 2031	30			33			L+2.000	4
Laredo Ridge, due 2028	100			104			L+1.875	10
Marsh Landing, due 2017 and 2023	370			418			L+1.750 - L+1.875	22
PFMG and related subsidiaries financing agreement, due 2030	27			29			6.000	—
Roadrunner, due 2031	37			40			L+1.625	5
South Trent Wind, due 2020	57			62			L+1.625	10
TA High Desert, due 2020 and 2032	49			52			L+2.500/5.150	8
Tapestry, due 2021	172			181			L+1.625	20
Utah Solar Portfolio, due 2022	287			—			L+2.625	13
Viento, due 2023	178			189			L+2.750	27
Walnut Creek, due 2023	310			351			L+1.625	41
WCEP Holdings, due 2023	46			46			L+3.000	—
Other	—			2			various	—
Subtotal project-level debt	4,601			4,254
Total debt	6,057			5,656
Less current maturities	(291		)	(264		)
Less deferred financing costs	(70		)	(63		)
Total long-term debt	$	5,696		$	5,329

^(a) As of December 31, 2016, L+ equals 3 month LIBOR plus x%, except for the Alpine term loan, Marsh Landing term loan, Walnut Creek term loan, Utah Solar Portfolio debt, and NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, where L+ equals 1 month LIBOR plus x% and Kansas South and Viento, where L+ equals 6 month LIBOR plus x%.

^(b) Net of discount of $16.5 million and $21.5 million as of December 31, 2016 and 2015, respectively.

^(c) Net of discount of $10 million and $15 million as of December 31, 2016 and 2015, respectively.

^(d) Applicable rate is determined by the Borrower Leverage Ratio, as defined in the credit agreement.

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 arrangement. As of December 31, 2016, 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, and interest payments will commence on March 15, 2017. 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, as described below.

NRG Yield Operating LLC 2024 Senior Notes

On August 5, 2014, NRG Yield Operating LLC issued $500 million of senior unsecured notes, or the 2024 Senior Notes. The 2024 Senior Notes bear interest at 5.375% and mature in August 2024. Interest on the notes is payable semi-annually on February 15 and August 15 of each year. The 2024 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.

2020 Convertible Senior Notes

The Company has outstanding $287.5 million aggregate principal amount of 3.25% Convertible Senior Notes due 2020, or the 2020 Convertible Notes.  The 2020 Convertible Notes are convertible, under certain circumstances, into 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. The 2020 Convertible Notes mature on June 1, 2020, unless earlier repurchased or converted in accordance with their terms. Prior to the close of business on the business day immediately preceding December 1, 2019, the 2020 Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the close of business on the second scheduled trading day immediately preceding the maturity date. The 2020 Convertible Notes are 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, 2016, the 2020 Convertible Notes were trading at approximately 97% of their face value, resulting in a total market value of $278 million compared to a carrying value of $271 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 Convertible Debt indenture. As of December 31, 2016, the Company's Class C common stock closed at $15.80 per share, resulting in a pro forma conversion value for the Convertible Notes of approximately $165 million.

During the years ended December 31, 2016 and 2015, the Company recorded the following expense in relation to the 2020 Convertible Notes at the effective rate of 5.10%:

(In millions)	2016		2015
Interest expense at 3.25% coupon rate	$	9	$	5
Debt discount amortization	4		2
Debt issuance costs amortization	1		1
	$	14	$	8

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. Interest on the 2019 Convertible Notes is payable semi-annually in arrears on February 1 and August 1 of each year. 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, 2016, the 2019 Convertible Notes were trading at approximately 99.6% of their face value, resulting in a total market value of $344 million compared to a carrying value of $335 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, 2016, the Company's Class A common stock closed at $15.36 per share, resulting in a pro forma conversion value for the Convertible Notes of approximately $228 million.

During the years ended December 31, 2016 and 2015, the Company recorded the following expense in relation to the 2019 Convertible Notes at the effective rate of 5.00%:

(In millions)	2016		2015
Interest expense at 3.5% coupon rate	$	12	$	12
Debt discount amortization	5		4
Debt issuance costs amortization	2		2
	$	19	$	18

NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility

In connection with the Company's initial public offering of Class A common stock in July 2013, as further described in Note 1, Nature of Business, NRG Yield LLC and NRG Yield Operating LLC entered into a senior secured revolving credit facility, or the Yield Credit Facility, which was amended on June 26, 2015, to, among other things, increase the availability to $495 million. The Company's revolving credit facility can be used for cash or for the issuance of letters of credit.

During 2015, the Company borrowed $254 million from the revolving credit facility to finance the acquisition of the November 2015 Drop Down Assets as discussed in Note 3, Business Acquisitions, as well asfund dividend payments and tax equity contributions.

The Company borrowed $60 million from the revolving credit facility and repaid $366 million during the year endedDecember 31, 2016. The Company used its pro rata proceeds of $97.5 million from the CVSR Holdco Financing Arrangement in July 2016, a portion of its proceeds from the issuance of the 2026 Senior Notes in August 2015, as well as its cash on hand to repay the outstanding borrowings under the revolving credit facility.

As of December 31, 2016, there were no outstanding borrowings and the Company had $60 million of letters of credit outstanding under the revolving credit facility.

Project - level Debt

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 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. Agua Caliente Borrower 2 LLC owns a 16% interest in the Agua Caliente solar farm and holds $41 million of the Agua Caliente Holdco debt. 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. Concurrent with the February 2017 borrowing, the Company entered into a letter of credit commitment of $17 million and issued same to support the Company's debt service requirement obligations. The Company pays semi-annual related fees of 2.25% on the outstanding balance.

Utah Solar Portfolio, due 2022

As part of its March 2017 Drop Down Assets acquisition, the Company assumed non-recourse debt of $287 million relating to the Utah Solar Portfolio at 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 the NRG acquisition in November 2016, and additional borrowings of $65 million incurred during 2016. The Company also entered into letter agreements for a commitment of $13 million to support the Company's debt service requirement obligations. The Company pays an availability fee of 2.625% on the amount on a quarterly basis. On March 27, 2017, the letters of credit were amended, reducing the issued amount to $11 million.

Energy Center Minneapolis LLC Series D Notes

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 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.

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.

Avenal

On March 18, 2015, Avenal, one of the Company's equity method investments, amended its credit agreement to increase its borrowings by $43 million and to reduce the related interest rate from 6 month LIBOR plus an applicable margin of 2.25% to 6 month LIBOR plus 1.75% from March 18, 2015, through March 17, 2022, 6 month LIBOR plus 2.00% from March 18, 2022, through March 17, 2027, and 6 month LIBOR plus 2.25% from March 18, 2027, through the maturity date.  As a result of the credit agreement amendment, the Company received net proceeds of $20 million after fees from its 49.95% ownership in Avenal. Effective September 30, 2015, the Company increased its ownership to 50% by acquiring an additional 0.05% membership interest in Avenal.

Lease financing arrangements

Alta Wind Holdings (Alta Wind II - V) and Alta I (operating entities) have finance lease obligations issued under lease transactions whereby the respective operating entities sold and leased back undivided interests in specific assets of the project. The sale and related lease transactions are accounted for as financing arrangements as the operating entities have continued involvement with the property. The terms and conditions of each facility lease are substantially similar. Each operating entity makes rental payments as stipulated in the facility lease agreements on a semiannual basis every June 30 and December 30 through the final maturity dates. In addition, the operating entities have a credit agreement with a group of lenders that provides for the issuance of letters of credit to support certain operating and debt service obligations. Certain operations and maintenance, as well as rent reserve requirements are satisfied by letters of credit issued under the NRG Yield Operating agreement. As of December 31, 2016, $965 million was outstanding under the finance lease obligations, and $119 million of letters of credit were issued under the credit agreement and $23 million were issued under the Yield Credit Facility.

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. In connection with the acquisition of the Alta Wind Portfolio in 2015, as described in Note 3, Business Acquisitions, the Company acquired thirty-one additional interest rate swaps, thirty of which were settled during 2015. During 2015, the Company acquired thirty-two additional interest rate swaps in connection with the January 2015 and November 2015 Drop Downs, as described in Note 3, Business Acquisitions.

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, 2016:

	% of Principal		Fixed Interest Rate		Floating Interest Rate	Notional Amount at December 31, 2016 (In millions)		Effective Date	Maturity Date
Alpine	85	%	2.744	%	3-Month LIBOR	$	115	various	December 31, 2029
Alpine	85	%	2.421	%	3-Month LIBOR	8		June 24, 2014	June 30, 2025
Avra Valley	85	%	2.333	%	3-Month LIBOR	49		November 30, 2012	November 30, 2030
AWAM	100	%	2.47	%	3-Month LIBOR	18		May 22, 2013	May 15, 2031
Blythe	75	%	3.563	%	3-Month LIBOR	14		June 25, 2010	June 25, 2028
Borrego	75	%	1.125	%	3-Month LIBOR	7		April 3, 2013	June 30, 2020
El Segundo	75	%	2.417	%	3-Month LIBOR	330		November 30, 2011	August 31, 2023
Kansas South	75	%	2.368	%	6-Month LIBOR	23		June 28, 2013	December 31, 2030
Laredo Ridge	75	%	2.31	%	3-Month LIBOR	79		March 31, 2011	March 31, 2026
Marsh Landing	75	%	3.244	%	3-Month LIBOR	342		June 28, 2013	June 30, 2023
Roadrunner	75	%	4.313	%	3-Month LIBOR	28		September 30, 2011	December 31, 2029
South Trent	75	%	3.265	%	3-Month LIBOR	43		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	155		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	230		December 15, 2016	September 30, 2036
Viento Funding II	90	%	various		6-Month LIBOR	160		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	276		June 28, 2013	May 31, 2023
WCEP Holdings	90	%	4.003	%	3-Month LIBOR	46		June 28, 2013	May 31, 2023
Total						$	2,069

Annual Maturities

Annual payments based on the maturities of the Company's debt, for the years ending after December 31, 2016, are as follows:

	(In millions)
2017	$	291
2018	304
2019	665
2020	654
2021	452
Thereafter	3,718
Total	$	6,084

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.

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Earnings Per Share

12 Months Ended

Dec. 31, 2016

Earnings (Loss) Per Share Disclosure [Abstract]

Earnings Per Share

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 prior periods presented below 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 earnings per share is shown in the following table:

	Year Ended December 31, 2016				Year Ended December 31, 2015				Year Ended December 31, 2014
(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 earnings per share attributable to NRG Yield, Inc. common stockholders
Net income attributable to NRG Yield, Inc.	$	20	$	37	$	14	$	19	$	8	$	8
Weighted average number of common shares outstanding — basic and diluted	35		63		35		49		28		28
Earnings per weighted average common share — basic and diluted	$	0.58	$	0.58	$	0.40	$	0.40	$	0.30	$	0.30

^(a) Net income attributable to NRG Yield, Inc. and basic and diluted 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,
	2016	2015	2014
	(In millions of shares)
2019 Convertible Notes - Common Class A	15	15	12
2020 Convertible Notes - Common Class C	10	5	—

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Stockholders' Equity

12 Months Ended

Dec. 31, 2016

Stockholders' Equity Attributable to Parent [Abstract]

Stockholders' Equity

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 return for the issuance of these shares, the Company received $468 million, net of underwriting discounts and commissions of $27 million. 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 $395 million of the 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.

On July 29, 2014, the Company issued 12,075,000 shares of Class A common stock for net proceeds, after underwriting discount and expenses, of $630 million. The Company utilized the proceeds of the offering 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 Class C common stock and Class D common stock have the same rights and privileges and rank equally, share ratably and are identical in all respects to the shares of Class A common stock and Class B common stock, respectively, as to all matters, except that each share of Class C common stock and Class D common stock is entitled to 1/100th of a vote on all stockholder matters. The par value per share of the Company’s Class A common stock and Class B common stock remains unchanged at $0.01 per share after the effect of the stock split described above. Accordingly, the stock split was accounted for as a stock dividend. The Company recorded a transfer between retained earnings and common stock equal to the par value of each share of Class C common stock and Class D common stock that was issued. 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 and, as a result, it currently owns 53.3% of the economic interests of NRG Yield LLC, with NRG retaining 46.7% of the economic interests of NRG Yield LLC.

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, 2016:

	Fourth Quarter 2016		Third Quarter 2016		Second Quarter 2016		First Quarter 2016
Dividends per Class A share	$	0.25	$	0.24	$	0.23	$	0.225
Dividends per Class C share	$	0.25	$	0.24	$	0.23	$	0.225

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, 2017, the Company declared a quarterly dividend on its Class A and Class C common stock of $0.26 per share, payable on March 15, 2017, to stockholders of record as of March 1, 2017.

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 to NRG

The following table lists the distributions paid to NRG during the year ended December 31, 2016:

	Fourth Quarter 2016		Third Quarter 2016		Second Quarter 2016		First Quarter 2016
Distributions per Class B unit	$	0.25	$	0.24	$	0.23	$	0.225
Distributions per Class D unit	$	0.25	$	0.24	$	0.23	$	0.225

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, 2017, NRG Yield LLC declared a quarterly distribution on its Class B and Class D common stock of $0.26 per unit, payable to NRG on March 15, 2017.

During the first quarter of 2017 and the years ended December 31, 2016, 2015 and 2014, 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 March 2017 Drop Down Assets of $8 million was recorded as a contribution from NRG and increased the balance of its noncontrolling interest in 2017. 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 and reduced the balance of its noncontrolling interest in 2016. The difference between the cash paid and historical value of the January 2015 and November 2015 Drop Down Assets of $109 million, as well as $32 million of AOCL, was recorded as a contribution from NRG and increased the balance of its noncontrolling interest in 2015. The difference between the cash paid and historical value of the June 2014 Drop Down Assets of $113 million was recorded as a distribution to NRG and reduced the balance of its noncontrolling interest in 2014.  In addition, as the projects were owned by NRG prior to the Company’s acquisitions, the pre-acquisition earnings 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. In addition, NRG maintained a 25% ownership interest in the Class B interests of NRG Wind TE Holdco.  This 25% interest is also reflected within the Company’s noncontrolling interest balance.

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Segment Reporting

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Year ended December 31, 2014
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	317		$	316		$	195		$	—		$	828
Cost of operations	55			83			139			—			277
Depreciation and amortization	82			133			18			—			233
General and administrative	—			—			—			8			8
Acquisition-related transaction and integration costs	—			—			—			4			4
Operating income (loss)	180			100			38			(12		)	306
Equity in earnings of unconsolidated affiliates	14			8			—			—			22
Other income, net	—			5			—			1			6
Loss on debt extinguishment	—			(1		)	—			—			(1		)
Interest expense	(53		)	(126		)	(7		)	(30		)	(216		)
Income (loss) before income taxes	141			(14		)	31			(41		)	117
Income tax expense	—			—			—			4			4
Net Income (Loss)	$	141		$	(14	)	$	31		$	(45	)	$	113

	Year ended December 31, 2016
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	333		$	518		$	170		$	—		$	1,021
Cost of operations	66			126			114			—			306
Depreciation and amortization	80			197			20			—			297
Impairment losses	—			183			—			—			183
General and administrative	—			—			—			16			16
Acquisition-related transaction and integration costs	—			—			—			1			1
Operating income (loss)	187			12			36			(17		)	218
Equity in earnings of unconsolidated affiliates	13			47			—			—			60
Other income, net	1			2			—			—			3
Interest expense	(48		)	(147		)	(7		)	(78		)	(280		)
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 investment in affiliates	$	106		$	1,046		$	—		$	—		$	1,152
Capital expenditures (a)	7			2			14			—			23
Total Assets	$	1,993		$	5,988		$	426		$	429		$	8,836

	Year ended December 31, 2015
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	336		$	443		$	174		$	—		$	953
Cost of operations	59			136			126			—			321
Depreciation and amortization	81			197			19			—			297
General and administrative	—			—			—			12			12
Acquisition-related transaction and integration costs	—			—			—			3			3
Operating income (loss)	196			110			29			(15		)	320
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		)	(147		)	(7		)	(61		)	(263		)
Income (loss) before income taxes	156			(20		)	22			(76		)	82
Income tax expense	—			—			—			12			12
Net Income (Loss)	$	156		$	(20	)	$	22		$	(88	)	$	70
Balance Sheet
Equity investments in affiliates	$	110		$	687		$	—		$	—		$	797
Capital expenditures (a)	4			6			20			—			30
Total Assets	$	2,102		$	6,070		$	428		$	189		$	8,789

Segment Reporting

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, 2016, 2015 and 2014:

	2016		2015		2014
Customer	Conventional (%)	Renewables (%)	Conventional (%)	Renewables (%)	Conventional (%)	Renewables (%)
SCE	21%	21%	23%	17%	24%	7%
PG&E	12%	11%	13%	12%	15%	13%

	Year ended December 31, 2016
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	333		$	518		$	170		$	—		$	1,021
Cost of operations	66			126			114			—			306
Depreciation and amortization	80			197			20			—			297
Impairment losses	—			183			—			—			183
General and administrative	—			—			—			16			16
Acquisition-related transaction and integration costs	—			—			—			1			1
Operating income (loss)	187			12			36			(17		)	218
Equity in earnings of unconsolidated affiliates	13			47			—			—			60
Other income, net	1			2			—			—			3
Interest expense	(48		)	(147		)	(7		)	(78		)	(280		)
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 investment in affiliates	$	106		$	1,046		$	—		$	—		$	1,152
Capital expenditures (a)	7			2			14			—			23
Total Assets	$	1,993		$	5,988		$	426		$	429		$	8,836

^(a) Includes accruals.

	Year ended December 31, 2015
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	336		$	443		$	174		$	—		$	953
Cost of operations	59			136			126			—			321
Depreciation and amortization	81			197			19			—			297
General and administrative	—			—			—			12			12
Acquisition-related transaction and integration costs	—			—			—			3			3
Operating income (loss)	196			110			29			(15		)	320
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		)	(147		)	(7		)	(61		)	(263		)
Income (loss) before income taxes	156			(20		)	22			(76		)	82
Income tax expense	—			—			—			12			12
Net Income (Loss)	$	156		$	(20	)	$	22		$	(88	)	$	70
Balance Sheet
Equity investments in affiliates	$	110		$	687		$	—		$	—		$	797
Capital expenditures (a)	4			6			20			—			30
Total Assets	$	2,102		$	6,070		$	428		$	189		$	8,789

^(a) Includes accruals.

	Year ended December 31, 2014
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	317		$	316		$	195		$	—		$	828
Cost of operations	55			83			139			—			277
Depreciation and amortization	82			133			18			—			233
General and administrative	—			—			—			8			8
Acquisition-related transaction and integration costs	—			—			—			4			4
Operating income (loss)	180			100			38			(12		)	306
Equity in earnings of unconsolidated affiliates	14			8			—			—			22
Other income, net	—			5			—			1			6
Loss on debt extinguishment	—			(1		)	—			—			(1		)
Interest expense	(53		)	(126		)	(7		)	(30		)	(216		)
Income (loss) before income taxes	141			(14		)	31			(41		)	117
Income tax expense	—			—			—			4			4
Net Income (Loss)	$	141		$	(14	)	$	31		$	(45	)	$	113

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Income Taxes

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Effective Tax Rate

The income tax provision consisted of the following amounts:

	Year Ended December 31,
	2016			2015			2014
	(In millions, except percentages)
Current
U.S. Federal	$	—		$	—		$	—
State	—			—			—
Total — current	—			—			—
Deferred
U.S. Federal	(1		)	10			2
State	—			2			2
Total — deferred	(1		)	12			4
Total income tax (benefit) expense	$	(1	)	$	12		$	4
Effective tax rate	(100.0		)%	14.6		%	3.4		%

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

	Year Ended December 31,
	2016			2015			2014
	(In millions, except percentages)
Income Before Income Taxes	1			82			117
Tax at 35%	—			29			41
State taxes, net of federal benefit	—			2			1
Investment tax credits	(1		)	(1		)	—
Impact of non-taxable partnership earnings	(1		)	(17		)	(33		)
Production tax credits, including prior year true-up	4			(4		)	(6		)
Change in state effective tax rate	—			—			1
Other	(3		)	3			—
Income tax (benefit) expense	$	(1	)	$	12		$	4
Effective income tax rate	(100.0		)%	14.6		%	3.4		%

For the years ended December 31, 2016, 2015 and 2014, 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 53.3% of NRG Yield LLC and consolidates the results due to its controlling interest. The Company records NRG's 46.7% 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,
	2016			2015
	(In millions)
Deferred tax liabilities:
Investment in projects	$	3		$	27
Total deferred tax liabilities	3			27
Deferred tax assets:
Production tax credits carryforwards	5			10
Investment tax credits	1			1
U.S. Federal net operating loss carryforwards	226			181
State net operating loss carryforwards	3			5
Total deferred tax assets	235			197
Valuation allowance	$	(16	)	$	—
Total deferred tax assets, net of valuation allowance	$	219		$	197
Net deferred noncurrent tax asset	$	216		$	170

Tax Receivable and Payable

As of December 31, 2016, the Company had a domestic tax receivable of $6 million, which related to federal cash grants for the Borrego project. This amount is fully reserved pending further discussions with the US Treasury Department.

Deferred Tax Assets and Valuation Allowance

Net deferred tax balance — As of December 31, 2016 and 2015, NRG recorded a net deferred tax asset of $232 million and $170 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 $16 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, 2016, the Company had domestic NOLs carryforwards for federal income tax purposes of $226 million and cumulative state NOLs of $3 million tax-effected.

Uncertain Tax Positions

The Company had no identified uncertain tax positions that require evaluation as of December 31, 2016.

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Related Party Transactions

12 Months Ended

Dec. 31, 2016

Related Party Transactions [Abstract]

Related Party Transactions Disclosure

Related Party Transactions

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, operating costs and other income and expense.

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 and $12 million of revenues during the years ended December 31, 2015 and 2014, respectively. Included in the revenues for the years ended December 31, 2015, and 2014, are unrealized losses and gains, respectively, on forward contracts with NRG Texas Power LLC hedging the sale of power from Elbow Creek, extending through the end of 2015, as further described in Note 7, Accounting for Derivative Instruments and Hedging Activities. 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.

PPA by and between Elbow Creek and NRG

In October 2015, Elbow Creek, the Company's subsidiary in the Renewables segment, entered into a PPA with NRG Power Marketing for the sale of energy and environmental attributes with the effective date of November 1, 2015, and an expiration date of October 31, 2022. Elbow Creek generated $8 million of revenue during the year endedDecember 31, 2016.

PPA by and between NRG Energy Center Dover LLC and NRG

In February 2016, NRG Energy Center Dover LLC, or NRG Dover, a subsidiary of the Company, entered into a PPA with NRG Power Marketing for the sale of energy and environmental attributes with an effective date of February 1, 2016 and expiration date of December 31, 2018. NRG Dover generated $5 million of revenue during the year ended December 31, 2016. The agreement in place is in addition to the existing Power Sales and Services Agreement described further below.

Power Sales and Services Agreement by and between NRG Energy Center Dover LLC and NRG

NRG Dover is party to a Power Sales and Services Agreement with NRG Power Marketing. The agreement is automatically renewed on a month-to-month basis unless terminated by either party upon at least 30 day written notice. Under the agreement, NRG Power Marketing has the exclusive right to (i) manage, market and sell power, (ii) procure fuel and fuel transportation for operation of the Dover generating facility, to include for purposes other than generating power, (iii) procure transmission services required for the sale of power and (iv) procure and market emissions credits for operation of the Dover generating facility.

In addition, NRG Power Marketing has the exclusive right and obligation to direct the output from the generating facility, in accordance with and to meet the terms of any power sales contracts executed against the power generation of the Dover facility. Under the agreement, NRG Power Marketing pays NRG Dover gross receipts generated through sales, less costs incurred by NRG Power Marketing related to providing such services as transmission and delivery costs, as well as fuel costs. For the years ended December 31, 2016, 2015 and 2014, NRG Dover purchased approximately $1 million, $5 million and $10 million, respectively, of natural gas from NRG Power Marketing under the Power Sales and Services Agreement.

Energy Marketing Services Agreement by and between NRG Energy Center Minneapolis LLC and NRG

NRG Energy Center Minneapolis LLC, or NRG Minneapolis, a subsidiary of the Company is party to an Energy Marketing Services Agreement with NRG Power Marketing. The agreement commenced in August 2014 and is automatically renewed annually unless terminated by either party upon at least 90 day written notice prior to the end of any term. Under the agreement, NRG Power Marketing will procure fuel and fuel transportation for the operation of the Minneapolis generating facility. For the years ended December 31, 2016, 2015 and 2014, NRG Minneapolis purchased approximately $7 million, $8 million and $2 million, respectively, of natural gas from NRG Power Marketing.

Operations and Maintenance (O&M) Services Agreements by and between Thermal Entities and NRG

On October 1, 2014, NRG entered into Plant O&M Services Agreements with certain wholly-owned subsidiaries of the Company. NRG provides necessary and appropriate services to operate and maintain the subsidiaries' plant operations, businesses and thermal facilities. NRG is to be 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. Prior to October 1, 2014, NRG provided the same services to Thermal entities on an informal basis. For each of the years ended December 31, 2016 and 2015, total fees incurred under the agreements were $29 million. For the year ended December 31, 2014, total fees incurred were $27 million. There was a balance of $20 million and $29 million due to NRG in accounts payable — affiliate as of December 31, 2016, and 2015, respectively. As of December 31, 2016, $11 million of the balance was recorded in the current liabilities of the consolidated balance sheet and $9 million was recorded in non-current liabilities of the consolidated balance sheet.

O&MServices 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, $4 million and $6 million for the years ended December 31, 2016, 2015 and 2014, respectively.

O&MServices Agreements by and between El Segundo and NRG El Segundo Operations

El Segundo incurs fees under an O&M agreement with NRG El Segundo Operations, Inc., a wholly-owned subsidiary of NRG. Under the O&M agreement, NRG El Segundo Operations, Inc. manages, operates and maintains the El Segundo facility for an initial term of ten years following the commercial operations date. For each of the years ended December 31, 2016, 2015 and 2014, the costs incurred under the agreement were approximately $4 million. There was a balance of $1 million due to NRG El Segundo in accounts payable — affiliate as of December 31, 2016 and 2015.

Administrative Services Agreement by and between Marsh Landing and GenOn Energy Services, LLC and related Assignment and Assumption Agreement

Marsh Landing was a party to an administrative services agreement with GenOn Energy Services, LLC, a wholly owned subsidiary of NRG, through December 18, 2016. Under the agreement, GenOn Energy Services, LLC provided processing and invoice payment services on behalf of Marsh Landing. Marsh Landing reimbursed GenOn Energy Services, LLC for the amounts it paid. The Company reimbursed costs under this agreement of approximately $14 million for the year ended December 31, 2016, and $13 million for the years ended December 31, 2015 and 2014, respectively. For the year ended December 31, 2014, $2 million was capitalized. There was a balance of $1 million and $6 million due to GenOn Energy Services, LLC in accounts payable — affiliate as of December 31, 2016 and 2015, respectively.

Marsh Landing had the right to terminate the agreement for convenience upon thirty days prior written notice. In lieu of a termination of the agreement, Marsh Landing requested that GenOn Energy Services LLC enter into an assignment and assumption agreement with NRG West Coast LLC, a wholly owned subsidiary of NRG. The administrative services agreement was assigned to NRG West Coast LLC on December 19, 2016.

Administrative Services Agreement by and between CVSR and NRG

CVSR was a party to an administrative services agreement with NRG Energy Services, a wholly-owned subsidiary of NRG, which was subsequently assigned to NRG Renew Operations & Maintenance LLC, or RENOM, on July 15, 2015. The Company reimbursed a total of $4 million and $7 million to NRG Energy Services for the expenses incurred for the years ended December 31, 2015 and 2014, respectively. See below for further discussions of the costs incurred by CVSR under the administrative services agreement with RENOM in 2016.

Administrative Services Agreement by and between the Company and NRG Renew Operations & Maintenance LLC

Various wholly-owned subsidiaries of the Company in the Renewables segment are party to an administrative services agreement with RENOM, a wholly-owned subsidiary of NRG, which provides O&M services on behalf of these entities. The Company incurred total expenses for these services in the amount of $13 million and $7 million for the years ended December 31, 2016 and 2015, respectively. There was a balance of $5 million and $1 million due to RENOM as of December 31, 2016 and 2015, respectively.

O&MServices Agreements by and between Walnut Creek and NRG

Walnut Creek incurs fees under an O&M agreement with NRG Energy Services LLC, a wholly-owned subsidiary of NRG. Under the O&M agreement, NRG Energy Services LLC manages, operates and maintains the Walnut Creek facility and is reimbursed for the services provided. The Company incurred total expenses for these services in the amount of $3 million for each of the years ended December 31, 2016 and 2015 and $2 million for the year ended December 31, 2014.

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, 2016, the base management fee was approximately $7.5 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, 2016, the fee was increased by approximately $0.5 million per year, primarily due to the acquisition of the CVSR Drop Down. 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, $8 million, and $6 million for the years ended December 31, 2016, 2015, and 2014, respectively. There was a balance of $3 million in accounts payable — affiliate due to NRG as of December 31, 2016.

Administrative Services Agreements by and between Wind TE Holdco LLC and NRG

NRG Asset Services LLC, a wholly-owned subsidiary of NRG, provides support services to NRG Wind TE Holdco LLC project entities pursuant to various support services agreements. The agreements provide for administrative and support services and reimbursements of certain insurance, consultant and credit costs. For the years ended December 31, 2016, 2015 and 2014, the costs incurred under the agreements were $2 million, $3 million and $1 million, respectively.

Accounts Payable to NRG Repowering Holdings LLC

During 2013, NRG Repowering Holdings, LLC, a wholly-owned subsidiary of NRG, made payments to BA Leasing BSC, LLC, or BA Leasing, of $18 million, which were expected to be repaid with the proceeds of the cash grant received by BA Leasing with respect to the PFMG DG Solar Projects, in connection with a sale-leaseback arrangement between the PFMG DG Solar Projects and BA Leasing. As of December 31, 2014, PFMG DG Solar Projects had a corresponding receivable for the reimbursement of the cash grant from BA Leasing and related payable to NRG Repowering Holdings, LLC. In the first quarter of 2014, the PFMG DG Solar Projects received $11 million from BA Leasing and reduced the remaining receivable with an offset to the deferred liability recorded in connection with the sale - leaseback arrangement. The PFMG DG Solar Projects utilized the $11 million to repay NRG Repowering Holdings LLC. There was a balance of $7 million in accounts payable — affiliate as of December 31, 2015 which was settled in October 2016 with an offset to noncontrolling interest in the equity section of the consolidated balance sheet.

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 quarter of 2018. On January 5, 2017, the parties amended the EPC Agreement, based on a customer change order, to increase the capacity of the district energy system from 73 MWt to 80 MWt, which also increased the payment from $79 million to $87 million.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 $15 million, $10 million, and $9 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Future minimum lease commitments under operating leases for the years ending after December 31, 2016, are as follows:

Period	(In millions)
2017	$	9
2018	9
2019	10
2020	9
2021	9
Thereafter	152
Total	$	198

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, 2016, 2015 and 2014, the Company purchased $32 million, $40 million and $55 million, respectively, under such arrangements. As further described in Note 15, Related Party Transactions, these balances include intercompany purchases in the amount of $8 million, $13 million, and $12 million, respectively.

As of December 31, 2016, the Company's commitments under such outstanding agreements are estimated as follows:

Period	(In millions)
2017	$	13
2018	5
2019	2
2020	3
2021	3
Thereafter	19
Total	$	45

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. 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. On August 3, 2016, the court approved a stipulation entered into by the parties. The stipulation provided that the plaintiffs would file an amended complaint by August 19, 2016, which they did on August 18, 2016. The defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016. On February 24, 2017, the court approved the parties' stipulation which provides the plaintiffs' opposition is due on June 15, 2017 and defendants' reply is due on August 14, 2017.

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. Oral argument is scheduled for June 20, 2017.

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.

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Unaudited Quarterly Financial Data

12 Months Ended

Dec. 31, 2016

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. Summarized unaudited quarterly financial data is as follows:

	Quarter Ended
	December 31,			September 30,		June 30,		March 31,
	2016
	(In millions, except per share data)
Operating Revenues	$	232		$	272	$	283	$	234
Operating (Loss) Income	(99		)	117		128		72
Net (Loss) Income (a)	(115		)	50		65		2
Net (Loss) Income (b)	(126		)	47		63		1
Change	11			3		2		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

^(a) The Company's unaudited quarterly financial data was recast for the effect of the March 2017 Drop Down Assets.

^(b) As previously reported.

	Quarter Ended
	December 31,		September 30,		June 30,		March 31,
	2015
	(In millions, except per share data)
Operating Revenues	$	224	$	256	$	259	$	214
Operating Income	70		101		99		50
Net Income (Loss) (a)	12		35		44		(21		)
Net Income (Loss) (b)	12		32		42		(21		)
(Change)	—		3		2		—
Net Income (Loss) Attributable to NRG Yield, Inc.	11		17		10		(5		)
Weighted average number of Class A common shares outstanding - basic and diluted	35		35		35		35
Weighted average number of Class C common shares outstanding - basic and diluted	63		63		35		35
Earnings (Loss) per Weighted Average Class A and Class C Common Share - Basic and Diluted	$	0.12	$	0.18	$	0.15	$	(0.07	)

^(a) The Company's unaudited quarterly financial data was recast for the effect of the March 2017 Drop Down Assets.

^(b) As previously reported.

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Yield, Inc. (Parent) Footnotes

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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

Background and Basis of Presentation

Background

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.”

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, 2016, the Company and NRG have 53.3% and 46.7% 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.

Long-term Debt

Long-term Debt

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

	December 31, 2016			December 31, 2015			Interest rate % (a)	Letters of Credit Outstanding at December 31, 2016
	(In millions, except rates)
2026 Senior Notes	$	350		$	—		5.000
2024 Senior Notes	500			500			5.375
2020 Convertible Notes	271			266			3.250
2019 Convertible Notes	335			330			3.500
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 (b)	—			306			L+2.500	$	60
Project-level debt:
Alpine, due 2022	145			154			L+1.750	37
Alta Wind I, lease financing arrangement, due 2034	242			252			7.015	16
Alta Wind II, lease financing arrangement, due 2034	191			198			5.696	27
Alta Wind III, lease financing arrangement, due 2034	198			206			6.067	27
Alta Wind IV, lease financing arrangement, due 2034	128			133			5.938	19
Alta Wind V, lease financing arrangement, due 2035	206			213			6.071	30
Alta Realty Investments, due 2031	31			33			7.000	—
Alta Wind Asset Management, due 2031	18			19			L+2.375	—
Avra Valley, due 2031	57			60			L+1.750	3
Blythe, due 2028	19			21			L+1.625	6
Borrego, due 2025 and 2038	69			72			L+ 2.500/5.650	5
CVSR, due 2037	771			793			2.339 - 3.775	—
CVSR Holdco Notes, due 2037	199			—			4.680	13
El Segundo Energy Center, due 2023	443			485			L+1.625 - L+2.250	82
Energy Center Minneapolis, due 2017 and 2025	96			108			5.950 -7.250	—
Energy Center Minneapolis Series D Notes, due 2031	125			—			3.550	—
Kansas South, due 2031	30			33			L+2.000	4
Laredo Ridge, due 2028	100			104			L+1.875	10
Marsh Landing, due 2017 and 2023	370			418			L+1.750 - L+1.875	22
PFMG and related subsidiaries financing agreement, due 2030	27			29			6.000	—
Roadrunner, due 2031	37			40			L+1.625	5
South Trent Wind, due 2020	57			62			L+1.625	10
TA High Desert, due 2020 and 2032	49			52			L+2.500/5.150	8
Tapestry, due 2021	172			181			L+1.625	20
Utah Solar Portfolio, due 2022	287			—			L+2.625	13
Viento, due 2023	178			189			L+2.750	27
Walnut Creek, due 2023	310			351			L+1.625	41
WCEP Holdings, due 2023	46			46			L+3.000	—
Other	—			2			various	—
Subtotal project-level debt	4,601			4,254
Total debt	6,057			5,656
Less current maturities	(291		)	(264		)
Less deferred financing costs	(70		)	(63		)
Total long-term debt	$	5,696		$	5,329

^(a) As of December 31, 2016, L+ equals 3 month LIBOR plus x%, except for the Alpine term loan, Marsh Landing term loan, Walnut Creek term loan, Utah Solar Portfolio debt, and NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, where L+ equals 1 month LIBOR plus x% and Kansas South and Viento, where L+ equals 6 month LIBOR plus x%.

^(b) Net of discount of $16.5 million and $21.5 million as of December 31, 2016 and 2015, respectively.

^(c) Net of discount of $10 million and $15 million as of December 31, 2016 and 2015, respectively.

^(d) Applicable rate is determined by the Borrower Leverage Ratio, as defined in the credit agreement.

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 arrangement. As of December 31, 2016, 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, and interest payments will commence on March 15, 2017. 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, as described below.

NRG Yield Operating LLC 2024 Senior Notes

On August 5, 2014, NRG Yield Operating LLC issued $500 million of senior unsecured notes, or the 2024 Senior Notes. The 2024 Senior Notes bear interest at 5.375% and mature in August 2024. Interest on the notes is payable semi-annually on February 15 and August 15 of each year. The 2024 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.

2020 Convertible Senior Notes

The Company has outstanding $287.5 million aggregate principal amount of 3.25% Convertible Senior Notes due 2020, or the 2020 Convertible Notes.  The 2020 Convertible Notes are convertible, under certain circumstances, into 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. The 2020 Convertible Notes mature on June 1, 2020, unless earlier repurchased or converted in accordance with their terms. Prior to the close of business on the business day immediately preceding December 1, 2019, the 2020 Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the close of business on the second scheduled trading day immediately preceding the maturity date. The 2020 Convertible Notes are 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, 2016, the 2020 Convertible Notes were trading at approximately 97% of their face value, resulting in a total market value of $278 million compared to a carrying value of $271 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 Convertible Debt indenture. As of December 31, 2016, the Company's Class C common stock closed at $15.80 per share, resulting in a pro forma conversion value for the Convertible Notes of approximately $165 million.

During the years ended December 31, 2016 and 2015, the Company recorded the following expense in relation to the 2020 Convertible Notes at the effective rate of 5.10%:

(In millions)	2016		2015
Interest expense at 3.25% coupon rate	$	9	$	5
Debt discount amortization	4		2
Debt issuance costs amortization	1		1
	$	14	$	8

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. Interest on the 2019 Convertible Notes is payable semi-annually in arrears on February 1 and August 1 of each year. 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, 2016, the 2019 Convertible Notes were trading at approximately 99.6% of their face value, resulting in a total market value of $344 million compared to a carrying value of $335 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, 2016, the Company's Class A common stock closed at $15.36 per share, resulting in a pro forma conversion value for the Convertible Notes of approximately $228 million.

During the years ended December 31, 2016 and 2015, the Company recorded the following expense in relation to the 2019 Convertible Notes at the effective rate of 5.00%:

(In millions)	2016		2015
Interest expense at 3.5% coupon rate	$	12	$	12
Debt discount amortization	5		4
Debt issuance costs amortization	2		2
	$	19	$	18

NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility

In connection with the Company's initial public offering of Class A common stock in July 2013, as further described in Note 1, Nature of Business, NRG Yield LLC and NRG Yield Operating LLC entered into a senior secured revolving credit facility, or the Yield Credit Facility, which was amended on June 26, 2015, to, among other things, increase the availability to $495 million. The Company's revolving credit facility can be used for cash or for the issuance of letters of credit.

During 2015, the Company borrowed $254 million from the revolving credit facility to finance the acquisition of the November 2015 Drop Down Assets as discussed in Note 3, Business Acquisitions, as well asfund dividend payments and tax equity contributions.

The Company borrowed $60 million from the revolving credit facility and repaid $366 million during the year endedDecember 31, 2016. The Company used its pro rata proceeds of $97.5 million from the CVSR Holdco Financing Arrangement in July 2016, a portion of its proceeds from the issuance of the 2026 Senior Notes in August 2015, as well as its cash on hand to repay the outstanding borrowings under the revolving credit facility.

As of December 31, 2016, there were no outstanding borrowings and the Company had $60 million of letters of credit outstanding under the revolving credit facility.

Project - level Debt

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 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. Agua Caliente Borrower 2 LLC owns a 16% interest in the Agua Caliente solar farm and holds $41 million of the Agua Caliente Holdco debt. 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. Concurrent with the February 2017 borrowing, the Company entered into a letter of credit commitment of $17 million and issued same to support the Company's debt service requirement obligations. The Company pays semi-annual related fees of 2.25% on the outstanding balance.

Utah Solar Portfolio, due 2022

As part of its March 2017 Drop Down Assets acquisition, the Company assumed non-recourse debt of $287 million relating to the Utah Solar Portfolio at 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 the NRG acquisition in November 2016, and additional borrowings of $65 million incurred during 2016. The Company also entered into letter agreements for a commitment of $13 million to support the Company's debt service requirement obligations. The Company pays an availability fee of 2.625% on the amount on a quarterly basis. On March 27, 2017, the letters of credit were amended, reducing the issued amount to $11 million.

Energy Center Minneapolis LLC Series D Notes

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 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.

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.

Avenal

On March 18, 2015, Avenal, one of the Company's equity method investments, amended its credit agreement to increase its borrowings by $43 million and to reduce the related interest rate from 6 month LIBOR plus an applicable margin of 2.25% to 6 month LIBOR plus 1.75% from March 18, 2015, through March 17, 2022, 6 month LIBOR plus 2.00% from March 18, 2022, through March 17, 2027, and 6 month LIBOR plus 2.25% from March 18, 2027, through the maturity date.  As a result of the credit agreement amendment, the Company received net proceeds of $20 million after fees from its 49.95% ownership in Avenal. Effective September 30, 2015, the Company increased its ownership to 50% by acquiring an additional 0.05% membership interest in Avenal.

Lease financing arrangements

Alta Wind Holdings (Alta Wind II - V) and Alta I (operating entities) have finance lease obligations issued under lease transactions whereby the respective operating entities sold and leased back undivided interests in specific assets of the project. The sale and related lease transactions are accounted for as financing arrangements as the operating entities have continued involvement with the property. The terms and conditions of each facility lease are substantially similar. Each operating entity makes rental payments as stipulated in the facility lease agreements on a semiannual basis every June 30 and December 30 through the final maturity dates. In addition, the operating entities have a credit agreement with a group of lenders that provides for the issuance of letters of credit to support certain operating and debt service obligations. Certain operations and maintenance, as well as rent reserve requirements are satisfied by letters of credit issued under the NRG Yield Operating agreement. As of December 31, 2016, $965 million was outstanding under the finance lease obligations, and $119 million of letters of credit were issued under the credit agreement and $23 million were issued under the Yield Credit Facility.

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. In connection with the acquisition of the Alta Wind Portfolio in 2015, as described in Note 3, Business Acquisitions, the Company acquired thirty-one additional interest rate swaps, thirty of which were settled during 2015. During 2015, the Company acquired thirty-two additional interest rate swaps in connection with the January 2015 and November 2015 Drop Downs, as described in Note 3, Business Acquisitions.

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, 2016:

	% of Principal		Fixed Interest Rate		Floating Interest Rate	Notional Amount at December 31, 2016 (In millions)		Effective Date	Maturity Date
Alpine	85	%	2.744	%	3-Month LIBOR	$	115	various	December 31, 2029
Alpine	85	%	2.421	%	3-Month LIBOR	8		June 24, 2014	June 30, 2025
Avra Valley	85	%	2.333	%	3-Month LIBOR	49		November 30, 2012	November 30, 2030
AWAM	100	%	2.47	%	3-Month LIBOR	18		May 22, 2013	May 15, 2031
Blythe	75	%	3.563	%	3-Month LIBOR	14		June 25, 2010	June 25, 2028
Borrego	75	%	1.125	%	3-Month LIBOR	7		April 3, 2013	June 30, 2020
El Segundo	75	%	2.417	%	3-Month LIBOR	330		November 30, 2011	August 31, 2023
Kansas South	75	%	2.368	%	6-Month LIBOR	23		June 28, 2013	December 31, 2030
Laredo Ridge	75	%	2.31	%	3-Month LIBOR	79		March 31, 2011	March 31, 2026
Marsh Landing	75	%	3.244	%	3-Month LIBOR	342		June 28, 2013	June 30, 2023
Roadrunner	75	%	4.313	%	3-Month LIBOR	28		September 30, 2011	December 31, 2029
South Trent	75	%	3.265	%	3-Month LIBOR	43		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	155		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	230		December 15, 2016	September 30, 2036
Viento Funding II	90	%	various		6-Month LIBOR	160		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	276		June 28, 2013	May 31, 2023
WCEP Holdings	90	%	4.003	%	3-Month LIBOR	46		June 28, 2013	May 31, 2023
Total						$	2,069

Annual Maturities

Annual payments based on the maturities of the Company's debt, for the years ending after December 31, 2016, are as follows:

	(In millions)
2017	$	291
2018	304
2019	665
2020	654
2021	452
Thereafter	3,718
Total	$	6,084

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.

Commitments and Contingencies

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 $15 million, $10 million, and $9 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Future minimum lease commitments under operating leases for the years ending after December 31, 2016, are as follows:

Period	(In millions)
2017	$	9
2018	9
2019	10
2020	9
2021	9
Thereafter	152
Total	$	198

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, 2016, 2015 and 2014, the Company purchased $32 million, $40 million and $55 million, respectively, under such arrangements. As further described in Note 15, Related Party Transactions, these balances include intercompany purchases in the amount of $8 million, $13 million, and $12 million, respectively.

As of December 31, 2016, the Company's commitments under such outstanding agreements are estimated as follows:

Period	(In millions)
2017	$	13
2018	5
2019	2
2020	3
2021	3
Thereafter	19
Total	$	45

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. 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. On August 3, 2016, the court approved a stipulation entered into by the parties. The stipulation provided that the plaintiffs would file an amended complaint by August 19, 2016, which they did on August 18, 2016. The defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016. On February 24, 2017, the court approved the parties' stipulation which provides the plaintiffs' opposition is due on June 15, 2017 and defendants' reply is due on August 14, 2017.

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. Oral argument is scheduled for June 20, 2017.

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.

Dividends [Text Block]

Dividends

Cash distributions paid to NRG Yield, Inc. by its subsidiary, NRG Yield LLC, were $92 million, $69 million, and $41 million for the years ended December 31, 2016, 2015, and 2014, respectively.

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Valuation and Qualifying Accounts (Notes)

12 Months Ended

Dec. 31, 2016

Valuation and Qualifying Accounts [Abstract]

Valuation and Qualifying Accounts

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS

For the Year Ended December 31, 2016

	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Balance at End of Period
	(In millions)
Income tax valuation allowance, deducted from deferred tax assets
Year Ended December 31, 2016	$	—	$	—	$	16	$	16

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

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Basis of Presentation

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.

Principles of Consolidation

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

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 $110 million and $93 million as of December 31, 2016 and 2015, respectively.

Restricted Cash

Restricted Cash

Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use. Of these funds as of December 31, 2016, approximately $25 million is designated for current debt service payments, $13 million is designated to fund operating expenses and $37 million is designated for distributions to the Company, with the remaining $90 million restricted for reserves including debt service, performance obligations and other reserves, as well as capital expenditures.

Trade Receivables and Allowance for Doubtful Accounts

Trade Receivables and Allowance for Doubtful Accounts

Trade receivables are reported 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, 2016 and 2015.

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.

Inventory

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

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.

Asset Impairments

Asset Impairments

Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is 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.

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

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 loan.

Intangible Assets

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.

Income Taxes

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, 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.

Revenue Recognition

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, 2016, 2015, and 2014 was $553 million, $416 million, and $296 million, respectively.

Derivative Financial Instruments

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

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

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

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, 2016 and 2015, along with the additions and accretion related to the Company's ARO obligations for the year ended December 31, 2016:

	(In millions)
Balance as of December 31, 2015	$	43
Revisions in estimates for current obligations	2
Accretion — expense	3
Balance as of December 31, 2016	$	48

Guarantees

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

Investments Accounted for by the Equity Method

The Company has investments in various energy projects accounted for by the equity method, seven of which are VIEs, where the Company is not a primary beneficiary, and two of which are owned by a subsidiary that is consolidated as a VIE, 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.

Leases

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

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

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 amount 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 amount of net earnings during the reporting period. 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

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

Reclassifications

Certain prior year amounts have been reclassified for comparative purposes.

Recent Accounting Developments

Recent Accounting Developments

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 were issued to address the diversity in classification and presentation of changes in restricted cash and restricted cash equivalents on the statement of cash flows which is currently not addressed under Topic 230. The amendments of ASU No. 2016-18 would 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 should be applied retrospectively.  The Company is currently evaluating the impact of the standard on the Company’s statement of cash flows.

ASU 2016-16 — In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory, or ASU No. 2016-16.  The amendments of ASU No. 2016-16 were issued to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory.  Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party which has resulted in diversity in practice and increased complexity within financial reporting.  The amendments of ASU No. 2016-16 would require an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and do not require new disclosure requirements.  The amendments of ASU No. 2016-16 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. 2016-16 should be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption.  The Company is currently evaluating the impact of the standard on the Company’s results of operations, cash flows and financial position.

ASU 2016-15 — In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments, or ASU No. 2016-15. The amendments of ASU No. 2016-15 were issued to address eight specific cash flow issues for which stakeholders have indicated to the FASB that a diversity in practice existed in how entities were presenting and classifying these items in the statement of cash flows. The issues addressed by ASU No. 2016-15 include but are not limited to the classification of debt prepayment and debt extinguishment costs, payments made for contingent consideration for a business combination, proceeds from the settlement of insurance proceeds, distributions received from equity method investees and separately identifiable cash flows and the application of the predominance principle. The amendments of ASU No. 2016-15 are effective for public entities for fiscal years beginning after December 15, 2017 and interim periods in those fiscal years. Early adoption is permitted, including adoption in an interim fiscal period with all amendments adopted in the same period. The adoption of ASU No. 2016-15 is required to be applied retrospectively. The Company is currently evaluating the impact of the standard on the Company's statement of cash flows.

ASU 2016-07 — In March 2016, the FASB issued ASU No. 2016-07, Investments - Equity Method and Joint Ventures (Topic 323), or ASU No. 2016-07. The amendments of ASU No. 2016-07 eliminate the requirement that when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations, and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. The amendments require that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting with no retroactive adjustment to the investment. In addition, ASU No. 2016-07 requires that an entity that has an available-for-sale equity security that becomes qualified for the equity method of accounting recognize through earnings the unrealized holding gain or loss in accumulated other comprehensive income at the date the investment becomes qualified for use of the equity method. The Company adopted this standard effective January 1, 2017. The adoption of ASU No. 2016-07 is required to be applied prospectively. The Company does not expect the standard to have a material impact on its results of operations, cash flows and financial position.

ASU 2016-02 — In 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 expects to adopt the standard effective January 1, 2019 utilizing the required modified retrospective approach for the earliest period presented. 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 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. As this review is still in process, it is currently not practicable to quantify the impact of adopting the ASU at this time.

ASU 2016-01 — In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, or ASU No. 2016-01. The amendments of ASU No. 2016-01 eliminate available-for-sale classification of equity investments and require that equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be generally measured at fair value with changes in fair value recognized in net income.  Further, the amendments require that financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset.  The guidance in ASU No. 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.

ASU 2015-16 — In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, or ASU No. 2015-16. The amendments of ASU No. 2015-16 require that an acquirer recognize measurement period adjustments to the provisional amounts recognized in a business combination in the reporting period during which the adjustments are determined. Additionally, the amendments of ASU No. 2015-16 require the acquirer to record in the same period's financial statements the effect on earnings of changes in depreciation, amortization or other income effects, if any, as a result of the measurement period adjustment, calculated as if the accounting had been completed at the acquisition date as well as disclosing on either the face of the income statement or in the notes the portion of the amount recorded in current period earnings that would have been recorded in previous reporting periods. The guidance in ASU No. 2015-16 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amendments should be applied prospectively. The Company adopted ASU No. 2015-16 for the year ended December 31, 2016, and the adoption did not have a material impact on the Company's results of operations, cash flows and financial position.

ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU No. 2014-09, 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 expects to adopt the standard effective January 1, 2018 and apply the guidance retrospectively to contracts at the date of adoption. The Company will recognize the cumulative effect of applying Topic 606 at the date of initial application, as prescribed under the modified retrospective transition method. The Company also expects to elect 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. As leases are excluded from the scope of Topic 606, the Company expects the standard to have an immaterial impact on the Company's results of operations, cash flows and financial position; however, the Company continues to assess the impact in connection with its plan of adoption.

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Segment Reporting Segment Reporting (Policies)

12 Months Ended

Dec. 31, 2016

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).

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Nature of Business Nature of Business (Tables)

12 Months Ended

Dec. 31, 2016

Nature of Business Disclosure [Abstract]

IPO of NRG Yield

The following table represents the structure of the Company as of December 31, 2016:

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	2035
Desert Sunlight 300	25	%	75	Pacific Gas and Electric	2040
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 (e)	50	%	265	PacifiCorp	2036
			921
Distributed Solar
AZ DG Solar Projects	100	%	5	Various	2025 - 2033
PFMG DG Solar Projects	51	%	4	Various	2032
			9
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)	74.3	%	16	Corn Belt Power Cooperative	2027
Elbow Creek (b)	75	%	92	NRG Power Marketing LLC	2022
Elkhorn Ridge (b)	50.3	%	41	Nebraska Public Power District	2029
Forward (b)	75	%	22	Constellation NewEnergy, Inc.	2017
Goat Wind (b)	74.9	%	113	Dow Pipeline Company	2025
Hardin (b)	74.3	%	11	Interstate Power and Light Company	2027
Laredo Ridge	100	%	80	Nebraska Public Power District	2031
Lookout (b)	75	%	29	Southern Maryland Electric Cooperative	2030
Odin (b)	74.9	%	15	Missouri River Energy Services	2028
Pinnacle	100	%	55	Maryland Department of General Services and University System of Maryland	2031
San Juan Mesa (b)	56.3	%	68	Southwestern Public Service Company	2025
Sleeping Bear (b)	75	%	71	Public Service Company of Oklahoma	2032
South Trent	100	%	101	AEP Energy Partners	2029
Spanish Fork (b)	75	%	14	PacifiCorp	2028

Projects	Percentage Ownership		Net Capacity (MW) (a)	Offtake Counterparty	Expiration
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)	74.9	%	121	Southwestern Public Service Company	2027
			1,999
Thermal
Thermal equivalent MWt(c)	100	%	1,319	Various	Various
NRG Energy Center Dover LLC	100	%	103	NRG Power Marketing LLC	2018
Thermal generation	100	%	20	Various	Various
			1,442
Total net capacity (excluding equivalent MWt) (d)			4,997

^(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, 2016.

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

^(c) 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.

^(d) NRG Yield's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's generation capacity including this noncontrolling interest was 5,003 MWs.

^(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).

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

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Schedule of Asset Retirement Obligations [Table Text Block]

The following table represents the balance of ARO obligations as of December 31, 2016 and 2015, along with the additions and accretion related to the Company's ARO obligations for the year ended December 31, 2016:

	(In millions)
Balance as of December 31, 2015	$	43
Revisions in estimates for current obligations	2
Accretion — expense	3
Balance as of December 31, 2016	$	48

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Business Acquisitions Business Acquisitions (Tables)

12 Months Ended

Dec. 31, 2016

2017 Drop Down Assets [Member]

Business Acquisition [Line Items]

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

The following tables present the Company's historical information summary combining the financial information for the March 2017 Drop Down Assets transferred in connection with the acquisitions:

	As of December 31, 2016
	As Previously Reported		March 2017 Drop Down Assets		As Currently Reported
(In millions)
Current assets	$	645	$	11	$	656
Property, plant and equipment	5,460		—		5,460
Non-current assets	2,278		442		2,720
Total assets	8,383		453		8,836
Debt	5,708		279		5,987
Other current and non-current liabilities	305		5		310
Total liabilities	6,013		284		6,297
Net assets	$	2,370	$	169	$	2,539

	As of December 31, 2015
	As Previously Reported		March 2017 Drop Down Assets		As Currently Reported
(In millions)
Current assets	$	416	$	—	$	416
Property, plant and equipment	5,878		—		5,878
Non-current assets	2,395		100		2,495
Total assets	8,689		100		8,789
Debt	5,593		—		5,593
Other current and non-current liabilities	358		—		358
Total liabilities	5,951		—		5,951
Net assets	$	2,738	$	100	$	2,838

	Year ended December 31, 2016
	As Previously Reported			March 2017 Drop Down Assets		As Currently Reported
(In millions)
Total operating revenues	$	1,021		$	—	$	1,021
Operating income	218			—		218
Net (loss) income	(15		)	17		2

	Year ended December 31, 2015
	As Previously Reported		March 2017 Drop Down Assets		As Currently Reported
(In millions)
Total operating revenues	$	953	$	—	953
Operating income	320		—		320
Net income	65		5		70

	Year ended December 31, 2014
	As Previously Reported		March 2017 Drop Down Assets		As Currently Reported
(In millions)
Total operating revenues	$	828	$	—	$	828
Operating income	306		—		306
Net income	108		5		113

CVSR [Member]

Business Acquisition [Line Items]

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

The following is the summary of historical net liabilities assumed in connection with the CVSR Drop Down as of September 1, 2016:

	CVSR
	(In millions)
Current assets	$	95
Property, plant and equipment	826
Non-current assets	13
Total assets	934
Debt (a)	966
Other current and non-current liabilities	12
Total liabilities	978
Net liabilities assumed	(44		)
Accumulated other comprehensive loss	(25		)
Historical net liabilities assumed	$	(19	)

^(a) Net of deferred financing costs of $5 million.

Alta Wind Portfolio [Member]

Business Acquisition [Line Items]

Business Acquisition, Purchase Price [Table Text Block]

The purchase price of $923 million was allocated as follows:

	Acquisition Date Fair Value at December 31, 2014		Measurement period adjustments			Revised Acquisition Date
Assets	(In millions)
Cash	$	22	$	—		$	22
Current and non-current assets	49		(2		)	47
Property, plant and equipment	1,304		6			1,310
Intangible assets	1,177		(6		)	1,171
Total assets acquired	2,552		(2		)	2,550
Liabilities
Debt	1,591		—			1,591
Current and non-current liabilities	38		(2		)	36
Total liabilities assumed	1,629		(2		)	1,627
Net assets acquired	$	923	$	—		$	923

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016			December 31, 2015			Depreciable Lives
	(In millions)
Facilities and equipment	$	6,215		$	6,480		2 - 40 Years
Land and improvements	171			171
Construction in progress (a)	25			9
Total property, plant and equipment	6,411			6,660
Accumulated depreciation	(951		)	(782		)
Net property, plant and equipment	$	5,460		$	5,878

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

12 Months Ended

Dec. 31, 2016

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, 2016:

(In millions)	NRG Wind TE Holdco		Alta TE Holdco		Spring Canyon
Other current and non-current assets	$	193	$	17	$	4
Property, plant and equipment	441		461		100
Intangible assets	2		274		—
Total assets	636		752		104
Current and non-current liabilities	209		9		6
Total liabilities	209		9		6
Noncontrolling interest	139		107		67
Net assets less noncontrolling interests	$	288	$	636	$	31

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, 2016:

Name	Economic Interest	Investment Balance
		(In millions)
Utah Solar Portfolio (a)	50%	$346
Desert Sunlight	25%	282
GenConn(b)	50%	106
Agua Caliente Borrower 2	16%	96
Elkhorn Ridge(c)	50.3%	85
San Juan Mesa(c)	56.3%	74
NRG DGPV Holdco 1 LLC (d)	95%	75
NRG DGPV Holdco 2 LLC (d)	95%	24
NRG RPV Holdco 1 LLC(d)	95%	71
Avenal	50%	(7)
Total equity investments in affiliates		$1,152

^(a) Economic interest based on cash to be distributed. Four Brothers Solar, LLC, Granite Mount Holdings, LLC and Iron Spring 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 75% 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, and NRG RPV Holdco 1 LLC are tax equity structures and VIEs. The related allocations are described below.

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,
	2016			2015			2014
Income Statement Data:	(In millions)
GenConn
Operating revenues	$	72		$	78		$	82
Operating income	38			40			40
Net income	26			28			28
Desert Sunlight
Operating revenues	$	211		$	206		134
Operating income	129			124			74
Net income	80			73			37
Utah Solar Portfolio (a)
Operating revenues	$	13		$	—		$	—
Operating loss	(6		)	(1		)	—
Net loss	(6		)	(1		)	—
				As of December 31,
				2016			2015
Balance Sheet Data:				(In millions)
GenConn
Current assets				$	36		$	36
Non-current assets				389			416
Current liabilities				16			16
Non-current liabilities				196			215
Desert Sunlight
Current assets				$	281		$	310
Non-current assets				1,401			1,435
Current liabilities				64			82
Non-current liabilities				1,043			1,086
Utah Solar Portfolio (a)
Current assets				$	20		$	11
Non-current assets				1,105			705
Current liabilities				14			229
Non-current liabilities				38			—

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

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

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

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, 2016				As of December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable, including current portion	$	30	$	30	$	47	$	47
Liabilities:
Long-term debt, including current portion	$	6,057	$	6,056	$	5,656	$	5,538

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, 2016 and 2015:

	As of December 31, 2016				As of December 31, 2015
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	1,455	$	4,601	$	978	$	4,560

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, 2016		As of December 31, 2016		As of December 31, 2015
	Fair Value (a)		Fair Value (a)		Fair Value (a)
(In millions)	Level 1		Level 2		Level 2
Derivative assets:
Commodity contracts	$	1	$	1	$	—
Interest rate contracts	—		1		—
Total assets	$	1	$	2	$	—
Derivative liabilities:
Commodity contracts	$	—	$	1	$	2
Interest rate contracts	—		75		98
Total liabilities	$	—	$	76	$	100

^(a) There were no assets or liabilities classified as Level 1 as of December 31, 2015. There were no assets or liabilities classified Level 3 as of December 31, 2016 and 2015.

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Accounting for Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2016

Accounting for Derivative Instruments and Hedging Activities Disclosure [Abstract]

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, 2016 and 2015:

		Total Volume
		December 31, 2016		December 31, 2015
Commodity	Units	(In millions)
Natural Gas	MMBtu	3		4
Interest	Dollars	$	2,070	$	1,991

Fair value within the derivative instrument valuation on the balance sheets

The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:

	Fair Value
	Derivative Assets		Derivative Liabilities
	December 31, 2016		December 31, 2016		December 31, 2015
	(In millions)
Derivatives Designated as Cash Flow Hedges:
Interest rate contracts current	$	—	$	26	$	34
Interest rate contracts long-term	1		39		56
Total Derivatives Designated as Cash Flow Hedges	1		65		90
Derivatives Not Designated as Cash Flow Hedges:
Interest rate contracts current	—		5		3
Interest rate contracts long-term	—		5		5
Commodity contracts current	2		1		2
Total Derivatives Not Designated as Cash Flow Hedges	2		11		10
Total Derivatives	$	3	$	76	$	100

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

The following table summarizes the offsetting of derivatives by counterparty master agreement level as of December 31, 2016:

	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	(75		)	1			(74		)
Total interest rate contracts	(74		)	—			(74		)
Total derivative instruments	$	(73	)	$	—		$	(73	)

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,
	2016			2015			2014
	(In millions)
Accumulated OCL beginning balance	$	(83	)	$	(76	)	$	(16	)
Reclassified from accumulated OCL to income due to realization of previously deferred amounts	13			14			14
Mark-to-market of cash flow hedge accounting contracts	—			(21		)	(74		)
Accumulated OCL ending balance, net of income tax benefit of $16, $16 and $6, respectively	$	(70	)	$	(83	)	$	(76	)
Accumulated OCL attributable to noncontrolling interests	(42		)	(56		)	(67		)
Accumulated OCL attributable to NRG Yield, Inc.	$	(28	)	$	(27	)	$	(9	)
Losses expected to be realized from OCL during the next 12 months, net of income tax benefit of $3	$	16

Amounts reclassified from accumulated OCL into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to interest expense. There was no ineffectiveness for the years ended December 31, 2016, 2015 and 2014.

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.

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Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016	PPAs			Leasehold Rights			Customer Relationships			Customer Contracts			Emission Allowances			Development Rights			Other			Total
(In millions)
January 1, 2016	$	1,264		$	86		$	66		$	15		$	15		$	3		$	6		$	1,455
Other	—			—			—			—			(6		)	—			—			(6		)
December 31, 2016	1,264			86			66			15			9			3			6			1,449
Less accumulated amortization	(138		)	(9		)	(4		)	(7		)	(2		)	(1		)	(2		)	(163		)
Net carrying amount	$	1,126		$	77		$	62		$	8		$	7		$	2		$	4		$	1,286

Year ended December 31, 2015	PPAs			Leasehold Rights			Customer Relationships			Customer Contracts			Emission Allowances			Development Rights			Other			Total
(In millions)
January 1, 2015	$	1,270		$	86		$	66		$	15		$	16		$	3		$	6		$	1,462
Other	(6		)	—			—			—			(1		)	—			—			(7		)
December 31, 2015	1,264			86			66			15			15			3			6			1,455
Less accumulated amortization	(75		)	(5		)	(3		)	(6		)	(1		)	(1		)	(2		)	(93		)
Net carrying amount	$	1,189		$	81		$	63		$	9		$	14		$	2		$	4		$	1,362

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Long-term Debt (Tables)

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Schedule of Effective Interest Rate [Table Text Block]

During the years ended December 31, 2016 and 2015, the Company recorded the following expense in relation to the 2019 Convertible Notes at the effective rate of 5.00%:

(In millions)	2016		2015
Interest expense at 3.5% coupon rate	$	12	$	12
Debt discount amortization	5		4
Debt issuance costs amortization	2		2
	$	19	$	18

Schedule of long-term debt

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

	December 31, 2016			December 31, 2015			Interest rate % (a)	Letters of Credit Outstanding at December 31, 2016
	(In millions, except rates)
2026 Senior Notes	$	350		$	—		5.000
2024 Senior Notes	500			500			5.375
2020 Convertible Notes	271			266			3.250
2019 Convertible Notes	335			330			3.500
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 (b)	—			306			L+2.500	$	60
Project-level debt:
Alpine, due 2022	145			154			L+1.750	37
Alta Wind I, lease financing arrangement, due 2034	242			252			7.015	16
Alta Wind II, lease financing arrangement, due 2034	191			198			5.696	27
Alta Wind III, lease financing arrangement, due 2034	198			206			6.067	27
Alta Wind IV, lease financing arrangement, due 2034	128			133			5.938	19
Alta Wind V, lease financing arrangement, due 2035	206			213			6.071	30
Alta Realty Investments, due 2031	31			33			7.000	—
Alta Wind Asset Management, due 2031	18			19			L+2.375	—
Avra Valley, due 2031	57			60			L+1.750	3
Blythe, due 2028	19			21			L+1.625	6
Borrego, due 2025 and 2038	69			72			L+ 2.500/5.650	5
CVSR, due 2037	771			793			2.339 - 3.775	—
CVSR Holdco Notes, due 2037	199			—			4.680	13
El Segundo Energy Center, due 2023	443			485			L+1.625 - L+2.250	82
Energy Center Minneapolis, due 2017 and 2025	96			108			5.950 -7.250	—
Energy Center Minneapolis Series D Notes, due 2031	125			—			3.550	—
Kansas South, due 2031	30			33			L+2.000	4
Laredo Ridge, due 2028	100			104			L+1.875	10
Marsh Landing, due 2017 and 2023	370			418			L+1.750 - L+1.875	22
PFMG and related subsidiaries financing agreement, due 2030	27			29			6.000	—
Roadrunner, due 2031	37			40			L+1.625	5
South Trent Wind, due 2020	57			62			L+1.625	10
TA High Desert, due 2020 and 2032	49			52			L+2.500/5.150	8
Tapestry, due 2021	172			181			L+1.625	20
Utah Solar Portfolio, due 2022	287			—			L+2.625	13
Viento, due 2023	178			189			L+2.750	27
Walnut Creek, due 2023	310			351			L+1.625	41
WCEP Holdings, due 2023	46			46			L+3.000	—
Other	—			2			various	—
Subtotal project-level debt	4,601			4,254
Total debt	6,057			5,656
Less current maturities	(291		)	(264		)
Less deferred financing costs	(70		)	(63		)
Total long-term debt	$	5,696		$	5,329

^(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, 2016:

	% of Principal		Fixed Interest Rate		Floating Interest Rate	Notional Amount at December 31, 2016 (In millions)		Effective Date	Maturity Date
Alpine	85	%	2.744	%	3-Month LIBOR	$	115	various	December 31, 2029
Alpine	85	%	2.421	%	3-Month LIBOR	8		June 24, 2014	June 30, 2025
Avra Valley	85	%	2.333	%	3-Month LIBOR	49		November 30, 2012	November 30, 2030
AWAM	100	%	2.47	%	3-Month LIBOR	18		May 22, 2013	May 15, 2031
Blythe	75	%	3.563	%	3-Month LIBOR	14		June 25, 2010	June 25, 2028
Borrego	75	%	1.125	%	3-Month LIBOR	7		April 3, 2013	June 30, 2020
El Segundo	75	%	2.417	%	3-Month LIBOR	330		November 30, 2011	August 31, 2023
Kansas South	75	%	2.368	%	6-Month LIBOR	23		June 28, 2013	December 31, 2030
Laredo Ridge	75	%	2.31	%	3-Month LIBOR	79		March 31, 2011	March 31, 2026
Marsh Landing	75	%	3.244	%	3-Month LIBOR	342		June 28, 2013	June 30, 2023
Roadrunner	75	%	4.313	%	3-Month LIBOR	28		September 30, 2011	December 31, 2029
South Trent	75	%	3.265	%	3-Month LIBOR	43		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	155		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	230		December 15, 2016	September 30, 2036
Viento Funding II	90	%	various		6-Month LIBOR	160		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	276		June 28, 2013	May 31, 2023
WCEP Holdings	90	%	4.003	%	3-Month LIBOR	46		June 28, 2013	May 31, 2023
Total						$	2,069

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, 2016, are as follows:

	(In millions)
2017	$	291
2018	304
2019	665
2020	654
2021	452
Thereafter	3,718
Total	$	6,084

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2016

Earnings (Loss) Per Share Disclosure [Abstract]

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

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

	Year Ended December 31, 2016				Year Ended December 31, 2015				Year Ended December 31, 2014
(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 earnings per share attributable to NRG Yield, Inc. common stockholders
Net income attributable to NRG Yield, Inc.	$	20	$	37	$	14	$	19	$	8	$	8
Weighted average number of common shares outstanding — basic and diluted	35		63		35		49		28		28
Earnings per weighted average common share — basic and diluted	$	0.58	$	0.58	$	0.40	$	0.40	$	0.30	$	0.30

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Stockholders' Equity Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016:

	Fourth Quarter 2016		Third Quarter 2016		Second Quarter 2016		First Quarter 2016
Distributions per Class B unit	$	0.25	$	0.24	$	0.23	$	0.225
Distributions per Class D unit	$	0.25	$	0.24	$	0.23	$	0.225

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, 2016:

	Fourth Quarter 2016		Third Quarter 2016		Second Quarter 2016		First Quarter 2016
Dividends per Class A share	$	0.25	$	0.24	$	0.23	$	0.225
Dividends per Class C share	$	0.25	$	0.24	$	0.23	$	0.225

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Segment Reporting (Tables)

12 Months Ended

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, 2016, 2015 and 2014:

	2016		2015		2014
Customer	Conventional (%)	Renewables (%)	Conventional (%)	Renewables (%)	Conventional (%)	Renewables (%)
SCE	21%	21%	23%	17%	24%	7%
PG&E	12%	11%	13%	12%	15%	13%

Schedule of Segment Reporting Information, by Segment

	Year ended December 31, 2014
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	317		$	316		$	195		$	—		$	828
Cost of operations	55			83			139			—			277
Depreciation and amortization	82			133			18			—			233
General and administrative	—			—			—			8			8
Acquisition-related transaction and integration costs	—			—			—			4			4
Operating income (loss)	180			100			38			(12		)	306
Equity in earnings of unconsolidated affiliates	14			8			—			—			22
Other income, net	—			5			—			1			6
Loss on debt extinguishment	—			(1		)	—			—			(1		)
Interest expense	(53		)	(126		)	(7		)	(30		)	(216		)
Income (loss) before income taxes	141			(14		)	31			(41		)	117
Income tax expense	—			—			—			4			4
Net Income (Loss)	$	141		$	(14	)	$	31		$	(45	)	$	113

	Year ended December 31, 2016
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	333		$	518		$	170		$	—		$	1,021
Cost of operations	66			126			114			—			306
Depreciation and amortization	80			197			20			—			297
Impairment losses	—			183			—			—			183
General and administrative	—			—			—			16			16
Acquisition-related transaction and integration costs	—			—			—			1			1
Operating income (loss)	187			12			36			(17		)	218
Equity in earnings of unconsolidated affiliates	13			47			—			—			60
Other income, net	1			2			—			—			3
Interest expense	(48		)	(147		)	(7		)	(78		)	(280		)
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 investment in affiliates	$	106		$	1,046		$	—		$	—		$	1,152
Capital expenditures (a)	7			2			14			—			23
Total Assets	$	1,993		$	5,988		$	426		$	429		$	8,836

	Year ended December 31, 2015
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	336		$	443		$	174		$	—		$	953
Cost of operations	59			136			126			—			321
Depreciation and amortization	81			197			19			—			297
General and administrative	—			—			—			12			12
Acquisition-related transaction and integration costs	—			—			—			3			3
Operating income (loss)	196			110			29			(15		)	320
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		)	(147		)	(7		)	(61		)	(263		)
Income (loss) before income taxes	156			(20		)	22			(76		)	82
Income tax expense	—			—			—			12			12
Net Income (Loss)	$	156		$	(20	)	$	22		$	(88	)	$	70
Balance Sheet
Equity investments in affiliates	$	110		$	687		$	—		$	—		$	797
Capital expenditures (a)	4			6			20			—			30
Total Assets	$	2,102		$	6,070		$	428		$	189		$	8,789

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income tax provision from continuing operations

The income tax provision consisted of the following amounts:

	Year Ended December 31,
	2016			2015			2014
	(In millions, except percentages)
Current
U.S. Federal	$	—		$	—		$	—
State	—			—			—
Total — current	—			—			—
Deferred
U.S. Federal	(1		)	10			2
State	—			2			2
Total — deferred	(1		)	12			4
Total income tax (benefit) expense	$	(1	)	$	12		$	4
Effective tax rate	(100.0		)%	14.6		%	3.4		%

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,
	2016			2015			2014
	(In millions, except percentages)
Income Before Income Taxes	1			82			117
Tax at 35%	—			29			41
State taxes, net of federal benefit	—			2			1
Investment tax credits	(1		)	(1		)	—
Impact of non-taxable partnership earnings	(1		)	(17		)	(33		)
Production tax credits, including prior year true-up	4			(4		)	(6		)
Change in state effective tax rate	—			—			1
Other	(3		)	3			—
Income tax (benefit) expense	$	(1	)	$	12		$	4
Effective income tax rate	(100.0		)%	14.6		%	3.4		%

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,
	2016			2015
	(In millions)
Deferred tax liabilities:
Investment in projects	$	3		$	27
Total deferred tax liabilities	3			27
Deferred tax assets:
Production tax credits carryforwards	5			10
Investment tax credits	1			1
U.S. Federal net operating loss carryforwards	226			181
State net operating loss carryforwards	3			5
Total deferred tax assets	235			197
Valuation allowance	$	(16	)	$	—
Total deferred tax assets, net of valuation allowance	$	219		$	197
Net deferred noncurrent tax asset	$	216		$	170

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Long-term Purchase Commitment [Table Text Block]

As of December 31, 2016, the Company's commitments under such outstanding agreements are estimated as follows:

Period	(In millions)
2017	$	13
2018	5
2019	2
2020	3
2021	3
Thereafter	19
Total	$	45

Future minimum lease commitments under operating leases

Future minimum lease commitments under operating leases for the years ending after December 31, 2016, are as follows:

Period	(In millions)
2017	$	9
2018	9
2019	10
2020	9
2021	9
Thereafter	152
Total	$	198

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Unaudited Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Summary of Unaudited Quarterly Financial Data

Summarized unaudited quarterly financial data is as follows:

	Quarter Ended
	December 31,			September 30,		June 30,		March 31,
	2016
	(In millions, except per share data)
Operating Revenues	$	232		$	272	$	283	$	234
Operating (Loss) Income	(99		)	117		128		72
Net (Loss) Income (a)	(115		)	50		65		2
Net (Loss) Income (b)	(126		)	47		63		1
Change	11			3		2		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

^(a) The Company's unaudited quarterly financial data was recast for the effect of the March 2017 Drop Down Assets.

^(b) As previously reported.

	Quarter Ended
	December 31,		September 30,		June 30,		March 31,
	2015
	(In millions, except per share data)
Operating Revenues	$	224	$	256	$	259	$	214
Operating Income	70		101		99		50
Net Income (Loss) (a)	12		35		44		(21		)
Net Income (Loss) (b)	12		32		42		(21		)
(Change)	—		3		2		—
Net Income (Loss) Attributable to NRG Yield, Inc.	11		17		10		(5		)
Weighted average number of Class A common shares outstanding - basic and diluted	35		35		35		35
Weighted average number of Class C common shares outstanding - basic and diluted	63		63		35		35
Earnings (Loss) per Weighted Average Class A and Class C Common Share - Basic and Diluted	$	0.12	$	0.18	$	0.15	$	(0.07	)

^(a) The Company's unaudited quarterly financial data was recast for the effect of the March 2017 Drop Down Assets.

^(b) As previously reported.

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Nature of Business (Details) - MW			12 Months Ended
		Jul. 29, 2014	Dec. 31, 2016	Aug. 31, 2016	Nov. 02, 2015	Jun. 30, 2015
Nature of Business
Power Generation Capacity, Megawatts	[1],[2]		4,997
Megawatts Thermal Equivalent, Available Under right-to-use Provisions			134
Power Generation Capacity, Megawatts, including portion attributable to noncontrolling interest	[1],[2]		5,003
Conventional Generation [Member]
Nature of Business
Power Generation Capacity, Megawatts	[1]		1,945
Utility-Scale Solar
Nature of Business
Power Generation Capacity, Megawatts	[1]		921
Distributed Solar
Nature of Business
Power Generation Capacity, Megawatts	[1]		9
Wind Farms [Member]
Nature of Business
Power Generation Capacity, Megawatts	[1]		1,999
Thermal [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		1,442
Steam and Chilled Water Capacity, Megawatts Thermal Equivalent	[1],[3]		1,319
Thermal [Member] | Thermal [Member]
Nature of Business
Power Generation Capacity, Megawatts	[1]		20
NRG Yield LLC | NRG Yield, Inc. [Member]
Nature of Business
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Voting Interest			44.90%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		53.30%	53.30%
NRG Yield LLC | NRG
Nature of Business
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Voting Interest			55.10%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		46.70%	46.70%
GenConn Middletown [Member] | Conventional Generation [Member]
Nature of Business
Equity Method Investment, Ownership Percentage			50.00%
Power Generation Capacity, Megawatts	[1]		95
GenConn Devon [Member] | Conventional Generation [Member]
Nature of Business
Equity Method Investment, Ownership Percentage			50.00%
Power Generation Capacity, Megawatts	[1]		95
Marsh Landing | Conventional Generation [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		720
El Segundo [Member] | Conventional Generation [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		550
Walnut Creek [Member] | Conventional Generation [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		485
Agua Caliente [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership			16.00%
Power Generation Capacity, Megawatts	[1]		46
Alpine [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		66
Avenal [Member] | Utility-Scale Solar
Nature of Business
Equity Method Investment, Ownership Percentage			50.00%			49.95%
Power Generation Capacity, Megawatts	[1]		23
Avra Valley [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		26
NRG Solar Blythe LLC [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		21
Borrego [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		26
NRG Solar Roadrunner LLC [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		20
CVSR [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		250
RE Kansas South [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		20
TA - High Desert LLC [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		20
Utah Solar Portfolio [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership			50.00%
Power Generation Capacity, Megawatts	[1]		265
Desert Sunlight [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership			25.00%
AZ DG Solar Projects | Distributed Solar
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		5
PFMG DG Solar Projects | Distributed Solar
Nature of Business
Percentage of Ownership			51.00%
Power Generation Capacity, Megawatts	[1]		4
Alta I [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		150
Alta II [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		150
Alta III [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		150
Alta IV [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		102
Alta V [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		168
Alta X [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership	[3]		100.00%
Power Generation Capacity, Megawatts	[1],[3]		137
Alta XI [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership	[3]		100.00%
Power Generation Capacity, Megawatts	[1],[3]		90
South Trent | Wind Farms [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		101
Spanish Fork [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			75.00%
Power Generation Capacity, Megawatts	[1],[4]		14
Laredo Ridge [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		80
Lookout [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			75.00%
Power Generation Capacity, Megawatts	[1],[4]		29
Odin Wind Farm [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			74.90%
Power Generation Capacity, Megawatts	[1],[4]		15
Taloga [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		130
Pinnacle [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		55
San Juan Mesa Wind Project, LLC [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			56.30%
Power Generation Capacity, Megawatts	[1],[4]		68
Sleeping Bear [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			75.00%
Power Generation Capacity, Megawatts	[1],[4]		71
Buffalo Bear [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		19
Crosswinds [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			74.30%
Power Generation Capacity, Megawatts	[1],[4]		16
Elbow Creek [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			75.00%
Power Generation Capacity, Megawatts	[1],[4]		92
Forward [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			75.00%
Power Generation Capacity, Megawatts	[1],[4]		22
Goat Wind [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			74.90%
Power Generation Capacity, Megawatts	[1],[4]		113
Elkhorn Ridge Wind, LLC [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			50.30%
Power Generation Capacity, Megawatts	[1],[4]		41
Hardin [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			74.30%
Power Generation Capacity, Megawatts	[1],[4]		11
Spring Canyon [Member] | Wind Farms [Member]
Nature of Business
Power Generation Capacity, Megawatts attributed to noncontrolling interest			6
Spring Canyon II [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			90.10%
Power Generation Capacity, Megawatts	[1],[4]		29
Spring Canyon III [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			90.10%
Power Generation Capacity, Megawatts	[1],[4]		25
Wildorado [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership			74.90%
Power Generation Capacity, Megawatts	[1],[4]		121
NRG Energy Center Dover [Member] | Thermal [Member]
Nature of Business
Percentage of Ownership			100.00%
Power Generation Capacity, Megawatts	[1]		103
CVSR [Member]
Nature of Business
Equity Method Investment, Ownership Percentage				48.95%
November 2015 Drop Down Assets [Member] | Wind Farms [Member]
Nature of Business
Power Generation Capacity, Megawatts					814
Southern California Edison [Member] | Desert Sunlight [Member] | Utility-Scale Solar
Nature of Business
Power Generation Capacity, Megawatts	[1]		63
Pacific Gas and Electric [Member] | Desert Sunlight [Member] | Utility-Scale Solar
Nature of Business
Power Generation Capacity, Megawatts	[1]		75

[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, 2016.

[2] NRG Yield's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's generation capacity including this noncontrolling interest was 5,003 MWs.

[3] c) 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.

[4] (b) Projects are part of tax equity arrangements.

XML

Nature of Business - Drop Down Assets (Details) - USD ($) $ in Millions	Mar. 27, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Pro-Rate Share of Debt Held by Unconsolidated Affiliates		$ 589
Agua Caliente Borrower 2 [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage		16.00%
Subsequent Event [Member] | Agua Caliente Borrower 2 [Member]
Business Acquisition [Line Items]
Pro-Rate Share of Debt Held by Unconsolidated Affiliates	$ 135
Subsequent Event [Member] | March 2017 Drop Down Assets [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	130
Business Acquisition, Consideration Transferred, Working Capital	1
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	$ 328
Subsequent Event [Member] | Agua Caliente [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage	16.00%

XML

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary of Significant Accounting Policies [Line Items]
Asset Retirement Obligation, Accretion Expense		$ 3
Income Taxes, Threshold Percentage		50.00%
Contingent Rental Income Associated with PPAs		$ 553	$ 416	$ 296
Asset Retirement Obligation		48	43
Deferred Tax Assets, Net		216	170
Proceeds from renewable energy grants	[1]	0	0	$ 422
Asset Retirement Obligation, Revision of Estimate		2
Project Level Subsidiaries [Member]
Summary of Significant Accounting Policies [Line Items]
Other Cash Equivalents, at Carrying Value		110	$ 93
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		13
Cash Distribution [Member]
Summary of Significant Accounting Policies [Line Items]
Restricted Cash and Cash Equivalents		37
Reserves [Member]
Summary of Significant Accounting Policies [Line Items]
Restricted Cash and Cash Equivalents		$ 90

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

XML

Business Acquisitions - 2017 Acquisitions (Details) - USD ($) $ in Millions	Mar. 27, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Debt (Current and non-current) (a)		$ 6,057	$ 5,656
Agua Caliente Borrower 2 [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage		16.00%
Subsequent Event [Member] | March 2017 Drop Down Assets [Member]
Business Acquisition [Line Items]
Percentage of Right to Receive Cash Distributed	50.00%
Payments to Acquire Businesses, Gross	$ 130
Business Combination, Working Capital Adjustments	$ 1
Subsequent Event [Member] | Agua Caliente [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage	16.00%
Subsequent Event [Member] | Agua Caliente Borrower 2 [Member] | March 2017 Drop Down Assets [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	31.00%
Business Combination, Consideration Transferred, Liabilities Incurred	$ 41
Subsequent Event [Member] | March 2017 Drop Down Assets [Member]
Business Acquisition [Line Items]
Net assets acquired	$ 8
Subsequent Event [Member] | Utah Solar Portfolio [Member] | March 2017 Drop Down Assets [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	51.00%
Business Combination, Consideration Transferred, Liabilities Incurred	$ 287

XML

Business Acquisition - Drop Down Assets (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Business Acquisition [Line Items]
Current assets	[1]	$ 656				$ 416				$ 656		$ 416
Property, plant and equipment	[1]	5,460				5,878				5,460		5,878
Non-current assets	[1]	2,720				2,495				2,720		2,495
Total Assets	[1]	8,836				8,789				8,836		8,789
Debt		5,987				5,593				5,987		5,593
Other current and non-current liabilities		310				358				310		358
Total Liabilities	[1]	6,297				5,951				6,297		5,951
Net assets		2,539				2,838				2,539		2,838
Total operating revenues		232	$ 272	$ 283	$ 234	224	$ 256	$ 259	$ 214	1,021	[2]	953	[2]	$ 828	[2]
Operating income		(99)	117	128	72	70	101	99	50	218	[2]	320	[2]	306	[2]
Net (loss) income		(126)	47	63	1	12	32	42	(21)	2	[2],[3]	70	[2],[3],[4]	113	[2],[3],[4]
Scenario, Previously Reported [Member]
Business Acquisition [Line Items]
Current assets		645				416				645		416
Property, plant and equipment		5,460				5,878				5,460		5,878
Non-current assets		2,278				2,395				2,278		2,395
Total Assets		8,383				8,689				8,383		8,689
Debt		5,708				5,593				5,708		5,593
Other current and non-current liabilities		305				358				305		358
Total Liabilities		6,013				5,951				6,013		5,951
Net assets		2,370				2,738				2,370		2,738
Total operating revenues										1,021		953		828
Operating income										218		320		306
Net (loss) income		(115)	$ 50	$ 65	$ 2	12	$ 35	$ 44	$ (21)	(15)		65		108
March 2017 Drop Down Assets [Member]
Business Acquisition [Line Items]
Current assets		11				0				11		0
Property, plant and equipment		0				0				0		0
Non-current assets		442				100				442		100
Total Assets		453				100				453		100
Debt		279				0				279		0
Other current and non-current liabilities		5				0				5		0
Total Liabilities		284				0				284		0
Net assets		$ 169				$ 100				169		100
Total operating revenues										0		0		0
Operating income										0		0		0
Net (loss) income										$ 17		$ 5		$ 5

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[3] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[4] Retrospectively adjusted as discussed in Note 1, Nature of Business.

XML

Business Acquisitions Business Acquisitions - CVSR (Details) - USD ($) $ in Millions			1 Months Ended	12 Months Ended
		Sep. 02, 2016	Sep. 30, 2016	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014	Sep. 01, 2016	Aug. 31, 2016	Jun. 30, 2015	Mar. 18, 2015
Business Acquisition [Line Items]
Debt (Current and non-current) (a)				$ 6,057.0		$ 5,656.0
Current assets	[1]			656.0		416.0
Property, plant and equipment	[1]			5,460.0		5,878.0
Assets	[1]			8,836.0		8,789.0
Debt				5,987.0		5,593.0
Other current and non-current liabilities				310.0		358.0
Liabilities	[1]			6,297.0		5,951.0
Accumulated other comprehensive loss				(28.0)	[1]	(27.0)	[1]	$ (9.0)
Debt Issuance Costs, Net				70.0		63.0
Acquisition-related transaction and integration costs	[2]			1.0		3.0		$ 4.0
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, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt									$ 496.0
Business Combination, Indemnification Assets, Amount as of Acquisition Date									67.0
Current assets									95.0
Property, plant and equipment									826.0
Non-current assets									13.0
Assets									934.0
Debt									966.0
Other current and non-current liabilities									12.0
Liabilities									978.0
Net Assets									44.0
Accumulated other comprehensive loss									(25.0)
Net Assets, excluding Accumulated Other Comprehensive Income (Loss)									(19.0)
Debt Issuance Costs, Net									5.0
Acquisition-related transaction and integration costs				$ 1.0
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual			$ 22.0
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual			$ 2.0
Avenal [Member] | Utility-Scale Solar [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage				50.00%							49.95%
Business Acquisition, Percentage of Voting Interests Acquired												0.05%
CVSR [Member] | Utility-Scale Solar [Member]
Business Acquisition [Line Items]
Percentage of Ownership				100.00%
CVSR Financing Agreement [Member]
Business Acquisition [Line Items]
Debt (Current and non-current) (a)				$ 771.0		793.0
CVSR Financing Agreement [Member] | CVSR [Member]
Business Acquisition [Line Items]
Debt (Current and non-current) (a)									771.0
CVSR Holdco due 2037 [Member]
Business Acquisition [Line Items]
Debt (Current and non-current) (a)				$ 199.0		$ 0.0
CVSR Holdco due 2037 [Member] | CVSR [Member]
Business Acquisition [Line Items]
Debt (Current and non-current) (a)									$ 200.0

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

XML

Business Acquisitions Business Acquisitions - November 2015 Drop Down Assets (Details)		Feb. 19, 2016 USD ($)	Nov. 03, 2015 USD ($)	Dec. 31, 2016 MW	Nov. 02, 2015 USD ($) MW
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW	[1],[2]			4,997
November 2015 Drop Down Assets [Member]
Business Acquisition [Line Items]
Number of Facilities					12
Payments to Acquire Businesses, Gross		$ 207,000,000	$ 209,000,000
Business Acquisition, Consideration Transferred, Working Capital		$ 2,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets			30,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment			669,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets			177,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets			876,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt			193,000,000
Other current and non-current liabilities			32,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities			225,000,000
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value			282,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net			$ 369,000,000
Wind Farms [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW	[1]			1,999
Wind Farms [Member] | November 2015 Drop Down Assets [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW					814
Financial Institutions [Member] | November 2015 Drop Down Assets [Member]
Business Acquisition [Line Items]
Taxable Income Allocation, Pre-Flip			99.00%
Taxable Income Allocation, Post-Flip			8.53%
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]
Business Acquisition [Line Items]
Percentage of Cash Available for Distributions			75.00%
Post-Flip Point [Member] | November 2015 Drop Down Assets [Member]
Business Acquisition [Line Items]
Percentage of Cash Available for Distributions			68.60%
Pre-determined Date Through Flip Point If Flip Has Not Occured [Member] | Financial Institutions [Member] | November 2015 Drop Down Assets [Member]
Business Acquisition [Line Items]
Percentage of Cash Available for Distributions			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, 2016.

[2] NRG Yield's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's generation capacity including this noncontrolling interest was 5,003 MWs.

XML

Business Acquisitions Business Acquisitions - Desert Sunlight/Spring Canyon/Fuel Cell (Details)		Jun. 30, 2015	Jun. 29, 2015 USD ($)	May 08, 2015	Apr. 30, 2015	Dec. 31, 2016 MW	May 07, 2015
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1],[2]					4,997
Utility-Scale Solar [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]					921
Wind Farms [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]					1,999
Wind Farms [Member] | Spring Canyon [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired							90.10%
Wind Farms [Member] | Spring Canyon II [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts						32
Wind Farms [Member] | Spring Canyon III [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts						28
Thermal [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]					1,442
Desert Sunlight [Member]
Business Acquisition [Line Items]
Number of Facilities | $			2
Power Generation Capacity, Megawatts						550
Payments to Acquire Equity Method Investments | $			$ 285,000,000
Desert Sunlight [Member] | Utility-Scale Solar [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage						25.00%
Supply Commitment [Member] | Spring Canyon [Member]
Business Acquisition [Line Items]
Weighted average remaining amortization period (in years)				24 years
Supply Commitment [Member] | UB Fuel Cell [Member]
Business Acquisition [Line Items]
Weighted average remaining amortization period (in years)					12 years
Supply Commitment [Member] | Southern California Edison [Member] | Desert Sunlight [Member]
Business Acquisition [Line Items]
Weighted average remaining amortization period (in years)		20 years
Supply Commitment [Member] | Pacific Gas and Electric [Member] | Desert Sunlight [Member]
Business Acquisition [Line Items]
Weighted average remaining amortization period (in years)		25 years
UB Fuel Cell [Member] | Thermal [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts						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, 2016.

[2] NRG Yield's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's generation capacity including this noncontrolling interest was 5,003 MWs.

XML

Business Acquisitions Business Acquisitions - January 2015 Drop Down Assets (Details) $ in Millions		Jan. 02, 2015 USD ($)	Dec. 31, 2016 MW	Feb. 19, 2016 USD ($)	Nov. 02, 2015 MW
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1],[2]		4,997
November 2015 Drop Down Assets [Member]
Business Acquisition [Line Items]
Business Acquisition, Consideration Transferred, Working Capital | $				$ 2
January 2015 Drop Down Assets [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred | $		$ 489
Business Acquisition, Consideration Transferred, Working Capital | $		9
Business Combination, Consideration Transferred, Liabilities Incurred | $		737
Business Combination, Separately Recognized Transactions, Net Gains and Losses | $		61
AOCI Including Portion Attributable to Noncontrolling Interest, before Tax | $		$ 23
Wind Farms [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		1,999
Wind Farms [Member] | November 2015 Drop Down Assets [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts					814
Wind Farms [Member] | Laredo Ridge [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		80
Wind Farms [Member] | Buffalo Bear [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		19
Wind Farms [Member] | Taloga [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		130
Wind Farms [Member] | Pinnacle [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		55
Conventional Generation [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		1,945
Conventional Generation [Member] | Walnut Creek [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		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, 2016.

[2] NRG Yield's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's generation capacity including this noncontrolling interest was 5,003 MWs.

XML

Business Acquisitions Business Acquisitions - Alta Wind (Details) $ / shares in Units, $ in Millions						5 Months Ended	12 Months Ended
		Aug. 12, 2014 USD ($) MW	Aug. 05, 2014 USD ($)	Jul. 29, 2014 USD ($) shares	Jul. 22, 2013 USD ($) shares	Dec. 31, 2014 USD ($)	Dec. 31, 2016 USD ($) MW		Dec. 31, 2015 USD ($)		Dec. 31, 2014 USD ($)		Jul. 30, 2014 $ / shares
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW	[1],[2]						4,997
Proceeds from the issuance of common stock					$ 468		$ 0	[3]	$ 599	[3]	$ 630	[3]
Business Combination, Acquisition Related Costs	[4]						1		$ 3		$ 4
Alta Wind Portfolio [Member]
Business Acquisition [Line Items]
Number of Facilities		7
Payments to Acquire Businesses, Gross		$ 923
Business Combination, Consideration Transferred		870
Business Acquisition, Consideration Transferred, Working Capital		53
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt		1,591
Cash		22
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Cash						$ 0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current and Non-Current Assets		49
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Other Assets						(2)
Business Acquisition, Purchase Price Allocation, Other Assets, Adjusted		47
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment		1,304
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment						6
Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment, Adjusted		1,310
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles		1,177
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Intangibles						(6)
Business Acquisition, Purchase Price Allocation, Intangible Assets, Other than Goodwill, Adjusted		1,171
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets		2,552
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Total Assets						(2)
Business Acquisition, Purchase Price Allocation, Assets Acquired, Adjusted		2,550
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Noncurrent Liabilities Longterm Debt						0
Business Acquisition, Purchase Price Allocation, Noncurrent Liabilities, Long-term Debt, Adjusted		1,591
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current and Non-Current Liabilities		38
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Current and Noncurrent Liabilities						(2)
Business Acquisition, Purchase Price Allocation, Current and Non-current Liabilities, Adjusted		36
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities		1,629
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Financial Liabilities						(2)
Business Acquisition, Purchase Price Allocation, Liabilities Assumed, Adjusted		1,627
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		923
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Net Assets Acquired						$ 0
Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net Adjusted		$ 923
Business Combination, Acquisition Related Costs							$ 2
Alta Wind Holdings [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW		947
Public Shareholders [Member] | Common Class A [Member]
Business Acquisition [Line Items]
Sale of Stock, Number of Shares Issued in Transaction | shares				12,075,000	22,511,250
Share Price | $ / shares													$ 54.00
Proceeds from the issuance of common stock				$ 630
5.375% Senior Notes due in 2024 [Member]
Business Acquisition [Line Items]
Debt Instrument, Interest Rate, Stated Percentage							5.375%
5.375% Senior Notes due in 2024 [Member] | NRG Yield Operating LLC [Member]
Business Acquisition [Line Items]
Proceeds from Issuance of Senior Long-term Debt			$ 500
Debt Instrument, Interest Rate, Stated Percentage			5.375%

[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, 2016.

[2] NRG Yield's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's generation capacity including this noncontrolling interest was 5,003 MWs.

[3] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[4] Retrospectively adjusted as discussed in Note 1, Nature of Business.

XML

Business Acquisitions Business Acquisitions - June 2014 Drop Down Assets (Details) - June 2014 Drop Down Assets [Member] $ in Millions	Jun. 30, 2014 USD ($)
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 357
Business Acquisitions, Consideration Transferred, Purchase Price	349
Business Acquisition, Consideration Transferred, Working Capital	8
Business Combination, Consideration Transferred, Liabilities Incurred	$ 612

XML

Property, Plant and Equipment (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment
Property, plant and equipment, gross		$ 6,411	$ 6,660
Under construction		25	9
Less accumulated depreciation		(951)	(782)
Property, plant and equipment	[1]	5,460	5,878
Prepaid Long Term Service Agreement		20
Support Equipment and Facilities [Member]
Property, Plant and Equipment
Property, plant and equipment, gross		6,215	6,480
Land and improvements
Property, Plant and Equipment
Property, plant and equipment, gross		$ 171	$ 171
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		40 years

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

XML

Investments Accounted for by the Equity Method and Variable Interest Entities Investments Accounted for by the Equity Method and Variable Interest Entities - 2017 Drop Downs (Details) - MW		Mar. 27, 2017	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Power Generation Capacity, Megawatts	[1],[2]		4,997
Subsequent Event [Member] | Agua Caliente [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		16.00%

[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, 2016.

[2] NRG Yield's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's generation capacity including this noncontrolling interest was 5,003 MWs.

XML

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		Jun. 29, 2015	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	[1]		$ 1,152	$ 797
Retained Earnings, Undistributed Earnings from Equity Method Investees			51
Utah Solar Portfolio [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	[2]		346
Desert Sunlight [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments			$ 282
Payments to Acquire Equity Method Investments		$ 285
Business Acquisition, Consideration Transferred, Working Capital		$ 171
GCE Holding LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	[3]		50.00%
Equity Method Investments	[3]		$ 106
Retained Earnings, Undistributed Earnings from Equity Method Investees				$ 45
Agua Caliente Borrower 2 [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			16.00%
Equity Method Investments			$ 96
Elkhorn Ridge Wind, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			66.70%
Percentage of Ownership	[4]		50.30%
Equity Method Investments	[4]		$ 85
San Juan Mesa Wind Project, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			75.00%
Percentage of Ownership	[4]		56.30%
Equity Method Investments	[4]		$ 74
NRG DGPV Holdco 1 [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	[5]		95.00%
Equity Method Investments	[5]		$ 75
NRG DGPV Holdco 2 [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	[5]		95.00%
Equity Method Investments	[5]		$ 24
NRG RPV Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Ownership	[5]		95.00%
Equity Method Investments	[5]		$ 71
Avenal [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			50.00%
Equity Method Investments			$ (7)
Utility-Scale Solar [Member] | Utah Solar Portfolio [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	[2]		50.00%
Utility-Scale Solar [Member] | Desert Sunlight [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			25.00%

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Economic interest based on cash to be distributed. Four Brothers Solar, LLC, Granite Mount Holdings, LLC and Iron Spring Holdings, LLC are tax equity structures and VIEs. The related allocations are described below.

[3] GenConn is a variable interest entity.

[4] 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 75% of the Class B interests in Wind TE Holdco.

[5] Economic interest based on cash to be distributed. NRG DGPV Holdco 1 LLC, NRG DGPV Holdco 2 LLC, and NRG RPV Holdco 1 LLC are tax equity structures and VIEs. The related allocations are described below.

XML

Investments Accounted for by the Equity Method and Variable Interest Entities Investments Accounted for by the Equity Method and Variable Interest Entities - Not consolidated entities (Details) $ in Millions			1 Months Ended	3 Months Ended								12 Months Ended
		Mar. 27, 2017 USD ($)	Apr. 30, 2010	Dec. 31, 2016 USD ($) MW	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2016 USD ($) MW		Dec. 31, 2015 USD ($)		Dec. 31, 2014 USD ($)		Jul. 15, 2016	Sep. 22, 2010 USD ($)
Schedule of Equity Method Investments [Line Items]
Pro-Rate Share of Debt Held by Unconsolidated Affiliates				$ 589								$ 589
Power Generation Capacity, Megawatts | MW	[1],[2]			4,997								4,997
Debt (Current and non-current) (a)				$ 6,057				$ 5,656				$ 6,057		$ 5,656
Total operating revenues				232	$ 272	$ 283	$ 234	224	$ 256	$ 259	$ 214	1,021	[3]	953	[3]	$ 828	[3]
Operating income				(99)	117	128	72	70	101	99	50	218	[3]	320	[3]	306	[3]
Net (loss) income				(126)	$ 47	$ 63	$ 1	12	$ 32	42	$ (21)	2	[3],[4]	70	[3],[4],[5]	113	[3],[4],[5]
Current assets	[6]			656				416				656		416
Liabilities, Current	[6]			472				489				472		489
Liabilities, Noncurrent	[6]			5,825				5,462				5,825		5,462
Utah Solar Portfolio [Member]
Schedule of Equity Method Investments [Line Items]
Total operating revenues												13		0		0
Operating income												(6)		(1)		0
Net (loss) income												(6)		(1)		0
Current assets				20				11				20		11
Non-current assets				1,105				705				1,105		705
Liabilities, Current				14				229				14		229
Liabilities, Noncurrent				$ 38				0				$ 38		0
Avenal [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%								50.00%
Power Generation Capacity, Megawatts | MW				45								45
Power Purchase Agreement Period			20 years
Notes and Loans Payable																			$ 35
Debt Instrument, Interest Rate, Stated Percentage																			4.50%
GCE Holding LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	[7]			50.00%								50.00%
Total operating revenues												$ 72		78		82
Operating income												38		40		40
Net (loss) income												26		28		28
Current assets				$ 36				36				36		36
Non-current assets				389				416				389		416
Liabilities, Current				16				16				16		16
Liabilities, Noncurrent				$ 196				215				$ 196		215
Desert Sunlight [Member]
Schedule of Equity Method Investments [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment										$ 106
Power Generation Capacity, Megawatts | MW				550								550
Debt (Current and non-current) (a)				$ 1,100								$ 1,100
Total operating revenues												211		206		134
Operating income												129		124		74
Net (loss) income												80		73		$ 37
Current assets				281				310				281		310
Non-current assets				1,401				1,435				1,401		1,435
Liabilities, Current				64				82				64		82
Liabilities, Noncurrent				$ 1,043				1,086				$ 1,043		1,086
NRG DGPV Holdco 2 [Member]
Schedule of Equity Method Investments [Line Items]
Debt (Current and non-current) (a)								21						21
Desert Sunlight [Member] | Desert Sunlight [Member]
Schedule of Equity Method Investments [Line Items]
Debt (Current and non-current) (a)								1,100						1,100
EurusEnergy [Member] | Avenal [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%								50.00%
SyndicateofBanks [Member] | Avenal [Member]
Schedule of Equity Method Investments [Line Items]
Debt (Current and non-current) (a)				$ 134				143				$ 134		143					$ 209
CVSR Financing Agreement [Member]
Schedule of Equity Method Investments [Line Items]
Debt Instrument, Interest Rate, Stated Percentage																		4.68%
Debt (Current and non-current) (a)				771				793				771		793
Notes Payable to Banks [Member] | Agua Caliente Financing Agreement [Member]
Schedule of Equity Method Investments [Line Items]
Debt (Current and non-current) (a)				136								136
Notes Payable to Banks [Member] | Agua Caliente Financing Agreement [Member] | Agua Caliente [Member]
Schedule of Equity Method Investments [Line Items]
Debt (Current and non-current) (a)				$ 849								$ 849
Fixed Rate Notes [Member] | GCE Holding LLC [Member]
Schedule of Equity Method Investments [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				4.73%								4.73%
Debt (Current and non-current) (a)				$ 212				$ 220				$ 212		$ 220
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount				106								106
Line of Credit Facility, Maximum Borrowing Capacity				$ 237								$ 237
Working Capital Facility [Member] | GCE Holding LLC [Member]
Schedule of Equity Method Investments [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				1.875%								1.875%
Line of Credit Facility, Maximum Borrowing Capacity				$ 35								$ 35
Working Capital Facility [Member] | GenConn Facility [Member]
Schedule of Equity Method Investments [Line Items]
Line of Credit Facility, Fair Value of Amount Outstanding				$ 14								$ 14
U.S. Treasury Rate [Member] | Notes Payable to Banks [Member] | Agua Caliente Financing Agreement [Member]
Schedule of Equity Method Investments [Line Items]
Debt Instrument, Basis Spread on Variable Rate												0.375%
Subsequent Event [Member] | Agua Caliente [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		16.00%
Subsequent Event [Member] | Utah Solar Portfolio [Member]
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		100.00%
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount		$ 346
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners		99.00%
Percentage of Right to Receive Cash Distributed		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, 2016.

[2] NRG Yield's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's generation capacity including this noncontrolling interest was 5,003 MWs.

[3] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[4] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[5] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[6] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[7] GenConn is a variable interest entity.

XML

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)		Feb. 19, 2016 USD ($)	Nov. 03, 2015 USD ($)	Jun. 30, 2015 USD ($)	Dec. 31, 2016 USD ($) MW	Dec. 31, 2015 USD ($)	Nov. 02, 2015 USD ($) MW	May 07, 2015
Schedule of Equity Method Investments [Line Items]
Non-current assets	[1]				$ 2,720,000,000	$ 2,495,000,000
Power Generation Capacity, Megawatts | MW	[2],[3]				4,997
Property, plant and equipment	[1]				$ 5,460,000,000	5,878,000,000
Assets	[1]				8,836,000,000	8,789,000,000
Liabilities	[1]				$ 6,297,000,000	$ 5,951,000,000
November 2015 Drop Down Assets [Member]
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired							75.00%
Number of Facilities							12
Payments to Acquire Businesses, Gross		$ 207,000,000	$ 209,000,000
Business Acquisition, Consideration Transferred, Working Capital		$ 2,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment			669,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities			225,000,000
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value			$ 282,000,000
Wind Farms [Member]
Schedule of Equity Method Investments [Line Items]
Power Generation Capacity, Megawatts | MW	[2]				1,999
Wind Farms [Member] | November 2015 Drop Down Assets [Member]
Schedule of Equity Method Investments [Line Items]
Power Generation Capacity, Megawatts | MW							814
Wind Farms [Member] | Spring Canyon [Member]
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]
Power Generation Capacity, Megawatts | MW					32
Wind Farms [Member] | Spring Canyon III [Member]
Schedule of Equity Method Investments [Line Items]
Power Generation Capacity, Megawatts | MW					28
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%
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]
Schedule of Equity Method Investments [Line Items]
Percentage of Cash Available for Distributions			75.00%
Post-Flip Point [Member] | November 2015 Drop Down Assets [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Cash Available for Distributions			68.60%
Pre-determined Date Through Flip Point If Flip Has Not Occured [Member] | Financial Institutions [Member] | November 2015 Drop Down Assets [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Cash Available for Distributions			100.00%
November 2015 Drop Down Assets [Member]
Schedule of Equity Method Investments [Line Items]
Non-current assets					$ 193,000,000
Property, plant and equipment					441,000,000
Intangible Assets, Net (Excluding Goodwill)					2,000,000
Assets					636,000,000
Liabilities					209,000,000
Noncontrolling Interest in Variable Interest Entity					139,000,000
Net Assets					288,000,000
Alta X and XI TE Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Non-current assets					17,000,000
Property, plant and equipment					461,000,000
Intangible Assets, Net (Excluding Goodwill)					274,000,000
Assets					752,000,000
Liabilities					9,000,000
Noncontrolling Interest in Variable Interest Entity					107,000,000
Net Assets					$ 636,000,000
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%
Proceeds from Noncontrolling Interests				$ 119,000,000
Alta X and XI TE Holdco [Member] | Post-Flip Point [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Cash Available for Distributions					97.12%
Alta X and XI TE Holdco [Member] | Pre-determined Date Through Flip Point If Flip Has Not Occured [Member] | Financial Institutions [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Cash Available for Distributions					100.00%
Alta X and XI TE Holdco [Member] | First Year [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Cash Available for Distributions					100.00%
Alta X and XI TE Holdco [Member] | Second Year through Flip Point [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Cash Available for Distributions					94.34%
Spring Canyon [Member]
Schedule of Equity Method Investments [Line Items]
Non-current assets					$ 4,000,000
Property, plant and equipment					100,000,000
Intangible Assets, Net (Excluding Goodwill)					0
Assets					104,000,000
Liabilities					6,000,000
Noncontrolling Interest in Variable Interest Entity					67,000,000
Net Assets					$ 31,000,000
Spring Canyon [Member] | Pre-Flip Point [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Cash Available for Distributions					65.19%
Spring Canyon [Member] | Pre-Flip Point [Member] | Financial Institutions [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Cash Available for Distributions					34.81%
Spring Canyon [Member] | Post-Flip Point [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Cash Available for Distributions					95.00%
Spring Canyon [Member] | Post-Flip Point [Member] | Financial Institutions [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Cash Available for Distributions					5.00%

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] (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, 2016.

[3] NRG Yield's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's generation capacity including this noncontrolling interest was 5,003 MWs.

XML

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
		Feb. 29, 2016 USD ($) generatingunit MW	May 08, 2015 generatingunit MW	Dec. 31, 2016 USD ($) generatingunit MW	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2016 USD ($) generatingunit MW		Dec. 31, 2015 USD ($)		Dec. 31, 2014 USD ($)		Aug. 05, 2016 USD ($)
Schedule of Equity Method Investments [Line Items]
Current assets	[1]			$ 656				$ 416				$ 656		$ 416
Total operating revenues				232	$ 272	$ 283	$ 234	224	$ 256	$ 259	$ 214	1,021	[2]	953	[2]	$ 828	[2]
Equity Method Investments	[1]			$ 1,152				797				$ 1,152		797
Power Generation Capacity, Megawatts | MW	[3],[4]			4,997								4,997
Liabilities, Current	[1]			$ 472				489				$ 472		489
Liabilities, Noncurrent	[1]			5,825				5,462				5,825		5,462
Operating income				(99)	117	128	72	70	101	99	50	218	[2]	320	[2]	306	[2]
Net (loss) income				(126)	$ 47	$ 63	$ 1	12	$ 32	$ 42	$ (21)	2	[2],[5]	70	[2],[5],[6]	113	[2],[5],[6]
NRG DGPV Holdco 1 [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	[7]			75								75
GCE Holding LLC [Member]
Schedule of Equity Method Investments [Line Items]
Current assets				36				36				36		36
Total operating revenues												72		78		82
Equity Method Investments	[8]			106								106
Non-current assets				389				416				389		416
Liabilities, Current				16				16				16		16
Liabilities, Noncurrent				196				$ 215				196		215
Operating income												38		40		40
Net (loss) income												26		$ 28		$ 28
NRG DGPV Holdco 2 [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	[7]			24								24
NRG DGPV Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	[7]			99								99
NRG RPV Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	[7]			$ 71								$ 71
Tax Equity Financed Portfolio of Leases - Community Solar [Member] | NRG DGPV Holdco 1 [Member]
Schedule of Equity Method Investments [Line Items]
Number of Solar Leases in Portfolio | generatingunit			10
Power Generation Capacity, Megawatts | MW			8
Remaining Lease Term			19 years
Tax Equity Financed Portfolio of Leases - Commercial PV 1 [Member] | NRG DGPV Holdco 1 [Member]
Schedule of Equity Method Investments [Line Items]
Number of Solar Leases in Portfolio | generatingunit			12
Power Generation Capacity, Megawatts | MW			37
Remaining Lease Term			18 years
Tax Equity Financed Portfolio of Leases - Commercial PV 1 [Member] | NRG DGPV Holdco 2 [Member]
Schedule of Equity Method Investments [Line Items]
Number of Solar Leases in Portfolio | generatingunit		18
Power Generation Capacity, Megawatts | MW		28
Remaining Lease Term		21 years
Tax Equity Financed Portfolio of Leases - Commercial PV 2 [Member] | NRG DGPV Holdco 1 [Member]
Schedule of Equity Method Investments [Line Items]
Number of Solar Leases in Portfolio | generatingunit			3
Power Generation Capacity, Megawatts | MW			1
Remaining Lease Term			20 years
Tax Equity Financed Portfolio of Leases - Commercial PV 2 [Member] | NRG DGPV Holdco 2 [Member]
Schedule of Equity Method Investments [Line Items]
Number of Solar Leases in Portfolio | generatingunit		21
Power Generation Capacity, Megawatts | MW		18
Remaining Lease Term		20 years
Existing Portfolio of Leases [Member] | NRG RPV Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Number of Solar Leases in Portfolio | generatingunit				2,200								2,200
Power Generation Capacity, Megawatts | MW				15								15
Remaining Lease Term												19 years
Tax Equity Financed Portfolio of Leases [Member] | NRG RPV Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Capital Contributions From Partners in Equity Method Investment				$ 59								$ 59
Number of Solar Leases in Portfolio | generatingunit				5,400								5,400
Power Generation Capacity, Megawatts | MW				31								31
Maximum [Member] | Tax Equity Financed Portfolio of Leases [Member] | NRG DGPV Holdco 1 [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments				$ 100								$ 100
Maximum [Member] | Tax Equity Financed Portfolio of Leases [Member] | NRG DGPV Holdco 2 [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments				50								50
Maximum [Member] | Tax Equity Financed Portfolio of Leases [Member] | NRG RPV Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Capital Contributions From Partners in Equity Method Investment		$ 150		60								$ 60						$ 100
Remaining Lease Term												19 years
NRG [Member] | NRG DGPV Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Due to Related Parties, Current				$ 14								$ 14

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[3] (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, 2016.

[4] NRG Yield's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's generation capacity including this noncontrolling interest was 5,003 MWs.

[5] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[6] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[7] Economic interest based on cash to be distributed. NRG DGPV Holdco 1 LLC, NRG DGPV Holdco 2 LLC, and NRG RPV Holdco 1 LLC are tax equity structures and VIEs. The related allocations are described below.

[8] GenConn is a variable interest entity.

XML

Fair Value of Financial Instruments Fair Value of Financial Instruments - Balance Sheet Grouping (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt	$ 5,987	$ 5,593
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financing Receivable, Net	30	47
Debt	6,056	5,538
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financing Receivable, Net	30	47
Debt	6,057	5,656
Fair Value, Inputs, Level 2 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt	1,455	978
Fair Value, Inputs, Level 3 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt	$ 4,601	$ 4,560

XML

Fair Value of Financial Instruments Fair Value of Financial Instruments - Recurring Fair Value Measurements (Details) - USD ($)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
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
Derivative Assets		3,000,000
Derivative Liabilities		76,000,000	$ 100,000,000
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3		0
Fair Value, Assets, Level 1 to Level 2 Transfers, Amount		0	0
Fair Value, Assets, Level 2 to Level 1 Transfers, Amount		0	0
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount		0	0
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount		0	0
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	[1]	1,000,000
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	[1]	2,000,000	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		0	0
Derivative Liabilities	[1]	0
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		0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities	[1]	76,000,000	100,000,000
Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		2,000,000
Derivative Liabilities		1,000,000
Commodity contracts | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		1,000,000
Derivative Liabilities		0
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]
Derivative Assets		1,000,000	0
Derivative Liabilities		1,000,000	2,000,000
Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		1,000,000
Derivative Liabilities		75,000,000
Interest Rate Contract [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		0
Derivative Liabilities		0
Interest Rate Contract [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		1,000,000	0
Derivative Liabilities		$ 75,000,000	$ 98,000,000

[1] There were no assets or liabilities classified as Level 1 as of December 31, 2015. There were no assets or liabilities classified Level 3 as of December 31, 2016 and 2015.

XML

Fair Value of Financial Instruments Fair Value of Financial Instruments - Derivative FV Measurement and Credit Risk (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 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	$ 2,800
Estimated Counterparty Credit Risk Exposure to Certain Counterparties, Period	5 years

XML

Accounting for Derivative Instruments and Hedging Activities Accounting for Derivative Instruments and Hedging Activities - FV of Derivatives (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Liabilities	$ 76	$ 100
Derivative Assets	3
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative, Collateral, Right to Reclaim Cash	0	0
Fair Value of Gross Derivative Assets/(Liabilities), Net	(73)
Derivative Asset Fair Value Gross Liability Net Of Derivative Liability Fair Value Gross Asset	0
Derivative Asset, Fair Value, Amount Offset Against Collateral Net Of Derivative Liability, Fair Value, Amount Offset Against Collateral	(73)
Natural Gas [Member] | MMbtu [Member]
Derivative [Line Items]
Derivative, Notional Amount	3	4
Interest [Member] | Dollars
Derivative [Line Items]
Derivative, Notional Amount	2,070	1,991
Derivatives Designated as Cash Flow Hedges
Derivative [Line Items]
Derivative Liabilities	65	90
Derivative Assets	1
Derivatives Not Designated as Cash Flow Hedges
Derivative [Line Items]
Derivative Liabilities	11	10
Derivative Assets	2
Commodity contracts
Derivative [Line Items]
Derivative Liabilities	1
Derivative Assets	2
Derivative Asset, Fair Value, Gross Liability	0
Derivative instruments — affiliate	2
Derivative Liability, Fair Value, Gross Asset	0
Derivative Liability	1
Fair Value of Gross Derivative Assets/(Liabilities), Net	1
Derivative Asset Fair Value Gross Liability Net Of Derivative Liability Fair Value Gross Asset	0
Derivative Asset, Fair Value, Amount Offset Against Collateral Net Of Derivative Liability, Fair Value, Amount Offset Against Collateral	1
Interest rate contracts current | Derivatives Designated as Cash Flow Hedges
Derivative [Line Items]
Derivative Liabilities	26	34
Derivative Assets	0
Interest rate contracts current | Derivatives Not Designated as Cash Flow Hedges
Derivative [Line Items]
Derivative Liabilities	5	3
Derivative Assets	0
Interest rate contracts long-term | Derivatives Designated as Cash Flow Hedges
Derivative [Line Items]
Derivative Liabilities	39	56
Derivative Assets	1
Interest rate contracts long-term | Derivatives Not Designated as Cash Flow Hedges
Derivative [Line Items]
Derivative Liabilities	5	5
Derivative Assets	0
Commodity contracts current | Derivatives Not Designated as Cash Flow Hedges
Derivative [Line Items]
Derivative Liabilities	1	$ 2
Derivative Assets	2
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liabilities	75
Derivative Assets	1
Derivative Asset, Fair Value, Gross Liability	1
Derivative instruments — affiliate	0
Derivative Liability, Fair Value, Gross Asset	1
Derivative Liability	74
Fair Value of Gross Derivative Assets/(Liabilities), Net	(74)
Derivative Asset Fair Value Gross Liability Net Of Derivative Liability Fair Value Gross Asset	0
Derivative Asset, Fair Value, Amount Offset Against Collateral Net Of Derivative Liability, Fair Value, Amount Offset Against Collateral	$ (74)

XML

Accounting for Derivative Instruments and Hedging Activities Accounting for Derivative Instruments and Hedging Activities - AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Loss	$ (70)		$ (83)		$ (76)	$ (16)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	13		14		14
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	0		(21)		(74)
Accumulated other comprehensive loss	(28)	[1]	(27)	[1]	(9)
Loss expected to be realized from OCI during the next 12 months, net of tax	16
Accumulated Other Comprehensive Income (Loss), Cumulative Change in Gain (Loss) from Cash Flow Hedges, Tax Amount	16		16		6
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months, Tax	4
Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Loss	$ (42)		$ (56)		$ (67)

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

XML

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain/(loss) on derivatives	$ 13	$ (7)	$ (60)
Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain/(loss) on derivatives	$ 2	16	(22)
Commodity contracts | Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gain/(loss) on derivatives		$ (2)	$ 2

XML

Intangible Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Finite-Lived Intangible Assets
Gross amount at the end of the period		$ 1,449	$ 1,455	$ 1,462
Gross amount at the beginning of the period		1,455	1,462
Less accumulated amortization		(163)	(93)
Net carrying amount	[1]	1,286	1,362
Amortization of Intangible Assets		$ 70	55	30
Finite-Lived Intangible Asset, Useful Life		20 years
Finite-Lived Intangible Assets, Other Changes		$ (6)	(7)
Contra Revenue Intangibles Amortization		69	54	29
Accumulated Amortization of Out of Market Contracts		3
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
Gross amount at the beginning of the period		15	15
Less accumulated amortization		(7)	(6)
Net carrying amount		8	9
Finite-Lived Intangible Assets, Other Changes		0	0
Customer Relationships
Finite-Lived Intangible Assets
Gross amount at the end of the period		66	66	66
Gross amount at the beginning of the period		66	66
Less accumulated amortization		(4)	(3)
Net carrying amount		62	63
Finite-Lived Intangible Assets, Other Changes		0	0
Supply Commitment Arrangement [Domain]
Finite-Lived Intangible Assets
Gross amount at the end of the period		1,264	1,264	1,270
Gross amount at the beginning of the period		1,264	1,270
Less accumulated amortization		(138)	(75)
Net carrying amount		1,126	1,189
Finite-Lived Intangible Assets, Other Changes		0	(6)
Other Intangible Assets [Member]
Finite-Lived Intangible Assets
Gross amount at the end of the period		6	6	6
Gross amount at the beginning of the period		6	6
Less accumulated amortization		(2)	(2)
Net carrying amount		4	4
Finite-Lived Intangible Assets, Other Changes		0	0
Emission Allowances [Member]
Finite-Lived Intangible Assets
Gross amount at the end of the period		9	15	16
Gross amount at the beginning of the period		15	16
Less accumulated amortization		(2)	(1)
Net carrying amount		7	14
Finite-Lived Intangible Assets, Other Changes		(6)	(1)
Research and Development Expense [Member]
Finite-Lived Intangible Assets
Gross amount at the end of the period		3	3	3
Gross amount at the beginning of the period		3	3
Less accumulated amortization		(1)	(1)
Net carrying amount		2	2
Finite-Lived Intangible Assets, Other Changes		0	0
Leasehold Rights [Member]
Finite-Lived Intangible Assets
Gross amount at the end of the period		86	86	$ 86
Gross amount at the beginning of the period		86	86
Less accumulated amortization		(9)	(5)
Net carrying amount		77	81
Finite-Lived Intangible Assets, Other Changes		0	$ 0
Out of Market Contracts [Member]
Finite-Lived Intangible Assets
Amortization		1
NRG Solar Blythe LLC [Member]
Finite-Lived Intangible Assets
Out of Market Contracts		4
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

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

XML

Asset Impairments Asset Impairments(Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment losses	[1],[2]	$ 183	$ 0	$ 0
Elbow Creek [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment losses		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		$ 6

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

XML

Long-term Debt Long-term Debt - Summary Table (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Nov. 30, 2016	Oct. 31, 2016	Jul. 15, 2016
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 6,057	$ 5,656
Debt Issuance Costs, Net		(70)	(63)
Long-term Debt, Excluding Current Maturities		5,696	5,329
Pro-Rate Share of Debt Held by Unconsolidated Affiliates		589
Current portion of long-term debt	[1]	(291)	(264)
Other Debt [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		0	2
Project [Domain]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		4,601	4,254
3.25% Convertible Notes due 2020 [Member]
Debt Instrument [Line Items]
Interest Expense at Effective Rate		14	8
Debt (Current and non-current) (a)		$ 271	266
Debt Instrument, Interest Rate, Stated Percentage		3.25%
3.5% Convertible Notes due 2019 [Member]
Debt Instrument [Line Items]
Interest Expense at Effective Rate		$ 19	18
Debt (Current and non-current) (a)		$ 335	330
Debt Instrument, Interest Rate, Stated Percentage		3.50%
5.375% Senior Notes due in 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.375%
Senior Notes		$ 500	500
5.00% Senior Notes due in 2026 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.00%
Senior Notes		$ 350	0
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]	2.50%
Debt (Current and non-current) (a)		$ 0	306
Alpine Financing Agreement, due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3-Month LIBOR
Debt (Current and non-current) (a)		$ 145	154
Alta Wind I, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 242	252
Debt Instrument, Interest Rate, Stated Percentage		7.015%
Alta Wind II, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 191	198
Debt Instrument, Interest Rate, Stated Percentage		5.696%
Alta Wind III, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 198	206
Debt Instrument, Interest Rate, Stated Percentage		6.067%
Alta Wind IV, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 128	133
Debt Instrument, Interest Rate, Stated Percentage		5.938%
Alta Wind V, lease financing arrangement, due 2035 [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 206	213
Debt Instrument, Interest Rate, Stated Percentage		6.071%
Alta Realty Investments, due 2031 [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 31	33
Debt Instrument, Interest Rate, Stated Percentage		7.00%
Alta Wind Asset Management, due 2031 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3 month LIBOR
Debt Instrument, Basis Spread on Variable Rate		2.375%
Debt (Current and non-current) (a)		$ 18	19
Avra Valley Financing Agreement [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 57	60
NRG Solar Blythe LLC Credit Agreement Due 2028 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.625%
Debt (Current and non-current) (a)		$ 19	21
Borrego Financing Agreement, due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		2.50%
Debt (Current and non-current) (a)		$ 69	72
Borrego Financing Agreement, due 2038 [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		5.65%
West Holdings Credit Agreement [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 443	485
NRG Energy Center Minneapolis LLC Senior Secured Notes [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		96	108
NRG Energy Center Minneapolis Series D Notes [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 125	$ 0
Debt Instrument, Interest Rate, Stated Percentage		3.55%			3.55%
Kansas South Facility, due 2031 [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.00%
Debt (Current and non-current) (a)		$ 30	$ 33
Laredo Ridge Wind, LLC, due in 2026 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.875%
Debt (Current and non-current) (a)		$ 100	104
Marsh Landing Term Loan Facility [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		370	418
PFMG Financing Agreement [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 27	29
Debt Instrument, Interest Rate, Stated Percentage		6.00%
Roadrunner Financing Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.625%
Debt (Current and non-current) (a)		$ 37	$ 40
Kansas South Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		6 month LIBOR
South Trent Financing Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.625%
Debt (Current and non-current) (a)		$ 57	$ 62
Avra Valley [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.75%
High Desert Facility [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 49	$ 52
Tapestry Wind LLC due in 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.625%
Debt (Current and non-current) (a)		$ 172	181
Utah Solar Portfolio [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		2.625%
Debt (Current and non-current) (a)		$ 287	0	$ 222
Viento Funding II, Inc., due in 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		2.75%
Debt (Current and non-current) (a)		$ 178	189
Walnut Creek Energy, LLC, due in 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		1 month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.625%
Debt (Current and non-current) (a)		$ 310	351
WCEP Holdings, LLC, due in 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		3.00%
Debt (Current and non-current) (a)		$ 46	$ 46
Marsh Landing Tranche B due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.875%
Marsh Landing Tranche A due December 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
NRG Energy Center Minneapolis LLC Senior Secured Notes, due 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.95%
NRG Energy Center Minneapolis LLC Senior Secured Notes, due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.25%
High Desert Facility, due 2033 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		2.50%
TA - High Desert, due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.15%
CVSR Financing Agreement [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 771	$ 793
Debt Instrument, Interest Rate, Stated Percentage						4.68%
CVSR Holdco due 2037 [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)		$ 199	$ 0
Debt Instrument, Interest Rate, Stated Percentage		4.68%
Letter of Credit [Member] | NRG Yield Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		$ 60
Letter of Credit [Member] | Alpine Financing Agreement, due 2022 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		37
Letter of Credit [Member] | Alta Wind I, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		16
Letter of Credit [Member] | Alta Wind II, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		27
Letter of Credit [Member] | Alta Wind III, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		27
Letter of Credit [Member] | Alta Wind IV, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		19
Letter of Credit [Member] | Alta Wind V, lease financing arrangement, due 2035 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		30
Letter of Credit [Member] | Alta Realty Investments, due 2031 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		0
Letter of Credit [Member] | Alta Wind Asset Management, due 2031 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		0
Letter of Credit [Member] | Avra Valley Financing Agreement [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		3
Letter of Credit [Member] | NRG Solar Blythe LLC Credit Agreement Due 2028 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		6
Letter of Credit [Member] | Borrego Financing Agreement, due 2024 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		5
Letter of Credit [Member] | West Holdings Credit Agreement [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		82
Letter of Credit [Member] | NRG Energy Center Minneapolis LLC Senior Secured Notes [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		0
Letter of Credit [Member] | NRG Energy Center Minneapolis Series D Notes [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		0
Letter of Credit [Member] | Kansas South Facility, due 2031 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		4
Letter of Credit [Member] | Laredo Ridge Wind, LLC, due in 2026 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		10
Letter of Credit [Member] | Marsh Landing Term Loan Facility [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		22
Letter of Credit [Member] | PFMG Financing Agreement [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		0
Letter of Credit [Member] | Roadrunner Financing Agreement [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		5
Letter of Credit [Member] | South Trent Financing Agreement [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		10
Letter of Credit [Member] | High Desert Facility [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		8
Letter of Credit [Member] | Tapestry Wind LLC due in 2021 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		20
Letter of Credit [Member] | Utah Solar Portfolio [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		13
Letter of Credit [Member] | Viento Funding II, Inc., due in 2023 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		27
Letter of Credit [Member] | Walnut Creek Energy, LLC, due in 2023 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		41
Letter of Credit [Member] | WCEP Holdings LLC [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		0
Letter of Credit [Member] | CVSR Financing Agreement [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		0
Letter of Credit [Member] | CVSR Holdco due 2037 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		$ 13
Minimum [Member] | Alpine [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate
Minimum [Member] | Alpine Financing Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
Minimum [Member] | West Holdings Credit Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		1 month LIBOR
Debt Instrument, Basis Spread on Variable Rate
Minimum [Member] | West Holdings Credit Agreement due 2023 Tranche A [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.625%
Minimum [Member] | West Holdings Credit Agreement due 2023 Tranche B [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.25%
Minimum [Member] | CVSR Financing Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.339%
Maximum [Member] | Alpine [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate
Maximum [Member] | Alpine Financing Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate
Maximum [Member] | West Holdings Credit Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate
Maximum [Member] | CVSR Financing Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.775%

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] (b)

XML

Long-term Debt Long-term Debt - Corporate Debt (Details)							1 Months Ended	3 Months Ended	12 Months Ended
		Aug. 18, 2016 USD ($)	Jul. 15, 2016 USD ($)	Jun. 30, 2015	May 15, 2015	Aug. 05, 2014 USD ($)	Dec. 31, 2016 USD ($) $ / shares	Mar. 31, 2016	Dec. 31, 2016 USD ($) $ / shares	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Mar. 31, 2017 USD ($)	Feb. 17, 2017 USD ($)	Nov. 30, 2016 USD ($)	Jun. 29, 2015 USD ($) $ / shares	Mar. 31, 2014 USD ($)	Feb. 11, 2014 USD ($)
Debt Instrument [Line Items]
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt									$ 23,000,000	$ 23,000,000	$ 23,000,000
Debt (Current and non-current) (a)							$ 6,057,000,000		6,057,000,000	5,656,000,000
3.25% Convertible Notes due 2020 [Member]
Debt Instrument [Line Items]
Convertible Debt															$ 287,500,000
Interest Expense, Debt									9,000,000	5,000,000
Amortization of Debt Discount (Premium)									4,000,000	2,000,000
Amortization of Financing Costs									1,000,000	1,000,000
Interest Expense at Effective Rate									$ 14,000,000	8,000,000
Debt Instrument, Interest Rate, Stated Percentage							3.25%		3.25%
Debt Instrument, Convertible, Conversion Price | $ / shares															$ 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							96.625%		96.625%
Long-term Debt, Fair Value							$ 278,000,000		$ 278,000,000
Debt (Current and non-current) (a)							271,000,000		271,000,000	266,000,000
Conversion Value of Convertible Debt							$ 165,000,000		$ 165,000,000
3.5% Convertible Notes due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Effective Percentage							5.00%		5.00%
Convertible Debt																$ 345,000,000
Interest Expense, Debt									$ 12,000,000	12,000,000
Amortization of Debt Discount (Premium)									5,000,000	4,000,000
Amortization of Financing Costs									2,000,000	2,000,000
Interest Expense at Effective Rate									$ 19,000,000	18,000,000
Debt Instrument, Interest Rate, Stated Percentage							3.50%		3.50%
Debt Instrument, Convertible, Conversion Ratio					42.9644
Percent of face value							99.625%		99.625%
Long-term Debt, Fair Value							$ 344,000,000		$ 344,000,000
Debt (Current and non-current) (a)							335,000,000		335,000,000	330,000,000
Conversion Value of Convertible Debt							$ 228,000,000		$ 228,000,000
5.00% Senior Notes due in 2026 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Unsecured Debt		$ 350,000,000
Debt Instrument, Interest Rate, Stated Percentage							5.00%		5.00%
Senior Notes							$ 350,000,000		$ 350,000,000	0
Convertible Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount																	$ 1,000
5.375% Senior Notes due in 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage							5.375%		5.375%
Senior Notes							$ 500,000,000		$ 500,000,000	500,000,000
NRG Yield Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)							0		$ 0	306,000,000
Debt Instrument, Basis Spread on Variable Rate	[1]								2.50%
Line of Credit Facility, Maximum Borrowing Capacity							495,000,000		$ 495,000,000
Proceeds from Issuance of Debt									60,000,000
Line of Credit Facility, Fair Value of Amount Outstanding							0		0
Repayments of Debt									366,000,000
CVSR Financing Agreement [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.68%
Debt (Current and non-current) (a)							771,000,000		771,000,000	793,000,000
Proceeds from Issuance of Debt			$ 200,000,000
Proceeds from Debt, Net of Issuance Costs			$ 97,500,000
Utah Solar Portfolio [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)							287,000,000		$ 287,000,000	0				$ 222,000,000
Debt Instrument, Basis Spread on Variable Rate									2.625%
Proceeds from (Repayments of) Secured Debt							65,000,000
Line of Credit Facility, Commitment Fee Percentage								2.625%
Letter of Credit [Member] | NRG Yield Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount							60,000,000		$ 60,000,000
Letter of Credit [Member] | CVSR Financing Agreement [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount							0		0
Letter of Credit [Member] | Utah Solar Portfolio [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount							$ 13,000,000		$ 13,000,000
November 2015 Drop Down Assets [Member] | NRG Yield Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Debt										$ 254,000,000
NRG Yield Operating LLC [Member] | 5.375% Senior Notes due in 2024 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Senior Long-term Debt						$ 500,000,000
Debt Instrument, Interest Rate, Stated Percentage						5.375%
Common Class C [Member]
Debt Instrument [Line Items]
Common Stock Closing Price | $ / shares							$ 15.80		$ 15.80
Common Class A [Member]
Debt Instrument [Line Items]
Common Stock Closing Price | $ / shares							$ 15.36		$ 15.36
Subsequent Event [Member] | Aqua Caliente Borrower 2, due 2038 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage												5.43%
Equity Method Investment, Ownership Percentage													16.00%
Debt (Current and non-current) (a)												$ 41,000,000	$ 130,000,000
Subsequent Event [Member] | Letter of Credit [Member] | Aqua Caliente Borrower 2, due 2038 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity													$ 17,000,000
Semi Annual Debt Related Fee Percentage													2.25%
Line of Credit [Member] | Utah Solar Portfolio [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity							$ 13,000,000		$ 13,000,000
Line of Credit [Member] | Subsequent Event [Member] | Utah Solar Portfolio [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity												$ 11,000,000

[1] (b)

XML

Long-term Debt Long-term Debt - Thermal/CVSR (Details) - USD ($) $ in Millions	Oct. 31, 2016	Jul. 15, 2016	Dec. 31, 2016	Sep. 01, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Debt (Current and non-current) (a)			$ 6,057		$ 5,656
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%
Debt (Current and non-current) (a)			$ 125		0
CVSR Financing Agreement [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Debt		$ 200
Debt Instrument, Interest Rate, Stated Percentage		4.68%
Debt (Current and non-current) (a)			$ 771		793
CVSR Holdco due 2037 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.68%
Debt (Current and non-current) (a)			$ 199		$ 0
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]
Debt (Current and non-current) (a)				771
CVSR [Member] | CVSR Holdco due 2037 [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)				$ 200

XML

Long-term Debt Long-term Debt - Avenal/Lease financing arrangements (Details) - USD ($) $ in Millions			12 Months Ended
		Mar. 18, 2015	Dec. 31, 2016	Dec. 31, 2015	Jun. 30, 2015
Debt Instrument [Line Items]
Debt (Current and non-current) (a)			$ 6,057	$ 5,656
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	[1]		2.50%
Debt (Current and non-current) (a)			$ 0	$ 306
Letter of Credit [Member] | Alta Wind I - V Lease financing arrangement [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)			119
Alta Wind I - V Lease financing arrangement [Member]
Debt Instrument [Line Items]
Debt (Current and non-current) (a)			$ 965
Avenal [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 43
Proceeds from Debt, Net of Issuance Costs		$ 20
Equity Method Investment, Ownership Percentage			50.00%
September 22, 2010 to March 18, 2015 [Member] | Avenal [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		6 month LIBOR
Debt Instrument, Basis Spread on Variable Rate		2.25%
March 18, 2015 to March 17, 2022 [Member] | Avenal [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		6 month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.75%
March 18, 2022 to March 17, 2027 [Member] | Avenal [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		6 month LIBOR
Debt Instrument, Basis Spread on Variable Rate		2.00%
March 18, 2027 through Maturity [Member] | Avenal [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis		6 month LIBOR
Debt Instrument, Basis Spread on Variable Rate		2.25%
Alta Wind I - V Lease financing arrangement [Member] | Revolving Credit Facility [Member] | NRG Yield Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Letters of Credit, Issued Amount			$ 23
Utility-Scale Solar [Member] | Avenal [Member]
Debt Instrument [Line Items]
Equity Method Investment, Ownership Percentage			50.00%		49.95%

[1] (b)

XML

Long-term Debt Long-term Debt - Swaps/Maturities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Debt Instrument [Line Items]
2016	$ 291
2017	304
2018	665
2019	654
2020	452
Thereafter	3,718
Long-term Debt, Gross	6,084
Interest Rate Swap [Member]
Debt Instrument [Line Items]
Derivative, Notional Amount	$ 2,069
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%
Derivative, Fixed Interest Rate	2.744%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 115
Interest Rate Swap [Member] | NRG Solar Alpine LLC [Member] | Maturity - June 30, 2025 [Member]
Debt Instrument [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	85.00%
Derivative, Fixed Interest Rate	2.421%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 8
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	$ 49
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	$ 14
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	$ 7
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%
Derivative, Fixed Interest Rate	2.417%
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
Derivative, Notional Amount	$ 330
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	$ 23
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	$ 79
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	$ 342
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	$ 28
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	$ 43
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	$ 155
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
Interest Rate Swap [Member] | Utah Solar Portfolio [Member] | Maturity - December 21, 2029 [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	$ 230
Alta Wind Asset Management, due 2031 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	3 month LIBOR
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	$ 18
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	$ 160
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	$ 276
WCEP Holdings, LLC, due in 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	3-Month LIBOR
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	$ 46

XML

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended								5 Months Ended		12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2013		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Numerator:
Net income attributable to NRG Yield, Inc.		$ (13)	$ 33	$ 32	$ 5	$ 11	$ 17	$ 10	$ (5)			$ 57	[1]	$ 33	[1]	$ 16	[1]
Common Class A [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Earnings Per Share, Diluted		$ (0.14)	$ 0.30	$ 0.29	$ 0.05
Weighted Average Number of Shares Outstanding, Diluted		35	49	49	35
Numerator:
Net income attributable to NRG Yield, Inc.										$ 8	[2]	$ 20		$ 14
Denominator:
Weighted average number of common shares outstanding — basic and diluted						35	35	35	35			35	[1]	35	[1]	28	[1]
Basic and diluted loss per share:
Earnings per weighted average common share — basic and diluted	[1],[2]											$ 0.58		$ 0.40		$ 0.30
Common Class C [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Earnings Per Share, Diluted		$ (0.14)	$ 0.32	$ 0.31	$ 0.05
Weighted Average Number of Shares Outstanding, Diluted		63	73	73	63
Numerator:
Net income attributable to NRG Yield, Inc.										$ 8	[2]	$ 37		$ 19
Denominator:
Weighted average number of common shares outstanding — basic and diluted						63	63	35	35			63	[1]	49	[1]	28	[1]
Basic and diluted loss per share:
Earnings per weighted average common share — basic and diluted	[2]									$ 0.30
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												15		15		12
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												10		5		0

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

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

XML

Stockholders' Equity Stockholders' Equity (Details)										1 Months Ended	3 Months Ended				12 Months Ended
		Mar. 27, 2017 USD ($)	Sep. 02, 2016 USD ($)	Feb. 19, 2016 USD ($)	Nov. 03, 2015 USD ($)	Jun. 29, 2015 USD ($) shares	Jan. 02, 2015 USD ($)	Jul. 29, 2014 USD ($) shares	Jul. 22, 2013 USD ($) $ / shares shares	Jul. 31, 2013 USD ($)	Dec. 31, 2016 USD ($) $ / shares MW shares	Sep. 30, 2016 $ / shares	Jun. 30, 2016 $ / shares	Mar. 31, 2016 $ / shares	Dec. 31, 2016 USD ($) $ / shares MW shares		Dec. 31, 2015 USD ($) $ / shares shares		Dec. 31, 2014 USD ($)		Sep. 01, 2016 USD ($)	Nov. 02, 2015 USD ($) MW
Statement of Stockholders' Equity
Dividends Payable, Date Declared															Feb. 15, 2017
Distribution Made to Limited Liability Company (LLC) Member, Distributions Paid, Per Unit | $ / shares											$ 0.25
Common Stock, Par or Stated Value Per Share | $ / shares											$ 0.01				$ 0.01		$ 0.01
Proceeds from the issuance of common stock									$ 468,000,000						$ 0	[1]	$ 599,000,000	[1]	$ 630,000,000	[1]
Expense Related to Distribution or Servicing and Underwriting Fees									$ 27,000,000
Common Stock, Dividends, Per Share, Declared | $ / shares															$ 0.26
Preferred Stock, Shares Authorized | shares									10,000,000		10,000,000				10,000,000		10,000,000
Preferred Stock, Par or Stated Value Per Share | $ / shares									$ 0.01		$ 0.01				$ 0.01		$ 0.01
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued	[2]										$ 0				$ 0		$ 0
Payments of Capital Distribution	[1]														$ 170,000,000		76,000,000		333,000,000
Dividends Payable, Date to be Paid															Mar. 15, 2017
Noncontrolling Interest, Increase from Business Combination																	$ 74,000,000
Dividends Payable, Date of Record															Mar. 01, 2017
Power Generation Capacity, Megawatts | MW	[3],[4]										4,997				4,997
Common Class A [Member]
Statement of Stockholders' Equity
Common Stock, Shares Authorized | shares									500,000,000
Common Stock, Par or Stated Value Per Share | $ / shares											$ 0.01				$ 0.01
Common Class D [Member]
Statement of Stockholders' Equity
Distribution Made to Limited Liability Company (LLC) Member, Distributions Paid, Per Unit | $ / shares												$ 0.24	$ 0.23
Common Stock, Voting Rights															1/100th
Common Class B [Member]
Statement of Stockholders' Equity
Distribution Made to Limited Liability Company (LLC) Member, Distributions Paid, Per Unit | $ / shares														$ 0.225
Common Stock, Shares Authorized | shares									500,000,000
Common Class C [Member]
Statement of Stockholders' Equity
Proceeds from the issuance of common stock						$ 599,000,000
Investment Banking, Advisory, Brokerage, and Underwriting Fees and Commissions						$ 21,000,000
Public Shareholders [Member] | Common Class A [Member]
Statement of Stockholders' Equity
Sale of Stock, Number of Shares Issued in Transaction | shares								12,075,000	22,511,250
Proceeds from the issuance of common stock								$ 630,000,000
NRG
Statement of Stockholders' Equity
Payments to Acquire Interest in Subsidiaries and Affiliates										$ 395,000,000
NRG | Common Class B [Member]
Statement of Stockholders' Equity
Sale of Stock, Number of Shares Issued in Transaction | shares									42,738,750
NRG Yield, Inc. [Member]
Statement of Stockholders' Equity
Preferred Stock, Shares Authorized | shares											10,000,000				10,000,000		10,000,000
Preferred Stock, Par or Stated Value Per Share | $ / shares											$ 0.01				$ 0.01		$ 0.01
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued	[5]										$ 0				$ 0		$ 0
NRG Yield, Inc. [Member] | Common Class A [Member]
Statement of Stockholders' Equity
Common Stock, Shares Authorized | shares											500,000,000				500,000,000		500,000,000
Common Stock, Par or Stated Value Per Share | $ / shares											$ 0.01				$ 0.01		$ 0.01
NRG Yield, Inc. [Member] | Common Class D [Member]
Statement of Stockholders' Equity
Common Stock, Shares Authorized | shares											500,000,000				500,000,000		500,000,000
NRG Yield, Inc. [Member] | Common Class B [Member]
Statement of Stockholders' Equity
Common Stock, Shares Authorized | shares											500,000,000				500,000,000		500,000,000
NRG Yield, Inc. [Member] | Common Class C [Member]
Statement of Stockholders' Equity
Common Stock, Shares Authorized | shares											500,000,000				500,000,000		500,000,000
NRG Yield LLC | NRG
Statement of Stockholders' Equity
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest								46.70%							46.70%
NRG Yield LLC | NRG Yield, Inc. [Member]
Statement of Stockholders' Equity
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest								53.30%							53.30%
CVSR [Member]
Statement of Stockholders' Equity
Business Combination, Separately Recognized Transactions, Net Gains and Losses															$ 112,000,000
AOCI Including Portion Attributable to Noncontrolling Interest, before Tax											$ 6,000,000				$ 6,000,000
Business Acquisition, Percentage of Voting Interests Acquired																					51.05%
Payments to Acquire Businesses, Gross			$ 78,500,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt																					$ 496,000,000
2015 Drop Down Asssets [Member]
Statement of Stockholders' Equity
Business Combination, Separately Recognized Transactions, Net Gains and Losses																	$ 109,000,000
AOCI Including Portion Attributable to Noncontrolling Interest, before Tax																	$ 32,000,000
November 2015 Drop Down Assets [Member]
Statement of Stockholders' Equity
Business Acquisition, Percentage of Voting Interests Acquired																						75.00%
Number of Facilities																						12
Payments to Acquire Businesses, Gross				$ 207,000,000	$ 209,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt					193,000,000
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value					282,000,000
January 2015 Drop Down Assets [Member]
Statement of Stockholders' Equity
Business Combination, Separately Recognized Transactions, Net Gains and Losses							$ 61,000,000
AOCI Including Portion Attributable to Noncontrolling Interest, before Tax							$ 23,000,000
June 2014 Drop Down Assets [Member]
Statement of Stockholders' Equity
Business Combination, Separately Recognized Transactions, Net Gains and Losses																			$ 113,000,000
Subsequent Event [Member]
Statement of Stockholders' Equity
Noncontrolling Interest, Increase from Business Combination		$ 8,000,000
Wind Farms [Member]
Statement of Stockholders' Equity
Power Generation Capacity, Megawatts | MW	[3]										1,999				1,999
Wind Farms [Member] | November 2015 Drop Down Assets [Member]
Statement of Stockholders' Equity
Power Generation Capacity, Megawatts | MW																						814
Financial Institutions [Member] | November 2015 Drop Down Assets [Member]
Statement of Stockholders' Equity
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value					$ 159,000,000
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 | shares						3,678,000

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[3] (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, 2016.

[4] NRG Yield's total generation capacity is net of 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's generation capacity including this noncontrolling interest was 5,003 MWs.

[5] Retrospectively adjusted as discussed in Note 1, Nature of Business.

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Segment Reporting (Details) - USD ($) $ in Millions		3 Months Ended										5 Months Ended	12 Months Ended
		Dec. 31, 2016		Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2013	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Segment Reporting
Total operating revenues		$ 232		$ 272	$ 283	$ 234	$ 224		$ 256	$ 259	$ 214		$ 1,021	[1]	$ 953	[1]	$ 828	[1]
Cost of operations													306		321		277
Depreciation and amortization	[1]												297		297		233
Impairment losses	[1],[2]												183		0		0
General and administrative	[1]												16		12		8
Acquisition-related transaction and integration costs	[1]												1		3		4
Operating Income		(99)		117	128	72	70		101	99	50		218	[1]	320	[1]	306	[1]
Equity in earnings of unconsolidated affiliates	[1],[2]												60		31		22
Other Nonoperating Income (Expense)	[1]												3		3		6
Gains (Losses) on Extinguishment of Debt	[1],[2]												0		(9)		(1)
Interest Expense	[1]												(280)		(263)		(216)
Income Before Income Taxes	[1]												1		82		117
Income tax (benefit) expense	[1]												(1)		12		4
Net Income		(126)		$ 47	$ 63	$ 1	12		$ 32	$ 42	$ (21)		2	[1],[2]	70	[1],[2],[3]	113	[1],[2],[3]
Equity investments in affiliates	[4]	1,152					797						1,152		797
Capital Expenditures		23	[5]				30	[6]					23	[5]	30	[6]
Total Assets	[4]	8,836					8,789						8,836		8,789
Conventional Generation
Segment Reporting
Total operating revenues													333		336		317
Cost of operations													66		59		55
Depreciation and amortization													80		81		82
Impairment losses													0
General and administrative													0		0		0
Acquisition-related transaction and integration costs													0		0		0
Operating Income													187		196		180
Equity in earnings of unconsolidated affiliates													13		14		14
Other Nonoperating Income (Expense)													1		1		0
Gains (Losses) on Extinguishment of Debt															(7)		0
Interest Expense													(48)		(48)		(53)
Income Before Income Taxes													153		156		141
Income tax (benefit) expense													0		0		0
Net Income													153		156
Equity investments in affiliates		106					110						106		110
Capital Expenditures		7	[5]				4	[6]					7	[5]	4	[6]
Total Assets		1,993					2,102						1,993		2,102
Renewables
Segment Reporting
Total operating revenues													518		443		316
Cost of operations													126		136		83
Depreciation and amortization													197		197		133
Impairment losses													183
General and administrative													0		0		0
Acquisition-related transaction and integration costs													0		0		0
Operating Income													12		110		100
Equity in earnings of unconsolidated affiliates													47		17		8
Other Nonoperating Income (Expense)													2		2		5
Gains (Losses) on Extinguishment of Debt															(2)		(1)
Interest Expense													(147)		(147)		(126)
Income Before Income Taxes													(86)		(20)		(14)
Income tax (benefit) expense													0		0		0
Net Income													(86)		(20)
Equity investments in affiliates		1,046					687						1,046		687
Capital Expenditures		2	[5]				6	[6]					2	[5]	6	[6]
Total Assets		5,988					6,070						5,988		6,070
Thermal [Member]
Segment Reporting
Total operating revenues													170		174		195
Cost of operations													114		126		139
Depreciation and amortization													20		19		18
Impairment losses													0
General and administrative													0		0		0
Acquisition-related transaction and integration costs													0		0		0
Operating Income													36		29		38
Equity in earnings of unconsolidated affiliates													0		0		0
Other Nonoperating Income (Expense)													0		0		0
Gains (Losses) on Extinguishment of Debt															0		0
Interest Expense													(7)		(7)		(7)
Income Before Income Taxes													29		22		31
Income tax (benefit) expense													0		0		0
Net Income													29		22
Equity investments in affiliates		0					0						0		0
Capital Expenditures		14	[5]				20	[6]					14	[5]	20	[6]
Total Assets		426					428						426		428
Corporate
Segment Reporting
Total operating revenues													0		0		0
Cost of operations													0		0		0
Depreciation and amortization													0		0		0
Impairment losses													0
General and administrative													16		12		8
Acquisition-related transaction and integration costs													1		3		4
Operating Income													(17)		(15)		(12)
Equity in earnings of unconsolidated affiliates													0		0		0
Other Nonoperating Income (Expense)													0		0		1
Gains (Losses) on Extinguishment of Debt															0		0
Interest Expense													(78)		(61)		(30)
Income Before Income Taxes													(95)		(76)		(41)
Income tax (benefit) expense													(1)		12		4
Net Income													(94)		(88)		$ (45)
Equity investments in affiliates		0					0						0		0
Capital Expenditures		0	[5]				0	[6]					0	[5]	0	[6]
Total Assets		$ 429					$ 189						$ 429		$ 189
Affiliated Entity [Member]
Segment Reporting
General and administrative												$ 6
Southern California Edison [Member] | Conventional Generation
Segment Reporting
Customer's Percentage of Total Revenue													21.00%		23.00%		24.00%
Southern California Edison [Member] | Renewables
Segment Reporting
Customer's Percentage of Total Revenue													21.00%		17.00%		7.00%
PG&E [Member] | Conventional Generation
Segment Reporting
Customer's Percentage of Total Revenue													12.00%		13.00%		15.00%
PG&E [Member] | Renewables
Segment Reporting
Customer's Percentage of Total Revenue													11.00%		12.00%		13.00%

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[3] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[4] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[5] Includes accruals.

[6] Includes accruals.

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Income Taxes (Provision) (Details) - USD ($) $ in Millions			12 Months Ended
		Jul. 29, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	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			(1)	10	2
State			0	2	2
Total — deferred			(1)	12	4
Income tax (benefit) expense	[1]		$ (1)	$ 12	$ 4
Effective tax rate (as a percent)			(100.00%)	14.60%	3.40%
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	[1]		$ 1	$ 82	$ 117
Tax at 35%			0	29	41
State taxes, net of federal benefit			0	2	(1)
Investment tax credits			(1)	(1)	0
Impact of non-taxable partnership earnings			(1)	(17)	(33)
Production tax credits, including prior year true-up			4	(4)	(6)
Change in state effective tax rate			0	0	1
Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Amount			$ (3)	3	$ 0
Income Taxes Receivable				$ 6
NRG | NRG Yield LLC
Reconciliation of the U.S. federal statutory rate to the Company's effective rate from continuing operations
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		46.70%	46.70%
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 (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		53.30%	53.30%

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

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Income Taxes (Deferred) (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Deferred Tax Liabilities, Gross [Abstract]
Total deferred tax assets, net of valuation allowance	$ 3,000,000	$ 27,000,000
Deferred Tax Liabilities, Gross	3,000,000	27,000,000
Deferred Tax Assets, Gross [Abstract]
Production tax credits carryforwards	5,000,000	10,000,000
Investment tax credits	1,000,000	1,000,000
U.S. Federal net operating loss carryforwards	226,000,000	181,000,000
State net operating loss carryforwards	3,000,000	5,000,000
Total deferred tax assets	235,000,000	197,000,000
Deferred Tax Assets, Valuation Allowance	16,000,000	0
Deferred Tax Assets, Net of Valuation Allowance	219,000,000	197,000,000
Deferred Tax Assets, Net	216,000,000	170,000,000
Deferred Tax Assets, Net, Excluding Valuation Allowance	$ 232,000,000	170,000,000
Unrecognized Tax Benefits		$ 0

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Related Party Transactions (Details) - USD ($) $ in Millions		3 Months Ended	5 Months Ended	12 Months Ended
		Sep. 30, 2015	Dec. 31, 2013	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jan. 05, 2017	Oct. 31, 2016
Related Party Transaction
General and administrative	[1]			$ 16.0	$ 12.0	$ 8.0
Accounts payable — affiliate	[2]			40.0	86.0
GenOn Energy Services LLC [Member]
Related Party Transaction
Due to Affiliate				1.0	6.0
Affiliated Entity [Member]
Related Party Transaction
General and administrative			$ 6.0
NRG Repowering Holdings LLC [Member]
Related Party Transaction
Due to Affiliate				7.0
Payments					18.0
Receipt of payments		$ 11.0
coal, gas purchases						10.0
Cost of Natural Gas Purchases				1.0	5.0
Walnut Creek [Member] | NRG [Member] | Operations and Maintenance services [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party				3.0	3.0	2.0
NRG Yield [Member] | NRG [Member]
Related Party Transaction
Management Services Fee, Increase					0.5
General and administrative				10.0	8.0
NRG Yield [Member] | NRG [Member] | Scenario, Plan [Member]
Related Party Transaction
Management Services Fee, Annual				7.5
El Segundo [Member] | NRG El Segundo Operations, Inc. [Member]
Related Party Transaction
Due to Affiliate				1.0
Related Party Transaction, Expenses from Transactions with Related Party				4.0	4.0
CVSR [Member] | NRG Energy Services LLC [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party				4.0	7.0
Thermal [Member] | NRG [Member]
Related Party Transaction
Due to Affiliate				20.0	29.0
Accounts payable — affiliate				11.0
Accounts payable — affiliate				9.0
Related Party Transaction, Expenses from Transactions with Related Party				29.0	29.0	27.0
NRG Energy Center Dover [Member] | NRG [Member]
Related Party Transaction
Revenue from Related Parties				5.0
NRG Yield, Inc. [Member] | NRG [Member]
Related Party Transaction
Due to Affiliate				3.0
GCE Holding LLC [Member] | NRG [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party				5.0	4.0	6.0
Marsh Landing [Member] | GenOn Energy Services LLC [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party				14.0	13.0	13.0
Related Party Costs, Capitalized Amount						2.0
Marsh Landing [Member] | NRG RENOM [Member]
Related Party Transaction
Due to Affiliate				5.0	1.0
Related Party Transaction, Expenses from Transactions with Related Party				13.0	7.0
November 2015 Drop Down Assets [Member] | NRG [Member]
Related Party Transaction
Related Party Transaction, Other Revenues from Transactions with Related Party					16.0	12.0
November 2015 Drop Down Assets [Member] | NRG [Member] | Support services [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party				2.0	3.0	1.0
Elbow Creek [Member] | NRG [Member]
Related Party Transaction
Revenue from Related Parties				8.0
NRG Energy Center Minneapolis LLC [Member] | NRG [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party				$ 7.0	$ 8.0	$ 2.0
NECP [Member] | NRG [Member]
Related Party Transaction
Related Party Transaction, Amount to be Paid Upon Completion of Project								$ 79.0
Subsequent Event [Member] | NECP [Member] | NRG [Member]
Related Party Transaction
Related Party Transaction, Amount to be Paid Upon Completion of Project							$ 87.0

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

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Commitments and Contingencies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Long-term Purchase Commitment [Line Items]
Operating Leases, Rent Expense	$ 15	$ 10	$ 9
Operating Leases, Future Minimum Payments Due, Next Twelve Months	9
Operating Leases, Future Minimum Payments, Due in Two Years	9
Operating Leases, Future Minimum Payments, Due in Three Years	10
Operating Leases, Future Minimum Payments, Due in Four Years	9
Operating Leases, Future Minimum Payments, Due in Five Years	9
Operating Leases, Future Minimum Payments, Due Thereafter	152
Operating Leases, Future Minimum Payments Due	198
Utilities Operating Expense, Purchased Power under Long-term Contracts	32	40	55
Purchase Obligation, Due in Next Twelve Months	13
Unrecorded Unconditional Purchase Obligation, Due within Two Years	5
Unrecorded Unconditional Purchase Obligation, Due within Three Years	2
Unrecorded Unconditional Purchase Obligation, Due within Four Years	3
Unrecorded Unconditional Purchase Obligation, Due within Five Years	3
Unrecorded Unconditional Purchase Obligation, Due after Five Years	19
Purchase Obligation	45
NRG [Member]
Long-term Purchase Commitment [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts	$ 8	$ 13	$ 12

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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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2013	[4]	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Net Income/(Loss) per Weighted Average Common Share - Basic (in dollars per share)		$ (0.14)	$ 0.34	$ 0.33	$ 0.05	$ 0.12	$ 0.18	$ 0.15	$ (0.07)
Net income attributable to NRG Yield, Inc.		$ (13)	$ 33	$ 32	$ 5	$ 11	$ 17	$ 10	$ (5)			$ 57	[1]	$ 33	[1]	$ 16	[1]
Net Income		(126)	47	63	1	12	32	42	(21)			2	[1],[2]	70	[1],[2],[3]	113	[1],[2],[3]
Quarterly Financial Information, Quarterly Charges and Credits, Amount Reconciling to Previously Reported Results		11	3	2	1	0	3	2	0
Operating income		(99)	117	128	72	70	101	99	50			218	[1]	320	[1]	306	[1]
Total operating revenues		$ 232	$ 272	$ 283	$ 234	$ 224	$ 256	$ 259	$ 214			$ 1,021	[1]	$ 953	[1]	$ 828	[1]
Common Class A [Member]
Weighted Average Number of Shares Outstanding, Diluted		35	49	49	35
Weighted average number of common shares outstanding — basic and diluted						35	35	35	35			35	[1]	35	[1]	28	[1]
Net income attributable to NRG Yield, Inc.										$ 8		$ 20		$ 14
Earnings Per Share, Diluted		$ (0.14)	$ 0.30	$ 0.29	$ 0.05
Common Class C [Member]
Weighted Average Number of Shares Outstanding, Diluted		63	73	73	63
Net Income/(Loss) per Weighted Average Common Share - Basic (in dollars per share)	[4]											$ 0.58		$ 0.40
Weighted average number of common shares outstanding — basic and diluted						63	63	35	35			63	[1]	49	[1]	28	[1]
Net income attributable to NRG Yield, Inc.										$ 8		$ 37		$ 19
Earnings Per Share, Diluted		$ (0.14)	$ 0.32	$ 0.31	$ 0.05
Scenario, Previously Reported [Member]
Net Income		$ (115)	$ 50	$ 65	$ 2	$ 12	$ 35	$ 44	$ (21)			(15)		65		$ 108
Operating income												218		320		306
Total operating revenues												$ 1,021		$ 953		$ 828

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[2] Retrospectively adjusted as discussed in Note 1, Nature of Business.

[3] Retrospectively adjusted as discussed in Note 1, Nature of Business.

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

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Yield, Inc. (Parent) Footnotes (Details) - USD ($) $ in Millions			12 Months Ended
		Mar. 27, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Payments of Capital Distribution	[1]		$ 170	$ 76	$ 333
Pro-Rate Share of Debt Held by Unconsolidated Affiliates			589
NRG Yield, Inc. [Member] | NRG Yield LLC [Member]
Payments of Capital Distribution			$ 92	$ 69	$ 41
Agua Caliente Borrower 2 [Member]
Equity Method Investment, Ownership Percentage			16.00%
Subsequent Event [Member] | Agua Caliente [Member]
Equity Method Investment, Ownership Percentage		16.00%
Subsequent Event [Member] | March 2017 Drop Down Assets [Member]
Business Combination, Consideration Transferred		$ 130
Business Acquisition, Consideration Transferred, Working Capital		1
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt		328
Subsequent Event [Member] | Agua Caliente Borrower 2 [Member]
Pro-Rate Share of Debt Held by Unconsolidated Affiliates		$ 135

[1] Retrospectively adjusted as discussed in Note 1, Nature of Business.

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Valuation and Qualifying Accounts (Details) - Valuation Allowance of Deferred Tax Assets [Member] $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$ 0
Charged to Costs and Expenses	0
Charged to Other Accounts	16
Balance at End of Period	$ 16