10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the Quarterly Period Ended: June 30, 2016
o	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number: 001-36002

NRG Yield, Inc.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	46-1777204 (I.R.S. Employer Identification No.)
804 Carnegie Center, Princeton, New Jersey (Address of principal executive offices)	08540 (Zip Code)

(609) 524-4500

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

YesxNoo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

YesxNoo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YesoNox

As of July 31, 2016, there were 34,586,250 shares of Class A common stock outstanding, par value $0.01 per share, 42,738,750 shares of Class B common stock outstanding, par value $0.01 per share, 62,784,250 shares of Class C common stock outstanding, par value $0.01 per share, and 42,738,750 shares of Class D common stock outstanding, par value $0.01 per share.

1

TABLE OF CONTENTS

Index

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION	3
GLOSSARY OF TERMS	4
PART I — FINANCIAL INFORMATION	6
ITEM 1 — FINANCIAL STATEMENTS AND NOTES	6
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	29
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	42
ITEM 4 — CONTROLS AND PROCEDURES	43
PART II — OTHER INFORMATION	44
ITEM 1 — LEGAL PROCEEDINGS	44
ITEM 1A — RISK FACTORS	44
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	44
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	44
ITEM 4 — MINE SAFETY DISCLOSURES	44
ITEM 5 — OTHER INFORMATION	44
ITEM 6 — EXHIBITS	45
SIGNATURES	46

2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q of NRG Yield, Inc., together with its consolidated subsidiaries, or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. The words "believes," "projects," "anticipates," "plans," "expects," "intends," "estimates" and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause the Company's actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Item 1A — Risk Factors in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2015, and the following:

• The Company's ability to maintain and grow its quarterly dividend;

• The Company's ability to successfully identify, evaluate and consummate acquisitions from third parties;

• The Company's ability to acquire assets from NRG;

• The Company's ability to raise additional capital due to its indebtedness, corporate structure, market conditions or otherwise;

• Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions (including wind and solar conditions), catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that the Company may not have adequate insurance to cover losses as a result of such hazards;

• The Company's ability to operate its businesses efficiently, manage maintenance capital expenditures and costs effectively, and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;

• The willingness and ability of counterparties to the Company's offtake agreements to fulfill their obligations under such agreements;

• The Company's ability to enter into contracts to sell power and procure fuel on acceptable terms and prices as current offtake agreements expire;

• Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws;

• Changes in law, including judicial decisions;

• Operating and financial restrictions placed on the Company that are contained in the project-level debt facilities and other agreements of certain subsidiaries and project-level subsidiaries generally, in the NRG Yield Operating LLC amended and restated revolving credit facility, in the indentures governing the Senior Notes and in the indentures governing the Company's convertible notes; and

• The Company's ability to borrow additional funds and access capital markets, as well as the Company's substantial indebtedness and the possibility that the Company may incur additional indebtedness going forward.

Forward-looking statements speak only as of the date they were made, and the Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause the Company's actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report on Form 10-Q should not be construed as exhaustive.

3

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:

2015 Form 10-K	NRG Yield, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2015
2019 Convertible Notes	$345 million aggregate principal amount of 3.50% Convertible Notes due 2019, issued by NRG Yield, Inc.
2020 Convertible Notes	$287.5 million aggregate principal amount of 3.25% Convertible Notes due 2020, issued by NRG Yield, Inc.
AOCL	Accumulated Other Comprehensive Loss
ARO	Asset Retirement Obligation
ASC	The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP
ASU	Accounting Standards Updates – updates to the ASC
Buffalo Bear	Buffalo Bear, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Buffalo Bear project
CAFD	Cash Available For Distribution, which the Company defines as net income before interest expense, income taxes, depreciation and amortization, plus cash distributions from unconsolidated affiliates, 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 other assets
COD	Commercial Operations Date
Company	NRG Yield, Inc. together with its consolidated subsidiaries
CVSR	California Valley Solar Ranch
CVSR Holdco	CVSR Holdco LLC, the indirect owner of CVSR
DGPV Holdco 1	NRG DGPV Holdco 1 LLC
DGPV Holdco 2	NRG DGPV Holdco 2 LLC
Distributed Solar	Solar power projects, typically less than 20 MW in size, that primarily sell power produced to customers for usage on site, or are interconnected to sell power into the local distribution grid
Drop Down Assets	Collectively, the January 2015 Drop Down Assets and the November 2015 Drop Down Assets
Economic Gross Margin	Energy and capacity revenue less cost of fuels
El Segundo	NRG West Holdings LLC, the subsidiary of Natural Gas Repowering LLC, which owns the El Segundo Energy Center project
ERCOT	Electric Reliability Council of Texas, the ISO and the regional reliability coordinator of the various electricity systems within Texas
EWG	Exempt Wholesale Generator
Exchange Act	The Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the U.S.
GenConn	GenConn Energy LLC
HLBV	Hypothetical Liquidation at Book Value
IASB	International Accounting Standards Board
ISO	Independent System Operator, also referred to as RTO
January 2015 Drop Down Assets	The Laredo Ridge, Tapestry and Walnut Creek projects, which were acquired by NRG Yield Operating LLC from NRG on January 2, 2015
Kansas South	NRG Solar Kansas South LLC, the operating subsidiary of NRG Solar Kansas South Holdings LLC, which owns the Kansas South project
Laredo Ridge	Laredo Ridge Wind, LLC, the operating subsidiary of Mission Wind Laredo, LLC, which owns the Laredo Ridge project
LIBOR	London Inter-Bank Offered Rate
Marsh Landing	NRG Marsh Landing LLC, formerly GenOn Marsh Landing LLC

4

MMBtu	Million British Thermal Units
MW	Megawatts
MWh	Saleable megawatt hours, net of internal/parasitic load megawatt-hours
MWt	Megawatts Thermal Equivalent
NERC	North American Electric Reliability Corporation
Net Exposure	Counterparty credit exposure to NRG Yield, Inc. net of collateral
NOLs	Net Operating Losses
November 2015 Drop Down Assets	75% of the Class B interests of NRG Wind TE Holdco, which owns a portfolio of 12 wind facilities totaling 814 net MW, which was acquired by NRG Yield Operating LLC from NRG on November 3, 2015
NRG	NRG Energy, Inc.
NRG Wind TE Holdco	NRG Wind TE Holdco LLC
NRG Yield LLC	The holding company through which the projects are owned by NRG, the holder of Class B and Class D units, and NRG Yield, Inc., the holder of the Class A and Class C units
NRG Yield Operating LLC	The holder of the project assets that are owned by NRG Yield LLC
OCI/OCL	Other comprehensive income/loss
Pinnacle	Pinnacle Wind, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Pinnacle project
PPA	Power Purchase Agreement
PUCT	Public Utility Commission of Texas
QF	Qualifying Facility under the Public Utility Regulatory Policies Act of 1978
Recapitalization	The adoption of the Company's Second Amended and Restated Certificate of Incorporation which authorized two new classes of common stock, Class C common stock and Class D common stock, and distributed shares of such new classes of common stock to holders of the Company’s outstanding Class A common stock and Class B common stock, respectively, through a stock split on May 14, 2015
ROFO Agreement	Amended and Restated Right of First Offer Agreement between the Company and NRG
RPV Holdco	NRG RPV Holdco 1 LLC
RTO	Regional Transmission Organization
SEC	U.S. Securities and Exchange Commission
Senior Notes	NRG Yield Operating LLC's $500 million of 5.375% unsecured senior notes due 2024
TA High Desert	TA-High Desert LLC, the operating subsidiary of NRG Solar Mayfair LLC, which owns the TA High Desert project
Taloga	Taloga Wind, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Taloga project
Tapestry	Collection of the Pinnacle, Buffalo Bear and Taloga projects
Thermal Business	The Company's thermal business, which consists of thermal infrastructure assets that provide steam, hot water and/or chilled water, and in some instances electricity, to commercial businesses, universities, hospitals and governmental units
U.S.	United States of America
Utility Scale Solar	Solar power projects, typically 20 MW or greater in size (on an alternating current, or AC, basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level
VaR	Value at Risk
VIE	Variable Interest Entity
Walnut Creek	NRG Walnut Creek, LLC, the operating subsidiary of WCEP Holdings, LLC, which owns the Walnut Creek project

5

PART I - FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

NRG YIELD, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three months ended June 30,						Six months ended June 30,
(In millions, except per share amounts)	2016			2015 (a)			2016			2015 (a)
Operating Revenues
Total operating revenues	$	258		$	235		$	478		$	435
Operating Costs and Expenses
Cost of operations	75			75			158			159
Depreciation and amortization	67			70			133			137
General and administrative	3			3			6			6
Acquisition-related transaction and integration costs	—			1			—			1
Total operating costs and expenses	145			149			297			303
Operating Income	113			86			181			132
Other Income (Expense)
Equity in earnings of unconsolidated affiliates	18			8			20			10
Other income, net	1			—			1			1
Loss on debt extinguishment	—			(7		)	—			(7		)
Interest expense	(62		)	(45		)	(130		)	(118		)
Total other expense, net	(43		)	(44		)	(109		)	(114		)
Income Before Income Taxes	70			42			72			18
Income tax expense	12			4			12			—
Net Income	58			38			60			18
Less: Pre-acquisition net loss of Drop Down Assets	—			(3		)	—			(7		)
Net Income Excluding Pre-acquisition Net Loss of Drop Down Assets	58			41			60			25
Less: Net income attributable to noncontrolling interests	26			31			23			20
Net Income Attributable to NRG Yield, Inc.	$	32		$	10		$	37		$	5
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	35			35			35			35
Weighted average number of Class A common shares outstanding - diluted	49			35			35			35
Weighted average number of Class C common shares outstanding - basic	63			35			63			35
Weighted average number of Class C common shares outstanding - diluted	73			35			63			35
Earnings per Weighted Average Class A and Class C Common Share - Basic	$	0.33		$	0.15		$	0.38		$	0.07
Earnings per Weighted Average Class A Common Share - Diluted	0.29			0.15			0.38			0.07
Earnings per Weighted Average Class C Common Share - Diluted	0.31			0.15			0.38			0.07
Dividends Per Class A Common Share	0.23			0.20			0.455			0.59
Dividends Per Class C Common Share	$	0.23		$	0.20		$	0.455		$	0.20

^(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 COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three months ended June 30,						Six months ended June 30,
(In millions)	2016			2015 (a)			2016			2015 (a)
Net Income	$	58		$	38		$	60		$	18
Other Comprehensive (Loss) Income, net of tax
Unrealized (loss) gain on derivatives, net of income tax benefit (expense) of $3, ($4), $12 and $4	(16		)	23			(57		)	3
Other comprehensive (loss) income	(16		)	23			(57		)	3
Comprehensive Income	42			61			3			21
Less: Pre-acquisition net loss of Drop Down Assets	—			(3		)	—			(7		)
Less: Comprehensive income (loss) attributable to noncontrolling interests	13			48			(14		)	30
Comprehensive Income (Loss) Attributable to NRG Yield, Inc.	$	29		$	16		$	17		$	(2	)

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

See accompanying notes to consolidated financial statements.

7

NRG YIELD, INC.

CONSOLIDATED BALANCE SHEETS

(In millions, except shares)	June 30, 2016			December 31, 2015
ASSETS	(unaudited)
Current Assets
Cash and cash equivalents	$	89		$	111
Restricted cash	55			48
Accounts receivable — trade	109			95
Accounts receivable — affiliate	1			—
Inventory	35			35
Derivative instruments	1			—
Notes receivable	7			7
Prepayments and other current assets	22			22
Total current assets	319			318
Property, plant and equipment, net of accumulated depreciation of $832 and $701	4,947			5,056
Other Assets
Equity investments in affiliates	778			798
Notes receivable	6			10
Intangible assets, net of accumulated amortization of $132 and $93	1,321			1,362
Deferred income taxes	170			170
Other non-current assets	66			61
Total other assets	2,341			2,401
Total Assets	$	7,607		$	7,775
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt	$	251		$	241
Accounts payable — trade	21			23
Accounts payable — affiliate	32			85
Derivative instruments	37			39
Accrued expenses and other current liabilities	39			68
Total current liabilities	380			456
Other Liabilities
Long-term debt	4,465			4,562
Accounts payable — affiliate	20			—
Derivative instruments	122			61
Other non-current liabilities	63			64
Total non-current liabilities	4,670			4,687
Total Liabilities	5,050			5,143
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 June 30, 2016, and December 31, 2015	1			1
Additional paid-in capital	1,835			1,855
Retained earnings	26			12
Accumulated other comprehensive loss	(47		)	(27		)
Noncontrolling interest	742			791
Total Stockholders' Equity	2,557			2,632
Total Liabilities and Stockholders' Equity	$	7,607		$	7,775

See accompanying notes to consolidated financial statements.

8

NRG YIELD, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six months ended June 30,
	2016			2015 (a)
	(In millions)
Cash Flows from Operating Activities
Net income	$	60		$	18
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of unconsolidated affiliates	(20		)	(10		)
Distributions from unconsolidated affiliates	22			32
Depreciation and amortization	133			137
Amortization of financing costs and debt discounts	10			6
Amortization of intangibles and out-of-market contracts	40			26
Adjustment for debt extinguishment	—			7
Changes in income taxes	12			—
Changes in derivative instruments	(2		)	(37		)
Disposal of asset components and ARO accretion	4			2
Changes in prepaid and accrued capacity payments	(65		)	(66		)
Changes in other working capital	4			(22		)
Net Cash Provided by Operating Activities	198			93
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired	—			(37		)
Acquisition of Drop Down Assets, net of cash acquired	—			(489		)
Capital expenditures	(11		)	(8		)
(Increase) decrease in restricted cash	(7		)	5
Decrease in notes receivable	4			3
Return of investment from unconsolidated affiliates	29			15
Investments in unconsolidated affiliates	(59		)	(328		)
Other	2			—
Net Cash Used in Investing Activities	(42		)	(839		)
Cash Flows from Financing Activities
Net contributions from noncontrolling interests	8			123
Distributions to NRG for NRG Wind TE Holdco	(6		)	—
Proceeds from the issuance of common stock	—			600
Payment of dividends and distributions to shareholders	(83		)	(61		)
Payment of debt issuance costs	—			(11		)
Net borrowings from the revolving credit facility	12			267
Net payments of long-term debt	(109		)	(294		)
Net Cash (Used in) Provided by Financing Activities	(178		)	624
Net Decrease in Cash and Cash Equivalents	(22		)	(122		)
Cash and Cash Equivalents at Beginning of Period	111			429
Cash and Cash Equivalents at End of Period	$	89		$	307

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

See accompanying notes to consolidated financial statements.

9

NRG YIELD, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Nature of Business

NRG Yield, Inc., together with its consolidated subsidiaries, or the Company, is a dividend growth-oriented company formed by NRG as a Delaware corporation on December 20, 2012, to serve as the primary vehicle through which NRG owns, operates and acquires contracted renewable and conventional generation and thermal infrastructure assets. NRG Yield, Inc. owns 100% of the Class A units and Class C units of NRG Yield LLC, including a controlling interest through its position as managing member. NRG Yield LLC, through its wholly owned subsidiary, NRG Yield Operating LLC, is the holder of a portfolio of renewable and conventional generation and thermal infrastructure assets, primarily located in the Northeast, Southwest and California regions of the U.S.

NRG Yield, Inc. consolidates the results of NRG Yield LLC through its controlling interest, with NRG's interest shown as noncontrolling interest in the financial statements. On May 14, 2015, NRG Yield, Inc. completed a stock split whereby 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. In addition, on June 29, 2015, NRG Yield, Inc. completed the issuance of 28,198,000 shares of Class C common stock for net proceeds of $599 million. The holders of NRG Yield, Inc.'s outstanding shares of Class A and Class C common stock are entitled to dividends as declared. NRG receives its distributions from NRG Yield LLC through its ownership of NRG Yield LLC Class B and Class D units.

The following table represents the structure of the Company as of June 30, 2016:

10

As of June 30, 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
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	48.95	%	122	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
			482
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	74.3	%	16	Corn Belt Power Cooperative	2027
Elbow Creek	75	%	92	NRG Power Marketing LLC	2022
Elkhorn Ridge	50.3	%	41	Nebraska Public Power District	2029
Forward	75	%	22	Constellation NewEnergy, Inc.	2017
Goat Wind	74.9	%	113	Dow Pipeline Company	2025
Hardin	74.3	%	11	Interstate Power and Light Company	2027
Laredo Ridge	100	%	80	Nebraska Public Power District	2031
Lookout	75	%	29	Southern Maryland Electric Cooperative	2030
Odin	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	56.3	%	68	Southwestern Public Service Company	2025
Sleeping Bear	75	%	71	Public Service Company of Oklahoma	2032
South Trent	100	%	101	AEP Energy Partners	2029
Spanish Fork	75	%	14	PacifiCorp	2028
Spring Canyon II (b)	90.1	%	29	Platte River Power Authority	2039
Spring Canyon III (b)	90.1	%	25	Platte River Power Authority	2039
Taloga	100	%	130	Oklahoma Gas & Electric	2031
Wildorado	74.9	%	121	Southwestern Public Service Company	2027
			1,999

11

Projects	Percentage Ownership		Net Capacity (MW)(a)	Offtake Counterparty	Expiration
Thermal
Thermal equivalent MWt (c)	100	%	1,315	Various	Various
NRG Dover Energy Center LLC	100	%	103	NRG Power Marketing LLC	2018
Thermal generation	100	%	20	Various	Various
Total net capacity (excluding equivalent MWt)(d)			4,558

^(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 June 30, 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) Total net capacity excludes 55 MW for RPV Holdco and 45 MW for DGPV Holdco 1 and DGPV Holdco 2, which are consolidated by NRG, as further described in Note 4, Variable Interest Entities, or VIEs.

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 11, 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, with the equity associated with the Class B and Class D common stockholder, NRG, and the third-party interests under certain tax equity arrangements classified as noncontrolling interest.

As described in Note 3, Business Acquisitions, 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, from NRG for 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. Additionally, 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, including $9 million for working capital. The acquisitions of the November 2015 Drop Down Assets and the January 2015 Drop Down Assets, or collectively, the Drop Down Assets, were accounted for as transfers 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 since the inception of common control. Accordingly, 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), which was April 1, 2014 for the January Drop Down Assets and the majority of the November 2015 Drop Down Assets. The recast did not affect net income attributable to NRG Yield, Inc., weighted average number of shares outstanding, earnings per share or dividends. With respect to the November 2015 Drop Down Assets, the Company has recorded all minority interests in NRG Wind TE Holdco as noncontrolling interest in the Consolidated Financial Statements for all periods presented.

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with the SEC’s regulations for interim financial information. Accordingly, they do not include all of the information and notes required by GAAP for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the Company’s audited consolidated financial statements for the year ended December 31, 2015. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of June 30, 2016, and the results of operations, comprehensive income and cash flows for the six months ended June 30, 2016, and 2015.

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Note 2 — Summary of Significant Accounting Policies

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.

Noncontrolling Interests

The following table reflects the changes in the Company's noncontrolling interest balance:

	(In millions)
Balance as of December 31, 2015	$	791
Capital contributions from tax equity investors, net of distributions	8
November 2015 Drop Down Assets working capital payment	2
Comprehensive loss	(14		)
Distributions to NRG	(45		)
Balance as of June 30, 2016	$	742

Distributions to NRG

The following table lists the distributions paid on NRG Yield LLC's Class B and D units during the six months ended June 30, 2016:

	Second Quarter 2016		First Quarter 2016
Distributions per Class B Unit	$	0.23	$	0.225
Distributions per Class D Unit	$	0.23	$	0.225

On July 26, 2016, NRG Yield LLC declared a distribution on its units of $0.24 per unit payable on September 15, 2016 to unit holders of record as of September 1, 2016. The portion of the distributions paid by NRG Yield LLC to NRG is recorded as a reduction to the Company's noncontrolling interest balance.

Additionally, the Company paid $6 million to NRG relating to its noncontrolling interest in NRG Wind TE Holdco for the six months ended June 30, 2016.

Recent Accounting Developments

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 guidance in ASU No. 2016-07 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. The adoption of ASU No. 2016-07 is required to be applied prospectively and early adoption is permitted. The Company does not expect the standard to have a material impact on its results of operations, cash flows and financial position.

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ASU 2016-02 — In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or ASU No. 2016-02. The amendments of ASU No. 2016-02 complete the joint effort between the FASB and the International Accounting Standards Board, or IASB, to develop a common leasing standard for GAAP and International Financial Reporting Standards, or IFRS, 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. The guidance in ASU No. 2016-02 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, ASU No. 2016-02 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The guidance in ASU No. 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those annual periods. The adoption of ASU No. 2016-02 is required to be applied using a modified retrospective approach for the earliest period presented and early adoption is permitted. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.

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 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 this standard on January 1, 2016, and the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.

ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU No. 2014-09.  The amendments of ASU No. 2014-09 complete the joint effort between the FASB and the International Accounting Standards Board, or IASB, to develop a common revenue standard for GAAP and International Financial Reporting Standards, or IFRS, and to improve financial reporting.  The guidance in ASU No. 2014-09 provides that an entity should recognize revenue to depict the transfer of goods or services 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 the following steps to be applied by an entity: (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies the performance obligation.  In August 2015, the FASB issued ASU 2015-14, which formally deferred the effective date by one year to make the guidance of ASU No. 2014-09 effective for annual reporting periods beginning after December 15, 2017, including interim periods therein.  Early adoption is permitted, but not prior to the original effective date, which was for annual reporting periods beginning after December 15, 2016.

In addition to ASU No. 2014-09, the FASB has issued additional guidance which provides further clarification on Topic 606. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606), or ASU No. 2016-08. The amendments of ASU No. 2016-08 clarify how to apply the implementation guidance on principal versus agent considerations related to the sale of goods or services to a customer as updated by ASU No. 2014-09. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606), or ASU No. 2016-10. The amendments of ASU No. 2016-10 provide further clarification on contract revenue recognition as updated by ASU No. 2014-09, specifically related to the identification of separately identifiable performance obligations and the implementation of licensing contracts. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606), or ASU No. 2016-12. The amendments of ASU No. 2016-12 provide further clarification on contract revenue recognition as updated by ASU No. 2014-09, specifically related to collectability, the presentation of tax collected from customers, and non-cash consideration, as well as offering practical expedients. The Company is working through an adoption plan which includes the evaluation of revenue contracts compared to the new standard and evaluating the impact of Topic 606 on the Company's results of operations, cash flows and financial position.

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Note 3 — Business Acquisitions

2016 Acquisitions

CVSR — On August 8, 2016, the Company and NRG entered into a definitive agreement regarding the acquisition of the remaining 51.05% interest in the CVSR project for total expected cash consideration of $78.5 million plus assumed debt and working capital adjustments to be calculated at close. The sale is subject to customary closing conditions and is expected to close during the third quarter of 2016. The Company expects to fund the acquisition with drawings under the Company's revolving credit facility.

The acquisition will be accounted for as 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 since the inception of common control. Accordingly, the Company will prepare its consolidated financial statements to reflect the transfer as if it 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), which would be January 1, 2015. The recast would not affect net income attributable to NRG Yield, Inc., weighted average number of shares outstanding, earnings per share or dividends.

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.

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 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

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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.

Note 4 — Variable Interest Entities, or VIEs

Entities that are Consolidated

The Company has a controlling financial interest in certain entities which have been identified as VIEs under ASC 810, Consolidations, or ASC 810. These arrangements are primarily related to tax equity arrangements entered into with third parties in order to monetize certain tax credits associated with wind facilities, as further described in Note 5,Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's audited consolidated financial statements included in the 2015 Form 10-K.

Summarized financial information for the Company's consolidated VIEs consisted of the following as of June 30, 2016:

(In millions)	NRG Wind TE Holdco		Alta Wind TE Holdco		Spring Canyon
Other current and non-current assets	$	190	$	27	$	4
Property, plant and equipment	638		472		102
Intangible assets	2		281		—
Total assets	830		780		106
Current and non-current liabilities	215		8		6
Total liabilities	215		8		6
Noncontrolling interest	235		121		70
Net assets less noncontrolling interests	$	380	$	651	$	30

Entities that are not Consolidated

The Company has interests in entities that are considered VIEs under ASC 810, 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, as further described in Note 5,Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's audited consolidated financial statements included in the 2015 Form 10-K.

NRG DGPV Holdco 1 LLC — The Company and NRG, maintain a partnership, 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 20 years; and (ii) a tax equity-financed portfolio of approximately 12 commercial photovoltaic systems representing approximately 37 MW with a weighted average remaining PPA term of 19 years. Both 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 and other ancillary related assets from NRG Renew LLC or its subsidiaries, via intermediate funds.  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 $78 million on a combined basis as of June 30, 2016.

NRG RPV Holdco 1 LLC — The Company and NRG Residential Solar Solutions LLC, a subsidiary of NRG, maintain a partnership, NRG RPV Holdco 1 LLC, or RPV Holdco, that holds operating portfolios of residential solar assets developed by NRG Home Solar, a subsidiary of NRG, including: (i) an existing, unlevered portfolio of over 2,200 leases across nine states representing approximately 17 MW with a weighted average remaining lease term of approximately 17 years; and (ii) a tax equity-financed portfolio of approximately 5,500 leases representing approximately 38 MW, with an average lease term for the existing and new leases of approximately 17 to 20 years. Under this partnership, the Company had previously committed to fund up to $150 million of capital, which was reduced to $100 million in February 2016.

The Company's maximum exposure to loss is limited to its equity investment, which was $67 million as of June 30, 2016.

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On August 5, 2016, the Company and NRG amended the RPV Holdco partnership to further reduce the aggregate commitment of $100 million to $60 million in connection with NRG’s change in business model approach in the residential solar business.

GenConn Energy LLC — The Company has a 50% interest in GCE Holding LLC, the owner of GenConn, which owns and operates two190 MW peaking generation facilities in Connecticut at the Devon and Middletown sites. As of June 30, 2016, the Company's investment in GenConn was $108 million and its maximum exposure to loss is limited to its equity investment.

The following table presents summarized financial information for GCE Holding LLC:

	Three months ended June 30,				Six months ended June 30,
(In millions)	2016		2015		2016		2015
Income Statement Data:
Operating revenues	$	18	$	18	$	36	$	40
Operating income	10		11		19		20
Net income	$	6	$	8	$	13	$	14

	June 30, 2016		December 31, 2015
Balance Sheet Data:	(In millions)
Current assets	$	34	$	36
Non-current assets	408		416
Current liabilities	14		16
Non-current liabilities	$	211	$	215

Note 5 — Fair Value of Financial Instruments

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.

For cash and cash equivalents, restricted cash, accounts receivable, accounts receivable — affiliate, accounts payable, accounts payable — affiliate, accrued expenses and other liabilities, the carrying amounts approximate 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 June 30, 2016				As of December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(In millions)
Assets:
Notes receivable, including current portion	$	13	$	13	$	17	$	17
Liabilities:
Long-term debt, including current portion	$	4,772	$	4,772	$	4,863	$	4,745

The fair value of notes receivable and long-term debt are based on expected future cash flows discounted at market interest rates, or current interest rates for similar instruments, and are classified as Level 3 within the fair value hierarchy.

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Recurring Fair Value Measurements

The Company records its derivative assets and liabilities at fair value on its consolidated balance sheet. There were no derivative asset positions on the Company's consolidated balance sheet 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 June 30, 2016		As of December 31, 2015
	Fair Value (a)		Fair Value (a)
(In millions)	Level 2		Level 2
Derivative assets:
Commodity contracts	$	1	$	—
Total assets	1		—
Derivative liabilities:
Commodity contracts	—		2
Interest rate contracts	159		98
Total liabilities	$	159	$	100

^(a) There were no assets or liabilities classified as Level 1 or Level 3 as of June 30, 2016, and December 31, 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 is, for interest rate swaps, calculated based on credit default swaps using the bilateral method. For commodities, to the extent that the net exposure under a specific master agreement is an asset, the Company uses the counterparty’s default swap rate. If the net 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 June 30, 2016, the credit reserve resulted in a $5 million increase in fair value, which was composed of a $4 million gain in OCI and $1 million gain in interest expense. It is possible that future market prices could vary from those used in recording assets and liabilities and such variations could be material.

Concentration of Credit Risk

In addition to the credit risk discussion in Note 2, Summary of Significant Accounting Policies, to the Company's audited consolidated financial statements included in the Company's 2015 Form 10-K, the following 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 June 30, 2016, credit risk exposure to these counterparties attributable to the Company's ownership interests was approximately $2.5 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, as further described in Note 12, Segment Reporting, to the Company's audited consolidated financial statements included in the Company's 2015 Form 10-K. However, such regulated utility counterparties can be impacted by changes in government regulations, which the Company is unable to predict.

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Note 6 — Accounting for Derivative Instruments and Hedging Activities

This footnote should be read in conjunction with the complete description under Note 7, Accounting for Derivative Instruments and Hedging Activities,to the Company's audited consolidated financial statements included in the Company's 2015 Form 10-K.

Energy-Related Commodities

As of June 30, 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. At June 30, 2016, these contracts were not designated as cash flow or fair value hedges.

Interest Rate Swaps

As of June 30, 2016, the Company had interest rate derivative instruments on non-recourse debt extending through 2031, 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 June 30, 2016, and December 31, 2015.

		Total Volume
		June 30, 2016		December 31, 2015
Commodity	Units	(In millions)
Natural Gas	MMBtu	4		4
Interest	Dollars	$	1,932	$	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
	June 30, 2016		June 30, 2016		December 31, 2015
	(In millions)
Derivatives Designated as Cash Flow Hedges:
Interest rate contracts current	$	—	$	34	$	34
Interest rate contracts long-term	—		108		56
Total Derivatives Designated as Cash Flow Hedges	—		142		90
Derivatives Not Designated as Cash Flow Hedges:
Interest rate contracts current	—		3		3
Interest rate contracts long-term	—		14		5
Commodity contracts current	1		—		2
Total Derivatives Not Designated as Cash Flow Hedges	1		17		10
Total Derivatives	$	1	$	159	$	100

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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 June 30, 2016, and December 31, 2015, there were no offsetting amounts at the counterparty master agreement level or outstanding collateral paid or received.

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:

	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In millions)
Accumulated OCL beginning balance	$	(110	)	$	(81	)	$	(69	)	$	(61	)
Reclassified from accumulated OCL to income due to realization of previously deferred amounts	3			4			6			7
Mark-to-market of cash flow hedge accounting contracts	(19		)	19			(63		)	(4		)
Accumulated OCL ending balance, net of income tax benefit of $28 and $10, respectively	$	(126	)	$	(58	)	$	(126	)	$	(58	)
Accumulated OCL attributable to noncontrolling interests	(79		)	(42		)	(79		)	(42		)
Accumulated OCL attributable to NRG Yield, Inc.	$	(47	)	$	(16	)	$	(47	)	$	(16	)
Losses expected to be realized from OCL during the next 12 months, net of income tax benefit of $4	$	18					$	18

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 six months ended June 30, 2016, and 2015.

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 three months ended June 30, 2016, and 2015, the impact to the consolidated statements of income was a loss of $2 million and a gain of $31 million, respectively. For the six months ended June 30, 2016, and 2015, the impact to the consolidated statements of income was a loss of $9 million and a gain of $19 million, respectively.

A portion of the Company’s derivative commodity contracts relates to its Thermal Business for the purchase of fuel commodities based on the forecasted usage of the thermal district energy centers. Realized gains and losses on these contracts are reflected in the fuel 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.

Commodity contracts also hedged the forecasted sale of power for Elbow Creek, Alta X and Alta XI in 2015 until the start of the PPAs. The effect of these commodity hedges was recorded to operating revenues. For the three and six months ended June 30, 2015, the impact to the consolidated statements of income was an unrealized loss of $4 million and an unrealized gain of $3 million, respectively.

See Note 5, Fair Value of Financial Instruments, for a discussion regarding concentration of credit risk.

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Note 7 — Long-term Debt

This footnote should be read in conjunction with the complete description under Note 9, Long-term Debt, to the Company's audited consolidated financial statements included in the 2015 Form 10-K. Long-term debt consisted of the following:

	June 30, 2016		December 31, 2015		June 30, 2016, interest rate % (a)	Letters of Credit Outstanding at June 30, 2016
	(In millions, except rates)
2019 Convertible Notes (b)	$	333	$	330	3.500
2020 Convertible Notes (c)	268		266		3.250
Senior Notes, due 2024	500		500		5.375
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 (d)	318		306		L+2.75	$	67
Project-level debt:
Alpine, due 2022	151		154		L+1.75	37
Alta Wind I, lease financing arrangement, due 2034	245		252		7.015	16
Alta Wind II, lease financing arrangement, due 2034	194		198		5.696	23
Alta Wind III, lease financing arrangement, due 2034	201		206		6.067	24
Alta Wind IV, lease financing arrangement, due 2034	130		133		5.938	16
Alta Wind V, lease financing arrangement, due 2035	208		213		6.071	27
Alta Realty Investments, due 2031	32		33		7.000	—
Alta Wind Asset Management, due 2031	18		19		L+2.375	—
Avra Valley, due 2031	58		60		L+1.75	3
Blythe, due 2028	21		21		L+1.625	6
Borrego, due 2025 and 2038	71		72		L+ 2.50/5.65	5
El Segundo Energy Center, due 2023	457		485		L+1.625 - L+2.25	82
Energy Center Minneapolis, due 2017 and 2025	100		108		5.95 -7.25	—
Kansas South, due 2031	31		33		L+2.00	4
Laredo Ridge, due 2028	102		104		L+1.875	10
Marsh Landing, due 2017 and 2023	410		418		L+1.75 - L+1.875	45
PFMG and related subsidiaries financing agreement, due 2030	29		29		6.000	—
Roadrunner, due 2031	38		40		L+1.625	5
South Trent Wind, due 2020	59		62		L+1.625	10
TA High Desert, due 2020 and 2032	51		52		L+2.50/5.15	8
Tapestry, due 2021	176		181		L+1.625	20
Viento, due 2023	183		189		L+2.75	27
Walnut Creek, due 2023	341		351		L+1.625	60
WCEP Holdings, due 2023	46		46		L+3.00	—
Other	1		2		various	—
Subtotal project-level debt:	3,353		3,461
Total debt	4,772		4,863
Less current maturities	251		241
Less deferred financing costs	56		60
Total long-term debt	$	4,465	$	4,562

^(a) As of June 30, 2016, L+ equals 3 month LIBOR plus x%, except for the Marsh Landing term loan, Walnut Creek term loan, and NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, where L+ equals 1 month LIBOR plus x% and Kansas South, where L+ equals 6 month LIBOR plus x%.

^(b) Net of discount of $12 million and $15 million as of June 30, 2016, and December 31, 2015, respectively.

^(c) Net of discount of $19 million and $21 million as of June 30, 2016, and December 31, 2015, respectively.

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

21

The financing arrangements listed above contain certain covenants, including financial covenants that the Company is required to be in compliance with during the term of the respective arrangement. As of June 30, 2016, the Company was in compliance with all of the required covenants.

The discussion below describes material changes to or additions of long-term debt for the six months ended June 30, 2016.

CVSR Holdco Financing Arrangement

On July 15, 2016, CVSR Holdco, the indirect owner of the CVSR project, which is 48.95% owned by the Company, issued $200 million of senior secured notes that bear interest at 4.68% and mature on March 31, 2037.  The Company’s pro-rata share of the borrowings was $97.5 million.  Net proceeds of $97.5 million were distributed to NRG Yield Operating LLC based on its pro-rata ownership.

NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility

The Company borrowed $60 million from the revolving credit facility and repaid $48 million during the six months ended June 30, 2016. As of June 30, 2016, $318 million of borrowings and $67 million of letters of credit were outstanding. The Company used its pro rata proceeds of $97.5 million from the CVSR Holdco Financing Arrangement, as described above, along with $28 million of cash on hand, to reduce borrowings under the Company’s revolving credit facility. As of July 31, 2016, $193 million of borrowings were outstanding.

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Note 8 — Earnings Per Share

Basic and diluted earnings (loss) per common share are computed by dividing net income (loss) 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. The number of shares and per share amounts for the prior periods presented below have been retrospectively restated to reflect the Recapitalization.

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

	Three months ended June 30,
	2016				2015
(In millions, except per share data)(a)	Common Class A		Common Class C		Common Class A		Common Class C
Basic earnings per share attributable to NRG Yield, Inc. common stockholders
Net income attributable to NRG Yield, Inc.	$	11	$	21	$	5	$	5
Weighted average number of common shares outstanding - basic	35		63		35		35
Earnings per weighted average common share — basic	$	0.33	$	0.33	$	0.15	$	0.15
Diluted earnings per share attributable to NRG Yield, Inc. common stockholders
Net income attributable to NRG Yield, Inc.	$	14	$	23	$	5	$	5
Weighted average number of common shares outstanding - diluted	49		73		35		35
Earnings per weighted average common share — diluted	$	0.29	$	0.31	$	0.15	$	0.15

	Six months ended June 30,
	2016				2015
(In millions, except per share data)(a)	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.	$	13	$	24	$	3	$	3
Weighted average number of common shares outstanding	35		63		35		35
Earnings per weighted average common share — basic and diluted	$	0.38	$	0.38	$	0.07	$	0.07

^(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.

With respect to the Class A common stock, there were a total of 15 million anti-dilutive outstanding equity instruments for the six months ended June 30, 2016, and the three and six months ended June 30, 2015, related to the 2019 Convertible Notes. With respect to the Class C common stock, there were a total of 10 million anti-dilutive outstanding equity instruments for the six months ended June 30, 2016 related to the 2020 Convertible Notes.

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Note 9 — Segment Reporting

The Company’s segment structure reflects how management currently operates and allocates resources. The Company's businesses are primarily 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).

	Three months ended June 30, 2016
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	85		$	134		$	39		$	—		$	258
Cost of operations	16			32			27			—			75
Depreciation and amortization	20			42			5			—			67
General and administrative	—			—			—			3			3
Operating income (loss)	49			60			7			(3		)	113
Equity in earnings of unconsolidated affiliates	4			14			—			—			18
Other income, net	—			1			—			—			1
Interest expense	(12		)	(30		)	(1		)	(19		)	(62		)
Income (loss) before income taxes	41			45			6			(22		)	70
Income tax expense	—			—			—			12			12
Net Income (Loss)	$	41		$	45		$	6		$	(34	)	$	58
Total Assets	$	2,037		$	4,961		$	423		$	186		$	7,607

	Three months ended June 30, 2015 (a)
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	85		$	108		$	42		$	—		$	235
Cost of operations	15			29			31			—			75
Depreciation and amortization	21			45			4			—			70
General and administrative	—			—			—			3			3
Acquisition-related transaction and integration costs	—			—			—			1			1
Operating income (loss)	49			34			7			(4		)	86
Equity in earnings of unconsolidated affiliates	4			4			—			—			8
Loss on debt extinguishment	(7		)	—			—			—			(7		)
Interest expense	(13		)	(17		)	(2		)	(13		)	(45		)
Income (loss) before income taxes	33			21			5			(17		)	42
Income tax expense	—			—			—			4			4
Net Income (Loss)	$	33		$	21		$	5		$	(21	)	$	38

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

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	Six months ended June 30, 2016
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	164		$	231		$	83		$	—		$	478
Cost of operations	39			63			56			—			158
Depreciation and amortization	40			83			10			—			133
General and administrative	—			—			—			6			6
Operating income (loss)	85			85			17			(6		)	181
Equity in earnings of unconsolidated affiliates	7			13			—						20
Other income, net	—			1			—			—			1
Interest expense	(23		)	(66		)	(3		)	(38		)	(130		)
Income (loss) before income taxes	69			33			14			(44		)	72
Income tax expense	—			—			—			12			12
Net Income (Loss)	$	69		$	33		$	14		$	(56	)	$	60

	Six months ended June 30, 2015 (a)
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	161		$	185		$	89		$	—		$	435
Cost of operations	36			58			65			—			159
Depreciation and amortization	42			86			9			—			137
General and administrative	—			—			—			6			6
Acquisition-related transaction and integration costs	—			—			—			1			1
Operating income (loss)	83			41			15			(7		)	132
Equity in earnings of unconsolidated affiliates	7			3			—			—			10
Other income, net	1			—			—			—			1
Loss on debt extinguishment	(7		)	—			—			—			(7		)
Interest expense	(25		)	(63		)	(4		)	(26		)	(118		)
Income (loss) before income taxes	59			(19		)	11			(33		)	18
Net Income (Loss)	$	59		$	(19	)	$	11		$	(33	)	$	18

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

Note 10 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:

	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In millions, except percentages)
Income before income taxes	$	70		$	42		$	72		$	18
Income tax expense	12			4			12			—
Effective income tax rate	17.1		%	9.5		%	16.7		%	—		%

For the three and six months ended June 30, 2016, and 2015, the overall effective tax rate was different than the statutory rate of 35% primarily due to taxable earnings allocated to NRG resulting from its interest in NRG Yield LLC and production and investment tax credits generated from certain wind and solar assets, respectively.

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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Note 11 — Related Party Transactions

In addition to the transactions and relationships described elsewhere in these notes to the consolidated financial statements, NRG and certain subsidiaries of NRG provide services to the Company and its project entities. Amounts due to NRG subsidiaries are recorded as accounts payable - affiliate and amounts due to the Company from NRG or its subsidiaries are recorded as accounts receivable - affiliate in the Company's balance sheet.

Power Hedge Contracts by and between Renewables segment Entities and NRG

Certain NRG Wind TE Holdco entities, which are subsidiaries in the Renewables segment, entered into power hedge contracts with NRG Texas Power LLC and generated $12 million during the six months ended June 30, 2015. Effective October 2015, Elbow Creek, one of the NRG Wind TE Holdco entities, entered into a PPA with NRG Power Marketing LLC, or NRG Power Marketing, as further described below, and the hedge agreement between Elbow Creek and NRG Texas Power LLC was terminated.

Additionally, Alta X and Alta XI entered into a hedge agreement with NRG Power Marketing, as further described in Note 6, Accounting for Derivative Instruments and Hedging Activities, to hedge the forecasted sale of power until the start of the PPAs on January 1, 2016.

Power Purchase Agreement 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 expiring on October 31, 2022. Elbow Creek generated $4 million of revenue during the six months ended June 30, 2016.

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

Certain wholly-owned subsidiaries of the Company are party to a Plant O&M Services Agreement with NRG, pursuant to which NRG provides necessary and appropriate services to operate and maintain the subsidiaries' plant operations, businesses and thermal facilities. NRG is reimbursed for the provided services, as well as for all reasonable and related expenses and expenditures, and payments to third parties for services and materials rendered to or on behalf of the parties to the agreements. NRG is not entitled to any management fee or mark-up under the agreements. Total fees incurred under the agreements were $15 million for the six months ended June 30, 2016, and 2015. There was a balance of $27 million and $29 million due to NRG in accounts payable — affiliate as of June 30, 2016, and December 31, 2015, respectively. As of June 30, 2016, $7 million of the balance was recorded in the current liabilities of the consolidated balance sheet and $20 million was recorded in long term liabilities of the consolidated balance sheet. Subsequent to June 30, 2016, $4 million of the outstanding balance has been paid.

Power Purchase Agreement 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 $2 million of revenue during the six months ended June 30, 2016. The agreement in place is additive to the existing Power Sales and Services Agreement as described further below.

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

NRG Energy Center Dover LLC, or NRG Dover, a subsidiary of the Company, 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 days 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. In July 2013, the coal-fueled plant was converted to a natural gas facility. For the six months ended June 30, 2016, and 2015, NRG Dover purchased $1 million and $3 million, respectively, of natural gas from NRG Power Marketing.

26

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, a wholly-owned subsidiary of NRG. Under the agreement, NRG Power Marketing procures fuel and fuel transportation for the operation of the Minneapolis generating facility. For the six months ended June 30, 2016, and 2015, NRG Minneapolis purchased $4 million and $5 million, respectively, of natural gas from NRG Power Marketing.

O&MServices Agreements by and between GenConn and NRG

GenConn incurs fees under two O&M services agreements with wholly-owned subsidiaries of NRG. The fees incurred under the agreements were $3 million and $2 million for the six months ended June 30, 2016, and 2015, respectively.

O&MServices Agreement by and between El Segundo and NRG

El Segundo incurs fees under an O&M services agreement with NRG El Segundo Operations, Inc., a wholly-owned subsidiary of NRG. Under the O&M services 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 the six months ended June 30, 2016, and 2015, the costs incurred under the agreement were $2 million. There was a balance of $1 million due to NRG El Segundo in accounts payable — affiliate as of June 30, 2016, and December 31, 2015.

Administrative Services Agreement by and between Marsh Landing and NRG

Marsh Landing is a party to an administrative services agreement with GenOn Energy Services, LLC, a wholly-owned subsidiary of NRG, which provides invoice processing and payment on behalf of Marsh Landing. Marsh Landing reimburses GenOn Energy Services, LLC for the amounts paid by it. The Company reimbursed costs under this agreement of $5 million and $9 million for the six months ended June 30, 2016, and 2015, respectively. There was a balance of $6 million due to GenOn Energy Services, LLC in accounts payable — affiliate as of June 30, 2016, and December 31, 2015.

Administrative Services Agreement by and between CVSR and NRG

CVSR is a party to an administrative services agreement with NRG Renew Operation & Maintenance LLC, a wholly-owned subsidiary of NRG, which provides O&M services on behalf of CVSR. CVSR reimburses NRG Energy Services LLC for the amounts paid by it. CVSR reimbursed costs under this agreement of $2 million and $3 million for the six months ended June 30, 2016, and 2015, respectively.

Management Services Agreement by and between the Company and NRG

NRG provides the Company with various operation, 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 June 30, 2016, the base management fee was approximately $7 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, 2015, the fee was increased by $1 million per year primarily due to the acquisitions of the January 2015 Drop Down Assets and the November 2015 Drop Down Assets. Costs incurred under this agreement were $5 million for the six months ended June 30, 2016, and 2015, which included certain direct expenses incurred by NRG on behalf of the Company in addition to the base management fee. There was a balance of $4 million due to NRG in accounts payable — affiliate as of June 30, 2016. Subsequent to June 30, 2016, the balance has been paid in full.

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

Certain subsidiaries of NRG have entered into agreements with the Company's project entities to provide operation and maintenance services for the balance of the plants not covered by turbine supplier's maintenance and service agreements for the post-warranty period. The agreements have various terms with provisions for extension until terminated. For the six months ended June 30, 2016, and 2015, the costs incurred under the agreements were $3 million and $2 million, respectively.

Certain subsidiaries of NRG provide support services to the NRG Wind TE Holdco 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 six months ended June 30, 2016, and 2015, the costs incurred under the agreements were $1 million and $2 million, respectively.

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Note 12— Contingencies

The Company's material legal proceeding is described below. The Company believes that it has a valid defense to this legal proceeding and intends to defend it 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 proceeding 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 proceeding 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 purported class action lawsuit against NRG Yield, Inc. and against each current and former member of its board of directors individually 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 the Company'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 provides that the plaintiffs will file an amended complaint by August 19, 2016. The Defendants need to file a responsive pleading by October 18, 2016.

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ITEM 2 — 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 November 2015 Drop Down Assets, which were acquired from NRG on November 3, 2015. As further discussed in Note 1, Nature of Business, to the Consolidated Financial Statements, the purchase of these assets was accounted for in accordance with ASC 805-50, Business Combinations - Related Issues, pursuant to which 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 from NRG with the offset to noncontrolling interest. 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.

As you read this discussion and analysis, you should refer to the Company's Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the six months ended June 30, 2016, and 2015. You should also refer to the Company's 2015 Form 10-K, which includes 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 income;

• 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.

29

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 represents4,435 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 approximately17 years as of June 30, 2016, based on CAFD. The Company also owns thermal infrastructure assets with an aggregate steam and chilled water capacity of 1,315 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.

Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2015 Form 10-K in Item 1, Business — Regulatory Matters and Item 1A, Risk Factors.

As owners of power plants and participants in wholesale and thermal energy markets, certain of the Company's subsidiaries are subject to regulation by various federal and state government agencies. These include FERC and the PUCT, as well as other public utility commissions in certain states where the Company's assets are located. Each of the Company's U.S. generating facilities qualifies as a EWG or QF. In addition, the Company is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, the Company must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where the Company operates.

The Company's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT.

Environmental Matters

The Company’s environmental matters are described in the Company’s 2015 Form 10-K in Item 1, Business — Environmental Matters and Item 1A, Risk Factors.

The Company is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of facilities. The Company is also subject to laws and regulations surrounding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. Environmental laws have become increasingly stringent and the Company expects this trend to continue.

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 Company believes that its inability to access the capital markets has largely subsided and has continued to improve through the second quarter and into the third quarter of 2016.  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 or equity financing to complete such acquisitions or replenish capital for future acquisitions. 

30

Consolidated Results of Operations

The following table provides selected financial information:

	Three months ended June 30,								Six months ended June 30,
(In millions, except otherwise noted)	2016			2015			Change %		2016			2015			Change %
Operating Revenues
Energy and capacity revenues	$	275		$	254		8		$	512		$	458		12
Contract amortization	(17		)	(15		)	13		(34		)	(26		)	31
Mark-to-market economic hedging activities	—			(4		)	100		—			3			(100	)
Total operating revenues	258			235			10		478			435			10
Operating Costs and Expenses
Cost of fuels	14			16			(13	)	30			38			(21	)
Emissions credit amortization	—			—			—		6			—			100
Operations and maintenance	47			42			12		90			87			3
Other costs of operations	14			17			(18	)	32			34			(6	)
Depreciation and amortization	67			70			(4	)	133			137			(3	)
General and administrative	3			3			—		6			6			—
Acquisition-related transaction and integration costs	—			1			(100	)	—			1			(100	)
Total operating costs and expenses	145			149			(3	)	297			303			(2	)
Operating Income	113			86			31		181			132			37
Other Income (Expense)
Equity in earnings of unconsolidated affiliates	18			8			125		20			10			100
Other income, net	1			—			100		1			1			—
Loss on debt extinguishment	—			(7		)	(100	)	—			(7		)	100
Interest expense	(62		)	(45		)	38		(130		)	(118		)	10
Total other expense, net	(43		)	(44		)	(2	)	(109		)	(114		)	(4	)
Income Before Income Taxes	70			42			67		72			18			300
Income tax expense	12			4			200		12			—			100
Net Income	58			38			53		60			18			233
Less: Pre-acquisition net loss of Drop Down Assets	—			(3		)	(100	)	—			(7		)	(100	)
Net Income Excluding Pre-acquisition Net Loss of Drop Down Assets	58			41			41		60			25			(140	)
Less: Net income attributable to noncontrolling interests	26			31			(16	)	23			20			(15	)
Net Income Attributable to NRG Yield, Inc.	$	32		$	10		220		$	37		$	5		NM

NM - Not meaningful

	Three months ended June 30,		Six months ended June 30,
Business metrics:	2016	2015	2016	2015
Renewables MWh generated/sold (in thousands) (a)	1,820	1,699	3,470	2,873
Conventional MWh generated (in thousands) (b)	376	541	637	861
Thermal MWt sold (in thousands)	448	434	1,001	1,051
Thermal MWh sold (in thousands) (c)	9	83	49	127

^(a) Volumes sold do not include the MWh generated 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 23 MWh and 74 MWh generated by NRG Dover, a subsidiary of the Company, under the PPA with NRG Power Marketing during the three and six months ended June 30, 2016, respectively, as further described in Note 11, Related Party Transactions.

31

Management’s Discussion of the Results of Operations for the Three Months ended June 30, 2016, and 2015

Gross Margin and 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 gains, 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 three months ended June 30, 2016, and 2015:

	Conventional Generation			Renewables			Thermal			Total
(In millions)
Three months ended June 30, 2016
Energy and capacity revenues	$	87		$	149		$	39		$	275
Cost of fuels	(1		)	—			(13		)	(14		)
Contract amortization	(2		)	(15		)	—			(17		)
Gross margin	84			134			26			244
Contract amortization	2			15			—			17
Economic gross margin	$	86		$	149		$	26		$	261
Three months ended June 30, 2015
Energy and capacity revenues	$	86		$	126		$	42		$	254
Cost of fuels	—			—			(16		)	(16		)
Contract amortization	(1		)	(14		)	—			(15		)
Mark-to-market for economic hedging activities	—			(4		)	—			(4		)
Gross margin	85			108			26			219
Contract amortization	1			14			—			15
Mark-to-market for economic hedging activities	—			4			—			4
Economic gross margin	$	86		$	126		$	26		$	238

Gross margin increased by $25 million and economic gross marginincreased by $23 million during the three months ended June 30, 2016, compared to the same period in 2015, primarily due to:    

(In millions)
Increase in Renewables economic gross margin due to higher wind generation primarily at Alta, as well as the acquisition of Spring Canyon	$	14
Increase in Renewables economic gross margin due to higher pricing in the Alta X and XI PPAs, which began in January 2016, compared with merchant prices in 2015	9
Increase in economic gross margin	23
Higher contract amortization primarily for the Alta X and XI PPAs, which began in January 2016	(2		)
Increase due to unrealized losses on forward contracts with an NRG subsidiary hedging the forecasted sale of power from Elbow Creek, Alta X and Alta XI in 2015, prior to the start of the PPAs	4
Increase in gross margin	$	25

Operations and Maintenance Expense

Operations and maintenance expense increased by $5 million during the three months ended June 30, 2016, compared to the same period in 2015, primarily due to component disposals and inventory adjustments for certain wind projects and the acquisition of Spring Canyon in 2015, partially offset by the extended forced outage at El Segundo in 2015.

32

Other Costs of Operations

Other costs of operations decreased by $3 million during the three months ended June 30, 2016, compared to the same period in 2015, primarily due to a property tax rebate received in 2016 for the Alta projects.

Equity in Earnings of Unconsolidated Affiliates

Equity in earnings of unconsolidated affiliates increased by $10 million during the three months ended June 30, 2016, compared to the same period in 2015, due primarily to the acquisition of Desert Sunlight, which was acquired on June 29, 2015, as well as increased equity in earnings from DGPV Holdco and RPV Holdco.

Interest Expense     

Interest expense increased by $17 million during the three months ended June 30, 2016, compared to the same period in 2015, due primarily to:

(In millions)
Increase from changes in the fair value of Alpine interest rate swaps	$	7
Increase for Alta due to change in value of Alta X and XI interest rate swaps, partially offset by a decrease in interest expense for the redemption of Alta X and XI project-level debt	5
Increase due to the 2020 Convertible Notes issued in June 2015, amortization of the related discount on the notes and debt issuance costs	4
Increase due to higher revolving credit facility borrowings in 2016	1
	$	17

Income Tax Expense

For the three months ended June 30, 2016, the Company recorded income tax expense of $12 million on pretax income of $70 million. For the same period in 2015, the Company recorded income tax expense of $4 million on pretax income of $42 million. For the three months ended June 30, 2016 and 2015, the Company's 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.

Income Attributable to Noncontrolling Interests

For the three months ended June 30, 2016, the Company had income of $42 million attributable to NRG's interest in the Company and a loss of $16 million attributable to non-controlling interests with respect to its tax equity financing arrangements and the application of the HLBV method. For the three months ended June 30, 2015, the Company had income of $24 million attributable to NRG's interest in the Company and income of $7 million attributable to non-controlling interests with respect to its tax equity financing arrangements and the application of the HLBV method.

33

Management’s Discussion of the Results of Operations for the Six Months ended June 30, 2016, and 2015

Gross Margin and 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 gains, 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 six months ended June 30, 2016, and 2015:

	Conventional Generation			Renewables			Thermal			Total
(In millions)
Six months ended June 30, 2016
Energy and capacity revenues	$	167		$	261		$	84		$	512
Cost of fuels	(1		)	—			(29		)	(30		)
Contract amortization	(3		)	(30		)	(1		)	(34		)
Emissions credit amortization	(6		)	—			—			(6		)
Gross margin	157			231			54			442
Contract amortization	3			30			1			34
Emissions credit amortization	6			—			—			6
Economic gross margin	$	166		$	261		$	55		$	482
Six months ended June 30, 2015
Energy and capacity revenues	$	163		$	205		$	90		$	458
Cost of fuels	(1		)	—			(37		)	(38		)
Contract amortization	(2		)	(23		)	(1		)	(26		)
Mark-to-market for economic hedging activities	—			3			—			3
Gross margin	160			185			52			397
Contract amortization	2			23			1			26
Mark-to-market for economic hedging activities	—			(3		)	—			(3		)
Economic gross margin	$	162		$	205		$	53		$	420

34

Gross margin increased by $45 million and economic gross margin increased by $62 million during the six months ended June 30, 2016, compared to the same period in 2015 due to:

(In millions)
Increase in Renewables economic gross margin due to higher wind generation, primarily for the Alta projects, as well as the acquisition of Spring Canyon	$	40
Increase in Renewables economic gross margin due to higher pricing in the Alta X and XI PPAs which began in January 2016, compared with merchant prices in 2015	16
Increase in Conventional Generation economic gross margin primarily due to higher revenues at El Segundo in 2016 as a result of a return to service after an extended forced outage in 2015	4
Increase in Thermal economic gross margin primarily due to lower gas prices, partially offset by a decrease in generation due to milder weather conditions	2
Increase in economic gross margin	62
Higher contract amortization primarily for the Alta X and XI PPAs, which began in January 2016	(8		)
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		)
Decrease due to unrealized gains on forward contracts with an NRG subsidiary hedging the forecasted sale of power from Elbow Creek, Alta X and Alta XI in 2015, prior to the start of the PPAs	(3		)
Increase in gross margin	$	45

Operations and Maintenance Expense

Operations and maintenance expense increased by $3 million during the six months ended June 30, 2016, compared to the same period in 2015, due to:

Increase in Renewables operations and maintenance expense primarily due to component disposals and inventory adjustments for certain wind projects, higher wind generation in the current year, and the acquisition of Spring Canyon in 2015	$	8
Decrease in the Conventional operations and maintenance expense primarily due to extended forced outage at El Segundo in 2015	(4		)
Decrease in Thermal operations and maintenance expense due to lower generation due to milder weather conditions	(1		)
	$	3

Other Costs of Operations

Other costs of operations decreased by $2 million during the six months ended June 30, 2016, compared to the same period in 2015, primarily due to a property tax rebate received in 2016 for the Alta projects.

Equity in Earnings of Unconsolidated Affiliates

Equity in earnings of unconsolidated affiliates increased by $10 million during the six months ended June 30, 2016, compared to the same period in 2015, due primarily to the acquisition of Desert Sunlight, which was acquired on June 29, 2015, as well as increased equity in earnings from DGPV Holdco, RPV Holdco and San Juan Mesa, partially offset by losses from Elkhorn Ridge.

35

Interest Expense

Interest expense increased by $12 million during the six months ended June 30, 2016, compared to the same period in 2015, due to:

(In millions)
Increase from changes in the fair value of Alpine interest rate swaps	$	9
Increase due to issuance of the 2020 Convertible Notes in the second quarter of 2015, amortization of the related discount on the notes and debt issuance costs	8
Increase due to higher revolving credit facility borrowings in 2016	3
Decrease from repricing of project-level financing arrangements and principal repayments in the Conventional segment	(1		)
Decrease for redemption of Alta X and XI project-level debt	(7		)
	$	12

Income Tax Expense

For the six months ended June 30, 2016, the Company recorded income tax expense of $12 million on pretax income of $72 million. For the same period in 2015, the Company did not record any income tax expense on pretax income of $18 million. For the six months ended June 30, 2016 and 2015, the overall effective tax rate was different than the statutory rate of 35% primarily due to taxable earnings allocated to NRG resulting from its interest in NRG Yield LLC and production and investment tax credits generated from certain wind and solar assets, respectively.

Income Attributable to Noncontrolling Interests

For the six months ended June 30, 2016, the Company had income of $52 million attributable to NRG related to its 46.7% economic interest in NRG Yield LLC and its 25% interest in NRG Wind TE Holdco. Additionally, for the six months ended June 30, 2016, the Company had a loss of $29 million attributable to non-controlling interests with respect to its tax equity financing arrangements and the application of the HLBV method. For the six months ended June 30, 2015, the Company had income of $13 million attributable to NRG's 55.3% economic interest in the Company and income of $7 million attributable to non-controlling interests with respect to its tax equity financing arrangements and application of the HLBV method.

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, to service debt and to pay dividends. Historically, the Company's predecessor operations were financed as part of NRG's integrated operations and largely relied on internally generated cash flows as well as corporate and/or project-level borrowings to satisfy its capital expenditure requirements. 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 June 30, 2016, and December 31, 2015, the Company's liquidity was approximately $254 million and $292 million, respectively, comprised of cash, restricted cash, and availability under the Company's revolving credit facility. The Company's liquidity includes $55 million and $48 million of restricted cash balances as of June 30, 2016, and December 31, 2015, respectively. Restricted cash consists primarily of funds to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use. The Company's various financing arrangements are described in Note 7, Long-term Debt. As of June 30, 2016, the Company had $110 million of available borrowings under its 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.

36

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 June 30, 2016:

	S&P	Moody's
NRG Yield, Inc.	BB+	Ba2
5.375% Senior Notes, due 2024	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 Note 7, Long-term Debt, to this Form 10-Q and Note 9, Long-term Debt, to the audited consolidated financial statements included in the Company's 2015 Form 10-K, the Company's financing arrangements consist of the revolving credit facility, the 2019 Convertible Notes, the 2020 Convertible Notes, the Senior Notes and project-level financings for its various assets.

CVSR Holdco Financing Arrangement

On July 15, 2016, CVSR Holdco, the indirect owner of the CVSR project, which is 48.95% owned by the Company, issued $200 million of senior secured notes that bear interest at 4.68% and mature on March 31, 2037.  The Company’s pro-rata share of the borrowings was $97.5 million.  Net proceeds of $97.5 million were distributed to NRG Yield Operating LLC based on its pro-rata ownership.  The proceeds were utilized, along with $28 million of cash on hand, to reduce borrowings under the Company’s revolving credit facility. As of July 31, 2016, $193 million of borrowings were outstanding.

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 Note 7, Long-term Debt; (ii) capital expenditures; (iii) acquisitions and investments; and (iv) cash dividends to investors.

Capital Expenditures

The Company's capital spending program is mainly focused on maintenance capital expenditures, or costs to maintain the assets currently operating, such as costs to replace or refurbish assets during routine maintenance, and growth capital expenditures or construction of new assets and completing the construction of assets where construction is in process. The Company develops annual capital spending plans based on projected requirements for maintenance and growth capital. For the six months ended June 30, 2016, the Company used approximately $11 million to fund capital expenditures, of which $9 million related to maintenance capital expenditures. For the six months ended June 30,2015, the Company used approximately $8 million to fund capital expenditures, of which $6 million related to maintenance capital expenditures.

Acquisitions and Investments

The Company intends to acquire generation 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. 

CVSR— On August 8, 2016, the Company and NRG entered into a definitive agreement regarding the acquisition of the remaining 51.05% interest in the CVSR project for total expected cash consideration of $78.5 million plus assumed debt and working capital adjustments to be calculated at close. The sale is subject to customary closing conditions and is expected to close during the third quarter of 2016. The Company expects to fund the acquisition with drawings under the Company's revolving credit facility.

37

Cash Dividends to Investors

NRG Yield, Inc. 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 it generates 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; 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 other assets. 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.

The following table lists the dividends paid on NRG Yield, Inc.'s Class A common stock and Class C common stock during the six months ended June 30, 2016:

	Second Quarter 2016		First Quarter 2016
Dividends per Class A share	$	0.23	$	0.225
Dividends per Class C share	$	0.23	$	0.225

On July 26, 2016, NRG Yield, Inc. declared quarterly dividends on its Class A common stock and Class C common stock of $0.24 per share payable on September 15, 2016, to stockholders of record as of September 1, 2016.

38

Cash Flow Discussion

The following table reflects the changes in cash flows for the six months ended June 30, 2016, compared to 2015:

	Six months ended June 30,
	2016			2015			Change
	(In millions)
Net cash provided by operating activities	$	198		$	93		$	105
Net cash used in investing activities	(42		)	(839		)	797
Net cash (used in) provided by financing activities	(178		)	624			(802		)

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	$	89
Changes in working capital driven primarily by the timing of wind generation in 2015 compared to 2016	26
Lower distributions from unconsolidated affiliates	(10		)
	$	105

Net Cash Used In Investing Activities

Changes to net cash used in investing activities were driven by:	(In millions)
Payments made to acquire the January 2015 Drop Down Assets	$	489
Decrease in investments in unconsolidated affiliates in 2016 primarily due to the investment in Desert Sunlight made in 2015	283
Payments to acquire businesses in 2015, net of cash acquired	37
Changes in restricted cash due to higher funding for certain projects' debt reserves partially offset by higher project distributions in 2016 compared to 2015	(12		)
	$	797

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 NRG Yield, Inc. Class C common stock offering on June 29, 2015, net of underwriting discounts and commissions	$	(600	)
Lower net borrowings from the revolving credit facility	(255		)
Lower net payments for long-term debt in 2016 compared to 2015	185
Decrease in net contributions from noncontrolling interests	(115		)
Increase in dividends and distributions paid to common stockholders due to the increase in dividend per share in 2016 compared to 2015	(22		)
Debt issuance costs paid in 2015	11
Payment of distributions to NRG due to NRG's 25% ownership of NRG Wind TE Holdco in 2016	(6		)
	$	(802	)

39

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

As of December 31, 2015, the Company has a cumulative federal NOL carry forward balance of $519 million for financial statement purposes, which will begin expiring in 2033. As a result of the Company's tax position, and based on current forecasts, the Company does not anticipate significant income tax payments for federal, state and local jurisdictions in 2016. 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 nine years.

The Company is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state jurisdictions. The Company is not subject to U.S. federal or state income tax examinations for years prior to 2013. 

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 June 30, 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. DGPV Holdco 1, DGPV Holdco 2, RPV Holdco and GenConn 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 $836 million as of June 30, 2016. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to the Company. See also Note 4, Variable Interest Entities, or VIEs.

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 our capital expenditure programs, as disclosed in the Company's 2015 Form 10-K.

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 June 30, 2016, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at June 30, 2016. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Note 5, Fair Value of Financial Instruments.

Derivative Activity (Losses)/Gains	(In millions)
Fair value of contracts as of December 31, 2015	$	(100	)
Contracts realized or otherwise settled during the period	19
Changes in fair value	(77		)
Fair Value of contracts as of June 30, 2016	$	(158	)

40

	Fair Value of contracts as of June 30, 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 2	$	36	$	59	$	35	$	28	$	158

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. In any event, 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 Note 2, Summary of Significant Accounting Policies, to the Company's 2015 Form 10-K. 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.

Recent Accounting Developments

See Note 2, Summary of Significant Accounting Policies, for a discussion of recent accounting developments.

41

ITEM 3 — Quantitative and Qualitative Disclosures About Market Risk

The Company is exposed to several market risks in its normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, liquidity risk, and credit risk.

Commodity Price Risk

Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities, and correlations between various commodities, such as electricity, natural gas and emissions credits. The Company manages the commodity price risk of its merchant generation operations by entering into derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted power sales or purchases of fuel. The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operation and other factors.

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase or decrease in natural gas prices across the term of the derivative contracts would cause a change of approximately $1 million to the net value of derivatives as of June 30, 2016.

Interest Rate Risk

The Company is exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, or collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.

Most of the Company's project subsidiaries enter into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. See Note 9, Long-Term Debt, to the Company's audited consolidated financial statements included in the Company's 2015 Form 10-K for more information about interest rate swaps of the Company's project subsidiaries.

If all of the above swaps had been discontinued on June 30, 2016, the Company would have owed the counterparties $163 million. Based on the investment grade rating of the counterparties, the Company believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.

The Company has long-term debt instruments that subject it to the risk of loss associated with movements in market interest rates. As of June 30, 2016, a 1% change in interest rates would result in an approximately $3 million change in market interest expense on a rolling twelve-month basis.

As of June 30, 2016, the fair value of the Company's debt was $4,772 million and the carrying value was $4,772 million. The Company estimates that a 1% decrease in market interest rates would have increased the fair value of its long-term debt by approximately $311 million.

Liquidity Risk

Liquidity risk arises from the general funding needs of the Company's activities and in the management of the Company's assets and liabilities.

Counterparty Credit Risk

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; and (ii) the use of credit mitigation measures such as prepayment arrangements or volumetric limits. 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.

42

ITEM 4 — Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure ControlsandProcedures

Under the supervision and with the participation of the Company's management, including its principal executive officer, principal financial officer and principal accounting officer, the Company conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act. Based on this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.

Changes in Internal Control over Financial Reporting

There were no changes in the Company’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the second quarter of 2016 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

43

PART II - OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of the material legal proceedings in which the Company was involved through June 30, 2016, see Note 12, Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

Information regarding risk factors appears in Part I, Item 1A, Risk Factors, in the Company's 2015 Form 10-K. There have been no material changes in the Company's risk factors since those reported in its 2015 Form 10-K.

ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 — OTHER INFORMATION

None.

44

ITEM 6 — EXHIBITS

Number	Description	Method of Filing
2.1	Purchase and Sale Agreement, dated as of August 8, 2016, between NRG Solar CVSR Holdings 2 LLC and NRG Yield Operating LLC.	Incorporated herein by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K, filed on August 9, 2016.
3.1	Certificate of Amendment to Second Amended and Restated Certificate of Incorporation of NRG Yield, Inc., dated as of May 2, 2016.	Incorporated herein by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K, filed on May 2, 2016.
3.2	Restated Certificate of Incorporation of NRG Yield, Inc., dated as of May 2, 2016.	Incorporated herein by reference to Exhibit 3.1 to the Registrant's Quarterly Report on Form 10-Q, filed on May 5, 2016.
10.1	Amendment No. 2 to Amended and Restated Limited Liability Company Agreement of NRG RPV Holdco 1 LLC, dated as of August 5, 2016, by and between NRG Yield RPV Holding LLC and NRG Residential Solar Solutions LLC.	Filed herewith.
10.2	Employment Agreement, dated as of May 6, 2016, between NRG Yield, Inc. and Christopher S. Sotos.	Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K/A, filed on August 9, 2016.
31.1	Rule 13a-14(a)/15d-14(a) certification of Christopher S. Sotos.	Filed herewith.
31.2	Rule 13a-14(a)/15d-14(a) certification of Kirkland B. Andrews.	Filed herewith.
31.3	Rule 13a-14(a)/15d-14(a) certification of David Callen.	Filed herewith.
32	Section 1350 Certification.	Furnished herewith.
101 INS	XBRL Instance Document.	Filed herewith.
101 SCH	XBRL Taxonomy Extension Schema.	Filed herewith.
101 CAL	XBRL Taxonomy Extension Calculation Linkbase.	Filed herewith.
101 DEF	XBRL Taxonomy Extension Definition Linkbase.	Filed herewith.
101 LAB	XBRL Taxonomy Extension Label Linkbase.	Filed herewith.
101 PRE	XBRL Taxonomy Extension Presentation Linkbase.	Filed herewith.

45

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 thereunto duly authorized.

	NRG YIELD, INC. (Registrant)
	/s/ CHRISTOPHER S. SOTOS
	Christopher S. Sotos
	Chief Executive Officer (Principal Executive Officer)
	/s/ KIRKLAND B. ANDREWS
	Kirkland B. Andrews
	Chief Financial Officer (Principal Financial Officer)
	/s/ DAVID CALLEN
	David Callen
Date: August 9, 2016	Chief Accounting Officer (Principal Accounting Officer)

46

EX-10.1

Exhibit 10.1

NRG RPV HOLDCO 1 LLC

AMENDMENT NO. 2 TO AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT

THIS AMENDMENT NO. 2 TO AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT, dated as of August 5, 2016 (this “Amendment”), is made and entered into by and between NRG YIELD RPV HOLDING LLC, a Delaware limited liability company (“NRG Yield RPV”), as a Class A Member, and NRG RESIDENTIAL SOLAR SOLUTIONS LLC, a Delaware limited liability company (“NRG RSS”), as a Class B Member.

RECITALS

A.    NRG Yield RPV and NRG RSS are the owners of 100% of the Class A Interests and Class B Interests, respectively, of NRG RPV HOLDCO 1 LLC, a Delaware limited liability company (the “Company”), and are Members of the Company pursuant to that certain Amended and Restated Limited Liability Company Agreement, dated April 9, 2015, as amended by that certain Amendment No. 1 to the Amended and Restated Limited Liability Company Agreement dated March 1, 2016 (collectively, the “A&R LLC Agreement”). Capitalized terms used but not otherwise defined in this Amendment shall have the respective meanings specified in the A&R LLC Agreement.

B.    The Members have agreed to amend the A&R LLC Agreement in accordance with Section 13.7 thereof to set forth certain agreements between the Members as set forth below.

NOW, THEREFORE, in consideration of the premises and the mutual undertakings contained herein, the parties hereto hereby agree, as follows:

1.Amendment to Section 1.1. The definition of “Class A Member Capital Contribution Commitment” is hereby amended by deleting the amount “$100,000,000” and replacing it with “$60,000,000”.

2.Effect of Amendment. Except as amended by this Amendment, the A&R LLC Agreement remains in full force and effect. All references to the A&R LLC Agreement in any other agreement or document shall hereinafter be deemed to refer to the A&R LLC Agreement as amended by this Amendment.

3.Miscellaneous. The provisions set forth in Sections 13.3,13.4 and 13.10 of the A&R LLC Agreement shall be applicable to this Amendment mutatis mutandis and to the full extent necessary shall be deemed to be incorporated herein.

[Signature Pages Follow.]

IN WITNESS WHEREOF, the Parties hereto have executed this Amendment as of the date first written above.

CLASS B MEMBER:

NRG RESIDENTITAL SOLAR SOLUTIONS LLC

By: /s/ Elizabeth Killinger

Name: Elizabeth Killinger

Title: President

[Signature page to Amendment No. 2 to A&R LLC Agreement of NRG RPV Holdco 1 LLC]

CLASS A MEMBER:

NRG YIELD RPV HOLDING LLC

By: /s/ Chad Plotkin

Name: Chad Plotkin

Title: SVP, Finance

[Signature page to Amendment No. 2 to A&R LLC Agreement of NRG RPV Holdco 1 LLC]

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Christopher S. Sotos, certify that:

1. I have reviewed this quarterly report on Form 10-Q of NRG Yield, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ CHRISTOPHER S. SOTOS

Christopher S. Sotos

Chief Executive Officer

(Principal Executive Officer)

Date: August 9, 2016

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Kirkland B. Andrews, certify that:

1. I have reviewed this quarterly report on Form 10-Q of NRG Yield, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ KIRKLAND B. ANDREWS

Kirkland B. Andrews

Chief Financial Officer

(Principal Financial Officer)

Date: August 9, 2016

EX-31.3

EXHIBIT 31.3

CERTIFICATION

I, David Callen, certify that:

1. I have reviewed this quarterly report on Form 10-Q of NRG Yield, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ DAVID CALLEN

David Callen

Chief Accounting Officer

(Principal Accounting Officer)

Date: August 9, 2016

EX-32

EXHIBIT 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of NRG Yield, Inc. on Form 10-Q for the quarter ended June 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer's knowledge:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Form 10-Q.

Date: August 9, 2016

/s/ CHRISTOPHER S. SOTOS

Christopher S. Sotos

Chief Executive Officer

(Principal Executive Officer)

/s/ KIRKLAND B. ANDREWS

Kirkland B. Andrews

Chief Financial Officer

(Principal Financial Officer)

/s/ DAVID CALLEN

David Callen

Chief Accounting Officer

(Principal Accounting Officer) 

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of this Form 10-Q or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NRG Yield, Inc. and will be retained by NRG Yield, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 31, 2016
Document And Entity Information [Abstract]
Entity Registrant Name	NRG Yield, Inc.
Entity Central Index Key	0001567683
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Common Class A [Member]
Class of Stock
Entity Common Stock, Shares Outstanding		34,586,250
Common Class B [Member]
Class of Stock
Entity Common Stock, Shares Outstanding		42,738,750
Common Class C [Member]
Class of Stock
Entity Common Stock, Shares Outstanding		62,784,250
Common Class D [Member]
Class of Stock
Entity Common Stock, Shares Outstanding		42,738,750

XML

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions		3 Months Ended				6 Months Ended
		Jun. 30, 2016		Jun. 30, 2015		Jun. 30, 2016	Jun. 30, 2015
Operating Revenues
Total operating revenues		$ 258		$ 235	[1],[2]	$ 478	$ 435	[1],[2]
Operating Costs and Expenses
Cost of operations		75		75	[1]	158	159	[1]
Depreciation and amortization		67		70	[1],[2]	133	137	[1],[2],[3]
General and administrative		3		3	[1],[2]	6	6	[1],[2]
Acquisition-related transaction and integration costs		0		1	[1],[2]	0	1	[1],[2]
Total operating costs and expenses		145		149	[1]	297	303	[1]
Operating Income		113		86	[1],[2]	181	132	[1],[2]
Other Income (Expense)
Equity in earnings of unconsolidated affiliates		18		8	[1],[2]	20	10	[1],[2]
Other income, net		1		0	[1]	1	1	[1],[2]
Loss on debt extinguishment		0		(7)	[1],[2]	0	(7)	[1],[2],[3]
Interest expense		(62)		(45)	[1],[2]	(130)	(118)	[1],[2]
Total other expense, net		(43)		(44)	[1]	(109)	(114)	[1]
Income Before Income Taxes		70		42	[1],[2]	72	18	[1],[2]
Income tax expense		12		4	[2]	12	0
Net Income		58		38	[1],[2],[4]	60	18	[1],[2],[4]
Less: Pre-acquisition net loss of Drop Down Assets		0		(3)	[4]	0	(7)	[1],[4]
Net Income Excluding Pre-acquisition Net Loss of Drop Down Assets		58		41	[1]	60	25	[1]
Less: Net income attributable to noncontrolling interests		26		31	[1]	23	20	[1]
Net Income Attributable to NRG Yield, Inc.		$ 32		10		37	5
Earnings Per Share Attributable to NRG Yield, Inc. Class A and Class C Common Stockholders
Dividends Per Common Share, Cash Paid		$ 0.23
Common Class C [Member]
Other Income (Expense)
Net Income Attributable to NRG Yield, Inc.	[5]	$ 21		$ 5		$ 24	$ 3
Earnings Per Share Attributable to NRG Yield, Inc. Class A and Class C Common Stockholders
Weighted average number of common shares outstanding - basic	[5]	63		35		63	35
Weighted average number of common shares outstanding - diluted		73	[5]	35	[5]	63	35
Earnings per Weighted Average Class A and Class C Common Share - Basic	[5]	$ 0.33		$ 0.15		$ 0.38	$ 0.07
Earnings per Weighted Average Class A and Class C Common Share - Basic	[5]	0.31		0.15		0.38	0.07
Dividends Per Common Share, Cash Paid		$ 0.23		$ 0.20		$ 0.455	$ 0.20
Common Class A [Member]
Other Income (Expense)
Net Income Attributable to NRG Yield, Inc.	[5]	$ 11		$ 5		$ 13	$ 3
Earnings Per Share Attributable to NRG Yield, Inc. Class A and Class C Common Stockholders
Weighted average number of common shares outstanding - basic	[5]	35		35		35	35
Weighted average number of common shares outstanding - diluted		49	[5]	35	[5]	35	35
Earnings per Weighted Average Class A and Class C Common Share - Basic	[5]	$ 0.33		$ 0.15		$ 0.38	$ 0.07
Earnings per Weighted Average Class A and Class C Common Share - Basic		0.29	[5]	0.15	[5]	0.38	0.07	[5]
Dividends Per Common Share, Cash Paid		$ 0.23		$ 0.20		$ 0.455	$ 0.59

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

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

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

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

[5] (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.

XML

Consolidated Statements of Comprehensive Loss - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015		Jun. 30, 2016	Jun. 30, 2015
Net Income	$ 58	$ 38	[1],[2],[3]	$ 60	$ 18	[1],[2],[3]
Other Comprehensive (Loss) Income, net of tax
Unrealized (loss) gain on derivatives, net of income tax benefit (expense) of $4, ($4), $13 and $4	(16)	23		(57)	3
Other comprehensive (loss) income	(16)	23	[3]	(57)	3	[3]
Comprehensive Income	42	61	[3]	3	21	[3]
Less: Pre-acquisition net loss of Drop Down Assets	0	(3)	[3]	0	(7)	[1],[3]
Less: Comprehensive income (loss) attributable to noncontrolling interests	13	48		(14)	30
Comprehensive Income (Loss) Attributable to NRG Yield, Inc.	$ 29	$ 16		$ 17	$ (2)

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

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

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

XML

Consolidated Statements of Comprehensive Loss (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Unrealized gain/loss on derivatives, income tax expense /(benefit)	$ (3)	$ 4	$ (12)	$ (4)

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 89	$ 111
Restricted cash	55	48
Accounts receivable — trade	109	95
Accounts receivable — affiliate	1	0
Inventory	35	35
Derivative instruments	1	0
Notes receivable	7	7
Prepayments and other current assets	22	22
Total current assets	319	318
Property, plant and equipment, net	4,947	5,056
Other Assets
Equity investments in affiliates	778	798
Notes receivable	6	10
Intangible assets, net of accumulated amortization of $132 and $93	1,321	1,362
Deferred income taxes	170	170
Other non-current assets	66	61
Total other assets	2,341	2,401
Total Assets	7,607	7,775
Current Liabilities
Current portion of long-term debt	251	241
Accounts payable — trade	21	23
Accounts payable — affiliate	32	85
Derivative instruments	37	39
Accrued expenses and other current liabilities	39	68
Total current liabilities	380	456
Other Liabilities
Long-term debt	4,465	4,562
Accounts payable — affiliate	20	0
Derivative instruments	122	61
Other non-current liabilities	63	64
Total non-current liabilities	4,670	4,687
Total Liabilities	5,050	5,143
Stockholders' Equity
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued	0	0
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 March 31, 2016, and December 31, 2015	1	1
Additional paid-in capital	1,835	1,855
Retained earnings	26	12
Accumulated other comprehensive loss	(47)	(27)
Noncontrolling interest	742	791
Total Stockholders' Equity	2,557	2,632
Total Liabilities and Stockholders' Equity	$ 7,607	$ 7,775

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Intangible assets, net of accumulated amortization of $132 and $93	$ 132	$ 93
Less accumulated depreciation	$ 832	$ 701
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	$ 0.01
Common Stock, Shares Authorized	500,000,000	500,000,000
Common Stock, Shares, Issued	34,586,250	34,586,250
Preferred Stock [Member]
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Class B [Member]
Common Stock, Shares Authorized	500,000,000	500,000,000
Common Stock, Shares, Issued	42,738,750	42,738,750
Common Class C [Member]
Common Stock, Shares Authorized	500,000,000	500,000,000
Common Stock, Shares, Issued	62,784,250	34,586,250
Common Class D [Member]
Common Stock, Shares Authorized	500,000,000	500,000,000
Common Stock, Shares, Issued	42,738,750	42,738,750

XML

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Statement of Cash Flows [Abstract]
Return on investment from unconsolidated affiliates	$ 29	$ 15
Cash Flows from Operating Activities
Net income	60	18	[1],[2],[3]
Adjustments to reconcile net income to net cash provided by operating activities:
Income (Loss) from Equity Method Investments	(20)	(10)	[1],[2]
Distributions from unconsolidated affiliates	22	32	[4]
Depreciation and amortization	133	137	[1],[2],[4]
Amortization of financing costs and debt discounts	10	6	[4]
Amortization of Intangibles and Out of Market Contracts	40	26	[4]
Adjustment for debt extinguishment	0	(7)	[1],[2],[4]
Changes in deferred income taxes	12	0	[4]
Changes in derivative instruments	(2)	(37)	[4]
Disposal of asset components and ARO accretion	4	2
Changes in Prepaid and Accrued Capacity Payments	(65)	(66)
Changes in other working capital	4	(22)	[4]
Net Cash Provided by Operating Activities	198	93	[4]
Cash Flows from Investing Activities
Payments to Acquire Businesses, Net of Cash Acquired	0	37	[4]
Acquisition of Drop Down Assets, net of cash acquired	0	489	[4]
Capital expenditures	(11)	(8)	[4]
(Increase) decrease in restricted cash	(7)	5	[4]
Increase (Decrease) in Notes Receivables	4	3	[4]
Investments in unconsolidated affiliates	(59)	(328)	[4]
Other	2	0	[4]
Net Cash Used in Investing Activities	(42)	(839)	[4]
Cash Flows from Financing Activities
Net contributions from noncontrolling interests	8	123	[4]
Distributions to NRG for NRG Wind TE Holdco	(6)	0	[4]
Proceeds from the issuance of common stock	0	600	[4]
Payment of dividends and distributions to shareholders	(83)	(61)	[4]
Payment of debt issuance costs	0	11	[4]
Net borrowings from the revolving credit facility	12	267
Net payments of long-term debt	(109)	(294)
Net Cash (Used in) Provided by Financing Activities	(178)	624	[4]
Net Decrease in Cash and Cash Equivalents	(22)	(122)	[4]
Cash and Cash Equivalents at Beginning of Period	111	429	[4]
Cash and Cash Equivalents at End of Period	$ 89	$ 307	[4]

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

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

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

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

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Nature of Business

6 Months Ended

Jun. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Business

Nature of Business

NRG Yield, Inc., together with its consolidated subsidiaries, or the Company, is a dividend growth-oriented company formed by NRG as a Delaware corporation on December 20, 2012, to serve as the primary vehicle through which NRG owns, operates and acquires contracted renewable and conventional generation and thermal infrastructure assets. NRG Yield, Inc. owns 100% of the Class A units and Class C units of NRG Yield LLC, including a controlling interest through its position as managing member. NRG Yield LLC, through its wholly owned subsidiary, NRG Yield Operating LLC, is the holder of a portfolio of renewable and conventional generation and thermal infrastructure assets, primarily located in the Northeast, Southwest and California regions of the U.S.

NRG Yield, Inc. consolidates the results of NRG Yield LLC through its controlling interest, with NRG's interest shown as noncontrolling interest in the financial statements. On May 14, 2015, NRG Yield, Inc. completed a stock split whereby 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. In addition, on June 29, 2015, NRG Yield, Inc. completed the issuance of 28,198,000 shares of Class C common stock for net proceeds of $599 million. The holders of NRG Yield, Inc.'s outstanding shares of Class A and Class C common stock are entitled to dividends as declared. NRG receives its distributions from NRG Yield LLC through its ownership of NRG Yield LLC Class B and Class D units.

The following table represents the structure of the Company as of June 30, 2016:

As of June 30, 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
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	48.95	%	122	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
			482
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	74.3	%	16	Corn Belt Power Cooperative	2027
Elbow Creek	75	%	92	NRG Power Marketing LLC	2022
Elkhorn Ridge	50.3	%	41	Nebraska Public Power District	2029
Forward	75	%	22	Constellation NewEnergy, Inc.	2017
Goat Wind	74.9	%	113	Dow Pipeline Company	2025
Hardin	74.3	%	11	Interstate Power and Light Company	2027
Laredo Ridge	100	%	80	Nebraska Public Power District	2031
Lookout	75	%	29	Southern Maryland Electric Cooperative	2030
Odin	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	56.3	%	68	Southwestern Public Service Company	2025
Sleeping Bear	75	%	71	Public Service Company of Oklahoma	2032
South Trent	100	%	101	AEP Energy Partners	2029
Spanish Fork	75	%	14	PacifiCorp	2028
Spring Canyon II (b)	90.1	%	29	Platte River Power Authority	2039
Spring Canyon III (b)	90.1	%	25	Platte River Power Authority	2039
Taloga	100	%	130	Oklahoma Gas & Electric	2031
Wildorado	74.9	%	121	Southwestern Public Service Company	2027
			1,999

Projects	Percentage Ownership		Net Capacity (MW)(a)	Offtake Counterparty	Expiration
Thermal
Thermal equivalent MWt (c)	100	%	1,315	Various	Various
NRG Dover Energy Center LLC	100	%	103	NRG Power Marketing LLC	2018
Thermal generation	100	%	20	Various	Various
Total net capacity (excluding equivalent MWt)(d)			4,558

^(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 June 30, 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) Total net capacity excludes 55 MW for RPV Holdco and 45 MW for DGPV Holdco 1 and DGPV Holdco 2, which are consolidated by NRG, as further described in Note 4, Variable Interest Entities, or VIEs.

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 11, 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, with the equity associated with the Class B and Class D common stockholder, NRG, and the third-party interests under certain tax equity arrangements classified as noncontrolling interest.

As described in Note 3, Business Acquisitions, 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, from NRG for 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. Additionally, 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, including $9 million for working capital. The acquisitions of the November 2015 Drop Down Assets and the January 2015 Drop Down Assets, or collectively, the Drop Down Assets, were accounted for as transfers 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 since the inception of common control. Accordingly, 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), which was April 1, 2014 for the January Drop Down Assets and the majority of the November 2015 Drop Down Assets. The recast did not affect net income attributable to NRG Yield, Inc., weighted average number of shares outstanding, earnings per share or dividends. With respect to the November 2015 Drop Down Assets, the Company has recorded all minority interests in NRG Wind TE Holdco as noncontrolling interest in the Consolidated Financial Statements for all periods presented.

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with the SEC’s regulations for interim financial information. Accordingly, they do not include all of the information and notes required by GAAP for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the Company’s audited consolidated financial statements for the year ended December 31, 2015. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of June 30, 2016, and the results of operations, comprehensive income and cash flows for the six months ended June 30, 2016, and 2015.

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

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.

Noncontrolling Interests

The following table reflects the changes in the Company's noncontrolling interest balance:

	(In millions)
Balance as of December 31, 2015	$	791
Capital contributions from tax equity investors, net of distributions	8
November 2015 Drop Down Assets working capital payment	2
Comprehensive loss	(14		)
Distributions to NRG	(45		)
Balance as of June 30, 2016	$	742

Distributions to NRG

The following table lists the distributions paid on NRG Yield LLC's Class B and D units during the six months ended June 30, 2016:

	Second Quarter 2016		First Quarter 2016
Distributions per Class B Unit	$	0.23	$	0.225
Distributions per Class D Unit	$	0.23	$	0.225

On July 26, 2016, NRG Yield LLC declared a distribution on its units of $0.24 per unit payable on September 15, 2016 to unit holders of record as of September 1, 2016. The portion of the distributions paid by NRG Yield LLC to NRG is recorded as a reduction to the Company's noncontrolling interest balance.

Additionally, the Company paid $6 million to NRG relating to its noncontrolling interest in NRG Wind TE Holdco for the six months ended June 30, 2016.

Recent Accounting Developments

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 guidance in ASU No. 2016-07 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. The adoption of ASU No. 2016-07 is required to be applied prospectively and early adoption is permitted. 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 February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or ASU No. 2016-02. The amendments of ASU No. 2016-02 complete the joint effort between the FASB and the International Accounting Standards Board, or IASB, to develop a common leasing standard for GAAP and International Financial Reporting Standards, or IFRS, 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. The guidance in ASU No. 2016-02 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, ASU No. 2016-02 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The guidance in ASU No. 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those annual periods. The adoption of ASU No. 2016-02 is required to be applied using a modified retrospective approach for the earliest period presented and early adoption is permitted. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.

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 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 this standard on January 1, 2016, and the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.

ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU No. 2014-09.  The amendments of ASU No. 2014-09 complete the joint effort between the FASB and the International Accounting Standards Board, or IASB, to develop a common revenue standard for GAAP and International Financial Reporting Standards, or IFRS, and to improve financial reporting.  The guidance in ASU No. 2014-09 provides that an entity should recognize revenue to depict the transfer of goods or services 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 the following steps to be applied by an entity: (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies the performance obligation.  In August 2015, the FASB issued ASU 2015-14, which formally deferred the effective date by one year to make the guidance of ASU No. 2014-09 effective for annual reporting periods beginning after December 15, 2017, including interim periods therein.  Early adoption is permitted, but not prior to the original effective date, which was for annual reporting periods beginning after December 15, 2016.

In addition to ASU No. 2014-09, the FASB has issued additional guidance which provides further clarification on Topic 606. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606), or ASU No. 2016-08. The amendments of ASU No. 2016-08 clarify how to apply the implementation guidance on principal versus agent considerations related to the sale of goods or services to a customer as updated by ASU No. 2014-09. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606), or ASU No. 2016-10. The amendments of ASU No. 2016-10 provide further clarification on contract revenue recognition as updated by ASU No. 2014-09, specifically related to the identification of separately identifiable performance obligations and the implementation of licensing contracts. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606), or ASU No. 2016-12. The amendments of ASU No. 2016-12 provide further clarification on contract revenue recognition as updated by ASU No. 2014-09, specifically related to collectability, the presentation of tax collected from customers, and non-cash consideration, as well as offering practical expedients. The Company is working through an adoption plan which includes the evaluation of revenue contracts compared to the new standard and evaluating the impact of Topic 606 on the Company's results of operations, cash flows and financial position.

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Business Acquisitions

6 Months Ended

Jun. 30, 2016

Business Combinations [Abstract]

Business Acquisition

Business Acquisitions

2016 Acquisitions

CVSR — On August 8, 2016, the Company and NRG entered into a definitive agreement regarding the acquisition of the remaining 51.05% interest in the CVSR project for total expected cash consideration of $78.5 million plus assumed debt and working capital adjustments to be calculated at close. The sale is subject to customary closing conditions and is expected to close during the third quarter of 2016. The Company expects to fund the acquisition with drawings under the Company's revolving credit facility.

The acquisition will be accounted for as 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 since the inception of common control. Accordingly, the Company will prepare its consolidated financial statements to reflect the transfer as if it 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), which would be January 1, 2015. The recast would not affect net income attributable to NRG Yield, Inc., weighted average number of shares outstanding, earnings per share or dividends.

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.

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 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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Variable Interest Entities

6 Months Ended

Jun. 30, 2016

Equity Method Investments and Joint Ventures [Abstract]

Investments Accounted for by the Equity Method and Variable Interest Entities

Variable Interest Entities, or VIEs

Entities that are Consolidated

The Company has a controlling financial interest in certain entities which have been identified as VIEs under ASC 810, Consolidations, or ASC 810. These arrangements are primarily related to tax equity arrangements entered into with third parties in order to monetize certain tax credits associated with wind facilities, as further described in Note 5,Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's audited consolidated financial statements included in the 2015 Form 10-K.

Summarized financial information for the Company's consolidated VIEs consisted of the following as of June 30, 2016:

(In millions)	NRG Wind TE Holdco		Alta Wind TE Holdco		Spring Canyon
Other current and non-current assets	$	190	$	27	$	4
Property, plant and equipment	638		472		102
Intangible assets	2		281		—
Total assets	830		780		106
Current and non-current liabilities	215		8		6
Total liabilities	215		8		6
Noncontrolling interest	235		121		70
Net assets less noncontrolling interests	$	380	$	651	$	30

Entities that are not Consolidated

The Company has interests in entities that are considered VIEs under ASC 810, 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, as further described in Note 5,Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's audited consolidated financial statements included in the 2015 Form 10-K.

NRG DGPV Holdco 1 LLC — The Company and NRG, maintain a partnership, 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 20 years; and (ii) a tax equity-financed portfolio of approximately 12 commercial photovoltaic systems representing approximately 37 MW with a weighted average remaining PPA term of 19 years. Both 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 and other ancillary related assets from NRG Renew LLC or its subsidiaries, via intermediate funds.  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 $78 million on a combined basis as of June 30, 2016.

NRG RPV Holdco 1 LLC — The Company and NRG Residential Solar Solutions LLC, a subsidiary of NRG, maintain a partnership, NRG RPV Holdco 1 LLC, or RPV Holdco, that holds operating portfolios of residential solar assets developed by NRG Home Solar, a subsidiary of NRG, including: (i) an existing, unlevered portfolio of over 2,200 leases across nine states representing approximately 17 MW with a weighted average remaining lease term of approximately 17 years; and (ii) a tax equity-financed portfolio of approximately 5,500 leases representing approximately 38 MW, with an average lease term for the existing and new leases of approximately 17 to 20 years. Under this partnership, the Company had previously committed to fund up to $150 million of capital, which was reduced to $100 million in February 2016.

The Company's maximum exposure to loss is limited to its equity investment, which was $67 million as of June 30, 2016.

On August 5, 2016, the Company and NRG amended the RPV Holdco partnership to further reduce the aggregate commitment of $100 million to $60 million in connection with NRG’s change in business model approach in the residential solar business.

GenConn Energy LLC — The Company has a 50% interest in GCE Holding LLC, the owner of GenConn, which owns and operates two190 MW peaking generation facilities in Connecticut at the Devon and Middletown sites. As of June 30, 2016, the Company's investment in GenConn was $108 million and its maximum exposure to loss is limited to its equity investment.

The following table presents summarized financial information for GCE Holding LLC:

	Three months ended June 30,				Six months ended June 30,
(In millions)	2016		2015		2016		2015
Income Statement Data:
Operating revenues	$	18	$	18	$	36	$	40
Operating income	10		11		19		20
Net income	$	6	$	8	$	13	$	14

	June 30, 2016		December 31, 2015
Balance Sheet Data:	(In millions)
Current assets	$	34	$	36
Non-current assets	408		416
Current liabilities	14		16
Non-current liabilities	$	211	$	215

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Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities [Table Text Block]

The Company records its derivative assets and liabilities at fair value on its consolidated balance sheet. There were no derivative asset positions on the Company's consolidated balance sheet 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 June 30, 2016		As of December 31, 2015
	Fair Value (a)		Fair Value (a)
(In millions)	Level 2		Level 2
Derivative assets:
Commodity contracts	$	1	$	—
Total assets	1		—
Derivative liabilities:
Commodity contracts	—		2
Interest rate contracts	159		98
Total liabilities	$	159	$	100

^(a) There were no assets or liabilities classified as Level 1 or Level 3 as of June 30, 2016, and December 31, 2015.

Fair Value of Financial Instruments

Fair Value of Financial Instruments

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.

For cash and cash equivalents, restricted cash, accounts receivable, accounts receivable — affiliate, accounts payable, accounts payable — affiliate, accrued expenses and other liabilities, the carrying amounts approximate 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 June 30, 2016				As of December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(In millions)
Assets:
Notes receivable, including current portion	$	13	$	13	$	17	$	17
Liabilities:
Long-term debt, including current portion	$	4,772	$	4,772	$	4,863	$	4,745

The fair value of notes receivable and long-term debt are based on expected future cash flows discounted at market interest rates, or current interest rates for similar instruments, and are classified as Level 3 within the fair value hierarchy.

Recurring Fair Value Measurements

The Company records its derivative assets and liabilities at fair value on its consolidated balance sheet. There were no derivative asset positions on the Company's consolidated balance sheet 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 June 30, 2016		As of December 31, 2015
	Fair Value (a)		Fair Value (a)
(In millions)	Level 2		Level 2
Derivative assets:
Commodity contracts	$	1	$	—
Total assets	1		—
Derivative liabilities:
Commodity contracts	—		2
Interest rate contracts	159		98
Total liabilities	$	159	$	100

^(a) There were no assets or liabilities classified as Level 1 or Level 3 as of June 30, 2016, and December 31, 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 is, for interest rate swaps, calculated based on credit default swaps using the bilateral method. For commodities, to the extent that the net exposure under a specific master agreement is an asset, the Company uses the counterparty’s default swap rate. If the net 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 June 30, 2016, the credit reserve resulted in a $5 million increase in fair value, which was composed of a $4 million gain in OCI and $1 million gain in interest expense. It is possible that future market prices could vary from those used in recording assets and liabilities and such variations could be material.

Concentration of Credit Risk

In addition to the credit risk discussion in Note 2, Summary of Significant Accounting Policies, to the Company's audited consolidated financial statements included in the Company's 2015 Form 10-K, the following 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 June 30, 2016, credit risk exposure to these counterparties attributable to the Company's ownership interests was approximately $2.5 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, as further described in Note 12, Segment Reporting, to the Company's audited consolidated financial statements included in the Company's 2015 Form 10-K. 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

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Accounting for Derivative Instruments and Hedging Activities

Accounting for Derivative Instruments and Hedging Activities

This footnote should be read in conjunction with the complete description under Note 7, Accounting for Derivative Instruments and Hedging Activities,to the Company's audited consolidated financial statements included in the Company's 2015 Form 10-K.

Energy-Related Commodities

As of June 30, 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. At June 30, 2016, these contracts were not designated as cash flow or fair value hedges.

Interest Rate Swaps

As of June 30, 2016, the Company had interest rate derivative instruments on non-recourse debt extending through 2031, 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 June 30, 2016, and December 31, 2015.

		Total Volume
		June 30, 2016		December 31, 2015
Commodity	Units	(In millions)
Natural Gas	MMBtu	4		4
Interest	Dollars	$	1,932	$	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
	June 30, 2016		June 30, 2016		December 31, 2015
	(In millions)
Derivatives Designated as Cash Flow Hedges:
Interest rate contracts current	$	—	$	34	$	34
Interest rate contracts long-term	—		108		56
Total Derivatives Designated as Cash Flow Hedges	—		142		90
Derivatives Not Designated as Cash Flow Hedges:
Interest rate contracts current	—		3		3
Interest rate contracts long-term	—		14		5
Commodity contracts current	1		—		2
Total Derivatives Not Designated as Cash Flow Hedges	1		17		10
Total Derivatives	$	1	$	159	$	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 June 30, 2016, and December 31, 2015, there were no offsetting amounts at the counterparty master agreement level or outstanding collateral paid or received.

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:

	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In millions)
Accumulated OCL beginning balance	$	(110	)	$	(81	)	$	(69	)	$	(61	)
Reclassified from accumulated OCL to income due to realization of previously deferred amounts	3			4			6			7
Mark-to-market of cash flow hedge accounting contracts	(19		)	19			(63		)	(4		)
Accumulated OCL ending balance, net of income tax benefit of $28 and $10, respectively	$	(126	)	$	(58	)	$	(126	)	$	(58	)
Accumulated OCL attributable to noncontrolling interests	(79		)	(42		)	(79		)	(42		)
Accumulated OCL attributable to NRG Yield, Inc.	$	(47	)	$	(16	)	$	(47	)	$	(16	)
Losses expected to be realized from OCL during the next 12 months, net of income tax benefit of $4	$	18					$	18

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 six months ended June 30, 2016, and 2015.

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 three months ended June 30, 2016, and 2015, the impact to the consolidated statements of income was a loss of $2 million and a gain of $31 million, respectively. For the six months ended June 30, 2016, and 2015, the impact to the consolidated statements of income was a loss of $9 million and a gain of $19 million, respectively.

A portion of the Company’s derivative commodity contracts relates to its Thermal Business for the purchase of fuel commodities based on the forecasted usage of the thermal district energy centers. Realized gains and losses on these contracts are reflected in the fuel 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.

Commodity contracts also hedged the forecasted sale of power for Elbow Creek, Alta X and Alta XI in 2015 until the start of the PPAs. The effect of these commodity hedges was recorded to operating revenues. For the three and six months ended June 30, 2015, the impact to the consolidated statements of income was an unrealized loss of $4 million and an unrealized gain of $3 million, respectively.

See Note 5, Fair Value of Financial Instruments, for a discussion regarding concentration of credit risk.

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Long-term Debt

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Long-term Debt

Long-term Debt

This footnote should be read in conjunction with the complete description under Note 9, Long-term Debt, to the Company's audited consolidated financial statements included in the 2015 Form 10-K. Long-term debt consisted of the following:

	June 30, 2016		December 31, 2015		June 30, 2016, interest rate % (a)	Letters of Credit Outstanding at June 30, 2016
	(In millions, except rates)
2019 Convertible Notes (b)	$	333	$	330	3.500
2020 Convertible Notes (c)	268		266		3.250
Senior Notes, due 2024	500		500		5.375
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 (d)	318		306		L+2.75	$	67
Project-level debt:
Alpine, due 2022	151		154		L+1.75	37
Alta Wind I, lease financing arrangement, due 2034	245		252		7.015	16
Alta Wind II, lease financing arrangement, due 2034	194		198		5.696	23
Alta Wind III, lease financing arrangement, due 2034	201		206		6.067	24
Alta Wind IV, lease financing arrangement, due 2034	130		133		5.938	16
Alta Wind V, lease financing arrangement, due 2035	208		213		6.071	27
Alta Realty Investments, due 2031	32		33		7.000	—
Alta Wind Asset Management, due 2031	18		19		L+2.375	—
Avra Valley, due 2031	58		60		L+1.75	3
Blythe, due 2028	21		21		L+1.625	6
Borrego, due 2025 and 2038	71		72		L+ 2.50/5.65	5
El Segundo Energy Center, due 2023	457		485		L+1.625 - L+2.25	82
Energy Center Minneapolis, due 2017 and 2025	100		108		5.95 -7.25	—
Kansas South, due 2031	31		33		L+2.00	4
Laredo Ridge, due 2028	102		104		L+1.875	10
Marsh Landing, due 2017 and 2023	410		418		L+1.75 - L+1.875	45
PFMG and related subsidiaries financing agreement, due 2030	29		29		6.000	—
Roadrunner, due 2031	38		40		L+1.625	5
South Trent Wind, due 2020	59		62		L+1.625	10
TA High Desert, due 2020 and 2032	51		52		L+2.50/5.15	8
Tapestry, due 2021	176		181		L+1.625	20
Viento, due 2023	183		189		L+2.75	27
Walnut Creek, due 2023	341		351		L+1.625	60
WCEP Holdings, due 2023	46		46		L+3.00	—
Other	1		2		various	—
Subtotal project-level debt:	3,353		3,461
Total debt	4,772		4,863
Less current maturities	251		241
Less deferred financing costs	56		60
Total long-term debt	$	4,465	$	4,562

^(a) As of June 30, 2016, L+ equals 3 month LIBOR plus x%, except for the Marsh Landing term loan, Walnut Creek term loan, and NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, where L+ equals 1 month LIBOR plus x% and Kansas South, where L+ equals 6 month LIBOR plus x%.

^(b) Net of discount of $12 million and $15 million as of June 30, 2016, and December 31, 2015, respectively.

^(c) Net of discount of $19 million and $21 million as of June 30, 2016, and December 31, 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 respective arrangement. As of June 30, 2016, the Company was in compliance with all of the required covenants.

The discussion below describes material changes to or additions of long-term debt for the six months ended June 30, 2016.

CVSR Holdco Financing Arrangement

On July 15, 2016, CVSR Holdco, the indirect owner of the CVSR project, which is 48.95% owned by the Company, issued $200 million of senior secured notes that bear interest at 4.68% and mature on March 31, 2037.  The Company’s pro-rata share of the borrowings was $97.5 million.  Net proceeds of $97.5 million were distributed to NRG Yield Operating LLC based on its pro-rata ownership.

NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility

The Company borrowed $60 million from the revolving credit facility and repaid $48 million during the six months ended June 30, 2016. As of June 30, 2016, $318 million of borrowings and $67 million of letters of credit were outstanding. The Company used its pro rata proceeds of $97.5 million from the CVSR Holdco Financing Arrangement, as described above, along with $28 million of cash on hand, to reduce borrowings under the Company’s revolving credit facility. As of July 31, 2016, $193 million of borrowings were outstanding.

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Earnings Per Share

6 Months Ended

Jun. 30, 2016

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

Basic and diluted earnings (loss) per common share are computed by dividing net income (loss) 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. The number of shares and per share amounts for the prior periods presented below have been retrospectively restated to reflect the Recapitalization.

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

	Three months ended June 30,
	2016				2015
(In millions, except per share data)(a)	Common Class A		Common Class C		Common Class A		Common Class C
Basic earnings per share attributable to NRG Yield, Inc. common stockholders
Net income attributable to NRG Yield, Inc.	$	11	$	21	$	5	$	5
Weighted average number of common shares outstanding - basic	35		63		35		35
Earnings per weighted average common share — basic	$	0.33	$	0.33	$	0.15	$	0.15
Diluted earnings per share attributable to NRG Yield, Inc. common stockholders
Net income attributable to NRG Yield, Inc.	$	14	$	23	$	5	$	5
Weighted average number of common shares outstanding - diluted	49		73		35		35
Earnings per weighted average common share — diluted	$	0.29	$	0.31	$	0.15	$	0.15

	Six months ended June 30,
	2016				2015
(In millions, except per share data)(a)	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.	$	13	$	24	$	3	$	3
Weighted average number of common shares outstanding	35		63		35		35
Earnings per weighted average common share — basic and diluted	$	0.38	$	0.38	$	0.07	$	0.07

^(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.

With respect to the Class A common stock, there were a total of 15 million anti-dilutive outstanding equity instruments for the six months ended June 30, 2016, and the three and six months ended June 30, 2015, related to the 2019 Convertible Notes. With respect to the Class C common stock, there were a total of 10 million anti-dilutive outstanding equity instruments for the six months ended June 30, 2016 related to the 2020 Convertible Notes.

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Segment Reporting

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Segment Reporting

Segment Reporting

The Company’s segment structure reflects how management currently operates and allocates resources. The Company's businesses are primarily 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).

	Three months ended June 30, 2016
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	85		$	134		$	39		$	—		$	258
Cost of operations	16			32			27			—			75
Depreciation and amortization	20			42			5			—			67
General and administrative	—			—			—			3			3
Operating income (loss)	49			60			7			(3		)	113
Equity in earnings of unconsolidated affiliates	4			14			—			—			18
Other income, net	—			1			—			—			1
Interest expense	(12		)	(30		)	(1		)	(19		)	(62		)
Income (loss) before income taxes	41			45			6			(22		)	70
Income tax expense	—			—			—			12			12
Net Income (Loss)	$	41		$	45		$	6		$	(34	)	$	58
Total Assets	$	2,037		$	4,961		$	423		$	186		$	7,607

	Three months ended June 30, 2015 (a)
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	85		$	108		$	42		$	—		$	235
Cost of operations	15			29			31			—			75
Depreciation and amortization	21			45			4			—			70
General and administrative	—			—			—			3			3
Acquisition-related transaction and integration costs	—			—			—			1			1
Operating income (loss)	49			34			7			(4		)	86
Equity in earnings of unconsolidated affiliates	4			4			—			—			8
Loss on debt extinguishment	(7		)	—			—			—			(7		)
Interest expense	(13		)	(17		)	(2		)	(13		)	(45		)
Income (loss) before income taxes	33			21			5			(17		)	42
Income tax expense	—			—			—			4			4
Net Income (Loss)	$	33		$	21		$	5		$	(21	)	$	38

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

	Six months ended June 30, 2016
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	164		$	231		$	83		$	—		$	478
Cost of operations	39			63			56			—			158
Depreciation and amortization	40			83			10			—			133
General and administrative	—			—			—			6			6
Operating income (loss)	85			85			17			(6		)	181
Equity in earnings of unconsolidated affiliates	7			13			—						20
Other income, net	—			1			—			—			1
Interest expense	(23		)	(66		)	(3		)	(38		)	(130		)
Income (loss) before income taxes	69			33			14			(44		)	72
Income tax expense	—			—			—			12			12
Net Income (Loss)	$	69		$	33		$	14		$	(56	)	$	60

	Six months ended June 30, 2015 (a)
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	161		$	185		$	89		$	—		$	435
Cost of operations	36			58			65			—			159
Depreciation and amortization	42			86			9			—			137
General and administrative	—			—			—			6			6
Acquisition-related transaction and integration costs	—			—			—			1			1
Operating income (loss)	83			41			15			(7		)	132
Equity in earnings of unconsolidated affiliates	7			3			—			—			10
Other income, net	1			—			—			—			1
Loss on debt extinguishment	(7		)	—			—			—			(7		)
Interest expense	(25		)	(63		)	(4		)	(26		)	(118		)
Income (loss) before income taxes	59			(19		)	11			(33		)	18
Net Income (Loss)	$	59		$	(19	)	$	11		$	(33	)	$	18

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

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Income Taxes

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:

	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In millions, except percentages)
Income before income taxes	$	70		$	42		$	72		$	18
Income tax expense	12			4			12			—
Effective income tax rate	17.1		%	9.5		%	16.7		%	—		%

For the three and six months ended June 30, 2016, and 2015, the overall effective tax rate was different than the statutory rate of 35% primarily due to taxable earnings allocated to NRG resulting from its interest in NRG Yield LLC and production and investment tax credits generated from certain wind and solar assets, respectively.

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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Related Party Transactions

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

Related Party Transactions Disclosure

Related Party Transactions

In addition to the transactions and relationships described elsewhere in these notes to the consolidated financial statements, NRG and certain subsidiaries of NRG provide services to the Company and its project entities. Amounts due to NRG subsidiaries are recorded as accounts payable - affiliate and amounts due to the Company from NRG or its subsidiaries are recorded as accounts receivable - affiliate in the Company's balance sheet.

Power Hedge Contracts by and between Renewables segment Entities and NRG

Certain NRG Wind TE Holdco entities, which are subsidiaries in the Renewables segment, entered into power hedge contracts with NRG Texas Power LLC and generated $12 million during the six months ended June 30, 2015. Effective October 2015, Elbow Creek, one of the NRG Wind TE Holdco entities, entered into a PPA with NRG Power Marketing LLC, or NRG Power Marketing, as further described below, and the hedge agreement between Elbow Creek and NRG Texas Power LLC was terminated.

Additionally, Alta X and Alta XI entered into a hedge agreement with NRG Power Marketing, as further described in Note 6, Accounting for Derivative Instruments and Hedging Activities, to hedge the forecasted sale of power until the start of the PPAs on January 1, 2016.

Power Purchase Agreement 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 expiring on October 31, 2022. Elbow Creek generated $4 million of revenue during the six months ended June 30, 2016.

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

Certain wholly-owned subsidiaries of the Company are party to a Plant O&M Services Agreement with NRG, pursuant to which NRG provides necessary and appropriate services to operate and maintain the subsidiaries' plant operations, businesses and thermal facilities. NRG is reimbursed for the provided services, as well as for all reasonable and related expenses and expenditures, and payments to third parties for services and materials rendered to or on behalf of the parties to the agreements. NRG is not entitled to any management fee or mark-up under the agreements. Total fees incurred under the agreements were $15 million for the six months ended June 30, 2016, and 2015. There was a balance of $27 million and $29 million due to NRG in accounts payable — affiliate as of June 30, 2016, and December 31, 2015, respectively. As of June 30, 2016, $7 million of the balance was recorded in the current liabilities of the consolidated balance sheet and $20 million was recorded in long term liabilities of the consolidated balance sheet. Subsequent to June 30, 2016, $4 million of the outstanding balance has been paid.

Power Purchase Agreement 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 $2 million of revenue during the six months ended June 30, 2016. The agreement in place is additive to the existing Power Sales and Services Agreement as described further below.

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

NRG Energy Center Dover LLC, or NRG Dover, a subsidiary of the Company, 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 days 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. In July 2013, the coal-fueled plant was converted to a natural gas facility. For the six months ended June 30, 2016, and 2015, NRG Dover purchased $1 million and $3 million, respectively, of natural gas from NRG Power Marketing.

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, a wholly-owned subsidiary of NRG. Under the agreement, NRG Power Marketing procures fuel and fuel transportation for the operation of the Minneapolis generating facility. For the six months ended June 30, 2016, and 2015, NRG Minneapolis purchased $4 million and $5 million, respectively, of natural gas from NRG Power Marketing.

O&MServices Agreements by and between GenConn and NRG

GenConn incurs fees under two O&M services agreements with wholly-owned subsidiaries of NRG. The fees incurred under the agreements were $3 million and $2 million for the six months ended June 30, 2016, and 2015, respectively.

O&MServices Agreement by and between El Segundo and NRG

El Segundo incurs fees under an O&M services agreement with NRG El Segundo Operations, Inc., a wholly-owned subsidiary of NRG. Under the O&M services 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 the six months ended June 30, 2016, and 2015, the costs incurred under the agreement were $2 million. There was a balance of $1 million due to NRG El Segundo in accounts payable — affiliate as of June 30, 2016, and December 31, 2015.

Administrative Services Agreement by and between Marsh Landing and NRG

Marsh Landing is a party to an administrative services agreement with GenOn Energy Services, LLC, a wholly-owned subsidiary of NRG, which provides invoice processing and payment on behalf of Marsh Landing. Marsh Landing reimburses GenOn Energy Services, LLC for the amounts paid by it. The Company reimbursed costs under this agreement of $5 million and $9 million for the six months ended June 30, 2016, and 2015, respectively. There was a balance of $6 million due to GenOn Energy Services, LLC in accounts payable — affiliate as of June 30, 2016, and December 31, 2015.

Administrative Services Agreement by and between CVSR and NRG

CVSR is a party to an administrative services agreement with NRG Renew Operation & Maintenance LLC, a wholly-owned subsidiary of NRG, which provides O&M services on behalf of CVSR. CVSR reimburses NRG Energy Services LLC for the amounts paid by it. CVSR reimbursed costs under this agreement of $2 million and $3 million for the six months ended June 30, 2016, and 2015, respectively.

Management Services Agreement by and between the Company and NRG

NRG provides the Company with various operation, 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 June 30, 2016, the base management fee was approximately $7 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, 2015, the fee was increased by $1 million per year primarily due to the acquisitions of the January 2015 Drop Down Assets and the November 2015 Drop Down Assets. Costs incurred under this agreement were $5 million for the six months ended June 30, 2016, and 2015, which included certain direct expenses incurred by NRG on behalf of the Company in addition to the base management fee. There was a balance of $4 million due to NRG in accounts payable — affiliate as of June 30, 2016. Subsequent to June 30, 2016, the balance has been paid in full.

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

Certain subsidiaries of NRG have entered into agreements with the Company's project entities to provide operation and maintenance services for the balance of the plants not covered by turbine supplier's maintenance and service agreements for the post-warranty period. The agreements have various terms with provisions for extension until terminated. For the six months ended June 30, 2016, and 2015, the costs incurred under the agreements were $3 million and $2 million, respectively.

Certain subsidiaries of NRG provide support services to the NRG Wind TE Holdco 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 six months ended June 30, 2016, and 2015, the costs incurred under the agreements were $1 million and $2 million, respectively.

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Contingencies (Notes)

6 Months Ended

Jun. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Contingencies Disclosure [Text Block]

Contingencies

The Company's material legal proceeding is described below. The Company believes that it has a valid defense to this legal proceeding and intends to defend it 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 proceeding 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 proceeding 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 purported class action lawsuit against NRG Yield, Inc. and against each current and former member of its board of directors individually 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 the Company'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 provides that the plaintiffs will file an amended complaint by August 19, 2016. The Defendants need to file a responsive pleading by October 18, 2016.

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

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

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.

Noncontrolling Interest Disclosure [Text Block]

Noncontrolling Interests

The following table reflects the changes in the Company's noncontrolling interest balance:

	(In millions)
Balance as of December 31, 2015	$	791
Capital contributions from tax equity investors, net of distributions	8
November 2015 Drop Down Assets working capital payment	2
Comprehensive loss	(14		)
Distributions to NRG	(45		)
Balance as of June 30, 2016	$	742

Distributions [Policy Text Block]

Distributions to NRG

The following table lists the distributions paid on NRG Yield LLC's Class B and D units during the six months ended June 30, 2016:

	Second Quarter 2016		First Quarter 2016
Distributions per Class B Unit	$	0.23	$	0.225
Distributions per Class D Unit	$	0.23	$	0.225

On July 26, 2016, NRG Yield LLC declared a distribution on its units of $0.24 per unit payable on September 15, 2016 to unit holders of record as of September 1, 2016. The portion of the distributions paid by NRG Yield LLC to NRG is recorded as a reduction to the Company's noncontrolling interest balance.

Additionally, the Company paid $6 million to NRG relating to its noncontrolling interest in NRG Wind TE Holdco for the six months ended June 30, 2016.

Recent Accounting Developments

Recent Accounting Developments

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 guidance in ASU No. 2016-07 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. The adoption of ASU No. 2016-07 is required to be applied prospectively and early adoption is permitted. 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 February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or ASU No. 2016-02. The amendments of ASU No. 2016-02 complete the joint effort between the FASB and the International Accounting Standards Board, or IASB, to develop a common leasing standard for GAAP and International Financial Reporting Standards, or IFRS, 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. The guidance in ASU No. 2016-02 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, ASU No. 2016-02 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The guidance in ASU No. 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those annual periods. The adoption of ASU No. 2016-02 is required to be applied using a modified retrospective approach for the earliest period presented and early adoption is permitted. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.

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 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 this standard on January 1, 2016, and the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.

ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU No. 2014-09.  The amendments of ASU No. 2014-09 complete the joint effort between the FASB and the International Accounting Standards Board, or IASB, to develop a common revenue standard for GAAP and International Financial Reporting Standards, or IFRS, and to improve financial reporting.  The guidance in ASU No. 2014-09 provides that an entity should recognize revenue to depict the transfer of goods or services 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 the following steps to be applied by an entity: (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies the performance obligation.  In August 2015, the FASB issued ASU 2015-14, which formally deferred the effective date by one year to make the guidance of ASU No. 2014-09 effective for annual reporting periods beginning after December 15, 2017, including interim periods therein.  Early adoption is permitted, but not prior to the original effective date, which was for annual reporting periods beginning after December 15, 2016.

In addition to ASU No. 2014-09, the FASB has issued additional guidance which provides further clarification on Topic 606. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606), or ASU No. 2016-08. The amendments of ASU No. 2016-08 clarify how to apply the implementation guidance on principal versus agent considerations related to the sale of goods or services to a customer as updated by ASU No. 2014-09. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606), or ASU No. 2016-10. The amendments of ASU No. 2016-10 provide further clarification on contract revenue recognition as updated by ASU No. 2014-09, specifically related to the identification of separately identifiable performance obligations and the implementation of licensing contracts. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606), or ASU No. 2016-12. The amendments of ASU No. 2016-12 provide further clarification on contract revenue recognition as updated by ASU No. 2014-09, specifically related to collectability, the presentation of tax collected from customers, and non-cash consideration, as well as offering practical expedients. The Company is working through an adoption plan which includes the evaluation of revenue contracts compared to the new standard and evaluating the impact of Topic 606 on the Company's results of operations, cash flows and financial position.

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Segment Reporting Segment Reporting (Policies)

6 Months Ended

Jun. 30, 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 primarily 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)

6 Months Ended

Jun. 30, 2016

Nature of Business Disclosure [Abstract]

IPO of NRG Yield

The following table represents the structure of the Company as of June 30, 2016:

Schedule of Ownership

As of June 30, 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
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	48.95	%	122	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
			482
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	74.3	%	16	Corn Belt Power Cooperative	2027
Elbow Creek	75	%	92	NRG Power Marketing LLC	2022
Elkhorn Ridge	50.3	%	41	Nebraska Public Power District	2029
Forward	75	%	22	Constellation NewEnergy, Inc.	2017
Goat Wind	74.9	%	113	Dow Pipeline Company	2025
Hardin	74.3	%	11	Interstate Power and Light Company	2027
Laredo Ridge	100	%	80	Nebraska Public Power District	2031
Lookout	75	%	29	Southern Maryland Electric Cooperative	2030
Odin	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	56.3	%	68	Southwestern Public Service Company	2025
Sleeping Bear	75	%	71	Public Service Company of Oklahoma	2032
South Trent	100	%	101	AEP Energy Partners	2029
Spanish Fork	75	%	14	PacifiCorp	2028
Spring Canyon II (b)	90.1	%	29	Platte River Power Authority	2039
Spring Canyon III (b)	90.1	%	25	Platte River Power Authority	2039
Taloga	100	%	130	Oklahoma Gas & Electric	2031
Wildorado	74.9	%	121	Southwestern Public Service Company	2027
			1,999

Projects	Percentage Ownership		Net Capacity (MW)(a)	Offtake Counterparty	Expiration
Thermal
Thermal equivalent MWt (c)	100	%	1,315	Various	Various
NRG Dover Energy Center LLC	100	%	103	NRG Power Marketing LLC	2018
Thermal generation	100	%	20	Various	Various
Total net capacity (excluding equivalent MWt)(d)			4,558

^(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 June 30, 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) Total net capacity excludes 55 MW for RPV Holdco and 45 MW for DGPV Holdco 1 and DGPV Holdco 2, which are consolidated by NRG, as further described in Note 4, Variable Interest Entities, or VIEs.

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

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Distributions Made to Limited Liability Company (LLC) Member, by Distribution [Table Text Block]

The following table lists the distributions paid on NRG Yield LLC's Class B and D units during the six months ended June 30, 2016:

	Second Quarter 2016		First Quarter 2016
Distributions per Class B Unit	$	0.23	$	0.225
Distributions per Class D Unit	$	0.23	$	0.225

Schedule of Change in Noncontrolling Interest [Table Text Block]

The following table reflects the changes in the Company's noncontrolling interest balance:

	(In millions)
Balance as of December 31, 2015	$	791
Capital contributions from tax equity investors, net of distributions	8
November 2015 Drop Down Assets working capital payment	2
Comprehensive loss	(14		)
Distributions to NRG	(45		)
Balance as of June 30, 2016	$	742

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Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 2016

Schedule of Equity Method Investments [Line Items]

Schedule of Variable Interest Entities [Table Text Block]

Summarized financial information for the Company's consolidated VIEs consisted of the following as of June 30, 2016:

(In millions)	NRG Wind TE Holdco		Alta Wind TE Holdco		Spring Canyon
Other current and non-current assets	$	190	$	27	$	4
Property, plant and equipment	638		472		102
Intangible assets	2		281		—
Total assets	830		780		106
Current and non-current liabilities	215		8		6
Total liabilities	215		8		6
Noncontrolling interest	235		121		70
Net assets less noncontrolling interests	$	380	$	651	$	30

GCE Holding LLC [Member]

Schedule of Equity Method Investments [Line Items]

Summarized financial information of equity method investment

The following table presents summarized financial information for GCE Holding LLC:

	Three months ended June 30,				Six months ended June 30,
(In millions)	2016		2015		2016		2015
Income Statement Data:
Operating revenues	$	18	$	18	$	36	$	40
Operating income	10		11		19		20
Net income	$	6	$	8	$	13	$	14

	June 30, 2016		December 31, 2015
Balance Sheet Data:	(In millions)
Current assets	$	34	$	36
Non-current assets	408		416
Current liabilities	14		16
Non-current liabilities	$	211	$	215

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Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Estimated carrying values and fair values

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 June 30, 2016				As of December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(In millions)
Assets:
Notes receivable, including current portion	$	13	$	13	$	17	$	17
Liabilities:
Long-term debt, including current portion	$	4,772	$	4,772	$	4,863	$	4,745

Schedule of Fair Value, Assets and Liabilities [Table Text Block]

The Company records its derivative assets and liabilities at fair value on its consolidated balance sheet. There were no derivative asset positions on the Company's consolidated balance sheet 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 June 30, 2016		As of December 31, 2015
	Fair Value (a)		Fair Value (a)
(In millions)	Level 2		Level 2
Derivative assets:
Commodity contracts	$	1	$	—
Total assets	1		—
Derivative liabilities:
Commodity contracts	—		2
Interest rate contracts	159		98
Total liabilities	$	159	$	100

^(a) There were no assets or liabilities classified as Level 1 or Level 3 as of June 30, 2016, and December 31, 2015.

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Accounting for Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2016

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 June 30, 2016, and December 31, 2015.

		Total Volume
		June 30, 2016		December 31, 2015
Commodity	Units	(In millions)
Natural Gas	MMBtu	4		4
Interest	Dollars	$	1,932	$	1,991

Fair value within the derivative instrument valuation on the balance sheets

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

	Fair Value
	Derivative Assets		Derivative Liabilities
	June 30, 2016		June 30, 2016		December 31, 2015
	(In millions)
Derivatives Designated as Cash Flow Hedges:
Interest rate contracts current	$	—	$	34	$	34
Interest rate contracts long-term	—		108		56
Total Derivatives Designated as Cash Flow Hedges	—		142		90
Derivatives Not Designated as Cash Flow Hedges:
Interest rate contracts current	—		3		3
Interest rate contracts long-term	—		14		5
Commodity contracts current	1		—		2
Total Derivatives Not Designated as Cash Flow Hedges	1		17		10
Total Derivatives	$	1	$	159	$	100

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

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:

	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In millions)
Accumulated OCL beginning balance	$	(110	)	$	(81	)	$	(69	)	$	(61	)
Reclassified from accumulated OCL to income due to realization of previously deferred amounts	3			4			6			7
Mark-to-market of cash flow hedge accounting contracts	(19		)	19			(63		)	(4		)
Accumulated OCL ending balance, net of income tax benefit of $28 and $10, respectively	$	(126	)	$	(58	)	$	(126	)	$	(58	)
Accumulated OCL attributable to noncontrolling interests	(79		)	(42		)	(79		)	(42		)
Accumulated OCL attributable to NRG Yield, Inc.	$	(47	)	$	(16	)	$	(47	)	$	(16	)
Losses expected to be realized from OCL during the next 12 months, net of income tax benefit of $4	$	18					$	18

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Long-term Debt (Tables)

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Schedule of long-term debt

Long-term debt consisted of the following:

	June 30, 2016		December 31, 2015		June 30, 2016, interest rate % (a)	Letters of Credit Outstanding at June 30, 2016
	(In millions, except rates)
2019 Convertible Notes (b)	$	333	$	330	3.500
2020 Convertible Notes (c)	268		266		3.250
Senior Notes, due 2024	500		500		5.375
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019 (d)	318		306		L+2.75	$	67
Project-level debt:
Alpine, due 2022	151		154		L+1.75	37
Alta Wind I, lease financing arrangement, due 2034	245		252		7.015	16
Alta Wind II, lease financing arrangement, due 2034	194		198		5.696	23
Alta Wind III, lease financing arrangement, due 2034	201		206		6.067	24
Alta Wind IV, lease financing arrangement, due 2034	130		133		5.938	16
Alta Wind V, lease financing arrangement, due 2035	208		213		6.071	27
Alta Realty Investments, due 2031	32		33		7.000	—
Alta Wind Asset Management, due 2031	18		19		L+2.375	—
Avra Valley, due 2031	58		60		L+1.75	3
Blythe, due 2028	21		21		L+1.625	6
Borrego, due 2025 and 2038	71		72		L+ 2.50/5.65	5
El Segundo Energy Center, due 2023	457		485		L+1.625 - L+2.25	82
Energy Center Minneapolis, due 2017 and 2025	100		108		5.95 -7.25	—
Kansas South, due 2031	31		33		L+2.00	4
Laredo Ridge, due 2028	102		104		L+1.875	10
Marsh Landing, due 2017 and 2023	410		418		L+1.75 - L+1.875	45
PFMG and related subsidiaries financing agreement, due 2030	29		29		6.000	—
Roadrunner, due 2031	38		40		L+1.625	5
South Trent Wind, due 2020	59		62		L+1.625	10
TA High Desert, due 2020 and 2032	51		52		L+2.50/5.15	8
Tapestry, due 2021	176		181		L+1.625	20
Viento, due 2023	183		189		L+2.75	27
Walnut Creek, due 2023	341		351		L+1.625	60
WCEP Holdings, due 2023	46		46		L+3.00	—
Other	1		2		various	—
Subtotal project-level debt:	3,353		3,461
Total debt	4,772		4,863
Less current maturities	251		241
Less deferred financing costs	56		60
Total long-term debt	$	4,465	$	4,562

^(a) As of June 30, 2016, L+ equals 3 month LIBOR plus x%, except for the Marsh Landing term loan, Walnut Creek term loan, and NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, where L+ equals 1 month LIBOR plus x% and Kansas South, where L+ equals 6 month LIBOR plus x%.

^(b) Net of discount of $12 million and $15 million as of June 30, 2016, and December 31, 2015, respectively.

^(c) Net of discount of $19 million and $21 million as of June 30, 2016, and December 31, 2015, respectively.

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

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2016

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

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

	Three months ended June 30,
	2016				2015
(In millions, except per share data)(a)	Common Class A		Common Class C		Common Class A		Common Class C
Basic earnings per share attributable to NRG Yield, Inc. common stockholders
Net income attributable to NRG Yield, Inc.	$	11	$	21	$	5	$	5
Weighted average number of common shares outstanding - basic	35		63		35		35
Earnings per weighted average common share — basic	$	0.33	$	0.33	$	0.15	$	0.15
Diluted earnings per share attributable to NRG Yield, Inc. common stockholders
Net income attributable to NRG Yield, Inc.	$	14	$	23	$	5	$	5
Weighted average number of common shares outstanding - diluted	49		73		35		35
Earnings per weighted average common share — diluted	$	0.29	$	0.31	$	0.15	$	0.15

	Six months ended June 30,
	2016				2015
(In millions, except per share data)(a)	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.	$	13	$	24	$	3	$	3
Weighted average number of common shares outstanding	35		63		35		35
Earnings per weighted average common share — basic and diluted	$	0.38	$	0.38	$	0.07	$	0.07

XML

Segment Reporting (Tables)

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Three months ended June 30, 2016
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	85		$	134		$	39		$	—		$	258
Cost of operations	16			32			27			—			75
Depreciation and amortization	20			42			5			—			67
General and administrative	—			—			—			3			3
Operating income (loss)	49			60			7			(3		)	113
Equity in earnings of unconsolidated affiliates	4			14			—			—			18
Other income, net	—			1			—			—			1
Interest expense	(12		)	(30		)	(1		)	(19		)	(62		)
Income (loss) before income taxes	41			45			6			(22		)	70
Income tax expense	—			—			—			12			12
Net Income (Loss)	$	41		$	45		$	6		$	(34	)	$	58
Total Assets	$	2,037		$	4,961		$	423		$	186		$	7,607

	Three months ended June 30, 2015 (a)
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	85		$	108		$	42		$	—		$	235
Cost of operations	15			29			31			—			75
Depreciation and amortization	21			45			4			—			70
General and administrative	—			—			—			3			3
Acquisition-related transaction and integration costs	—			—			—			1			1
Operating income (loss)	49			34			7			(4		)	86
Equity in earnings of unconsolidated affiliates	4			4			—			—			8
Loss on debt extinguishment	(7		)	—			—			—			(7		)
Interest expense	(13		)	(17		)	(2		)	(13		)	(45		)
Income (loss) before income taxes	33			21			5			(17		)	42
Income tax expense	—			—			—			4			4
Net Income (Loss)	$	33		$	21		$	5		$	(21	)	$	38

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

	Six months ended June 30, 2016
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	164		$	231		$	83		$	—		$	478
Cost of operations	39			63			56			—			158
Depreciation and amortization	40			83			10			—			133
General and administrative	—			—			—			6			6
Operating income (loss)	85			85			17			(6		)	181
Equity in earnings of unconsolidated affiliates	7			13			—						20
Other income, net	—			1			—			—			1
Interest expense	(23		)	(66		)	(3		)	(38		)	(130		)
Income (loss) before income taxes	69			33			14			(44		)	72
Income tax expense	—			—			—			12			12
Net Income (Loss)	$	69		$	33		$	14		$	(56	)	$	60

	Six months ended June 30, 2015 (a)
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	161		$	185		$	89		$	—		$	435
Cost of operations	36			58			65			—			159
Depreciation and amortization	42			86			9			—			137
General and administrative	—			—			—			6			6
Acquisition-related transaction and integration costs	—			—			—			1			1
Operating income (loss)	83			41			15			(7		)	132
Equity in earnings of unconsolidated affiliates	7			3			—			—			10
Other income, net	1			—			—			—			1
Loss on debt extinguishment	(7		)	—			—			—			(7		)
Interest expense	(25		)	(63		)	(4		)	(26		)	(118		)
Income (loss) before income taxes	59			(19		)	11			(33		)	18
Net Income (Loss)	$	59		$	(19	)	$	11		$	(33	)	$	18

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

XML

Income Taxes (Tables)

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

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

The income tax provision consisted of the following:

	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In millions, except percentages)
Income before income taxes	$	70		$	42		$	72		$	18
Income tax expense	12			4			12			—
Effective income tax rate	17.1		%	9.5		%	16.7		%	—		%

XML

Nature of Business (Details) $ in Millions						6 Months Ended
		Feb. 19, 2016 USD ($)	Nov. 03, 2015 USD ($)	Jun. 29, 2015 USD ($) shares	Jan. 02, 2015 USD ($)	Jun. 30, 2016 USD ($) MW	Jun. 30, 2015 USD ($)	[1]	Nov. 02, 2015 MW
Nature of Business
Proceeds from the issuance of common stock | $						$ 0	$ 600
Megawatts Thermal Equivalent, Available Under right-to-use Provisions						134
Power Generation Capacity, Megawatts	[2]					4,558
Conventional Generation [Member]
Nature of Business
Power Generation Capacity, Megawatts	[2]					1,945
Utility-Scale Solar
Nature of Business
Power Generation Capacity, Megawatts	[2]					482
Distributed Solar [Member]
Nature of Business
Power Generation Capacity, Megawatts	[2]					9
Wind Farms [Member]
Nature of Business
Power Generation Capacity, Megawatts	[2]					1,999
Thermal [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					20
Steam and Chilled Water Capacity, Megawatts Thermal Equivalent	[2],[3]					1,315
NRG Energy Center Dover [Member]
Nature of Business
Percentage of Ownership						100.00%
NRG Yield [Member] | NRG Yield [Member]
Nature of Business
Sale of Stock, Number of Shares Issued in Transaction | shares				28,198,000
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%
NRG Yield LLC | NRG [Member]
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%
GenConn Middletown | Conventional Generation [Member]
Nature of Business
Equity Method Investment, Ownership Percentage						50.00%
Power Generation Capacity, Megawatts	[2]					95
GenConn Devon [Member] | Conventional Generation [Member]
Nature of Business
Equity Method Investment, Ownership Percentage						50.00%
Power Generation Capacity, Megawatts	[2]					95
Marsh Landing | Conventional Generation [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					720
El Segundo [Member] | Conventional Generation [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					550
Walnut Creek [Member] | Conventional Generation [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					485
Alpine [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					66
AZ DG Solar Projects [Member] | Distributed Solar [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					5
PFMG DG Solar Projects [Member] | Distributed Solar [Member]
Nature of Business
Percentage of Ownership						51.00%
Power Generation Capacity, Megawatts	[2]					4
Avenal [Member] | Utility-Scale Solar
Nature of Business
Equity Method Investment, Ownership Percentage						50.00%
Power Generation Capacity, Megawatts	[2]					23
Avra Valley | Utility-Scale Solar
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					26
NRG Solar Blythe LLC [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					21
Borrego [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					26
Roadrunner | Utility-Scale Solar
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					20
CVSR [Member] | Utility-Scale Solar
Nature of Business
Equity Method Investment, Ownership Percentage						48.95%
Power Generation Capacity, Megawatts	[2]					122
Kansas South [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					20
TA - High Desert LLC [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					20
Desert Sunlight [Member] | Utility-Scale Solar
Nature of Business
Percentage of Ownership						25.00%
Alta I [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					150
Alta II [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					150
Alta III [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					150
Alta IV [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					102
Alta V [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					168
Alta X [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership	[4]					100.00%
Power Generation Capacity, Megawatts	[2],[4]					137
Alta XI [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership	[4]					100.00%
Power Generation Capacity, Megawatts	[2],[4]					90
South Trent | Wind Farms [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					101
Spanish Fork [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						75.00%
Power Generation Capacity, Megawatts	[2]					14
Laredo Ridge [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					80
Lookout [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						75.00%
Power Generation Capacity, Megawatts	[2]					29
Odin Wind Farm [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						74.90%
Power Generation Capacity, Megawatts	[2]					15
Taloga [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					130
Wildorado [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						74.90%
Power Generation Capacity, Megawatts	[2]					121
Pinnacle [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					55
San Juan Mesa Wind Project, LLC [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						56.30%
Power Generation Capacity, Megawatts	[2]					68
Sleeping Bear [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						75.00%
Power Generation Capacity, Megawatts	[2]					71
Buffalo Bear [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						100.00%
Power Generation Capacity, Megawatts	[2]					19
Crosswinds [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						74.30%
Power Generation Capacity, Megawatts	[2]					16
Elbow Creek [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						75.00%
Power Generation Capacity, Megawatts	[2]					92
Elkhorn Ridge Wind, LLC [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						50.30%
Power Generation Capacity, Megawatts	[2]					41
Forward [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						75.00%
Power Generation Capacity, Megawatts	[2]					22
Goat Wind [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						74.90%
Power Generation Capacity, Megawatts	[2]					113
Hardin [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						74.30%
Power Generation Capacity, Megawatts	[2]					11
Spring Canyon II [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						90.10%
Power Generation Capacity, Megawatts	[2],[4]					29
Spring Canyon III [Member] | Wind Farms [Member]
Nature of Business
Percentage of Ownership						90.10%
Power Generation Capacity, Megawatts	[2],[4]					25
NRG RPV Holdco [Member]
Nature of Business
Power Generation Capacity, Megawatts						55
NRG DGPV Holdco [Member]
Nature of Business
Power Generation Capacity, Megawatts						45
NRG Energy Center Dover [Member] | Thermal [Member]
Nature of Business
Power Generation Capacity, Megawatts	[2]					103
November 2015 Drop Down Assets [Member]
Nature of Business
Business Acquisition, Consideration Transferred, Working Capital | $		$ 2
Business Acquisition, Percentage of Voting Interests Acquired									75.00%
Payments to Acquire Businesses, Gross | $		$ 207	$ 209
November 2015 Drop Down Assets [Member] | Wind Farms [Member]
Nature of Business
Power Generation Capacity, Megawatts	[2]								814
January 2015 Drop Down Assets [Member]
Nature of Business
Business Acquisitions, Purchase Price | $					$ 489
Business Acquisition, Consideration Transferred, Working Capital | $					$ 9
Southern California Edison [Member] | Desert Sunlight [Member] | Utility-Scale Solar
Nature of Business
Power Generation Capacity, Megawatts	[2]					63
Pacific Gas and Electric [Member] | Desert Sunlight [Member] | Utility-Scale Solar
Nature of Business
Power Generation Capacity, Megawatts	[2]					75
Common Class D [Member] | NRG Yield LLC
Nature of Business
Sale of Stock, Percentage of Ownership after Transaction						100.00%
Common Class A [Member] | NRG Yield LLC
Nature of Business
Sale of Stock, Percentage of Ownership after Transaction						100.00%
Common Class C [Member]
Nature of Business
Proceeds from the issuance of common stock | $				$ 599
Financial Institutions [Member] | November 2015 Drop Down Assets [Member]
Nature of Business
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value | $			$ 159

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

[2] Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of June 30, 2016.

[3] 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] Projects are part of tax equity arrangements

XML

Summary of Significant Accounting Policies (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015		Feb. 19, 2016	Dec. 31, 2015
Summary of Significant Accounting Policies [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest	$ (742)			$ (742)				$ (791)
Capital contributions from tax equity investors, net of distributions				8	$ 123	[1]
Comprehensive loss	$ 13		$ 48	(14)	30
Distributions to NRG				$ (45)
Dividends Payable, Date Declared				Jul. 26, 2016
Common Stock, Dividends, Per Share, Declared				$ 0
Dividends Payable, Date to be Paid				Sep. 15, 2016
Dividends Payable, Date of Record				Sep. 01, 2016
Payments of Capital Distribution				$ 6	$ 0	[1]
November 2015 Drop Down Assets [Member]
Summary of Significant Accounting Policies [Line Items]
Business Acquisition, Consideration Transferred, Working Capital							$ 2
Financial Institutions [Member]
Summary of Significant Accounting Policies [Line Items]
Capital contributions from tax equity investors, net of distributions				$ 8
Common Class B [Member]
Summary of Significant Accounting Policies [Line Items]
Distribution Made to Limited Liability Company (LLC) Member, Distributions Paid, Per Unit		$ 0.225
Common Class D [Member]
Summary of Significant Accounting Policies [Line Items]
Distribution Made to Limited Liability Company (LLC) Member, Distributions Paid, Per Unit		$ 0.225

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

XML

Business Acquisitions CVSR (Details) - Subsequent Event [Member] - CVSR [Member] $ in Millions	Aug. 08, 2016 USD ($)
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	51.05%
Payments to Acquire Businesses, Gross	$ 78.5

XML

Business Acquisitions Business Acquisitions - November 2015 Drop Down (Details)		Feb. 19, 2016 USD ($)	Nov. 03, 2015 USD ($)	Jun. 30, 2016 MW	Nov. 02, 2015 USD ($) MW
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts | MW	[1]			4,558
November 2015 Drop Down Assets [Member]
Business Acquisition [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 Combination, Long-term Debt			193,000,000
Business Acquisition, Consideration Transferred, Working Capital		$ 2,000,000
Financial Institutions [Member] | November 2015 Drop Down Assets [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value			$ 159,000,000
Taxable Income Allocation, Pre-Flip			99.00%
Taxable Income Allocation, Post-Flip			8.53%
Post-Flip Point [Member] | November 2015 Drop Down Assets [Member]
Business Acquisition [Line Items]
Percentage of Cash Available for Distributions			68.60%
Pre-Flip Point [Member] | November 2015 Drop Down Assets [Member]
Business Acquisition [Line Items]
Percentage of Cash Available for Distributions			75.00%
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%
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	[1]				814

[1] Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of June 30, 2016.

XML

Business Acquisitions Business Acquisitions - Desert Sunlight/Spring Canyon/Fuel Cell (Details)		Jun. 30, 2015 USD ($)	May 08, 2015	Apr. 30, 2015	Jun. 30, 2016 MW	Jun. 29, 2015 USD ($)	May 07, 2015
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]				4,558
Utility-Scale Solar [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]				482
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]				20
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%
UB Fuel Cell [Member] | Thermal [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts					1.4
Supply Commitment [Member] | Spring Canyon [Member]
Business Acquisition [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life			24 years
Supply Commitment [Member] | UB Fuel Cell [Member]
Business Acquisition [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life				12 years
Southern California Edison [Member] | Supply Commitment [Member] | Desert Sunlight [Member]
Business Acquisition [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life		20 years
Pacific Gas and Electric [Member] | Supply Commitment [Member] | Desert Sunlight [Member]
Business Acquisition [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life		25 years

[1] Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of June 30, 2016.

XML

Business Acquisitions Business Acquisitions - January 2015 Drop Downs (Details) $ in Millions		Jan. 02, 2015 USD ($)	Jun. 30, 2016 MW
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		4,558
January 2015 Drop Down Assets [Member]
Business Acquisition [Line Items]
Payment to NRG for acquired January 2015 Drop Down Assets | $		$ 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
Accumulated Other Comprehensive Income (Loss), before Tax | $		$ 23
Wind Farms [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		1,999
Conventional Generation [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		1,945
Laredo Ridge [Member] | Wind Farms [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		80
Buffalo Bear [Member] | Wind Farms [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		19
Taloga [Member] | Wind Farms [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		130
Pinnacle [Member] | Wind Farms [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		55
Walnut Creek [Member] | Conventional Generation [Member]
Business Acquisition [Line Items]
Power Generation Capacity, Megawatts	[1]		485

[1] Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of June 30, 2016.

XML

Variable Interest Entities Variable Interest Entities - Consolidated Entities (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Other Assets	$ 2,341	$ 2,401
Property, Plant and Equipment, Net	4,947	5,056
Total Assets	7,607	7,775
Liabilities	5,050	$ 5,143
November 2015 Drop Down Assets [Member]
Schedule of Equity Method Investments [Line Items]
Other Assets	190
Property, Plant and Equipment, Net	638
Intangible Assets, Net (Excluding Goodwill)	2
Total Assets	830
Liabilities	215
Noncontrolling Interest in Variable Interest Entity	235
Net Assets	380
Alta X and XI TE Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Other Assets	27
Property, Plant and Equipment, Net	472
Intangible Assets, Net (Excluding Goodwill)	281
Total Assets	780
Liabilities	8
Noncontrolling Interest in Variable Interest Entity	121
Net Assets	651
Spring Canyon [Member]
Schedule of Equity Method Investments [Line Items]
Other Assets	4
Property, Plant and Equipment, Net	102
Intangible Assets, Net (Excluding Goodwill)	0
Total Assets	106
Liabilities	6
Noncontrolling Interest in Variable Interest Entity	70
Net Assets	$ 30

XML

Variable Interest Entities Variable Interest Entities - DGPV (Details) $ in Millions		May 08, 2015 generatingunit MW	Jun. 30, 2016 USD ($) MW	Dec. 31, 2015 USD ($)
Schedule of Equity Method Investments [Line Items]
Equity investments in affiliates			$ 778	$ 798
Power Generation Capacity, Megawatts | MW	[1]		4,558
NRG DGPV Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in affiliates			$ 78
Tax Equity Financed Portfolio of Leases - Commercial PV [Member] | NRG DGPV Fund 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		19 years
Tax Equity Financed Portfolio of Leases - Community Solar [Member] | NRG DGPV Fund 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		20 years
Maximum [Member] | Tax Equity Financed Portfolio of Leases [Member] | NRG DGPV Fund 1 [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in affiliates			100
Maximum [Member] | Tax Equity Financed Portfolio of Leases [Member] | NRG DGPV Fund 2 [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in affiliates			$ 50

[1] Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of June 30, 2016.

XML

Variable Interest Entities Variable Interest Entities - RPV (Details) $ in Millions		6 Months Ended
		Jun. 30, 2016 USD ($) generatingunit MW	Aug. 05, 2016 USD ($)	Dec. 31, 2015 USD ($)
Schedule of Equity Method Investments [Line Items]
Power Generation Capacity, Megawatts | MW	[1]	4,558
Equity investments in affiliates		$ 778		$ 798
NRG RPV Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Equity investments in affiliates		$ 67
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
Power Generation Capacity, Megawatts | MW		17
Remaining Lease Term		17 years
Tax Equity Financed Portfolio of Leases [Member] | NRG RPV Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Number of Solar Leases in Portfolio | generatingunit		5,500
Power Generation Capacity, Megawatts | MW		38
Minimum [Member] | Tax Equity Financed Portfolio of Leases [Member] | NRG RPV Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Remaining Lease Term		17 years
Maximum [Member] | Tax Equity Financed Portfolio of Leases [Member] | NRG RPV Holdco [Member]
Schedule of Equity Method Investments [Line Items]
Remaining Lease Term		20 years
Equity investments in affiliates		$ 150
Capital Contributions From Partners in Equity Method Investment		$ 100
Subsequent Event [Member] | 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			$ 60

[1] Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of June 30, 2016.

XML

Variable Interest Entities Variable Interest Entities - GenConn (Details) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2016 USD ($) facility MW	Jun. 30, 2015 USD ($)		Jun. 30, 2016 USD ($) facility MW	Jun. 30, 2015 USD ($)		Dec. 31, 2015 USD ($)
Schedule of Equity Method Investments [Line Items]
Power Generation Capacity, Megawatts | MW	[1]	4,558			4,558
Equity investments in affiliates		$ 778			$ 778			$ 798
Total operating revenues		258	$ 235	[2],[3]	478	$ 435	[2],[3]
Operating Income (Loss)		113	86	[2],[3]	181	132	[2],[3]
Net Income (Loss)		58	38	[2],[3],[4]	60	18	[2],[3],[4]
Current assets		319			319			318
Current liabilities		380			380			456
Non-current liabilities		$ 4,670			$ 4,670			4,687
GCE Holding LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage		50.00%			50.00%
Equity investments in affiliates		$ 108			$ 108
Total operating revenues		18	18		36	40
Operating Income (Loss)		10	11		19	(20)
Net Income (Loss)		6	$ 8		13	$ 14
Current assets		34			34			36
Non-current assets		408			408			416
Current liabilities		14			14			16
Non-current liabilities		$ 211			$ 211			$ 215
Gen Conn Energy LLC [Member]
Schedule of Equity Method Investments [Line Items]
Power Generation Units, Number | facility		2			2
Power Generation Capacity, Megawatts | MW		190			190

[1] Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of June 30, 2016.

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

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

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

XML

Fair Value of Financial Instruments Fair Value of Financial Instruments - Balance Sheet Grouping (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financing Receivable, Net	$ 13	$ 17
Long-term Debt and Capital Lease Obligations, Including Current Maturities	4,772	4,863
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Financing Receivable, Net	13	17
Long-term Debt and Capital Lease Obligations, Including Current Maturities	$ 4,772	$ 4,745

XML

Fair Value of Financial Instruments Fair Value of Financial Instruments - Recurring Fair Value (Details) - USD ($)		Jun. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 1,000,000
Derivative Liability, Fair Value, Gross Liability		159,000,000	$ 100,000,000
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	[1]	1,000,000	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
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 Liability, Fair Value, Gross Liability	[1]	159,000,000	100,000,000
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
Commodity 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 Asset, Fair Value, Gross Asset	[1]	1,000,000	0
Derivative Liability, Fair Value, Gross Liability	[1]	0	2,000,000
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 Liability, Fair Value, Gross Liability	[1]	$ 159,000,000	$ 98,000,000

[1] (a) There were no assets or liabilities classified as Level 1 or Level 3 as of June 30, 2016, and December 31, 2015.

XML

Fair Value of Financial Instruments Fair Value of Financial Instruments - Credit Risk and Derivative FV Measurements (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value Assets, Valuation Techniques, Impact of Credit Reserve to Fair Value	$ 5
Estimated Counterparty Credit Risk Exposure to Certain Counterparties, Period	5 years
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$ 2,500
Gain (Loss) on Derivative Instruments [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value Assets, Valuation Techniques, Impact of Credit Reserve to Fair Value	4
Interest Expense [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Fair Value Assets, Valuation Techniques, Impact of Credit Reserve to Fair Value	$ 1

XML

Accounting for Derivative Instruments and Hedging Activities Accounting for Derivative Instruments and Hedging Activities - FV of Derivatives (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 1
Derivative Liability, Fair Value, Gross Liability	159	$ 100
Derivative, Collateral, Right to Reclaim Cash	0	0
Derivative, Collateral, Obligation to Return Cash	0	0
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Gross Liability	142	90
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1
Derivative Liability, Fair Value, Gross Liability	17	10
Interest Rate Contract Current [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Gross Liability	34	34
Interest Rate Contract Current [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Gross Liability	3	3
Interest Rate Contract Non Current [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Gross Liability	108	56
Interest Rate Contract Non Current [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Gross Liability	14	5
Commodity Contract Current [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1
Derivative Liability, Fair Value, Gross Liability	0	2
Interest [Member] | United States of America, Dollars
Derivatives, Fair Value [Line Items]
Derivative, Notional Amount	1,932	1,991
Natural Gas [Member] | MMbtu [Member]
Derivatives, Fair Value [Line Items]
Derivative, Notional Amount	$ 4	$ 4

XML

Accounting for Derivative Instruments and Hedging Activities Accounting for Derivative Instruments and Hedging Activities - AOCI (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Accumulated Other Comprehensive Loss, Net of Tax	$ (126)	$ (58)	$ (126)	$ (58)	$ (110)	$ (69)	$ (81)	$ (61)
Accumulated Other Comprehensive Loss, Cumulative Change in Loss from Cash Flow Hedges, Tax Amount	28	10	28	10
Mark-to-market of cash flow hedge accounting contracts	(19)	19	(63)	(4)
Losses expected to be realized from OCL during the next 12 months, net of income tax benefit of $4			18
Losses expected to be realized from OCL during the next 12 months, Tax Amount	4		4
Gain (Loss) on Cash Flow Hedge Ineffectiveness, Net			0	0
Reclassification out of Accumulated Other Comprehensive Income [Member]
Derivative [Line Items]
Reclassified from accumulated OCL to income due to realization of previously deferred amounts	3	4	6	7
Noncontrolling Interest [Member]
Derivative [Line Items]
Accumulated Other Comprehensive Loss, Net of Tax	(79)	(42)	(79)	(42)
Successor [Member]
Derivative [Line Items]
Accumulated Other Comprehensive Loss, Net of Tax	$ (47)	$ (16)	$ (47)	$ (16)

XML

Accounting for Derivative Instruments and Hedging Activities Accounting for Derivative Instruments and Hedging Activities - Impact to Statement of Operations (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (2)	$ (31)	$ (9)	$ (19)
Commodity Contract [Member] | Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Gain (Loss) on Derivatives		$ (4)		$ (3)

XML

Long-term Debt Long-term Debt - Debt Table (Details) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Debt		$ 4,772,000	$ 4,863,000
Current portion of long-term debt		251,000	241,000
Cumulative Effect of New Accounting Principle in Period of Adoption		56,000	60,000
Long-term Debt, Excluding Current Maturities		4,465,000	4,562,000
5.375% Senior Notes due in 2024 [Member]
Debt Instrument [Line Items]
Senior Notes		$ 500,000	500,000
Debt Instrument, Interest Rate, Stated Percentage	[1]	5.375%
3.5% Convertible Notes due 2019 [Member]
Debt Instrument [Line Items]
Debt	[2]	$ 333,000	330,000
Debt Instrument, Interest Rate, Stated Percentage	[1]	3.50%
Debt Instrument, Unamortized Discount		$ 12,000	15,000
NRG Yield Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt	[3]	$ 318,000	306,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	[1]	1 month LIBOR
Debt Instrument, Basis Spread on Variable Rate	[3]	2.75%
3.25% Convertible Notes due 2020 [Member]
Debt Instrument [Line Items]
Debt	[4]	$ 268,000	266,000
Debt Instrument, Interest Rate, Stated Percentage	[1]	3.25%
Debt Instrument, Unamortized Discount		$ 19,000	21,000
Alta Wind I, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Debt		$ 245,000	252,000
Debt Instrument, Interest Rate, Stated Percentage	[1]	7.015%
Alta Wind II, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Debt		$ 194,000	198,000
Debt Instrument, Interest Rate, Stated Percentage	[1]	5.696%
Alta Wind III, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Debt		$ 201,000	206,000
Debt Instrument, Interest Rate, Stated Percentage	[1]	6.067%
Alta Wind IV, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Debt		$ 130,000	133,000
Debt Instrument, Interest Rate, Stated Percentage	[1]	5.938%
Alta Wind V, lease financing arrangement, due 2035 [Member]
Debt Instrument [Line Items]
Debt		$ 208,000	213,000
Debt Instrument, Interest Rate, Stated Percentage	[1]	6.071%
Alta Realty Investments, due 2031 [Member]
Debt Instrument [Line Items]
Debt		$ 32,000	33,000
Debt Instrument, Interest Rate, Stated Percentage	[1]	7.00%
Alta Wind Asset Management, due 2031 [Member]
Debt Instrument [Line Items]
Debt		$ 18,000	19,000
Debt Instrument, Description of Variable Rate Basis	[1]	3 month LIBOR
Debt Instrument, Basis Spread on Variable Rate		2.375%
West Holdings Credit Agreement [Member]
Debt Instrument [Line Items]
Debt		$ 457,000	485,000
Debt Instrument, Description of Variable Rate Basis	[1]	3 month LIBOR
West Holdings Credit Agreement due 2023 Tranche A [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.625%
Marsh Landing Term Loan Facility [Member]
Debt Instrument [Line Items]
Debt		$ 410,000	418,000
Walnut Creek Energy, LLC, due in 2023 [Member]
Debt Instrument [Line Items]
Debt		$ 341,000	351,000
Debt Instrument, Description of Variable Rate Basis	[1]	1 month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.625%
Tapestry Wind LLC due in 2021 [Member]
Debt Instrument [Line Items]
Debt		$ 176,000	181,000
Debt Instrument, Description of Variable Rate Basis	[1]	3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.625%
Viento Funding II, Inc., due in 2023 [Member]
Debt Instrument [Line Items]
Debt		$ 183,000	189,000
Debt Instrument, Description of Variable Rate Basis	[1]	3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		2.75%
NRG Energy Center Minneapolis LLC Senior Secured Notes [Member]
Debt Instrument [Line Items]
Debt		$ 100,000	108,000
Laredo Ridge Wind, LLC, due in 2026 [Member]
Debt Instrument [Line Items]
Debt		$ 102,000	104,000
Debt Instrument, Description of Variable Rate Basis	[1]	3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.875%
South Trent Financing Agreement [Member]
Debt Instrument [Line Items]
Debt		$ 59,000	62,000
Debt Instrument, Description of Variable Rate Basis	[1]	3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.625%
Avra Valley Financing Agreement [Member]
Debt Instrument [Line Items]
Debt		$ 58,000	60,000
Debt Instrument, Description of Variable Rate Basis	[1]	3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.75%
High Desert Facility [Member]
Debt Instrument [Line Items]
Debt		$ 51,000	52,000
WCEP Holdings, LLC, due in 2023 [Member]
Debt Instrument [Line Items]
Debt		$ 46,000	46,000
Debt Instrument, Description of Variable Rate Basis	[1]	3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		3.00%
Other Debt [Member]
Debt Instrument [Line Items]
Debt		$ 1,000	2,000
Letters of Credit Outstanding, Amount		0
Roadrunner Financing Agreement [Member]
Debt Instrument [Line Items]
Debt		$ 38,000	40,000
Debt Instrument, Description of Variable Rate Basis	[1]	3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.625%
Kansas South Facility, due 2031 [Member]
Debt Instrument [Line Items]
Debt		$ 31,000	33,000
Debt Instrument, Description of Variable Rate Basis	[1]	6-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		2.00%
NRG Solar Blythe LLC Credit Agreement Due 2028 [Member]
Debt Instrument [Line Items]
Debt		$ 21,000	21,000
Debt Instrument, Description of Variable Rate Basis	[1]	3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.625%
PFMG Financing Agreement [Member]
Debt Instrument [Line Items]
Debt		$ 29,000	29,000
Debt Instrument, Interest Rate, Stated Percentage	[1]	6.00%
Project [Domain]
Debt Instrument [Line Items]
Debt		$ 3,353,000	3,461,000
West Holdings Credit Agreement due 2023 Tranche B [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.25%
Marsh Landing Tranche A due December 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	[1]	1 month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.75%
Marsh Landing Tranche B due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	[1]	1 month LIBOR
Debt Instrument, Basis Spread on Variable Rate		1.875%
Alpine Financing Agreement, due 2022 [Member]
Debt Instrument [Line Items]
Debt		$ 151,000	154,000
Debt Instrument, Description of Variable Rate Basis	[1]	3-Month LIBOR
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%
Borrego Financing Agreement, due 2024 [Member]
Debt Instrument [Line Items]
Debt		$ 71,000	$ 72,000
Debt Instrument, Description of Variable Rate Basis	[1]	3-Month LIBOR
Debt Instrument, Basis Spread on Variable Rate		2.50%
Borrego Financing Agreement, due 2038 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.65%
High Desert Facility, due 2033 [Member]
Debt Instrument [Line Items]
Debt Instrument, Description of Variable Rate Basis	[1]	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%
Letter of Credit [Member] | NRG Yield Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		$ 67,000
Letter of Credit [Member] | Alta Wind I, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		16,000
Letter of Credit [Member] | Alta Wind II, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		23,000
Letter of Credit [Member] | Alta Wind III, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		24,000
Letter of Credit [Member] | Alta Wind IV, lease financing arrangement, due 2034 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		16,000
Letter of Credit [Member] | Alta Wind V, lease financing arrangement, due 2035 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		27,000
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] | West Holdings Credit Agreement [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		82,000
Letter of Credit [Member] | Marsh Landing Term Loan Facility [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		45,000
Letter of Credit [Member] | Walnut Creek Energy, LLC, due in 2023 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		60,000
Letter of Credit [Member] | Tapestry Wind LLC due in 2021 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		20,000
Letter of Credit [Member] | Viento Funding II, Inc., due in 2023 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		27,000
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] | Laredo Ridge Wind, LLC, due in 2026 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		10,000
Letter of Credit [Member] | South Trent Financing Agreement [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		10,000
Letter of Credit [Member] | Avra Valley Financing Agreement [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		3,000
Letter of Credit [Member] | High Desert Facility [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		8,000
Letter of Credit [Member] | WCEP Holdings LLC [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		5,000
Letter of Credit [Member] | Kansas South Facility, due 2031 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		4,000
Letter of Credit [Member] | NRG Solar Blythe LLC Credit Agreement Due 2028 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		6,000
Letter of Credit [Member] | PFMG Financing Agreement [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		0
Letter of Credit [Member] | Alpine Financing Agreement, due 2022 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		37,000
Letter of Credit [Member] | Borrego Financing Agreement, due 2024 [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount		$ 5,000

[1] As of June 30, 2016, L+ equals 3 month LIBOR plus x%, except for the Marsh Landing term loan, Walnut Creek term loan, and NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, where L+ equals 1 month LIBOR plus x% and Kansas South, where L+ equals 6 month LIBOR plus x%

[2] Net of discount of $12 million and $15 million as of June 30, 2016, and December 31, 2015, respectively.

[3] Applicable rate is determined by the Borrower Leverage Ratio, as defined in the credit agreement.

[4] Net of discount of $19 million and $21 million as of June 30, 2016, and December 31, 2015, respectively

XML

Long-term Debt Long-term Debt - Corporate Debt (Details) - USD ($) $ in Millions			1 Months Ended	6 Months Ended
		Jul. 15, 2016	Jul. 31, 2016	Jun. 30, 2016
3.5% Convertible Notes due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	[1]			3.50%
NRG Yield Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Debt				$ 60.0
Repayments of Debt				48.0
Line of Credit Facility, Fair Value of Amount Outstanding				$ 318.0
3.25% Convertible Notes due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	[1]			3.25%
Letter of Credit [Member] | NRG Yield Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Letters of Credit Outstanding, Amount				$ 67.0
Subsequent Event [Member] | NRG Yield Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Repayments of Debt			$ 28.0
Line of Credit Facility, Fair Value of Amount Outstanding			$ 193.0
Subsequent Event [Member] | CVSR Financing Agreement [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Debt		$ 200.0
Debt Instrument, Interest Rate, Stated Percentage		4.68%
Proceeds from Debt, Net of Issuance Costs		$ 97.5
Utility-Scale Solar [Member] | CVSR [Member]
Debt Instrument [Line Items]
Equity Method Investment, Ownership Percentage				48.95%

[1] As of June 30, 2016, L+ equals 3 month LIBOR plus x%, except for the Marsh Landing term loan, Walnut Creek term loan, and NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, where L+ equals 1 month LIBOR plus x% and Kansas South, where L+ equals 6 month LIBOR plus x%

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Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended				6 Months Ended
		Jun. 30, 2016		Jun. 30, 2015		Jun. 30, 2016	Jun. 30, 2015
Common Class A [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income (Loss) Available to Common Stockholders, Diluted		$ 14	[1]	$ 5	[1]	$ 13	$ 3
Weighted average number of common shares outstanding - diluted		49,000,000	[1]	35,000,000	[1]	35,000,000	35,000,000
Earnings Per Share, Diluted		$ 0.29	[1]	$ 0.15	[1]	$ 0.38	$ 0.07	[1]
Common Class C [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income (Loss) Available to Common Stockholders, Diluted		$ 23	[1]	$ 5	[1]	$ 23	$ 3
Weighted average number of common shares outstanding - diluted		73,000,000	[1]	35,000,000	[1]	63,000,000	35,000,000
Earnings Per Share, Diluted	[1]	$ 0.31		$ 0.15		$ 0.38	$ 0.07
3.5% Convertible Notes due 2019 [Member] | Common Class A [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount				15		15,000,000	15,000,000
3.25% Convertible Notes due 2020 [Member] | Common Class C [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount				0		10,000,000	0

[1] (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.

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Segment Reporting (Details) - USD ($) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015		Jun. 30, 2016	Jun. 30, 2015		Dec. 31, 2015
Segment Reporting
Operating revenues		$ 258	$ 235	[1],[2]	$ 478	$ 435	[1],[2]
Cost of operations		75	75	[2]	158	159	[2]
Depreciation and amortization		67	70	[1],[2]	133	137	[1],[2],[3]
General and administrative		3	3	[1],[2]	6	6	[1],[2]
Acquisition-related transaction and integration costs		0	1	[1],[2]	0	1	[1],[2]
Operating Income		113	86	[1],[2]	181	132	[1],[2]
Equity in earnings of unconsolidated affiliates		18	8	[1],[2]	20	10	[1],[2]
Other income, net		1	0	[1]	1	1	[1],[2]
Loss on debt extinguishment		0	(7)	[1],[2]	0	(7)	[1],[2],[3]
Interest expense		(62)	(45)	[1],[2]	(130)	(118)	[1],[2]
Income Before Income Taxes		70	42	[1],[2]	72	18	[1],[2]
Income tax expense		12	4	[2]	12	0
Net Income		58	38	[1],[2],[4]	60	18	[1],[2],[4]
Total Assets		7,607			7,607			$ 7,775
Conventional Generation
Segment Reporting
Operating revenues		85	85	[2]	164	161	[2]
Cost of operations		16	15	[2]	39	36	[2]
Depreciation and amortization		20	21	[2]	40	42	[2]
General and administrative		0	0	[2]	0	0	[2]
Acquisition-related transaction and integration costs	[2]		0			0
Operating Income		49	49	[2]	85	83	[2]
Equity in earnings of unconsolidated affiliates		4	4	[2]	7	7	[2]
Other income, net		0			0	1	[2]
Loss on debt extinguishment	[2]		(7)			(7)
Interest expense		(12)	(13)	[2]	(23)	(25)	[2]
Income Before Income Taxes		41	33	[2]	69	59	[2]
Income tax expense		0	0	[2]	0
Net Income		41	33	[2]	69	59	[2]
Total Assets		2,037			2,037
Renewables
Segment Reporting
Operating revenues		134	108	[2]	231	185	[2]
Cost of operations		32	29	[2]	63	58	[2]
Depreciation and amortization		42	45	[2]	83	86	[2]
General and administrative		0	0	[2]	0	0	[2]
Acquisition-related transaction and integration costs	[2]		0			0
Operating Income		60	34	[2]	85	41	[2]
Equity in earnings of unconsolidated affiliates		14	4	[2]	13	3	[2]
Other income, net		1			1	0	[2]
Loss on debt extinguishment	[2]		0			0
Interest expense		(30)	(17)	[2]	(66)	(63)	[2]
Income Before Income Taxes		45	21	[2]	33	(19)	[2]
Income tax expense		0	0	[2]	0
Net Income		45	21	[2]	33	(19)	[2]
Total Assets		4,961			4,961
Thermal [Member]
Segment Reporting
Operating revenues		39	42	[2]	83	89	[2]
Cost of operations		27	31	[2]	56	65	[2]
Depreciation and amortization		5	4	[2]	10	9	[2]
General and administrative		0	0	[2]	0	0	[2]
Acquisition-related transaction and integration costs	[2]		0			0
Operating Income		7	7	[2]	17	15	[2]
Equity in earnings of unconsolidated affiliates		0	0	[2]	0	0	[2]
Other income, net		0			0	0	[2]
Loss on debt extinguishment	[2]		0			0
Interest expense		(1)	(2)	[2]	(3)	(4)	[2]
Income Before Income Taxes		6	5	[2]	14	11	[2]
Income tax expense		0	0	[2]	0
Net Income		6	5	[2]	14	11	[2]
Total Assets		423			423
Corporate
Segment Reporting
Operating revenues		0	0	[2]	0	0	[2]
Cost of operations		0	0	[2]	0	0	[2]
Depreciation and amortization		0	0	[2]	0	0	[2]
General and administrative		3	3	[2]	6	6	[2]
Acquisition-related transaction and integration costs	[2]		1			1
Operating Income		(3)	(4)	[2]	(6)	(7)	[2]
Equity in earnings of unconsolidated affiliates		0	0	[2]		0	[2]
Other income, net		0			0	0	[2]
Loss on debt extinguishment	[2]		0			0
Interest expense		(19)	(13)	[2]	(38)	(26)	[2]
Income Before Income Taxes		(22)	(17)	[2]	(44)	(33)	[2]
Income tax expense		12	4	[2]	12
Net Income		(34)	$ (21)	[2]	(56)	$ (33)	[2]
Total Assets		$ 186			$ 186

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

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

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

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

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Income Taxes (Provision) (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015		Jun. 30, 2016	Jun. 30, 2015
Income Tax Expense (Benefit), Continuing Operations [Abstract]
Income before income taxes	$ 70	$ 42	[1],[2]	$ 72	$ 18	[1],[2]
Income tax expense	$ 12	$ 4	[2]	$ 12	$ 0
Effective income tax rate	17.14286%	9.50%		16.66667%	0.00%
U.S. federal statutory rate (as a percent)				35.00%

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

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

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Related Party Transactions (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended			6 Months Ended			12 Months Ended
	Jul. 31, 2016	Jun. 30, 2016	Jun. 30, 2015	[1],[2]	Jun. 30, 2016	Jun. 30, 2015		Dec. 31, 2015
Related Party Transaction
General and administrative		$ 3	$ 3		$ 6	$ 6	[1],[2]
Due to Affiliate, Current		32			32			$ 85
Accounts payable — affiliate		20			20			0
GenOn Energy Services LLC [Member]
Related Party Transaction
Due to Affiliate		6			6			6
NRG Repowering Holdings LLC [Member]
Related Party Transaction
Cost of Natural Gas Purchases					1	3
NRG Yield [Member] | NRG [Member]
Related Party Transaction
Management Services Fee, Increase								1
General and administrative					5	5
NRG Yield [Member] | NRG [Member] | Scenario, Plan [Member]
Related Party Transaction
Management Services Fee, Annual					7
NRG Yield, Inc. [Member] | NRG [Member]
Related Party Transaction
Due to Affiliate		4			4
Thermal [Member] | NRG [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party					15	15
Due to Affiliate		27			27			29
Due to Affiliate, Current		7			7
Accounts payable — affiliate		20			20
NRG Energy Center Dover [Member] | NRG [Member]
Related Party Transaction
Revenue from Related Parties					2
NRG Energy Center Minneapolis LLC [Member] | NRG [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party					4	5
Marsh Landing [Member] | GenOn Energy Services LLC [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party					5	9
El Segundo [Member] | NRG El Segundo Operations, Inc. [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party					2	2
Due to Affiliate		$ 1			1			$ 1
Gen Conn Energy LLC [Member] | NRG [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party					3	2
CVSR [Member] | NRG Energy Services LLC [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party					2	3
November 2015 Drop Down Assets [Member] | NRG [Member]
Related Party Transaction
Related Party Transaction, Other Revenues from Transactions with Related Party						12
Elbow Creek [Member] | NRG [Member]
Related Party Transaction
Revenue from Related Parties					4
Operations and Maintenance services [Member] | November 2015 Drop Down Assets [Member] | NRG [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party					3	2
Support services [Member] | November 2015 Drop Down Assets [Member] | NRG [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party					$ 1	$ 2
Subsequent Event [Member]
Related Party Transaction
Repayments of Related Party Debt	$ 4

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

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