UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year ended December 31, 2014.

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition period from                      to                       .

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.)
211 Carnegie Center, Princeton, New Jersey (Address of principal executive offices)	08540 (Zip Code)

(609) 524-4500

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Exchange on Which Registered
Common Stock, Class A, par value $0.01	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes x    No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.   Yes o    No x

Indicate by check mark whether the registrant (1) has filed all reports 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.    Yes x    No o

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).    Yes x    No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    x

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 Act).    Yes o    No x

As of the last business day of the most recently completed second fiscal quarter, the aggregate market value of the common stock of the registrant held by non-affiliates was approximately $1,049,804,101 based on the closing sale price of $52.05 as reported on the New York Stock Exchange.

Indicate the number of shares outstanding of each of the registrant's classes of common stock as of the latest practicable date.

Class	Outstanding at January 31, 2015
Common Stock, Class A, par value $0.01 per share	34,586,250
Common Stock, Class B, par value $0.01 per share	42,738,750

Documents Incorporated by Reference:

Portions of the Registrant's definitive Proxy Statement relating to its 2015 Annual Meeting of Stockholders

are incorporated by reference into Part III of this Annual Report on Form 10-K

1

TABLE OF CONTENTS

Index

GLOSSARY OF TERMS	3
PART I	6
Item 1 — Business	6
Item 1A — Risk Factors	15
Item 1B — Unresolved Staff Comments	32
Item 2 — Properties	33
Item 3 — Legal Proceedings	34
Item 4 — Mine Safety Disclosures	34
PART II	35
Item 5 — Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6 — Selected Financial Data	37
Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations	38
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	56
Item 8 — Financial Statements and Supplementary Data	56
Item 9 — Changes in Disagreements With Accountants on Accounting and Financial Disclosure	57
Item 9A — Controls and Procedures	57
Item 9B — Other Information	59
PART III	59
Item 10 — Directors, Executive Officers and Corporate Governance	59
Item 11 — Executive Compensation	61
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	61
Item 13 — Certain Relationships and Related Transactions, and Director Independence	61
Item 14 — Principal Accounting Fees and Services	61
PART IV	62
Item 15 — Exhibits, Financial Statement Schedules	62
EXHIBIT INDEX	136

2

GLOSSARY OF TERMS

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

Acquired ROFO Assets	The TA-High Desert, RE Kansas South and El Segundo projects, which were acquired from NRG on June 30, 2014
Alta Sellers	Terra-Gen Finance Company, LLC and certain of its affiliates
ARRA	American Recovery and Reinvestment Act of 2009
ASC	The FASB Accounting Standards Codification, which the FASB established as the source of authoritative U.S. 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
CAA	Clean Air Act
CfD	Contract for Differences
CO2	Carbon Dioxide
COD	Commercial operations date
CFTC	U.S. Commodity Future Trading Commission
DGCL	Delaware General Corporation Law
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
Dodd-Frank Act	The Dodd-Frank Wall Street Reform and Consumer Protection Act
El Segundo	NRG West Holdings LLC, the subsidiary of Natural Gas Repowering LLC, which owns the El Segundo Energy Center project
EME	Edison Mission Energy
EME-NYLD-Eligible Assets	Certain assets of Edison Mission Energy that fit within the Company's asset portfolio
EPC	Engineering, Procurement and Construction
ERCOT	Electric Reliability Council of Texas, the Independent System Operator 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
FCM	Forward Capacity Market
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
FPA	Federal Power Act
GHG	Greenhouse gases
ISO	Independent System Operator, also referred to as Regional Transmission Organization, or RTO
ISO-NE	ISO New England Inc.
ITC	Investment Tax Credit
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
MMBtu	Million British Thermal Units
MW	Megawatt
MWh	Saleable megawatt hour, net of internal/parasitic load megawatt-hour

3

MWt	Megawatts Thermal Equivalent
NEPOOL	New England Power Pool
NERC	North American Electric Reliability Corporation
Net Exposure	Counterparty credit exposure to NRG Yield, Inc. net of collateral
NOLs	Net Operating Losses
NOx	Nitrogen Oxide
NPNS	Normal Purchase Normal Sale
NRG	NRG Energy, Inc.
NRG Yield	Accounting predecessor, representing the combination of the projects that were acquired by NRG Yield LLC
NRG Yield, Inc.	NRG Yield, Inc., or the Company
NRG Yield LLC	The holding company through which the projects are owned by NRG, the holder of Class B common units, and NRG Yield, Inc., the holder of the Class A common units
NRG Yield Operating LLC	The holder of the project assets that belong to NRG Yield LLC
NSPS	New Source Performance Standards
OCI/OCL	Other comprehensive income/loss
OMB	Office of Management and Budget
OSHA	Occupational Safety and Health Administration
Pinnacle	Pinnacle Wind, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Pinnacle project
PJM	PJM Interconnection, LLC
PPA	Power Purchase Agreement
PUCT	Public Utility Commission of Texas
PUHCA	Public Utility Holding Company Act of 2005
PURPA	Public Utility Regulatory Policies Act of 1978
QF	Qualifying Facility under PURPA
RE Kansas South	NRG Solar Kansas South LLC, the operating subsidiary of NRG Solar Kansas South Holdings LLC, which owns the RE Kansas South project
ROFO Agreement	Right of First Offer Agreement between the Company and NRG
RPM	Reliability Pricing Model
RPS	Renewable Portfolio Standard
RTO	Renewable Transmission Originator
Senior Notes	NRG Yield Operating LLC's $500 million of 5.375% unsecured senior notes due 2024
SO2	Sulfur Dioxide
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
Terra-Gen	Terra-Gen Operating Company, LLC
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
U.S. DOE	U.S. Department of Energy
U.S. GAAP	Accounting principles generally accepted in the United States

4

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

Item 1 — Business

General

NRG Yield, Inc., or 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 as of December 31, 2014 collectively represents2,861 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 approximately 17 years as of December 31, 2014, based on cash available for distribution. The Company also owns thermal infrastructure assets with an aggregate steam and chilled water capacity of 1,310 net MWt and electric generation capacity of 124 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.

History

The Company was formed by NRG as a Delaware corporation on December 20, 2012. On July 22, 2013, the Company closed the initial public offering of 22,511,250 shares of its Class A common stock at an offering price of $22.00 per share. In connection with the offering, the Company’s shares of Class A common stock began trading on the New York Stock Exchange under the symbol “NYLD”. The net proceeds to the Company from the offering, after deducting underwriting discounts, were approximately $468 million, of which the Company used approximately $395 million to purchase 19,011,250 NRG Yield LLC Class A common units from NRG and $73 million to purchase 3,500,000 NRG Yield LLC Class A common units directly from NRG Yield LLC.

On July 29, 2014, the Company issued 12,075,000 shares of Class A common stock for net proceeds, after underwriting discount and expenses, of $630 million. The Company utilized the proceeds of the offering to acquire 12,075,000 additional Class A units of NRG Yield LLC and, as a result, subsequent to the secondary offering and as of December 31, 2014, the Company and NRG own 44.7% and 55.3% of NRG Yield LLC, respectively. As of December 31, 2014, NRG owned 42,738,750 NRG Yield LLC Class B common units and the Company owned 34,586,250 NRG Yield LLC Class A common units. NRG, through its holdings of Class B common stock, has 55.3% of the voting power in the Company and receives distributions from Yield LLC through its ownership of Class B common units. The holders of the Company's issued and outstanding shares of Class A common stock have 100% of economic interest, are entitled to dividends and have 44.7% of the voting power in the Company.

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

6

The diagram below depicts the Company’s organizational structure as of December 31, 2014:

7

Operations Overview

The Company's operating assets are comprised of the following projects as of December 31, 2014:

Projects	Percentage Ownership		Net Capacity (MW) (a)	Offtake Counterparty	Expiration
Conventional
GenConn Middletown	49.95	%	95	Connecticut Light & Power	2041
GenConn Devon	49.95	%	95	Connecticut Light & Power	2040
Marsh Landing	100	%	720	Pacific Gas and Electric	2023
El Segundo	100	%	550	Southern California Edison	2023
			1,460
Utility Scale Solar
Alpine	100	%	66	Pacific Gas and Electric	2033
Avenal	49.95	%	23	Pacific Gas and Electric	2031
Avra Valley	100	%	25	Tucson Electric Power	2032
Blythe	100	%	21	Southern California Edison	2029
Borrego	100	%	26	San Diego Gas and Electric	2038
Roadrunner	100	%	20	El Paso Electric	2031
CVSR	48.95	%	122	Pacific Gas and Electric	2038
RE Kansas South	100	%	20	Pacific Gas and Electric	2033
TA High Desert	100	%	20	Southern California Edison	2033
			343
Distributed Solar
AZ DG Solar Projects	100	%	5	Various	2025 - 2033
PFMG DG Solar Projects	51	%	5	Various	2032
			10
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	100	%	137	Southern California Edison	2038(c)
Alta XI	100	%	90	Southern California Edison	2038(c)
South Trent	100	%	101	AEP Energy Partners	2029
			1,048
Thermal
Thermal equivalent MWt(b)	100	%	1,310	Various	Various
Thermal generation	100	%	124	Various	Various
Total net capacity (excluding equivalent MWt)			2,985

(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of December 31, 2014.

(b) 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 NRG Yield Inc.'s thermal facilities and certain of its customers.

(c) PPA begins on January 1, 2016.

During the year ended December 31, 2014, the Company derived approximately 32% of its consolidated revenue from Southern California Edison, or SCE, and approximately 26% of its consolidated revenue from Pacific Gas and Electric, or PG&E.

8

Business Strategy

The Company's primary business strategy is to focus on the acquisition and ownership of assets with minimal long term price or volumetric offtake risk in order that it may be able to increase the cash dividends of Class A common stock over time without compromising the ongoing stability of the business. The Company's plan for executing this strategy includes the following key components:

Focus on contracted renewable energy and conventional generation and thermal infrastructure assets. The Company owns and operates utility scale and distributed renewable energy and natural gas-fired generation, thermal and other infrastructure assets with proven technologies, low operating risks and stable cash flows. The Company believes by focusing on this core asset class and leveraging its industry knowledge, it will maximize its strategic opportunities, be a leader in operational efficiency and maximize its overall financial performance.

Growing the business through acquisitions of contracted operating assets. The Company believes that its base of operations and relationship with NRG provide a platform in the conventional and renewable power generation and thermal sectors for strategic growth through cash accretive and tax advantaged acquisitions complementary to its existing portfolio. NRG granted the Company a right of first offer to acquire six of its power generating assets, or the NRG ROFO Assets, if and to the extent NRG elected to sell any of these assets prior to July 2018. On June 30, 2014, as described in Item 15 — Note 3, Business Acquisitions, NRG Yield Operating LLC acquired the El Segundo, TA High Desert, and RE Kansas South projects for total cash consideration of $357 million. In addition, the acquisition included the assumption of $612 million in project level debt.  The table below lists the remaining available NRG ROFO Assets:

Asset	Fuel Type	Net Capacity (MW)(1)	COD	Offtake (Term/Offtaker)
CVSR(2)	Solar	128	2013	25 year PPA/Pacific Gas & Electric
Ivanpah(3)	Solar	193	2013	20-25 year PPA/Pacific Gas & Electric and Southern California Edison
Agua Caliente(4)	Solar	148	2014	25 year PPA/Pacific Gas & Electric

(1)  Represents the maximum, or rated, electricity generating capacity of the facility in MW multiplied by NRG’s percentage ownership interest in the facility as of December 31, 2014.

(2)  Represents NRG’s remaining 51.05% ownership interest in CVSR.

(3)  Represents NRG’s 49.95% ownership interest in Ivanpah. Following a sale of this 49.95% interest, the remaining 50.05% of Ivanpah would be owned by NRG, Google Inc. and BrightSource Energy Inc.

(4)  Represents NRG’s 51% ownership interest in Agua Caliente. The remaining 49% of Agua Caliente is owned by MidAmerican Energy Holdings Inc.

On April 1, 2014, NRG acquired substantially all of the assets of Edison Mission Energy, or EME. Subsequent to the acquisition, NRG identified certain of the EME assets it believed fit within the Company’s asset portfolio, or the EME-NYLD-Eligible Assets.  On January 2, 2015, the Company and NRG completed the sale of certain EME-NYLD-Eligible Assets, including Walnut Creek, the Tapestry projects (Buffalo Bear, Pinnacle and Taloga) and Laredo Ridge, for total cash consideration of $489 million, including $9 million for working capital, plus $737 million of assumed project level debt. The acquisition of the EME-NYLD-Eligible Assets added a combined 770 MWs to the Company's net capacity.

NRG is not obligated to sell the remaining NRG ROFO Assets or the remaining EME-NYLD-Eligible Assets to the Company and, if offered, the Company cannot be sure whether these assets will be offered on acceptable terms, or that the Company will choose to consummate such acquisitions. In addition, NRG may offer additional assets to the Company, as described in Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations. The Company also expects to have significant opportunities to acquire other generation and thermal infrastructure assets from third parties where the Company believes its knowledge of the market, operating expertise and access to capital provides it with a competitive advantage.

Primary Focus on North America. The Company intends to primarily focus its investments in North America (including the unincorporated territories of the U.S.). The Company believes that industry fundamentals in North America present it with significant opportunity to acquire renewable, natural gas-fired generation and thermal infrastructure assets, without creating significant exposure to currency and sovereign risk. By primarily focusing its efforts on North America, the Company believes it will best leverage its regional knowledge of power markets, industry relationships and skill sets to maximize value for the stockholders.

9

Maintain sound financial practices to grow the dividend. The Company intends to maintain a commitment to disciplined financial analysis and a balanced capital structure to enable it to increase the dividend over time and serve the long-term interests of stockholders. The Company's financial practices include a risk and credit policy focused on transacting with credit-worthy counterparties; a financing policy, which focuses on seeking an optimal capital structure through various capital formation alternatives to minimize interest rate and refinancing risks, ensure stable long-term dividends and maximize value; and a dividend policy that is based on distributing all or substantially all cash available for distribution each quarter that the Company receives from NRG Yield LLC. The Company intends to evaluate various alternatives for financing future acquisitions and refinancing of existing project-level debt, in each case, to reduce the cost of debt, extend maturities and maximize cash available for distribution. The Companybelieves it has additional flexibility to seek alternative financing arrangements, including, but not limited to, debt financings at a holding company level.

Competition

Power generation is a capital-intensive business with numerous and diverse industry participants. The Company competes on the basis of the location of its plants and on the basis of contract price and terms of individual project. Within the power industry, there is a wide variation in terms of the capabilities, resources, nature and identity of the companies with whom the Company competes with depending on the market. Competitors for energy supply are utilities, independent power producers and other providers of distributed generation. The Company also competes to acquire new projects with solar developers who retain solar power plant ownership, independent power producers, financial investors and other dividend, growth-oriented companies. Competitive conditions may be substantially affected by various forms of energy legislation and regulation considered by federal, state and local legislatures and administrative agencies. Such laws and regulations may substantially increase the costs of acquiring, constructing and operating projects, and it could be difficult for the Company to adapt to and operate under such laws and regulations.

The Company's thermal business has certain cost efficiencies that may form barriers to entry. Generally, there is only one district energy system in a given territory, for which the only competition comes from on-site systems. While the district energy system can usually make an effective case for the efficiency of its services, some building owners nonetheless may opt for on-site systems, either due to corporate policies regarding allocation of capital, unique situations where an on-site system might in fact prove more efficient, or because of previously committed capital in systems that are already on-site. Growth in an existing district energy system generally comes from new building construction or existing building conversions within the service territory of the district energy provider.

Competitive Strengths

Stable, high quality cash flows with attractive tax profile. The Company's facilities have a highly stable, predictable cash flow profile consisting of predominantly long-life electric generation assets that sell electricity under long-term fixed priced contracts or pursuant to regulated rates with credit-worthy counterparties. Additionally, the Company's facilities have minimal fuel risk. For the Company's four conventional assets, fuel is provided by the toll counterparty or the cost thereof is a pass-through cost under the CfD. Renewable facilities have no fuel costs, and most of the Company's thermal infrastructure assets have contractual or regulatory tariff mechanisms for fuel cost recovery. The offtake agreements for the Company's conventional and renewable generation facilities have a weighted-average remaining duration of approximately 17 years as of December 31, 2014, based on cash available for distribution, providing long-term cash flow stability. The Company's generation offtake agreements with counterparties for whom credit ratings are available have a weighted-average Moody’s rating of A3 based on rated capacity under contract. Based on the current portfolio of assets, the Company does not expect to pay significant federal income tax for a period of approximately ten years. All of the Company's assets are in the U.S. and accordingly have no currency or repatriation risks.

High quality, long-lived assets with low operating and capital requirements. The Company benefits from a portfolio of relatively newly-constructed assets, other than thermal infrastructure assets, with all of its conventional and renewable assets having achieved COD within the past six years. The Company's assets are comprised of proven and reliable technologies, provided by leading original equipment manufacturers such as General Electric, or GE, Siemens AG, SunPower Corporation, or SunPower, and First Solar Inc., or First Solar. Given the modern nature of the portfolio, which includes a substantial number of relatively low operating and maintenance cost solar generation assets, the Company expects to achieve high fleet availability and expend modest maintenance-related capital expenditures. The Company estimates its solar portfolio has a weighted average remaining expected life (based on rated MW) of approximately 20 years. Additionally, with the support of services provided by NRG, the Company expects to continue to implement the same rigorous preventative operating and management practices that NRG uses across its fleet of assets. In 2014, NRG’s OSHA recordable rate was 0.73, which is within the top quartile plant operating performance for its entire fleet, based on applicable OSHA standards.

10

Significant scale and diversity. The Company owns and operates a large and diverse portfolio of contracted electric generation and thermal infrastructure assets. As of December 31, 2014, the Company's 2,861 net MW contracted generation portfolio benefits from significant diversification in terms of technology, fuel type, counterparty and geography. The Company's thermal business consists of eleven operations, seven of which are district energy centers that provide steam and chilled water to approximately 690 customers, and four of which provide generation. The Company believes its scale and access to best practices across the fleet improves its business development opportunities through enhanced industry relationships, reputation and understanding of regional power market dynamics. Furthermore, the Company's diversification reduces its operating risk profile and reliance on any single market.

Relationship with NRG. The Company believes its relationship with NRG, including NRG’s expressed intention to maintain a controlling interest in the Company, provides significant benefits, including management and operational expertise, and future growth opportunities. The Company's executive officers have considerable experience in owning and operating, as well as developing, acquiring and integrating, generation and thermal infrastructure assets, with, on average, over 15 years in the energy sector:

• NRG Management and Operational Expertise. The Company has access to the significant resources of NRG, the largest competitive power generator in the U.S., to support the operational, finance, legal, regulatory and environmental aspects, and growth strategy of its business. As such, the Company believes it avails itself of best-in-class resources, including management and operational expertise.

• NRG Asset Development and Acquisition Track Record. NRG's development and strategic teams are focused on the development and acquisition of renewable and conventional generation assets. They have successfully helped grow NRG's power generation portfolio from 24,365 net MWs at the end of 2009 to 52,263 net MWs as of December 31, 2014.

• NRG Financing Experience. The Company believes NRG has demonstrated a successful track record of sourcing attractive low-cost, long duration capital to fund project development and acquisitions. The Company expects to realize significant benefits from NRG’s financing and structuring expertise as well as its relationships with financial institutions and other lenders.

Environmentally well-positioned portfolio of assets. On a net capacity basis, the Company's portfolio of electric generation assets consists of 1,401 net MW of renewable generation capacity that are non-emitting sources of power generation. The Company's conventional assets consist of the dual fuel-fired GenConn assets as well as the Marsh Landing simple cycle natural gas-fired peaking generation facility and the El Segundo combined cycle natural gas-fired peaking facility. The Company does not anticipate having to expend any significant capital expenditures in the foreseeable future to comply with current environmental regulations applicable to its generation assets. Taken as a whole, the Company believes its strategy will be a net beneficiary of current and potential environmental legislation and regulatory requirements that may serve as a catalyst for capacity retirements and improve market opportunities for environmentally well-positioned assets like the Company's assets once its current offtake agreements expire.

Thermal infrastructure business has high entry costs. Significant capital has been invested to construct the Company's thermal infrastructure assets, serving as a barrier to entry in the markets in which such assets operate. As of December 31, 2014, the Company's thermal gross property, plant, and equipment was approximately $427 million. The Company's thermal district energy centers are located in urban city areas, with the chilled water and steam delivery systems located underground. Constructing underground delivery systems in urban areas requires long lead times for permitting, rights of way and inspections and is costly. By contrast, the incremental cost to add new customers in existing markets is relatively low. Once thermal infrastructure is established, the Company believes it has the ability to retain customers over long periods of time and to compete effectively for additional business against stand-alone on-site heating and cooling generation facilities. Installation of stand-alone equipment can require significant modification to a building as well as significant space for equipment and funding for capital expenditures. The Company's system technologies often provide economies of scale in terms of fuel procurement, ability to switch between multiple types of fuel to generate thermal energy, and fuel conversion efficiency. The Company's top ten thermal customers, which make up approximately 13% of the Company's consolidated revenues for the twelve months ended December 31, 2014, have had a relationship with the Company for an average of over 20 years.

11

Segment Review

The following table summarizes the Company's operating revenues, net income and assets by segment for the years ended December 31, 2014, 2013, and 2012, as discussed in Item 15 — Note 12, Segment Reporting, to the Consolidated Financial Statements. Refer to that footnote for additional information about the Company's segments. In addition, refer to Item 2 — Properties, for information about the facilities in each of the Company's segments.

	Year ended December 31, 2014
(In millions)	Conventional Generation		Renewables			Thermal		Corporate			Total
Operating revenues	$	244	$	144		$	195	$	—		$	583
Net income (loss)	109		(14		)	31		(45		)	81
Total assets	1,516		3,321			437		478			5,752

	Year ended December 31, 2013
(In millions)	Conventional Generation		Renewables		Thermal		Corporate			Total
Operating revenues	$	138	$	89	$	152	$	—		$	379
Net income (loss)	87		40		20		(15		)	132
Total assets	1,584		1,046		436		172			3,238

	Year ended December 31, 2012
(In millions)	Conventional Generation		Renewables			Thermal		Corporate			Total
Operating revenues	$	—	$	33		$	142	$	—		$	175
Net income (loss)	14		(1		)	16		(17		)	12

Government Incentives

Government incentives can enhance the economics of the Company's generating assets or investments by providing, for example, loan guarantees, cash grants, favorable tax treatment, favorable depreciation rules, or other incentives.  Certain recent proposals enhance federal incentives for renewable generation — including through the permanent extension of the wind power Production Tax Credit and the extension of the solar Investment Tax Credit, and could incentivize the development of additional renewable energy projects that would fit within the Company’s asset portfolio.  In addition, direct cash incentives may encourage additional renewable energy development by non-taxpaying entities that cannot always take advantage of tax credits.

Regulatory Matters

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 an 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 PUCT.

CFTC

The CFTC, among other things, has regulatory oversight authority over the trading of swaps, futures and many commodities under the Commodity Exchange Act, or CEA. The Dodd-Frank Act amended the CEA and increased the CFTC's regulatory authority on matters related to futures and over-the-counter derivatives like interest rate swaps.

The Company expects that, in 2015 and thereafter, the CFTC will further clarify the scope of the Dodd-Frank Act and publish additional rules concerning margin requirements and other issues that could affect the Company's over-the-counter derivatives trading. Because there are many details that remain to be addressed through CFTC rulemaking proceedings, at this time the Company cannot fully measure the impact of the Dodd-Frank Act on the Company, its operations or collateral requirements.

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FERC

FERC, among other things, regulates the transmission and the wholesale sale of electricity in interstate commerce under the authority of the FPA. The transmission of electric energy occurring wholly within ERCOT is not subject to FERC’s jurisdiction under Sections 203 or 205 of the FPA. Under existing regulations, FERC determines whether an entity owning a generation facility is an EWG, as defined in the PUHCA. FERC also determines whether a generation facility meets the ownership and technical criteria of a QF under the PURPA. Each of the Company’s non-ERCOT U.S. generating facilities qualifies as an EWG.

The FPA gives FERC exclusive rate-making jurisdiction over the wholesale sale of electricity and transmission of electricity in interstate commerce of public utilities (as defined by the FPA). Under the FPA, FERC, with certain exceptions, regulates the owners of facilities used for the wholesale sale of electricity or transmission in interstate commerce as public utilities, and establishes market rules that are just and reasonable.

Public utilities are required to obtain FERC’s acceptance, pursuant to Section 205 of the FPA, of their rate schedules for the wholesale sale of electricity. All of the Company’s non-QF generating entities located outside of ERCOT make sales of electricity pursuant to market-based rates, as opposed to traditional cost-of-service regulated rates. Every three years FERC will conduct a review of the Company’s market based rates and potential market power on a regional basis.

In accordance with the Energy Policy Act of 2005, FERC has approved the NERC as the national Energy Reliability Organization, or ERO. As the ERO, NERC is responsible for the development and enforcement of mandatory reliability standards for the wholesale electric power system. In addition to complying with NERC requirements, each NRG entity must comply with the requirements of the regional reliability entity for the region in which it is located.

The PURPA was passed in 1978 in large part to promote increased energy efficiency and development of independent power producers. The PURPA created QFs to further both goals, and FERC is primarily charged with administering the PURPA as it applies to QFs. Certain QFs are exempt from regulation, either in whole or in part, under the FPA as public utilities.

The PUHCA provides FERC with certain authority over and access to books and records of public utility holding companies not otherwise exempt by virtue of their ownership of EWGs, QFs, and Foreign Utility Companies. The Company is exempt from many of the accounting, record retention, and reporting requirements of the PUHCA.

Regulatory Developments

New Jersey and Maryland's Generator Contracting Programs — The New Jersey Board of Public Utilities and the Maryland Public Service Commission awarded long-term power purchase contracts to generation developers to encourage the construction of new generation capacity in the respective States. The constitutionality of the long-term contracts was challenged and the U.S. District Court for the District of New Jersey (in an October 25, 2013, decision) and the U.S. District Court for the District of Maryland (in an October 24, 2013, decision) found that the respective contracts violated the Supremacy Clause of the U.S. Constitution and were preempted. On June 30, 2014, the U.S. Court of Appeals for the Fourth Circuit affirmed the Maryland District Court's decision. On September 11, 2014, the U.S. Court of Appeals for the Third Circuit affirmed the New Jersey District Court's decision. Various parties have petitioned the U.S. Supreme Court for review of both cases. Any U.S. Supreme Court action may affect future capacity prices in PJM.

Environmental Matters

The Company is subject to a wide range of environmental laws in the development, ownership, construction and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of facilities. Environmental laws have become increasingly stringent and the Company expects this trend to continue. The electric generation industry is likely to face new requirements to address various emissions, including GHG, and threatened and endangered species.

In January 2014, the EPA re-proposed the NSPS for CO₂ emissions from new fossil-fuel-fired electric generating units that had been previously proposed in April 2012. The re-proposed standards are 1,000 pounds of CO₂ per MWh for large gas units and 1,100 pounds of CO₂ per MWh for coal units and small gas units. Proposed standards are in effect until a final rule is published or another rule is re-proposed. In June 2014, the EPA proposed a rule that would require states to develop CO₂ standards that would apply to existing fossil-fueled generating facilities. Specifically, the EPA proposed state-specific rate-based standards for CO₂ emissions, as well as guidelines for states to follow in developing plans to achieve the state-specific goals. The EPA anticipates finalizing both of these rules in the summer of 2015.

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Employees

The Company does not employ any of the individuals who manage operations. The personnel that carry out these activities are employees of NRG, and their services are provided for the Company's benefit under the Management Services Agreement with NRG as described in Item 15 — Note 14, Related Party Transactions.

Available Information

The Company's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to section 13(a) or 15(d) of the Exchange Act are available free of charge through the Company's website, www.nrgyield.com, as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. The Company also routinely posts press releases, presentations, webcasts, and other information regarding the Company on its website.

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Item 1A — Risk Factors

Risks Related to the Business

Certain facilities are newly constructed and may not perform as expected.

All of the Company's conventional and renewable assets have achieved commercial operations within the past six years. The ability of these facilities to meet the Company's performance expectations is subject to the risks inherent in newly constructed power generation facilities and the construction of such facilities, including, but not limited to, degradation of equipment in excess of the Company's expectations, system failures, and outages. The failure of these facilities to perform as the Company expects could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows and its ability to pay dividends to holders of the Company's common stock.

Pursuant to the Company's cash dividend policy, the Company intends to distribute all or substantially all of the cash available for distribution through regular quarterly distributions and dividends, and the Company's ability to grow and make acquisitions through cash on hand could be limited.

The Company expects to distribute all or substantially all of the cash available for distribution each quarter and to rely primarily upon external financing sources, including the issuance of debt and equity securities and, if applicable, borrowings under the Company's revolving credit facility to fund acquisitions and growth capital expenditures. The Company may be precluded from pursuing otherwise attractive acquisitions if the projected short-term cash flow from the acquisition or investment is not adequate to service the capital raised to fund the acquisition or investment, after giving effect to the Company's available cash reserves. The Company's growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent the Company issues additional equity securities in connection with any acquisitions or growth capital expenditures, the payment of dividends on these additional equity securities may increase the risk that the Company will be unable to maintain or increase its per share dividend. The incurrence of bank borrowings or other debt by NRG Yield Operating LLC or by the Company's project-level subsidiaries to finance the Company’s growth strategy will result in increased interest expense and the imposition of additional or more restrictive covenants, which, in turn, may impact the cash distributions the Company receives to distribute to holders of the Company’s common stock.

The Company may not be able to effectively identify or consummate any future acquisitions on favorable terms, or at all.

The Company's business strategy includes growth through the acquisitions of additional generation assets (including through corporate acquisitions). This strategy depends on the Company’s ability to successfully identify and evaluate acquisition opportunities and consummate acquisitions on favorable terms. However, the number of acquisition opportunities is limited. In addition, the Company will compete with other companies for these limited acquisition opportunities, which may increase the Company’s cost of making acquisitions or cause the Company to refrain from making acquisitions at all. Some of the Company’s competitors for acquisitions are much larger than the Company with substantially greater resources. These companies may be able to pay more for acquisitions and may be able to identify, evaluate, bid for and purchase a greater number of assets than the Company’s financial or human resources permit. If the Company is unable to identify and consummate future acquisitions, it will impede the Company’s ability to execute its growth strategy and limit the Company’s ability to increase the amount of dividends paid to holders of the Company’s common stock.

Furthermore, the Company’s ability to acquire future renewable facilities may depend on the viability of renewable assets generally. These assets currently are largely contingent on public policy mechanisms including ITCs, cash grants, loan guarantees, accelerated depreciation, RPS and carbon trading plans. These mechanisms have been implemented at the state and federal levels to support the development of renewable generation, demand-side and smart grid and other clean infrastructure technologies. The availability and continuation of public policy support mechanisms will drive a significant part of the economics and viability of the Company’s growth strategy and expansion into clean energy investments.

The Company’s ability to effectively consummate future acquisitions will also depend on the Company’s ability to arrange the required or desired financing for acquisitions.

The Company may not have sufficient availability under the Company’s credit facilities or have access to project-level financing on commercially reasonable terms when acquisition opportunities arise. An inability to obtain the required or desired financing could significantly limit the Company’s ability to consummate future acquisitions and effectuate the Company’s growth strategy. If financing is available, utilization of the Company’s credit facilities or project-level financing for all or a portion of the purchase price of an acquisition could significantly increase the Company’s interest expense, impose additional or more restrictive covenants and reduce cash available for distribution. Similarly, the issuance of additional equity securities as consideration for acquisitions could cause significant stockholder dilution and reduce the Company’s per share cash available for

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distribution if the acquisitions are not sufficiently accretive. The Company’s ability to consummate future acquisitions may also depend on the Company’s ability to obtain any required regulatory approvals for such acquisitions, including, but not limited to, approval by FERC under Section 203 of the FPA.

Finally, the acquisition of companies and assets are subject to substantial risks, including the failure to identify material problems during due diligence (for which the Company may not be indemnified post-closing), the risk of over-paying for assets (or not making acquisitions on an accretive basis) and the ability to retain customers. Further, the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, the Company's acquisitions may divert management’s attention from the Company's existing business concerns, disrupt the Company's ongoing business or not be successfully integrated. There can be no assurances that any future acquisitions will perform as expected or that the returns from such acquisitions will support the financing utilized to acquire them or maintain them. As a result, the consummation of acquisitions may have a material adverse effect on the Company's business, financial condition, results of operations and cash flows and ability to pay dividends to holders of the Company’s common stock.

The Company’s indebtedness could adversely affect its ability to raise additional capital to fund the Company’s operations or pay dividends. It could also expose the Company to the risk of increased interest rates and limit the Company’s ability to react to changes in the economy or the Company’s industry as well as impact the Company’s cash available for distribution.

As of December 31, 2014, the Company had approximately $4,050 million of total consolidated indebtedness, $3,224 million of which was incurred by the Company's non-guarantor subsidiaries. In addition, the Company’s share of its unconsolidated affiliates’ total indebtedness and letters of credit outstanding as of December 31, 2014, totaled approximately $567 million and $20 million, respectively (calculated as the Company’s unconsolidated affiliates’ total indebtedness as of such date multiplied by the Company’s percentage membership interest in such assets). On July 22, 2013, the Company entered into a $60 million revolving credit facility, which was amended and restated on April 25, 2014, to increase the available line of credit to $450 million and extend its maturity to April 2019. The revolving credit facility can be used for cash or for the issuance of letters of credit. As of December 31, 2014, there were $38 million of letters of credit issued under the facility. In addition, the Company had $296 million of letters of credit outstanding to support contracted obligations at the Company’s project-level entities. During the first quarter of 2014, the Company closed on its offering of $345 million aggregate principal amount of 3.50% Convertible Notes due 2019. The Notes are convertible, under certain circumstances, into the Company’s common stock, cash or a combination thereof at an initial conversion price of $46.55 per share of Class A common stock, which is equivalent to an initial conversion rate of approximately 21.4822 shares of Class A common stock per $1,000 principal amount of Convertible Notes. On August 5, 2014, NRG Yield Operating LLC issued $500 million of Senior Notes. The Senior Notes bear interest at 5.375% and mature in August 2024. Interest on the notes is payable semi-annually on February 15 and August 15 of each year, and commenced on February 15, 2015. The Company’s substantial debt could have important negative consequences on the Company’s financial condition, including:

• increasing the Company’s vulnerability to general economic and industry conditions;

• requiring a substantial portion of the Company’s cash flow from operations to be dedicated to the payment of principal and interest on the Company’s indebtedness, therefore reducing the Company’s ability to pay dividends to holders of the Company’s capital stock (including the Class A common stock) or to use the Company’s cash flow to fund its operations, capital expenditures and future business opportunities;

• limiting the Company’s ability to enter into long-term power sales or fuel purchases which require credit support;

• limiting the Company’s ability to fund operations or future acquisitions;

• restricting the Company’s ability to make certain distributions with respect to the Company’s capital stock (including the Class A common stock) and the ability of the Company’s subsidiaries to make certain distributions to it, in light of restricted payment and other financial covenants in the Company’s credit facilities and other financing agreements;

• exposing the Company to the risk of increased interest rates because certain of the Company’s borrowings, which may include borrowings under the Company’s amended and restated revolving credit facility, are at variable rates of interest;

• limiting the Company’s ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and

• limiting the Company’s ability to adjust to changing market conditions and placing it at a competitive disadvantage compared to the Company’s competitors who have less debt.

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The Company's amended and restated revolving credit facility contains financial and other restrictive covenants that limit the Company’s ability to return capital to stockholders or otherwise engage in activities that may be in the Company’s long-term best interests. The Company’s inability to satisfy certain financial covenants could prevent the Company from paying cash dividends, and the Company’s failure to comply with those and other covenants could result in an event of default which, if not cured or waived, may entitle the related lenders to demand repayment or enforce their security interests, which could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flows. In addition, failure to comply with such covenants may entitle the related lenders to demand repayment and accelerate all such indebtedness.

The agreements governing the Company’s project-level financing contain financial and other restrictive covenants that limit the Company’s project subsidiaries’ ability to make distributions to the Company or otherwise engage in activities that may be in the Company’s long-term best interests. The project-level financing agreements generally prohibit distributions from the project entities to the Company unless certain specific conditions are met, including the satisfaction of certain financial ratios. The Company’s inability to satisfy certain financial covenants may prevent cash distributions by the particular project(s) to it and, the Company’s failure to comply with those and other covenants could result in an event of default which, if not cured or waived may entitle the related lenders to demand repayment or enforce their security interests, which could have a material adverse effect on the Company’s business, results of operations and financial condition. In addition, failure to comply with such covenants may entitle the related lenders to demand repayment and accelerate all such indebtedness. If the Company is unable to make distributions from the Company’s project-level subsidiaries, it would likely have a material adverse effect on the Company’s ability to pay dividends to holders of the Company’s common stock.

Letter of credit facilities to support project-level contractual obligations generally need to be renewed after five to seven years, at which time the Company will need to satisfy applicable financial ratios and covenants. If the Company is unable to renew the Company’s letters of credit as expected or replace them with letters of credit under different facilities on favorable terms or at all, the Company may experience a material adverse effect on its business, financial condition or results of operations and cash flows. Furthermore, such inability may constitute a default under certain project-level financing arrangements, restrict the ability of the project-level subsidiary to make distributions to it and/or reduce the amount of cash available at such subsidiary to make distributions to the Company.

In addition, the Company’s ability to arrange financing, either at the corporate level or at a non-recourse project-level subsidiary, and the costs of such capital, are dependent on numerous factors, including:

• general economic and capital market conditions;

• credit availability from banks and other financial institutions;

• investor confidence in the Company, its partners, NRG, as the Company’s principal stockholder (on a combined voting basis) and manager under the Management Services Agreement, and the regional wholesale power markets;

• the Company’s financial performance and the financial performance of the Company subsidiaries;

• the Company’s level of indebtedness and compliance with covenants in debt agreements;

• maintenance of acceptable project credit ratings or credit quality;

• cash flow; and

• provisions of tax and securities laws that may impact raising capital.

The Company may not be successful in obtaining additional capital for these or other reasons. Furthermore, the Company may be unable to refinance or replace project-level financing arrangements or other credit facilities on favorable terms or at all upon the expiration or termination thereof. The Company's failure, or the failure of any of the Company’s projects, to obtain additional capital or enter into new or replacement financing arrangements when due may constitute a default under such existing indebtedness and may have a material adverse effect on the Company's business, financial condition, results of operations and cash flows.

Certain of the Company's long-term bilateral contracts with state-regulated utilities could be declared invalid by a court of competent jurisdiction.

A significant portion of the Company's revenues are derived from long-term bilateral contracts with state-regulated utilities. Other state-regulated contracts, to which the Company is not a party, are being challenged in federal court and have been declared unconstitutional on the grounds that the rate for energy and capacity established by the state-regulated contracts impermissibly conflict with the rate for energy and capacity established by FERC. To date, federal district courts in New Jersey and Maryland have struck down contracts on similar grounds. In 2014, the U.S. Court of Appeals for the Fourth Circuit upheld the Maryland court decision, while the U.S. Court of Appeals for the Third Circuit upheld the New Jersey decision. If certain of

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the Company's state-regulated agreements with utilities are held to be invalid, the Company may be unable to replace such contracts, which could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows.

The generation of electric energy from solar and wind energy sources depends heavily on suitable meteorological conditions.

If solar or wind conditions are unfavorable, the Company's electricity generation and revenue from renewable generation facilities may be substantially below the Company's expectations. The electricity produced and revenues generated by a solar electric or wind energy generation facility is highly dependent on suitable solar or wind conditions, as applicable, and associated weather conditions, which are beyond the Company's control. Furthermore, components of the Company's systems, such as solar panels and inverters, could be damaged by severe weather, such as hailstorms or tornadoes. In addition, replacement and spare parts for key components may be difficult or costly to acquire or may be unavailable. Unfavorable weather and atmospheric conditions could impair the effectiveness of the Company's assets or reduce their output beneath their rated capacity or require shutdown of key equipment, impeding operation of the Company's renewable assets.

The Company bases its investment decisions with respect to each renewable generation facility on the findings of related wind and solar studies conducted on-site prior to construction or based on historical conditions at existing facilities. However, actual climatic conditions at a facility site, particularly wind conditions, may not conform to the findings of these studies and therefore, the Company's solar and wind energy facilities may not meet anticipated production levels or the rated capacity of the Company's generation assets, which could adversely affect the business, financial condition and results of operations and cash flows.

Operation of electric generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows.

The ongoing operation of the Company's facilities involves risks that include the breakdown or failure of equipment or processes or performance below expected levels of output or efficiency due to wear and tear, latent defect, design error or operator error or force majeure events, among other things. Operation of the Company's facilities also involves risks that the Company will be unable to transport its products to its customers in an efficient manner due to a lack of transmission capacity. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems, occur from time to time and are an inherent risk of the business. Unplanned outages typically increase operation and maintenance expenses and may reduce revenues as a result of selling fewer MWh or require the Company to incur significant costs as a result of obtaining replacement power from third parties in the open market to satisfy forward power sales obligations. The Company's inability to operate its electric generation assets efficiently, manage capital expenditures and costs and generate earnings and cash flow from the Company's asset-based businesses could have a material adverse effect on the business, financial condition, results of operations and cash flows. While the Company maintains insurance, obtains warranties from vendors and obligates contractors to meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not cover the Company's lost revenues, increased expenses or liquidated damages payments should it experience equipment breakdown or non-performance by contractors or vendors.

Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems.

In addition to natural risks such as earthquake, flood, lightning, hurricane and wind, other hazards, such as fire, explosion, structural collapse and machinery failure are inherent risks in the Company's operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment and contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in the Company being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. The Company maintains an amount of insurance protection that it considers adequate but cannot provide any assurance that the Company's insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which the Company may be subject. Furthermore, the Company's insurance coverage is subject to deductibles, caps, exclusions and other limitations. A loss for which the Company is not fully insured (which may include a significant judgment against any facility or facility operator) could have a material adverse effect on the Company's business, financial condition, results of operations or cash flows. Further, due to rising insurance costs and changes in the insurance markets, the Company cannot provide any assurance that its insurance coverage will continue to be available at all or at rates or on terms similar to those presently available. Any losses not covered by insurance could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows.

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Maintenance, expansion and refurbishment of electric generation facilities involve significant risks that could result in unplanned power outages or reduced output.

The Company's facilities may require periodic upgrading and improvement. Any unexpected operational or mechanical failure, including failure associated with breakdowns and forced outages, could reduce the Company's facilities' generating capacity below expected levels, reducing the Company's revenues and jeopardizing the Company's ability to pay dividends to holders of its common stock at expected levels or at all. Degradation of the performance of the Company's solar facilities above levels provided for in the related offtake agreements may also reduce the Company's revenues. Unanticipated capital expenditures associated with maintaining, upgrading or repairing the Company's facilities may also reduce profitability.

If the Company makes any major modifications to its conventional power generation facilities, it may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source review provisions of the CAA in the future. Any such modifications could likely result in substantial additional capital expenditures. The Company may also choose to repower, refurbish or upgrade its facilities based on its assessment that such activity will provide adequate financial returns. Such facilities require time for development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices. This could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows.

Counterparties to the Company's offtake agreements may not fulfill their obligations and, as the contracts expire, the Company may not be able to replace them with agreements on similar terms in light of increasing competition in the markets in which the Company operates.

A significant portion of the electric power the Company generates is sold under long-term offtake agreements with public utilities or industrial or commercial end-users, with a weighted average remaining duration of approximately 16 years (based on net capacity under contract). As of December 31, 2014, the largest customers of the Company's power generation assets, including assets in which the Company has less than a 100% membership interest, were SCE, PG&E and CL&P, which represented 52%, 32% and 6% respectively, of the net electric generation capacity of the Company's facilities.

If, for any reason, any of the purchasers of power under these agreements are unable or unwilling to fulfill their related contractual obligations or if they refuse to accept delivery of power delivered thereunder or if they otherwise terminate such agreements prior to the expiration thereof, the Company's assets, liabilities, business, financial condition, results of operations and cash flows could be materially and adversely affected. Furthermore, to the extent any of the Company's power purchasers are, or are controlled by, governmental entities, the Company's facilities may be subject to legislative or other political action that may impair their contractual performance.

The power generation industry is characterized by intense competition and the Company's electric generation assets encounter competition from utilities, industrial companies and other independent power producers, in particular with respect to uncontracted output. In recent years, there has been increasing competition among generators for offtake agreements and this has contributed to a reduction in electricity prices in certain markets characterized by excess supply above designated reserve margins. In light of these market conditions, the Company may not be able to replace an expiring or terminated agreement with an agreement on equivalent terms and conditions, including at prices that permit operation of the related facility on a profitable basis. In addition, the Company believes many of its competitors have well-established relationships with the Company's current and potential suppliers, lenders, customers and have extensive knowledge of its target markets. As a result, these competitors may be able to respond more quickly to evolving industry standards and changing customer requirements than the Company will be able to. Adoption of technology more advanced than the Company's could reduce its competitors' power production costs resulting in their having a lower cost structure than is achievable with the technologies currently employed by the Company and adversely affect its ability to compete for offtake agreement renewals. If the Company is unable to replace an expiring or terminated offtake agreement, the affected facility may temporarily or permanently cease operations. External events, such as a severe economic downturn, could also impair the ability of some counterparties to the Company's offtake agreements and other customer agreements to pay for energy and/or other products and services received.

The Company's inability to enter into new or replacement offtake agreements or to compete successfully against current and future competitors in the markets in which the Company operates could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows.

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Certain of the Company's assets operate, wholly or partially, without long-term power sale agreements.

The generation capacity of the Company’s Dover and Paxton thermal generation assets has been sold through May 2018 in the annual Base Residual Auction, or BRA, under the PJM-administered RPM. Capacity revenue beginning in June 2018 is not yet determined. These facilities do not have offtake agreements for energy sales and sell energy through NRG Power Marketing LLC, an NRG affiliate, into the bid-based auction market for energy administered by PJM based on economic dispatch of their units. If the Company is unable to sell available capacity from those facilities beginning in June 2018 through the BRA or one of the other RPM capacity auctions or is unable to enter into a offtake agreement or otherwise sell unallocated or unsold capacity at favorable terms, there may be a material adverse effect on the Company's business, financial condition, results of operations and cash flows.

In addition, the Alta X and XI facilities will operate as merchant facilities without long-term power sales agreements for 2015, and therefore are exposed to market fluctuations. Without the benefit of long-term power sales agreements for these assets, the Company cannot be sure that it will be able to sell any or all of the power generated by these facilities at commercially attractive rates or that these facilities will be able to operate profitably. This could lead to future impairments of the Company's property, plant and equipment, which could have a material adverse effect on the Company's results of operations, financial condition or cash flows.

A portion of the steam and chilled water produced by the Company's thermal assets is sold at regulated rates, and the revenue earned by the Company's GenConn assets is established each year in a rate case; accordingly, the profitability of these assets is dependent on regulatory approval.

Approximately 375 net MWt of capacity from certain of the Company's thermal assets are sold at rates approved by one or more federal or state regulatory commissions, including the Pennsylvania Public Utility Commission and the California Public Utilities Commission for the thermal assets. Similarly, the revenues related to approximately 380 MW of capacity from the GenConn assets are established each year by the Connecticut Public Utilities Regulatory Authority. While such regulatory oversight is generally premised on the recovery of prudently incurred costs and a reasonable rate of return on invested capital, the rates that the Company may charge, or the revenue that the Company may earn with respect to this capacity are subject to authorization of the applicable regulatory authorities. There can be no assurance that such regulatory authorities will consider all of the costs to have been prudently incurred or that the regulatory process by which rates or revenues are determined will always result in rates or revenues that achieve full recovery of costs or an adequate return on the Company's capital investments. While the Company's rates and revenues are generally established based on an analysis of costs incurred in a base year, the rates the Company is allowed to charge, and the revenues the Company is authorized to earn, may or may not match the costs at any given time. If the Company's costs are not adequately recovered through these regulatory processes, it could have a material adverse effect on the business, financial condition, results of operations and cash flows.

Supplier and/ or customer concentration at certain of the Company's facilities may expose the Company to significant financial credit or performance risks.

The Company often relies on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel, equipment, technology and/or other services required for the operation of certain facilities. In addition, certain of the Company's suppliers provide long-term warranties with respect to the performance of their products or services. If any of these suppliers cannot perform under their agreements with the Company, or satisfy their related warranty obligations, the Company will need to utilize the marketplace to provide or repair these products and services. There can be no assurance that the marketplace can provide these products and services as, when and where required. The Company may not be able to enter into replacement agreements on favorable terms or at all. If the Company is unable to enter into replacement agreements to provide for fuel, equipment, technology and other required services, it would seek to purchase the related goods or services at market prices, exposing the Company to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price. The Company may also be required to make significant capital contributions to remove, replace or redesign equipment that cannot be supported or maintained by replacement suppliers, which could have a material adverse effect on the business, financial condition, results of operations, credit support terms and cash flows.

In addition, potential or existing customers at the Company’s district energy centers and combined heat and power plants, or the Energy Centers, may opt for on-site systems in lieu of using the Company’s Energy Centers, either due to corporate policies regarding the allocation of capital, unique situations where an on-site system might in fact prove more efficient, because of previously committed capital in systems that are already on-site, or otherwise. At times, the Company relies on a single customer or a few customers to purchase all or a significant portion of a facility's output, in some cases under long-term agreements that account for a substantial percentage of the anticipated revenue from a given facility.

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The failure of any supplier to fulfill its contractual obligations to the Company or the Company’s loss of potential or existing customers could have a material adverse effect on its financial results. Consequently, the financial performance of the Company's facilities is dependent on the credit quality of, and continued performance by, the Company's suppliers and vendors and the Company’s ability to solicit and retain customers.

The Company currently owns, and in the future may acquire, certain assets in which the Company has limited control over management decisions and its interests in such assets may be subject to transfer or other related restrictions.

The Company has limited control over the operation of GenConn, Avenal and CVSR because the Company beneficially owns 49.95%, 49.95% and 48.95%, respectively, of the membership interests in such assets. The Company may seek to acquire additional assets in which it owns less than a majority of the related membership interests in the future. In these investments, the Company will seek to exert a degree of influence with respect to the management and operation of assets in which it owns less than a majority of the membership interests by negotiating to obtain positions on management committees or to receive certain limited governance rights, such as rights to veto significant actions. However, the Company may not always succeed in such negotiations. The Company may be dependent on its co-venturers to operate such assets. The Company's co-venturers may not have the level of experience, technical expertise, human resources management and other attributes necessary to operate these assets optimally. In addition, conflicts of interest may arise in the future between theCompany and its stockholders, on the one hand, and the Company's co-venturers, on the other hand, where the Company's co-venturers' business interests are inconsistent with the interests of the Company and its stockholders. Further, disagreements or disputes between the Company and its co-venturers could result in litigation, which could increase expenses and potentially limit the time and effort the Company's officers and directors are able to devote to the business.

The approval of co-venturers also may be required for the Company to receive distributions of funds from assets or to sell, pledge, transfer, assign or otherwise convey its interest in such assets, or for the Company to acquire NRG's interests in such co-ventures as an initial matter. Alternatively, the Company's co-venturers may have rights of first refusal or rights of first offer in the event of a proposed sale or transfer of the Company's interests in such assets. These restrictions may limit the price or interest level for interests in such assets, in the event the Company wants to sell such interests.

Furthermore, certain of the Company's facilities are operated by third-party operators, such as First Solar. To the extent that third-party operators do not fulfill their obligations to manage operations of the facilities or are not effective in doing so, the amount of cash available for distribution may be adversely affected.

The Company's assets are exposed to risks inherent in the use of interest rate swaps and forward fuel purchase contracts and the Company may be exposed to additional risks in the future if it utilizes other derivative instruments.

The Company uses interest rate swaps to manage interest rate risk. In addition, the Company uses forward fuel purchase contracts to hedge its limited commodity exposure with respect to the Company's district energy assets. If the Company elects to enter into such commodity hedges, the related asset could recognize financial losses on these arrangements as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. If actively quoted market prices and pricing information from external sources are not available, the valuation of these contracts would involve judgment or the use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts. If the values of these financial contracts change in a manner that the Company does not anticipate, or if a counterparty fails to perform under a contract, it could harm the business, financial condition, results of operations and cash flows.

The Company's business is subject to restrictions resulting from environmental, health and safety laws and regulations.

The Company is subject to various federal, state and local environmental and health and safety laws and regulations. In addition, the Company may be held primarily or jointly and severally liable for costs relating to the investigation and clean-up of any property where there has been a release or threatened release of a hazardous regulated material as well as other affected properties, regardless of whether the Company knew of or caused the release. In addition to these costs, which are typically not limited by law or regulation and could exceed an affected property's value, the Company could be liable for certain other costs, including governmental fines and injuries to persons, property or natural resources. Further, some environmental laws provide for the creation of a lien on a contaminated site in favor of the government as security for damages and any costs the government incurs in connection with such contamination and associated clean-up. Although the Company generally requires its operators to undertake to indemnify it for environmental liabilities they cause, the amount of such liabilities could exceed the financial ability of the operator to indemnify the Company. The presence of contamination or the failure to remediate contamination may adversely affect the Company's ability to operate the business.

21

The Company does not own all of the land on which its power generation or thermal assets are located, which could result in disruption to its operations.

The Company does not own all of the land on which its power generation or thermal assets are located and the Company is, therefore, subject to the possibility of less desirable terms and increased costs to retain necessary land use if it does not have valid leases or rights-of-way or if such rights-of-way lapse or terminate. Although the Company has obtained rights to construct and operate these assets pursuant to related lease arrangements, the rights to conduct those activities are subject to certain exceptions, including the term of the lease arrangement. The loss of these rights, through the Company's inability to renew right-of-way contracts or otherwise, may adversely affect the Company's ability to operate its generation and thermal infrastructure assets.

The electric generation business is subject to substantial governmental regulation and may be adversely affected by changes in laws or regulations, as well as liability under, or any future inability to comply with, existing or future regulations or other legal requirements.

The Company's electric generation business is subject to extensive U.S. federal, state and local laws and regulation. Compliance with the requirements under these various regulatory regimes may cause the Company to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability. Public utilities under the FPA are required to obtain FERC acceptance of their rate schedules for wholesale sales of electric energy, capacity and ancillary services. Except for generating facilities within the footprint of ERCOT which are regulated by the PUCT, all of the Company’s assets make wholesale sales of electric energy, capacity and ancillary services in interstate commerce and are public utilities for purposes of the FPA, unless otherwise exempt from such status. FERC's orders that grant market-based rate authority to wholesale power marketers reserve the right to revoke or revise that authority if FERC subsequently determines that the seller can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, public utilities are subject to FERC reporting requirements that impose administrative burdens and that, if violated, can expose the company to criminal and civil penalties or other risks.

The Company's market-based sales will be subject to certain rules prohibiting manipulative or deceptive conduct, and if any of the Company's generating companies are deemed to have violated those rules, they will be subject to potential disgorgement of profits associated with the violation, penalties, suspension or revocation of market based rate authority. If such generating companies were to lose their market-based rate authority, such companies would be required to obtain FERC's acceptance of a cost-of-service rate schedule and could become subject to the significant accounting, record-keeping, and reporting requirements that are imposed on utilities with cost- based rate schedules. This could have a material adverse effect on the rates the Company is able to charge for power from its facilities.

Most of the Company's assets are operating as EWGs as defined under the PUHCA, or QFs as defined under the PURPA, as amended, and therefore are exempt from certain regulation under the PUHCA and the PURPA. If a facility fails to maintain its status as an EWG or a QF or there are legislative or regulatory changes revoking or limiting the exemptions to the PUHCA, then the Company may be subject to significant accounting, record-keeping, access to books and records and reporting requirements and failure to comply with such requirements could result in the imposition of penalties and additional compliance obligations.

Substantially all of the Company's generation assets are also subject to the reliability standards promulgated by the designated Electric Reliability Organization (currently the North American Electric Reliability Corporation, or NERC) and approved by FERC. If the Company fails to comply with the mandatory reliability standards, it could be subject to sanctions, including substantial monetary penalties and increased compliance obligations. The Company will also be affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules that occur in the existing regional markets operated by RTOs or ISOs, such as PJM. The RTOs/ISOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, mitigation, including price limitations, offer caps, and other mechanisms to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have a material adverse effect on the profitability of the Company's generation facilities acquired in the future that sell energy, capacity and ancillary products into the wholesale power markets. The regulatory environment for electric generation has undergone significant changes in the last several years due to state and federal policies affecting wholesale competition and the creation of incentives for the addition of large amounts of new renewable generation and, in some cases, transmission assets. These changes are ongoing and the Company cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on the Company's business. In addition, in some of these markets, interested parties have proposed to re-regulate the markets or require divestiture of electric generation assets by asset owners or operators to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process. If competitive restructuring of the electric power markets is reversed, discontinued, or delayed, the Company's business prospects and financial results could be negatively impacted.

22

The Company is subject to environmental laws and regulations that impose extensive and increasingly stringent requirements on its operations, as well as potentially substantial liabilities arising out of environmental contamination.

The Company's assets are subject to numerous and significant federal, state and local laws, including statutes, regulations, guidelines, policies, directives and other requirements governing or relating to, among other things: protection of wildlife, including threatened and endangered species; air emissions; discharges into water; water use; the storage, handling, use, transportation and distribution of dangerous goods and hazardous, residual and other regulated materials, such as chemicals; the prevention of releases of hazardous materials into the environment; the prevention, presence and remediation of hazardous materials in soil and groundwater, both on and offsite; land use and zoning matters; and workers' health and safety matters. The Company's facilities could experience incidents, malfunctions and other unplanned events that could result in spills or emissions in excess of permitted levels and result in personal injury, penalties and property damage. As such, the operation of the Company's facilities carries an inherent risk of environmental, health and safety liabilities (including potential civil actions, compliance or remediation orders, fines and other penalties), and may result in the assets being involved from time to time in administrative and judicial proceedings relating to such matters. The Company has implemented environmental, health and safety management programs designed to continually improve environmental, health and safety performance. Environmental laws and regulations have generally become more stringent over time, and the Company expects this trend to continue. Significant costs may be incurred for capital expenditures under environmental programs to keep the assets compliant with such environmental laws and regulations. If it is not economical to make those expenditures, it may be necessary to retire or mothball facilities or restrict or modify the Company's operations to comply with more stringent standards. These environmental requirements and liabilities could have a material adverse effect on the business, financial condition, results of operations and cash flows.

Risks that are beyond the Company's control, including but not limited to acts of terrorism or related acts of war, natural disaster, hostile cyber intrusions or other catastrophic events, could have a material adverse effect on the business, financial condition, results of operations and cash flows.

The Company's generation facilities that were acquired or those that the Company otherwise acquires or constructs and the facilities of third parties on which they rely may be targets of terrorist activities, as well as events occurring in response to or in connection with them, that could cause environmental repercussions and/or result in full or partial disruption of the facilities ability to generate, transmit, transport or distribute electricity or natural gas. Strategic targets, such as energy-related facilities, may be at greater risk of future terrorist activities than other domestic targets. Hostile cyber intrusions, including those targeting information systems as well as electronic control systems used at the generating plants and for the related distribution systems, could severely disrupt business operations and result in loss of service to customers, as well as create significant expense to repair security breaches or system damage.

Furthermore, certain of the Company's power generation thermal assets are located in active earthquake zones in California and Arizona, and certain project companies and suppliers conduct their operations in the same region or in other locations that are susceptible to natural disasters. In addition, California and some of the locations where certain suppliers are located, from time to time, have experienced shortages of water, electric power and natural gas. The occurrence of a natural disaster, such as an earthquake, drought, flood or localized extended outages of critical utilities or transportation systems, or any critical resource shortages, affecting the Company or its suppliers, could cause a significant interruption in the business, damage or destroy the Company's facilities or those of its suppliers or the manufacturing equipment or inventory of the Company's suppliers. Any such terrorist acts, environmental repercussions or disruptions or natural disasters could result in a significant decrease in revenues or significant reconstruction or remediation costs, beyond what could be recovered through insurance policies, which could have a material adverse effect on the business, financial condition, results of operations and cash flows.

Government regulations providing incentives for renewable generation could change at any time and such changes may negatively impact the Company's growth strategy.

The Company's growth strategy depends in part on government policies that support renewable generation and enhance the economic viability of owning renewable electric generation assets. Renewable generation assets currently benefit from various federal, state and local governmental incentives such as ITCs, cash grants in lieu of ITCs, loan guarantees, RPS, programs, modified accelerated cost-recovery system of depreciation and bonus depreciation. For example, the U.S. Internal Revenue Code of 1986, as amended, provides an ITC of 30% of the cost-basis of an eligible resource, including solar energy facilities placed in service prior to the end of 2016, which percentage is currently scheduled to be reduced to 10% for solar energy systems placed in service after December 31, 2016.

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Many states have adopted RPS programs mandating that a specified percentage of electricity sales come from eligible sources of renewable energy. However, the regulations that govern the RPS programs, including pricing incentives for renewable energy, or reasonableness guidelines for pricing that increase valuation compared to conventional power (such as a projected value for carbon reduction or consideration of avoided integration costs), may change. If the RPS requirements are reduced or eliminated, it could lead to fewer future power contracts or lead to lower prices for the sale of power in future power contracts, which could have a material adverse effect on the Company's future growth prospects.

Such material adverse effects may result from decreased revenues, reduced economic returns on certain project company investments, increased financing costs, and/or difficulty obtaining financing. Furthermore, the ARRA included incentives to encourage investment in the renewable energy sector, such as cash grants in lieu of ITCs, bonus depreciation and expansion of the U.S. DOE loan guarantee program. It is uncertain what loan guarantees may be made by the U.S. DOE loan guarantee program in the future. In addition, the cash grant in lieu of ITCs program only applies to facilities that commenced construction prior to December 31, 2011, which commencement date may be determined in accordance with the safe harbor if more than 5% of the total cost of the eligible property was paid or incurred by December 31, 2011.

If the Company is unable to utilize various federal, state and local government incentives to acquire additional renewable assets in the future, or the terms of such incentives are revised in a manner that is less favorable to the Company, it may suffer a material adverse effect on the business, financial condition, results of operations and cash flows.

The Company relies on electric interconnection and transmission facilities that it does not own or control and that are subject to transmission constraints within a number of the Company's regions. If these facilities fail to provide the Company with adequate transmission capacity, it may be restricted in its ability to deliver electric power to its customers and may either incur additional costs or forego revenues.

The Company depends on electric interconnection and transmission facilities owned and operated by others to deliver the wholesale power it will sell from its electric generation assets to its customers. A failure or delay in the operation or development of these interconnection or transmission facilities or a significant increase in the cost of the development of such facilities could result in lost revenues. Such failures or delays could limit the amount of power the Company's operating facilities deliver or delay the completion of the Company's construction projects. Additionally, such failures, delays or increased costs could have a material adverse effect on the business, financial condition and results of operations. If a region's power transmission infrastructure is inadequate, the Company's recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have a sufficient incentive to invest in expansion of transmission infrastructure. The Company also cannot predict whether interconnection and transmission facilities will be expanded in specific markets to accommodate competitive access to those markets. In addition, certain of the Company's operating facilities' generation of electricity may be curtailed without compensation due to transmission limitations or limitations on the electricity grid's ability to accommodate intermittent electricity generating sources, reducing the Company's revenues and impairing its ability to capitalize fully on a particular facility's generating potential. Such curtailments could have a material adverse effect on the business, financial condition, results of operations and cash flows. Furthermore, economic congestion on transmission networks in certain of the markets in which the Company operates may occur and the Company may be deemed responsible for congestion costs. If the Company were liable for such congestion costs, its financial results could be adversely affected.

The Company's costs, results of operations, financial condition and cash flows could be adversely impacted by the disruption of the fuel supplies necessary to generate power at its conventional and thermal power generation facilities.

Delivery of fossil fuels to fuel the Company's conventional and thermal generation facilities is dependent upon the infrastructure (including natural gas pipelines) available to serve each such generation facility as well as upon the continuing financial viability of contractual counterparties. As a result, the Company is subject to the risks of disruptions or curtailments in the production of power at these generation facilities if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.

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Risks Related to the Relationship with NRG

NRG is the Company's controlling stockholder and exercises substantial influence over the Company. The Company is highly dependent on NRG.

NRG owns all of the Company's outstanding Class B common stock. Each share of the Company's outstanding Class B common stock is entitled to one vote per share. As a result of its ownership of the Class B common stock, NRG owns 55.3% of the combined voting power of the Company's Class A and Class B common stock as of December 31, 2014. NRG has also expressed its intention to maintain a controlling interest in the Company. As a result of this ownership, NRG has a substantial influence on the Company's affairs and its voting power will constitute a large percentage of any quorum of the Company's stockholders voting on any matter requiring the approval of the Company's stockholders. Such matters include the election of directors, the adoption of amendments to the Company's amended and restated certificate of incorporation and bylaws and approval of mergers or sale of all or substantially all of its assets. This concentration of ownership may also have the effect of delaying or preventing a change in control of the Company or discouraging others from making tender offers for their shares. In addition, NRG will have the right to appoint all of the Company's directors. NRG may cause corporate actions to be taken even if their interests conflict with the interests of the Company's other stockholders (including holders of the Company's Class A common stock).

Furthermore, the Company depends on the management and administration services provided by or under the direction of NRG under the Management Services Agreement. NRG personnel and support staff that provide services to the Company under the Management Services Agreement are not required to, and the Company does not expect that they will, have as their primary responsibility the management and administration of the Company or to act exclusively for the Company and the Management Services Agreement does not require any specific individuals to be provided by NRG. Under the Management Services Agreement, NRG has the discretion to determine which of its employees perform assignments required to be provided to the Company. Any failure to effectively manage the Company's operations or to implement its strategy could have a material adverse effect on the business, financial condition, results of operations and cash flows. The Management Services Agreement will continue in perpetuity, until terminated in accordance with its terms.

The Company also depends upon NRG for the provision of management and administration services at all of the Company's facilities. Any failure by NRG to perform its requirements under these arrangements or the failure by the Company to identify and contract with replacement service providers, if required, could adversely affect the operation of the Company's facilities and have a material adverse effect on the business, financial condition, results of operations and cash flows.

The Company may not be able to consummate future acquisitions from NRG.

The Company's ability to grow through acquisitions depends, in part, on NRG's ability to identify and present the Company with acquisition opportunities. NRG established the Company to hold and acquire a diversified suite of power generating assets in the United States and its territories. Although NRG has agreed to grant the Company a right of first offer with respect to certain power generation assets that NRG may elect to sell in the future, NRG will be under no obligation to sell the NRG ROFO Assets or the EME-NYLD-Eligible Assets or to accept any related offer from us. Furthermore, NRG has no obligation to source acquisition opportunities specifically for the Company. In addition, NRG has not agreed to commit any minimum level of dedicated resources for the pursuit of renewable power-related acquisitions. There are a number of factors which could materially and adversely impact the extent to which suitable acquisition opportunities are made available from NRG, including:

• the same professionals within NRG's organization that are involved in acquisitions that are suitable for the Company have responsibilities within NRG's broader asset management business, which may include sourcing acquisition opportunities for NRG. Limits on the availability of such individuals will likewise result in a limitation on the availability of acquisition opportunities for the Company; and

• in addition to structural limitations, the question of whether a particular asset is suitable is highly subjective and is dependent on a number of factors including an assessment by NRG relating to the Company's liquidity position at the time, the risk profile of the opportunity and its fit with the balance of the Company's then current operations and other factors. If NRG determines that an opportunity is not suitable for the Company, it may still pursue such opportunity on its own behalf, or on behalf of another NRG affiliate.

In making these determinations, NRG may be influenced by factors that result in a misalignment or conflict of interest.

25

The departure of some or all of NRG's employees could prevent the Company from achieving its objectives.

The Company depends on the diligence, skill and business contacts of NRG's professionals and the information and opportunities they generate during the normal course of their activities. Furthermore, approximately 31% of NRG's employees at the Company generation plants are covered by collective bargaining agreements as of December 31, 2014. The Company's future success will depend on the continued service of these individuals, who are not obligated to remain employed with NRG, or otherwise successfully renegotiate their collective bargaining agreements when such agreements expire or otherwise terminate. NRG has experienced departures of key professionals and personnel in the past and may do so in the future, and the Company cannot predict the impact that any such departures will have on its ability to achieve its objectives. The departure of a significant number of NRG's professionals or a material portion of the NRG employees who work at any of the Company's facilities for any reason, or the failure to appoint qualified or effective successors in the event of such departures, could have a material adverse effect on the Company's ability to achieve its objectives. The Management Services Agreement does not require NRG to maintain the employment of any of its professionals or to cause any particular professional to provide services to the Company or on its behalf.

The Company's organizational and ownership structure may create significant conflicts of interest that may be resolved in a manner that is not in the best interests of the Company or the best interests of holders of its Class A common stock and that may have a material adverse effect on the business, financial condition, results of operations and cash flows.

The Company's organizational and ownership structure involves a number of relationships that may give rise to certain conflicts of interest between the Company and holders of its Class A common stock, on the one hand, and NRG, on the other hand. The Company has entered into a Management Services Agreement with NRG. Each of the Company's executive officers are a shared NRG executive and devote his or her time to both the Company and NRG as needed to conduct the respective businesses pursuant to the Management Services Agreement. Although the Company's directors and executive officers owe fiduciary duties to the Company's stockholders, these shared NRG executives have fiduciary and other duties to NRG, which duties may be inconsistent with the Company's best interests and holders of the Company's Class A common stock. In addition, NRG and its representatives, agents and affiliates have access to the Company's confidential information. Although some of these persons are subject to confidentiality obligations pursuant to confidentiality agreements or implied duties of confidence, the Management Services Agreement does not contain general confidentiality provisions.

Additionally, all of the Company's executive officers continue to have economic interests in NRG and, accordingly, the benefit to NRG from a transaction between the Company and NRG will proportionately inure to their benefit as holders of economic interests in NRG. NRG is a related party under the applicable securities laws governing related party transactions and may have interests which differ from the Company's interests or those of holders of the Class A common stock, including with respect to the types of acquisitions made, the timing and amount of dividends by the Company, the reinvestment of returns generated by the Company's operations, the use of leverage when making acquisitions and the appointment of outside advisors and service providers. Any material transaction between the Company and NRG will be subject to the Company's related party transaction policy, which will require prior approval of such transaction by the Company's corporate committees. Those of the Company's executive officers who have economic interests in NRG may be conflicted when advising the Company's corporate committees or otherwise participating in the negotiation or approval of such transactions. These executive officers have significant project- and industry-specific expertise that could prove beneficial to the Company's decision-making process and the absence of such strategic guidance could have a material adverse effect on the corporate committees' ability to evaluate any such transaction. Furthermore, the creation of corporate committees and the Company's related party transaction approval policy may not insulate the Company from derivative claims related to related party transactions and the conflicts of interest described in this risk factor. Regardless of the merits of such claims, the Company may be required to expend significant management time and financial resources in the defense thereof. Additionally, to the extent the Company fails to appropriately deal with any such conflicts, it could negatively impact the Company's reputation and ability to raise additional funds and the willingness of counterparties to do business with the Company, all of which could have a material adverse effect on the business, financial condition, results of operations and cash flows.

26

The Company may be unable or unwilling to terminate the Management Services Agreement.

The Management Services Agreement provides that the Company may terminate the agreement upon 30 days prior written notice to NRG upon the occurrence of any of the following: (i) NRG defaults in the performance or observance of any material term, condition or covenant contained therein in a manner that results in material harm to the Company and the default continues unremedied for a period of 30 days after written notice thereof is given to NRG; (ii) NRG engages in any act of fraud, misappropriation of funds or embezzlement that results in material harm to the Company; (iii) NRG is grossly negligent in the performance of its duties under the agreement and such negligence results in material harm to the Company; or (iv) upon the happening of certain events relating to the bankruptcy or insolvency of NRG. Furthermore, if the Company requests an amendment to the scope of services provided by NRG under the Management Services Agreement and is not able to agree with NRG as to a change to the service fee resulting from a change in the scope of services within 180 days of the request, the Company will be able terminate the agreement upon 30 days prior notice to NRG. The Company will not be able to terminate the agreement for any other reason, including if NRG experiences a change of control, and the agreement continues in perpetuity, until terminated in accordance with its terms. If NRG's performance does not meet the expectations of investors, and the Company is unable to terminate the Management Services Agreement, the market price of the Class A common stock could suffer.

If NRG terminates the Management Services Agreement or defaults in the performance of its obligations under the agreement the Company may be unable to contract with a substitute service provider on similar terms, or at all.

The Company relies on NRG to provide it with management services under the Management Services Agreement and will not have independent executive or senior management personnel. The Management Services Agreement provides that NRG may terminate the agreement upon 180 days prior written notice of termination to the Company if it defaults in the performance or observance of any material term, condition or covenant contained in the agreement in a manner that results in material harm and the default continues unremedied for a period of 30 days after written notice of the breach is given. If NRG terminates the Management Services Agreement or defaults in the performance of its obligations under the agreement, the Company may be unable to contract with a substitute service provider on similar terms or at all, and the costs of substituting service providers may be substantial. In addition, in light of NRG's familiarity with the Company's assets, a substitute service provider may not be able to provide the same level of service due to lack of pre-existing synergies. If the Company cannot locate a service provider that is able to provide substantially similar services as NRG does under the Management Services Agreement on similar terms, it would likely have a material adverse effect on the business, financial condition, results of operation and cash flows.

The liability of NRG is limited under the Company's arrangements with it and the Company has agreed to indemnify NRG against claims that it may face in connection with such arrangements, which may lead it to assume greater risks when making decisions relating to the Company than it otherwise would if acting solely for its own account.

Under the Management Services Agreement, NRG does not assume any responsibility other than to provide or arrange for the provision of the services described in the Management Services Agreement in good faith. In addition, under the Management Services Agreement, the liability of NRG and its affiliates will be limited to the fullest extent permitted by law to conduct involving bad faith, fraud, willful misconduct or gross negligence or, in the case of a criminal matter, action that was known to have been unlawful. In addition, the Company has agreed to indemnify NRG to the fullest extent permitted by law from and against any claims, liabilities, losses, damages, costs or expenses incurred by an indemnified person or threatened in connection with the Company's operations, investments and activities or in respect of or arising from the Management Services Agreement or the services provided by NRG, except to the extent that the claims, liabilities, losses, damages, costs or expenses are determined to have resulted from the conduct in respect of which such persons have liability as described above. These protections may result in NRG tolerating greater risks when making decisions than otherwise would be the case, including when determining whether to use leverage in connection with acquisitions. The indemnification arrangements to which NRG is a party may also give rise to legal claims for indemnification that are adverse to the Company and holders of its common stock.

27

Risks Inherent in an Investment in the Company

The Company may not be able to continue paying comparable or growing cash dividends to holders of its common stock in the future.

              The amount of cash available for distribution principally depends upon the amount of cash the Company generates from its operations, which will fluctuate from quarter to quarter based on, among other things:

• the level and timing of capital expenditures the Company makes;

• the completion of ongoing construction activities on time and on budget;

• the level of operating and general and administrative expenses, including reimbursements to NRG for services provided to the Company in accordance with the Management Services Agreement;

• seasonal variations in revenues generated by the business;

• debt service requirements and other liabilities;

• fluctuations in working capital needs;

• the Company's ability to borrow funds and access capital markets;

• restrictions contained in the Company's debt agreements (including project-level financing and the Company's revolving credit facility); and

• other business risks affecting cash levels.

              As a result of all these factors, the Company cannot guarantee that it will have sufficient cash generated from operations to pay a specific level of cash dividends to holders of its common stock. Furthermore, holders of the Company's common stock should be aware that the amount of cash available for distribution depends primarily on cash flow, and is not solely a function of profitability, which is affected by non-cash items.

    The Company may incur other expenses or liabilities during a period that could significantly reduce or eliminate its cash available for distribution and, in turn, impair its ability to pay dividends to holders of the Company's common stock during the period. Because the Company is a holding company, its ability to pay dividends on the Company's common stock is limited by restrictions on the ability of the Company's subsidiaries to pay dividends or make other distributions to the Company, including restrictions under the terms of the agreements governing project-level financing. The project-level financing agreements generally prohibit distributions from the project entities prior to COD and thereafter prohibit distributions to the Company unless certain specific conditions are met, including the satisfaction of financial ratios. The Company's amended and restated revolving credit facility will also restrict the Company's ability to declare and pay dividends if an event of default has occurred and is continuing or if the payment of the dividend would result in an event of default.

              NRG Yield LLC's cash available for distribution will likely fluctuate from quarter to quarter, in some cases significantly, due to seasonality. As result, the Company may cause NRG Yield LLC to reduce the amount of cash it distributes to its members in a particular quarter to establish reserves to fund distributions to its members in future periods for which the cash distributions the Company would otherwise receive from NRG Yield LLC would otherwise be insufficient to fund its quarterly dividend. If the Company fails to cause NRG Yield LLC to establish sufficient reserves, the Company may not be able to maintain its quarterly dividend with a respect to a quarter adversely affected by seasonality.

              Finally, dividends to holders of the Company's common stock will be paid at the discretion of the Company's board of directors. The Company's board of directors may decrease the level of or entirely discontinue payment of dividends.

The Company is a holding company and its only material asset is its interest in NRG Yield LLC, and the Company is accordingly dependent upon distributions from NRG Yield LLC and its subsidiaries to pay dividends and taxes and other expenses.

              The Company is a holding company and has no material assets other than its ownership of membership interests in NRG Yield LLC, a holding company that has no material assets other than its interest in NRG Yield Operating LLC, whose sole material assets are the project companies. None of the Company, NRG Yield LLC or NRG Yield Operating LLC has any independent means of generating revenue. The Company intends to cause NRG Yield Operating LLC's subsidiaries to make distributions to NRG Yield Operating LLC and, in turn, make distributions to NRG Yield LLC, and, in turn, to make distributions to the Company in an amount sufficient to cover all applicable taxes payable and dividends, if any, declared by the Company. To the extent that the Company needs funds for a quarterly cash dividend to holders of the Company's common stock or otherwise, and NRG Yield Operating LLC or NRG Yield LLC is restricted from making such distributions under applicable law or regulation or is otherwise unable to provide such funds (including as a result of NRG Yield Operating LLC's operating subsidiaries being unable to make distributions), it could materially adversely affect the Company's liquidity and financial condition and limit the Company's ability to pay dividends to holders of the Company's common stock.

28

The Company has a limited operating history and as a result there is no assurance the Company can operate on a profitable basis.

              The Company has a limited operating history on which to base an evaluation of its business and prospects. The Company's prospects must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stages of operation. The Company cannot assure investors that it will be successful in addressing the risks the Company may encounter, and the Company's failure to do so could have a material adverse effect on its business, financial condition, results of operations and cash flows.

Market interest rates may have an effect on the value of the Company's Class A common stock.

              One of the factors that will influence the price of shares of the Company's Class A common stock will be the effective dividend yield of such shares (i.e., the yield as a percentage of the then market price of the Company's shares) relative to market interest rates. An increase in market interest rates, which are currently at low levels relative to historical rates, may lead investors of shares of the Company's Class A common stock to expect a higher dividend yield and the Company's inability to increase its dividend as a result of an increase in borrowing costs, insufficient cash available for distribution or otherwise, could result in selling pressure on, and a decrease in the market price of the Company's Class A common stock as investors seek alternative investments with higher yield.

If the Company is deemed to be an investment company, the Company may be required to institute burdensome compliance requirements and the Company's activities may be restricted, which may make it difficult for the Company to complete strategic acquisitions or effect combinations.

              If the Company is deemed to be an investment company under the Investment Company Act of 1940, or the Investment Company Act, the Company's business would be subject to applicable restrictions under the Investment Company Act, which could make it impracticable for the Company to continue its business as contemplated.

              The Company believes it is not an investment company under Section 3(b)(1) of the Investment Company Act because the Company is primarily engaged in a non-investment company business. The Company intends to conduct its operations so that the Company will not be deemed an investment company. However, if the Company were to be deemed an investment company, restrictions imposed by the Investment Company Act, including limitations on the Company's capital structure and the Company's ability to transact with affiliates, could make it impractical for the Company to continue its business as contemplated.

Market volatility may affect the price of the Company's Class A common stock.

              The market price of the Company's Class A common stock may fluctuate significantly in response to a number of factors, most of which the Company cannot predict or control, including general market and economic conditions, disruptions, downgrades, credit events and perceived problems in the credit markets; actual or anticipated variations in its quarterly operating results or dividends; changes in the Company's investments or asset composition; write-downs or perceived credit or liquidity issues affecting the Company's assets; market perception of NRG, the Company's business and the Company's assets; the Company's level of indebtedness and/or adverse market reaction to any indebtedness that the Company may incur in the future; the Company's ability to raise capital on favorable terms or at all; loss of any major funding source; the termination of the Management Services Agreement or additions or departures of NRG's key personnel; changes in market valuations of similar power generation companies; and speculation in the press or investment community regarding the Company or NRG.

              Securities markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. Any broad market fluctuations may adversely affect the trading price of the Company's Class A common stock.

The Company is a "controlled company," controlled by NRG, whose interest in the Company's business may be different from the holders of the Company's common stock.

              As of December 31, 2014, NRG controls 55.3% of the Company's combined voting power and is able to elect all of the Company's board of directors. As a result, the Company is considered a "controlled company" for the purposes of the NYSE listing requirements. As a "controlled company," the Company is permitted to, and the Company may, opt out of the NYSE listing requirements that would require (i) a majority of the members of the Company's board of directors to be independent, (ii) that the Company establish a compensation committee and a nominating and governance committee, each comprised entirely of independent directors, or (iii) that the compensation of the Company's executive officers and nominees for directors are determined or recommended to the Company's board of directors by the independent members of the Company's board of directors. The NYSE listing requirements are intended to ensure that directors who meet the independence standard are free of any conflicting interest that could influence their actions as directors.

29

Provisions of the Company's charter documents or Delaware law could delay or prevent an acquisition of the Company, even if the acquisition would be beneficial to holders of the Company's Class A common stock, and could make it more difficult to change management.

              Provisions of the Company's amended and restated certificate of incorporation and bylaws may discourage, delay or prevent a merger, acquisition or other change in control that holders of the Company's Class A common stock may consider favorable, including transactions in which such stockholders might otherwise receive a premium for their shares. This is because these provisions may prevent or frustrate attempts by stockholders to replace or remove members of the Company's management. These provisions include:

• a prohibition on stockholder action through written consent;

• a requirement that special meetings of stockholders be called upon a resolution approved by a majority of the Company's directors then in office;

• advance notice requirements for stockholder proposals and nominations; and

• the authority of the board of directors to issue preferred stock with such terms as the board of directors may determine.

              Section 203 of the DGCL prohibits a publicly held Delaware corporation from engaging in a business combination with an interested stockholder, generally a person that together with its affiliates owns or within the last three years has owned 15% of voting stock, for a period of three years after the date of the transaction in which the person became an interested stockholder, unless the business combination is approved in a prescribed manner.  Additionally, the Company's amended and restated certificate of incorporation prohibits any person and any of its associate or affiliate companies in the aggregate, public utility or holding company from acquiring, other than secondary market transactions, an amount of the Company's Class A common stock sufficient to result in a transfer of control without the prior written consent of the Company's board of directors. Any such change of control, in addition to prior approval from the Company's board of directors, would require prior authorization from FERC. Similar restrictions may apply to certain purchasers of the Company's securities which are holding companies regardless of whether the Company's securities are purchased in offerings by the Company or NRG, in open market transactions or otherwise. A purchaser of the Company's securities which is a holding company will need to determine whether a given purchase of the Company's securities may require prior FERC approval.

Investors may experience dilution of ownership interest due to the future issuance of additional shares of the Company's Class A common stock.

              The Company is in a capital intensive business, and may not have sufficient funds to finance the growth of the Company's business, future acquisitions or to support the Company's projected capital expenditures. As a result, the Company may require additional funds from further equity or debt financings, including tax equity financing transactions or sales of preferred shares or convertible debt to complete future acquisitions, expansions and capital expenditures and pay the general and administrative costs of the Company's business. In the future, the Company may issue the Company's previously authorized and unissued securities, resulting in the dilution of the ownership interests of purchasers of the Company's Class A common stock offered hereby. Under the Company's amended and restated certificate of incorporation, the Company is authorized to issue 500,000,000 shares of Class A common stock, 500,000,000 shares of Class B common stock and 10,000,000 shares of preferred stock with preferences and rights as determined by the Company's board of directors. The potential issuance of additional shares of common stock or preferred stock or convertible debt may create downward pressure on the trading price of the Company's Class A common stock.

If securities or industry analysts do not publish or cease publishing research or reports about the Company, the Company's business or the Company's market, or if they change their recommendations regarding the Company's Class A common stock adversely, the stock price and trading volume of the Company's Class A common stock could decline.

              The trading market for the Company's Class A common stock is influenced by the research and reports that industry or securities analysts may publish about the Company, the Company's business, the Company's market or the Company's competitors. If any of the analysts who may cover the Company change their recommendation regarding the Company's Class A common stock adversely, or provide more favorable relative recommendations about the Company's competitors, the price of the Company's Class A common stock would likely decline. If any analyst who covers the Company were to cease coverage of the Company or fail to regularly publish reports on the Company, the Company could lose visibility in the financial markets, which in turn could cause the stock price or trading volume of the Company's Class A common stock to decline.

Future sales of the Company's common stock by NRG may cause the price of the Company's Class A common stock to fall.

The market price of the Company's Class A common stock could decline as a result of sales by NRG of such shares (issuable to NRG upon the exchange of some or all of its NRG Yield LLC Class B units) in the market, or the perception that these sales could occur.

30

               The market price of the Company's Class A common stock may also decline as a result of NRG disposing or transferring some or all of the Company's outstanding Class B common stock, which disposals or transfers would reduce NRG's ownership interest in, and voting control over the Company. These sales might also make it more difficult for the Company to sell equity securities at a time and price that the Company deems appropriate. NRG and certain of its affiliates have certain demand and piggyback registration rights with respect to shares of the Company's Class A common stock issuable upon the exchange of NRG Yield LLC's Class B units. The presence of additional shares of the Company's Class A common stock trading in the public market, as a result of the exercise of such registration rights may have a material adverse effect on the market price of the Company's securities.

Risks Related to Taxation

The Company's future tax liability may be greater than expected if the Company does not generate NOLs sufficient to offset taxable income.

              The Company expects to generate NOLs and NOL carryforwards that it can utilize to offset future taxable income. Based on the Company's current portfolio of assets, which include renewable assets that benefit from an accelerated tax depreciation schedule, and subject to potential tax audits, which may result in income, sales, use or other tax obligations, the Company does not expect to pay significant federal income tax for a period of approximately ten years. While the Company expect these losses will be available to the Company as a future benefit, in the event that they are not generated as expected, successfully challenged by the IRS (in a tax audit or otherwise) or subject to future limitations as discussed below, the Company's ability to realize these benefits may be limited. A reduction in the Company's expected NOLs, a limitation on the Company's ability to the use such losses or future tax audits, may result in a material increase in the Company's estimated future income tax liability and may negatively impact the Company's liquidity and financial condition.

The Company's ability to use NOLs to offset future income may be limited.

              The Company's ability to the use NOLs generated in the future could be substantially limited if the Company were to experience an "ownership change" as defined under Section 382 of the Code. In general, an "ownership change" would occur if the Company's "5-percent shareholders," as defined under Section 382 of the Code, collectively increased their ownership in the Company by more than 50 percentage points over a rolling three-year period. A corporation that experiences an ownership change will generally be subject to an annual limitation on the use of its pre-ownership change deferred tax assets equal to the equity value of the corporation immediately before the ownership change, multiplied by the long-term tax-exempt rate for the month in which the ownership change occurs. Future sales of the Company's Class A common stock by NRG, as well as future issuances by the Company, could contribute to a potential ownership change.

A valuation allowance may be required for the Company's deferred tax assets.

              The Company's expected NOLs will be reflected as a deferred tax asset as they are generated until utilized to offset income. Valuation allowances may need to be maintained for deferred tax assets that the Company estimates are more likely than not to be unrealizable, based on available evidence at the time the estimate is made. Valuation allowances related to deferred tax assets can be affected by changes to tax laws, statutory tax rates and future taxable income levels and based on input from the Company's auditors, tax advisors or regulatory authorities. In the event that the Company were to determine that the Company would not be able to realize all or a portion of the Company's net deferred tax assets in the future, the Company would reduce such amounts through a charge to income tax expense in the period in which that determination was made, which could have a material adverse impact on the Company's financial condition and results of operations and the Company's ability to maintain profitability.

Distributions to holders of the Company's Class A common stock may be taxable as dividends.

It is difficult to predict whether the Company will generate earnings or profits as computed for federal income tax purposes in any given tax year. If the Company makes distributions from current or accumulated earnings and profits as computed for federal income tax purposes, such distributions will generally be taxable to holders of the Company's Class A common stock in the current period as ordinary dividend income for federal income tax purposes. Under current law, such dividends would be eligible for the lower tax rates applicable to qualified dividend income of non-corporate taxpayers. While the Company expects that a portion of its distributions to holders of the Company's Class A common stock may exceed the Company's current and accumulated earnings and profits as computed for federal income tax purposes and therefore constitute a non-taxable return of capital distribution to the extent of a stockholder's basis in the Company's Class A common stock, no assurance can be given that this will occur.

31

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Annual Report on Form 10-K of NRG Yield, Inc., 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 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;

• 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, 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;

• Counterparties to the Company's offtake agreements willingness and ability 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;

• The Company's ability to receive anticipated cash grants with respect to certain renewable (wind and solar) assets;

• Operating and financial restrictions placed on the Company and its subsidiaries that are contained in the project-level debt facilities and other agreements of certain subsidiaries and project-level subsidiaries generally and in the NRG Yield Operating LLC revolving credit facility; 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 Annual Report on Form 10-K should not be construed as exhaustive.

Item 1B — Unresolved Staff Comments

None.

32

Item 2 — Properties

Listed below are descriptions of NRG Yield, Inc.'s interests in facilities, operations and/or projects owned or leased as of December 31, 2014.

		Capacity
		Rated MW	Net MW	Owner-ship				PPA Terms
Assets	Location					Fuel	COD	Counterparty	Expiration
Conventional
GenConn Devon	Milford, CT	190	95	49.95	%	Natural Gas/Oil	June 2010	CL&P	2040
GenConn Middletown	Middletown, CT	190	95	49.95	%	Natural Gas/Oil	June 2011	CL&P	2041
Marsh Landing	Antioch, CA	720	720	100	%	Natural Gas	May 2013	PG&E	2023
El Segundo	El Segundo, CA	550	550	100	%	Natural Gas	August 2013	SCE	2023
Total Conventional		1,650	1,460
Utility Scale Solar
Blythe	Blythe, CA	21	21	100	%	Solar	December 2009	SCE	2029
Roadrunner	Santa Teresa, NM	20	20	100	%	Solar	August 2011	El Paso Electric	2031
Avenal	Avenal, CA	45	23	49.95	%	Solar	August 2011	PG&E	2031
Avra Valley	Pima County, AZ	25	25	100	%	Solar	December 2012	Tucson Electric Power	2032
Alpine	Lancaster, CA	66	66	100	%	Solar	January 2013	PG&E	2033
Borrego	Borrego Springs, CA	26	26	100	%	Solar	February 2013	SDG&E	2038
CVSR	San Luis Obispo, CA	250	122	48.95	%	Solar	October 2013	PG&E	2038
RE Kansas South	Lemoore, CA	20	20	100	%	Solar	June 2013	PG&E	2033
TA High Desert	Lancaster, CA	20	20	100	%	Solar	March 2013	SCE	2033
Total Utility Scale Solar		493	343
Thermal Generation
Dover	Dover, DE	106	106	100	%	Natural Gas	June 2013	Power sold into PJM markets
Princeton Hospital	Princeton, NJ	5	5	100	%	Natural Gas	January 2012	Excess power sold to local utility
Paxton Creek Cogen	Harrisburg, PA	12	12	100	%	Natural Gas	November 1986	Power sold into PJM markets
Tucson Convention Center	Tucson, AZ	1	1	100	%	Natural Gas	January 2003	Excess power sold to local utility
Total Thermal Generation		124	124
Distributed Solar
AZ DG Solar Projects	AZ	5	5	100	%	Solar	December 2010 - January 2013	Various public entities	2025-2033
PFMG DG Solar Projects	CA	9	5	51	%	Solar	October 2012 - December 2012	Various public entities	2032
Total Distributed Solar		14	10
Wind
Alta I	Tehachapi, CA	150	150	100	%	Wind	December 2010	SCE	2035
Alta II	Tehachapi, CA	150	150	100	%	Wind	December 2010	SCE	2035
Alta III	Tehachapi, CA	150	150	100	%	Wind	February 2011	SCE	2035
Alta IV	Tehachapi, CA	102	102	100	%	Wind	March 2011	SCE	2035
Alta V	Tehachapi, CA	168	168	100	%	Wind	April 2011	SCE	2035
Alta X	Tehachapi, CA	137	137	100	%	Wind	February 2014	SCE	2038 (a)
Alta XI	Tehachapi, CA	90	90	100	%	Wind	February 2014	SCE	2038 (a)
South Trent	Sweetwater, TX	101	101	100	%	Wind	January 2009	AEP Energy Partners	2029
Total Wind		1,048	1,048
Total NRG Yield, Inc.		3,329	2,985

(a) PPA begins on January 1, 2016.

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The following table summarizes the Company's thermal steam and chilled water facilities as of December 31, 2014:

Name and Location of Facility	% Owned	Thermal Energy Purchaser	Megawatt Thermal Equivalent Capacity (MWt)	Generating Capacity
NRG Energy Center Minneapolis, MN	100.0	Approx. 100 steam and 50 chilled water customers	322 136	Steam: 1,100 MMBtu/hr. Chilled water: 38,700 tons
NRG Energy Center San Francisco, CA	100.0	Approx. 175 steam customers	133	Steam: 454 MMBtu/hr.
NRG Energy Center Omaha, NE	100.0 12.0(a) 100.0 0.0(a)	Approx. 60 steam and 60 chilled water customers	142 73 77 26	Steam: 485 MMBtu/hr Steam: 250 MMBtu/hr Chilled water: 22,000 tons Chilled water: 7,250 tons
NRG Energy Center Harrisburg, PA	100.0	Approx. 140 steam and 3 chilled water customers	108 13	Steam: 370 MMBtu/hr. Chilled water: 3,600 tons
NRG Energy Center Phoenix, AZ	0.0(a) 100.0 12.0(a) 0.0(a)	Approx. 35 chilled water customers	4 104 14 28	Steam: 13 MMBtu/hr Chilled water: 29,600 tons Chilled water: 3,950 tons Chilled water: 8,000 tons
NRG Energy Center Pittsburgh, PA	100.0	Approx. 25 steam and 25 chilled water customers	88 46	Steam: 302 MMBtu/hr. Chilled water: 12,934 tons
NRG Energy Center San Diego, CA	100.0	Approx. 15 chilled water customers	26	Chilled water: 7,425 tons
NRG Energy Center Dover, DE	100.0	Kraft Foods Inc. and Procter & Gamble Company	66	Steam: 225 MMBtu/hr.
NRG Energy Center Princeton, NJ	100.0	Princeton HealthCare System	21 17	Steam: 72 MMBtu/hr. Chilled water: 4,700 tons
		Total Generating Capacity (MWt)	1,444

(a) Capacity of 134 MWt available under the right-to-use provisions contained in agreements between two of NRG Yield Inc.'s thermal facilities and certain of its customers.

Item 3 — Legal Proceedings

None.

Item 4 — Mine Safety Disclosures

Not applicable.

34

PART II

Item 5 — Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information and Holders

The Company's Class A common stock trades on the New York Stock Exchange under the symbol “NYLD.” The Company's Class B common stock is not publicly traded.

As of January 31, 2015, there was one holder of record of the Class A common stock and one holder of record of the Class B common stock.

The following table sets forth, for the period indicated, the high and low sales prices as well as the closing price of the Company's Class A common stock as reported by the New York Stock Exchange from July 17, 2013, the first day of trading following the Company's initial public offering announcement, through December 31, 2014. The initial public offering price of the Company's Class A common stock was $22.00 per share.

Common Stock Price	Fourth Quarter 2014	Third Quarter 2014	Second Quarter 2014	First Quarter 2014	Fourth Quarter 2013	Period from July 17 to September 30, 2013
High	$50.84	$55.15	$53.19	$40.57	$41.18	$31.26
Low	39.63	46.89	39.44	34.88	30.07	26.50
Closing	47.14	53.97	40.40	39.99	40.01	30.29
Dividends Per Common Share	$0.375	$0.365	$0.35	$0.33	$0.23	n/a

Dividends

On February 17, 2015, the Company declared a quarterly dividend on its Class A common stock of $0.39 per share payable on March 16, 2015, to stockholders of record as of March 2, 2015.

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

35

Stock Performance Graph

The performance graph below compares NRG Yield, Inc.'s cumulative total stockholder return on the Company's Class A common stock for the period from July 16, 2013 through December 31, 2014, with the cumulative total return of the Standard & Poor's 500 Composite Stock Price Index, or S&P 500, and the Philadelphia Utility Sector Index, or UTY.

The performance graph shown below is being furnished and compares each period assuming that $100 was invested on the initial public offering date in each of the Class A common stock of the Company, the stocks included in the S&P 500 and the stocks included in the UTY, and that all dividends were reinvested.

Comparison of Cumulative Total Return

	July 16, 2013		December 31, 2013		December 31, 2014
NRG Yield, Inc.	$	100.00	$	183.04	$	222.39
S&P 500	100.00		111.36		126.61
UTY	100.00		97.99		125.20

36

Item 6 — Selected Financial Data

The following table presents the Company's historical selected financial data, which has been recast to include the Acquired ROFO Assets, as if the transfer had taken place from the beginning of the financial statements period, or from the date the entities were under common control. The acquisition is further described in Item — 15, Note 3,Business Acquisitions. Additionally, for all periods prior to the initial public offering, the data below reflects the Company's accounting predecessor, or NRG Yield, the financial statements of which were prepared on a ''carve-out'' basis from NRG and are intended to represent the financial results of the contracted renewable energy and conventional generation and thermal infrastructure assets in the U.S. that were acquired by NRG Yield LLC on July 22, 2013. For all periods subsequent to the initial public offering, the data below reflects the Company's consolidated financial results.

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

	Fiscal year ended December 31,
(In millions, except per share data)	2014			2013			2012			2011			2010
Statement of Income Data:
Operating Revenues
Total operating revenues	$	583		$	379		$	175		$	164		$	143
Operating Costs and Expenses
Cost of operations	214			144			114			109			102
Depreciation and amortization	136			61			25			22			16
General and administrative — affiliate	8			7			7			6			5
Acquisition-related transaction and integration costs	4			—			—			—			—
Total operating costs and expenses	362			212			146			137			123
Operating Income	221			167			29			27			20
Other Income (Expense)
Equity in earnings of unconsolidated affiliates	27			22			19			13			1
Other income, net	3			3			2			2			3
Interest expense	(166		)	(52		)	(28		)	(19		)	(13		)
Total other expense	(136		)	(27		)	(7		)	(4		)	(9		)
Income Before Income Taxes	85			140			22			23			11
Income tax expense	4			8			10			9			4
Net Income	$	81		$	132		$	12		$	14		$	7
Less: Pre-acquisition net income of Acquired ROFO Assets	17			23
Net Income Excluding Pre-acquisition Net Income of Acquired ROFO Assets	64			109
Less: Predecessor income prior to initial public offering on July 22, 2013	—			54
Less: Net income attributable to NRG	48			42
Net Income Attributable to NRG Yield, Inc.	$	16		$	13
Earnings Per Share Attributable to NRG Yield, Inc. Class A Common Stockholders
Earnings per Weighted Average Class A Common Share - Basic and Diluted	$	0.59		$	0.57		n/a			n/a			n/a
Dividends per Class A common share (a)	$	1.42		$	0.23		n/a			n/a			n/a
Other Financial Data:
Capital expenditures	33			353			564			373			65
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	223		$	120		$	56		$	32		$	36
Investing activities	(1,068		)	(515		)	(594		)	(468		)	(200		)
Financing activities	1,177			432			536			427			180
Balance Sheet Data (at period end):
Cash and cash equivalents	$	391		$	59		$	22		$	24		$	33
Property, plant and equipment, net	3,487			2,291			2,130			863			526
Total assets	5,752			3,238			2,540			1,239			784
Total liabilities	4,272			1,986			1,538			678			592
Total stockholders' equity	1,480			1,252			1,002			561			192
(a) Dividends on Class A common shares began after the initial public offering on July 22, 2013.

37

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

The following discussion analyzes the Company's historical financial condition and results of operations. For all periods prior to the initial public offering, the discussion reflects the Company's accounting predecessor, or NRG Yield, the financial statements of which were prepared on a ''carve-out'' basis from NRG and are intended to represent the financial results of the contracted renewable energy and conventional generation and thermal infrastructure assets in the U.S. that were acquired by NRG Yield LLC on July 22, 2013. For all periods subsequent to the initial public offering, the discussion reflects the Company's consolidated financial results. In addition, as discussed in Item 15 — Note 1, Nature of Business to this Form 10-K, the purchase of the Acquired ROFO Assets on June 30, 2014 was accounted for in accordance with ASC 850-50, Business Combinations - Related Issues, whereas the assets and liabilities transferred to the Company relate to interests under common control by NRG and accordingly, were recorded at historical cost. The difference between the cash proceeds and historical value of the net assets was recorded as a distribution to NRG and reduced the balance of its 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, refer to the Company's Consolidated Statements of Operations to this Form 10-K, which present the results of operations for the years ended December 31, 2014, 2013 and 2012. Also refer to Item 1 - Business, 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 operations;

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

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

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

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Executive Summary

Introduction and Overview

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

The Company owns a diversified portfolio of contracted renewable and conventional generation and thermal infrastructure assets in the United States. The Company’s contracted generation portfolio collectively represents2,861 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 December 31, 2014based on cash available for distribution. The Company also owns thermal infrastructure assets with an aggregate steam and chilled water capacity of 1,310 net MWt and electric generation capacity of 124 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.

Government Incentives

Government incentives can enhance the economics of the Company's generating assets or investments by providing, for example, loan guarantees, cash grants, favorable tax treatment, favorable depreciation rules, or other incentives.  Certain recent proposals enhance federal incentives for renewable generation — including through the permanent extension of the wind power Production Tax Credit and the extension of the solar Investment Tax Credit, and could incentivize the development of additional renewable energy projects that would fit within the Company’s asset portfolio.  In addition, direct cash incentives may encourage additional renewable energy development by non-taxpaying entities that cannot always take advantage of tax credits.

Significant Events During the Twelve Months Ended December 31, 2014

Alta Wind Portfolio Acquisition

On August 12, 2014, the Company acquired 100% of the membership interests of Alta Wind Asset Management Holdings, LLC, Alta Wind Company, LLC, Alta Wind X Holding Company, LLC and Alta Wind XI Holding Company, LLC, which collectively own seven wind facilities that total 947 MW located in Tehachapi, California, and a portfolio of associated land leases, or the Alta Wind Portfolio. The purchase price for the Alta Wind Portfolio was $923 million, which included a base purchase price of $870 million, and a payment for working capital of $53 million, plus the assumption of $1.6 billion of non-recourse project-level debt. Terra-Gen, an affiliate of the Alta Sellers, provides the day-to-day operations and maintenance services under a 10-year O&M agreement, which will automatically extend for additional five-year periods unless either party provides notice of termination at least 90 days prior to the expiration of the then-current term. Pursuant to the terms of such agreement, Terra-Gen is paid a fixed monthly payment (adjusted annually for inflation) and reimbursed for certain costs incurred. In order to fund the purchase price, the Company completed an equity offering of 12,075,000 shares of its Class A common stock at an offering price of $54.00 per share on July 29, 2014, which resulted in net proceeds of $630 million, after underwriting discounts and expenses. In addition, on August 5, 2014, NRG Yield Operating LLC issued $500 million of Senior Notes, as described in Item 15 — Note 9, Long-term Debt.

Acquisition of Acquired ROFO Assets from NRG

On June 30, 2014, the Company acquired from NRG: (i) El Segundo, a 550 MW fast-start, gas-fired facility located in Los Angeles County, California; (ii) TA High Desert, a 20 MW solar facility located in Los Angeles County, California; and (iii) RE Kansas South, a 20 MW solar facility located in Kings County, California. The assets were acquired pursuant to the ROFO Agreement. The Company paid NRG total cash consideration of $357 million, which represents a base purchase price of $349 million and a payment for working capital of $8 million. In addition, the acquisition included the assumption of $612 million in project-level debt.

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Issuance of 3.50% Convertible Notes

During the first quarter of 2014, the Company issued $345 million in aggregate principal amount of its convertible notes as described in Item 15 — Note 9, Long-term Debt.

Significant Events During the Twelve Months Ended December 31, 2013

On December 31, 2013, NRG Energy Center Omaha Holdings, LLC, an indirect wholly owned subsidiary of NRG Yield LLC, acquired Energy Systems Company, or Energy Systems, an operator of steam and chilled thermal facilities that provides heating and cooling services to nonresidential customers in Omaha, Nebraska. See Item 15 —Note 3, Business Acquisitions, for information related to the acquisition.

During 2013, Alpine, Avra, Borrego, CVSR, El Segundo, Marsh Landing, RE Kansas South, and TA High Desert achieved COD. In addition, Borrego completed financing arrangements with a group of lenders. See Item 15 —Note 9,Long-term Debt, for information related to these financing activities. The Company completed its initial public offering of its Class A common stock on July 22, 2013. See Item 15 —Note 1, Nature of Business, for information related to the initial public offering.

Significant Events During the Twelve Months Ended December 31, 2012

During 2012, Alpine completed a financing arrangement with a group of lenders. See Item 15 —Note 9,Long-term Debt for information related to this financing activity.

Environmental Matters and Regulatory Matters

Details of environmental matters are presented in Item 15 — Note 16, Environmental Matters. Details of regulatory matters are presented in Item 1— Business, Regulatory Matters. Details of some of this information relates to costs that may be material to the Company's financial results.

Basis of Presentation

For all periods prior to the Company's initial public offering, the accompanying combined financial statements represent the combination of the assets that NRG Yield LLC acquired and were prepared using NRG's historical basis in the assets and liabilities. For the purposes of the combined financial statements, the term "NRG Yield" represents the accounting predecessor, or the combination of the acquired businesses. For all periods subsequent to the initial public offering, the accompanying consolidated financial statements represent the consolidated results of NRG Yield, Inc., which consolidates NRG Yield LLC through its controlling interest.

The acquisition of the TA High Desert, RE Kansas South, and El Segundo projects from NRG on June 30, 2014 was accounted for as a transfer of entities under common control. The guidance requires retrospective combination of the entities for all periods presented as if the combination has been in effect since the inception of common control. Accordingly, the Company prepared its consolidated financial statements to reflect the transfer as if it had taken place on January 1, 2012, or from the date the entities were under common control, which was May 13, 2013, for RE Kansas South and March 28, 2013, for TA High Desert. Member's equity represents NRG's equity in the subsidiaries, and accordingly, in connection with their acquisition by the Company, the balance was reclassified into noncontrolling interest. The Company reduces net income attributable to its Class A common stockholders by the pre-acquisition net income for the Acquired ROFO Assets as it is not available to the stockholders.

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Consolidated Results of Operations

2014 compared to 2013

The following table provides selected financial information:

	Year ended December 31,
(In millions, except otherwise noted)	2014			2013			Change %
Operating Revenues
Total operating revenues	$	583		$	379		54
Operating Costs and Expenses
Cost of operations	214			144			49
Depreciation and amortization	136			61			123
General and administrative — affiliate	8			7			14
Acquisition-related transaction and integration costs	4			—			100
Total operating costs and expenses	362			212			71
Operating Income	221			167			32
Other Income (Expense)
Equity in earnings of unconsolidated affiliates	27			22			23
Other income, net	3			3			—
Interest expense	(166		)	(52		)	219
Total other expense	(136		)	(27		)	404
Income Before Income Taxes	85			140			(39	)
Income tax expense	4			8			(50	)
Net Income	81			132			(39	)
Less: Pre-acquisition net income of Acquired ROFO Assets	17			23			(26	)
Net Income Excluding Pre-acquisition Net Income of Acquired ROFO Assets	64			109			(41	)
Less: Predecessor income prior to initial public offering on July 22, 2013	—			54			(100	)
Less: Net income attributable to NRG	48			42			14
Net Income Attributable to NRG Yield, Inc.	$	16		$	13		23

	Year ended December 31,
Business metrics:	2014 (a)	2013 (a)
Renewable MWh sold (in thousands)	1,552	854
Thermal MWt sold (in thousands)	2,060	1,679

(a) Volumes sold do not include MWh of 205 thousand and 139 thousand for thermal generation for the years ended December 31, 2014, and 2013, respectively.

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Management’s discussion of the results of operations for the years ended December 31, 2014 and 2013

Operating Revenues

	Conventional		Renewables		Thermal		Total
(In millions)
Year ended December 31, 2014	$	244	$	144	$	195	$	583
Year ended December 31, 2013	138		89		152		379

Operating revenuesincreased by $204 million during the twelve months ended December 31, 2014, compared to the same period in 2013 due to:

Increase in Conventional revenues as El Segundo and Marsh Landing reached commercial operations in 2013	$	106
Increase due to acquisition of Alta Wind Portfolio in August 2014	49
Increase in Thermal revenues generated from Energy Systems acquired in the fourth quarter of 2013, repowering of Dover facilities in the second quarter of 2013, as well as increased generation at other Thermal facilities due to weather conditions in the first quarter of 2014	43
Increase in Renewables revenue generated by the RE Kansas South, TA High Desert, and Borrego facilities which reached commercial operations in the first half of 2013	6
	$	204

Cost of Operations

	Conventional		Renewables		Thermal		Total
(In millions)
Year ended December 31, 2014	$	41	$	34	$	139	$	214
Year ended December 31, 2013	23		11		110		144

Cost of operations increased by $70 million during the year ended December 31, 2014, compared to the same period 2013 due to:

Increased costs in connection with the Energy Systems acquisition, higher cost of production due to repowering of Dover facilities in the second quarter of 2013, as well as increased generation at other Thermal facilities due to weather conditions in the first quarter of 2014	$	29
Increase due to acquisition of Alta Wind Portfolio in August 2014	20
Increase in costs associated with maintenance and operations at Marsh Landing and El Segundo which reached commercial operations in 2013	18
Increase in costs associated with maintenance and operations of RE Kansas South, TA High Desert, Alpine and Borrego facilities which reached commercial operations in the first half of 2013	3
	$	70

Depreciation and Amortization

Depreciation and amortization increased by $75 million during the year ended December 31, 2014, compared to 2013, due to:

(In millions)
Additional depreciation for Marsh Landing and El Segundo, which reached commercial operations in 2013	$	46
Increase due to acquisition of Alta Wind Portfolio in August 2014	23
Additional depreciation for solar facilities that began operating in 2013 and the acquisition of Energy Systems in December 2013	6
	$	75

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Equity in Earnings of Unconsolidated Affiliates

Equity in earnings of unconsolidated affiliates increased by $5 million during the year ended December 31, 2014, compared to 2013, due primarily to an increase in income for CVSR as it reached commercial operations in late 2013.

Interest Expense

Interest expense increased by $114 million during the year ended December 31, 2014, compared to the same period in 2013 due to:

(In millions)
Interest expense on the project-level debt assumed in the Alta Wind Portfolio acquisition in August 2014	$	45
Issuance of Senior Notes in August 2014, Convertible Notes in March 2014 and to a lesser extent increased interest expense on the Company's revolving credit facility	30
Increase in interest expense in the Renewable segment primarily related to the Alpine interest rate swap	21
Increase in interest expense for the El Segundo and Marsh Landing projects which reached commercial operations in 2013	18
	$	114

Income Tax Expense

For the year ended December 31, 2014, the Company recorded income tax expense of $4 million on pretax income of $85 million. For the same period in 2013, the Company recorded income tax expense of $8 million on pretax income of $140 million. For the year ended December 31, 2014, the overall effective tax rate was different than the statutory rate of 35% primarily due to taxable earnings allocated to NRG resulting from its 55.3% interest in NRG Yield LLC and production tax credits generated from certain Alta Wind Portfolio facilities. For the same period in 2013, 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 65.5% interest in NRG Yield LLC.

Income Attributable to NRG

Income attributable to NRG increased by $6 million for the year ended December 31, 2014, compared to the same period in 2013 due to the Company being public for the full year in 2014 compared to a shorter period in 2013, partially offset by a decrease in NRG's interest in the Company from 65.5% to 55.3% as a result of the equity offering on July 29, 2014.

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Consolidated Results of Operations

2013 compared to 2012

The following table provides selected financial information:

	Year ended December 31,
(In millions, except otherwise noted)	2013			2012			Change %
Operating Revenues
Total operating revenues	$	379		$	175		117
Operating Costs and Expenses
Cost of operations	144			114			26
Depreciation and amortization	61			25			144
General and administrative — affiliate	7			7			—
Total operating costs and expenses	212			146			45
Operating Income	167			29			476
Other Income (Expense)
Equity in earnings of unconsolidated affiliates	22			19			16
Other income, net	3			2			50
Interest expense	(52		)	(28		)	86
Total other expense	(27		)	(7		)	286
Income Before Income Taxes	140			22			N/M
Income tax expense	8			10			(20	)
Net Income	132			12			N/M
Less: Pre-acquisition net income (loss) of Acquired ROFO Assets	23			(1		)
Net Income Excluding Pre-acquisition Net Income (Loss) of Acquired ROFO Assets	109			$	13
Less: Predecessor income prior to initial public offering on July 22, 2013	54
Less: Net income attributable to NRG	42
Net Income Attributable to NRG Yield, Inc.	$	13

	Year ended December 31,
Business metrics:	2013 (a)	2012 (a)
Renewable MWh sold (in thousands)	854	422
Thermal MWt sold (in thousands)	1,679	1,517

(a) Volumes sold do not include MWh of 139 thousand and 88 thousand for thermal generation for the years ended December 31, 2013 and 2012, respectively.

N/M - Not meaningful.

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Management’s discussion of the results of operations for the year ended December 31, 2013, and 2012

Operating Revenues

	Conventional		Renewables		Thermal		Total
(In millions)
Year ended December 31, 2013	$	138	$	89	$	152	$	379
Year ended December 31, 2012	—		33		142		175

Operating revenuesincreased by $204 million during the year ended December 31, 2013, compared to 2012, due to:

(In millions)
Increase in Conventional revenues as Marsh Landing and El Segundo reached commercial operations in 2013	$	138
Increase in Renewables revenue as TA High Desert, RE Kansas South, Alpine, Avra Valley, and Borrego reached commercial operations in late 2012 and early 2013	56
Increase in Thermal revenue due to repowering of Dover facilities in 2013 as well as a full year of operation of Princeton hospital	10
	$	204

Cost of Operations

	Conventional		Renewables		Thermal		Total
(In millions)
Year ended December 31, 2013	$	23	$	11	$	110	$	144
Year ended December 31, 2012	2		9		103		114

Cost of operations increased by $30 million during the year ended December 31, 2013, compared to the same period in 2012, due to:

(In millions)
Increase in Conventional costs as Marsh Landing and El Segundo reached commercial operations in 2013	$	21
Increase in Thermal costs due to repowering of Dover facilities in 2013 as well as a full year of operation of Princeton hospital	7
Increase in Renewables costs as TA High Desert, RE Kansas South, Alpine, Avra Valley, and Borrego reached commercial operations in late 2012 and early 2013	2
	$	30

Depreciation and Amortization

Depreciation and amortization increased by $36 million during the year ended December 31, 2013, compared to the same period in 2012, due primarily to $20 million of additional depreciation associated with El Segundo and Marsh Landing which reached commercial operations in 2013 and $16 million for solar projects that reached commercial operations in late 2012 and early 2013.

Equity in Earnings of Unconsolidated Affiliates

Equity in earnings of unconsolidated affiliates increased by $3 million during the year ended December 31, 2013, compared to the same period in 2012, due primarily to CVSR reaching commercial operations in 2013.

Interest Expense

Interest expense increased by $24 million during the year ended December 31, 2013, compared to the same period in 2012, due primarily to $25 million of interest expense related to Marsh Landing and El Segundo reaching commercial operations in 2013, which resulted in higher borrowings and less capitalized interest during 2013.

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Income Tax Expense

For the year ended December 31, 2013, the Company recorded income tax expense of $8 million on pretax income of $140 million. For the same period in 2012, the Company recorded income tax expense of $10 million on pretax income of $22 million. For the year ended December 31, 2013, 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 65.5% interest in NRG Yield LLC. For the year ended December 31, 2012, the Company's overall effective tax rate was different than the statutory rate of 35% primarily due to the impact of state and local income taxes.

Income Attributable to NRG

Income attributable to NRG of $42 million represents NRG's 65.5% interest in NRG Yield LLC's net income during the period from July 22, 2013 through December 31, 2013.

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, and to service debt. 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 December 31, 2014, and December 31, 2013, the Company's liquidity was approximately $825 million and $186 million, respectively, comprised of cash, restricted cash, and availability under the Company's revolving credit facility. The increase primarily relates to the available line of credit under the revolving credit facility. The Company's various financing arrangements are described in Item 15 —Note 9, Long-term Debt. On January 2, 2015, the Company borrowed $210 million under its revolving credit facility to fund the acquisition of Walnut Creek, Laredo Ridge and the Tapestry projects. On February 2, 2015 the Company made an optional repayment of $15 million of principal and interest.

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, finance growth, operating and maintenance capital expenditures, and to fund dividends to holders of the Company's Class A common stock. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.

Credit Ratings

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

The following table summarizes the credit ratings for the Company and its Senior Notes as of December 31, 2014:

	S&P	Moody's
NRG Yield, Inc.	BB+	Ba1
5.375% Senior Notes, due 2024	BB+	Ba1

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 securities as appropriate given market conditions. As described in Item 15 —Note 9, Long-term Debt, the Company's financing arrangements consist of the revolving credit facility, the Convertible Notes, the Senior Notes and project-level financings for its various assets.

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In connection with the initial public offering of the Company's Class A common stock, as further described in Item 15 —Note 1, Nature of Business, NRG Yield LLC and its direct wholly owned subsidiary, NRG Yield Operating LLC entered into a senior secured revolving credit facility, which provided a revolving line of credit of $60 million. On April 25, 2014, the Company amended its revolving credit facility to increase the available line of credit to $450 million and extend its maturity to April 2019. The revolving credit facility can be used for cash or for the issuance of letters of credit.

As described in Item 15 — Note 9, Long-term Debt, during the first quarter of 2014, the Company issued $345 million of Convertible Notes. The Convertible Notes are convertible, under certain circumstances, into the Company’s Class A common stock, cash or a combination thereof at an initial conversion price of $46.55 per share of Class A common stock, which is equivalent to an initial conversion rate of approximately 21.4822 shares of Class A common stock per $1,000 principal amount of Convertible Notes. The proceeds from the issuance were used primarily to fund the purchase of the Acquired ROFO Assets. In addition, on August 5, 2014, NRG Yield Operating LLC issued $500 million of Senior Notes, and used the proceeds to fund the acquisition of the Alta Wind Portfolio. The Senior Notes bear interest at 5.375% and mature in 2024.

On July 29, 2014, the Company issued 12,075,000 shares of Class A common stock for net proceeds, after underwriting discount and expenses, of $630 million. The proceeds were primarily used to fund the acquisition of the Alta Wind Portfolio and the excess of the proceeds over the amount utilized is available for general corporate purposes, including future acquisitions.

On February 24, 2015, the Company’s board of directors approved amendments to the Company's certificate of incorporation that would, among other things, create two new classes of capital stock, Class C common stock and Class D common stock. The amendments will be voted on at the Company’s Annual Meeting of Stockholders to be held on May 5, 2015. If such amendments are approved, the Company intends to request that the board of directors consider a distribution of shares of the Class C common stock as a dividend to the holders of the Class A common stock and a distribution of shares of the Class D common stock as a dividend to NRG, the holder of the Class B common stock. The Class C common stock and Class D common stock will have the same rights and privileges and rank equally, share ratably and be identical in all respects to the shares of Class A common stock and Class B common stock, respectively, as to all matters, except that each share of Class C common stock and Class D common stock will be entitled to 1/100^th of a vote on all stockholder matters.

In addition, subject to the approval of the proposed amendments described above, NRG has agreed to amend the ROFO Agreement to make additional assets available to the Company should NRG choose to sell them, including (i) two natural gas facilities totaling 895 MW of net capacity that are expected to reach COD in 2017 and 2020, (ii) an equity interest in a wind portfolio that includes wind facilities totaling approximately 934 MW of net capacity, and (iii) up to $250 million of equity interests in one or more residential or distributed solar generation portfolios developed by affiliates of NRG.

Uses of Liquidity

The Company's requirements for liquidity and capital resources, other than for operating its facilities, are categorized as: (i) debt service obligations, as described more fully in Item 15 —Note 9, Long-term Debt; (ii) capital expenditures; and (iii) cash dividends to investors.

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Debt Service Obligations

Principal payments on debt as of December 31, 2014, are due in the following periods:

Description	2015		2016		2017		2018		2019		There-after		Total
	(In millions)
NRG Yield Inc. Convertible Notes, due 2019	$	—	$	—	$	—	$	—	$	345	$	—	$	345
NRG Yield Operating LLC Senior Notes, due 2024	—		—		—		—		—		500		500
Project-level debt:
Alta Wind I, lease financing arrangement, due 2034	10		10		10		11		12		208		261
Alta Wind II, lease financing arrangement, due 2034	7		7		8		8		8		167		205
Alta Wind III, lease financing arrangement, due 2034	7		7		8		8		8		174		212
Alta Wind IV, lease financing arrangement, due 2034	4		5		5		5		6		113		138
Alta Wind V, lease financing arrangement, due 2035	7		7		8		8		8		182		220
Alta Wind X, due 2021	—		13		13		13		13		248		300
Alta Wind XI, due 2021	—		8		9		8		9		157		191
Alta Realty Investments, due 2031	1		1		1		2		2		27		34
Alta Wind Asset Management, due 2031	1		1		1		1		1		15		20
NRG West Holdings LLC, due 2023	36		41		41		47		49		292		506
NRG Marsh Landing LLC, due 2017 and 2023	46		48		52		55		57		206		464
NRG Solar Alpine LLC, due 2014 and 2022	9		9		9		8		8		120		163
NRG Energy Center Minneapolis LLC, due 2017 and 2025	12		13		13		8		11		64		121
NRG Solar Borrego LLC, due 2024 and 2038	3		3		3		2		2		62		75
South Trent Wind LLC, due 2020	4		4		4		4		4		45		65
NRG Solar Avra Valley LLC, due 2031	3		3		3		3		4		47		63
TA High Desert LLC, due 2023 and 2033	3		3		3		3		3		40		55
NRG Roadrunner LLC, due 2031	2		2		3		3		3		29		42
NRG Solar Kansas South LLC, due 2031	2		2		2		2		2		25		35
NRG Solar Blythe LLC, due 2028	1		1		2		1		2		15		22
PFMG and related subsidiaries financing agreement, due 2030	1		2		2		1		1		24		31
NRG Energy Center Princeton LLC, due 2017	1		—		—		—		—		—		1
Total debt	$	160	$	190	$	200	$	201	$	558	$	2,760	$	4,069

Capital Expenditures

The Company's capital spending program is focused on growth capital expenditures, or construction of new assets and completing the construction of assets where construction is in process, and maintenance capital expenditures, or costs to maintain the assets currently operating such as costs to replace or refurbish assets during routine maintenance. The Company develops annual capital spending plans based on projected requirements for maintenance capital and completion of facilities under construction. For the years ended December 31, 2014, 2013, and 2012, the Company used approximately $33 million, $353 million, and $564 million, respectively, to fund capital expenditures, includingmaintenance capital expenditures of $8 million,$8 million and $5 million, respectively.Growth capital expenditures primarily related to the construction of the Company’s solar generating assets, Marsh Landing and El Segundo.

In January 2015, El Segundo experienced a steam turbine water intrusion resulting in a forced outage on Units 5 and 6.  The Company has undertaken a root cause analysis and is reviewing the financial impact of repair costs and capacity revenue loss that are not otherwise covered by warranty or available insurance coverage.  The units are expected to return to service early in the second quarter of 2015.

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Acquisitions

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, operating expertise and access to capital provides a competitive advantage, and to utilize such acquisitions as a means to grow its cash available for distribution. 

On June 30, 2014, NRG Yield Operating LLC acquired the El Segundo, TA High Desert, and RE Kansas South projects for a total cash consideration of $357 million, which represents a base purchase price of $349 million and $8 million of working capital adjustments. In addition, the acquisition included the assumption of $612 million in project level debt. The assets and liabilities transferred to the Company relate to interests under common control by NRG and accordingly, were recorded at historical cost in accordance with ASC 805-50, Business Combinations - Related Issues.

OnAugust 12, 2014, the Company acquired 100% of the membership interests of Alta Wind Asset Management Holdings, LLC, Alta Wind Company, LLC, Alta Wind X Holding Company, LLC and Alta Wind XI Holding Company, LLC for $923 million, which included a base purchase price of $870 million, as well as a payment for working capital of $53 million, plus the assumption of $1.6 billion of non-recourse project-level debt. In order to fund the purchase price, the Company completed an equity offering of 12,075,000 shares of its Class A common stock at an offering price of $54.00 per share on July 29, 2014, which resulted in net proceeds of $630 million and on August 5, 2014, NRG Yield Operating LLC issued $500 million of Senior Notes which bear interest at a rate of 5.375% and mature in August 2024.

On January 2, 2015, NRG Yield Operating LLC acquired the following projects from NRG: (i) Laredo Ridge, a 80 MW wind facility located in Petersburg, Nebraska, (ii) the Tapestry projects, which include Buffalo Bear, a 19 MW wind facility in Oklahoma, Taloga, a 130 MW wind facility in Oklahoma, and Pinnacle, a 55 MW wind facility in 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 adjustments of $9 million for working capital, plus assumed project level debt of $737 million. The Company funded the acquisition with cash on hand and approximately $210 million borrowed under the Company's revolving credit facility.

On February 26, 2015, NRG Yield Operating LLC entered into a definitive agreement with Invenergy Wind Global LLC to acquire a majority interest in Spring Canyon II, a 34 MW wind facility, and Spring Canyon III, a 29 MW wind facility, each located in Logan County, Colorado. The purchase price will be funded with cash on hand. The acquisition is subject to customary closing conditions, including the receipt of regulatory and third party approvals. The Company expects the acquisition to close during the second quarter of 2015. Power generated by Spring Canyon II and Spring Canyon III is sold to Platte River Power Authority under long-term PPAs with approximately 25 years of remaining contract life.

Cash Dividends to Investors

The Company intends to use the amount of cash that it receives from its distributions from NRG Yield LLC to pay quarterly dividends to the holders of its Class A common stock. NRG Yield LLC intends to distribute to its unit holders in the form of a quarterly distribution all of the cash available for distribution that is generated each quarter less reserves for the prudent conduct of the business, including among others, maintenance capital expenditures to maintain the operating capacity of the assets. Cash available for distribution is defined as earnings before income taxes, depreciation and amortization, excluding contract amortization, cash interest paid, income taxes paid, maintenance capital expenditures, investments in unconsolidated affiliates, growth capital expenditures, net of capital and debt funding, and principal amortization of indebtedness, and including cash distributions from unconsolidated affiliates. The common stock dividend is subject to available capital, market conditions, and compliance with associated laws and regulations. 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 the Company's Class A common stock during the year ended December 31, 2014:

	Fourth Quarter 2014		Third Quarter 2014		Second Quarter 2014		First Quarter 2014
Dividends per share	$	0.375	$	0.365	$	0.35	$	0.33

On February 17, 2015, the Company declared a quarterly dividend on its Class A common stock of $0.39 per share payable on March 16, 2015, to stockholders of record as of March 2, 2015.

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Cash Flow Discussion

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

The following table reflects the changes in cash flows for the year ended December 31, 2014, compared to 2013:

Year ended December 31,	2014			2013			Change
(In millions)
Net cash provided by operating activities	$	223		$	120		$	103
Net cash used in investing activities	(1,068		)	(515		)	(553		)
Net cash provided by financing activities	1,177			432			745

Net Cash Provided By Operating Activities

Changes to net cash provided by operating activities were driven by:	(In millions)
Increase in operating income due to El Segundo, Marsh Landing and most of the Renewable projects being placed in service in late 2012 or 2013 adjusted for non-cash charges	$	72
Higher net distributions from unconsolidated affiliates for the period ending December 31, 2014 compared to the same period in 2013	3
Decreased working capital requirements due to assets placed in service in late 2012 and 2013	28
	$	103

Net Cash Used In Investing Activities

Changes to net cash used in investing activities were driven by:	(In millions)
Increase in cash paid for Alta Wind Portfolio in 2014 compared to cash paid for Energy Systems in 2013	$	(781	)
Payment to NRG for Acquired ROFO Assets	(357		)
Decrease in capital expenditures for El Segundo, Marsh Landing and some of the Renewable projects, as the assets were placed in service in late 2012 or 2013	320
Decrease in restricted cash, primarily for Marsh Landing, Borrego, Alta Wind Portfolio, El Segundo, Alpine and High Desert	103
Increase in notes receivable, including affiliates	(2		)
Increase in proceeds from renewable grants in 2014 compared to 2013	112
Decrease in investments in unconsolidated affiliates in 2014 compared to 2013 and other	52
	$	(553	)

Net Cash Provided By Financing Activities

Changes in net cash provided by financing activities were driven by:	(In millions)
Decrease in dividends and returns of capital to NRG, net of change in cash contributions from NRG	$	515
Increase due to the $630 million equity offering of Class A common stock on July 29, 2014, compared to the prior year initial public offering of $468 million	162
Increase in cash received from issuance of Senior Notes and other long term debt, partially offset by higher principal payments in 2014 compared to 2013	176
Increase in dividends paid in 2014 compared to 2013	(86		)
Increase in cash paid for deferred financing costs	(22		)
	$	745

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Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

The following table reflects the changes in cash flows for the year ended December 31, 2013, compared to 2012:

Year ended December 31,	2013			2012			Change
(In millions)
Net cash provided by operating activities	$	120		$	56		$	64
Net cash used in investing activities	(515		)	(594		)	79
Net cash provided by financing activities	432			536			(104		)

Net Cash Provided By Operating Activities

Changes to net cash provided by operating activities were driven by:	(In millions)
Increase in operating income due to Borrego, Avra Valley, Alpine, Kansas South, High Desert, El Segundo and Marsh Landing being placed in service in late 2012 or 2013 adjusted for non-cash charges	$	136
Higher net distributions from unconsolidated affiliates for the period ending December 31, 2013 compared to the same period in 2012	(8		)
Increased working capital requirements due to assets placed in service in late 2012 and 2013	(64		)
	$	64

Net Cash Used In Investing Activities

Changes to net cash used in investing activities were driven by:	(In millions)
Acquisition of Energy Systems in December 2013	$	(120	)
Decrease in capital expenditures for El Segundo, Marsh Landing, Borrego, Avra Valley and Alpine as the assets were placed in service in late 2012 or 2013	211
Increase in restricted cash, primarily for Marsh Landing and El Segundo	(31		)
Decrease in notes receivable, including affiliates	27
Decrease in proceeds from renewable grants	(3		)
Increase in investments in unconsolidated affiliates	(7		)
Other	2
	$	79

Net Cash Provided By Financing Activities

Changes in net cash provided by financing activities were driven by:	(In millions)
Increase in dividends and returns of capital to NRG, net of change in cash contributions from NRG	$	(819	)
Proceeds from the issuance of Class A common stock	468
Dividends to Class A and Class B common shareholders in 2013	(15		)
Net increase in cash received from proceeds for issuance of long-term debt, net of payments	255
Decrease in cash paid for deferred financing costs	7
	$	(104	)

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

As of December 31, 2014, the Company has a cumulative federal NOL carry forward balance of $219 million for financial statement purposes, which will begin expiring in 2033, and does not anticipate any federal income tax payments for 2015. As a result of the Company's tax position, and based on current forecasts, the Company does not anticipate significant income tax payments for state and local jurisdictions in 2015.

The Company has no uncertain tax benefits.

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Off-Balance Sheet Arrangements

Obligations under Certain Guarantee Contracts

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

Retained or Contingent Interests

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

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of December 31, 2014, 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. One of these investments, GenConn Energy LLC,is a variable interest entity 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 $567 million as of December 31, 2014. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to the Company. See also Item 15 — Note 5, Investments Accounted for by the Equity Method and Variable Interest Entities.

Contractual Obligations and Commercial Commitments

The Company has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs. The following table summarizes the Company's contractual obligations. See Item 15 — Note 9, Long-term Debtand Item 15 - Note 15, Commitments and Contingencies, to the Company's audited financial statements for additional discussion.

	By Remaining Maturity at December 31,
	2014
Contractual Cash Obligations	Under 1 Year		1-3 Years		3-5 Years		Over 5 Years		Total		2013
	(In millions)
Long-term debt (including estimated interest)	$	368	$	801	$	1,120	$	3,826	$	6,115	$	2,225
Operating leases	6		10		10		103		129		25
Fuel purchase and transportation obligations	15		7		5		26		53		55
Other liabilities	9		18		17		74		118		78
Total	$	398	$	836	$	1,152	$	4,029	$	6,415	$	2,383

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 and fixed rate debt, the Company enters into interest rate swap agreements.

The tables below disclose the activities that include non-exchange traded contracts accounted for at fair value in accordance with ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at December 31, 2014, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at December 31, 2014. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Item 15 —Note 6, Fair Value of Financial Instruments.

Derivative Activity Gains/(Losses)	(In millions)
Fair value of contracts as of December 31, 2013	$	(26	)
Contracts realized or otherwise settled during the period	30
Contracts acquired during the period	(5		)
Changes in fair value	(75		)
Fair Value of Contracts as of December 31, 2014	$	(76	)

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	Fair Value of Contracts as of December 31, 2014
	Maturity
Fair value hierarchy Gains/(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	$	(31	)	$	(29	)	$	(6	)	$	(10	)	$	(76	)

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 U.S. GAAP. The preparation of these financial statements and related disclosures in compliance with U.S. 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 Item 15 — Note 2, Summary of Significant Accounting Policies. 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.

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

Income Taxes and Valuation Allowance for Deferred Tax Assets

In assessing the recoverability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is primarily dependent upon earnings in various jurisdictions.

The Company's operating companies, as former subsidiaries of NRG, continue to be under audit for multiple years by taxing authorities in other jurisdictions. Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws. The project-level entities, as former subsidiaries of NRG, are subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and local jurisdictions. NRG is no longer subject to U.S. federal income tax examinations for years prior to 2010. With few exceptions, state and local income tax examinations are no longer open for years before 2009.

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

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

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

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

• Adverse business climate;

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

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

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

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

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

Acquisition Accounting

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

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

Recent Accounting Developments

See Item 15 — Note 2, Summary of Significant Accounting Policies, to the audited financial statements for a discussion of recent accounting developments.

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Item 7A — 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 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 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 in the net value of derivatives as of December 31, 2014.

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, 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 Item 15 — Note 9, Long-term Debt, for more information about interest rate swaps of the Company's project subsidiaries.

If all of the above swaps had been discontinued on December 31, 2014, the Company would have owed the counterparties $73 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 December 31, 2014, a 1% change in interest rates would result in an approximately $2 million change in interest expense on a rolling twelve month basis.

As of December 31, 2014, the fair value of the Company's debt was $4,136 million and the carrying value was $4,050 million. The Company estimates that a 1% decrease in market interest rates would have increased the fair value of its long-term debt by $251 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.

Item 8 — Financial Statements and Supplementary Data

The financial statements and schedules are listed in Part IV, Item 15 of this Form 10-K.

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Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A — Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Internal Control Over Financial Reporting

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 report on Form 10-K.

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 fourth quarter of 2014 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Inherent Limitations over Internal Controls

The Company's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with U.S. GAAP. The Company's internal control over financial reporting includes those policies and procedures that:

1. Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company's assets;

2. Provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with U.S. GAAP, and that the Company's receipts and expenditures are being made only in accordance with authorizations of its management and directors; and

3. Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the consolidated financial statements.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls. Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management's Report on Internal Control over Financial Reporting

The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). 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 its internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company's evaluation under the framework in Internal Control — Integrated Framework (2013), the Company's management concluded that its internal control over financial reporting was effective as of December 31, 2014.

The scope of management’s assessment of the effectiveness of its internal control over financial reporting included the Company's consolidated operations except for the operations of Alta Wind Portfolio, which the Company acquired in August 2014. Alta Wind Portfolio represented 43% of the Company’s consolidated total assets and 8% of consolidated operating revenues as of and for the year ended December 31, 2014.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2014, has been audited by KPMG LLP, the Company's independent registered public accounting firm, as stated in its report which is included in this Form 10-K.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

NRG Yield, Inc.:

We have audited NRG Yield, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). NRG Yield, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, NRG Yield, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

The scope of management’s assessment of their effectiveness of internal control over financial reporting included the Company’s consolidated operations except for the operations of Alta Wind Portfolio, which the Company acquired in August 2014. Alta Wind Portfolio represented 43% of the Company’s consolidated total assets and 8% of consolidated operating revenues as of and for the year ended December 31, 2014. Our audit of internal control over financial reporting of NRG Yield, Inc. also excluded an evaluation of the internal control over financial reporting of Alta Wind Portfolio.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of NRG Yield, Inc. and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2014, and our report dated February 27, 2015 expressed an unqualified opinion on those consolidated financial statements.

(signed) KPMG LLP

Philadelphia, PA

February 27, 2015

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Item 9B — Other Information

None.

PART III

Item 10 — Directors, Executive Officers and Corporate Governance

Directors

Kirkland B. Andrews has served as Executive Vice President, Chief Financial Officer and Director since the Company's formation in December 2012. Mr. Andrews has served as Executive Vice President and Chief Financial Officer of NRG Energy since September 2011. Prior to joining NRG, he served as Managing Director and Co-Head Investment Banking, Power and Utilities—Americas at Deutsche Bank Securities from June 2009 to September 2011. Prior to this, he served in several capacities at Citigroup Global Markets Inc., including Managing Director, Group Head, North American Power from November 2007 to June 2009, and Head of Power M&A, Mergers and Acquisitions from July 2005 to November 2007. In his banking career, Mr. Andrews led multiple large and innovative strategic, debt, equity and commodities transactions. Mr. Andrews’ extensive investment banking experience, specifically in the energy industry and financial structuring, brings important experience and skills to the Company’s board of directors.

John F. Chlebowski has served as a Director since July 2013.Mr. Chlebowski had been a director of NRG from December 2003 to July 2013. Mr. Chlebowski served as the President and Chief Executive Officer of Lakeshore Operating Partners, LLC, a bulk liquid distribution firm, from March 2000 until his retirement in December 2004. From July 1999 until March 2000, Mr. Chlebowski was a senior executive and cofounder of Lakeshore Liquids Operating Partners, LLC, a private venture firm in the bulk liquid distribution and logistics business, and from January 1998 until July 1999, he was a private investor and consultant in bulk liquid distribution. From 1994 until 1997, he was the President and Chief Executive Officer of GATX Terminals Corporation, a subsidiary of GATX Corporation. Prior to that, he served as Vice President of Finance and Chief Financial Officer of GATX Corporation from 1986 to 1994. Mr. Chlebowski is a director of First Midwest Bancorp Inc. and the Non-Executive Chairman of SemGroup Corporation. Mr. Chlebowski also served as a director of Laidlaw International, Inc. from June 2003 until October 2007, SpectraSite, Inc. from June 2004 until August 2005, and Phosphate Resource Partners Limited Partnership from June 2004 until August 2005. Mr. Chlebowski’s extensive leadership and financial expertise, as a result of his position as a former chief executive officer and his service on several boards of companies involved in the restructuring or recovery of their core business, enable him to contribute to the board of directors' significant managerial, strategic, and financial oversight skills. Furthermore, Mr. Chlebowski’s service on other public boards, notably as a non-executive Chairman, provides valuable insight into the application of various governance principals to the Company’s board of directors.

David Crane has served as the President, Chief Executive Officer and Director since the Company's formation in December 2012. Mr. Crane has served as the President, Chief Executive Officer of NRG and a director of NRG since December 2003. Prior to joining NRG, Mr. Crane served as Chief Executive Officer of International Power plc, a UK-domiciled wholesale power generation company, from January 2003 to November 2003, and as Chief Operating Officer from March 2000 through December 2002. Mr. Crane was Senior Vice President—Global Power New York at Lehman Brothers Inc., an investment banking firm, from January 1999 to February 2000, and was Senior Vice President—Global Power Group, Asia (Hong Kong) at Lehman Brothers from June 1996 to January 1999. Mr. Crane was also a director of El Paso Corporation from December 2009 to May 2012. As Chief Executive Officer of the Company, Mr. Crane provides the board of directors with management's perspective regarding the Company's day-to-day operations and overall strategic plan. His extensive leadership experience enables Mr. Crane to play a key role in all matters involving the Company's board of directors and act as the head of management to the independent directors of the Company's board of directors. In addition, having recently served as a director of El Paso Corporation, Mr. Crane is able to contribute an additional perspective from the energy industry.

Brian R. Ford has served as a Director since July 2013. Mr. Ford was the Chief Executive Officer of Washington Philadelphia Partners, LP, a real estate investment company, from 2008 through 2010. He retired as a partner from Ernst & Young LLP in June 2008 where he had been employed since 1971. Mr. Ford currently serves on the board of various public companies: GulfMark Offshore, Inc., a global provider of marine transportation, since 2009, where he also serves as the chairman of the audit committee and as a member of the governance nominating committee; AmeriGas Propane, Inc., a propane company, since 2013, where he also serves as a member of its audit committee and corporate governance committee; FS Investment Corporation III, a specialty finance company that invests primarily in the debt securities of private U.S. middle-market companies, since 2013, where he also serves as the chairman of the audit committee.  He also serves on the boards of Drexel University and Drexel University College of Medicine. Mr. Ford received his B.S. in Economics from Rutgers University.  Mr. Ford's extensive experience in accounting and public company matters provides strong financial, audit and accounting skills to the Company's board of directors.

59

Mauricio Gutierrez has served as Executive Vice President, Chief Operating Officer and Director since the Company's formation in December 2012. Mr. Gutierrez has served as Executive Vice President and Chief Operating Officer of NRG since July 2010. In this capacity, Mr. Gutierrez oversees NRG's Plant Operations, Commercial Operations, Environmental Compliance, as well as the Engineering, Procurement and Construction division. He previously served as Executive Vice President, Commercial Operations, from January 2009 to July 2010 and Senior Vice President, Commercial Operations, from March 2008 to January 2009. In this capacity, he was responsible for the optimization of NRG's asset portfolio and fuel requirements. Prior to this, Mr. Gutierrez served as Vice President Commercial Operations Trading from May 2006 to March 2008. Prior to joining NRG in August 2004, Mr. Gutierrez held various positions within Dynegy, Inc., including Managing Director, Trading—Southeast and Texas, Senior Trader East Power and Asset Manager. Prior to Dynegy, Mr. Gutierrez served as senior consultant and project manager at DTP involved in various energy and infrastructure projects in Mexico. Mr. Gutierrez’s knowledge of the Company’s assets, operations and businesses bring important experience and skills to the Company’s board of directors. 

Ferrell P. McClean has served as a Director since July 2013. Ms. McClean was a Managing Director and the Senior Advisor to the head of the Global Oil & Gas Group in Investment Banking at J.P. Morgan Chase & Co. from 2000 through the end of 2001. She joined J.P. Morgan & Co. Incorporated in 1969 and founded the Leveraged Buyout and Restructuring Group within the Mergers & Acquisitions Group in 1986. From 1991 until 2000, Ms. McClean was a Managing Director and co-headed the Global Energy Group within the Investment Banking Group at J.P. Morgan & Co. She retired as a director of GrafTech International in 2014, El Paso Corporation in 2012 and Unocal Corporation in 2005. Ms. McClean's experience in investment banking for industrial companies as well as her experience and understanding of financial accounting, finance and disclosure matters enables her to provide essential guidance to the Company's board of directors and management team.

Christopher S. Sotoshas served as a Director since May 2013. Mr. Sotos has served as Senior Vice President—Strategy and Mergers and Acquisitions of NRG since November 2012. Previously, he served as NRG's Senior Vice President and Treasurer from March 2008 to September 2012. In this role, he was responsible for all treasury functions, including raising capital, valuation, debt administration and cash management. Mr. Sotos joined NRG in 2004 as a Senior Finance Analyst, following more than nine years in key financial roles within the energy sector and other industries for Houston-based companies such as Koch Capital Markets, Entergy Wholesale Operations and Service Corporation International. Mr. Sotos also serves on the board of FuelCell Energy, Inc. Mr. Sotos brings strong financial and accounting skills to the Company's board of directors.

Executive Officers

For biographical information for Mr. Andrews, Mr. Crane and Mr. Gutierrez, see above under “Directors.”

David R. Hill has served as Executive Vice President and General Counsel since the Company's formation in December 2012. Mr. Hill has served as Executive Vice President and General Counsel of NRG since September 2012. Prior to joining NRG, Mr. Hill was a partner and co-head of Sidley Austin LLP's global energy practice group from February 2009 to August 2012. Prior to joining Sidley Austin, Mr. Hill served as General Counsel of the U.S. Department of Energy from August 2005 to January 2009 and, for the three years prior to that, as Deputy General Counsel for Energy Policy of the DOE. Prior to his federal government services, Mr. Hill was a partner at major law firms in Washington D.C. and Kansas City, Missouri, and handled a variety of regulatory, litigation and corporate matters.

Ronald B. Stark has served as Vice President and Chief Accounting Officer since the Company's formation in December 2012. Mr. Stark has served as Vice President and Chief Accounting Officer of NRG since March 2012. Mr. Stark served as the Vice President, Internal Audit of NRG from August 2011 to February 2012. He previously served as Director, Financial Reporting of NRG from October 2007 through July 2011. Mr. Stark joined NRG in January 2007. Prior to joining NRG, Mr. Stark held various executive and managerial accounting positions at Pegasus Communications and Berlitz International and began his career with Deloitte and Touche.

Code of Ethics

The Company has adopted a code of ethics entitled "NRG Yield Code of Conduct" that applies to directors and officers of the Company. It may be accessed through the Corporate Governance section of the Company's website at http://www.nrgyield.com/corpgov.htm. The Company also elects to disclose the information required by Form 8-K, Item 5.05, "Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the Code of Ethics," through the Company's website, and such information will remain available on this website for at least a 12-month period. A copy of the "NRG Yield, Inc. Code of Conduct" is available in print to any stockholder who requests it.

Information required by this Item will be incorporated by reference to the similarly named section of the Company's definitive Proxy Statement for its 2015 Annual Meeting of Stockholders.

60

Item 11 — Executive Compensation

Other information required by this Item will be incorporated by reference to the similarly named section of the Company's Definitive Proxy Statement for its 2015 Annual Meeting of Stockholders.

Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Securities Authorized for Issuance under Equity Compensation Plans

Plan Category	(a) Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights	(b) Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		(c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
Equity compensation plans approved by security holders	24,611	$	—	954,139
Equity compensation plans not approved by security holders	—	N/A		—
Total	24,611	$	—	954,139

Other information required by this Item will be incorporated by reference to the similarly named section of NRG Yield, Inc.'s Definitive Proxy Statement for its 2015 Annual Meeting of Stockholders.

Item 13 — Certain Relationships and Related Transactions, and Director Independence

Information required by this Item will be incorporated by reference to the similarly named section of the Company's Definitive Proxy Statement for its 2015 Annual Meeting of Stockholders.

Item 14 — Principal Accounting Fees and Services

Information required by this Item will be incorporated by reference to the similarly named section of the Company's Definitive Proxy Statement for its 2015 Annual Meeting of Stockholders.

61

PART IV

Item 15 — Exhibits, Financial Statement Schedules

(a)(1) Financial Statements

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

Consolidated Statements of Operations — Years ended December 31, 2014, 2013 and 2012

Consolidated Statements of Comprehensive Income (Loss) — Years ended December 31, 2014, 2013 and 2012

Consolidated Balance Sheets — December 31, 2014 and 2013

Consolidated Statements of Cash Flows — Years ended December 31, 2014, 2013 and 2012

Consolidated Statement of Stockholders' Equity — Years ended December 31, 2014, 2013 and 2012

Notes to Consolidated Financial Statements

(a)(2) Financial Statement Schedules

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

NRG Yield, Inc. Financial Statements for the year ended December 31, 2014 and 2013 are included in NRG Yield, Inc.'s Annual Report on Form 10-K pursuant to the requirements of Rule 5-04(c) of Regulation S-X

GCE Holding LLC Unaudited Consolidated Financial Statements for the years ended December 31, 2014 and 2013 and GCE Holding LLC Audited Consolidated Financial Statements for the year ended December 31, 2012 are included in NRG Yield, Inc.'s Annual Report on Form 10-K pursuant to the requirements of Rule 3-09 of Regulation S-X

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

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

(b) Exhibits

See Exhibit Index submitted as a separate section of this report

(c) Not applicable

62

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

NRG Yield, Inc.:

We have audited the accompanying consolidated balance sheets of NRG Yield, Inc. and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2014. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule “Schedule I. Condensed Financial Information of Registrant.” These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedules based on our audits. We did not audit the December 31, 2012 consolidated financial statements of GCE Holding, LLC (a 50% owned investee company). The Company’s investment in GCE Holding, LLC at December 31, 2012 was $125 million, and its equity in earnings of GCE Holding, LLC was $15 million for the year ended December 31, 2012. The consolidated financial statements of GCE Holding, LLC were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for GCE Holding, LLC, is based solely on the report of the other auditors.

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

In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NRG Yield, Inc. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), NRG Yield, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Our report dated February 27, 2015, on the effectiveness of internal control over financial reporting as of December 31, 2014, contains an explanatory paragraph that states that the scope of management’s assessment of their effectiveness of internal control over financial reporting included the Company’s consolidated operations except for the operations of Alta Wind Portfolio, which the Company acquired in August 2014. Alta Wind Portfolio represented 43% of the Company’s consolidated total assets and 8% of consolidated operating revenues as of and for the year ended December 31, 2014. Our audit of internal control over financial reporting of NRG Yield, Inc. also excluded an evaluation of the internal control over financial reporting of Alta Wind Portfolio.

(signed) KPMG LLP

Philadelphia, Pennsylvania

February 27, 2015

63

NRG YIELD, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year ended December 31,
(In millions, except per share amounts)	2014			2013 (a)			2012 (a)
Operating Revenues
Total operating revenues	$	583		$	379		$	175
Operating Costs and Expenses
Cost of operations	214			144			114
Depreciation and amortization	136			61			25
General and administrative — affiliate	8			7			7
Acquisition-related transaction and integration costs	4			—			—
Total operating costs and expenses	362			212			146
Operating Income	221			167			29
Other Income (Expense)
Equity in earnings of unconsolidated affiliates	27			22			19
Other income, net	3			3			2
Interest expense	(166		)	(52		)	(28		)
Total other expense	(136		)	(27		)	(7		)
Income Before Income Taxes	85			140			22
Income tax expense	4			8			10
Net Income	$	81		$	132		$	12
Less: Pre-acquisition net income of Acquired ROFO Assets	17			23
Net Income Excluding Pre-acquisition Net Income of Acquired ROFO Assets	64			109
Less: Predecessor income prior to initial public offering on July 22, 2013	—			54
Less: Net income attributable to NRG (b)	48			42
Net Income Attributable to NRG Yield, Inc.	$	16		$	13
Earnings Per Share Attributable to NRG Yield, Inc. Class A Common Stockholders
Weighted average number of Class A common shares outstanding - basic and diluted	28			23
Earnings per Weighted Average Class A Common Share - Basic and Diluted	$	0.59		$	0.57
Dividends Per Common Share	$	1.42		$	0.23

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

^(b)The calculation of income attributable to NRG excludes pre-acquisition net income of the Acquired ROFO Assets.

See accompanying notes to consolidated financial statements.

64

NRG YIELD, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Year ended December 31,
	2014			2013 (a)		2012 (a)
	(In millions)
Net Income	$	81		$	132	$	12
Other Comprehensive (Loss) Income, net of tax
Unrealized gain (loss) on derivatives, net of income tax benefit (expense) of $5, $(16), and $7	(29		)	48		(20		)
Other comprehensive (loss) income	(29		)	48		(20		)
Comprehensive Income (Loss)	52			180		$	(8	)
Less: Predecessor comprehensive income prior to initial public offering on July 22, 2013	—			73
Less: Pre-acquisition net income of Acquired ROFO Assets	17			23
Less: Comprehensive income attributable to NRG	28			69
Comprehensive Income Attributed to NRG Yield Inc.	$	7		$	15

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

See accompanying notes to consolidated financial statements.

65

NRG YIELD, INC.

CONSOLIDATED BALANCE SHEETS

	December 31, 2014			December 31, 2013 (a)
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	391		$	59
Restricted cash	22			67
Accounts receivable — trade	67			51
Accounts receivable — affiliate	—			5
Inventory	18			15
Derivative instruments	—			1
Notes receivable	6			6
Renewable energy grant receivable	—			147
Deferred income taxes	16			—
Prepayments and other current assets	19			27
Total current assets	539			378
Property, plant and equipment
In service	3,788			2,459
Under construction	7			6
Total property, plant and equipment	3,795			2,465
Less accumulated depreciation	(308		)	(174		)
Net property, plant and equipment	3,487			2,291
Other Assets
Equity investments in affiliates	227			227
Notes receivable	15			21
Notes receivable — affiliate	—			2
Intangible assets, net of accumulated amortization of $26 and $7	1,266			103
Derivative instruments	1			20
Deferred income taxes	118			146
Other non-current assets	99			50
Total other assets	1,726			569
Total Assets	$	5,752		$	3,238

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

See accompanying notes to consolidated financial statements.

66

NRG YIELD, INC.

CONSOLIDATED BALANCE SHEETS (Continued)

	December 31, 2014			December 31, 2013 (a)
LIABILITIES AND STOCKHOLDERS’ EQUITY	(In millions, except share information)
Current Liabilities
Current portion of long-term debt	$	160		$	214
Accounts payable	19			42
Accounts payable — affiliate	44			52
Derivative instruments	31			31
Accrued expenses and other current liabilities	43			30
Total current liabilities	297			369
Other Liabilities
Long-term debt	3,890			1,569
Derivative instruments	46			16
Other non-current liabilities	39			32
Total non-current liabilities	3,975			1,617
Total Liabilities	4,272			1,986
Commitments and Contingencies	—			—
Stockholders' Equity
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued	—			—
Class A common stock, $0.01 par value; 500,000,000 shares authorized; 34,586,250 and 22,511,250 shares issued at December 31, 2014 and 2013	—			—
Class B common stock, $0.01 par value; 500,000,000 shares authorized; 42,738,750 shares issued at December 31, 2014 and 2013	—			—
Additional paid-in capital	1,240			621
Retained earnings	3			8
Accumulated other comprehensive loss	(9		)	—
Noncontrolling interest	246			623
Total Stockholders' Equity	1,480			1,252
Total Liabilities and Stockholders' Equity	$	5,752		$	3,238

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

See accompanying notes to consolidated financial statements.

67

NRG YIELD, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended December 31,
	2014			2013 (a)			2012 (a)
	(In millions)
Cash Flows from Operating Activities
Net income	$	81		$	132		$	12
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	(3		)	(6		)	2
Depreciation and amortization	136			61			25
Amortization of financing costs and debt discount/premiums	10			4			—
Amortization of intangibles and out-of-market contracts	17			1			—
Changes in deferred income taxes	4			8			10
Changes in derivative instruments	9			(21		)	2
Changes in other working capital	(31		)	(59		)	5
Net Cash Provided by Operating Activities	223			120			56
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired	(901		)	(120		)	—
Payment to NRG for Acquired ROFO assets	(357		)	—			—
Capital expenditures	(33		)	(353		)	(564		)
Decrease (increase) in restricted cash	60			(43		)	(12		)
Decrease (increase) in notes receivable, including affiliates	8			10			(17		)
Proceeds from renewable energy grants	137			25			28
Investments in unconsolidated affiliates	7			(34		)	(27		)
Other	11			—			(2		)
Net Cash Used in Investing Activities	(1,068		)	(515		)	(594		)
Cash Flows from Financing Activities
Capital contributions from NRG	2			171			355
Distributions and return of capital to NRG	(23		)	(707		)	(72		)
Proceeds from issuance of Class A common stock	630			468			—
Payment of dividends and distributions	(101		)	(15		)	—
Proceeds from issuance of long-term debt — external	924			594			308
Payment of debt issuance costs	(27		)	(5		)	(12		)
Payments for long-term debt — external	(228		)	(72		)	(37		)
Payments for long-term debt — affiliate	—			(2		)	(6		)
Net Cash Provided by Financing Activities	1,177			432			536
Net Increase (Decrease) in Cash and Cash Equivalents	332			37			(2		)
Cash and Cash Equivalents at Beginning of Period	59			22			24
Cash and Cash Equivalents at End of Period	$	391		$	59		$	22
Supplemental Disclosures
Interest paid, net of amount capitalized	$	(137	)	$	(63	)	$	(17	)
Non-cash investing and financing activities:
Additions to fixed assets for accrued capital expenditures	—			1			121
Decrease to fixed assets for accrued grants	—			(207		)	(1		)
Decrease to fixed assets for deferred tax asset	—			(12		)	—
Non-cash addition to additional paid-in capital for change in tax basis of property, plant and equipment for assets acquired from NRG	(14		)	153			—
Non-cash capital contributions from NRG	16			80			166
Non-cash return of capital and dividends to NRG	—			(76		)	—

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

See accompanying notes to consolidated financial statements.

68

NRG YIELD, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

	Preferred Stock		Class A Common Stock		Class B Common Stock		Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncon-trolling Interest			Members' Equity (a)			Total Members'/Stockholders' Equity (a)
	(In millions)
Balance as of December 31, 2011 (b)	$	—	$	—	$	—	$	—		$	—		$	—		$	—		$	387		$	387
Members' equity - Acquired ROFO Assets	—		—		—		—			—			—			—			174			174
Balances at December 31, 2011	$	—	$	—	$	—	$	—		$	—		$	—		$	—		$	561		$	561
Net Income	—		—		—		—			—			—			—			$	12		$	12
Unrealized gain on derivatives, net of tax	—		—		—		—			—			—			—			(20		)	(20		)
Capital contributions from NRG, cash	—		—		—		—			—			—			—			355			355
Capital contributions from NRG, non-cash	—		—		—		—			—			—			—			166			166
Dividends and return of capital to NRG, cash	—		—		—		—			—			—			—			(72		)	(72		)
Balances at December 31, 2012	$	—	$	—	$	—	$	—		$	—		$	—		$	—		$	1,002		$	1,002
Net Income	—		—		—		—			—			—			—			54			54
Unrealized gain on derivatives, net of tax	—		—		—		—			—			—			—			38			38
Capital contributions from NRG, cash	—		—		—		—			—			—			—			171			171
Capital contributions from NRG, non-cash	—		—		—		—			—			—			—			66			66
Dividends and return of capital to NRG, cash	—		—		—		—			—			—			—			(312		)	(312		)
Dividends and return of capital to NRG, non-cash	—		—		—		—			—			—			—			(33		)	(33		)
Balance as of July 22, 2013	$	—	$	—	$	—	$	—		$	—		$	—		$	—		$	986		$	986
Net Income	—		—		—		—			13			—			65			—			78
Unrealized (loss) gain on derivatives, net	—		—		—		—			—			(3		)	9			—			6
Capital contributions from NRG, non-cash	—		—		—		—			—			—			14			—			14
Distributions and return of capital to NRG, cash	—		—		—		—			—			—			—			(395		)	(395		)
Transfer of predecessors' equity to noncontrolling interest	—		—		—		—			—			3			588			(591		)	—
Reduction to non-controlling interest, non-cash	—		—		—		—			—			—			(43		)	—			(43		)
Common shares issued in public offering	—		—		—		468			—			—			—			—			468
Adjustment for change in tax basis of property, plant and equipment, non-cash	—		—		—		153			—			—			—			—			153
Payment of dividends to Class A common stockholders	—		—		—		—			(5		)	—			(10		)	—			(15		)
Balances at December 31, 2013	$	—	$	—	$	—	$	621		$	8		$	—		$	623		$	—		$	1,252
Net Income	—		—		—		—			16			—			48			—			64
Pre-acquisition net income of Acquired ROFO Assets	—		—		—		—			—			—			17			—			17
Unrealized loss on derivatives, net of tax	—		—		—		—			—			(9		)	(20		)	—			(29		)
Capital contributions from NRG, non-cash	—		—		—		—			—			—			16			—			16
Distributions and returns of capital to NRG net of contributions, cash	—		—		—		—			—			—			(21		)	—			(21		)
Payment for Acquired ROFO Assets	—		—		—		—			—			—			(357		)	—			(357		)
Proceeds from the issuance of Class A common stock	—		—		—		630			—			—			—			—			630
Equity portion of the convertible debt	—		—		—		23			—			—			—			—			23
Common stock dividends	—		—		—		(20		)	(21		)	—			(60		)	—			(101		)
Adjustment for change in tax basis of assets acquired from NRG, non-cash	—		—		—		(14		)	—			—			—			—			(14		)
Balances at December 31, 2014	$	—	$	—	$	—	$	1,240		$	3		$	(9	)	$	246		$	—		$	1,480

^(a)Retrospectively adjusted starting on January 1, 2012 as discussed in Note 1, Nature of Business.

^(b) As previously reported.

See accompanying notes to consolidated financial statements.

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NRG YIELD, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Nature of Business

NRG Yield, Inc., or the Company, was formed by NRG as a Delaware corporation on December 20, 2012. On July 22, 2013, the Company issued 22,511,250 shares of Class A common stock in an initial public offering. The Company utilized the net proceeds of the initial public offering to acquire 19,011,250 Class A units of NRG Yield LLC from NRG in return for $395 million, and 3,500,000 Class A units of NRG Yield LLC directly from NRG Yield LLC in return for $73 million.  In connection with the acquisition of the Class A units, the Company also became the sole managing member of NRG Yield LLC thereby acquiring a controlling interest in NRG Yield LLC. 

Immediately prior to the acquisition, NRG Yield LLC acquired a portfolio of contracted renewable and conventional generation and thermal infrastructure assets, primarily located in the Northeast, Southwest and California regions of the U.S., from NRG in return for Class B units in NRG Yield LLC.  These assets were simultaneously contributed by NRG Yield LLC to its direct wholly owned subsidiary NRG Yield Operating LLC at their historical cost in accordance with ASC 805-50, Business Combinations - Related Issues. 

Prior to the secondary offering, the Company and NRG owned 34.5% and 65.5% of NRG Yield LLC, respectively. On July 29, 2014, the Company issued 12,075,000 shares of Class A common stock secondary offering for net proceeds, after underwriting discount and expenses, of $630 million. The Company utilized the proceeds of the offering to acquire 12,075,000 additional Class A units of NRG Yield LLC and, as a result, subsequent to the secondary offering and as of December 31, 2014, the Company owns 44.7% of NRG Yield LLC, and consolidates the results of NRG Yield LLC through its controlling interest, with NRG's 55.3% interest shown as noncontrolling interest in the financial statements. The holders of the Company's issued and outstanding shares of Class A common stock have 100% of economic interest and are entitled to dividends. NRG receives distributions from Yield LLC through its ownership of Class B common units.

The following table represents the structure of the Company as of December 31, 2014:

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For all periods prior to the initial public offering, the accompanying combined financial statements represent the combination of the assets that NRG Yield LLC acquired and were prepared using NRG's historical basis in the assets and liabilities. For the purposes of the combined financial statements, the term "NRG Yield" represents the accounting predecessor, or the combination of the acquired businesses. For all periods subsequent to the initial public offering, the accompanying audited consolidated financial statements represent the consolidated results of the Company, which consolidates NRG Yield LLC through its controlling interest.

As of December 31, 2014, the Company's operating assets are comprised of the following projects:

Projects	Percentage Ownership		Net Capacity (MW) (a)	Offtake Counterparty	Expiration
Conventional
GenConn Middletown	49.95	%	95	Connecticut Light & Power	2041
GenConn Devon	49.95	%	95	Connecticut Light & Power	2040
Marsh Landing	100	%	720	Pacific Gas and Electric	2023
El Segundo	100	%	550	Southern California Edison	2023
			1,460
Utility Scale Solar
Alpine	100	%	66	Pacific Gas and Electric	2033
Avenal	49.95	%	23	Pacific Gas and Electric	2031
Avra Valley	100	%	25	Tucson Electric Power	2032
Blythe	100	%	21	Southern California Edison	2029
Borrego	100	%	26	San Diego Gas and Electric	2038
Roadrunner	100	%	20	El Paso Electric	2031
CVSR	48.95	%	122	Pacific Gas and Electric	2038
RE Kansas South	100	%	20	Pacific Gas and Electric	2033
TA High Desert	100	%	20	Southern California Edison	2033
			343
Distributed Solar
AZ DG Solar Projects	100	%	5	Various	2025 - 2033
PFMG DG Solar Projects	51	%	5	Various	2032
			10
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	100	%	137	Southern California Edison	2038(c)
Alta XI	100	%	90	Southern California Edison	2038(c)
South Trent	100	%	101	AEP Energy Partners	2029
			1,048
Thermal
Thermal equivalent MWt(b)	100	%	1,310	Various	Various
Thermal generation	100	%	124	Various	Various
Total net capacity (excluding equivalent MWt)			2,985

(a) Net capacity represents the maximum, or rated, generating capacity of the facility multiplied by the Company's percentage ownership in the facility as of December 31, 2014.

(b) 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 NRG Yield Inc.'s thermal facilities and certain of its customers.

(c) PPA begins on January 1, 2016.

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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 of the 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.

The historical combined financial statements include allocations of certain NRG corporate expenses. Management believes the assumptions and methodology underlying the allocation of general corporate overhead expenses are reasonable. The allocated costs include legal, accounting, tax, treasury, information technology, insurance, employee benefit costs, and other corporate costs. However, such expenses may not be indicative of the actual level of expense that would have been incurred if the Company had operated as an independent, publicly-traded company during the periods prior to the offering or of the costs expected to be incurred in the future. Allocations of NRG corporate expenses were $4 million for the period beginning on January 1, 2013 and ending on July 22, 2013 and $7 million for the year ended December 31, 2012. In connection with the initial public offering, the Company entered into a management services agreement with NRG for various services, including human resources, accounting, tax, legal, information systems, treasury, and risk management. Costs incurred by the Company under this agreement were $3 million for the period beginning July 23, 2013 and ending December 31, 2013 and $8 million for the year ended December 31, 2014, which included certain direct expenses incurred by NRG on behalf of the Company.

For all periods prior to the initial public offering, member's equity represents the combined equity of the Company's subsidiaries, including adjustments necessary to present the Company's financial statements as if the Company were in existence as of the beginning of the periods presented. Member's equity represents NRG's equity in the subsidiaries, and accordingly, in connection with the initial public offering, the historical equity balance as of that date was reclassified into noncontrolling interest. Subsequent to the initial public offering, stockholders' equity represents the equity associated with the Class A common stockholders, with the equity associated with the Class B common stockholders, or NRG, classified as noncontrolling interest.

As described in Note 3, Business Acquisitions, on June 30, 2014, NRG Yield Operating LLC acquired the TA High Desert, RE Kansas South, and El Segundo projects from NRG for total cash consideration of $357 million plus assumed project level debt. The acquisition of the TA High Desert, RE Kansas South, and El Segundo projects from NRG on June 30, 2014 was accounted for as a transfer of entities under common control. The guidance requires retrospective combination of the entities for all periods presented as if the combination has been in effect since the inception of common control. Accordingly, the Company prepared its consolidated financial statements to reflect the transfer as if it had taken place from the beginning of the financial statements period, or from the date the entities were under common control, which was May 13, 2013 for RE Kansas South and March 28, 2013 for TA High Desert, which represent the dates these entities were acquired by NRG. Member's equity represents NRG's equity in the subsidiaries, and accordingly, in connection with the acquisition by the Company, the balance was reclassified into noncontrolling interest.

Note 2 — Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The Company's consolidated and combined financial statements have been prepared in accordance with U.S. GAAP. The Financial Accounting Standards Board, or FASB, Accounting Standards Codification, or ASC, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants.

The consolidated and combined financial statements include the Company's accounts and operations and those of its subsidiaries in which it has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, the Company applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a variable interest entity, or VIE, should be consolidated.

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Cash and Cash Equivalents

Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.

Restricted Cash

Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use. These funds are used to pay for capital expenditures, current operating expenses and current debt service payments as well as to fund required equity contributions, per the restrictions of the debt agreements.

Trade Receivables and Allowance for Doubtful Accounts

Trade receivables are reported on the balance sheet at the invoiced amount adjusted for any write-offs and the allowance for doubtful accounts. The allowance for doubtful accounts is reviewed periodically based on amounts past due and significance. The allowance for doubtful accounts was immaterial as of December 31, 2014, and 2013.

Inventory

Inventory consists principally of spare parts and fuel oil and is valued at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost will be recovered with a normal profit in the ordinary course of business. The Company removes fuel inventories as they are used in the production of steam, chilled water or electricity. Spare parts inventory are removed when they are used for repairs, maintenance or capital projects.

Property, Plant and Equipment

Property, plant and equipment are stated at cost or, in the case of business acquisitions, fair value; however impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. See Note 3, Business Acquisitions, for more information on acquired property, plant and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation is computed using the straight-line method over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of operations.

Additionally, the Company reduces the book value of the property, plant and equipment of its eligible renewable energy projects for any cash grants that are submitted to the U.S. Treasury Department when the receivable is recorded for the net realizable amount. The related deferred tax asset is also recorded with a corresponding reduction to the book value of the property, plant and equipment. For further discussion of these matters see Note 4, Property, Plant and Equipment.

Asset Impairments

Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the statements of operations. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.

Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-Equity Method and Joint Ventures, or ASC 323, which requires that a loss in value of an investment that is other than a temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value.

Capitalized Interest

Interest incurred on funds borrowed to finance capital projects is capitalized, until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2014, 2013 and 2012 was less than $1 million, $18 million and $31 million, respectively.

When a project is available for operations, capitalized interest is reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets.

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Debt Issuance Costs

Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt.

Intangible Assets

Intangible assets represent contractual rights held by NRG Yield, Inc. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationship, power purchase agreements and development rights when specific rights and contracts are acquired. These intangible assets are amortized primarily on a straight-line basis.

Notes Receivable

Notes receivable consist of receivables related to the financing of required network upgrades and a variable-rate note secured by the equity interest in a joint venture. The notes issued with respect to network upgrades will be repaid within a 5 year period following the date each facility reaches commercial operations.

Income Taxes

The Company accounts for income taxes using the liability method in accordance with ASC 740, Income Taxes, or ASC 740, which requires that it use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

The Company has two categories of income tax expense or benefit — current and deferred, as follows:

• Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and

• Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income.

The Company reports some of its revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. The Company measures its deferred income tax assets and deferred income tax liabilities using income tax rates that are currently in effect. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets, net of valuation allowances. A valuation allowance is recorded to reduce the net deferred tax assets to an amount that is more-likely-than-not to be realized.

The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense.

In accordance with ASC 805 and as discussed further in Note 13, Income Taxes, changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax expense.

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Revenue Recognition

Thermal Revenues

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

Power Purchase Agreements, or PPAs

The majority of the Company’s revenues are obtained through PPAs or other contractual agreements. In order to determine lease classification as operating, the Company evaluates the terms of the PPA to determine if the lease includes any of the following provisions which would indicate capital lease treatment:

• Transfers the ownership of the generating facility,

• Bargain purchase option at the end of the term of the lease,

• Lease term is greater than 75% of the economic life of the generating facility, or

• Present value of minimum lease payments exceed 90% of the fair value of the generating facility at inception of the lease

In considering the above it was determined that all of Company’s PPAs are operating leases. ASC 840 requires the minimum lease payments received to be amortized over the term of the lease and contingent rentals are recorded when the achievement of the contingency becomes probable. Judgment is required by management in determining the economic life of each generating facility, in evaluating whether certain lease provisions constitute minimum payments or represent contingent rent and other factors in determining whether a contract contains a lease and whether the lease is an operating lease or capital lease.

Certain of these leases have no minimum lease payments and all of the rental income under these leases is recorded as contingent rent on an actual basis when the electricity is delivered. The contingent rental income recognized in the years ended December 31, 2014, 2013 and 2012 was $158 million, $105 million and $33 million, respectively.

Derivative Financial Instruments

The Company accounts for derivative financial instruments under ASC 815, Derivatives and Hedging, or ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value unless they qualify for a NPNS exception. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as hedges, if elected for hedge accounting, are either:

• Recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments; or

• Deferred and recorded as a component of accumulated OCI until the hedged transactions occur and are recognized in earnings.

The Company's primary derivative instruments are fuels purchase contracts used to control customer reimbursable fuel cost and interest rate instruments used to mitigate variability in earnings due to fluctuations in interest rates. On an ongoing basis, the Company assesses the effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. Internal analyses that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such a contract designated as a hedge. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. In this case, the gain or loss previously deferred in accumulated OCI would be frozen until the underlying hedged item is delivered unless the transaction being hedged is no longer probable of occurring in which case the amount in OCI would be immediately reclassified into earnings. If the derivative instrument is terminated, the effective portion of this derivative deferred in accumulated OCI will be frozen until the underlying hedged item is delivered.

Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.

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Concentrations of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of accounts receivable, notes receivable and derivative instruments. Accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy and financial industry. These industry concentrations may impact the overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. In addition, many of the Company's projects have only one customer. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See Note 6, Fair Value of Financial Instruments, for a further discussion of derivative concentrations and Note 12, Segment Reporting for concentration of counterparties.

Fair Value of Financial Instruments

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

Asset Retirement Obligations

Asset retirement obligations, or AROs, are accounted for in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made.

Upon initial recognition of a liability for an ARO, the asset retirement cost is capitalized by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. The Company's asset retirement obligations were $18 million and $9 million for the years ended December 31, 2014, and 2013, respectively. The Company records AROs as part of other non-current liabilities on its balance sheet.

Guarantees

The Company enters into various contracts that include indemnification and guarantee provisions as a routine part of its business activities. Examples of these contracts include EPC agreements, operation and maintenance agreements, service agreements, commercial sales arrangements and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Because many of the guarantees and indemnities the Company issues to third parties and affiliates do not limit the amount or duration of its obligations to perform under them, there exists a risk that the Company may have obligations in excess of the amounts agreed upon in the contracts mentioned above. For those guarantees and indemnities that do not limit the liability exposure, it may not be able to estimate what the liability would be, until a claim is made for payment or performance, due to the contingent nature of these contracts.

Investments Accounted for by the Equity Method

The Company has investments in three energy projects accounted for by the equity method, one of which is a VIE, where the Company is not a primary beneficiary. The equity method of accounting is applied to these investments in affiliates because the ownership structure prevents the Company from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of the investments is reflected as equity in earnings of unconsolidated affiliates.

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Sale Leaseback Arrangements

The Company is party to sale-leaseback arrangements that provide for the sale of certain assets to a third party and simultaneous leaseback to the Company. In accordance with ASC 840-40, Sale-Leaseback Transactions, if the seller-lessee retains, through the leaseback, substantially all of the benefits and risks incident to the ownership of the property sold, the sale-leaseback transaction is accounted for as a financing arrangement. An example of this type of continuing involvement would include an option to repurchase the assets or the buyer-lessor having the option to sell the assets back to the Company. This provision is included in most of the Company’s sale-leaseback arrangements. As such, the Company accounts for these arrangements as financings.

Under the financing method, the Company does not recognize as income any of the sale proceeds received from the lessor that contractually constitutes payment to acquire the assets subject to these arrangements. Instead, the sale proceeds received are accounted for as financing obligations and leaseback payments made by the Company are allocated between interest expense and a reduction to the financing obligation. Interest on the financing obligation is calculated using the Company’s incremental borrowing rate at the inception of the arrangement on the outstanding financing obligation. Judgment is required to determine the appropriate borrowing rate for the arrangement and in determining any gain or loss on the transaction that would be recorded either at the end of or over the lease term.

Business Combinations

The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805. ASC 805 requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity's financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred.

Use of Estimates

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

In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, environmental liabilities, acquisition accounting and legal costs incurred in connection with recorded loss contingencies, among others. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Reclassifications

Certain prior-year amounts have been reclassified for comparative purposes.

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Recent Accounting Developments

ASU 2014-16 - In November 2014, the FASB issued ASU No. 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity, or ASU No. 2014-16. The amendments of ASU No. 2014-16 clarify how U.S. GAAP should be applied in determining whether the nature of a host contract is more akin to debt or equity and in evaluating whether the economic characteristics and risks of an embedded feature are "clearly and closely related" to its host contract. The guidance in ASU No. 2014-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.

ASU 2014-09 - In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU No. 2014-09. 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 U.S. GAAP and International Financial Reporting Standards, or IFRS, and to improve financial reporting. The guidance in ASU No. 2014-09 provides that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the considerations 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. The guidance of ASU No. 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods therein. Early adoption is not permitted. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.

ASU 2013-11 - In July 2013, the FASB issued ASU No. 2013-11, Income Taxes (Topic 740) Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, or ASU No. 2013-11.  The amendments of ASU 2013-11, require an entity to present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, as a reduction of a deferred tax asset for an NOL, a similar tax loss or tax credit carryforwards rather than a liability when the uncertain tax position would reduce the NOL or other carryforward under the tax law of the applicable jurisdiction and the entity intends to use the deferred tax asset for that purpose.  The guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company adopted this standard effective January 1, 2014. The adoption of this standard did not impact the Company's results of operations or cash flows as the Company has no uncertain tax benefits as of December 31, 2014.

Note 3 — Business Acquisitions

2014 Acquisitions

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

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

The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The initial accounting for the business combination is not complete because the evaluation necessary to assess the fair values of certain net assets acquired is still in process. The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. The allocation of the purchase price may be modified up to one year from the date of the acquisition as more information is obtained about the fair value of assets acquired and liabilities assumed. The purchase price of $923 million was provisionally allocated as follows:

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	Acquisition Date		Measurement period adjustments			Revised Acquisition Date
	(In millions)
Assets
Cash	$	22	$	—		$	22
Current and non-current assets	49		—			49
Property, plant and equipment	1,057		247			1,304
Intangible assets	1,420		(243		)	1,177
Total assets acquired	2,548		4			2,552
Liabilities
Debt	1,591		—			1,591
Current and non-current liabilities	34		4			38
Total liabilities assumed	1,625		4			1,629
Net assets acquired	$	923	$	—		$	923

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

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Fair value measurements

The provisional fair values of the property, plant and equipment and intangible assets at the acquisition date were measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined in ASC 820. Significant inputs were as follows:

• Property, plant and equipment— The estimated fair values were determined primarily based on an income method using discounted cash flows and validated using a cost approach based on the replacement cost of the assets less economic obsolescence. The income approach was applied by determining the enterprise value for each acquired entity and subtracting the fair value of the intangible assets and working capital to determine the implied value of the tangible fixed assets. This methodology was primarily relied upon as the forecasted cash flows incorporate the specific attributes of each asset including age, useful life, equipment condition and technology. The income approach also allows for an accurate reflection of current and expected market dynamics such as supply and demand and regulatory environment as of the acquisition date.

• Intangible Assets - PPAs— The fair values of the PPAs acquired were determined utilizing a variation of the income approach where the incremental future cash flows resulting from the acquired PPAs compared to the cash flows based on current market prices were discounted to present value at a weighted average cost of capital reflective of a market participant. The values were corroborated with available market data. The PPA values will be amortized over the term of the PPAs, which approximate 22 years.

• Intangible Assets - Leasehold rights— The fair values of the leasehold rights acquired, which represent the contractual right to receive royalty payments equal to a percentage of PPA revenue from certain projects, were determined utilizing the income approach. The values were corroborated with available market data. The leasehold rights values will be amortized over a period of 21 years, which is equal to the average term of the contracts.

Supplemental Pro Forma Information

Since the acquisition date, the Alta Wind Portfolio contributed $49 million in operating revenues and $39 million in net losses. The following unaudited supplemental pro forma information represents the results of operations as if the Company had acquired the Alta Wind Portfolio on January 1, 2013:

	For the year ended December 31,
(In millions, except per share amounts)	2014		2013
Operating Revenues	$	715	$	531
Net Income	63		87
Net Income Attributable to NRG Yield, Inc.	7		8
Earnings per Weighted Average Class A Common Share - Basic and Diluted	$	0.20	$	0.23

The supplemental unaudited pro forma information has been adjusted to include the pro forma impact of depreciation of property, plant and equipment and amortization of PPAs, based on the preliminary purchase price allocations. The pro forma data has also been adjusted to reflect the additional interest expense in connection with the issuance of Senior Notes, adjustment to the non-controlling interest due to the change in NRG's ownership interest to 55.3% from 65.5% effective July 29, 2014, as well as the related tax impact. There were no transactions during the periods between NRG and the Alta Wind Portfolio. The pro forma results are presented for illustrative purposes only and do not reflect the realization of potential cost savings or any related integration costs.

Acquired ROFO Assets —On June 30, 2014, NRG Yield Operating LLC acquired from NRG: (i) El Segundo, a 550 MW fast-start, gas-fired facility located in Los Angeles County, California; (ii) TA High Desert, a 20 MW solar facility located in Los Angeles County, California; and (iii) RE Kansas South, a 20 MW solar facility located in Kings County, California. The Company paid total cash consideration of $357 million, which represents a base purchase price of $349 million and $8 million of working capital adjustments. In addition, the acquisition included the assumption of $612 million in project- level debt. The assets and liabilities transferred to the Company relate to interests under common control by NRG and accordingly, were recorded at historical cost in accordance with ASC 805-50. The difference between the cash proceeds and historical value of the net assets was recorded as a distribution to NRG and reduced the balance of its noncontrolling interest. Since the transaction constituted a transfer of entities under common control, the guidance requires retrospective combination of the entities for all periods presented as if the combination has been in effect since the inception of common control.

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The following is a summary of assets and liabilities transferred in connection with the acquisition as of June 30, 2014:

	RE Kansas South		TA High Desert		El Segundo
	(In millions)
Current assets	$	1	$	3	$	43
Property, plant and equipment	50		67		625
Non-current assets	2		13		76
Total assets	53		83		744
Debt	35		57		520
Other current and non-current liabilities	2		—		30
Total liabilities	37		57		550
Net assets acquired	$	16	$	26	$	194

The following table presents historical information summary combining the financial information for the Acquired ROFO Assets transferred in connection with the acquisition:

	December 31, 2013
	As Previously Reported		RE Kansas South		TA High Desert		El Segundo		As Currently Reported
			(In millions)
Current assets	$	267	$	25	$	28	$	58	$	378
Property, plant and equipment	1,541		51		63		636		2,291
Non-current assets	505		3		10		51		569
Total assets	2,313		79		101		745		3,238
Debt	1,133		58		80		512		1,783
Other current and non-current liabilities	169		5		3		26		203
Total liabilities	$	1,302	$	63	$	83	$	538	$	1,986

	Year ended December 31, 2013
	As Previously Reported		RE Kansas South			TA High Desert		El Segundo		As Currently Reported
Operating revenues	$	313	$	2		$	8	$	56	$	379
Operating income	128		1			4		34		167
Net income	$	109	$	(1	)	$	1	$	23	$	132

2013 Acquisitions

Energy Systems — On December 31, 2013, NRG Energy Center Omaha Holdings, LLC, an indirect wholly owned subsidiary of NRG Yield LLC, acquired Energy Systems Company, or Energy Systems, for approximately $120 million. The acquisition was financed from cash on hand. Energy Systems is an operator of steam and chilled water thermal facilities that provides heating and cooling services to nonresidential customers in Omaha, Nebraska. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The purchase price was primarily allocated to property, plant and equipment of $60 million, customer relationships of $59 million, and $1 million of working capital. The accounting for Energy Systems was completed as of September 30, 2014, at which point the provisional fair values became final with no material changes.

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2012 Acquisitions

Marsh Landing— On December 14, 2012, through its acquisition of GenOn Energy, Inc., or GenOn, NRG acquired 100% of the Marsh Landing project, a 720 MW natural gas-fueled peaking facility being constructed near Antioch, California. Immediately prior to the initial public offering, NRG transferred ownership of Marsh Landing to NRG Yield LLC. Power generated from Marsh Landing is sold to Pacific Gas & Electric, or PG&E, under a 10 year PPA. In connection with the acquisition, the Company assumed obligations under a credit agreement for up to $650 million in construction and permanent financing for the Marsh Landing generating facility. The Marsh Landing generating facility reached commercial operations on May 1, 2013.

The fair value of the net assets acquired was $138 million. The accounting for the acquisition was completed on December 13, 2013. The Company recorded a measurement period adjustment increasing the provisional fair value of the acquired property, plant and equipment by $73 million, from $537 million to $610 million. The primary driver for the revised fair value was the refinement of the methodology used to value the assets.

2015 Acquisition of EME-NYLD-Eligible Assets from NRG

On January 2, 2015, NRG Yield Operating LLC acquired the following projects from NRG: (i) Laredo Ridge, a 80 MW wind facility located in Petersburg, Nebraska, (ii) the Tapestry projects, which include Buffalo Bear, a 19 MW wind facility in Buffalo, Oklahoma, Taloga, a 130 MW wind facility in Putnum, 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 plus assumed project level debt of $737 million, including $9 million for working capital. The Company funded the acquisition with cash on hand and drawings under the Company's revolving credit facility. The assets and liabilities transferred to the Company relate to interests under common control by NRG and accordingly, were recorded at historical cost in accordance with ASC 805-50, Business Combinations - Related Issues. The difference between the cash paid and historical value of the entities' equity of $84 million was recorded as a distribution to NRG and reduced the balance of its noncontrolling interest. Since the transaction constituted a transfer of net assets under common control, the guidance requires retrospective combination of the entities for all periods presented as if the combination has been in effect since the inception of common control. The Company funded the acquisition with cash on hand and borrowings under the Company's revolving credit facility.

The following is a summary of assets and liabilities transferred in connection with the acquisition on January 2, 2015:

	Walnut Creek		Tapestry		Laredo Ridge
	(In millions)
Current assets	$	46	$	14	$	7
Property, plant and equipment	575		286		118
Non-current assets	57		61		49
Total assets	678		361		174
Debt	437		192		108
Other current and non-current liabilities	62		5		4
Total liabilities	499		197		112
Net assets acquired	$	179	$	164	$	62

EME was acquired by NRG on April 1, 2014. The initial accounting for the business combination is not complete because the evaluation necessary to assess the fair values of certain net assets acquired is still in process. The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.

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Supplemental Pro Forma Information

The following unaudited supplemental pro forma information represents the results of operations as if the Company had acquired the EME-NYLD-Eligible Assets on January 1, 2013:

	For the year ended December 31,
(In millions, except per share amounts)	2014		2013
Operating Revenues	$	715	$	513
Net Income	97		145
Net Income Attributable to NRG Yield, Inc.	21		16
Earnings per Weighted Average Class A Common Share - Basic and Diluted	$	0.76	$	0.69

Note 4 — Property, Plant and Equipment

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

	December 31, 2014			December 31, 2013			Depreciable Lives
	(In millions)
Facilities and equipment	$	3,701		$	2,373		2 - 33 Years
Land and improvements	87			86
Construction in progress	7			6
Total property, plant and equipment	3,795			2,465
Accumulated depreciation	(308		)	(174		)
Net property, plant and equipment	$	3,487		$	2,291

Renewable Energy Grants

The Borrego solar project achieved commercial operations on February 12, 2013 and transferred the construction in progress to property, plant and equipment. On May 16, 2013, the Borrego solar project, as a qualified renewable energy project, applied for a cash grant in lieu of investment tax credit from the U.S. Treasury Department in the amount of $39 million. A receivable for the cash grant was recorded when the application was filed, which resulted in a reduction to the book basis of the property, plant and equipment. In addition, the receivable was reduced to $36 million as a result of the federal government’s sequestration, which was put into effect on March 1, 2013. The related deferred tax asset of $10 million was recorded with a corresponding reduction of the book value of Borrego’s property, plant and equipment. In March 2014, the Company received payment of $30 million for the cash grant related to Borrego. The Company recorded a reserve for the shortage pending further discussions with the US treasury Department.

The TA High Desert solar project achieved commercial operations on March 25, 2013 and transferred the construction in progress to property, plant and equipment. On May 22, 2013, the TA High Desert solar project, as a qualified renewable energy project, applied for a cash grant in lieu of investment tax credit from the U.S. Treasury Department in the amount of $25 million. A receivable for the cash grant was recorded when the application was filed, which resulted in a reduction to the book basis of the property, plant and equipment. In addition, the receivable was reduced to $20 million as a result of the federal government’s sequestration, which was put into effect on March 1, 2013. The related deferred tax asset of $6 million was recorded with a corresponding reduction of the book value of TA High Desert's property, plant and equipment. In April 2014, TA High Desert received a payment of $20 million for the cash grant and reduced the book value of its property, plant and equipment by the amount by which the grant was reduced.

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The RE Kansas South solar project achieved commercial operations on June 7, 2013, and transferred the construction in progress to property, plant and equipment. On June 27, 2013, the RE Kansas South solar project, as a qualified renewable energy project, applied for a cash grant in lieu of investment tax credit from the U.S. Treasury Department in the amount of $23 million. A receivable for the cash grant was recorded when the application was filed, which resulted in a reduction to the book basis of the property, plant and equipment. In addition, the receivable was reduced to $21 million as a result of the federal government’s sequestration, which was put into effect on March 1, 2013. The related deferred tax asset of $6 million was recorded with a corresponding reduction of the book value of RE Kansas South's property, plant and equipment. In April 2014, RE Kansas South received a payment of $21 million for the cash grant.

Note 5 — Investments Accounted for by the Equity Method and Variable Interest Entities

Equity Method Investments

Avenal—The Company owns a 49.95% equity interest in Avenal, which consists of three solar PV projects in Kings County, California, approximately 45 MWs, all of which became commercially operational during the third quarter of 2011. NRG retained a 0.05% interest and Eurus Energy owns the remaining 50% of Avenal. Power generated by the projects is sold under a 20-year PPA. On September 22, 2010, Avenal entered into a $35 million promissory note facility with the Company. Amounts drawn under the promissory note facility accrue interest at 4.5% per annum. As of December 31, 2013, the amount outstanding under the facility was $2 million. The facility was repaid in January 2014. Also, on September 22, 2010, Avenal entered into a $209 million financing arrangement with a syndicate of banks, or the Avenal Facility. As of December 31, 2014, and 2013, Avenal had outstanding $107 million and $112 million, respectively, under the Avenal Facility. As of December 31, 2014, the Company had an $11 million equity investment in Avenal.

CVSR—The Company owns 48.95% of CVSR, located in San Luis Obispo, California, totaling 250 MW, while NRG continues to own the remaining 51.05% of CVSR. Power generated by the project is sold under a 25-year PPA. As of December 31, 2014, the Company had a $102 million equity investment in CVSR.

In 2011, High Plains Ranch II, LLC, the direct owner of CVSR, entered into the CVSR Financing Agreement with the FFB to borrow up to $1.2 billion to fund the costs of constructing the solar facility. The CVSR Financing Agreement matures in 2037 and the loans provided by the FFB are guaranteed by the U.S. DOE. Amounts borrowed under the CVSR Financing Agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of 0.375% and are secured by the assets of CVSR. As of December 31, 2014, and 2013, $815 million and $1,104 million, respectively, were outstanding under the loan. In 2012 and 2013, CVSR submitted applications to the U.S. Treasury Department for cash grants as each phase of the project began commercial operations. In January 2014, the U.S. Treasury Department awarded cash grants on the CVSR project of $307 million ($285 million net of sequestration), which is approximately 75% of the cash grant amount for which the Company had applied. The cash grant proceeds were used to pay the outstanding balance of the bridge loan due in February 2014 and the remaining amount was used to pay a portion of the outstanding balance on the bridge loan due in August 2014. The remaining balance of the bridge loan due in August 2014 was paid by SunPower. CVSR is evaluating the basis for the U.S. Treasury Department’s award and all of its options for recovering the amount by which the U.S. Treasury Department reduced the CVSR cash grant award.

The following table presents summarized financial information for CVSR:

	Year Ended December 31,
	2014		2013		2012
Income Statement Data:	(In millions)
Operating revenues	$	82	$	47	$	2
Operating income	40		22		1
Net income	17		4		1
			As of December 31,
			2014		2013
			(In millions)
Balance Sheet Data:
Current assets			$	173	$	455
Non-current assets			868		932
Current liabilities			33		412
Non-current liabilities			799		769

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Variable Interest Entities, or VIEs

GenConn Energy LLC — The Company has a 49.95% interest in GCE Holding LLC, the owner of GenConn Energy LLC, or GenConn, which owns and operates two190 MW peaking generation facilities in Connecticut at the Devon and Middletown sites. Each of these facilities was constructed pursuant to a 30-year cost of service type contract with the Connecticut Light & Power Company. All four units at the GenConn Devon facility reached commercial operation in June 2010 and were released to the ISO-NE by July 2010. In June 2011, all four units at the GenConn Middletown facility reached commercial operation and were released to the ISO-NE. GenConn is considered a VIE under ASC 810, however the Company is not the primary beneficiary, and accounts for its investment under the equity method.

The project was funded through equity contributions from the owners and non-recourse, project level debt. As of December 31, 2014, the Company's investment in GenConn was $114 million and its maximum exposure to loss is limited to its equity investment. On September 17, 2013, GenConn refinanced its existing project financing facility. The refinanced facility is comprised of a $237 million note with an interest rate of 4.73% and a maturity date of July 2041 and a 5-year, $35 million working capital facility that matures in 2018 which can be used to issue letters of credit at an interest rate of 1.875% per annum. As of December 31, 2014 $228 million was outstanding under the note and nothing was drawn on the working capital facility. The refinancing is secured by all of the GenConn assets.

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

	Year ended December 31,
	2014		2013		2012
Income Statement Data:	(In millions)
Operating revenues	$	82	$	80	$	78
Operating income	40		44		45
Net income	28		31		29

	December 31, 2014		December 31, 2013
Balance Sheet Data:	(In millions)
Current assets	$	33	$	32
Non-current assets	438		454
Current liabilities	20		18
Non-current liabilities	223		232

The following table presents undistributed equity earnings for the Company's three equity method investments:

	As of December 31,
	2014		2013
	(In millions)
Undistributed earnings from equity investments	$	22	$	19

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Note 6 — Fair Value of Financial Instruments

For cash and cash equivalents, restricted cash, accounts receivable, accounts payable, intercompany accounts payable and receivable, accrued expenses and other liabilities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.

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

	As of December 31, 2014				As of December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable, including current portion — affiliate	$	—	$	—	$	2	$	2
Notes receivable, including current portion	21		21		27		27
Liabilities:
Long-term debt, including current portion	4,050		4,136		1,783		1,785

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.

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.

Recurring Fair Value Measurements

The Company records its derivative assets and liabilities at fair market value on its consolidated balance sheet. The following table presents assets and liabilities measured and recorded at fair value on the Company's consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:

	As of December 31, 2014
	Fair Value (a)
(In millions)	Level 2
Derivative assets:
Commodity contracts	$	—
Interest rate contracts	1
Total assets	$	1
Derivative liabilities:
Commodity contracts	$	3
Interest rate contracts	74
Total liabilities	$	77

(a) There were no assets or liabilities classified as Level 1 or Level 3 as of December 31, 2014.

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	As of December 31, 2013
	Fair Value (a)
(In millions)	Level 2		Level 3		Total
Derivative assets:
Commodity contracts	$	1	$	—	$	1
Interest rate contracts	20		—		20
Total assets	21		—		21
Derivative liabilities:
Commodity contracts	1		1		2
Interest rate contracts	45		—		45
Total liabilities	$	46	$	1	$	47

(a) There were no assets or liabilities classified as Level 1 as of December 31, 2013.

There were no transfers during the years ended December 31, 2014 and 2013, between Levels 1 and 2. The following table reconciles, for the year ended December 31, 2014, the beginning and ending balances for derivative instruments that are recognized at fair value in the consolidated financial statements, at least annually, using significant unobservable inputs:

	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
(In millions)	Year ended December 31, 2014
	Derivatives
Beginning balance	$	(1	)
Total gains and losses (realized/unrealized) included in earnings	1
Ending balance as of December 31, 2014	$	—

There have been no transfers in and/or out of Level 3 during the year ended December 31, 2014.

Derivative Fair Value Measurements

A majority of 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 remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available. These contracts are valued using various valuation techniques including but not limited to internal models that apply fundamental analysis of the market and corroboration with similar markets. As of December 31, 2014, there were no contracts valued with prices provided by models and other valuation techniques.

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 calculated based on credit default swaps. To the extent that the net exposure is an asset, the Company uses the counterparty’s default swap rate. If the exposure is a liability, the Company uses its default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume the liabilities or that a market participant would be willing to pay for the assets. As of December 31, 2014, the credit reserve resulted in a $1 million increase in fair value which is a gain in OCI. It is possible that future market prices could vary from those used in recording assets and liabilities and such variations could be material.

Concentration of Credit Risk

In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, the following item is a discussion of the concentration of credit risk for the Company's financial instruments. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties.

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Counterparty credit exposure includes credit risk exposure under certain long-term agreements, including solar and other PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company estimates the exposure related to these contracts based on various techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of December 31, 2014, credit risk exposure to these counterparties attributable to the Company's ownership interests was approximately $1.7 billion for the next five years. The majority of these power contracts are with utilities with strong credit quality and public utility commission or other regulatory support, as further described in Note 12, Segment Reporting. However, such regulated utility counterparties can be impacted by changes in government regulations, which the Company is unable to predict.

Note 7 — Accounting for Derivative Instruments and Hedging Activities

ASC 815 requires the Company to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a NPNS exception. The Company may elect to designate certain derivatives as cash flow hedges, if certain conditions are met, and defer the effective portion of the change in fair value of the derivatives to accumulated OCI, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings. For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 applies to the Company's energy related commodity contracts and interest rate swaps.

Energy-Related Commodities

To manage the commodity price risk associated with its competitive supply activities and the price risk associated with wholesale power sales, the Company may enter into derivative hedging instruments, namely, forward contracts that commit the Company to sell energy commodities or purchase fuels in the future. The objectives for entering into derivatives contracts designated as hedges include fixing the price for a portion of anticipated future electricity sales and fixing the price of a portion of anticipated fuel purchases for the operation of its subsidiaries. At December 31, 2014, the Company had forward and financial contracts for the purchase/sale of electricity and related products economically hedging the Company's district energy centers' forecasted output or load obligations through 2015. The Company also had forward contracts for the purchase of fuel commodities relating to the forecasted usage of the district energy centers through 2017. At December 31, 2014, these contracts were not designated as cash flow or fair value hedges.

Also, as of December 31, 2014, the Company had other energy-related contracts that did not meet the definition of a derivative instrument or qualified for the NPNS exception and were therefore exempt from fair value accounting treatment as follows:

• Power tolling contracts through 2038, and

• Natural gas transportation contracts through 2028.

Interest Rate Swaps

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

As of December 31, 2014, the Company had interest rate derivative instruments on non-recourse debt extending through 2031, some of which are designated as cash flow hedges.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of the Company's open derivative transactions broken out by commodity as of December 31, 2014, and 2013.

		Total Volume
		December 31, 2014		December 31, 2013
Commodity	Units	(In millions)
Natural Gas	MMBtu	2		2
Interest	Dollars	$	2,107	$	1,234

The increase in the interest rate position was primarily the result of the interest rate swaps acquired with the Alta Wind Portfolio.

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Fair Value of Derivative Instruments

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

	Fair Value
	Derivative Assets				Derivative Liabilities
	December 31, 2014		December 31, 2013		December 31, 2014		December 31, 2013
	(In millions)
Derivatives Designated as Cash Flow Hedges:
Interest rate contracts current	$	—	$	—	$	23	$	26
Interest rate contracts long-term	1		14		27		16
Total Derivatives Designated as Cash Flow Hedges	1		14		50		42
Derivatives Not Designated as Cash Flow Hedges:
Interest rate contracts current	—		—		5		3
Interest rate contracts long-term	—		6		19		—
Commodity contracts current	—		1		3		2
Total Derivatives Not Designated as Cash Flow Hedges	—		7		27		5
Total Derivatives	$	1	$	21	$	77	$	47

The Company has elected to present derivative assets and liabilities on the balance sheet on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. As of December 31, 2014, there was no outstanding collateral paid or received. The following table summarizes the offsetting of derivatives by counterparty master agreement level:

	Gross Amounts Not Offset in the Statement of Financial Position
As of December 31, 2014	Gross Amounts of Recognized Assets/Liabilities			Derivative Instruments			Net Amount
Commodity contracts:	(In millions)
Derivative assets	$	—		$	—		$	—
Derivative liabilities	(3		)	—			(3		)
Total commodity contracts	(3		)	—			(3		)
Interest rate contracts:
Derivative assets	1			(1		)	—
Derivative liabilities	(74		)	1			(73		)
Total interest rate contracts	(73		)	—			(73		)
Total derivative instruments	$	(76	)	$	—		$	(76	)

	Gross Amounts Not Offset in the Statement of Financial Position
As of December 31, 2013	Gross Amounts of Recognized Assets/Liabilities			Derivative Instruments			Net Amount
Commodity contracts:	(In millions)
Derivative assets	$	1		$	—		$	1
Derivative liabilities	(2		)	—			(2		)
Total commodity contracts	(1		)	—			(1		)
Interest rate contracts:
Derivative assets	20			(12		)	8
Derivative liabilities	(45		)	12			(33		)
Total interest rate contracts	(25		)	—			(25		)
Total derivative instruments	$	(26	)	$	—		$	(26	)

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Accumulated Other Comprehensive Loss

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

	Year ended December 31,
	2014			2013			2012
	(In millions)
Accumulated OCL beginning balance	$	—		$	(48	)	$	(28	)
Reclassified from accumulated OCL to income due to realization of previously deferred amounts	11			13			5
Mark-to-market of cash flow hedge accounting contracts	(40		)	35			(25		)
Accumulated OCL ending balance, net of income tax benefit of $6, $1 and $17, respectively	$	(29	)	$	—		$	(48	)
Accumulated OCL attributable to NRG	(20		)	—
Accumulated OCL attributable to NRG Yield, Inc.	$	(9	)	$	—
Losses expected to be realized from OCL during the next 12 months, net of income tax of $2	$	(11	)

Impact of Derivative Instruments on the Statements of Operations

The Company has interest rate derivative instruments that are not designated as cash flow hedges as well as ineffectiveness on cash flow hedge derivatives. The effect of interest rate hedges is recorded to interest expense. For the years ended December 31, 2014 and 2013, the impact to the consolidated statements of operations was a loss of $22 million and a gain of $13 million, respectively.

The Company’s derivative commodity contracts relate 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 statement of operations for these contracts.

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

Note 8 — Intangible Assets

Intangible Assets — The Company's intangible assets as of December 31, 2014, and 2013 primarily reflect intangible assets established from its business acquisitions and are comprised of the following:

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

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

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

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

• PPAs — Established predominantly with the Alta Wind acquisition, these represent the fair value of PPAs acquired. These will be amortized, generally on a straight-line basis, over the term of the PPA.

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

• Other — Consists of the acquisition date fair value of the contractual rights to a ground lease for South Trent and to utilize certain interconnection facilities for Blythe.

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

Year ended December 31, 2014	Emission Allowances		Development Rights			Customer Contracts			Customer Relationships			PPAs			Leasehold Rights			Other		Total
			(In millions)
January 1, 2014	$	8	$	4		$	15		$	66		$	14		$	—		$	3	$	110
Acquisition of Alta Wind Portfolio	—		—			—			—			1,091			86			—		1,177
Other	1		—			—			—			4			—			—		5
December 31, 2014	9		4			15			66			1,109			86			3		1,292
Less accumulated amortization	—		(1		)	(5		)	(2		)	(16		)	(2		)	—		(26		)
Net carrying amount	$	9	$	3		$	10		$	64		$	1,093		$	84		$	3	$	1,266

Year ended December 31, 2013	Emission Allowances		Development Rights			Customer Contracts			Customer Relationships			PPAs			Leasehold Rights		Other		Total
	(In millions)
January 1, 2013	$	8	$	4		$	15		$	7		$	4		$	—	$	3	$	41
Business acquisition/transfer	—		—			—			59			10			—		—		69
December 31, 2013	8		4			15			66			14			—		3		110
Less accumulated amortization	—		(1		)	(4		)	(1		)	(1		)	—		—		(7		)
Net carrying amount	$	8	$	3		$	11		$	65		$	13		$	—	$	3	$	103

The Company recorded amortization of $19 million, $4 million and $1 million during the years ended December 31, 2014, 2013 and 2012. Of these amounts, $15 million for the year ended December 31, 2014 was recorded as contra-revenue reflecting the amortization of the fair value of the power purchase agreements acquired with Alta Wind Portfolio. The following table presents estimated amortization of the Company's intangible assets for each of the next five years:

Year Ended December 31,	Total
	(In millions)
2015	$	45
2016	58
2017	58
2018	58
2019	59

The weighted average amortization period related to the intangibles acquired in the year ended December 31, 2014 was 22 years for power purchase agreements and 21 years for leasehold rights.

Out-of-market contracts — The out-of-market contract liability represents the out-of-market value of the PPA for the Blythe solar project and the out-of-market value of the land lease for Alta Wind XI Holding Company, LLC, as of their respective acquisition dates. The Blythe solar project's liability of $5 million is recorded to other non-current liabilities and is amortized to revenue on a units-of-production basis over the twenty-year term of the agreement. The Alta Wind XI Holding Company, LLC's liability of $5 million is recorded to other non-current liabilities and is amortized to cost of operations on a straight-line basis over the term of the land lease. At December 31, 2014, accumulated amortization of out-of-market contracts was $2 million and amortization expense was less than $1 million for the year ended December 31, 2014.

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Note 9 — Long-term Debt

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

	December 31, 2014		December 31, 2013		Interest rate % (a)
	(In millions, except rates)
Convertible Notes, due 2019 (b)	$	326	—		3.500
Senior Notes, due 2024	500		—		5.375
Project-level debt:
Alta Wind I, lease financing arrangement, due 2034	261		—		7.015
Alta Wind II, lease financing arrangement, due 2034	205		—		5.696
Alta Wind III, lease financing arrangement, due 2034	212		—		6.067
Alta Wind IV, lease financing arrangement, due 2034	138		—		5.938
Alta Wind V, lease financing arrangement, due 2035	220		—		6.071
Alta Wind X, due 2021	300		—		L+2.00
Alta Wind XI, due 2021	191		—		L+2.00
Alta Realty Investments, due 2031	34		—		7.00
Alta Wind Asset Management, due 2031	20		—		L+2.375
NRG West Holdings LLC, due 2023	506		512		L+2.25 - L+2.875; L+2.25 - L+2.75
NRG Marsh Landing LLC, due 2017 and 2023	464		473		L+ 1.75 - L+1.875; L+2.75 - L+3.00
NRG Solar Alpine LLC, due 2014 and 2022	163		221		L+1.75 - L+2.50; L+2.25 - L+2.50
NRG Energy Center Minneapolis LLC, due 2017 and 2025	121		127		5.95 -7.31
NRG Solar Borrego LLC, due 2024 and 2038	75		78		L+ 2.50/5.65
South Trent Wind LLC, due 2020	65		69		L+2.75;L+2.625
NRG Solar Avra Valley LLC, due 2031	63		63		L+1.75; L+2.25
TA High Desert LLC, due 2023 and 2033	55		80		L+2.50/5.15
NRG Roadrunner LLC, due 2031	42		44		L+2.01
NRG Solar Kansas South LLC, due 2031	35		58		L+2.00;L+2.625
NRG Solar Blythe LLC, due 2028	22		24		L+2.75
PFMG and related subsidiaries financing agreement, due 2030	31		32		6.00
NRG Energy Center Princeton LLC, due 2017	1		2		5.95
Subtotal project-level debt:	3,224		1,783
Total debt	4,050		1,783
Less current maturities	160		214
Total long-term debt	$	3,890	$	1,569

(a) As of December 31, 2014, L+ equals 3 month LIBOR plus x%, except for Kansas South where L+ equals 6 month LIBOR plus x%.

(b) Net of discount of $19 million as of December 31, 2014.

The financing arrangements listed above contain certain covenants, including financial covenants that the Company is required to be in compliance with during the term of the arrangement. As of December 31, 2014, the Company was in compliance with all of the required covenants.

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The discussion below lists changes to or additions of long term debt for the year ended December 31, 2014.

NRG Yield, Inc. Convertible Notes

During the first quarter of 2014, the Company closed on its offering of $345 million of Convertible Notes. The Convertible Notes bear interest of 3.50% and mature in February 2019.  Interest on the Convertible Notes is payable semi-annually in arrears on February 1 and August 1 of each year, commencing on August 1, 2014. The Convertible Notes are convertible, under certain circumstances, into the Company’s Class A common stock, cash or a combination thereof at an initial conversion price of $46.55 per Class A common share, which is equivalent to an initial conversion rate of approximately 21.4822 shares of Class A common stock per $1,000 principal amount of Convertible Notes. The Convertible Notes mature on February 1, 2019, unless earlier repurchased or converted in accordance with their terms. Prior to the close of business on the business day immediately preceding August 1, 2018, the Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the close of business on the second scheduled trading day immediately preceding the maturity date. The Convertible Notes are guaranteed by NRG Yield Operating LLC and NRG Yield LLC.

The Convertible Notes are accounted for in accordance with ASC 470-20, Debt with Conversion and Other Options. Under ASC 470-20, issuers of convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are required to separately account for the liability (debt) and equity (conversion option) components. The application of ACS 470-20 resulted in the recognition of $23 million as the value for the equity component with the offset to debt discount. The debt discount is amortized to interest expense using the effective interest method through February 2019.

As of December 31, 2014, the Convertible Notes were trading at approximately 114% of their face value, resulting in a total market value of $395 million compared to a carrying value of $326 million. The actual conversion value of the Convertible Notes is based on the product of the conversion rate and the market price of the Company's common stock, as defined in the Convertible Debt indenture. As of December 31, 2014, the Company's common stock closed at $47.14 per share, resulting in a pro forma conversion value for the Convertible Notes of approximately $349 million.

During the years ended December 31, 2014, the Company recorded the following expense in relation to the Convertible Notes at the effective rate of 5.00%:

(In millions)
Interest expense at 3.5% coupon rate	11
Debt discount amortization	4
Debt issuance costs amortization	1
	$	16

NRG Yield Operating LLC Senior Notes

On August 5, 2014, NRG Yield Operating LLC issued $500 million of senior unsecured notes, or the Senior Notes. The Senior Notes bear interest at 5.375% and mature in August 2024. Interest on the notes is payable semi-annually on February 15 and August 15 of each year, and commenced on February 15, 2015. The Senior Notes are senior unsecured obligations of NRG Yield Operating LLC and are guaranteed by NRG Yield LLC, and by certain of NRG Yield Operating LLC’s wholly owned current and future subsidiaries.

NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility

In connection with the Company's initial public offering of Class A common stock in July 2013, as further described in Note 1, Nature of Business, NRG Yield LLC and NRG Yield Operating LLC entered into a senior secured revolving credit facility, or the Yield Credit Facility, which provided a revolving line of credit of $60 million. On April 25, 2014, NRG Yield LLC and NRG Yield Operating LLC amended the revolving credit facility to increase the available line of credit to $450 million and extend its maturity to April 2019. The Company's revolving credit facility can be used for cash or for the issuance of letters of credit. There was no cash drawn and $38 million of letters of credit issued in support of the obligations of the Alta Wind Portfolio under the revolving credit facility as of December 31, 2014.

On January 2, 2015, the Company borrowed $210 million under the Yield Credit Facility to fund the acquisition of Walnut Creek, Laredo Ridge and the Tapestry projects. On February 2, 2015 the Company made an optional repayment of $15 million of principal and interest.

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Project - level Debt

NRG West Holdings Credit Agreement

On August 23, 2011, NRG West Holdings LLC, or West Holdings, entered into a credit agreement with a group of lenders in respect to the El Segundo project, or the West Holdings Credit Agreement. The West Holdings Credit Agreement is comprised of a $540 million two tranche construction loan facility with additional facilities for the issuance of letters of credit or working capital loans and is secured by the assets of West Holdings.

The two tranche construction loan facility consists of the $480 million Tranche A Construction Facility, or the Tranche A Facility, and the $60 million Tranche B Construction Facility, or the Tranche B Facility. The Tranche A and Tranche B Facilities, which mature in August 2023, convert to a term loan and have an interest rate of 3-month LIBOR, plus an applicable margin which (i) increases by 0.125% periodically from conversion through year eight for the Tranche A Facility, and (ii) increases by (a) 0.125% upon term conversion and on the third and sixth anniversary of the term conversion and (b) by 0.250% on the eighth anniversary of the term conversion for the Tranche B Facility. The Tranche A and Tranche B Facilities amortize based upon a predetermined schedule over the term of the loan with the balance payable at maturity. The construction loan converted to a term loan on January 28, 2014.

The West Holdings Credit Agreement also provides for the issuance of letters of credit and working capital loans to support the El Segundo project's collateral needs. This includes letter of credit facilities on behalf of West Holdings of up to $90 million in support of the PPA, up to $48 million in support of the collateral agent, and a working capital facility which permits loans or the issuance of letters of credit of up to $10 million.

As of December 31, 2014, under the West Holdings Credit Agreement, West Holdings had $447 million outstanding under the Tranche A Facility, $59 million under the Tranche B Facility, issued a $33 million letter of credit in support of the PPA, a $48 million letter in support of debt service and a $1 million letter of credit under the working capital facility.

Alpine Financing

On March 16, 2012, NRG Solar Alpine LLC, or Alpine, entered into a credit agreement with a group of lenders for a $166 million construction loan that was convertible to a term loan upon completion of the project and a $68 million cash grant loan. On January 15, 2013, the credit agreement was amended reducing the cash grant loan to $63 million. On March 26, 2013, Alpine met the conditions under the credit agreement to convert the construction loan to a term loan. Immediately prior to the conversion, the Company drew an additional $164 million under the construction loan and $62 million under the cash grant loan. The term loan amortizes on a predetermined schedule with final maturity in November 2022.

In January 2014, Alpine repaid the $62 million of outstanding cash grant loan, including accrued interest and breakage fees, with the proceeds that it had received from the U.S. Treasury Department.On June 24, 2014, Alpine amended the credit agreement to increase its term loan borrowings by an additional $13 million and to reduce the related interest rate to 3 month LIBOR plus 1.75% through June 30, 2019 and 3 month LIBOR plus 2.00% through November 2022. The proceeds were utilized to make a distribution of $11 million to NRG Yield Operating LLC with the remaining $2 million utilized to fund the costs of the amendment.

Borrego Financing

On March 28, 2013, NRG Solar Borrego I LLC, or Borrego, entered into a credit agreement with a group of lenders, or the Borrego Financing Agreement, for $45 million of 5.65% fixed rate notes and a $36 million term loan. The term loan has an interest rate of 3 month LIBOR plus an applicable margin of 2.50%, which escalates 0.25% on the fourth and eighth anniversary of the closing date. The fixed rate notes mature in February 2038 and the term loan matures in December 2024. Both amortize based upon predetermined schedules. The Borrego Financing Agreement also includes a letter of credit facility on behalf of Borrego of up to $5 million. Borrego pays an availability fee of 100% of the applicable margin on issued letters of credit. As of December 31, 2014, $45 million was outstanding under the fixed rate notes, $30 million was outstanding under the term loans, and $5 million of letters of credit in support of the project were issued.

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Under the terms of the Borrego Financing Agreement on March 28, 2013, Borrego was required to enter into two fixed for floating interest rate swaps that would fix the interest rate for a minimum of 75% of the outstanding notional amount. Borrego will pay its counterparty the equivalent of a 1.125% fixed interest payment on a predetermined notional value, and quarterly, Borrego will receive the equivalent of a floating interest payment based on a 3 month LIBOR calculated on the same notional value through June 30, 2020. All interest rate swap payments by Borrego and its counterparties are made quarterly and the LIBOR rate is determined in advance of each interest period. The original notional amount of the swaps, which became effective April 3, 2013, was $15 million and will amortize in proportion to the term loan.

Marsh Landing Credit Agreement Term Conversion

In May 2013, Marsh Landing met the conditions under the credit agreement to convert the construction loan for the facility to a term loan which will amortize on a predetermined basis. Prior to term conversion, Marsh Landing drew the remaining funds available under the facility in order to pay costs due for construction. Marsh Landing issued a $24 million letter of credit under the facility in support of its debt service requirements. As of December 31, 2014, $108 million was outstanding under the Tranche A loan, $356 million was outstanding under the Tranche B loans, and $22 million of letters of credit in support of the project were issued.

On July 17, 2014, Marsh Landing amended its credit agreement to increase its borrowings by $34 million and to reduce the related interest rate for the Tranche A borrowings from 3 month LIBOR plus an applicable margin of 2.75% to 3 month LIBOR plus 1.75% through December 2017; and for the Tranche B to reduce the related interest rate from 3 month LIBOR plus 3.00% to 3 month LIBOR plus 1.875% through December 2017 and to 3 month LIBOR plus 2.125% through December 2020 and to 3 month LIBOR plus 2.375% thereafter. The proceeds from the borrowings were utilized to make a distribution of $29 million to NRG Yield Operating LLC and to fund the costs of the amendment.

TA High Desert Facility

The TA High Desert Facility is comprised of $53 million of fixed rate notes due 2033 at an interest rate of 5.15%, $7 million of floating rate notes due 2023, $22 million of bridge notes due the earlier of ten days after receipt of the cash grant or May 2014, and a revolving facility of $12 million. The floating rate notes have an interest rate of 3 month LIBOR plus 2.5% with LIBOR floor of 1.5%, while the bridge notes have an interest rate of 1 month LIBOR plus 2.50%. As described in Note 4, Property, Plant and Equipment, in April 2014, TA High Desert received payment of $20 million for its cash grant and utilized the proceeds, along with an additional $2 million of cash contributed by NRG to repay the cash grant bridge loan. The revolving facility can be used for cash or for the issuance of up to $9 million in letters of credit. As of December 31, 2014, $55 million of notes were outstanding and $8 million of letters of credit were outstanding under the revolving facility.  The notes amortize on predetermined schedules and are secured by all of the assets of TA High Desert.

RE Kansas South Facility

The RE Kansas South Facility includes a $38 million term loan due 2031 and a $21 million cash grant bridge loan due ten days after receipt of the cash grant. The term loan has an interest rate of 6 month LIBOR plus an applicable margin of 2.625% and increases by 0.25% every 4 years. The cash grant bridge loan had an interest rate of 1 month LIBOR plus an applicable margin of 2.00%. The term loan amortizes on a predetermined schedule and is secured by all of the assets of RE Kansas South. As described in Note 4, Property, Plant and Equipment, in April 2014, the Company received payment of $21 million for the cash grant related to RE Kansas South and utilized the proceeds to repay the cash grant bridge loan. On September 26, 2014, RE Kansas South amended its credit agreement to change the interest rate to 6 month LIBOR plus 2.00% through September 30, 2019 and to 6 month LIBOR plus 2.250% thereafter. As of December 31, 2014, $35 million was outstanding under the term loan and $4 million of letters of credit were issued under the RE Kansas South Facility.

Avra Valley Credit Agreement

On July 9, 2014, Avra Valley amended its credit agreement to increase its borrowings by $3 million and to reduce the related interest rate from 3 month LIBOR plus an applicable margin of 2.25% to 3 month LIBOR plus 1.75%. The proceeds were primarily utilized to make a distribution to NRG Yield Operating LLC.

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Alta Wind Financing Arrangements

As described in Note 3, Business Acquisitions, the Company acquired the Alta Wind Portfolio on August 12, 2014. In connection with the acquisition, the Company assumed the following debt arrangements:

Term Loan and Note Facilities

In June 2013, Alta Wind X entered into a credit agreement with several lenders for $337 million, which provided loans for the construction of the plant, letters of credit commitments to support certain obligations and a debt reserve loan commitment. The agreement contains a $300 million construction loan which converted to a term loan on March 31, 2014 and matures in March 2021. The term loan has an interest rate of 3 month LIBOR plus an applicable margin. The applicable margin was initially set at 2.00% for LIBOR-based loan increasing to 2.25% on the fourth anniversary of term loan conversion. The Company pays a commitment fee on the unused portion of all instruments of 0.75% quarterly in arrears on the last business day of March, June, September and December. The credit agreement also provides for a $20 million letter of credit facility to support obligations of the project, which expires on the term loan maturity date and a $17 million debt service loan commitments in the event the project is unable to meet its debt service obligations. As of December 31, 2014, $5 million of letters of credit were issued and no borrowings were made under the debt service loan commitments. In addition, a $3 million letter of credit to support a liquidity reserve requirement was issued under the Yield Credit Facility.

In June 2013, Alta Wind XI entered into a credit agreement with several lenders for $212 million, which provided loans for the construction of the plant, letters of credit commitments to support certain obligations and a debt reserve loan commitment. The agreement contains a $191 million construction loan which converted to a term loan on March 31, 2014 and matures in March 2021. The term loan has an interest rate of 3 month LIBOR plus an applicable margin. The applicable margin was initially set at 2.00% for LIBOR-based loan increasing to 2.25% on the fourth anniversary of term loan conversion. The Company pays a commitment fee on the unused portion of all instruments of 0.75% quarterly in arrears on the last business day of March, June, September and December. The credit agreement also provides for a $10 million letter of credit facility to support obligations under the PPA, which expires on the term loan maturity date and an $11 million in debt service loan commitments in the event the project is unable to meet its debt service obligations. As of December 31, 2014, no letters of credit were issued and no borrowings were made under the debt service loan commitments. In addition, a $3 million letter of credit to support a liquidity reserve requirement was issued under the Yield Credit Facility.

On May 22, 2013, AWAM entered into a credit agreement with a lender and borrowed a $20 million term loan. The proceeds from the issuance of the term loan were utilized to pay transactions costs and fund certain restricted cash accounts. AWAM has a $20 million term loan as of December 31, 2014, which has an interest rate of 3 month LIBOR plus an applicable margin of 2.375% and increases every four years to a maximum applicable margin of 2.88%. Principal and interest are payable quarterly on February 15, May 15, August 15 with a final maturity on May 15, 2031. The loan is secured by substantially all of the assets of AWAM. The term loan also has a debt service requirement, which is satisfied with a $1 million letter of credit issued under the Yield Credit Facility.

On January 31, 2011, Alta Realty entered into a $30 million note purchase agreement with a group of institutional investors with interest and principal payable quarterly on January 31, April 30, July 31, and October 31. The note has an interest rate of 7% and matures on January 31, 2031. The note purchase agreement also has a debt service requirement, which is satisfied with a $2 million letter of credit issued under the Yield Credit Facility. As of December 31, 2014, $34 million was outstanding under the note purchase agreement.

Lease financing arrangements

Alta Wind Holdings (Alta Wind II - V) and Alta I (operating entities) have finance lease obligations issued under lease transactions whereby the respective operating entities sold and leased back undivided interests in specific assets of the project. The sale and related lease transactions are accounted for as financing arrangements as the operating entities have continued involvement with the property. The terms and conditions of each facility lease are substantially similar. Each operating entity makes rental payments as stipulated in the facility lease agreements on a semiannual basis every June 30 and December 30 through the final maturity dates. In addition, the operating entities have a credit agreement with a group of lenders that provides for the issuance of letters of credit to support certain operating and debt service obligations. Certain O&M and rent reserve requirements are satisfied by letters of credit issued under the NRG Yield Operating agreement. As of December 31, 2014, $1,036 million was outstanding under the finance lease obligations, and $114 million of letters of credit issued under the credit agreement and $29 million issued under the Yield Credit Facility.

Interest Rate Swaps — Project Financings

Many of the Company's project subsidiaries entered into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. These swaps amortize in proportion to their respective loans and are floating for fixed

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where the project subsidiary pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value and will receive quarterly the equivalent of a floating interest payment based on the same notional value. All interest rate swap payments by the project subsidiary and its counterparty are made quarterly and the LIBOR is determined in advance of each interest period. In connection with the acquisition of the Alta Wind Portfolio, as described in Note 3, Business Acquisitions, the Company acquired thirty-one additional interest rate swaps.

The following table summarizes the swaps, some of which are forward starting as indicated, related to the Company's project level debt as of December 31, 2014.

	% of Principal	Fixed Interest Rate	Floating Interest Rate	Notional Amount at December 31, 2014 (In millions)	Effective Date	Maturity Date
NRG Marsh Landing LLC	75%	3.244%	3-Month LIBOR	431	June 28, 2013	June 30, 2023
NRG West Holdings LLC	75%	2.417%	3-Month LIBOR	384	November 30, 2011	August 31, 2023
South Trent Wind LLC	75%	3.265%	3-Month LIBOR	48	June 15, 2010	June 14, 2020
South Trent Wind LLC	75%	4.95%	3-Month LIBOR	21	June 30, 2020	June 14, 2028
NRG Solar Roadrunner LLC	75%	4.313%	3-Month LIBOR	31	September 30, 2011	December 31, 2029
NRG Solar Blythe LLC	75%	3.563%	3-Month LIBOR	17	June 25, 2010	June 25, 2028
NRG Solar Avra Valley LLC	85%	2.333%	3-Month LIBOR	54	November 30, 2012	November 30, 2030
NRG Solar Alpine LLC	85%	2.744%	3-Month LIBOR	129	various	December 31, 2029
NRG Solar Alpine LLC	85%	2.421%	3-Month LIBOR	10	June 24, 2014	June 30, 2025
RE Kansas South LLC	75%	2.368%	3-Month LIBOR	26	June 28, 2013	December 31, 2030
NRG Solar Borrego LLC	75%	1.125%	3-Month LIBOR	11	April 3, 2013	June 30, 2020
Alta X	100%	various	3-Month LIBOR	174	December 31, 2013	December 31, 2015
Alta X	100%	various	3-Month LIBOR	126	December 31, 2013	December 31, 2025
Alta X	100%	various	3-Month LIBOR	162	December 31, 2015	December 31, 2020
Alta X	100%	various	3-Month LIBOR	103	December 31, 2020	December 31, 2025
Alta XI	100%	various	3-Month LIBOR	138	December 31, 2013	December 31, 2015
Alta XI	100%	various	3-Month LIBOR	54	December 31, 2013	December 31, 2025
Alta XI	100%	various	3-Month LIBOR	103	December 31, 2015	December 31, 2020
Alta XI	100%	various	3-Month LIBOR	65	December 31, 2020	December 31, 2025
AWAM	100%	2.47%	3-Month LIBOR	20	May 22, 2013	May 15, 2031
Total				$2,107

Annual Maturities

Annual payments based on the maturities of the Company's debt, for the years ending after December 31, 2014, are as follows:

	(In millions)
2015	$	160
2016	190
2017	200
2018	201
2019	558
Thereafter	2,760
Total	$	4,069

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Note 10 — Earnings Per Share

Basic and diluted earnings per common share are computed by dividing net income by the weighted average number of common shares outstanding. Shares issued during the year are weighted for the portion of the year that they were outstanding.

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

	Year ended December 31, 2014		Period from July 23, 2013 to December 31, 2013
(In millions, except per share data)
Basic and diluted earnings per share attributable to NRG Yield, Inc. Class A common stockholders
Net income attributable to NRG Yield, Inc.	$	16	$	13
Weighted average number of Class A common shares outstanding	28		23
Earnings per weighted average Class A common share — basic and diluted	$	0.59	$	0.57

There were a total of six million anti-dilutive outstanding equity instruments related to the Convertible Notes as of December 31, 2014.

Note 11 — Stockholders' Equity

On July 22, 2013, in connection with its initial public offering, the Company authorized 500,000,000 shares of Class A common stock, par value $0.01 per share, of which 22,511,250 were issued to the public in connection with the initial public offering and became outstanding. In return for the issuance of these shares, the Company received $468 million, net of underwriting discounts and commissions of $27 million. In addition, in connection with the initial public offering, the Company authorized 500,000,000 shares of Class B common stock, par value $0.01 per share, of which 42,738,750 were issued to NRG concurrently with the initial public offering and became outstanding. The Company utilized $395 million of the proceeds from the issuance of the Class A common stock to acquire a controlling interest in NRG Yield LLC from NRG. Each share of both of the Class A common stock and Class B common stock entitles the holder to one vote on all matters. Class A common stockholders hold 100% of the economic interest and a 34.5% voting interest in the Company. Class B common stockholders held a 65.5% voting interest in NRG, Yield, Inc. prior to the secondary offering

On July 29, 2014, the Company issued 12,075,000 shares of Class A common stock for net proceeds, after underwriting discount and expenses, of $630 million. The Company utilized the proceeds of the offering to acquire 12,075,000 additional Class A units of NRG Yield LLC and, as a result, as of December 31, 2014, the Company owns 44.7% of NRG Yield LLC, and consolidates the results of NRG Yield LLC through its controlling interest, with NRG's 55.3% interest shown as noncontrolling interest in the financial statements.

Proposed Stock Split in Form of Stock Dividend

On February 24, 2015, the Company’s board of directors approved amendments to the Company's certificate of incorporation that would, among other things, create two new classes of capital stock, Class C common stock and Class D common stock. The amendments will be voted on at the Company’s Annual Meeting of Stockholders to be held on May 5, 2015. If such amendments are approved, the Company intends to request that the board of directors consider a distribution of shares of the Class C common stock as a dividend to the holders of the Class A common stock and a distribution of shares of the Class D common stock as a dividend to NRG, the holder of the Class B common stock. The Class C common stock and Class D common stock will have the same rights and privileges and rank equally, share ratably and be identical in all respects to the shares of Class A common stock and Class B common stock, respectively, as to all matters, except that each share of Class C common stock and Class D common stock will be entitled to 1/100th of a vote on all stockholder matters.

The par value per share of the Company’s Class A common stock and Class B common stock will remain unchanged at $0.01 per share after the effect of the dividend. If the dividend is authorized, on the effective date, the Company would record a transfer between retained earnings and common stock equal to the par value of each share of Class C common stock and Class D common stock that is issued. The Company will also give retroactive effect to prior period share and per share amounts in the consolidated financial statements for the effect of the dividend, such that all periods are comparable.

98

Dividends to Class A common stockholders

The following table lists the dividends paid on the Company's Class A common stock during the year ended December 31, 2014:

	Fourth Quarter 2014		Third Quarter 2014		Second Quarter 2014		First Quarter 2014
Dividends per share	$	0.375	$	0.365	$	0.35	$	0.33

On February 17, 2015, the Company declared a quarterly dividend on its Class A common stock of $0.39 per share payable on March 16, 2015, to stockholders of record as of March 2, 2015.

The common share dividend is subject to available capital, market conditions, and compliance with associated laws and regulations. The Company expects that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.

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

Distributions to NRG

The following table lists the distributions paid to NRG during the year ended December 31, 2014:

	Fourth Quarter 2014		Third Quarter 2014		Second Quarter 2014		First Quarter 2014
Distributions per unit	$	0.375	$	0.365	$	0.35	$	0.33

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

On February 17, 2015, the Company declared a quarterly distribution on its Class B units of $0.39 per unit payable on March 16, 2015.

On June 30, 2014, the Company acquired the TA High Desert, RE Kansas South, and El Segundo projects, as discussed in Note 3, Business Acquisitions. The difference between the cash paid and historical value of the entities' equity of $113 million was recorded as a distribution to NRG and reduced the balance of its noncontrolling interest. In addition, as the TA High Desert, RE Kansas South and El Segundo projects were owned by NRG until June 30, 2014, the pre-acquisition earnings of such projects are recorded as attributable to NRG's noncontrolling interest. Prior to the date of acquisition, El Segundo made a distribution to NRG of $23 million. Additionally, NRG Repowering Holding LLC (a wholly owned subsidiary of NRG) paid a contribution of $2 million to TA High Desert.

99

Note 12 — Segment Reporting

The Company’s segment structure reflects how management currently makes financial decisions and allocates resources. Its 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 generated more than 10% of its revenues from the following customers for the years ended December 31, 2014, and 2013. For the year ended December 31, 2012, there were no customers from whom the Company derived more than 10% of consolidated revenue.

	2014		2013
Customer	Conventional (%)	Renewables (%)	Conventional (%)	Renewables (%)
Southern California Edison	21%	11%	15%	4%
Pacific Gas and Electric	21%	5%	22%	7%

	Year ended December 31, 2014
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	244		$	144		$	195		$	—		$	583
Cost of operations	41			34			139			—			214
Depreciation and amortization	66			52			18			—			136
General and administrative — affiliate	—			—			—			8			8
Acquisition-related transaction and integration costs	—			—			—			4			4
Operating income (loss)	137			58			38			(12		)	221
Equity in earnings of unconsolidated affiliates	14			13			—			—			27
Other income, net	1			1			—			1			3
Interest expense	(43		)	(86		)	(7		)	(30		)	(166		)
Income (loss) before income taxes	109			(14		)	31			(41		)	85
Income tax expense	—			—			—			4			4
Net Income (Loss)	$	109		$	(14	)	$	31		$	(45	)	$	81
Balance Sheet
Equity investment in affiliates	$	114		$	113		$	—		$	—		$	227
Capital expenditures(a)	5			(1		)	7			—			11
Total Assets	$	1,516		$	3,321		$	437		$	478		$	5,752

(a) Includes accruals. Capital expenditures for Renewables include a sales tax refund received by Alpine in the first quarter of 2014.

	Year ended December 31, 2013
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	138		$	89		$	152		$	—		$	379
Cost of operations	23			11			110			—			144
Depreciation and amortization	20			26			15			—			61
General and administrative — affiliate	—			—			—			7			7
Operating income (loss)	95			52			27			(7		)	167
Equity in earnings of unconsolidated affiliates	16			6			—			—			22
Other income, net	1			2			—			—			3
Interest expense	(25		)	(20		)	(7		)	—			(52		)
Income (loss) before income taxes	87			40			20			(7		)	140
Income tax expense	—			—			—			8			8
Net Income (Loss)	$	87		$	40		$	20		$	(15	)	$	132
Balance Sheet
Equity investments in affiliates	$	118		$	109		$	—		$	—		$	227
Capital expenditures (a)	168			30			15			—			213
Total Assets	$	1,584		$	1,046		$	436		$	172		$	3,238

(a) Includes accruals.

100

	Year ended December 31, 2012
(In millions)	Conventional Generation			Renewables			Thermal			Corporate			Total
Operating revenues	$	—		$	33		$	142		$	—		$	175
Cost of operations	2			9			103			—			114
Depreciation and amortization	—			10			15			—			25
General and administrative — affiliate	—			—			—			7			7
Operating income (loss)	(2		)	14			24			(7		)	29
Equity in earnings of unconsolidated affiliates	15			4			—			—			19
Other income, net	1			1			—			—			2
Interest expense	—			(20		)	(8		)	—			(28		)
Income (loss) before income taxes	14			(1		)	16			(7		)	22
Income tax expense	—			—			—			10			10
Net Income (Loss)	$	14		$	(1	)	$	16		$	(17	)	$	12

Note 13 — Income Taxes

Effective Tax Rate

The income tax provision from continuing operations consisted of the following amounts:

	Year Ended December 31,
	2014			2013			2012
	(In millions, except percentages)
Current
U.S. Federal	$	—		$	—		$	7
Total — current	—			—			7
Deferred
U.S. Federal	2			14			1
State	2			(6		)	2
Total — deferred	4			8			3
Total income tax expense	$	4		$	8		$	10
Effective tax rate	4.7		%	5.7		%	45.5		%

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

	Year Ended December 31,
	2014			2013 (a)			2012 (b)
	(In millions, except percentages)
Income Before Income Taxes	85			140			22
Tax at 35%	30			49			8
State taxes, net of federal benefit	1			(6		)	2
Impact of non-taxable equity earnings	(22		)	(35		)	—
Production tax credits	(6		)	—			—
Change in state effective tax rate	1			—			—
Income tax expense	$	4		$	8		$	10
Effective income tax rate	4.7		%	5.7		%	45.5		%

(a) -Represents 34.5% ownership for the period July 22, 2013 through December 31, 2013

(b) - Represents pro forma tax provision for NRG Yield LLC

For the year ended December 31, 2014, the overall effective tax rate was different than the statutory rate of 35% primarily due to taxable earnings allocated to NRG resulting from its 55.3% interest in NRG Yield LLC and production tax credits generated from certain Alta Wind Portfolio facilities.

For the year ended December 31, 2013, the overall effective tax rate was different than the statutory rate of 35% primarily due to taxable earnings allocated to NRG resulting from its 65.5% interest in NRG Yield LLC.

101

On July 22, 2013, the Company acquired a controlling interest in NRG Yield LLC and its subsidiary NRG Yield Operating LLC. On July 29, 2014, the Company issued additional shares of Class A common stock, and as a result, it currently owns 44.7% of NRG Yield LLC and consolidates the results due to its controlling interest. The Company records NRG's 55.3% ownership as noncontrolling interest in the financial statements. For tax purposes, NRG Yield LLC is treated as a partnership; therefore, the Company and NRG each record their respective share of taxable income or loss.

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

	As of December 31,
	2014		2013
	(In millions)
Deferred tax assets:
Investment in projects	$	47	$	81
Production tax credits carryforwards	6		—
U.S. Federal net operating loss carryforwards	74		61
State net operating loss carryforwards	7		4
Total deferred tax assets	134		146
Net deferred tax asset	$	134	$	146

The following table summarizes the Company's net deferred tax position:

	As of December 31,
	2014		2013
	(In millions)
Net deferred tax asset — current	$	16	$	—
Net deferred tax asset — noncurrent	118		146
Net deferred tax asset	$	134	$	146

Tax Receivable and Payable

As of December 31, 2014, the Company had a domestic tax receivable of $6 million which related to federal cash grants for Borrego project. This amount is fully reserved pending further discussions with the US Treasury Department.

Deferred Tax Assets and Valuation Allowance

Net deferred tax balance — As of December 31, 2014, and 2013, NRG recorded a net deferred tax asset of $134 million and $146 million, respectively. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets. In arriving at this conclusion to utilize projections of future profit before tax in its estimate of future taxable income, the Company considered the profit before tax generated in recent years.

NOL carryforwards — At December 31, 2014, the Company had domestic NOLs consisting of carryforwards for federal income tax purposes of $74 million and cumulative state NOLs of $7 million tax-effected.

Uncertain Tax Positions

The Company had no identified uncertain tax positions that require evaluation as of December 31, 2014.

102

Note 14 — Related Party Transactions

Management Services Agreement by and between NRG and the Company

Since the Company has no employees, 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 December 31, 2014, the base management fee was approximately $6 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, 2014, the fee was increased by approximately $2 million per year in connection with the acquisition of the Acquired ROFO Assets and Alta Wind Portfolio. Costs incurred under this agreement were approximately $8 million for the year ended December 31, 2014 and $3 million for the period beginning July 23, 2013 and ending December 31, 2013. These costs included certain direct expenses incurred by NRG on behalf of the Company in addition to the base management fee, $5 million of which was unpaid as of December 31, 2014 and bears no interest. The balance was classified as a liability under accounts payable — affiliate in the Company's consolidated balance sheets as of December 31, 2014, and repaid in February 2015.

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

On October 1, 2014, NRG entered into Plant O&M Services Agreements with certain wholly-owned subsidiaries of the Company. NRG provides necessary and appropriate services to operate and maintain the subsidiaries' plant operations, businesses and thermal facilities. NRG is to be reimbursed for the provided services, as well as for all reasonable and related expenses and expenditures, and payments to third parties for services and materials rendered to or on behalf of the parties to the agreements. NRG is not entitled to any management fee or mark-up under the agreements. Prior to October 1, 2014, NRG provided same services to Thermal entities on an informal basis. For the years ended December 31, 2014 and 2013, total fees incurred under the agreements were $27 million and $24 million, respectively. There was a balance of $22 million due to NRG in accounts payable — affiliate as of December 31, 2014.

O&MServices Agreements by and between NRG and GenConn

GenConn incurs fees under two O&M agreements with wholly-owned subsidiaries of NRG. The fees incurred under the agreements were $6 million, $5 million and $5 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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

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

In addition, NRG Power Marketing has the exclusive right and obligation to direct the output from the generating facility, in accordance with and to meet the terms of any power sales contracts executed against the power generation of the Dover facility. Under the agreement, NRG Power Marketing pays NRG Dover gross receipts generated through sales, less costs incurred by NRG Power Marketing related to providing such services as transmission and delivery costs, as well as fuel costs. During 2011, the existing coal purchase contract expired and NRG Power Marketing entered into a new contract, which expired in December 2012, to purchase coal for the Dover Facility. For the year ended December 31, 2012, NRG Dover purchased approximately $2 million under this agreement. In July 2013, the originally coal-fueled plant was converted to a natural gas facility. For the years ended December 31, 2014, and 2013, NRG Dover purchased approximately $10 million and $5 million, respectively, of natural gas from NRG Power Marketing.

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

El Segundo incurs fees under an O&M agreement with NRG El Segundo Operations, Inc., a wholly-owned subsidiary of NRG. Under the O&M agreement, NRG El Segundo Operations, Inc. manages, operates and maintains the El Segundo facility for an initial term of ten years following the commercial operations date. For the years ended December 31, 2014, 2013, and 2012, the costs incurred under the agreement were approximately $4 million, $5 million, and $1 million, respectively. For the years ended December 31, 2013 and 2012, $2 million and $1 million of the costs incurred were capitalized and recorded to property, plant and equipment in the Company's consolidated balance sheets.

103

Ground Lease and Easement Agreement by and between El Segundo and El Segundo Power, LLC

El Segundo incurred lease expense under a ground lease and easement agreement with El Segundo Power, LLC, a wholly-owned subsidiary of NRG, for a parcel of real property in the city of El Segundo, California. The nonexclusive easements are for the support infrastructure for the project. The initial term of the agreement was over the construction of the project through the twentieth anniversary of the commercial operations date. For the years ended December 31, 2014, 2013, and 2012, theCompany incurred costs of approximately $1 million for each year. The costs are included in cost of operations in the Company's consolidated statements of operations.

Construction Management Services Agreement by and between El Segundo and NRG Construction Services LLC

El Segundo incurred fees under a construction management services agreement with NRG Construction Services LLC, a wholly-owned subsidiary of NRG, to act as construction manager of the project to manage the design, engineering, procurement and construction, commissioning, testing initial start-up and closeout of construction activities for the facility. For the years ended December 31, 2013 and 2012, total costs incurred were $4 million and $4 million, respectively. The costs were capitalized and recorded to property, plant and equipment in the Company's consolidated balance sheets. El Segundo achieved commercial operations in August 2013.

Energy Marketing Services Agreement with NRG Power Marketing LLC

El Segundo was a party to an energy marketing services agreement with NRG Power Marketing LLC, a wholly-owned subsidiary of NRG, to procure fuel and market capacity, energy and ancillary output of the facility prior to the start of the PPA with Southern California Edison. The agreement began in April 2013 and ended at the commercial operations date in August 2013. For the years ended December 31, 2014 and 2013, the Company recorded approximately $1 million and $12 million, respectively, in costs related to this agreement of which $9 million was recorded to property, plant and equipment in 2013, with remaining amount recorded to cost of operations in the Company's statement of operations.

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

Marsh Landing is a party to an administrative services agreement with GenOn Energy Services, LLC, a wholly owned subsidiary of NRG, which provides with processing and paying invoices services 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 approximately $13 million, $36 million, and $2 million for the years ended December 31, 2014, 2013 and 2012, respectively. For the years ended December 31, 2014, 2013 and 2012, $2 million, $29 million and $2 million, respectively, were capitalized. There was a balance of $4 million and $2 million due to GenOn Energy Services, LLC in accounts payable - affiliate as of December 31, 2014 and 2013, respectively.

Accounts Payable to NRG Renew LLC

During the third quarter of 2013, NRG Renew LLC (formerly known as NRG Solar LLC), a wholly-owned subsidiary of NRG, made 100% of the required capital contributions to CVSR, including the Company's 48.95% portion, of which $14 million was outstanding as of December 31, 2013. This balance was repaid to NRG Renew LLC during the quarter ended March 31, 2014.

Accounts Payable to NRG Repowering Holdings LLC

During 2013, NRG Repowering Holdings, LLC, a wholly-owned subsidiary of NRG, made payments to BA Leasing BSC, LLC, or BA Leasing, of $18 million, which were expected to be repaid with the proceeds of the cash grant received by BA leasing with respect to the PFMG DG Solar Projects, in connection with a sale-leaseback arrangement between the PFMG DG Solar Projects and BA Leasing. As of December 31, 2013, PFMG DG Solar Projects had a corresponding receivable for the reimbursement of the cash grant from BA Leasing and related payable to NRG Repowering Holdings, LLC. In the first quarter of 2014, the PFMG DG Solar Projects received $11 million from BA Leasing and reduced the remaining receivable with an offset to the deferred liability recorded in connection with the sale - leaseback arrangement. The PFMG DG Solar Projects utilized the $11 million to repay NRG Repowering Holdings LLC.

Note 15 — Commitments and Contingencies

104

Operating Lease Commitments

The Company leases certain facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2048. The effects of these scheduled rent increases, leasehold incentives, and rent concessions are recognized on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Lease expense under operating leases was $3 million for the year ended December 31, 2014, and $2 million for each of the years ended 2013 and 2012.

Future minimum lease commitments under operating leases for the years ending after December 31, 2014, are as follows:

Period	(In millions)
2015	$	6
2016	5
2017	5
2018	5
2019	5
Thereafter	103
Total	$	129

Gas and Transportation Commitments

The Company has entered into contractual arrangements to procure power, fuel and associated transportation services. For the years ended December 31, 2014, 2013 and 2012, the Company purchased $55 million, $40 million, and $30 million, respectively, under such arrangements.

As of December 31, 2014, the Company's commitments under such outstanding agreements are estimated as follows:

Period	(In millions)
2015	$	15
2016	4
2017	3
2018	3
2019	2
Thereafter	26
Total	$	53

Contingencies

In the normal course of business, the Company is subject to various claims and litigation. Management expects that these various litigation items will not have a material adverse effect on the Company's results of operations or financial position.

Note 16 — Environmental Matters

In 2013, NRG Energy Center San Francisco LLC, a wholly owned indirect subsidiary of the Company, received a notice of violation from the San Francisco Department of Public Health alleging improper monitoring of three underground storage tanks. The tanks have not leaked. The Company settled the matter in July 2014 for $123,000.

105

Note 17 — Unaudited Quarterly Data

Refer to Note 2, Summary of Significant Accounting Policies and Note 3, Business Acquisitions for a description of the effect of unusual or infrequently occurring events during the quarterly periods. Summarized unaudited quarterly financial data is as follows:

	Quarter Ended
	December 31,			September 30,		June 30,		March 31, (a)
	2014
	(In millions, except per share data)
Operating Revenues	$	148		$	161	$	134	$	140
Operating Income	46			70		51		54
Net (Loss) Income	(10		)	31		34		26
Net Income Attributable to NRG Yield, Inc.	$	—		$	6	$	6	$	4
Weighted average number of Class A common shares outstanding - basic and diluted	35			31		23		23
Earnings per Weighted Average Class A Common Share - Basic and Diluted	$	0.02		$	0.20	$	0.26	$	0.18

^(a) The Acquired ROFO Assets were purchased on June 30, 2014, and accordingly the Company had previously reported operating revenues of $110 million, operating income of $38 million and net income of $18 million for the three months ended March 31, 2014.

	Quarter Ended
	December 31, (b)		September 30, (b)(c)		June 30, (b)		March 31, (b)
	2013
(As recast)	(In millions, except per share data)
Operating Revenues	$	118	$	126	$	82	$	53
(As previously reported)
Operating Revenues	86		95		79		53
(Change )	32		31		3		—
(As recast)
Operating Income	54		63		38		12
(As previously reported)
Operating Income	33		45		38		12
Change	21		18		—		—
(As recast)
Net Income	37		49		35		11
(As previously reported)
Net Income	24		40		34		11
(Change)	13		9		1		—
Net Income Attributable to NRG Yield, Inc.	$	4	$	9	n/a		n/a
Weighted average number of Class A common shares outstanding - basic and diluted	23		23		n/a		n/a
Earnings per Weighted Average Class A Common Share - Basic and Diluted	$	0.17	$	0.39	n/a		n/a

^(b) The Company's unaudited quarterly financial data was recast for the effect of the Acquired ROFO Assets.

^(c) Earnings per weighted average class A common share are calculated for the period of July 22, 2013 to September 30, 2013.

106

Schedule I

NRG Yield, Inc. (Parent)

Condensed Financial Information of Registrant

Condensed Statements of Income

	Year ended December 31,
(In millions)	2014			2013 (a)
Equity earnings in consolidated subsidiaries	$	90		$	86
Interest expense	(5		)	—
Income Before Income Taxes	85			86
Income tax expense	4			8
Net Income	81			78
Less: Pre-acquisition net income of acquired ROFO assets	17			23
Less: Net income attributable to NRG	48			42
Net Income Attributable to NRG Yield, Inc.	$	16		$	13

^(a) Retrospectively adjusted as discussed in Item 15 — Note 1, Nature of Business of the Company's consolidated financial statements.

See accompanying notes to condensed financial statements.

107

Schedule I

NRG Yield, Inc.

Condensed Balance Sheets

	Year ended December 31,
	2014			2013 (a)
	(In millions)
Assets
Current Assets:
Deferred income taxes	16			—
Noncurrent Assets:
Investment in consolidated subsidiaries	1,330			1,106
Note receivable - Yield Operating	337			—
Debt Issuance Costs	5			—
Deferred income taxes	118			146
Total Assets	$	1,806		$	1,252
Liabilities and Equity
Deferred income taxes	—			—
Long-term debt	326			—
Total Liabilities	326			—
Stockholders' Equity:
Preferred stock, $0.01 par value; 10,000,000 shares authorized; none issued	—			—
Class A common stock, $0.01 par value; 500,000,000 shares authorized; 34,586,250 and 22,511,250 shares issued at December 31, 2014 and 2013	—			—
Class B common stock, $0.01 par value; 500,000,000 shares authorized; 42,738,750 shares issued at December 31, 2014 and 2013	—			—
Additional paid-in capital	1,240			621
Retained earnings	3			8
Accumulated other comprehensive loss	(9		)	—
Noncontrolling interest	246			623
Total Stockholders' Equity	1,480			1,252
Total Liabilities and Stockholders' Equity	$	1,806		$	1,252

^(a) Retrospectively adjusted as discussed in Item 15 — Note 1, Nature of Business of the Company's consolidated financial statements.

See accompanying notes to condensed financial statements.

108

Schedule I

NRG Yield, Inc.

Condensed Statements of Cash Flows

	Years ended December 31,
	2014			2013 (a)
	(In millions)
Net Cash Provided by Operating Activities	$	(1	)	$	5
Cash Flows from Investing Activities
Investments in consolidated affiliates	(630		)	(468		)
Increase in notes receivable - affiliate	(337		)	—
Net Cash Used in Investing Activities	(967		)	(468		)
Cash Flows from Financing Activities
Proceeds from issuance of debt	345			—
Proceeds from issuance of Class A common shares	630			468
Payment of debt issuance costs	(7		)	—
Cash received from Yield LLC for the payment of dividends	41			—
Payment of dividends to Class A common shareholders	(41		)	(5		)
Net Cash Provided by Financing Activities	968			463
Net Change in Cash and Cash Equivalents	—			—
Cash and Cash Equivalents at Beginning of Period	—			—
Cash and Cash Equivalents at End of Period	$	—		$	—

^(a) Retrospectively adjusted as discussed in Note 1, Nature of Business of the Company's consolidated financial statements.

See accompanying notes to condensed financial statements.

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Schedule I

NRG Yield, Inc. (Parent)

Notes to Condensed Financial Statements

Note 1 — Background and Basis of Presentation

Background

The Company was formed by NRG as a Delaware corporation on December 20, 2012. On July 22, 2013, it issued 22,511,250 shares of Class A common stock in an initial public offering. The Company utilized the net proceeds of the initial public offering to acquire 19,011,250 Class A units of NRG Yield LLC from NRG in return for $395 million, and 3,500,000 Class A units of NRG Yield LLC directly from NRG Yield LLC in return for $73 million.  In connection with the acquisition of the Class A units, NRG Yield, Inc. also became the sole managing member of NRG Yield LLC thereby acquiring a controlling interest in NRG Yield LLC. 

Immediately prior to the acquisition, NRG Yield LLC acquired a portfolio of contracted renewable and conventional generation and thermal infrastructure assets, primarily located in the Northeast, Southwest and California regions of the United States, from NRG in return for Class B units in NRG Yield LLC.  These assets were simultaneously contributed by NRG Yield LLC to its direct wholly owned subsidiary NRG Yield Operating LLC.  Following the initial public offering, NRG Yield, Inc. owned 34.5% of NRG Yield LLC and consolidated the results of NRG Yield LLC through its controlling interest, with NRG's 65.5% interest shown as noncontrolling interest in the financial statements.

On July 29, 2014, the Company issued 12,075,000 shares of Class A common stock for net proceeds, after underwriting discount and expenses, of $630 million. The Company utilized the proceeds of the offering to acquire 12,075,000 additional Class A units of NRG Yield LLC and, as a result, as of December 31, 2014, the Company now owns 44.7% of NRG Yield LLC, and continues to consolidate the results of NRG Yield LLC through its controlling interest. NRG Yield, Inc.'s sole purpose is to own 44.7% of NRG Yield LLC.

Basis of Presentation

The condensed parent-only company financial statements have been prepared in accordance with Rule 12-04 of

Regulation S-X, as the restricted net assets of NRG Yield, Inc.’s subsidiaries exceed 25% of the consolidated net assets of

NRG Yield, Inc. The parent's 100% investment in its subsidiaries has been recorded using the equity basis of accounting in the accompanying condensed parent-only financial statements. These statements should be read in conjunction with the consolidated statements and notes thereto of NRG Yield, Inc.

Note 2 — Long-Term Debt

For a discussion of NRG Yield Inc.’s financing arrangements, see Note 9, Debt and Capital Leases, to the Company's consolidated financial statements.

Note 3 — Commitments, Contingencies and Guarantees

See Note 13, Income Taxes and Note 15, Commitments and Contingencies to the Company's consolidated financial statements for a detailed discussion of NRG Yield, Inc.’s commitments and contingencies.

Note 4 — Dividends

Cash distributions paid to NRG Yield, Inc. by its subsidiary, NRG Yield LLC, were $41 million and $5 million for the years ended December 31, 2014 and 2013, respectively.

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Index to Consolidated Financial Statements

Unaudited Consolidated Financial Statements of GCE Holding LLC

Consolidated Statements of Income - Year ended December 31, 2014 and 2013

Consolidated Balance Sheets - December 31, 2014 and 2013

Consolidated Statements of Cash Flows - December 31, 2014 and 2013

Consolidated Statement of Changes in Partnership Equity - December 31, 2014 and 2013

Notes to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm

Audited Consolidated Financial Statements of GCE Holding LLC

Consolidated Statement of Income - Years ended December 31, 2012

Consolidated Balance Sheet - December 31, 2012

Consolidated Statement of Cash Flows - December and 2012

Consolidated Statement of Changes in Partnership Equity - December 31, 2012

Notes to Consolidated Financial Statements

The consolidated financial statements of GCE Holding LLC for the years ended December 31, 2014 and 2013 are presented herein without the related report of independent accountants in compliance with Rule 3-09 of Regulation S-X.

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GCE Holding LLC

Consolidated Statements of Operations (Unaudited)

For the Year Ended December 31,

(In thousands)

	2014			2013
Operating revenues	$	82,010		$	79,775
Operating expense	20,924			15,055
Depreciation and amortization expense	16,259			16,046
Taxes other than income	4,644			4,557
Income from operations	40,183			44,117
Other income and (deductions)	(53		)	(23		)
Interest expense	12,259			13,376
Income	$	27,871		$	30,718

The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.

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GCE Holding LLC

Consolidated Balance Sheets (Unaudited)

As of December 31,

(In thousands)

	2014			2013
Assets
Current assets:
Cash	$	14,659		$	16,367
Restricted cash	660			—
Regulatory assets	519			364
Accounts receivable	6,989			9,065
Other current assets	882			350
Fuel oil inventory	6,966			3,642
Materials & supplies inventory	2,141			2,077
Unamortized debt expense	613			484
	33,429			32,349
Property, plant and equipment:
In-service	477,817			477,813
Accumulated depreciation and amortization	(62,530		)	(46,592		)
	415,287			431,221
Long term assets:
Unamortized debt expense	11,897			12,678
Regulatory assets	10,672			10,057
	22,569			22,735
Total assets	$	471,285		$	486,305
Liabilities and Equity
Current liabilities:
Accounts payable	$	2,702		$	3,108
Accrued liabilities	1,962			2,074
Regulatory liabilities	1,772			1,016
Other current liabilities	466			507
Current portion of long term debt	8,002			8,002
Interest payable on long term debt	4,984			3,232
	19,888			17,939
Long term liabilities:
Long term debt	220,496			228,498
Regulatory liability	1,566			2,652
Asset retirement obligation	664			612
Other long-term liabilities	110			49
	222,836			231,811
Equity:
Paid-in capital	228,561			236,555
Retained earnings	—			—
	228,561			486,305
Total liabilities and equity	$	471,285		$	486,305

The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.

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GCE Holding LLC

Consolidated Statements of Cash Flows (Unaudited)

For the Year Ended December 31,

(In thousands)

	2014			2013
Net income	$	27,871		$	30,718
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	15,989			15,976
Amortization of Debt Issuance Costs	651			1,208
Amortization of regulatory assets	364			160
Net regulatory asset/liability	—			6,538
Net derivative asset/liability	—			(6,538		)
Changes in:
Accounts receivable	2,076			2,285
Other current assets	(531		)	278
Fuel oil inventory	(3,324		)	(22		)
Materials & supplies inventory	(65		)	(38		)
Accounts payable	(405		)	(1,631		)
Accrued liabilities	(51		)	142
Other current liabilities	(41		)	415
Interest payable on long term debt	1,752			3,208
Regulatory asset/liability	(1,463		)	(2,100		)
Total cash provided by operating activities	42,823			50,599
Plant expenditures including AFUDC debt	(4		)	(782		)
Changes in restricted cash	(660		)	11,351
Total cash provided by investing activities	(664		)	10,569
Borrowings of long term debt	—			236,500
Repayments of long term debt	(8,002		)	(228,395		)
Debt issuance costs	—			(9,275		)
Distribution of capital	(35,867		)	(43,631		)
Contribution of capital	2			—
Total cash used in financing activities	(43,867		)	(44,801		)
Net change for the period	(1,708		)	16,367
Balance at the beginning of the period	16,367			—
Balance at the end of the period	$	14,659		$	16,367
Cash paid during the period for:
Interest	$	9,202		$	7,816

The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.

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GCE Holding LLC

Consolidated Statements of Changes in Equity (Unaudited)

For the Years Ended December 31, 2014, 2013

(In thousands)

Paid-in Capital	Consolidated
Balance as of December 31, 2012	$	249,323
Distribution of capital	(12,768		)
Balance as of December 31, 2013	236,555
Contribution of capital	2
Distribution of capital	(7,996		)
Balance as of December 31, 2014	$	228,561

Retained Earnings	Consolidated
Balance as of December 31, 2012	$	145
Income for 2013	30,718
Distribution to Partners	(30,863		)
Balance as of December 31, 2013	—
Income for 2014	27,871
Distribution to partners	(27,871		)
Balance as of December 31, 2014	$	—

The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.

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GCE Holding LLC

Notes to the Consolidated Financial Statements (Unaudited)

Organization

GCE Holding LLC (GCE) is a 50-50 joint venture between The United Illuminating Company (UI) and NRG Connecticut Peaking Development LLC, an indirect subsidiary of NRG Yield, Inc. GenConn Energy LLC (GenConn) is a wholly-owned subsidiary of GCE. GenConn consists of two peaking generation plants, GenConn Devon LLC (GenConn Devon) and GenConn Middletown LLC (GenConn Middletown), which were chosen by the Connecticut Public Utilities Regulatory Authority (PURA) to help address the state’s growing need for more power generation during the heaviest load periods. The two peaking generation plants, each with a nominal capacity of 200 megawatts (MW), are located at the existing Connecticut plant locations in Devon and Middletown of NRG Energy, Inc. (NRG). GenConn Devon became operational in June 2010 and GenConn Middletown became operational in June 2011.

Basis of Presentation

The accounting records of GenConn are maintained in conformity with accounting principles generally accepted in the United States of America (GAAP).

The accounting records for GenConn are also maintained in accordance with the uniform systems of accounts prescribed by the Federal Energy Regulatory Commission (FERC) and PURA.

The preparation of financial statements in conformity with GAAP requires management to use estimates and assumptions that affect (1) the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and (2) the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

New Accounting Standards

Authoritative guidance requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. This guidance is effective for interim and annual reporting periods beginning after December 15, 2016 and is to be applied retrospectively. GenConn is currently evaluating the effect that adopting this new accounting guidance will have on its consolidated financial statements.

Consolidation

The consolidated financial statements of GCE include the results of operations and financial position of its wholly-owned subsidiaries GenConn Devon and GenConn Middletown. Intercompany accounts and transactions have been eliminated in consolidation.

Regulatory Accounting

GenConn has Locational Forward Reserve Market (LFRM) obligations through May 31, 2015 as a result of its seasonal bids (twice yearly) into the ISO-New England, Inc. (ISO-NE) markets. GenConn also has Forward Capacity Market (FCM) obligations as a result of its annual bids into ISO-NE markets. FCM auctions are conducted annually, awarded and represent obligations three-years into the future. GenConn’s current FCM obligation is through May 31, 2019. All bids into the LFRM and FCM markets are based on directives from PURA.

GenConn received a final decision from PURA on December 17, 2014, approving its 2015 revenue requirements of $66.0 million for GenConn ($29.5 million for the GenConn Devon facility and $36.5 million for the GenConn Middletown facility). Additionally, GenConn was granted a 9.95% Return on Equity (ROE) for 2015.

GenConn received an interim, final decision from PURA in Docket No. 13-06-38 on September 25, 2013, approving requested changes to the Contract for Difference (CfD) to reflect ISO-NE market rule changes.  GenConn requested revisions to the CfD so that the Contract Monthly LFRM Revenue term, that calculates the credit to the Buyer associated with LFRM revenues, includes an adjustment that would reduce the credit to the Buyer associated with the Failure-to-Activate penalty and the Failure-to-Reserve penalty by the amount resulting solely from the market rule change related to LFRM penalties. This change appropriately accounts for and passes charges for recovery through the CfD invoices. 

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A final decision was issued by PURA in Docket No. 13-06-38 on December 11, 2013 approving 2014 revenue requirements of $68.3 million for GenConn ($30.8 million for the GenConn Devon facility and $37.5 million for the GenConn Middletown facility). Additionally, GenConn was granted a 9.95% Return on Equity (ROE) for 2014.

GenConn received a final decision (2013 Decision) from PURA on January 9, 2013, approving its 2013 revenue requirements of $73.3 million for GenConn ($33.1 million for the GenConn Devon facility and $40.2 million for the GenConn Middletown facility). Additionally, GenConn was granted a 9.75% Return on Equity (ROE) for 2013. PURA also ruled in the 2013 Decision that GenConn project costs that were in excess of the proposed costs originally submitted in 2008, were prudently incurred and are recoverable. Recovery of these costs was included in the 2013 Decision. The increase in project costs was driven in large part by increased financing costs and the cost to build interconnection facilities at GenConn Middletown.

Management has determined that GenConn meets the criteria for an entity with regulated operations as defined by the authoritative guidance on accounting for the effects of certain types of regulation. As such, GenConn has established regulatory assets for certain costs deferred if it is probable that it will be able to recover such costs in future revenues, and has established regulatory liabilities for certain obligations recognized if it is probable that it will be relieved of such liabilities in future revenues based on the criteria outlined in the PURA Decisions related to the types of costs that are recoverable. Furthermore, GenConn has received approval from PURA in its final revenue requirements decisions allowing for the recovery and/or return of property taxes, financing costs, transmission related operating costs and interest expense.

GenConn’s regulatory assets and liabilities as of December 31, 2014 and 2013 are set forth below (in thousands):

Regulatory Assets:	Remaining Period	As of December 31, 2014		As of December 31, 2013
Property taxes	1 year	$	591	$	669
Deferred project costs	(a)	9,262		8,439
Financing costs	26 years	1,142		1,186
Operating costs	(b)	4		9
Sales & Use taxes	(c)	142		80
Interest expense	(d)	—		39
Debt amortization	(f)	50		—
Total Regulatory Assets		11,191		10,422
Less current portion of Regulatory Assets		519		364
Regulatory Assets, long-term		$	10,672	$	10,058
Regulatory Liabilities:
Operating costs	(b)	$	463	$	1,263
Interest expense	(d)	1,305		1,231
Maintenance costs	(e)	1,276		880
Debt Amortization	(f)	294		294
Total Regulatory Liabilities		3,338		3,668
Less current portion of Regulatory Liabilities		1,772		1,016
Regulatory Liabilities, long-term		$	1,566	$	2,652
(a) Represents project repair costs. Recovery to be determined in future revenue requirements.
(b) Represents a true-up of actual transmission related operating costs to amounts allowed in revenue requirements. The current portion will be recovered or returned in 2015 as allowed in PURA final decisions. The recovery or return of the long-term portion will be determined in future revenue requirements proceedings.
(c) Represents a true-up of actual sales & use taxes to amounts allowed in revenue requirements. Recovery will be determined in future revenue requirement proceedings.
(d) Represents a true-up of actual interest costs to amounts allowed in revenue requirements. The current portion will be recovered or returned in 2015 as allowed in PURA final decisions. The recovery or return of the long-term portion will be determined in future revenue requirements proceedings.
(e) Represents current collections for future anticipated large equipment maintenance costs.
(f) Represents a true-up of debt amortization expense to amounts allowed in revenue requirements. The return will be determined in future revenue requirements proceedings.

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Cash and Temporary Cash Investments

GenConn considers all of its highly liquid debt instruments with an original maturity of three months or less at the date of purchase to be cash and temporary cash investments.

Restricted Cash

GenConn’s restricted cash balance is comprised of two separate items: 1) an investment in a sinking fund which was required as part of its September 17, 2013 long term debt refinancing and 2) a financial assurance compliance requirement pursuant to security and control agreements entered into with ISO-NE. The sinking fund restricted cash is scheduled to pay the outstanding balance of the long term debt in full at its maturity date. The restricted cash associated with the ISO-NE financial assurance compliance requirement replaced a Letter of Credit GenConn obtained to meet this requirement historically. The security and control agreement with ISO-NE serves as a form of collateral securing the payment of all of GenConn’s potential obligations associated with market participation thereby satisfying financial assurance compliance requirements and minimizing GenConn’s compliance risks associated with participation in the ISO-NE markets.

Inventory

Inventory primarily consists of fuel oil and materials and supplies. Fuel oil is valued under the weighted average cost method and is expensed as consumed through plant operations. Materials and supplies inventory is valued at weighted average cost and is expensed to operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.

Accrued Liabilities

Accrued liabilities primarily consist of accrued property tax expense relating to GenConn Devon and GenConn Middletown which have entered into 30 year tax stabilization agreements with the City of Milford and the City of Middletown, respectively. The tax stabilization agreements terminate on May 1, 2040 for GenConn Devon, and on January 1, 2040 for GenConn Middletown.

Asset Retirement Obligation

The fair value of the liability for an asset retirement obligation is recorded in the period in which it is incurred and the cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, the obligation is settled either at its recorded amount or a gain or a loss is incurred.

Revenue Recognition

Operating revenues are recognized when contractually earned in the period provided and consist of revenues received from power and capacity sales into the ISO-NE markets and from Connecticut Light & Power (CL&P) under the CfDs (as discussed under “Contract for Differences”), based on authorized rates approved by regulatory bodies and can be changed only through formal proceedings with PURA.

Property, Plant and Equipment (PP&E)

PP&E is reflected in the accompanying Consolidated Balance Sheet at cost. Provisions for depreciation on in-service PP&E are computed on a straight-line basis over a 30 year life which was determined by the term of the CfD (as discussed later in the notes) and is representative of the economic life of the plant. The costs of current repairs, major maintenance projects and minor replacements are charged to appropriate operating expense accounts as incurred. Other plant includes other project costs primarily related to civil, mechanical, and electrical site work. GCE’s in-service property, plant and equipment were comprised as follows (in thousands):

	2014		2013
Gas Turbines	$	139,027	$	139,027
Other Plant	303,529		303,525
Capitalized Interest (AFUDC)	35,261		35,261
Gross PP&E In-service	$	477,817	$	477,813

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Impairment of Long-Lived Assets

The authoritative guidance on property, plant, and equipment requires the recognition of impairment losses on long-lived assets when the book value of an asset exceeds the sum of the expected future undiscounted cash flows that result from the use of the asset and its eventual disposition. If impairment arises, then the amount of any impairment is measured based on discounted cash flows or estimated fair value.

The authoritative guidance on property, plant, and equipment also requires that rate-regulated companies recognize an impairment loss when a regulator excludes all or part of a cost from rates, even if the regulator allows the company to earn a return on the remaining costs allowed. As discussed under “Regulatory Accounting,” determination that certain regulatory assets no longer qualify for accounting as such could have a material impact on the financial condition of GenConn. The probability of recovery and the recognition of regulatory assets under the criteria of the authoritative guidance on accounting for the effects of certain types of regulation must be assessed on an ongoing basis. At December 31, 2014, GenConn (as a rate regulated entity) did not have any assets that were impaired under this standard.

Allowance for Funds Used During Construction (AFUDC)

In accordance with the uniform system of accounts prescribed by the FERC and PURA, GenConn capitalizes AFUDC, which represents the approximate cost of debt and equity devoted to plant under construction which ended upon each of GenConn Devon and GenConn Middletown obtaining commercial operation which occurred during June, 2010 and June, 2011, respectively.

Contract for Differences

GenConn recovers its costs under two PURA-approved CfD agreements which are cost of service based and settle on a monthly basis. GenConn has signed CfDs for both facilities with CL&P both with terms of 30 years beginning upon the operations of each plant. Under the terms of the CfD, CL&P will either pay GenConn Devon and GenConn Middletown for the under-recovery or will be reimbursed by those entities for the over-recovery of revenues based on their participation in the ISO-NE markets.

These contracts are accounted for on an accrual basis. Under the CfDs, GenConn agrees that the PURA will determine its cost-of service rate in accordance with the related decisions. Also under the CfD, GenConn agrees to have the units participate and to bid all of the units in ISO-NE Markets as directed by the PURA.

Long‑Term Debt

GenConn issued $236.5 million of senior secured notes in the private placement market on September 17, 2013. GenConn used the proceeds to (1) repay $225 million outstanding under a credit agreement that had been obtained from a consortium of banks on April 24, 2009 for construction and related activities; (2) terminate the interest rate swap that had been required under the credit agreement; (3) rebalance its capital structure to the regulated capital structure of 50% debt and 50% equity; and (4) pay issuance costs. Required principal payments and payments from the restricted cash sinking fund investment are scheduled so that on the maturity date of July 25, 2041 the senior secured notes will be paid in full. Information regarding principal and sinking fund payments is set forth below (in thousands):

Principal Payments
During the twelve months ended December 31st:	Total
2015	$	8,002
2016	8,002
2017	8,002
2018	8,002
2019	8,002
2020 and thereafter	188,488
	$	228,498

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Sinking Fund
During the twelve months ended December 31st:	Total
2015	$	585
2016	585
2017	585
2018	585
2019	585
2020 and thereafter	12,320
	$	15,245

Also on September 17, 2013, GenConn closed on a new secured working capital facility with commitments totaling $35 million from two banks. The working capital facility also permits the issuance of letters of credit. GenConn may borrow under the working capital facility at interest rates equal to either the Base Rate or Eurodollar Rate plus the Applicable Margin, as each is defined in the related agreement. The maturity date of the working capital facility is September 17, 2018. As of December 31, 2014, there were no borrowings under the working capital facility, and there were letters of credit outstanding totaling approximately $19.3 million.

Substantially all of the assets of GenConn serve as collateral for the private placement debt and working capital facility. As of December 31, 2014, the fair value of GenConn’s Long-Term Debt was $251 million based on market conditions. As of December 31, 2013, the carrying value of the Long-Term Debt approximated fair value. Under each of the private placement debt and working capital facility agreements, GenConn is required to comply with certain covenants including the requirement to maintain a Consolidated Indebtedness to Total Capitalization ratio (as defined in the agreements) not to exceed 60%. As of December 31, 2014, GenConn’s Total Indebtedness to Total Capitalization ratio was 50%. In addition, GenConn is subject to a dividend payment test whereby dividends are permitted if the debt service coverage ratio (as defined in the agreements) for the last twelve months is at least 1.2 to 1.0. As of December 31, 2014, GenConn’s debt service coverage ratio was 2.86.

Unamortized Debt Expense

GCE and GenConn deferred debt issuance costs incurred on the bank and project financings are being amortized over the term of the related debt and have been allocated proportionately to both GenConn Devon and GenConn Middletown. The amortization and associated unamortized debt issuance cost balances are accounted for at GenConn Devon and GenConn Middletown as such amounts are recovered in rates. The unamortized debt issuance costs are included in Unamortized Debt Expense in the accompanying Consolidated Balance Sheet as of December 31, 2014 and 2013.

Related Party Transactions

There are no employees of GCE or any of its subsidiaries. UI and NRG (the Partners) are paid, through GCE, for services to GenConn which include administration, plant operations, construction and energy management pursuant to contractual arrangements. As of December 31, 2014 and 2013, amounts owed to the Partners for services were $1.1 million and $1.6 million, respectively, and are included in Accounts Payable in the accompanying Consolidated Balance Sheet. For the years ended December 31, 2014 and 2013, amounts paid to the Partners for services were $22.5 million and $12.4 million, respectively. For the years ended December 31, 2014 and 2013, amounts expensed for services were $8.0 million and $7.2 million, respectively.

GenConn made earnings distributions, through GCE, to the Partners of $27.9 million and $30.8 million for the years ended December 31, 2014 and 2013, respectively.

GenConn returned a portion of the Partner’s investment, through GCE, of $8.0 million and $12.8 million for the years ended December 31, 2014 and 2013, respectively.

GenConn Devon and GenConn Middletown lease both facilities and land from Devon Power LLC (Devon Power) and Middletown Power LLC (Middletown Power), respectively, both of which are subsidiaries of NRG. See the Lease Obligations section for additional details.

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Income Taxes

GCE is not subject to federal or state income taxes. UI and NRG are required to report on their federal and, as required, state income tax return its share of GCE’s income, gains, losses, deductions and credits. Accordingly, there is no provision for income taxes in the accompanying consolidated financial statements.

Derivatives

In connection with the Project Financing, in April 2009, GenConn entered into an interest rate swap agreement with each of the five banks participating in the syndication to reduce the risk of unfavorable changes in variable interest rates related to a portion of the Project Financing. The swaps had the effect of converting variable rate payments to fixed rate payments on approximately $42 million to $121 million principal amount outstanding of Project Financing debt through December 31, 2014 with quarterly settlements that began on March 31, 2010. Any income generated from the agreement was expected to be credited to customers and any expense generated was expected to be recovered from customers through PURA-approved revenue requirements. GenConn accounted for the interest rate swap agreement as an economic hedge. As such, GenConn established a regulatory liability or asset for the mark-to-market adjustments related to the interest rate swaps. On September 17, 2013, the interest swap agreement was terminated in conjunction with the private placement. The settlement payment as a result of such termination is included in unamortized debt expenses as approved by PURA.

The fair value hierarchy levels are Level 1 (quoted prices in active markets for identical assets and liabilities), Level 2 (significant other observable inputs), and Level 3 (significant unobservable inputs).

GenConn utilized an income approach valuation technique to value the interest rate swap derivatives measured and reported at fair value. As required by the authoritative guidance on fair value measurements, financial assets and liabilities are based on the lowest level of input that is significant to the fair value measurement. The interest rate swaps were valued based on the annual London Interbank Offering Rate (LIBOR) index. GenConn’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. GenConn had determined that the fair value of its interest rate swap derivatives were measured using Level 2 inputs.

Contingencies

In the ordinary course of business, GCE and its subsidiaries are involved in various proceedings, including legal, tax, regulatory and environmental matters, which require management’s assessment to determine the probability of whether a loss will occur and, if probable, an estimate of probable loss. When assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated, GCE accrues a reserve and discloses the reserve and related matter. GCE discloses matters when losses are probable for which an estimate is reasonably possible. Subsequent analysis is performed on a periodic basis to assess the impact of any changes in events or circumstances and any resulting need to adjust existing reserves or record additional reserves.

GenConn Middletown Cable System

Two circuits, referred to as “5X” and “6X,” connect the four units at the GenConn Middletown facility to the gas insulated substation.  In April 2011, the 5X circuit failed. Multiple repairs were made. However, the repairs failed to correct persistent partial discharge that was detected through periodic testing.  In March 2012, GenConn filed a lawsuit seeking damages against the electrical contractor responsible for the design and installation of the 5X and 6X and one of its subcontractors. During that same month, the former electrical contractor responsible for the failed installation filed a counterclaim in the amount of approximately $1.8 million and a mechanic’s lien on the GenConn Middletown facility in that same amount.

On July 13, 2012, the 5X circuit and the two units it serviced were taken out of service. On August 8, 2012, the 6X circuit and the remaining two units at the GenConn Middletown facility were taken out of service. This was done because of operation and safety concerns raised by retained experts and by further partial discharge testing. GenConn has amended its complaint, to seek additional damages, including those related to 6X. Further, GenConn hired another electrical contractor to undertake the replacement of the defective equipment.

The defective equipment was replaced during the second half of 2012 and all four units were returned to service on January 19, 2013. 

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In order to comply with certain covenants under its project financing, GenConn Middletown has posted a surety bond for the total amount of the mechanic’s lien, which discharged the lien.   As of December 31, 2014, GenConn Middletown has recorded $1.1 million as a regulatory asset related to the former electrical contractor’s $2.2 million counterclaim. Based on information obtained in discovery, the remaining $1.1 million appears to be comprised of the contractor’s alleged costs for performing repair and investigative work related to the April 2011 failure and the subsequent partial discharge, plus overhead, profit, legal and expert witness fees, all of which have yet to be billed. To the extent that GenConn is required to satisfy any of the claims, recovery of such costs would be pursued in a future revenue requirements proceeding.

The parties to the litigation are seeking to finalize a draft settlement agreement.   A trial date is set for March 2015 in case they are unable to do so by that point. Please refer to Deferred Project Costs included in the Regulatory Accounting table for further information for costs incurred as of December 31, 2014 regarding the defective equipment.

Lease Obligations

Operating leases with Devon Power LLC and Middletown Power LLC, both of which are NRG owned companies, consist primarily of leases of facilities and land for both GenConn Devon and GenConn Middletown. The term of the leases coincide with the maturity of the senior secured notes (2040 for GenConn Devon and 2041 for GenConn Middletown). For the years ended December 31, 2014 and 2013, total operating lease expense for GenConn Devon and GenConn Middletown was $0.6 million and $0.7 million, respectively. The future minimum lease payments under these operating leases are estimated to be as follows (in thousands):

	GenConn		GenConn
Twelve months ended December 31st:	Devon		Middletown
2015	$	579	$	668
2016	579		668
2017	579		668
2018	579		668
2019	579		668
2020 and thereafter	11,822		14,307
	$	14,717	$	17,647

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Table of Contents

Consolidated Financial Statements:

Report of Independent Auditors                                    

Consolidated Statements of Operations for the year ended December 31 2012

Consolidated Balance Sheets as of December 31, 2012

Consolidated Statements of Cash Flows for the years ended December 31, 2012

Consolidated Statements of Changes in Partnership Equity for the years ended December 31, 2012

Notes to the Financial Statements                                    

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Report of Independent Registered Public Accounting Firm

To the Management Committee of GCE Holding LLC:

We have audited the accompanying consolidated financial statements of GCE Holding LLC and its subsidiaries, which comprise the consolidated balance sheet as of December 31, 2012, and the related consolidated statement of operations, of changes in partnership equity and of cash flows for the year then ended.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

Our responsibility is to express an opinion on the consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GCE Holding LLC and its subsidiaries at December 31, 2012, and the results of their operations and their cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter

As discussed in the "Related Party Transaction" note to the consolidating financial statements, GCE Holding LLC has entered into significant transactions with The United Illuminating Company and NRG Connecticut Peaking Development LLC, which are related parties.

/s/ PricewaterhouseCoopers LLP

April 26, 2013

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GCE HOLDING LLC

Consolidated Statement of Operations

For the Year Ended December 2012

(In thousands)

	2012
Operating revenues	$	77,816
Operating expense	11,528
Depreciation and amortization expense	16,762
Taxes other than income	4,763
Income from operations	44,763
Other income and (deductions)	(1		)
Interest expense	15,513
Income	$	29,249

The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.

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GCE Holding LLC

Consolidated Balance Sheet

As of December 31, 2012

(In thousands)

Assets
Current assets:
Cash	$	—
Restricted cash	11,351
Regulatory assets	6,699
Accounts receivable	11,350
Other current assets	627
Fuel oil inventory	3,620
Materials & supplies inventory	2,039
Unamortized debt expense	1,502
	37,188
Property, plant and equipment:
In-service	478,598
Accumulated depreciation and amortization	(30,663		)
Net property, plant & equipment	447,935
Long term assets:
Unamortized debt expense	3,593
Regulatory assets	7,665
	11,258
Total assets	$	496,381
Liabilities and Equity
Current liabilities:
Accounts payable	$	6,436
Accrued liabilities	1,973
Regulatory liabilities	1,242
Current portion of long term debt	8,100
Interest payable on long term debt	24
Derivative liability	6,538
Other current liabilities	92
	24,405
Long term liabilities:
Long term debt	220,295
Regulatory liability	1,640
Asset retirement obligation	565
Other	9
	222,509
Equity:
Paid-in capital	249,322
Retained earnings	145
	249,467
Total liabilities and equity	$	496,381

The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.

126

GCE Holding LLC

Consolidated Statement of Cash Flows

For the Year Ended December 31, 2012

(In thousands)

	2012
Income	$	29,249
Adjustments to reconcile income to net cash provided by operating activities:
Depreciation & amortization expense	15,975
Amortization of debt issuance costs	1,502
Amortization of regulatory assets	874
Net regulatory asset/liability	1,967
Net derivative asset/liability	(1,967		)
Changes in:
Accounts receivable	(2,031		)
Other current assets	(582		)
Fuel oil inventory	213
Materials & supplies inventory	(21		)
Accounts payable	1,927
Accrued liabilities	(467		)
Other current liabilities	(2		)
Interest payable on long term debt	—
Regulatory asset/liability	(1,990		)
Total cash provided by (used in) operating activities	44,647
Plant expenditures including AFUDC debt	(984		)
Changes in restricted cash	8,122
Other	(330		)
Total cash provided by (used in) investing activities	6,808
Borrowings of long term debt	—
Repayments of long term debt	(8,280		)
Debt issuance costs	(87		)
Distribution of capital	(43,090		)
Contribution of capital	2
Total cash provided by (used in) financing activities	(51,455		)
Net change for the period	—
Balance at beginning of period	—
Balance at end of period	—
Cash paid during the period for:
Interest	$	12,804
Non-cash investing activity:
Plant expenditures included in ending payables	$	1,698

The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.

127

GCE Holding LLC

Consolidated Statement of Changes in Partnership Equity

For the Year Ended December 31, 2012

(In thousands)

Paid-in Capital	Consolidated
Balance as of December 31, 2011	$	253,063
Contribution of capital	2
Distribution of capital	(3,741		)
Balance as of December 31, 2012	249,323
Retained Earnings
Balance as of December 31, 2011	$	10,245
Income for 2012	29,249
Distribution to partners	(39,349		)
Balance as of December 31, 2012	$	145

The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.

128

GCE Holding LLC

Notes to the Consolidated Financial Statements

Organization

GCE Holding LLC (GCE) is a 50-50 joint venture between The United Illuminating Company (UI) and NRG Connecticut Peaking Development LLC, an indirect subsidiary of NRG Yield, Inc. GenConn Energy LLC (GenConn) is a wholly-owned subsidiary of GCE. GenConn consists of two peaking generation plants, GenConn Devon LLC (GenConn Devon) and GenConn Middletown LLC (GenConn Middletown), which were chosen by the Connecticut Public Utilities Regulatory Authority (PURA), formerly the Department of Public Utility Control (DPUC), to help address the state's growing need for more power generation during the heaviest load periods. The two peaking generation plants, each with a nominal capacity of 200 megawatts (MW), are located the existing Connecticut plant locations in Devon and Middletown of NRG Energy, Inc. (NRG). GenConn Devon became operational in June 2010 and GenConn Middletown became operational in June 2011.

Basis of Presentation

The accounting records of GenConn are maintained in conformity with accounting principles generally accepted in the United States of America (GAAP).

The accounting records for GenConn are also maintained in accordance with the uniform systems of accounts prescribed by the Federal Energy Regulatory Commission (FERC) and PURA.

The preparation of financial statements in conformity with GAAP requires management to use estimates and assumptions that affect (1) the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and (2) the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Certain amounts reported in the Consolidated Financial Statements in previous periods have been reclassified to conform to the current presentation, primarily related to the presentation of intercompany receivables and payables.

GenConn has evaluated subsequent events through the date its financial statements were available to be issued, April 26, 2013.

Consolidation

The consolidated financial statements of GCE include the results of operations and financial position of its wholly-owned subsidiaries GenConn Devon and GenConn Middletown. Intercompany accounts and transactions have been eliminated in consolidation.

New Accounting Standards

In May 2011, the Financial Accounting Standards Board issued amendments to authoritative guidance on fair value measurements and disclosures which did not have an impact on GenConn's consolidating financial statements.

Regulatory Accounting

GenConn bid its full capacity of the GenConn Devon and GenConn Middletown facilities into the ISO-New England, Inc. (ISO-NE) locational forward reserve market (LFRM) for the winter 2011/2012 period (October 1, 2011—May 31, 2012), for the summer 2012 period (June 1, 2012—September 30, 2012) and for the winter 2012/2013 period (October 1, 2012—May 31, 2013). GenConn bids the full capacity of the facilities into the ISO-NE forward capacity market (FCM), once per year, three years in advance and currently has capacity supply obligations through May 31, 2016.

GenConn filed a revenue requirements application with PURA on July 27, 2012, seeking approval of its 2013 revenue requirements for both the GenConn Devon and GenConn Middletown facilities. A final decision (2013 Decision) was issued by PURA on January 9, 2013, approving revenue requirements of $73.3 million for GenConn ($33.1 million for the Devon facility and $40.2 million for the Middletown facility, respectively). Additionally, GenConn was granted a 9.75% Return on Equity (ROE) for 2013 in the 2013 Decision. PURA also ruled in the 2013 Decision that the GenConn project costs that were in excess of the costs originally submitted in 2008, were prudently incurred and are recoverable. Recovery of these costs is included in the determination of the 2013 approved revenue requirements. The increase in project costs was driven in large part by increased financing costs and the cost to build interconnection facilities at GenConn Middletown.

129

Certain ISO-NE revenues and charges that were not included in the Contract for Differences (CfD) calculation were recorded and collected or paid through the ISO-NE settlement process from June 2010 through September 2011. In GenConn's 2011 revenue requirements proceeding, parties in that proceeding questioned the treatment of the revenues and charges with respect to the CfD calculation. The parties reached a settlement, which was approved by PURA, wherein GenConn reimbursed Connecticut Light & Power (CL&P) $3.0 million during the first quarter of 2012. This amount was fully accrued as of December 31, 2011.

Management has determined that GenConn meets the criteria for an entity with regulated operations as defined by the authoritative guidance on accounting for the effects of certain types of regulation. As such, GenConn has established regulatory assets for certain costs deferred if it is probable that it will be able to recover such costs in future revenues, and has established regulatory liabilities for certain obligations recognized if it is probable that it will be relieved of such liabilities in future revenues based on the criteria outlined in the PURA decisions related to the types of costs that are recoverable. Furthermore, GenConn has received approval from PURA in its final revenue requirements decisions allowing for the recovery and/or return of property taxes, transmission related operating costs and interest expense. GenConn's regulatory assets and liabilities as of December 31, 2012 included the following (in 000's):

Regulatory Assets:	Remaining Period	As of December 31, 2012
Mark-to-market adjustments related to interest rate swaps	(a) 4 years	$	6,539
Property taxes	1 year	665
Deferred project costs	(b)	5,769
Financing costs	27 years	1,229
Operating costs	(c)	41
Interest expense	(d)	121
Bonus depreciation	(e)	—
Total Regulatory Assets		14,364
Less current portion of Regulatory Assets		6,699
Regulatory Assets, long-term		$	7,665
Regulatory Liabilities:
Interest expense	(d)	43
Property tax expense	(f)	—
Operating costs	(c)	2,215
Maintenance costs	(g)	624
Bonus depreciation	(e)	—
Total Regulatory Liabilities		2,882
Less current portion of Regulatory Liabilities		1,242
Regulatory Liabilities, long-term		$	1,640

(a) Related to debt agreement which expires in April 2016. Balance classified as current as it adjusts with the market.

(b) Represents project repair costs. Recovery to be determined in future revenue requirements.

(c) Represents a true-up of actual transmission related operating costs to amounts allowed in revenue requirements. The current portion will be recovered or returned in 2013 as allowed in PURA final decisions. The recovery or return of the long-term portion will be determined in future revenue requirements proceedings.

(d) Represents a true-up of actual interest costs to amounts allowed in revenue requirements. The current portion will be recovered or returned in 2013 as allowed in PURA final decisions. The recovery or return of the long-term portion will be determined in future revenue requirements proceedings.

(e) True-up of the actual partners' deferred tax effects related to bonus depreciation to amounts allowed in revenue requirements were fully amortized as of December 31, 2012.

(f) True-up of property taxes to amounts allowed in revenue requirements were fully amortized as of December 31, 2012.

(g) Represents current collections for future anticipated large equipment maintenance costs.

Cash and Temporary Cash Investments

GenConn considers all of its highly liquid debt instruments with an original maturity of three months or less at the date of purchase to be cash and temporary cash investments.

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Restricted Cash

The use of all cash, including amounts derived from borrowings of notes payable and long-term debt as well as from the collection of accounts receivable, is restricted per the project financing agreements as certain payments, such as scheduled payments of long-term debt, are required to be made prior to dividend payments. Payments made outside the provisions of the project financing require prior approval from the bank.

Inventory

Inventory primarily consists of fuel oil and materials and supplies. Fuel oil is stated primarily at the lower of cost or market value under the weighted average cost method. Materials and supplies inventory is valued at weighted average cost and is expensed to operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.

Accrued Liabilities

Accrued liabilities primarily consist of accrued property tax expense relating to GenConn Devon and GenConn Middletown which have entered into 30 year tax stabilization agreements with the City of Milford and the City of Middletown, respectively.

Asset Retirement Obligation

The fair value of the liability for an asset retirement obligation is recorded in the period in which it is incurred and the cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, the obligation is settled either at its recorded amount or a gain or a loss is incurred.

Revenue Recognition

Operating revenues are recognized when contractually earned in the period provided and consist of revenues received from power and capacity sales into the ISO-NE markets and from CL&P under the CfD based on authorized rates approved by regulatory bodies and can be changed only through formal proceedings

Property, Plant and Equipment (PP&E)

PP&E is reflected in the accompanying Balance Sheet at cost. Provisions for depreciation on in-service PP&E are computed on a straight-line basis over a 30 year life which was determined by the term of the CfD (see below) and is representative of the economic life of the plant. The costs of current repairs, major maintenance projects and minor replacements are charged to appropriate operating expense accounts as incurred. Other plant includes other project costs primarily related to civil, mechanical, and electrical site work.

GCE's in-service property, plant and equipment were comprised as follows (in 000's):

	2012
Gas Turbines	$	139,027
Other Plant	304,310
Capitalized Interest (AFUDC)	35,261
Gross PP&E In-service	$	478,598

Impairment of Long-Lived Assets and Investments

The authoritative guidance on property, plant, and equipment requires the recognition of impairment losses on long-lived assets when the book value of an asset exceeds the sum of the expected future undiscounted cash flows that result from the use of the asset and its eventual disposition. If impairment arises, then the amount of any impairment is measured based on estimated fair value.

The authoritative guidance on property, plant, and equipment also requires that rate-regulated companies recognize an impairment loss when a regulator excludes all or part of a cost from rates, even if the regulator allows the company to earn a return on the remaining costs allowed. The probability of recovery and the recognition of regulatory assets under the criteria of the authoritative guidance on accounting for the effects of certain types of regulation must be assessed on an ongoing basis. At December 31, 2012, GenConn (as a rate regulated entity) did not have any assets that were impaired under this standard.

131

Allowance for Funds Used During Construction (AFUDC)

In accordance with the uniform system of accounts prescribed by the FERC and PURA, GenConn capitalizes AFUDC, which represents the approximate cost of debt and equity devoted to plant under construction and is included in Interest Expense for the portion related to debt and Other Income and Deductions for the portion related to equity in the accompanying Consolidated Statements of Operations.

Contract for Differences

GenConn recovers its costs under two PURA-approved CfD agreements which are cost of service based and settle on a monthly basis. GenConn has signed CfDs for both facilities with CL&P both with terms of 30 years beginning upon the operations of each plant. Under the terms of the CfD, CL&P will either pay GenConn Devon and GenConn Middletown for the under-recovery or will be reimbursed by those entities for the over-recovery of revenues based on their participation in the ISO-NE markets.

These contracts are accounted for on an accrual basis. Under the CfDs, GenConn agrees that the PURA will determine its cost-of service rate in accordance with the related decisions. Also under the CfD, GenConn agrees to have the units participate and to bid all of the units in ISO-NE Markets as directed by the PURA.

Long-Term Debt

GenConn obtained project financing from a consortium of banks on April 24, 2009 that made $243 million available for construction and related activities, and $48 million for a working capital facility (collectively, the "Project Financing"). The working capital facility also permits the issuance of letters of credit. The interest rate on the Project Financing is equal to either the Base Rate or Eurodollar Rate plus the Applicable Margin, as each is defined in the related agreements. The effective interest rate as of December 31, 2012 was 4.03%.

The availability under the working capital facility was reduced to $30 million on December 29, 2011 (90 days after the GenConn Middletown completion date). On March 22, 2012, the working capital facility was increased to $35 million. As of December 31, 2012, there were no borrowings under the working capital facility and there were letters of credit outstanding totaling $11.1 million and $22.0 million related to GenConn Devon and GenConn Middletown, respectively.

The maturity date of the Project Financing is April 24, 2016, provided that the working capital facility is paid in full on its maturity date of April 24, 2014. Principal payments are required to be made quarterly on the original $243 million borrowed. Borrowings on the Project Financing are reflected as Long-Term Debt in the accompanying Consolidated Balance Sheet.

Substantially all of the assets of GenConn serve as collateral for the Project Financing. As of December 31, 2012, the carrying value of the Long-Term Debt approximated fair value. Under the Project Financing, GenConn is required to comply with certain covenants including the requirement to maintain a historical debt service coverage ratio (as defined) of at least 1.1 to 1.0. As of December 31, 2012, GenConn's historical debt service coverage ratio was 2.59. In addition, GenConn is subject to a dividend payment test whereby quarterly dividends are permitted if the debt service coverage ratio for the last twelve months and the next twelve months are at least 1.3 to 1.0. As of December 31, 2012, GenConn had met all of its debt service coverage ratios to date. Information regarding repayments is set forth below (in 000's):

During the twelve months ended December 31st:	Total
2013	$	8,100
2014	8,100
2015	8,100
2016	204,095
	$	228,395

GenConn filed an application with PURA on June 28, 2012, seeking approval to refinance its long-term debt. In the application, GenConn requested the flexibility to execute a refinancing in order to access credit and/or bank markets when market conditions are deemed favorable by issuing notes in the private placement market or executing a bank loan in the bank market or a combination of notes and bank debt during the financing period, which would end on April 24, 2016, the maturity of the existing project financing. The working capital facility matures on April 24, 2014. PURA issued a final decision on August 13, 2012 granting approval of GenConn's application.

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Unamortized Debt Expense

GCE and GenConn deferred debt issuance costs incurred on the bank and project financings, which are being amortized over the term of the related debt and allocated evenly to both GenConn Devon and GenConn Middletown. The amortization and associated unamortized debt issuance cost balances are accounted for at GenConn Devon and GenConn Middletown as such amounts are recovered in rates. The unamortized debt issuance costs are included in Unamortized Debt Expense in the accompanying Consolidated Balance Sheet as of December 31, 2012.

Related Party Transactions

There are no employees of GCE or any of its subsidiaries. UI and NRG (the Partners) are paid, through GCE, for services to GenConn which include administration, plant operations, construction and energy management pursuant to contractual arrangements. As of December 31, 2012, amounts owed to the Partners for services of $0.8 million are included in Accounts Payable in the accompanying Consolidated Balance Sheet. For the year ended December 31, 2012, amounts paid to the Partners for services was $9.3 million.

For the year ended December 31, 2012, amounts paid to the Partners, through GCE, for interest was zero.

For the year ended December 31, 2012, interest expense on the related party notes from the Partners was zero and is included in the accompanying Consolidated Statements of Operations.

GenConn made distributions, through GCE, to the Partners of $39.3 million for the year ended December 31, 2012.

GenConn returned a portion of the Partner's investment, through GCE, of $3.7 million for the year ended December 31, 2012.

GenConn Devon and GenConn Middletown lease both facilities and land from Devon Power LLC (Devon Power) and Middletown Power LLC (Middletown Power), respectively, both of which are subsidiaries of NRG. See the Lease Obligations section for additional details.

Income Taxes

GCE is not subject to federal or state income taxes. UI and NRG are required to report on their federal and, as required, state income tax return its share of GCE's income, gains, losses, deductions and credits. Accordingly, there is no provision for income taxes in the accompanying consolidated financial statements.

Derivatives

In connection with the Project Financing, in April 2009, GenConn entered into an interest rate swap agreement with each of the five of the banks participating in the syndication to reduce the risk of unfavorable changes in variable interest rates related to a portion of the Project Financing. The swaps have the effect of converting variable rate payments to fixed rate payments on approximately $42 million to $121 million principal amount outstanding of Project Financing debt through December 31, 2014 with quarterly settlements that began on March 31, 2010. Any income generated from the agreement is expected to be credited to customers and any expense generated is expected to be recovered from customers through PURA-approved revenue requirements. GenConn is accounting for the interest rate swap agreement as an economic hedge. As such, GenConn established a regulatory liability or asset for the mark-to-market adjustments related to the interest rate swaps. As of December 31, 2012, $6.5 million was recorded as a Derivative Liability offset by a Regulatory Asset in the accompanying Consolidated Balance Sheet. The fair value hierarchy levels are Level 1 (quoted prices in active markets for identical assets and liabilities), Level 2 (significant other observable inputs), and Level 3 (significant unobservable inputs).

GenConn utilizes an income approach valuation technique to value the interest rate swap derivatives measured and reported at fair value. As required by the authoritative guidance on fair value measurements, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The interest rate swaps are valued based on the annual London Interbank Offering Rate (LIBOR) index. GenConn's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. GenConn has determined that the fair value of its interest rate swap derivatives is measured using Level 2 inputs.

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Contingencies

In the ordinary course of business, GCE and its subsidiaries are involved in various proceedings, including legal, tax, regulatory and environmental matters, which require management's assessment to determine the probability of whether a loss will occur and, if probable, an estimate of probable loss. When assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated, GCE accrues a reserve and discloses the reserve and related matter. GCE discloses matters when losses are probable for which an estimate is reasonably possible. Subsequent analysis is performed on a periodic basis to assess the impact of any changes in events or circumstances and any resulting need to adjust existing reserves or record additional reserves.

In April 2011, a circuit interconnecting two of the four units at the GenConn Middletown facility to the gas insulated substation failed. The circuit was replaced; however, it continued to exhibit persistent partial discharge and was monitored via periodic testing. In March 2012, GenConn filed a lawsuit seeking damages against the electrical contractor responsible for the design and installation of the defective circuit. Please refer to Deferred Project Costs included in the Regulatory Accounting table for further information for costs incurred as of December 31, 2012 regarding the defective equipment.

On July 13, 2012, two of the four units at the GenConn Middletown facility were taken out of service due to further partial discharge testing results on the related cable and terminal interconnection equipment within the circuit to address operational and safety concerns. On August 8, 2012, the remaining two units at the GenConn Middletown facility were taken out of service due to similar partial discharge test results. GenConn hired another electrical contractor to undertake the replacement of the defective equipment. The defective equipment was replaced during the second half of 2012 and all four units were returned to service on January 19, 2013. As a result of the outage, GenConn incurred penalties for not achieving availability in the LFRM in the amount of $0.1 million during the twelve months ended December 31, 2012. Penalties incurred from January 1 through January 19, 2013 were minor. The penalties incurred are included in the Operating Expenses in the accompanying Consolidated Statements of Operations. The amount is net of the amount of coverage GenConn obtained for the unavailable capacity.

In March 2012, the former electrical contractor responsible for the failed installation filed a mechanic's lien on the GenConn Middletown project in the amount of $1.8 million. In order to comply with certain covenants under the project financing, GenConn Middletown was required to post a surety bond for the total amount which discharged the lien. As of December 31, 2012, GenConn Middletown recorded $0.4 million as a regulatory asset and accrued $0.7 million, which was included in Property, Plant and Equipment, related to the $1.8 million claim. GenConn Middletown is currently awaiting a response from the former electrical contractor for detailed support for the remaining $0.7 million claim. Until a response is received, GenConn Middletown cannot presently assess the merit of this claim. To the extent that GenConn is required to satisfy any of the claims, recovery of such costs would be expected through future rates.

In July 2011, GenConn Devon and the former general contractor responsible for the construction of the GenConn Devon facility entered into a settlement agreement with respect to change order requests and delay and impact claims and pursuant to which GenConn Devon paid a settlement amount of $10.5 million upon satisfaction of certain conditions performed by the former general contractor. In April 2011, GenConn Middletown settled a claim by the former general contractor for work at the GenConn Middletown facility and entered into a settlement agreement pursuant to which GenConn Middletown paid a settlement amount of $3.0 million which is included in Property, Plant and Equipment in the accompanying Consolidated Balance Sheet. PURA has approved GenConn's recovery of the associated costs.

In December 2010, GenConn Middletown was required to provide a $1.4 million Letter of Credit (LC) to the owner of the transmission facilities to which GenConn Middletown connects. The LC is related to remaining work on the transmission facilities. Correspondingly, GenConn Middletown has a $3.5 million performance bond from the contractor required to complete the remaining work. In April 2011, GenConn Middletown was required to provide an additional $0.9 million LC for additional work on the same transmission facilities. In February 2013, the $0.9 million LC was reduced to $0.05 million and the $3.5 million performance bond from the contractor was reduced to $0.1 million as a significant portion of the work on the transmission facilities has been completed. The $1.4 million LC was released by the owner of the transmission facilities during the first quarter of 2013.

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Lease Obligations

Operating leases with Devon Power and Middletown Power consist primarily of leases of facilities and land for both GenConn Devon and GenConn Middletown. For the year ended December 31, 2012, operating lease expense for GenConn Devon and GenConn Middletown was $0.6 million. The future minimum lease payments under these operating leases are estimated to be as follows (in 000's):

Twelve months ended December 31st:	GenConn Devon		GenConn Middletown
2013	$	579	$	668
2014	579		668
2015	579		668
2016	579		668
2017	579		668
2018 and thereafter	12,980		15,643
	$	15,875	$	18,983

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EXHIBIT INDEX

Number	Description	Method of Filing
2.1	Purchase and Sale Agreement, dated as of May 5, 2014, by and between NRG Gas Development Company, LLC and NRG Yield Operating LLC.	Incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on May 9, 2014.
2.2	Purchase and Sale Agreement, dated as of May 5, 2014, by and between NRG Solar PV LLC and NRG Yield Operating LLC.	Incorporated herein by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K filed on May 9, 2014.
2.3	Purchase and Sale Agreement, dated as of May 5, 2014, by and between NRG Solar PV LLC and NRG Yield Operating LLC.	Incorporated herein by reference to Exhibit 2.3 to the Company’s Current Report on Form 8-K filed on May 9, 2014.
2.4	Purchase and Sale Agreement, dated June 3, 2014, by and among NRG Yield, Inc., NRG Yield Operating LLC, Terra-Gen Finance Company, LLC, NTD AWAM Holdings, LLC, CHIPS Alta Wind X Holding Company, LLC and CHIPS Alta Wind XI Holding Company, LLC.	Incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 9, 2014.
2.5	Purchase and Sale Agreement, dated as of November 4, 2014, by and between NRG Wind LLC and NRG Yield Operating LLC.	Incorporated herein by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed on November 7, 2014.
2.6	Purchase and Sale Agreement, dated as of November 4, 2014, by and between NRG Arroyo Nogales LLC and NRG Yield Operating LLC.	Incorporated herein by reference to Exhibit 2.2 to the Company's Current Report on Form 8-K filed on November 7, 2014.
3.1	Amended and Restated Certificate of Incorporation of NRG Yield, Inc., dated as of July 22, 2013.	Incorporated herein by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed on July 26, 2013.
3.2	Second Amended and Restated Bylaws of NRG Yield, Inc., dated as of July 22, 2013.	Incorporated herein by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K filed on July 26, 2013.
4.1	Second Amended and Restated Limited Liability Company Agreement of NRG Yield LLC, dated as of July 22, 2013.	Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on July 26, 2013.
4.2	Indenture, dated February 11, 2014, among NRG Yield, Inc., the Guarantors and Wilmington Trust, National Association, as trustee, re: the Company’s 3.50% Convertible Senior Notes due 2019.	Incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on February 11, 2014.
4.3	Form of 3.50% Convertible Senior Note due 2019.	Incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on February 11, 2014.
4.4	Indenture, dated August 5, 2014, among NRG Yield Operating LLC, the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on August 5, 2014.
4.5	Form of 5.375% Senior Note due 2024.	Incorporated herein by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on August 5, 2014.
4.6	Registration Rights Agreement, dated August 5, 2014, among NRG Yield Operating LLC, the guarantors named therein and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the initial purchasers.	Incorporated herein by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K filed on August 5, 2014.
4.7	Supplemental Indenture, dated as of November 7, 2014, among NRG Yield Operating LLC, the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on November 13, 2014.
10.1	Registration Rights Agreement, dated as of July 22, 2013, by and between NRG Energy, Inc. and NRG Yield, Inc.	Incorporated herein by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on July 26, 2013.
10.2	Exchange Agreement, dated as of July 22, 2013, by and among NRG Energy, Inc., NRG Yield, Inc. and NRG Yield LLC.	Incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed on July 26, 2013.

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10.3	Right of First Offer Agreement, dated as of July 22, 2013, by and between NRG Energy, Inc. and NRG Yield, Inc.	Incorporated herein by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed on July 26, 2013.
10.4	Management Services Agreement, dated as of July 22, 2013, by and between NRG Energy, Inc., NRG Yield, Inc., NRG Yield LLC and NRG Yield Operating LLC.	Incorporated herein by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed on July 26, 2013.
10.5	Trademark License Agreement, dated as of July 22, 2013, by and between NRG Energy, Inc. and NRG Yield, Inc.	Incorporated herein by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed on July 26, 2013.
10.6	Loan Guarantee Agreement, dated as of September 30, 2011, by and among High Plains Ranch II, LLC, as borrower, the U.S. Department of Energy, as guarantor, and the U.S. Department of Energy, as loan servicer.	Incorporated herein by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
10.7	Operation and Maintenance Agreement, dated as of January 31, 2011, by and among Avenal Solar Holdings LLC and NRG Energy Services LLC.	Incorporated herein by reference to Exhibit 10.11 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
10.8	Asset Management Agreement, dated as of August 30, 2012, by and among NRG Solar Avra Valley LLC and NRG Solar Asset Management LLC.	Incorporated herein by reference to Exhibit 10.12 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
10.9	Operation and Maintenance Agreement, dated as of August 1, 2012, by and among NRG Energy Services LLC and NRG Solar Borrego I LLC.	Incorporated herein by reference to Exhibit 10.13 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
10.10	Asset Management Agreement, dated as of March 15, 2012, by and among NRG Solar Alpine LLC and NRG Solar Asset Management LLC.	Incorporated herein by reference to Exhibit 10.14 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
10.11	Operation and Maintenance Agreement, dated as of September 30, 2011, by and among NRG Energy Services LLC and High Plains Ranch II, LLC.	Incorporated herein by reference to Exhibit 10.15 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
10.12	Project Administration Agreement, dated as of August 16, 2010, by and among South Trent Wind LLC and NRG Texas Power LLC.	Incorporated herein by reference to Exhibit 10.16 to the Company's Registration Statement on Form S-1/A filed on March 15, 2013.
10.13	Operation and Maintenance Agreement, dated as of April 24, 2009, by and among GenConn Devon LLC and Devon Power LLC.	Incorporated herein by reference to Exhibit 10.15 to the Company's Registration Statement on Form S-1 filed on June 6, 2013.
10.14	Operation and Maintenance Agreement, dated as of April 24, 2009, by and among GenConn Middletown LLC and Middletown Power LLC.	Incorporated herein by reference to Exhibit 10.16 to the Company's Registration Statement on Form S-1 filed on June 6, 2013.
10.15	Administrative Services Agreement, dated as of April 2, 2009, by and among GenOn Energy Services, LLC (formerly Mirant Services, LLC) and NRG Marsh Landing, LLC (formerly Mirant Marsh Landing, LLC.	Incorporated herein by reference to Exhibit 10.17 to the Company's Registration Statement on Form S-1 filed on June 6, 2013.
10.16†	NRG Yield, Inc. 2013 Equity Incentive Plan.	Incorporated herein by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K filed on July 26, 2013.
10.17	Form of Indemnification Agreement.	Incorporated herein by reference to Exhibit 10.20 to the Company's Registration Statement on Form S-1/A filed on June 21, 2013.
10.18	Amended and Restated Credit Agreement, dated April 25, 2014, by and among NRG Yield Operating LLC, NRG Yield LLC, Royal Bank of Canada, as Administrative Agent, the lenders party thereto, Royal Bank of Canada, Goldman Sachs Bank USA and Bank of America, N.A., as L/C Issuers and RBC Capital Markets as Sole Left Lead Arranger and Sole Left Lead Book Runner.	Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 28, 2014.
10.19	Credit Agreement, dated as of August 23, 2011, among NRG West Holdings LLC, ING Capital LLC, Union Bank, N.A., Mizuho Corporate Bank, Ltd., RBS Securities Inc., Credit Agricole Corporate and Investment Bank, and each of lenders and issuing banks thereto.*	Incorporated herein by reference to Exhibit 10.2 to the Company's quarterly report on Form 10-Q filed on August 7, 2014.
10.20	Amendment No. 1 dated October 7, 2011, by and between NRG West Holdings LLC and Credit Agricole Corporate and Investment Bank.	Incorporated herein by reference to Exhibit 10.3 to the Company's quarterly report on Form 10-Q filed on August 7, 2014.
10.21	Amendment No. 2 dated February 29, 2012, by and between NRG West Holdings LLC and Credit Agricole Corporate and Investment Bank.	Incorporated herein by reference to Exhibit 10.4 to the Company's quarterly report on Form 10-Q filed on August 7, 2014.

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10.22	Amended and Restated Credit Agreement, dated July 17, 2014, by and among NRG Marsh Landing LLC, The Royal Bank of Scotland Plc, Deutsche Bank Trust Company Americas and the lenders party thereto.	Incorporated herein by reference to Exhibit 10.5 to the Company's quarterly report on Form 10-Q filed on August 7, 2014.
10.23	First Amendment to the Credit Agreement and Collateral Agency and Intercreditor Agreement, dated July 17, 2014, by and among NRG Marsh Landing LLC, The Royal Bank of Scotland Plc, Deutsche Bank Trust Company Americas and the lenders party thereto.	Incorporated herein by reference to Exhibit 10.6 to the Company's quarterly report on Form 10-Q filed on August 7, 2014.
21.1	Subsidiaries of NRG Yield, Inc.	Filed herewith.
23.1	Consent of KPMG LLP.	Filed herewith.
23.2	Consent of PricewaterhouseCoopers LLP.	Filed herewith.
31.1	Rule 13a-14(a)/15d-14(a) certification of David Crane.	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 Ronald B. Stark.	Filed herewith.
32	Section 1350 Certification.	Filed 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.

†	Indicates exhibits that constitute compensatory plans or arrangements.
*	This filing excludes schedules pursuant to Item 601(b)(2) of Regulation S-K, which the registrant agrees to furnish supplementary to the Securities and Exchange Commission upon request by the Commission.

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SIGNATURES

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

	NRG YIELD, INC. (Registrant)
	/s/ DAVID CRANE
	David Crane
	Chief Executive Officer (Principal Executive Officer)
Date: February 27, 2015

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POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints David R. Hill and Brian E. Curci, each or any of them, such person's true and lawful attorney-in-fact and agent with full power of substitution and resubstitution for such person and in such person's name, place and stead, in any and all capacities, to sign any and all amendments to this report on Form 10-K, and to file the same with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing necessary or desirable to be done in and about the premises, as fully to all intents and purposes as such person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on February 27, 2015.

Signature	Title	Date
/s/ DAVID CRANE	President, Chief Executive Officer and	February 27, 2015
David Crane	Chairman of the Board (Principal Executive Officer)
/s/ KIRKLAND B. ANDREWS	Chief Financial Officer and Director	February 27, 2015
Kirkland B. Andrews	(Principal Financial Officer)
/s/ RONALD B. STARK	Chief Accounting Officer	February 27, 2015
Ronald B. Stark	(Principal Accounting Officer)
/s/ JOHN CHLEBOWSKI	Director	February 27, 2015
John Chlebowski
/s/ BRIAN FORD	Director	February 27, 2015
Brian Ford
/s/ MAURICIO GUTIERREZ	Director	February 27, 2015
Mauricio Gutierrez
/s/ FERRELL MCCLEAN	Director	February 27, 2015
Ferrell McClean
/s/ CHRISTOPHER SOTOS	Director	February 27, 2015
Christopher Sotos

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