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, 2012.	
 	 	 	
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 No. 001-15891
     NRG Energy, Inc.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of incorporation or organization)	 	41-1724239
(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, 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.     o
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 $5,522,415,032 based on the closing sale price of $17.36 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 February 21, 2013	
Common Stock, par value $0.01 per share	 	323,165,879	
Documents Incorporated by Reference:
Portions of the Registrant's definitive Proxy Statement relating to its 2013 Annual Meeting of Stockholders
are incorporated by reference into Part III of this Annual Report on Form 10-K

 	 	 	 	 	

1

TABLE OF CONTENTS

 	GLOSSARY OF TERMS	2	
PART I	6	
 	Item 1 — Business	7	
 	Item 1A — Risk Factors Related to NRG Energy,  Inc. 	32	
 	Item 1B — Unresolved Staff Comments	46	
 	Item 2 — Properties	47	
 	Item 3 — Legal Proceedings	50	
 	Item 4 — Mine Safety Disclosures	56	
PART II	56	
 	Item 5 — Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	57	
 	Item 6 — Selected Financial Data	59	
 	Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations	60	
 	Item 7A — Quantitative and Qualitative Disclosures About Market Risk	98	
 	Item 8 — Financial Statements and Supplementary Data	102	
 	Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	103	
 	Item 9A — Controls and Procedures	103	
 	Item 9B — Other Information	103	
PART III	103	
 	Item 10 — Directors, Executive Officers and Corporate Governance	104	
 	Item 11 — Executive Compensation	107	
 	Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	108	
 	Item 13 — Certain Relationships and Related Transactions, and Director Independence	108	
 	Item 14 — Principal Accounting Fees and Services	108	
PART IV	108	
 	Item 15 — Exhibits, Financial Statement Schedules	109	
EXHIBIT INDEX	212	

2

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

2012 Form 10-K	 	NRG's Annual Report on Form 10-K for the year ended December 31, 2012	
316(b) Rule	 	Regulations promulgated by the EPA to implement a section of the Clean Water Act regulating cooling water intake structures	
AB32	 	Assembly Bill 32 — California Global Warming Solutions Act of 2006	
ARO	 	Asset Retirement Obligation	
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	
AZNMSN	 	Arizona, New Mexico and Southern Nevada	
Baseload	 	Units expected to satisfy minimum baseload requirements of the system and produce electricity at an essentially constant rate and run continuously
	
BACT	 	Best Available Control Technology	
BRA	 	Base Residual Auction	
BTU	 	British Thermal Unit	
CAA	 	Clean Air Act	
CAIR	 	Clean Air Interstate Rule	
CAISO	 	California Independent System Operator	
Capital Allocation Program	 	NRG's plan of allocating capital between debt reduction, reinvestment in the business, share repurchases and shareholder dividends	
CCUS	 	Carbon capture, utilization and storage project	
CDWR	 	California Department of Water Resources	
C&I	 	Commercial, industrial and governmental/institutional	
CFTC	 	U.S. Commodity Futures Trading Commission	
CO2	 	Carbon dioxide	
CPS	 	CPS Energy	
CS	 	Credit Suisse Group	
CSAPR	 	Cross-State Air Pollution Rule	
CSRA	 	Credit Sleeve Reimbursement Agreement with Merrill Lynch in connection with acquisition of Reliant Energy, as hereinafter defined	
CWA	 	Clean Water Act	
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	
DNREC	 	Delaware Department of Natural Resources and Environmental Control	
DSU	 	Deferred Stock Unit	
EIS	 	Environmental Impact Statement	
Energy Plus	 	Energy Plus Holdings LLC	
EPA	 	United States Environmental Protection Agency	
EPC	 	Engineering, Procurement and Construction	
EPE	 	El Paso Electric Company	
ERCOT	 	Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas	
ESPP	 	Employee Stock Purchase Plan	
EWG	 	Exempt Wholesale Generator	
Exchange Act	 	The Securities Exchange Act of 1934, as amended	
FASB	 	Financial Accounting Standards Board	

3

 	
 	 	 	
FCM	 	Forward Capacity Market	
FERC	 	Federal Energy Regulatory Commission	
FFB	 	Federal Financing Bank	
FPA	 	Federal Power Act	
FRCC	 	Florida Reliability Coordinating Council	
Fresh Start	 	Reporting requirements as defined by ASC-852, Reorganizations	
GenOn Americas Generation	 	GenOn Americas Generation, LLC	
GenOn Americas Generation Senior Notes	 	GenOn Americas Generation's $850 million outstanding unsecured senior notes consisting of $450 million of 8.5% senior notes due 2021 and $400 million of 9.125% senior notes due 2031	
GenOn	 	GenOn Energy, Inc.	
GenOn Mid-Atlantic	 	GenOn Mid-Atlantic, LLC and, except where the context indicates otherwise, its subsidiaries, which include the coal generation units at two generating facilities under operating leases	
GenOn Senior Notes	 	GenOn's $2.5 billion outstanding unsecured senior notes consisting of $575 million of 7.625% senior notes due 2014, $725 million of 7.875% senior notes due 2017, $675 million of 9.5% senior notes due 2018, and $550 million of 9.875% senior notes due 2020	
GenOn Holdings	 	GenOn Energy Holdings, Inc.	
GHG	 	Greenhouse Gases	
Green Mountain Energy	 	Green Mountain Energy Company	
GWh	 	Gigawatt hour	
HAPs	 	Hazardous air pollutants	
Heat Rate	 	A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWh's generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh	
Intermediate	 	Units expected to satisfy system requirements that are greater than baseload and less than peaking	
ISO	 	Independent System Operator, also referred to as Regional Transmission Organizations, or RTO	
ISO-NE	 	ISO New England Inc.	
kWh	 	Kilowatt-hours	
LFRM	 	Locational Forward Reserve Market	
LIBOR	 	London Inter-Bank Offered Rate	
LTIPs	 	Collectively, the NRG Long-Term Incentive Plan and the NRG GenOn Long-Term Incentive Plan	
Marsh Landing	 	GenOn Marsh Landing, LLC	
Mass	 	Residential and small business	
MATS	 	Mercury and Air Toxics Standards promulgated by the EPA	
MDE	 	Maryland Department of the Environment	
Merger	 	The merger completed on December 14, 2012 by NRG and GenOn pursuant to the Merger Agreement	
Merger Agreement	 	The agreement by and among NRG, GenOn Energy, Inc. and Plus Merger Corporation, dated as of July 20, 2012	
Merit Order	 	A term used for the ranking of power stations in order of ascending marginal cost	
MISO	 	Midwest Independent Transmission System Operator, Inc.	
MMBtu	 	Million British Thermal Units	
MOPR	 	Minimum Offer Price Rule	
MSU	 	Market Stock Unit	
MW	 	Megawatts	
MWh	 	Saleable megawatt hours net of internal/parasitic load megawatt-hours	
MWt	 	Megawatts Thermal Equivalent	

4

 	
 	 	 	
NAAQS	 	National Ambient Air Quality Standards	
NERC	 	North American Electric Reliability Corporation	
Net Capacity Factor	 	The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period. The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation	
Net Exposure	 	Counterparty credit exposure to NRG, net of collateral	
Net Generation	 	The net amount of electricity produced, expressed in kWhs or MWhs, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation.	
NINA	 	Nuclear Innovation North America LLC	
NJDEP	 	New Jersey Department of Environmental Protection	
NOx	 	Nitrogen oxide	
NOL	 	Net Operating Loss	
NPNS	 	Normal Purchase Normal Sale	
NQSO	 	Non-Qualified Stock Option	
NRC	 	U.S. Nuclear Regulatory Commission	
NRG GenOn LTIP	 	NRG 2010 Stock Plan for GenOn Employees (formerly the GenOn Energy, Inc. 2010 Omnibus Incentive Plan, which was assumed by NRG in connection with the Merger)	
NRG LTIP	 	NRG Long-Term Incentive Plan	
NSPS	 	New Source Performance Standards	
NSR	 	New Source Review	
NYDEC	 	New York State Department of Environmental Conservation	
NYISO	 	New York Independent System Operator	
NYSPSC	 	New York State Public Service Commission	
OCI	 	Other comprehensive income	
Peaking	 	Units expected to satisfy demand requirements during the periods of greatest or peak load on the system	
PG&E	 	Pacific Gas & Electric	
Phase II 316(b) Rule	 	Certain regulations promulgated by the EPA to implement a section of the Clean Water Act regulating cooling water intake structures	
PJM	 	PJM Interconnection, LLC	
PJM market	 	The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia	
PM 2.5	 	Particulate matter particles with a diameter of 2.5 micrometers or less	
PPA	 	Power Purchase Agreement	
PSD	 	Prevention of Significant Deterioration	
PU	 	Performance Unit	
PUCT	 	Public Utility Commission of Texas	
PUHCA of 2005	 	Public Utility Holding Company Act of 2005	
PURPA	 	Public Utility Regulatory Policies Act of 1978	
QF	 	Qualifying Facility under PURPA	
QSE	 	Qualified Scheduling Entities	
RCRA	 	Resource Conservation and Recovery Act of 1976	
Reliant Energy	 	NRG's retail business in Texas purchased on May 1, 2009	
Repowering	 	Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility, not only to achieve a substantial emissions reduction, but also to increase facility capacity, and improve system efficiency	
REP	 	Retail Electric Provider	
RERH	 	RERH Holding, LLC and its subsidiaries	

5

 	
 	 	 	
Retail Business	 	Retail energy companies, collectively, Reliant Energy, Green Mountain Energy and Energy Plus, which are wholly owned subsidiaries of NRG	
Revolving Credit Facility	 	The Company's $2.3 billion revolving credit facility due 2016, a component of the Senior Credit Facility	
RGGI	 	Regional Greenhouse Gas Initiative	
RMR	 	Reliability Must-Run	
RPM	 	Reliability Pricing Model	
RSU	 	Restricted Stock Unit	
Schkopau	 	Kraftwerk Schkopau Betriebsgesellschaft mbH	
SEC	 	United States Securities and Exchange Commission	
Securities Act	 	The Securities Act of 1933, as amended	
Senior Credit Facility	 	NRG's senior secured facility, comprised of the $1.6 billion Term Loan Facility and the $2.3 billion Revolving Credit Facility	
SIFMA	 	Securities Industry and Financial Markets Association	
Senior Notes	 	The Company's $5.9 billion outstanding unsecured senior notes consisting of, $1.2 billion of 7.625% senior notes due 2018, $700 million of 8.5% senior notes due 2019, $800 million of 7.625% senior notes due 2019, $1.1 billion of 8.25% senior notes due 2020, $1.1 billion of 7.875% senior notes due 2021, and $990 million of 6.625% senior notes due 2023	
SERC	 	Southeastern Electric Reliability Council/Entergy	
SO2	 	Sulfur dioxide	
STP	 	South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% Interest	
STPNOC	 	South Texas Project Nuclear Operating Company	
TANE	 	Toshiba America Nuclear Energy Corporation	
TANE Facility	 	NINA's $500 million credit facility with TANE	
TEPCO	 	The Tokyo Electric Power Company of Japan, Inc.	
Term Loan Facility	 	The Company's $1.6 billion term loan facility due 2018, a component of the Senior Credit Facility	
Texas Genco	 	Texas Genco LLC, now referred to as the Company's Texas Region	
Tonnes	 	Metric tonnes, which are units of mass or weight in the metric system each equal to 2,205lbs and are the global measurement for GHG	
TSR	 	Total Shareholder Return	
TWh	 	Terawatt hour	
U.S.	 	United States of America	
U.S. DOE	 	United States Department of Energy	
U.S. GAAP	 	Accounting principles generally accepted in the United States	
Utility Scale Solar	 	Solar power projects, typically 20 MW or greater in size, that are interconnected into the transmission or distribution grid to sell power at a wholesale level	
VaR	 	Value at Risk	
VIE	 	Variable Interest Entity	
WCP	 	WCP (Generation) Holdings, Inc.	
WECC	 	Western Electricity Coordinating Council	

6

PART I
Item 1 — Business
General
NRG Energy, Inc., or NRG or the Company, is a competitive power and energy company that aspires to be a leader in the way the industry and consumers think about, use, produce and deliver energy and energy services in major competitive power markets in the United States. At its core, NRG is a wholesale power generator engaged in the ownership and operation of power generation facilities; the trading of energy, capacity and related products; and the transacting in and trading of fuel and transportation services. Second, while leveraging its core wholesale power business, NRG is a retail energy company engaged in the supply of energy, services, and innovative, sustainable products to retail customers in competitive markets through multiple channels and brands like Reliant Energy, Green Mountain Energy, and Energy Plus (collectively, the Retail Business). Finally, NRG is a clean energy leader and is focused on the deployment and commercialization of potentially disruptive technologies, like electric vehicles, Distributed Solar and smart meter technology, which have the potential to change the nature of the power supply industry.
Wholesale Power Generation
NRG's generation facilities are primarily located in the United States and comprise generation facilities across the merit order. The sale of capacity and power from baseload and intermediate generation facilities accounts for a majority of the Company's generation revenues. In addition, NRG's generation portfolio provides the Company with opportunities to capture additional revenues by selling power during periods of peak demand, offering capacity or similar products, and providing ancillary services to support system reliability.
Retail
NRG's Retail Business arranges for the transmission and delivery of energy-related products to customers, bills customers, collects payments for products sold, and maintains call centers to provide customer service. The Retail Business sells products that range from system power to bundled products, which combine system power with protection products, energy efficiency and renewable energy solutions, or other value added products and services, including customer rewards offered through exclusive loyalty and affinity program partnerships. Based on metered locations, as of December 31, 2012, NRG's Retail Business served approximately 2.2 million residential, small business, commercial and industrial customers.
Alternative Energy
NRG's investment in, and development of, new technologies is focused on identifying significant commercial opportunities and creating a comparative advantage for the Company. The Company's development and investment initiatives are primarily focused in the areas of Distributed Solar, solar thermal and solar photovoltaic, and also include other low-or no-GHG emitting energy generating sources, such as the fueling infrastructure for electric vehicle, or EV, ecosystems.

7

The map below shows the locations of NRG's U.S. power generation facilities as of December 31, 2012, (excluding Distributed Solar), both operating and under construction, as well as the states where NRG operates its Retail Business:

8

The following table summarizes NRG's global generation portfolio as of December 31, 2012, by operating segment, which includes 89 fossil fuel plants, four Utility Scale Solar facilities and four wind farms, as well as Distributed Solar facilities. Also included are three natural gas plants, three Utility Scale Solar facilities and additional Distributed Solar facilities currently under construction, and two Utility Scale Solar facilities partially in-service. All Utility Scale Solar and Distributed Solar facilities are described in megawatts on an alternating current, or AC, basis. MW figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the Company's ownership position excluding capacity from inactive/mothballed units:

 	 	Fossil Fuel, Nuclear, and Renewable	
 	 	(In MW)	
Generation Type	 	Texas	 	East	 	South Central	 	West	 	Other (Thermal)	 	Alter-native Energy	 	Total Domestic	 	Other (Inter-national)	 	Total Global	
Natural gas	 	5,510	
 	 	7,655	
 	 	3,820	
 	 	7,520	
 	 	105	
 	 	—	
 	 	24,610	
 	 	—	
 	 	24,610	
 	
Coal	 	4,195	
 	 	7,585	
 	 	1,495	
 	 	—	
 	 	15	
 	 	—	
 	 	13,290	
 	 	605	
 	 	13,895	
 	
Oil	 	—	
 	 	6,030	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	6,030	
 	 	—	
 	 	6,030	
 	
Nuclear	 	1,175	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	1,175	
 	 	—	
 	 	1,175	
 	
Wind	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	450	
 	 	450	
 	 	—	
 	 	450	
 	
Utility Scale Solar	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	345	
 	 	345	
 	 	—	
 	 	345	
 	
Distributed Solar	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	40	
 	 	40	
 	 	—	
 	 	40	
 	
Total generation capacity	 	10,880	
 	 	21,270	
 	 	5,315	
 	 	7,520	
 	 	120	
 	 	835	
 	 	45,940	
 	 	605	
 	 	46,545	

Under Construction	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas	 	—	
 	 	—	
 	 	—	
 	 	1,270	
 	 	—	
 	 	75	
 	 	1,345	
 	 	—	
 	 	1,345	
 	
Utility Scale Solar   	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	430	
 	 	430	
 	 	—	
 	 	430	
 	
Distributed Solar	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	5	
 	 	5	
 	 	—	
 	 	5	
 	
Total under construction	 	—	
 	 	—	
 	 	—	
 	 	1,270	
 	 	—	
 	 	510	
 	 	1,780	
 	 	—	
 	 	1,780	
 	
In addition, the Company's thermal assets provide steam and chilled water capacity of approximately 1,098 MWt through its district energy business.
GenOn Acquisition
On December 14, 2012, NRG completed the previously announced Merger with GenOn in accordance with the Merger Agreement, with GenOn continuing as a wholly-owned subsidiary of NRG.  The Company issued, as consideration for the Merger, 0.1216 shares of NRG common stock for each outstanding share of GenOn, including restricted stock units outstanding, on the acquisition date, totaling 93.9 million shares of NRG common stock, and approximately $1 million in cash for fractional shares. The Merger was accounted for as an acquisition, and NRG was deemed to have acquired GenOn for accounting purposes. Specifically, consolidated financial statements and financial and operational results of NRG include the results of the combined entities from December 15, 2012, unless indicated otherwise.
  GenOn, a generator of wholesale electricity, has baseload, intermediate and peaking power generation facilities using coal, natural gas and oil, totaling approximately 21,440 MW.  The acquisition is expected to enhance stockholder value by, among other things, enabling the combined company to capitalize on the following strategic advantages and opportunities:
 	 	
•	Diversification and Scale - The combined company, which retains the name NRG Energy, Inc., is the largest competitive power generation company in the United States with approximately 45,940 MW of fossil fuel, nuclear, solar and wind capacity across the merit order in major competitive energy markets across the United States, supporting nearly 40 million homes .	
 	 	
•	Synergies - Expected synergies of the combined company include cost and operational efficiency synergies, interest savings through significant deleveraging, reduced liquidity and collateral requirements, and a greater operational scale, which will enhance the combined company's ability to revitalize its generation fleet and optimize portfolio value.	

9

NRG's Business Strategy
The Company's business is focused on: (i) excellence in safety and operating performance of its existing assets; (ii) serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels with a variety of retail energy products and services differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) optimal hedging of coal and nuclear generation and retail load operations, while retaining optionality on the Company's intermediate and peaking facilities; (iv) repowering of power generation assets at premium sites; (v) investment in, and deployment of, alternative energy technologies both in its wholesale and, particularly, in and around its Retail Business and its customers; (vi) pursuing selective acquisitions, joint ventures, divestitures and investments; and (vii) engaging in a proactive capital allocation plan focused on achieving the regular return of and on stockholder capital within the dictates of prudent balance sheet management.
The Company believes that the American energy industry is going to be increasingly impacted by the long-term societal trend towards sustainability which is both generational and irreversible. Moreover, the information technology-driven revolution which has enabled greater and easier personal choice in other sectors of the consumer economy will do the same in the American energy sector over the years to come. As a result, energy consumers will have increasing personal control over whom they buy their energy from, how that energy is generated and used and what environmental impact these individual choices will have. The Company's initiatives in this area of future growth are focused on: (i) renewables, with a concentration in solar development; (ii) electric vehicle ecosystems; (iii) customer-facing energy products and services, including smart energy services that give consumers individual energy insights, choices and convenience, a variety of renewable and energy efficiency products, and numerous loyalty and affinity options and tailored product and service bundles sold through unique retail sales channels; and (iv) construction of other forms of on-site clean power generation. The Company's advances in each of these areas are driven by select acquisitions, joint ventures, and investments that are more fully described in Item 1,  Business - New and On-going Company Initiatives and Development Projects.
In summary, NRG's business strategy is intended to maximize stockholder value through the production and sale of safe, reliable and affordable power to its customers in the markets served by the Company, while aggressively positioning the Company to meet the market's increasing demand for sustainable and low carbon energy solutions. This strategy is designed to enhance the Company's core business of competitive power generation and mitigate the risk of declining power prices. The Company expects to become a leading provider of sustainable energy solutions that promotes national energy security, while utilizing the Company's Retail Business to complement and advance both initiatives.
Competition
NRG competes in wholesale power generation, deregulated retail energy services and in the development of renewable and conventional energy resources. The Retail Business competes with national and international companies that operate in multiple geographic areas, as well as numerous companies that are regional or local in nature, and other competitors, typically incumbent retail electric providers, which have the advantage of long-standing relationships with customers.
Wholesale Power Generation
Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. NRG competes on the basis of the location of its plants and ownership of portfolios of plants in various regions, which increases the stability and reliability of its energy revenues. Wholesale power generation is a regional business that is currently highly fragmented and diverse in terms of industry structure. As such, there is a wide variation in terms of the capabilities, resources, nature and identity of the companies NRG competes with depending on the market. Competitors include regulated utilities, other independent power producers, and power marketers or trading companies, including those owned by financial institutions, municipalities and cooperatives.
Retail
The restructured electricity markets across the nation provide an intensely competitive landscape for energy providers to sell products and services to all customer segments (residential, small and mid-market businesses, governments and other public institutions). The markets in which the Company competes include, but are not limited to the following states: Connecticut, Delaware, Illinois, Maryland, Massachusetts, New Jersey, New York, Pennsylvania, Ohio, Oregon and Texas, as well as the District of Columbia. The ERCOT market in Texas is NRG's primary market and constitutes both the largest number of customers and a substantial concentration of the Company's retail gross profits.
Retail customers make purchase decisions based on a variety of factors, including price, customer service, brand image, product choices, bundles or value-added features. Customers purchase products through a variety of sales channels including direct sales force, call centers, websites, brokers and brick-and-mortar stores.

10

Development
NRG continuously evaluates opportunities for development of new generation, on both a merchant and contracted basis. Merchant development opportunities are more limited due to the economic risks involved in volatile power markets. As such, the majority of NRG's development is in response to Requests For Proposals, or RFPs, for new conventional or renewable generation and/or generating capacity backed by contracts with credit-worthy counterparties.  Many RFPs are solicited by regulated utilities or electric system operators, often to comply with mandated renewable portfolio standards or to achieve an improved reserve margin, which is a measure of a market's available electric power capacity over and above the electric power capacity needed to meet normal peak demand levels.  NRG competes against other power plant developers and manufacturers of solar panel assemblies.  The number and type of competitors vary based on the location, generation type, project size and counterparty specified in the RFP.  Bids are awarded based on price, location of existing generation, prior experience developing generation resources similar to that specified in the RFP, and creditworthiness.
Competitive Strengths
Conventional Wholesale Power Generation
NRG has one of the largest and most diversified power generation portfolios in the United States, with approximately 45,105 MW of fossil fuel and nuclear generation capacity in 345 active generating units at 88 plants as of December 31, 2012. In addition, the Company has one combined cycle and two peaking natural gas plants under construction totaling 1,345 MW. The Company's power generation assets are diversified by fuel-type, dispatch level and region, which helps mitigate the risks associated with fuel price volatility and market demand cycles.
NRG's U.S. baseload and intermediate facilities provide the Company with a significant source of cash flow, while its peaking facilities provide NRG with opportunities to capture upside potential that can arise from time to time during periods of high demand, which typically drives higher energy prices.
Many of NRG's generation assets are located within densely populated areas that tend to have more robust wholesale pricing as a result of relatively favorable local supply-demand balance. NRG now has generation assets located in or near Houston, New York City, Washington D.C., Baltimore, New Jersey, southwestern Connecticut, Pittsburgh, Cleveland, and the Los Angeles, San Diego, and San Francisco metropolitan areas. These facilities are often ideally situated for repowering or the addition of new capacity, because their location and existing infrastructure give them significant advantages over undeveloped sites.
Following the GenOn acquisition, NRG increased its U.S. operating segments generation portfolio by 14,850 MW for the East, 5,390 MW for the West, and 1,200 MW for South Central. The combined company has greater diversity, scale and scope in energy generation and delivery, particularly given the complementary geographic footprints of the combined generating assets, and will have increased diversity from a fuel, geography and revenue (significant increase in capacity revenues) perspective and will be strategically positioned with a significant presence across key regions. In 2012, the combined fleet generated approximately 94 terawatt-hours of electricity.
Retail
Through its Retail Business, in 2012, NRG delivered over 59 TWhs and had approximately 2.2 million customers as of December 31, 2012, making it one of the largest retail energy providers in the United States. NRG's Retail Business offers a broad range of services and value propositions that enable it to attract, retain, and increase the value of the Company's residential, small business and commercial customer relationships. With the largest market share in ERCOT based on volume sales, Reliant Energy is recognized by its exemplary customer service as well as its innovative technology product offerings and home energy services. As one of the nation's leading retail providers of clean energy, Green Mountain Energy is widely recognized as a pioneer in the competitive retail energy market and provides customers an environmentally friendly alternative for their energy supply requirements. Acquired in 2011, Energy Plus primarily enrolls and retains electricity and natural gas customers through exclusive marketing arrangements with leading loyalty program providers and affinity group associations. Through the Retail Business, NRG is able to provide its customers a broad range of energy services and products, including system power, smart energy services, energy efficiency services, protection products, distributed generation, solar and wind products, carbon management and specialty services. The breadth and scope of the Retail Business also creates opportunities for delivering value enhancing energy solutions to customers on a national level. In addition, the GenOn acquisition enables an expanded wholesale-retail model. In an industry that is subject to commodity price volatility, NRG expects that an expanded core generation fleet will enable the combined company to duplicate in multiple markets, principally in the East, the successful integrated wholesale-retail business model that NRG currently operates in the Texas region.

11

Solar and Other Alternative Energy Technologies
NRG is one of the largest solar power developers in the United States, having demonstrated the ability to develop, construct and finance a full range of solar energy solutions for utilities, schools, municipalities, commercial and residential market segments. The Company has 1,270 MW of renewable generation capacity, of which 835 MW is operational and 435 MW is under construction as of December 31, 2012, comprised of ownership interests in four wind farms, nine Utility Scale Solar facilities, and numerous Distributed Solar facilities. Through its relationships with solar equipment providers, NRG is able to deploy diverse solar technologies in both the utility and distributed generating scale projects that create value for the Company while meeting the clean renewable energy requirements of its customers. In addition, NRG is responding to the growing consumer demand for cleaner transportation solutions by building the first privately funded EV charging infrastructure network in select major metropolitan areas.
Reliability of future cash flows and portfolio diversification  
NRG has hedged a portion of its coal and nuclear capacity with decreasing hedge levels through 2016. As a result of the GenOn acquisition, the majority of the acquired generation is mainly concentrated in markets with forward capacity payments that extend three years into the future. These capacity revenues not only enhance the reliability of future cash flows but are not correlated to natural gas prices. NRG also has cooperative load contract obligations in the South Central region expiring over various dates through 2025, which largely hedge the Company's generation in this region. In addition, as of December 31, 2012, the Company had purchased fuel forward under fixed price contracts, with contractually-specified price escalators, for approximately 42% of its expected coal requirement from 2013 to 2017, excluding inventory. The Company has the capacity and intent to enter into additional hedges when market conditions are favorable.
The Company also has the advantage of being able to supply its Retail Business with its own generation, which can reduce the need to sell and buy power from other financial institutions and intermediaries, resulting in lower transaction costs and credit exposures. This combination of generation and retail allows for a reduction in actual and contingent collateral, through offsetting transactions and by reducing the need to hedge the retail power supply through third parties.
The generation and retail combination also provides stability in cash flows, as changes in commodity prices generally have offsetting impacts between the two businesses. The offsetting nature of generation and retail, in relation to changes in market prices, is an integral part of NRG's goal of providing a reliable source of future cash flow for the Company.
When developing renewable and new, conventional power generation facilities, NRG typically secures long-term PPAs, which insulate the Company from commodity market volatility and provide future cash flow stability. These PPAs are typically contracted with high credit quality local utilities and have durations up to 25 years. Such projects include all of the Company's major Utility Scale Solar projects, in operation and under construction, as well as the 550 MW El Segundo Energy Center, or ESEC, and the 720 MW Marsh Landing project which are both currently under construction.
Commercial Operations Overview
NRG seeks to maximize profitability and manage cash flow volatility through the marketing, trading and sale of energy, capacity and ancillary services into spot, intermediate and long-term markets and through the active management and trading of emissions allowances, fuel supplies and transportation-related services. The Company's principal objectives are the realization of the full market value of its asset base, including the capture of its extrinsic value, the management and mitigation of commodity market risk and the reduction of cash flow volatility over time.
NRG enters into power sales and hedging arrangements via a wide range of products and contracts, including PPAs, fuel supply contracts, capacity auctions, natural gas derivative instruments and other financial instruments. In addition, because changes in power prices in the markets where NRG operates are generally correlated to changes in natural gas prices, NRG uses hedging strategies which may include power and natural gas forward sales contracts to manage the commodity price risk primarily associated with the Company's coal and nuclear generation assets. The objective of these hedging strategies is to stabilize the cash flow generated by NRG's portfolio of assets.

12

Coal and Nuclear Operations
The following table summarizes NRG's U.S. Coal and Nuclear capacity and the corresponding revenues and average natural gas prices and positions resulting from Coal and Nuclear hedge agreements extending beyond December 31, 2013, and through 2017:

 	2013	 	2014	 	2015	 	2016	 	2017	 	Annual
Average for
2013-2017	
 	(Dollars in millions unless otherwise stated)	
Net Coal and Nuclear Capacity (MW) (a)	14,368	
 	 	14,155	
 	 	11,843	
 	 	11,282	
 	 	11,282	
 	 	12,586	
 	
Forecasted Coal and Nuclear Capacity (MW) (b)	8,369	
 	 	8,771	
 	 	7,735	
 	 	7,544	
 	 	7,611	
 	 	8,006	
 	
Total Coal and Nuclear Sales (MW) (c)	8,810	
 	 	5,335	
 	 	2,569	
 	 	2,101	
 	 	1,558	
 	 	4,074	
 	
Percentage Coal and Nuclear Capacity Sold Forward  (d)	105	%	 	61	%	 	33	%	 	28	%	 	20	%	 	51	%	
Total Forward Hedged Revenues (e)	$	3,851	
 	 	$	2,332	
 	 	$	1,012	
 	 	$	818	
 	 	$	647	
 	 	 	
Weighted Average Hedged Price ($ per MWh) (e)	$	49.90	
 	 	$	49.91	
 	 	$	44.97	
 	 	$	44.31	
 	 	$	47.38	
 	 	 	
Average Equivalent Natural Gas Price ($ per MMBtu)	$	4.79	
 	 	$	5.09	
 	 	$	4.81	
 	 	$	4.87	
 	 	$	5.32	
 	 	 	
Gas Price Sensitivity Up $0.50/MMBtu on Coal and Nuclear Units	$	66	
 	 	$	211	
 	 	$	293	
 	 	$	290	
 	 	$	311	
 	 	 	
Gas Price Sensitivity Down $0.50/MMBtu on Coal and Nuclear Units	$	—	
 	 	$	(164	)	 	$	(243	)	 	$	(229	)	 	$	(256	)	 	 	
Heat Rate Sensitivity Up 1 MMBtu/MWh on Coal and Nuclear Units	$	70	
 	 	$	224	
 	 	$	282	
 	 	$	308	
 	 	$	333	
 	 	 	
Heat Rate Sensitivity Down 1 MMBtu/MWh on Coal and Nuclear Units	$	(27	)	 	$	(181	)	 	$	(235	)	 	$	(265	)	 	$	(289	)	 	 	
 	 	
(a)	Net Coal and Nuclear capacity represents nominal summer net MW capacity of power generated as adjusted for the Company's ownership position excluding capacity from inactive/mothballed units, see Item 2 -  Properties  for units scheduled to be deactivated.	
 	 	
(b)	Forecasted generation dispatch output (MWh) based on forward price curves as of December 31, 2012, which is then divided by number of hours in a given year to arrive at MW capacity. The dispatch takes into account planned and unplanned outage assumptions.	
 	 	
(c)	Includes amounts under power sales contracts and natural gas hedges. The forward natural gas quantities are reflected in equivalent MWh based on forward market implied heat rate as of December 31, 2012, and then combined with power sales to arrive at equivalent MWh hedged which is then divided by number of hours in given year to arrive at MW hedged. The Coal and Nuclear Sales include swaps and delta of options sold which is subject to change. For detailed information on the Company's hedging methodology through use of derivative instruments, see discussion in Item 15 - Note 5,  Accounting for Derivative Instruments and Hedging Activities , to the Consolidated Financial Statements. Includes inter-segment sales from the Company's wholesale power generation business to the Retail Business.	
 	 	
(d)	Percentage hedged is based on total Coal and Nuclear sales as described in (c) above divided by the forecasted Coal and Nuclear capacity.	
 	 	
(e)	Represents all U.S. Coal and Nuclear sales, including energy revenue and demand charges, excluding revenues derived from capacity auctions. For purpose of consistency, rail rates for South Central were held constant.	

Retail Operations
In 2012, the Company's Retail Business sold electricity to residential, commercial and industrial consumers at either fixed, indexed or variable prices. Residential and smaller commercial consumers typically contract for terms ranging from one month to two years while industrial contracts are often between one year and five years in length. In 2012, the Company's Retail Business sold approximately 59 TWhs of electricity. In any given year, TWh sold can be affected by weather, economic conditions and competition. The wholesale supply is typically purchased as the load is contracted in order to secure profit margin. The wholesale supply is purchased from a combination of NRG's wholesale portfolio and other third parties, depending on the existing hedge position for the NRG wholesale portfolio at the time. The ability to choose supply from the market or the Company's portfolio allows for an optimal combination to support and stabilize retail margins.

13

Capacity and Other Contracted Revenue Sources
NRG revenues and cash flows benefit from capacity/demand payments and other contracted revenue sources, originating from market clearing capacity prices, Resource Adequacy contracts, tolling arrangements, PPAs and other long-term contractual arrangements:
 	 	
•	East — The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE, and NYISO. These revenues increased greatly with the addition of the GenOn fleet. The region's share of the GenConn plants in Connecticut also earns fixed payments under long-term financial contracts with a utility counterparty.	
 	 	
•	South Central — NRG earns demand payments from its long-term full-requirements load contracts with ten Louisiana distribution cooperatives. Of the ten contracts, nine expire in 2025 and account for 75% of the cooperative customer contract load, with the remaining contract currently set to expire in 2014. This remaining counterparty, with a 550 MW load service contract, accounting for 25% of the cooperative total, has elected not to extend its contract when it expires in 2014.  Demand payments from the current long term contracts are tied to summer peak demand and provide a mechanism for recovering a portion of costs associated with new or changed environmental laws or regulations.	
 	 	
•	West — Many of the region's sites, including natural gas projects currently under construction, are under long-term tolling agreements. The remaining sites have short-term tolling agreements or Resource Adequacy contracts.	
 	 	
•	Thermal — Output from the Company's thermal assets is generally sold under long-term contracts or through regulated public utility tariffs. The contracts or tariffs contain capacity or demand elements, mechanisms for fuel recovery and/or the recovery of operating expenses. The PJM generation assets participate in the PJM capacity markets.	
 	 	
•	Texas — The region's sources of capacity and contracted revenues are through bilateral contracts with load serving entities.	
 	 	
•	International — Generation output from the Company's share of the Gladstone facility in Australia is sold under long-term contracts, which include capacity payments as well as the reimbursement of certain fixed and variable costs.	
 	 	
•	Alternative Energy — Output from solar energy assets is generally sold through long-term PPAs and renewable incentive agreements.	
Fuel Supply and Transportation
NRG's fuel requirements consist of nuclear fuel and various forms of fossil fuel including coal, natural gas and oil. The prices of fossil fuels are highly volatile. The Company obtains its fossil fuels from multiple suppliers and transportation sources. Although availability is generally not an issue, localized shortages, transportation availability, delays arising from extreme weather conditions and supplier financial stability issues can and do occur. The preceding factors related to the sources and availability of raw materials are fairly uniform across the Company's business segments and fuel products used.
Coal — The Company is adequately hedged, using forward coal supply agreements for its domestic coal consumption for 2013. NRG actively manages its coal requirements based on forecasted generation, market volatility and its inventory on site. As of December 31, 2012, NRG had purchased forward contracts to provide fuel for approximately 42% of the combined Company's expected requirements from 2013 through 2017, excluding inventory. Excluding purchases by GenOn pre-acquisition, the Company purchased approximately 29 million tons of coal in 2012, of which 98% was Powder River Basin coal and lignite, and the remaining from the Appalachian basin. Going forward, NRG expects the burn, based on forecasted generation, market volatility and its inventory on site, related to a full year of the acquired GenOn coal assets to approximate an additional 9.7 million tons of Appalachian coal. For fuel transport, NRG has entered into various rail, barge, truck transportation and rail car lease agreements with varying tenures that provide for substantially all of the Company's transportation requirement of Powder River Basin coal for the next two years and for most of the Company's transportation requirements of Appalachian coal for the next year.

14

The following table shows the percentage of the Company's coal requirements from 2013 through 2017 that have been purchased forward as of December 31, 2012:

 	Percentage of
Company's
Requirement (a)(b)	
2013	83	%	
2014	39	%	
2015	42	%	
2016	25	%	
2017	24	%	
 	 	
(a)	The hedge percentages reflect the current plan for the Jewett mine, which supplies lignite for NRG's Limestone facility. NRG has the contractual ability to change volumes and may do so in the future.	
 	 	
(b)	Does not include coal inventory.	
Natural Gas — NRG operates a fleet of mid-merit and peaking natural gas plants across all its U.S. wholesale regions. Fuel needs are managed on a spot basis, especially for peaking assets, as the Company does not believe it is prudent to forward purchase natural gas for units, the dispatch of which is highly unpredictable. The Company contracts for natural gas storage services as well as natural gas transportation services to deliver natural gas when needed.
Nuclear Fuel — STP's owners satisfy their fuel supply requirements by: (i) acquiring uranium concentrates and contracting for conversion of the uranium concentrates into uranium hexafluoride; (ii) contracting for enrichment of uranium hexafluoride; and (iii) contracting for fabrication of nuclear fuel assemblies. Through its proportionate participation in STPNOC, which is the NRC-licensed operator of STP and responsible for all aspects of fuel procurement, NRG is party to a number of long-term forward purchase contracts with many of the world's largest suppliers covering STP requirements for uranium and conversion services for the next five years, and with substantial portions of STP's requirements procured thereafter. Similarly, NRG is party to long-term contracts to procure STP's requirements for enrichment services and fuel fabrication for the life of the operating license.
Seasonality and Price Volatility
Annual and quarterly operating results of the Company's wholesale power generation segments can be significantly affected by weather and energy commodity price volatility. Significant other events, such as the demand for natural gas, interruptions in fuel supply infrastructure and relative levels of hydroelectric capacity can increase seasonal fuel and power price volatility. NRG derives a majority of its annual revenues in the months of May through October, when demand for electricity is generally at its highest in the Company's core domestic markets. Further, power price volatility is generally higher in the summer months, traditionally NRG's most important season. The Company's second most important season is the winter months of December through March when volatility and price spikes in underlying delivered fuel prices have tended to drive seasonal electricity prices. The preceding factors related to seasonality and price volatility are fairly uniform across the Company's wholesale generation business segments.
The sale of electric power to retail customers is also a seasonal business with the demand for power generally peaking during the summer months. As a result, net working capital requirements for the Company's retail operations generally increase during summer months along with the higher revenues, and then decline during off-peak months. Weather may impact operating results and extreme weather conditions could materially affect results of operations. The rates charged to retail customers may be impacted by fluctuations in total power prices and market dynamics like the price of natural gas, transmission constraints, competitor actions, and changes in market heat rates.

15

Regional Segment Review
Revenues
The following table contains a summary of NRG's operating revenues by segment for the years ended December 31, 2012, 2011, and 2010, as discussed in Item 15 — Note 17,  Segment Reporting,  to the Consolidated Financial Statements. Refer to that footnote for additional financial information about NRG's business segments and geographic areas, including a profit measure and total assets. In addition, refer to Item 2  — Properties , for information about facilities in each of NRG's business segments.

 	Year Ended December 31, 2012	
 	Energy
Revenues	 	Capacity
Revenues	 	Retail
Revenues	 	Mark-to-
Market
Activities	 	Contract Amor-tization	 	Other
Revenues(a)	 	Total
Operating
Revenues(b)	
 	(In millions)	
Retail	$	—	
 	 	$	—	
 	 	$	5,893	
 	 	$	(5	)	 	$	(116	)	 	$	—	
 	 	$	5,772	
 	
Texas	2,406	
 	 	81	
 	 	—	
 	 	(441	)	 	—	
 	 	28	
 	 	2,074	
 	
East	533	
 	 	314	
 	 	—	
 	 	(12	)	 	—	
 	 	19	
 	 	854	
 	
South Central	527	
 	 	240	
 	 	—	
 	 	30	
 	 	20	
 	 	(10	)	 	807	
 	
West	121	
 	 	124	
 	 	—	
 	 	10	
 	 	—	
 	 	4	
 	 	259	
 	
Other Conventional Generation	39	
 	 	41	
 	 	—	
 	 	—	
 	 	(1	)	 	241	
 	 	320	
 	
Alternative Energy	150	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	3	
 	 	153	
 	
Corporate and Eliminations (c)	(1,662	)	 	(38	)	 	(5	)	 	(32	)	 	—	
 	 	(80	)	 	(1,817	)	
Total	$	2,114	
 	 	$	762	
 	 	$	5,888	
 	 	$	(450	)	 	$	(97	)	 	$	205	
 	 	$	8,422	

(a)	Primarily consists of revenues generated by the Thermal business, operation and maintenance revenues and unrealized trading activities.	
 	 	
(b)	Total operating revenues includes GenOn revenues of $73 million for the period from December 15, 2012 to December 31, 2012.	
 	 	
(c)	Energy revenues include inter-segment sales primarily between Texas and East, and the Retail Business.	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Year Ended December 31, 2011	
 	Energy
Revenues	 	Capacity
Revenues	 	Retail
Revenues(d)	 	Mark-to-
Market
Activities	 	Contract Amor-tization	 	Other
Revenues(e)	 	Total
Operating
Revenues	
 	(In millions)	
Retail	$	—	
 	 	$	—	
 	 	$	5,812	
 	 	$	8	
 	 	$	(178	)	 	$	—	
 	 	$	5,642	
 	
Texas	2,545	
 	 	28	
 	 	—	
 	 	173	
 	 	—	
 	 	86	
 	 	2,832	
 	
East	579	
 	 	291	
 	 	—	
 	 	28	
 	 	—	
 	 	26	
 	 	924	
 	
South Central	548	
 	 	243	
 	 	—	
 	 	(12	)	 	20	
 	 	18	
 	 	817	
 	
West	31	
 	 	118	
 	 	—	
 	 	(4	)	 	—	
 	 	4	
 	 	149	
 	
Other Conventional Generation	58	
 	 	70	
 	 	—	
 	 	—	
 	 	(1	)	 	196	
 	 	323	
 	
Alternative Energy	43	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	1	
 	 	44	
 	
Corporate and Eliminations (f)	(1,735	)	 	(14	)	 	(5	)	 	132	
 	 	—	
 	 	(30	)	 	(1,652	)	
Total	$	2,069	
 	 	$	736	
 	 	$	5,807	
 	 	$	325	
 	 	$	(159	)	 	$	301	
 	 	$	9,079	

(d)	Retail revenues include Energy Plus revenues of $63 million for the period from October 1, 2011, to December 31, 2011.	
 	 	
(e)	Primarily consists of revenues generated by the Thermal business, operation and maintenance revenues and unrealized trading activities.	
 	 	
(f)	Energy revenues include inter-segment sales primarily between Texas and East, and the Retail Business.	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Year Ended December 31, 2010	
 	Energy
Revenues	 	Capacity
Revenues	 	Retail
Revenues(g)	 	Mark-to-
Market
Activities	 	Contract Amor-tization	 	Other
Revenues(h)	 	Total
Operating
Revenues	
 	(In millions)	
Retail	$	—	
 	 	$	—	
 	 	$	5,279	
 	 	$	(1	)	 	$	(223	)	 	$	—	
 	 	$	5,055	
 	
Texas	2,840	
 	 	25	
 	 	—	
 	 	57	
 	 	7	
 	 	111	
 	 	3,040	
 	
East	726	
 	 	396	
 	 	—	
 	 	(144	)	 	—	
 	 	47	
 	 	1,025	
 	
South Central	387	
 	 	235	
 	 	—	
 	 	(45	)	 	21	
 	 	10	
 	 	608	
 	
West	25	
 	 	113	
 	 	—	
 	 	(4	)	 	—	
 	 	4	
 	 	138	
 	
Other Conventional Generation	46	
 	 	71	
 	 	—	
 	 	(2	)	 	—	
 	 	186	
 	 	301	
 	
Alternative Energy	39	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	2	
 	 	41	
 	
Corporate and Eliminations(i)	(1,209	)	 	(16	)	 	(2	)	 	(60	)	 	—	
 	 	(72	)	 	(1,359	)	
Total	$	2,854	
 	 	$	824	
 	 	$	5,277	
 	 	$	(199	)	 	$	(195	)	 	$	288	
 	 	$	8,849	

(g)	Retail revenues include Green Mountain Energy revenues of $69 million for the period from November 5, 2010 through December 31, 2010.	
 	 	
(h)	Primarily consists of revenues generated by the Thermal business, operation and maintenance revenues and unrealized trading activities.	
 	 	
(i)	Energy revenues include inter-segment sales primarily between Texas and both Reliant Energy and Green Mountain Energy.	

16

Operational Statistics
The following are industry statistics for the Company's fossil and nuclear plants, as defined by the NERC and are more fully described below:
Annual Equivalent Availability Factor, or EAF — Measures the percentage of maximum generation available over time as the fraction of net maximum generation that could be provided over a defined period of time after all types of outages and deratings, including seasonal deratings, are taken into account.
Net Heat Rate — The net heat rate represents the total amount of fuel in BTU required to generate one net kWh provided.
Net Capacity Factor — The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period. The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation.
The tables below present these performance metrics for the Company's U.S. power generation portfolio, including leased facilities and those accounted for through equity method investments, for the years ended December 31, 2012, and 2011:

 	Year Ended December 31, 2012	
 	 	 	 	 	Fossil and Nuclear Plants	
 	Net Owned
Capacity (MW)(a)	 	Net
Generation
(MWh)(b)	 	Annual
Equivalent
Availability
Factor	 	Average Net
Heat Rate
BTU/kWh	 	Net Capacity
Factor	
 	(In thousands of MWh)	
Texas 	10,880	
 	 	37,695	
 	 	83.2	%	 	10,200	
 	 	40.7	%	
East	21,270	
 	 	6,630	
 	 	86.8	
 	 	11,200	
 	 	8.8	
 	
South Central	5,315	
 	 	15,927	
 	 	90.2	
 	 	9,400	
 	 	42.4	
 	
West	7,520	
 	 	2,146	
 	 	91.7	
 	 	12,000	
 	 	11.9	
 	
Alternative Energy	835	
 	 	1,988	

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Year Ended December 31, 2011	
 	 	 	 	 	Fossil and Nuclear Plants	
 	Net Owned
Capacity (MW)	 	Net
Generation
(MWh)	 	Annual
Equivalent
Availability
Factor	 	Average Net
Heat Rate
BTU/kWh	 	Net Capacity
Factor	
 	(In thousands of MWh)	
Texas	10,295	
 	 	45,165	
 	 	88.2	%	 	10,300	
 	 	46.7	%	
East (c)	6,915	
 	 	7,376	
 	 	87.2	
 	 	11,100	
 	 	11.1	
 	
South Central	4,125	
 	 	16,000	
 	 	89.9	
 	 	9,700	
 	 	43.9	
 	
West	2,130	
 	 	1,052	
 	 	88.5	
 	 	12,400	
 	 	5.6	
 	
Alternative Energy	545	
 	 	1,262	

(a)	Net Capacity Owned includes GenOn assets, which were acquired on December 14, 2012. These include 14,850 MW in East, 1,200 MW in South Central, and 5,390 MW in West.	
 	 	
(b)	Net Generation includes GenOn generation for the period from December 15, 2012 through December 31, 2012.	
 	 	
(c)	Factor data and heat rate do not include the Keystone and Conemaugh facilities.	

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The generation performance by region for the three years ended December 31, 2012, 2011, and 2010, is shown below:

 	Net Generation	
 	2012 (a)	 	2011	 	2010	
 	(In thousands of MWh)	
Texas	 	 	 	 	 	
Coal	24,825	
 	 	30,256	
 	 	29,633	
 	
Gas	4,709	
 	 	5,949	
 	 	4,794	
 	
Nuclear (b)	8,161	
 	 	8,960	
 	 	9,295	
 	
Total Texas	37,695	
 	 	45,165	
 	 	43,722	
 	
East	 	 	 	 	 	
Coal	4,514	
 	 	5,551	
 	 	7,905	
 	
Oil	228	
 	 	83	
 	 	114	
 	
Gas	1,888	
 	 	1,742	
 	 	1,347	
 	
Total East	6,630	
 	 	7,376	
 	 	9,366	
 	
South Central	 	 	 	 	 	
Coal	8,923	
 	 	10,865	
 	 	10,778	
 	
Gas (c)	7,004	
 	 	5,135	
 	 	390	
 	
Total South Central	15,927	
 	 	16,000	
 	 	11,168	
 	
West	 	 	 	 	 	
Gas	2,146	
 	 	1,052	
 	 	869	
 	
Total West	2,146	
 	 	1,052	
 	 	869	
 	
Alternative Energy	 	 	 	 	 	
Solar	740	
 	 	79	
 	 	52	
 	
Wind	1,248	
 	 	1,183	
 	 	978	
 	
Total Alternative Energy	1,988	
 	 	1,262	
 	 	1,030	

(a)	Includes GenOn generation for the period from December 15, 2012 through December 31, 2012.	
 	 	
(b)	MWh information reflects the Company's undivided interest in total MWh generated by STP.	
 	 	
(c)	Includes Cottonwood since November 15, 2010 (acquisition date).	
Market Framework
Organized Energy Markets in CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM
The majority of NRG's fleet operates in one of the organized energy markets, known as RTOs or ISOs. Each organized market administers day-ahead and real-time centralized bid-based energy and ancillary services markets pursuant to tariffs approved by the FERC, or in the case of ERCOT, market rules approved by the PUCT. These tariffs and rules dictate how the energy markets operate, how market participants make bilateral sales with one another, and how entities with market-based rates are compensated. Established prices reflect the value of energy at the specific location and time it is delivered, which is known as the Locational Marginal Price or LMP. Each market is subject to market mitigation measures designed to limit the exercise of locational market power. These market structures facilitate NRG's sale of power and capacity products at market-based rates.
Other than ERCOT, each of the ISOs also operates a capacity or resource adequacy market that provides an opportunity for generating and demand response resources to earn revenues to offset their fixed costs that are not recovered in the energy and ancillary services markets. The ISOs are also responsible for transmission planning and operations.
Texas
NRG's Texas wholesale power generation business is in the physical control area of the ERCOT market. The ERCOT market is one of the nation's largest and historically fastest growing power markets. For 2012, hourly demand ranged from a low of approximately 22,400 MW to a high of over 66,500 MW with installed generation capacity of approximately 84,500 MW (approximately 23,500 MW from coal, lignite and nuclear plants, 46,000 MW from gas, and 15,000 MW from wind, hydro, solar, biomass and behind-the-meter generation). The ERCOT market has limited interconnections to other markets in the United States. In addition, NRG's Retail Business activities in Texas are subject to standards and regulations adopted by the PUCT and ERCOT including the requirement for retailers to be certified by the PUCT in order to contract with end-users to sell electricity. In Texas, a majority of the load is in the ERCOT market and is served by competitive retail suppliers. Certain areas of the state are served by municipal utilities and electric cooperatives.

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Regulators and stakeholders in ERCOT are currently debating how to address projected shortfalls in planning reserve margins that may occur in 2013 and beyond.  A number of market rule changes have been implemented to provide pricing more reflective of higher energy value when operating reserves are scarce or constrained.  The primary stated goal of these market rule changes is to improve forward market pricing signals and provide incentives for resource investment.  Among the changes already implemented are:  energy offer floors for certain ancillary service deployments, an increase to the system-wide energy and ancillary service offer caps (currently at $4,500 per MWh but increasing to $5,000 in June 2013, $7,000 in June 2014, and to $9,000 in June 2015), an increase to the annual peaker net margin threshold to $262,500 from $175,000, an increase to the low system-wide energy offer cap to $2,000 (up from $500), and higher energy pricing for ISO unit commitments for capacity.  Other proposals under review include additional administrative pricing adjustments during operational shortages, mitigation of price dampening from minimum energy from on-line resources, and formalizing emergency supply procurement by the ISO in a manner that would not suppress competitive pricing.
East
NRG's generation assets located in the East region of the United States are within the control areas of the NYISO, ISO-NE, and PJM, and one plant is in Osceola, Florida, which is outside of the organized eastern markets. Each of the market regions in the East region provides for robust competition in the day-ahead and real-time energy and ancillary services markets. Additionally, each allows capacity resources to compete for fixed cost recovery in a capacity auction.
The East region achieves a significant portion of its revenues from capacity markets in ISO-NE, NYISO and PJM. PJM and ISO-NE employ a three-year forward capacity auction construct, while NYISO employs a month-ahead capacity auction construct. Capacity market prices are sensitive to design parameters, as well as additions of new capacity. In late 2012, both PJM and ISO-NE requested FERC approval to implement new buyer-side mitigation measures which will ensure that new capacity additions are appropriately priced in the relevant markets. The NYISO also strengthened its buyer-side market power rules in 2012. Additionally, NYISO is scheduled to begin its triennial adjustment of its capacity market parameters in 2013, which could have a major impact on future capacity prices.
NRG's Retail Business is active in a number of areas in the East region that have introduced retail competition, which allows NRG to competitively provide retail power, natural gas and other value-enhancing services to customers.  Each retail choice state is responsible for its own retail competition laws and regulations, and the specific operational, licensing, and compliance requirements vary on a state-by-state basis.  The Company's Retail Business holds licenses in many of the states allowing for retail choice in C&I and/or Mass markets.  In the East markets, incumbent utilities currently provide default service and as a result typically serve a majority of residential customers.  Primary factors in the success of retail competition include how the state provides and prices default service.  However, as customers become more informed about the many benefits of retail choice and states continue to implement retail policies to further improve market dynamics, retail choice is expected to grow.  The Retail Business continues to expand in the competitive choice states and offers a range of value propositions to consumers to meet individual and business preferences. 
The East Region also includes the Osceola plant that is outside the organized eastern markets. It is located in FRCC and is currently under a tolling arrangement that expires in 2014.
South Central
NRG's South Central region operates primarily in the SERC-Entergy region, in which power sales and purchases are consummated bilaterally between individual counterparties, and also in the MISO. In the SERC-Entergy region, transacting counterparties are required to procure transmission service from the relevant transmission owners at their FERC-approved tariff rates. In this market structure, NRG also provides balancing authority services through its operation of four balancing authorities, in addition to wholesale power that allows NRG to provide full requirement services to load-serving entities, including cooperatives and municipalities, thus making NRG a competitive alternative to the integrated utilities operating in the region.
West
The Company operates a fleet of natural gas fired facilities located entirely within the CAISO footprint. The CAISO operates day-ahead and real-time locational markets for energy and ancillary services, while managing congestion primarily through nodal prices. The CAISO system facilitates NRG's sale of power and capacity products at market-based rates, or bilaterally pursuant to tolling arrangements with California's load serving entities, or LSEs. The CPUC also determines specific capacity requirements for specified local areas utilizing inputs from the CAISO. Both CAISO and CPUC rules require LSEs to contract with sufficient generation resources in order to maintain minimum levels of generation within defined local delivery areas. Additionally, the CAISO has independent authority to contract with needed resources under certain circumstances.

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The increase in renewable resources in California is expected to drive a growing need for generation resources with increased operating flexibility, in addition to the established need for dispatchable generation within transmission-constrained areas of the transmission system, such as the San Diego, Greater San Francisco Bay Area, Big Creek/Ventura, and Los Angeles local reliability areas in which the Company currently operates natural gas-fired generation.  The projected retirement of older flexible gas-fired coastal generating units that utilize once-through cooling is also a significant driver of long-term prices in California.  Implementing market mechanisms to procure the needed flexibility, and allocating the costs associated with this flexibility, are key CAISO initiatives.  Another key CAISO-CPUC initiative in 2013 will be the consideration of a multi-year forward Resource Adequacy capacity procurement mechanism.  Most of NRG's CAISO natural gas-fired assets are in transmission-constrained local reliability areas, and may benefit from local capacity requirements.  The Company's Marsh Landing and El Segundo Energy Center developments, which are currently under construction and the subject of long-term tolling agreements, are examples of the type of flexible natural gas-fired generation resources that the CAISO has identified as necessary to maintain system reliability.  Longer term, NRG's California portfolio's locational advantage may be impacted by new transmission, which may affect load pocket procurement requirements, and by the state's goal for additional distributed generation, which may also be located within these constrained local areas. 
Solar
The Company also operates a fast-growing fleet of Utility Scale Solar and Distributed Solar generating assets within the CAISO, as well as balancing authorities in Arizona and New Mexico. Each of these states has implemented their own renewable portfolio standard requiring LSEs to provide a given percentage of their production from renewable resources, such as 33% of generation by 2020 in California. As a result, a number of LSEs have entered into long-term PPAs with the Company's Utility Scale Solar generating facilities. The Company currently has PPAs for over 1,100 MW of solar generation assets, over 750 MWs of which are located in California. In California and Arizona investor-owned utilities are nearing their procurement requirement, resulting in a trend towards smaller sized Utility Scale projects and a shift of contracting to municipalities and other public power entities. Distributed Solar opportunities remain strong as declining project costs allow pricing, without subsidies, to continue to approach parity with utility rates. As success in the Distributed Solar segment of the market builds, the states' public utility commissions are expected to reevaluate policies created to encourage the growth of this market segment, including the role of net energy metering (in California) and tariff subsidies (as evidenced by the end of commercial and industrial customer incentives in Arizona).

20

New and On-going Company Initiatives and Development Projects
Renewable Development and Acquisitions
As part of its core strategy, NRG intends to continue to invest in the development and acquisition of renewable energy projects, primarily solar. NRG's renewable strategy is intended to capitalize on first mover advantage in a high growth segment of NRG's business, the Company's existing presence in regions with attractive renewable resources and the prevalence, in the Company's core markets, of state-mandated renewable portfolio standards. This section briefly describes the Company's development efforts with respect to solar renewable technology.
Solar
NRG has acquired and is developing a number of solar projects utilizing photovoltaic, or PV, as well as solar thermal technologies. The following table is a brief summary of the Company's major Utility Scale Solar projects, as of December 31, 2012, that are or were under construction during the fourth quarter.

NRG Owned Projects	Location	PPA	MW (a)	Expected COD	Status	
Ivanpah (b)	Ivanpah, CA	20 - 25 year	392	
 	2013	Under Construction	
Agua Caliente (c)	Yuma County, AZ	25 year	290	
 	2012 - 2014	Partially In-Service	
CVSR (d)	San Luis Obispo, CA	25 year	250	
 	2012 - 2013	Partially In-Service	
Alpine	Lancaster, CA	20 year	66	
 	2013	Under Construction	
Borrego	Borrego Springs, CA	25 year	26	
 	2013	Under Construction	
Avra Valley	Pima County, AZ	20 year	25	
 	2012	In-Service	
 	 	
(a)	Represents total project size.	
 	 	
(b)	NRG owns a 50.1% stake in the Ivanpah solar project.	
 	 	
(c)	NRG owns a 51% stake in the 290 MW Agua Caliente project which includes 253 MW that reached commercial operations from January through December of 2012.	
 	 	
(d)	CVSR has 127 MW in operation as of December 31, 2012 as commercial operations on Phase 1 of 22 MW was achieved in September and Phases 2 and 4 totaling 105 MW achieved commercial operations in December 2012.	
Below is a summary of recent developments related to solar projects:
Ivanpah — The first unit of the Ivanpah project is expected to be completed and producing power in July of 2013. The second and third units are expected to be completed in the third and fourth quarters of 2013. Power generated from Ivanpah will be sold to Southern California Edison and PG&E under multiple 20 to 25 year PPAs.
Agua Caliente—  On January 18, 2012, the Company completed the sale of a 49% interest in NRG Solar AC Holdings LLC, the indirect owner of Agua Caliente, to MidAmerican Energy Holdings Company. Operations are scheduled to commence in phases through the first quarter of 2014, with 253 MW having achieved commercial operations from January through December of 2012. On April 12, 2012, the Company received permission from the U.S. DOE to accelerate the block completion schedule. The impact of this decision has allowed the Company to bring blocks on-line sooner and shortens the commercial operations date of the entire project by three months to March 2014. The acceleration has resulted in greater earnings earlier than originally anticipated, along with acceleration of payments under the EPC agreement which has been funded with earlier draw downs under the Agua Caliente Financing Agreement, as discussed in Item 15  —  Note 11,  Debt and Capital Leases  to the Consolidated Financial Statements, as well as equity support by the partners. Power generated from Agua Caliente is being sold to PG&E under a 25 year PPA. While full commercial operations of the entire project will be achieved in early 2014, the maximum capacity deliverable under the PPA of 290 MWs is expected to be on-line by the third quarter of 2013.
CVSR— NRG owns 100% of the 250 MW CVSR project in eastern San Luis Obispo County, California. During the second quarter of 2012, the Company met the conditions necessary to permit loan disbursements under the CVSR Financing Agreement, as discussed in Item 15  —  Note 11,  Debt and Capital Leases , to the Consolidated Financial Statements. Operations commenced on the first 22 MW phase in September 2012 and 105 MWs for Phases 2 and 4 in December 2012, with the final phase expected during the fourth quarter of 2013. Power generated from CVSR is sold to PG&E under a 25 year PPA.
Alpine — Alpine, located in Lancaster, CA, is a 66 MW photovoltaic facility utilizing First Solar thin film solar modules. The project, which reached commercial operations in January 2013, obtained financing during the first quarter of 2012, as discussed in Item 15  — Note 11,  Debt and Capital Leases , to the Consolidated Financial Statements. Power generated from Alpine will be sold to PG&E under a 20 year PPA.

21

Borrego — Borrego, located in Borrego Springs, CA, is a 26 MW facility utilizing SunPower's Oasis photovoltaic power block with single axis tracking. The project reached commercial operations in February 2013. Power generated from Borrego is sold to San Diego Gas and Electric under a 25 year PPA.
Avra Valley — Avra Valley, located in Pima County, AZ, is a 25 MW facility utilizing First Solar thin film solar modules with a single axis tracking system. The project, which achieved commercial operations in December 2012, obtained financing during the third quarter of 2012, as discussed in Item 15  —  Note 11,  Debt and Capital Leases , to the Consolidated Financial Statements. Power generated from Avra Valley is sold to Tucson Electric Power Company under a 20 year PPA.
Distributed Solar —The MetLife Stadium project, in East Rutherford, NJ, was completed during the third quarter 2012. NRG's installation of solar power generating systems at Gillette Stadium, in Foxboro, MA, achieved commercial operations in December 2012 while the system at Lincoln Financial Field, in Philadelphia, PA, achieved commercial operation in February 2013. Also achieving commercial operations in the fourth quarter of 2012 is a portfolio of 18 sites in southern California totaling 9 MWs, of which 51% is owned by NRG. All of the Company's Distributed Solar projects in operation or under construction are supported by long-term PPAs.
Conventional Power Development
Projects Under Construction
The Company's El Segundo Energy Center LLC, or ESEC, is continuing construction at its El Segundo Power Generating Station, a 550 MW fast start, gas turbine combined cycle generating facility in El Segundo, California. The facility is being constructed pursuant to a 10 year, 550 MW PPA with Southern California Edison.  The Company expects a commercial operation date of August 1, 2013.
Through the GenOn acquisition, the Company is continuing construction of the Marsh Landing project, a 720 MW natural gas-fired peaking facility adjacent to the Company's Contra Costa generating facility near Antioch, California. The facility is being constructed pursuant to a 10 year PPA with PG&E. The Company expects a commercial operation date in mid 2013.
Retail Growth Initiatives
The Company's Retail Business continues to expand in both Texas and the East through its innovative partnerships, channels, product lines and value propositions.  During 2012, NRG grew customer count by 51,000 in Texas and by 91,000 in the East markets.  In addition, NRG launched sales to businesses, manufacturing facilities, government entities and institutions in Ohio and New York. NRG's Retail Business is currently operating in 11 states including Texas, Connecticut, Delaware, Illinois, Maryland, Massachusetts, New Jersey, New York, Ohio, Oregon and Pennsylvania, as well as the District of Columbia.
NRG also continues to expand its innovative solutions, with over 720,000 customers using one of eSenseTM smart energy solutions giving customers energy insights, choices and convenience solutions.  Additionally, NRG's Retail Business continues to expand the Home Solutions SM  product line with almost 340,000 customers utilizing home services products including protection products such as surge protection, in home power line protection, HVAC maintenance and energy efficiency products such as air filter delivery and solar panel leasing, and with expansion into certain home warranty products.
Services Growth Initiatives

On December 14, 2012, the Company assumed operations and management responsibilities for the Homer City Generating station, a 1,884 MW three-unit-coal-fueled plant near Pittsburgh, PA.  This is an important milestone for NRG as, for the first time, the Company expanded its O&M services to a facility owned 100% by a third party.
The Company is also continuing to develop its backup energy generation capabilities to provide services to a broad array of customers around the country.

22

Electric Vehicle Infrastructure Development
NRG, through its subsidiary eVgo, continues its build out and operation of the Houston and Dallas/Fort Worth Metroplex, or DFW, EV ecosystems, and the Company's progress to date has positioned it to be the first company to equip an entire major market with the privately funded infrastructure needed for successful EV adoption and integration. As of December 31, 2012, eVgo had 17 public fast charging Freedom Station sites operational in Houston and 20 in DFW. These two ecosystems are the largest privately-funded comprehensive direct current fast-charging networks in the nation. In addition, eVgo had 6 sites in the newly entered Washington, DC/Baltimore market under construction or in permitting. eVgo offers consumers a subscription-based plan that provides for all charging requirements for EVs at a competitive monthly fee.
Additionally, eVgo has entered into an agreement with the CPUC to build at least 200 public fast charging Freedom Station sites and wiring and associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California. The agreement is part of a legal settlement, as discussed in detail in Item 15  —  Note 21,  Commitments and Contingencies , to the Consolidated Financial Statements, and was approved by the FERC on November 5, 2012.
W.A. Parish Peaking Unit and Commercial Scale Carbon Capture, Utilization and Storage System
On May 3, 2012, NRG entered into a financing arrangement in the form of a $54 million tax-exempt bond financing, as discussed in Item 15  —  Note 11,  Debt and Capital Leases , to the Consolidated Financial Statements. The proceeds of the bonds are being used for the construction of a peaking unit at the W.A. Parish plant and one or more components of a commercial scale CCUS. The CCUS is sponsored in part by a grant from the U.S. DOE. On August 14, 2012, NRG, through its wholly owned subsidiary, Petra Nova Power I LLC, entered into an EPC agreement for the construction of the 75 MW turbine as a peaking unit (later to be retrofitted for use as a cogeneration facility to provide steam and power to operate the CCUS), commenced construction in the fourth quarter of 2012, and anticipates a commercial operations date during the second quarter of 2013.
Construction of the CCUS is intended to allow NRG, through its wholly owned subsidiary Petra Nova LLC, or Petra Nova, to utilize the captured CO 2  in enhanced oil recovery operations in oil fields on the Texas Gulf Coast.  In December of 2012, the final air permit was issued by the Texas Commission on Environmental Quality for the full carbon capture system. The final Environmental Impact Statement is approved and the Record of Decision is expected to be issued by the U.S. DOE in March of 2013.
Regulatory Matters
As operators of power plants and participants in wholesale and retail energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC, and PUCT, as well as other public utility commissions in certain states where NRG's generating, thermal, or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states in which NRG entities are licensed to sell retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where the Company operates.
Federal Regulation
CFTC
The CFTC, among other things, has regulatory oversight authority over the trading of physical commodities, futures and other derivatives under the Commodity Exchange Act, or CEA. The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, increased the CFTC's regulatory authority on matters related to futures and over-the-counter derivatives trading, including, but not limited to: trading practices, trade clearance, transaction reporting and record keeping, position limits, and market participant capital and margin requirements. The Company has reached the conclusion that it is neither a swap dealer nor a major swap participant and has taken and will continue to take measures to otherwise comply with the Dodd-Frank Act.
The Company expects that, in 2013 and thereafter, the CFTC will further clarify the scope of the Dodd-Frank Act and publish additional rules concerning central clearing requirements, position limits, margin requirements, the definition of a “swap” and other issues that will affect the Company's futures and over-the-counter derivatives trading. Because there are many details that remain to be addressed through CFTC rulemaking proceedings, at this time NRG cannot fully measure the impact of the Dodd-Frank Act on the Company, its operations or collateral requirements.

23

FERC
The FERC, among other things, regulates the transmission and the wholesale sale by public utilities of electricity in interstate commerce under the authority of the FPA. Under existing regulations, the FERC determines whether an entity owning a generation facility is an EWG as defined in the PUHCA of 2005. The FERC also determines whether a generation facility meets the ownership and technical criteria of a QF under PURPA. The transmission of electric energy occurring wholly within ERCOT is not subject to the FERC's rate jurisdiction under Sections 203 or 205 of the FPA. Each of NRG's non-ERCOT U.S. generating facilities either qualifies as a QF, or the subsidiary owning the facility qualifies as an EWG.
Public utilities are required to obtain the FERC's acceptance, pursuant to Section 205 of the FPA, of their rate schedules for the wholesale sale of electricity. All of NRG's non-QF generating and power marketing entities located outside of ERCOT make sales of electricity pursuant to market-based rates, as opposed to traditional cost-of-service regulated rates.
State Regulation
In Texas, NRG's operations within the ERCOT footprint are not subject to rate regulation by the FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT, as well as to regulation by the NRC with respect to the Company's ownership interest in STP.
In New York, the Company's generation subsidiaries are electric corporations subject to "lightened" regulation by the NYSPSC. As such, the NYSPSC exercises its jurisdictional authority over certain non-rate aspects of the facilities, including safety, retirements, and the issuance of debt secured by recourse to the Company's generation assets located in New York. The Company currently has blanket authorization from the NYSPSC for the issuance of $15 billion of debt. Additionally, the NYSPSC has provided GenOn Bowline with a separate debt authorization of $1.488 billion.
In California, the Company's generation subsidiaries are subject to regulation by the CPUC with regard to certain non-rate aspects of the facilities, including health and safety, outage reporting and other aspects of the facilities' operations.
        Nuclear Operations
As a holder of an ownership interest in STP, NRG is an NRC licensee and is subject to NRC regulation. The NRC license gives the Company the right to only possess an interest in STP but not to operate it. As a possession-only licensee, i.e., non-operating co-owner, the NRC's regulation of NRG is primarily focused on the Company's ability to meet its financial and decommissioning funding assurance obligations. In connection with the NRC license, the Company and its subsidiaries have a support agreement to provide up to $120 million to support operations at STP.
Decommissioning Trusts — Upon expiration of the operation licenses for the two generating units at STP, currently scheduled for 2027 and 2028, the co-owners of STP are required under federal law to decontaminate and decommission the STP facility. Under NRC regulations, a power reactor licensee generally must pre-fund the full amount of its estimated NRC decommissioning obligations unless it is a rate-regulated utility, or a state or municipal entity that sets its own rates, or has the benefit of a state-mandated non-bypassable charge available to periodically fund the decommissioning trust such that the trust, plus allowable earnings, will equal the estimated decommissioning obligations by the time the decommissioning is expected to begin.
NRG, through its 44% ownership interest, is the beneficiary of decommissioning trusts that have been established to provide funding for decontamination and decommissioning of STP. CenterPoint Energy Houston Electric, LLC, or CenterPoint, and American Electric Power, or AEP, collect, through rates or other authorized charges to their electric utility customers, amounts designated for funding NRG's portion of the decommissioning of the facility. See also Item 15 — Note 6,  Nuclear Decommissioning Trust Fund,  to the Consolidated Financial Statements for additional discussion.
In the event that the funds from the trusts are ultimately determined to be inadequate to decommission the STP facilities, the original owners of the Company's STP interests, CenterPoint and AEP, each will be required to collect, through their PUCT-authorized non-bypassable rates or other charges to customers, additional amounts required to fund NRG's obligations relating to the decommissioning of the facility. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trusts, those excesses will be refunded to the respective rate payers of CenterPoint or AEP, or their successors.

24

Regional Regulatory Developments
NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Item 15 — Note 22,  Regulatory Matters,  to the Consolidated Financial Statements.
East Region
PJM —On April 12, 2011, FERC issued an order addressing a complaint filed by PJM Power Providers Group seeking to require PJM to address the potential adverse impacts of out-of-market generation on the PJM Reliability Pricing Model, or RPM, capacity market, as well as PJM's subsequent submission seeking revisions to the capacity market design, in particular the MOPR. In its order, FERC generally strengthened the MOPR and the protections against market price distortion from out-of-market generation. On November 17, 2011, FERC largely denied rehearing its April 12, 2011, order. Several parties have appealed FERC's decision to federal court, and those appeals have been consolidated in the Third Circuit Court of Appeals. The outcome of this proceeding could affect the Company's ability to meet its obligations under New Jersey's Long-Term Capacity Agreement Pilot Program, as well as drive future capacity prices.

On December 7, 2012, PJM filed comprehensive revisions to its MOPR rules at FERC. These changes would take effect for the 2013 BRA and would subject new generating resources supported by state-sponsored long-term contracts to stringent new mitigation rules. These rules include mitigating the bids offered by resources into the RPM auction to the PJM-determined net cost of new entry, and to continue mitigating such resources until they cleared three BRAs. Other resources, including those bid into the auction by select public power entities or not otherwise backed by state-sponsored contracts would be exempt from mitigation. On February 5, 2013, FERC issued a deficiency notice to PJM requiring PJM to submit more information by March 7, 2013.
PJM Cost of New Entry Settlement — On December 1, 2011, PJM filed to change the Cost of New Entry figure that is used to establish the PJM RPM demand curve, and which therefore has a direct effect on RPM price formation. On January 30, 2012 and again on April 11, 2012, FERC set different portions of the proposed gross Cost of New Entry amount for hearing and settlement judge procedures. On November 21, 2012, many parties agreed to a settlement of all outstanding issues. FERC approved the settlement on January 31, 2013.
New England
Forward Capacity Market — On January 19, 2012, the FERC issued an order largely denying rehearing of its prior decision addressing proposed amendments submitted by ISO New England Inc. to its FCM design, as well as two pending complaints. On March 16, 2012, the Company and other generators with interests in New England appealed the FERC's decision to the D.C. Circuit Court of Appeals. Briefing is currently underway.
New York
New Financial Reporting Rules in New York —On January 17, 2013, the NYSPSC issued an order addressing its policy of applying “lightened” regulation to wholesale generators. The order subjects wholesale generators, which would include NRG entities operating in New York, to financial reporting rules, including a requirement for generators to make an annual submission of “receipts and expenditures” to the NYSPSC in the form provided by the SEC in its final rule.
NYPSC Merger Conditions — On December 14, 2012, the NYPSC approved the merger between NRG and GenOn, subject to certain conditions. One condition is that NRG would be required to offer to sell the Bowline generating facility, located in West Haverstraw, NY, through an RFP process to a qualified bidder if it wishes to retire the Bowline facility. A second condition requires NRG to economically justify the proposed retirement or mothball of any of its facilities located in the Rest-of-State capacity zone. If NRG is unable to economically justify the mothball or retirement, then it would be required to offer to sell the affected facility through an RFP process to a qualified bidder. A third condition specifies that if the NYISO creates a Hudson Valley Capacity Zone, that NRG's In-City facilities plus Bowline would become subject to comparable conditions and the Company's Rest-of-State facilities would no longer be subject to the conditions. Finally, the NYPSC order states that all conditions terminate if NRG sells the Bowline facility.

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Dunkirk Power LLC Reliability Service —On March 14, 2012, Dunkirk Power LLC, or Dunkirk Power, filed a notice with the New York Department of Public Service, or DPS, of its intent to mothball the Dunkirk Station no later than September 10, 2012.  The effects of the mothball on electric system reliability were reviewed by Niagara Mohawk Power Corporation, d/b/a National Grid, or NG.  As a result of those studies, NG determined that the mothball of the Dunkirk Station would have a negative impact on the reliability of the New York transmission system and that portions of the Dunkirk Station may be retained for reliability purposes via a non-market compensation arrangement.  On July 12, 2012, Dunkirk Power filed a RMR agreement with the FERC. On July 20, 2012, NG and Dunkirk Power agreed on the material terms for a bilateral reliability support services, or RSS, agreement and submitted those terms to the NYPSC for rate recovery in NG's rates. On August 16, 2012, the NYPSC approved terms and on August 27, 2012, Dunkirk Power and NG entered into the RSS agreement that began on September 1, 2012. NG issued a request for proposals with respect to its reliability need in the Dunkirk area for the two years beginning June 1, 2014. Dunkirk Power submitted a proposal and is awaiting the results.
New York City Mitigation Order — On June 21, 2012, the FERC issued the first of two anticipated orders on the NYISO's implementation of mitigation rules designed to prevent the exercise of buyer-side market power in the In-City capacity market. The order related primarily to the appropriate modeling assumptions that the NYISO should use in determining whether new entrants are subject to mitigation and, if so, what offer floor should apply to their capacity market bids. The FERC directed the NYISO to conduct its mitigation determinations using modeling parameters comparable to those used in the demand-curve reset process. The FERC also agreed with NRG and other generators that the NYISO needs to make its mitigation determination process more transparent and ordered appropriate changes. Finally, the FERC directed the NYISO Independent Market Monitor to provide a report on the effectiveness of the capacity market buyer-side market power mitigation program.
In the second anticipated order issued on September 10, 2012, the FERC found that the NYISO had not properly applied its mitigation rules to two proposed in-city generation facilities totaling over 1,000 MW (owned respectively by Astoria Energy II LLC and Bayonne Energy Center, LLC - neither of which are affiliated with the Company) and required the NYISO to redo its exemption determinations for these proposed facilities based largely on the modeling procedures presented by the Company and the other in-city generators. The NYISO completed its determinations in time for the December, 2012 spot capacity auction. Both orders remain subject to rehearing.
Texas Region
ERCOT System-Wide Offer Caps -At its June 26, 2012 meeting, the PUCT approved an amendment to raise the ERCOT system-wide energy and ancillary service offer cap from $3,000 to $4,500 per MWh beginning August 1, 2012.  At its October 25, 2012 meeting, the PUCT approved further increases of the system-wide offer cap effective June 1, 2013 to $5,000, escalating to $7,000 on June 1, 2014, and to $9,000 on June 1, 2015. In addition, the PUCT increased the low system offer cap to the higher of $2,000 or 50 times Houston Ship Channel gas price index, triggered when ERCOT calculates a $300,000 per MW presumed net revenue recovery in a calendar year for a gas peaking unit (Peaker Net Margin), the low cap remaining in effect for the remainder of the calendar year. In future years, the Peaker Net Margin will be established as three times the cost of new entry. The ERCOT ISO is expected to shift the Power Balance Penalty Curve, or PBPC, to match these offer cap levels.  An increase in the cap on electricity prices could have a material impact on NRG's retail and wholesale operations. This is expected to be overall positive to NRG as it will potentially result in increased wholesale revenues. 
Over the past several months, ERCOT has implemented a number of measures intended to ensure that real-time energy prices accurately reflect supply scarcity conditions. Specific changes include requiring that energy from reliability services (such as responsive reserves and reliability unit commitments) be offered at the system-wide offer cap, implementing floor prices during the deployment of non-spinning reserve services, and shifting 500 MWs of non-spinning reserves to responsive reserves procurement by the ISO.
On June 1, 2012, the Brattle Group issued an ERCOT sponsored report on resource adequacy. The Brattle Report provides an analysis of the current ERCOT market performance and makes numerous market design recommendations designed to incent investment in additional resources in ERCOT. The report also includes five market design options for consideration to help ensure resource adequacy. The options range from maintaining the existing energy-only market design to a forward capacity market. The PUCT has initiated a new proceeding to evaluate the Brattle Group's recommendations and indicated its intention to determine whether the current reserve margin “target” should be made a market requirement. If the reserve margin is ultimately determined to be a requirement, the PUCT will provide direction to ERCOT regarding the market measures the ISO must implement to ensure the reserve margin requirement is consistently achieved. Such measures, in keeping with the Brattle Report recommended options, would be intended to improve investment incentives for new resources in the wholesale market. The PUCT is expected to make these decisions in the second half of 2013.

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On January 7, 2013, the NERC sent a letter to ERCOT expressing concern about ERCOT's declining reserve margin and projected capacity shortfall, which NERC has determined to be a high reliability risk for the ERCOT region, and asking ERCOT to provide a report to NERC by April 30, 2013 outlining the measures it is taking to increase reserve margins and ensure reliability and to present ERCOT's plans to the NERC Board at its May 9, 2013 meeting.
ERCOT Voluntary Mitigation Plan —On June 18, 2012, NRG submitted a Voluntary Mitigation Plan, or VMP, which had been agreed to by PUCT Staff, and the ERCOT Independent Market Monitor. The VMP establishes a safe harbor for energy offers from NRG's units in ERCOT's real-time market.  The VMP was approved by the PUCT on July 13, 2012. 
Nuclear Regulatory Commission Task Force Report — On July 12, 2011, the NRC Near-Term Task Force, or the Task Force, issued its report, which reviewed nuclear processes and regulations in light of the accident at the Fukushima Daiichi Nuclear Power Station in Japan. The Task Force concluded that U.S. nuclear plants are operating safely and did not identify changes to the existing nuclear licensing process nor recommend fundamental changes to spent nuclear fuel storage. The Task Force report made recommendations in three key areas: the NRC's regulatory framework, specific plant design requirements, and emergency preparedness and actions. STPNOC expects the report to be the first step in a longer-term review that the NRC will conduct, along with seeking broad stakeholder input. STPNOC continues to apply lessons learned and work with regulators and industry organizations on appropriate assessments and actions. 
On January 13, 2012, the NRC issued six draft “information request letters,” seeking industry comment on additional recommendations made by the Near-Term Task Force. Topics for comment include how to improve the robustness of existing emergency preparedness plans, whether to mandate on-site availability of emergency response materials, and guidance on how to identify sites vulnerable to flooding, seismic events, or other natural external hazards (such as hurricanes and tornadoes). The NRC has requested feedback from nuclear utilities on its proposed measures. Until further actions are taken by the NRC, the Company cannot predict the impact of the recommendations in the NRC Task Force report, and could be required to make additional investments at STP Units 1 & 2.
South Central Region
On December 1, 2012, MISO assumed the role of independent coordinator of transmission for Entergy. Additionally, Entergy has obtained conditional regulatory approvals to transfer functional control of its transmission assets to MISO, with a target date for joining of December 2013.  The Company's South Central region is dependent upon Entergy's transmission system to conduct its business, and thus would necessarily move with Entergy into MISO.  To date, the Company has publicly supported the transition of Entergy into MISO, based largely on the Company's positive experience with proven Day 2 Markets, such as MISO.  The Company has been an active participant in the stakeholder processes surrounding Entergy's integration into MISO, including the discussions involving MISO's allocation of financial transmission rights upon integration, and is working to mitigate any potential negative economic impacts of the MISO integration.
Environmental Matters
NRG is subject to a wide range of federal, state and local environmental laws in the development, ownership, construction and operation of projects in the United States and Australia. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. Environmental laws have become increasingly stringent and NRG expects this trend to continue. The electric generation industry will face new requirements to address air emissions, climate change, ash (and other wastes), water use, water discharges, and threatened and endangered species. In general, future laws are expected to require adding emission controls or other environmental controls or impose restrictions on the Company's operations. Complying with environmental requirements involves significant capital and operating expenses. NRG decides to invest capital for environmental controls based on relative certainty of the requirements, an evaluation of compliance options, and the expected economic returns on capital.

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Climate Change — NRG emits GHGs in the process of generating electricity. The following graphs illustrate the reduction in CO 2 , which makes up greater than 99% of the Company's GHG emissions, from 2000 to the present. GenOn's CO 2 emissions for 2011 and 2012 are shown separately (in the graph below) and starting with 2013 historical emissions for the combined company will be presented. NRG anticipates reductions in its future emissions profile as the Company implements its strategy to add more renewable sources like wind and solar, modernize the fleet through repowering, improve generation efficiencies, explore methods to capture CO 2 , and seek ways to offset GHGs.

In April 2012, the EPA proposed a rule under the NSPS section of the CAA, to limit the CO2emissions from certain new fossil-fuel-fired electric generating units. The proposed limit is 1,000 pounds of CO 2  per MWh, about the emission rate of a combined cycle gas turbine and cannot be achieved by coal-fired units without carbon capture and storage technology. The proposed rule does not apply to simple cycle combustion turbines or modified existing units. The proposed standard is in effect until the final rule is published. The Company expects the EPA to issue another rule that will require states to develop CO 2 standards that would apply to existing fossil-fueled generating facilities.

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The impact from legislation or federal, regional or state regulation of GHGs on the Company's financial performance will depend on a number of factors, including the regulatory design, level of GHG reductions, the applicability of offsets, and the extent to which NRG would be entitled to receive CO 2 emissions credits without having to purchase them in an auction or on the open market. Thereafter, under any such legislation or regulation, the impact on NRG would depend on the Company's level of success in developing and deploying low and no carbon technologies.
Federal Environmental Initiatives
Environmental Regulatory Landscape — A number of regulations with the potential to affect the Company and it's facilities are in development or under review by the EPA: NSPS for GHGs, NAAQS revisions and implementation, coal combustion byproducts regulation, effluent guidelines and once-through cooling regulations. While most of these regulations have been considered for some time, the outcomes and any resulting impact on NRG cannot be fully predicted until the rules are finalized (and any resulting legal challenges resolved).
Air 
The CAA and the resulting regulations (as well as similar state and local requirements) have the potential to impact air emissions, operating practices and pollution control equipment at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO 2 , ozone, and PM 2.5 . Most of the Company's facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS have become more stringent and NRG expects that trend to continue. The Company expects increased regulation at both the federal and state levels of its air emissions and maintains a comprehensive compliance strategy to address these continuing and new requirements. Complying with increasingly stringent NAAQS may require the installation of additional emissions control equipment at some NRG facilities. Significant air regulatory programs to which the Company is subject are described below.
Mercury Air Toxic Standards — In February 2012, EPA promulgated standards to control emissions of HAPs from coal and oil-fired electric generating units. The MATS rule establishes limits for mercury, non-mercury metals, certain organics and acid gases, which limits must be met beginning in April 2015. NRG expects to meet these standards with the addition of controls, continued use of PRB coal in Louisiana, New York and Texas, and the retirement of some coal-fired units. NRG does not anticipate any plant impairments or capital expenditures beyond the current environmental capital expenditures schedule and planned retirements of Avon Lake, Niles, Portland, New Castle, and Titus to comply with MATS.
Cross-State Air Pollution Rule — In 2005, EPA promulgated CAIR which established SO2 and NOx cap-and-trade programs applicable directly to states and indirectly to generating facilities in the eastern United States. In July 2008, the D.C. Circuit in  State of North Carolina v. Environmental Protection Agency  issued an opinion that would have vacated CAIR. In December 2008 the D.C. Circuit issued a second opinion that simply remanded the case to the EPA without vacating CAIR.

In August 2011, EPA finalized CSAPR, which was intended to replace CAIR starting in 2012. It was designed to address interstate SO 2  and NO x  emissions from certain power plants in the eastern half of the United States. In September 2011, GenOn and others asked the D.C. Circuit to stay and vacate CSAPR because, among other reasons, the rule circumvents the state implementation plan process expressly provided for in the CAA, affords affected parties no time to install compliance equipment before the compliance period starts and includes numerous material changes from the proposed rule, which deprived parties of an opportunity to provide comments. In December 2011, the court ordered the EPA to stay implementation of CSAPR and to keep CAIR in place until the court ruled on the legal deficiencies alleged with respect to CSAPR. In August 2012, the D.C. Circuit issued an opinion vacating CSAPR and keeping CAIR in place. In October 2012, the EPA filed a petition asking the D.C. Circuit to rehear the case  en banc,  which was denied in January 2013.
 Byproducts, Wastes, Hazardous Materials and Contamination
In June 2010, the EPA proposed two alternatives for regulating byproducts of coal combustion (e.g., ash and gypsum) under the RCRA. Under the first proposal, these byproducts would be regulated as solid wastes. Under the second proposal, these byproducts would be regulated as “special wastes” in a manner similar to the regulation of hazardous waste with an exception for certain types of beneficial use of these byproducts. The second alternative would impose significantly more stringent requirements on and increase materially the cost of disposal of coal combustion byproducts.

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Domestic Site Remediation Matters
Under certain federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products at the facility. NRG may also be responsible for property damage, personal injury and investigation and remediation costs incurred by a party in connection with hazardous material releases or threatened releases. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980 as amended by the Superfund Amendments and Reauthorization Act of 1986, or SARA, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and the courts have interpreted liability under such laws to be strict (without fault) and joint and several. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills or other occurrences during its operations. Further discussions of affected NRG sites can be found in Item 15 — Note 23,  Environmental Matters , to the Consolidated Financial Statements.
Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. In order to meet the federal government's obligations to safely manage spent nuclear fuel, or SNF, and high-level radioactive waste, or HLW, under the U.S. Nuclear Waste Policy Act of 1982, or the Act, the U.S. DOE established a blue ribbon commission to explore alternatives. Also consistent with the Act, owners of nuclear plants, including the owners of STP, entered into contracts setting out the obligations of the owners and the U.S. DOE, including the fees to be paid by the owners for the U.S. DOE's services. Since 1998, the U.S. DOE has been in default on its obligations to begin removing SNF and HLW from reactors, necessitating each site to take steps to construct interim spent fuel storage installations.
On February 5, 2013, STPNOC entered into a settlement agreement with the U.S. DOE for payment of damages relating to the U.S. DOE's failure to accept SNF and HLW under the Act through December 31, 2013. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such facilities. STPNOC currently stores all SNF generated by its nuclear generating facilities in on-site storage pools.  Since STPNOC's SNF storage pools generally do not have sufficient storage capacity for the life of the units, STPNOC is evaluating alternatives with respect to on-site storage of SNF and expects to pursue dry cask storage.  STPNOC plans to continue to assert claims against the U.S. DOE for damages relating to the U.S. DOE's failure to accept SNF and HLW.
Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the state of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. STP's warehouse capacity is adequate for on-site storage until a site in Andrews County, Texas becomes fully operational.
Water 
Clean Water Act —The Company is required under the CWA to comply with intake and discharge requirements, requirements for technological controls and operating practices. As with air quality regulations, federal and state water regulations are expected to impose additional and more stringent requirements or limitations in the future. This includes regulatory requirements governing cooling water intake structures, which are subject to regulation under section 316(b) of the CWA (the 316(b) regulations). In April 2011, the EPA proposed a 316(b) rule that would apply to virtually all existing facilities, including power plants that use cooling water intake structures to withdraw water from waters of the United States. That proposal would impose national standards for reducing mortality from impingement and entrainment of organisms. The final rule may differ from the proposal as a result of the public comment process. States such as California and New York moved ahead with their own more stringent requirements for once-through cooled units, which may satisfy the requirements of the expected revised 316(b) Rule. NRG expects to comply with the applicable requirements with a mix of intake and operational modifications.

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Regional Environmental Initiatives
East
On February 7, 2013, RGGI, Inc. released a proposed model rule that if promulgated by the nine member states would dramatically reduce the CO 2  cap from 165 million tons to 91 million tons in 2014 with a 2.5% reduction each year from 2015 to 2020. The Company is evaluating the effect on our units located in Connecticut, Delaware, Maryland, Massachusetts and New York.
On July 20, 2011, the NYDEC announced the State's final policy on cooling water intake structures, confirming the Company's planned capital expenditure for cooling water intakes in that state. The Company expects to comply with these requirements with a mix of intake modifications already included in the planned environmental capital expenditures and operational changes.
In April 2009, the NJDEP finalized a regulation requiring a two-phased reduction in NOx emission from combustion turbines. The Company's planned capital expenditures include installation of controls at Sayreville and Gilbert by the 2014 compliance date.
The Maryland Healthy Air Act was enacted in 2006 and required staged reductions of SO2, NOx and mercury emissions from certain large coal fired facilities with a final reduction for SO 2  and mercury in 2013. The balance of the Maryland coal units control investment took place in 2012 and the Maryland coal units are capable of complying with limits that took effect in 2013.
The MDE sued GenOn for alleged violations of water pollution laws at three fly ash disposal sites in Maryland: Faulkner (2008/2011), Brandywine (2010), and Westland (2012).  The plants have since discontinued use of the Faulkner disposal site and opened a new, state of the art carbon burnout facility at its Morgantown plant that allows greater beneficial use (as a cement substitute of the flyash).  A detailed discussion on the legal proceedings can be found in Item 3 — Legal Proceedings,  Maryland Fly Ash Facilities .
South Central
On February 11, 2009, the U.S. DOJ acting at the request of the EPA commenced a lawsuit against Louisiana Generating, LLC in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant.  This is the same matter for which NOVs were issued to LaGen on February 15, 2005, and on December 8, 2006.  On November 20, 2012, the U.S. DOJ lodged a Consent Decree to resolve the complaint.  Further discussion can be found in Item 3 — Legal Proceedings,  United States of America v. Louisiana Generating, LLC .
West
The California Air Resources Board adopted the state's GHG cap-and-trade program under Assembly Bill 32, or AB32, on October 20, 2011. Participation by the electric generation sector began in 2013. The Company does not expect implementation of the GHG cap-and-trade program in California to have a significant adverse financial impact on the Company for a variety of reasons, including the fact that the portion of NRG's California portfolio that is merchant consists mainly of natural gas-fired facilities and the market price of power when dispatched is expected to have embedded in it the market price of allowances. The contracted portion of most of NRG's portfolio included pass-through language with respect to the obligation to purchase allowances. New NRG renewable projects in California markets will support AB32 requirements for the increased use of renewable energy.
The California statewide policy to mitigate once-through cooling was effective as of October 1, 2010. NRG's affected plants submitted alternative plans to meet equivalent mitigation criteria which are reflected in the current schedule of environmental capital expenditures. Specified compliance dates for NRG's power plants are: El Segundo- December 31, 2015; Contra Costa, Encina and Pittsburg - December 31, 2017; and Mandalay and Ormond Beach - December 31, 2020.
Environmental Capital Expenditures
Based on current rules, technology and plans, as well as preliminary plans based on proposed rules, NRG estimates that environmental capital expenditures from 2013 through 2017 required to comply with environmental laws will be approximately $630 million, consisting of $398 million for legacy NRG facilities and $232 million for GenOn facilities. These costs are primarily associated with controls to satisfy MATS at Big Cajun II, W.A. Parish, Limestone, and Conemaugh and NO x  controls at Sayreville and Gilbert. The decrease from NRG's previous estimate is a result of changes in technology related to MATS compliance at Big Cajun II- Unit 3, and shifts in compliance schedules. Testing and engineering to finalize cost estimates related to further changes on the Big Cajun II MATS compliance plan and the recent Consent Decree lodged in  United States of America v. Louisiana Generating, LLC  are underway, but costs are not expected to exceed the current plan. NRG continues to explore cost effective compliance alternatives to reduce costs.

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NRG's current contracts with the Company's rural electric cooperative customers in the South Central region allow for recovery of a portion of the environmental capital costs incurred as the result of complying with any change in environmental law. Cost recoveries begin once the environmental equipment becomes operational and include a capital return. The actual recoveries will depend, among other things, on the timing of the completion of the capital projects and the remaining duration of the contracts.
Employees
As of December 31, 2012, NRG had 8,792 employees, approximately 35% of whom were covered by U.S. bargaining agreements. During 2012, the Company did not experience any labor stoppages or labor disputes at any of its facilities.
Available Information
NRG'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.nrgenergy.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 the Company's website.

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Item 1A — Risk Factors Related to NRG Energy, Inc.
The Merger may not achieve its anticipated results, and NRG may be unable to integrate the operations of GenOn in the manner expected.
NRG and GenOn entered into the Merger Agreement with the expectation that the Merger will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the Merger depends on whether the businesses of NRG and GenOn can be integrated in an efficient and effective manner. The integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of NRG's businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect the Company's ability to achieve the anticipated benefits of the Merger. NRG may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect NRG's future business, financial condition, operating results and prospects.
Many of NRG's power generation facilities operate, wholly or partially, without long-term power sale agreements.
Many of NRG's facilities operate as "merchant" facilities without long-term power sales agreements for some or all of their generating capacity and output, and therefore are exposed to market fluctuations. Without the benefit of long-term power sales agreements for these assets, NRG 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 or to the closing of certain of its facilities, resulting in economic losses and liabilities, which could have a material adverse effect on the Company's results of operations, financial condition or cash flows.
NRG's financial performance may be impacted by changing natural gas prices, significant and unpredictable price fluctuations in the wholesale power markets and other market factors that are beyond the Company's control.
A significant percentage of the Company's domestic revenues are derived from baseload power plants that are fueled by coal. In many of the competitive markets where NRG operates, the price of power typically is set by natural gas-fired power plants that generally have higher variable costs than NRG's coal-fired power plants. This allows the Company's coal generation assets to earn attractive operating margins compared to plants fueled by natural gas. A decrease in natural gas prices could result in a corresponding decrease in the market price of power that could significantly reduce the operating margins of the Company's baseload generation assets and materially and adversely impact its financial performance. At low enough natural gas prices, gas plants become more economical than coal generation.  In such a price environment, the Company's coal units cycle more often or even shut down until prices or load increases enough to justify running them again.
In addition, because changes in power prices in the markets where NRG operates are generally correlated with changes in natural gas prices, NRG's hedging portfolio includes natural gas derivative instruments to hedge power prices for its coal and nuclear generation. If this correlation between power prices and natural gas prices is not maintained and a change in gas prices is not proportionately offset by a change in power prices, the Company's natural gas hedges may not fully cover this differential. This could have a material adverse impact on the Company's cash flow and financial position.

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Market prices for power, capacity and ancillary services tend to fluctuate substantially. Unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility from supply and demand imbalances, especially in the day-ahead and spot markets. Long- and short-term power prices may also fluctuate substantially due to other factors outside of the Company's control, including:
 	 	
•	changes in generation capacity in the Company's markets, including the addition of new supplies of power from existing competitors or new market entrants as a result of the development of new generation plants, expansion of existing plants or additional transmission capacity;	
 	 	
•	electric supply disruptions, including plant outages and transmission disruptions;	
 	 	
•	changes in power transmission infrastructure;	
 	 	
•	fuel transportation capacity constraints;	
 	 	
•	weather conditions;	
 	 	
•	changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices;	
 	 	
•	development of new fuels and new technologies for the production of power;	
 	 	
•	development of new technologies for the production of natural gas;	
 	 	
•	regulations and actions of the ISOs; and	
 	 	
•	federal and state power market and environmental regulation and legislation.	
These factors have caused the Company's operating results to fluctuate in the past and will continue to cause them to do so in the future.
NRG's costs, results of operations, financial condition and cash flows could be adversely impacted by disruption of its fuel supplies.
NRG relies on coal, oil and natural gas to fuel a majority of its power generation facilities. Delivery of these fuels to the facilities is dependent upon the continuing financial viability of contractual counterparties as well as upon the infrastructure (including rail lines, rail cars, barge facilities, roadways, riverways and natural gas pipelines) available to serve each generation facility. As a result, the Company is subject to the risks of disruptions or curtailments in the production of power at its generation facilities if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.
NRG has sold forward a substantial portion of its coal and nuclear power in order to lock in long-term prices that it deemed to be favorable at the time it entered into the forward sale contracts. In order to hedge its obligations under these forward power sales contracts, the Company has entered into long-term and short-term contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow the Company to pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. Disruptions in the Company's fuel supplies may therefore require it to find alternative fuel sources at higher costs, to find other sources of power to deliver to counterparties at a higher cost, or to pay damages to counterparties for failure to deliver power as contracted. Any such event could have a material adverse effect on the Company's financial performance.
NRG also buys significant quantities of fuel on a short-term or spot market basis. Prices for all of the Company's fuels fluctuate, sometimes rising or falling significantly over a relatively short period of time. The price NRG can obtain for the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. This may have a material adverse effect on the Company's financial performance. Changes in market prices for natural gas, coal and oil may result from the following:
 	 	
•	weather conditions;	
 	 	
•	seasonality;	
 	 	
•	demand for energy commodities and general economic conditions;	
 	 	
•	disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation;	
 	 	
•	additional generating capacity;	
 	 	
•	availability and levels of storage and inventory for fuel stocks;	
 	 	
•	natural gas, crude oil, refined products and coal production levels;	
 	 	
•	changes in market liquidity;	
 	 	
•	federal, state and foreign governmental regulation and legislation; and	
 	 	
•	the creditworthiness and liquidity and willingness of fuel suppliers/transporters to do business with the Company.	

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NRG's plant operating characteristics and equipment, particularly at its coal-fired plants, often dictate the specific fuel quality to be combusted. The availability and price of specific fuel qualities may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, coal of specific quality may not be available at any price, or the Company may not be able to transport such coal to its facilities on a timely basis. In this case, the Company may not be able to run the coal facility even if it would be profitable. Operating a coal facility with different quality coal can lead to emission or operating problems. If the Company had sold forward the power from such a coal facility, it could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on the financial results of specific plants and on the Company's results of operations.
There may be periods when NRG will not be able to meet its commitments under forward sale obligations at a reasonable cost or at all.
A substantial portion of the output from NRG's coal and nuclear facilities has been sold forward under fixed price power sales contracts through 2014, and the Company also sells forward the output from its intermediate and peaking facilities when it deems it commercially advantageous to do so. Because the obligations under most of these agreements are not contingent on a unit being available to generate power, NRG is generally required to deliver power to the buyer, even in the event of a plant outage, fuel supply disruption or a reduction in the available capacity of the unit. To the extent that the Company does not have sufficient lower cost capacity to meet its commitments under its forward sale obligations, the Company would be required to supply replacement power either by running its other, higher cost power plants or by obtaining power from third-party sources at market prices that could substantially exceed the contract price. If NRG fails to deliver the contracted power, it would be required to pay the difference between the market price at the delivery point and the contract price, and the amount of such payments could be substantial.
In the South Central region, NRG has long-term contracts with rural cooperatives that require it to serve all of the cooperatives' requirements at prices that generally reflect the costs of coal-fired generation. During limited peak demand periods, the load requirements of these contract customers exceed the capacity of NRG's coal-fired Big Cajun II plant. During such peak demand periods, NRG employs its intermediate and/or peaking facilities.  Depending upon the then-current gas commodity pricing, NRG's financial returns from its South Central region could be negatively impacted for a limited period if the cost of its intermediate and/or peaking power is at higher prices than can be recovered under the Company's contracts.  
NRG's trading operations and the use of hedging agreements could result in financial losses that negatively impact its results of operations.
The Company typically enters into hedging agreements, including contracts to purchase or sell commodities at future dates and at fixed prices, in order to manage the commodity price risks inherent in its power generation operations. These activities, although intended to mitigate price volatility, expose the Company to other risks. When the Company sells power forward, it gives up the opportunity to sell power at higher prices in the future, which not only may result in lost opportunity costs but also may require the Company to post significant amounts of cash collateral or other credit support to its counterparties. The Company also relies on counterparty performance under its hedging agreements and is exposed to the credit quality of its counterparties under those agreements. Further, if the values of the 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 Company's business, operating results or financial position.
NRG does not typically hedge the entire exposure of its operations against commodity price volatility. To the extent it does not hedge against commodity price volatility, the Company's results of operations and financial position may be improved or diminished based upon movement in commodity prices.
NRG may engage in trading activities, including the trading of power, fuel and emissions allowances that are not directly related to the operation of the Company's generation facilities or the management of related risks. These trading activities take place in volatile markets and some of these trades could be characterized as speculative. The Company would expect to settle these trades financially rather than through the production of power or the delivery of fuel. This trading activity may expose the Company to the risk of significant financial losses which could have a material adverse effect on its business and financial condition.
NRG may not have sufficient liquidity to hedge market risks effectively.
The Company is exposed to market risks through its power marketing business, which involves the sale of energy, capacity and related products and the purchase and sale of fuel, transmission services and emission allowances. These market risks include, among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel, converting fuel into energy and delivering the energy to a buyer.

35

NRG undertakes these marketing activities through agreements with various counterparties. Many of the Company's agreements with counterparties include provisions that require the Company to provide guarantees, offset of netting arrangements, letters of credit, a first lien on assets and/or cash collateral to protect the counterparties against the risk of the Company's default or insolvency. The amount of such credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in the Company being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of the Company's strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than the Company anticipates or will be able to meet. Without a sufficient amount of working capital to post as collateral in support of performance guarantees or as a cash margin, the Company may not be able to manage price volatility effectively or to implement its strategy. An increase in the amount of letters of credit or cash collateral required to be provided to the Company's counterparties may negatively affect the Company's liquidity and financial condition.
Further, if any of NRG's facilities experience unplanned outages, the Company may be required to procure replacement power at spot market prices in order to fulfill contractual commitments. Without adequate liquidity to meet margin and collateral requirements, the Company may be exposed to significant losses, may miss significant opportunities, and may have increased exposure to the volatility of spot markets.
The accounting for NRG's hedging activities may increase the volatility in the Company's quarterly and annual financial results.
NRG engages in commodity-related marketing and price-risk management activities in order to financially hedge its exposure to market risk with respect to electricity sales from its generation assets, fuel utilized by those assets and emission allowances.
NRG generally attempts to balance its fixed-price physical and financial purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. These derivatives are accounted for in accordance with the Financial Accounting Standards Board, or FASB, ASC 815, Derivatives and Hedging,  or ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value with changes in the fair value resulting from fluctuations in the underlying commodity prices immediately recognized in earnings, unless the derivative qualifies for cash flow hedge accounting treatment. Whether a derivative qualifies for cash flow hedge accounting treatment depends upon it meeting specific criteria used to determine if the cash flow hedge is and will remain appropriate for the term of the derivative. All economic hedges may not necessarily qualify for cash flow hedge accounting treatment. As a result, the Company's quarterly and annual results are subject to significant fluctuations caused by changes in market prices.
Competition in wholesale power markets may have a material adverse effect on NRG's results of operations, cash flows and the market value of its assets.
NRG has numerous competitors in all aspects of its business, and additional competitors may enter the industry. Because many of the Company's facilities are old, newer plants owned by the Company's competitors are often more efficient than NRG's aging plants, which may put some of these plants at a competitive disadvantage to the extent the Company's competitors are able to consume the same or less fuel as the Company's plants consume. Over time, the Company's plants may be squeezed out of their markets, or may be unable to compete with these more efficient plants.
In NRG's power marketing and commercial operations, it competes on the basis of its relative skills, financial position and access to capital with other providers of electric energy in the procurement of fuel and transportation services, and the sale of capacity, energy and related products. In order to compete successfully, the Company seeks to aggregate fuel supplies at competitive prices from different sources and locations and to efficiently utilize transportation services from third-party pipelines, railways and other fuel transporters and transmission services from electric utilities.
Other companies with which NRG competes with may have greater liquidity, greater access to credit and other financial resources, lower cost structures, more effective risk management policies and procedures, greater ability to incur losses, longer-standing relationships with customers, greater potential for profitability from ancillary services or greater flexibility in the timing of their sale of generation capacity and ancillary services than NRG does.
NRG's competitors may be able to respond more quickly to new laws or regulations or emerging technologies, or to devote greater resources to the construction, expansion or refurbishment of their power generation facilities than NRG can. In addition, current and potential competitors may make strategic acquisitions or establish cooperative relationships among themselves or with third parties. Accordingly, it is possible that new competitors or alliances among current and new competitors may emerge and rapidly gain significant market share. There can be no assurance that NRG will be able to compete successfully against current and future competitors, and any failure to do so would have a material adverse effect on the Company's business, financial condition, results of operations and cash flow.

36

Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on NRG's revenues and results of operations. NRG may not have adequate insurance to cover these risks and hazards.
The ongoing operation of NRG's facilities involves risks that include the breakdown or failure of equipment or processes, performance below expected levels of output or efficiency and the inability to transport the Company's product 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 Company's business. Unplanned outages typically increase the Company's operation and maintenance expenses and may reduce the Company's revenues as a result of selling fewer MWh or require NRG to incur significant costs as a result of running one of its higher cost units or obtaining replacement power from third parties in the open market to satisfy the Company's forward power sales obligations. NRG's inability to operate the Company's plants 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 Company's results of operations, financial condition or cash flows. While NRG 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 be adequate to cover the Company's lost revenues, increased expenses or liquidated damages payments should the Company 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, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in NRG 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. NRG maintains an amount of insurance protection that it considers adequate, but the Company cannot provide any assurance that its insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which it may be subject. A successful claim for which the Company is not fully insured could hurt its financial results and materially harm NRG's financial condition. Further, due to rising insurance costs and changes in the insurance markets, NRG 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 financial condition, results of operations or cash flows.
Maintenance, expansion and refurbishment of power generation facilities involve significant risks that could result in unplanned power outages or reduced output and could have a material adverse effect on NRG's results of operations, cash flow and financial condition.
Many of NRG's facilities are old and require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could result in reduced profitability.
NRG cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events (such as natural disasters or terrorist attacks). The unexpected requirement of large capital expenditures could have a material adverse effect on the Company's liquidity and financial condition.
If NRG makes any major modifications to its power generation facilities, the Company 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 federal Clean Air Act. Any such modifications would likely result in substantial additional capital expenditures.

37

The Company may incur additional costs or delays in the development, construction and operation of new plants, improvements to existing plants, or the implementation of environmental control equipment at existing plants and may not be able to recover their investment or complete the project.
The Company is developing or constructing new generation facilities, improving its existing facilities; and adding environmental controls to its existing facilities. The development, construction, expansion, modification and refurbishment of power generation facilities involve many additional risks, including:
 	 	
•	the inability to receive U.S. DOE loan guarantees, funding or cash grants;	
 	 	
•	delays in obtaining necessary permits and licenses;	
 	 	
•	the inability to sell down interests in a project or develop successful partnering relationships;	
 	 	
•	environmental remediation of soil or groundwater at contaminated sites;	
 	 	
•	interruptions to dispatch at the Company's facilities;	
 	 	
•	supply interruptions;	
 	 	
•	work stoppages;	
 	 	
•	labor disputes;	
 	 	
•	weather interferences;	
 	 	
•	unforeseen engineering, environmental and geological problems;	
 	 	
•	unanticipated cost overruns;	
 	 	
•	exchange rate risks; and	
 	 	
•	failure of contracting parties to perform under contracts, including EPC contractors.	
Any of these risks could cause NRG's financial returns on new investments to be lower than expected, or could cause the Company to operate below expected capacity or availability levels, which could result in lost revenues, increased expenses, higher maintenance costs and penalties. Insurance is maintained to protect against these risks, warranties are generally obtained for limited periods relating to the construction of each project and its equipment in varying degrees, and contractors and equipment suppliers are obligated to meet certain performance levels. The insurance, warranties or performance guarantees, however, may not be adequate to cover increased expenses. As a result, a project may cost more than projected and may be unable to fund principal and interest payments under its construction financing obligations, if any. A default under such a financing obligation could result in losing the Company's interest in a power generation facility.
Furthermore, where the Company has partnering relationships with a third party, the Company is subject to the viability and performance of the third party. The Company's inability to find a replacement contracting party, particularly an EPC contractor, where the original contracting party has failed to perform, could result in the abandonment of the development and/or construction of such project, while the Company could remain obligated on other agreements associated with the project, including PPAs.
If the Company is unable to complete the development or construction of a facility or environmental control, or decides to delay, downsize, or cancel such project, it may not be able to recover its investment in that facility or environmental control. Furthermore, if construction projects are not completed according to specification, the Company may incur liabilities and suffer reduced plant efficiency, higher operating costs and reduced net income.
NRG and its subsidiaries have guaranteed the performance of third parties, which may result in substantial costs in the event of non-performance.
NRG and its subsidiaries have issued certain guarantees of the performance of others, which obligate NRG and its subsidiaries to perform in the event that the third parties do not perform. In the event of non-performance by the third parties, NRG could incur substantial cost to fulfill their obligations under these guarantees. Such performance guarantees could have a material impact on the operating results, financial condition, or cash flows of the Company.

38

The Company's development programs are subject to financing and public policy risks that could adversely impact NRG's financial performance or result in the abandonment of such development projects.
While NRG currently intends to develop and finance the more capital intensive projects on a non-recourse or limited recourse basis through separate project financed entities, and intends to seek additional investments in most of these projects from third parties, NRG anticipates that it will need to make significant equity investments in these projects. NRG may also decide to develop and finance some of the projects, such as smaller gas-fired and renewable projects, using corporate financial resources rather than non-recourse debt, which could subject NRG to significant capital expenditure requirements and to risks inherent in the development and construction of new generation facilities. In addition to providing some or all of the equity required to develop and build the proposed projects, NRG's ability to finance these projects on a non-recourse basis is contingent upon a number of factors, including the terms of the EPC contracts, construction costs, PPAs and fuel procurement contracts, capital markets conditions, the availability of tax credits and other government incentives for certain new technologies. To the extent NRG is not able to obtain non-recourse financing for any project or should the credit rating agencies attribute a material amount of the project finance debt to NRG's credit, the financing of the development projects could have a negative impact on the credit ratings of NRG.
NRG may also choose to undertake the repowering, refurbishment or upgrade of current facilities based on the Company's assessment that such activity will provide adequate financial returns. Such projects often require several years of 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.
Furthermore, the viability of the Company's renewable development projects are largely contingent on public policy mechanisms including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, renewable portfolio standards, or 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 development program and expansion into clean energy investments.
Supplier and/or customer concentration at certain of NRG's facilities may expose the Company to significant financial credit or performance risks.
NRG often relies on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel and other services required for the operation of certain of its facilities. If these suppliers cannot perform, the Company utilizes the marketplace to provide these services. There can be no assurance that the marketplace can provide these services as, when and where required.
At times, NRG 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. The Company has also hedged a portion of its exposure to power price fluctuations through forward fixed price power sales and natural gas price swap agreements. Counterparties to these agreements may breach or may be unable to perform their obligations. NRG may not be able to enter into replacement agreements on terms as favorable as its existing agreements, or at all. If the Company was unable to enter into replacement PPA's, the Company would sell its plants' power at market prices. If the Company is unable to enter into replacement fuel or fuel transportation purchase agreements, NRG would seek to purchase the Company's fuel requirements 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 failure of any supplier or customer to fulfill its contractual obligations to NRG could have a material adverse effect on the Company's financial results. Consequently, the financial performance of the Company's facilities is dependent on the credit quality of, and continued performance by, suppliers and customers.

39

NRG relies on power transmission facilities that it does not own or control and that are subject to transmission constraints within a number of the Company's core regions. If these facilities fail to provide NRG with adequate transmission capacity, the Company may be restricted in its ability to deliver wholesale electric power to its customers and the Company may either incur additional costs or forego revenues. Conversely, improvements to certain transmission systems could also reduce revenues.
NRG depends on transmission facilities owned and operated by others to deliver the wholesale power it sells from the Company's power generation plants to its customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, NRG's ability to sell and deliver wholesale power may be adversely impacted. 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 sufficient incentive to invest in expansion of transmission infrastructure. The Company cannot also predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.
In addition, in certain of the markets in which NRG operates, energy transmission congestion may occur and the Company may be deemed responsible for congestion costs if it schedules delivery of power between congestion zones during times when congestion occurs between the zones. If NRG were liable for such congestion costs, the Company's financial results could be adversely affected.
The Company has a significant amount of generation located in load pockets, making that generation valuable, particularly with respect to maintaining the reliability of the transmission grid. Expansion of transmission systems to reduce or eliminate these load pockets could negatively impact the value or profitability of the Company's existing facilities in these areas.
Because NRG owns less than a majority of some of its project investments, the Company cannot exercise complete control over their operations.
NRG has limited control over the operation of some project investments and joint ventures because the Company's investments are in projects where it beneficially owns less than a majority of the ownership interests. NRG seeks to exert a degree of influence with respect to the management and operation of projects in which it owns less than a majority of the ownership 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. NRG may be dependent on its co-venturers to operate such projects. The Company's co-venturers may not have the level of experience, technical expertise, human resources management and other attributes necessary to operate these projects optimally. The approval of co-venturers also may be required for NRG to receive distributions of funds from projects or to transfer the Company's interest in projects.
Future acquisition activities may have adverse effects.
NRG may seek to acquire additional companies or assets in the Company's industry or which complement the Company's industry. The acquisition of companies and assets is subject to substantial risks, including the failure to identify material problems during due diligence, the risk of over-paying for assets, the ability to retain customers and the inability to arrange financing for an acquisition as may be required or desired. Further, the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, the Company's acquisitions may 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 indebtedness incurred to acquire them or the capital expenditures needed to develop them.
NRG's business is subject to substantial governmental regulation and may be adversely affected by legislative or regulatory changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
NRG's business is subject to extensive foreign, and 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.

40

Public utilities under the FPA are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Except for ERCOT generating facilities and power marketers, all of NRG's non-qualifying facility generating companies and power marketing affiliates in the U.S. make sales of electricity in interstate commerce and are public utilities for purposes of the FPA. The FERC has granted each of NRG's generating and power marketing companies that make sales of electricity outside of ERCOT the authority to sell electricity at market-based rates. The FERC's orders that grant NRG's generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that NRG can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, NRG's market-based sales are subject to certain market behavior rules, and if any of NRG's generating and power marketing companies were deemed to have violated one of those rules, they are subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority. If NRG's generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC's acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates NRG charges for power from its facilities.
NRG is also 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 ISOs. The 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 an adverse effect on the profitability of NRG's generation facilities that sell energy and capacity into the wholesale power markets.
The regulatory environment has undergone significant changes in the last several years due to state and federal policies affecting wholesale and retail competition and the creation of incentives for the addition of large amounts of new renewable generation and, in some cases, transmission. 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 NRG's business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, as well as proposals to re-regulate the markets or require divestiture by generating companies 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.
NRG cannot predict at this time the outcome of the ongoing efforts by the CFTC to implement the Dodd-Frank Act and to increase the regulation of over-the-counter derivatives including those related to energy commodities. The CFTC efforts are seeking, among other things, increased clearing of such derivatives through clearing organizations and the increased standardization of contracts, products, and collateral requirements. Such changes could negatively impact NRG's ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, limiting NRG's ability to utilize liens as collateral and decreasing liquidity in the forward commodity markets. The Company expects that in 2013 the CFTC will clarify the scope of the Dodd-Frank Act and issue final rules concerning margin requirements for transactions and other issues that will affect the Company's over-the-counter derivatives trading.
NRG's ownership interest in a nuclear power facility subjects the Company to regulations, costs and liabilities uniquely associated with these types of facilities.
Under the Atomic Energy Act of 1954, as amended, or AEA, operation of STP, of which NRG indirectly owns a 44.0% interest, is subject to regulation by the NRC. Such regulation includes licensing, inspection, enforcement, testing, evaluation and modification of all aspects of nuclear reactor power plant design and operation, environmental and safety performance, technical and financial qualifications, decommissioning funding assurance and transfer and foreign ownership restrictions. NRG's 44% share of the output of STP represents approximately 1,175 MW of generation capacity.

41

There are unique risks to owning and operating a nuclear power facility. These include liabilities related to the handling, treatment, storage, disposal, transport, release and use of radioactive materials, particularly with respect to spent nuclear fuel, and uncertainties regarding the ultimate, and potential exposure to, technical and financial risks associated with modifying or decommissioning a nuclear facility. The NRC could require the shutdown of the plant for safety reasons or refuse to permit restart of the unit after unplanned or planned outages. New or amended NRC safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures. STP may be obligated to continue storing spent nuclear fuel if the U.S. DOE continues to fail to meet its contractual obligations to STP made pursuant to the U.S. Nuclear Waste Policy Act of 1982 to accept and dispose of STP's spent nuclear fuel. See also Item 1  — Environmental Matters — U.S. Federal Environmental Initiatives — Nuclear Waste  for further discussion. Costs associated with these risks could be substantial and have a material adverse effect on NRG's results of operations, financial condition or cash flow. In addition, to the extent that all or a part of STP is required by the NRC to permanently or temporarily shut down or modify its operations, or is otherwise subject to a forced outage, NRG may incur additional costs to the extent it is obligated to provide power from more expensive alternative sources — either NRG's own plants, third party generators or the ERCOT — to cover the Company's then existing forward sale obligations. Such shutdown or modification could also lead to substantial costs related to the storage and disposal of radioactive materials and spent nuclear fuel.
While STP maintains property and liability insurance for losses related to nuclear operations, there may be limitations on the amounts and types of insurance commercially available. An accident at STP or another nuclear facility could have a material adverse effect on NRG's financial condition, its operational results, or liquidity as losses may exceed the insurance coverage available and/or may result in the obligation to pay retrospective premium obligations.
NRG is subject to environmental laws that impose extensive and increasingly stringent requirements on the Company's ongoing operations, as well as potentially substantial liabilities arising out of environmental contamination. These environmental requirements and liabilities could adversely impact NRG's results of operations, financial condition and cash flows.
NRG's business is subject to the environmental laws of Australian and U.S., federal, state and local authorities. The Company must comply with numerous environmental laws and obtain numerous governmental permits and approvals to build and operate the Company's plants. Should NRG fail to comply with any environmental requirements that apply to its operations, the Company could be subject to administrative, civil and/or criminal liability and fines, and regulatory agencies could take other actions seeking to curtail the Company's operations. In addition, when new requirements take effect or when existing environmental requirements are revised, reinterpreted or subject to changing enforcement policies, NRG's business, results of operations, financial condition and cash flows could be adversely affected.
Environmental laws and regulations have generally become more stringent over time, and the Company expects this trend to continue. Regulations currently under revision by the EPA, including the 316(b) rule to mitigate impact by once-through cooling, could result in more stringent standards or reduced compliance flexibility. While the NRG fleet employs advanced controls, new regulations to address the ever more stringent NAAQS, limit GHG emissions, or restrict ash handling at coal-fired power plants could also further affect plant operations.
Policies at the national, regional and state levels to regulate GHG emissions, as well as climate change, could adversely impact NRG's results of operations, financial condition and cash flows.
NRG's GHG emissions for 2012 can be found in Item 1, Business - Environmental Matters. The impact of further legislation or regulation of GHGs on the Company's financial performance will depend on a number of factors, including the level of GHG standards, the extent to which mitigation is required, the applicability of offsets, and the extent to which NRG would be entitled to receive CO 2 emissions credits without having to purchase them in an auction or on the open market.
The Company operates generating units in Connecticut, Delaware, Maryland, Massachusetts, and New York that are subject to RGGI, which is a regional cap and trade system. In February 2013, RGGI, Inc. released a model rule that if adopted by the member states would reduce the number of allowances available and potentially increase the price of each allowance. The impact on future power prices could adversely impact NRG's results of operations, financial condition and cash flows.
The California CO2 cap and trade program for electric generating units greater than 25 MW commenced in 2013. The impact on the Company depends on the cost of the allowances and the ability to pass these costs through to customers.
GHG emissions from power plants are regulated under various section of the CAA. In 2012, EPA proposed stringent standards for GHG emissions from certain new fossil-fueled electric generating units (simple-cycle CTs are not covered). The proposed standard is in effect until the rule is finalized. The Company expects EPA to issue another rule that will require states to develop CO2 standards that would apply to existing fossil-fueled generating facilities at some future date. This rule could adversely impact NRG's results of operations, financial condition and cash flows.

42

Hazards customary to the power production industry include the potential for unusual weather conditions, which could affect fuel pricing and availability, the Company's route to market or access to customers, i.e., transmission and distribution lines, or critical plant assets. To the extent that climate change contributes to the frequency or intensity of weather related events, NRG's operations and planning process could be impacted.
NRG's business, financial condition and results of operations could be adversely impacted by strikes or work stoppages by its unionized employees or inability to replace employees as they retire.
As of December 31, 2012, approximately 51% of NRG's employees at its U.S. generation plants were covered by collective bargaining agreements. In the event that the Company's union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, NRG would be responsible for procuring replacement labor or the Company could experience reduced power generation or outages. NRG's ability to procure such labor is uncertain. Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms could have a material adverse effect on the Company's business, financial condition, results of operations and cash flow. In addition, a number of the Company's employees at NRG's plants are close to retirement. The Company's inability to replace those workers could create potential knowledge and expertise gaps as those workers retire.
Changes in technology may impair the value of NRG's power plants.
Research and development activities are ongoing to provide alternative and more efficient technologies to produce power, including "clean" coal and coal gasification, wind, photovoltaic (solar) cells, energy storage, and improvements in traditional technologies and equipment, such as more efficient gas turbines. Advances in these or other technologies could reduce the costs of power production to a level below what the Company has currently forecasted, which could adversely affect its cash flow, results of operations or competitive position.
Risks that are beyond NRG'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 NRG's financial condition, results of operations and cash flows.
NRG's generation facilities 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 distribution systems, could severely disrupt business operations and result in loss of service to customers, as well as significant expense to repair security breaches or system damage. Any such environmental repercussions or disruption 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 Company's financial condition, results of operations and cash flow.
NRG's level of indebtedness could adversely affect its ability to raise additional capital to fund its operations, or return capital to stockholders. It could also expose it to the risk of increased interest rates and limit its ability to react to changes in the economy or its industry.
NRG's substantial debt could have negative consequences, including:
 	 	
•	increasing NRG's vulnerability to general economic and industry conditions;	
 	 	
•	requiring a substantial portion of NRG's cash flow from operations to be dedicated to the payment of principal and interest on its indebtedness, therefore reducing NRG's ability to pay dividends to holders of its preferred or common stock or to use its cash flow to fund its operations, capital expenditures and future business opportunities;	
 	 	
•	limiting NRG's ability to enter into long-term power sales or fuel purchases which require credit support;	
 	 	
•	exposing NRG to the risk of increased interest rates because certain of its borrowings, including borrowings under its senior secured credit facility are at variable rates of interest;	
 	 	
•	limiting NRG'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 NRG's ability to adjust to changing market conditions and placing it at a competitive disadvantage compared to its competitors who have less debt.	

43

The indentures for NRG's notes and senior secured credit facility contain financial and other restrictive covenants that may limit the Company's ability to return capital to stockholders or otherwise engage in activities that may be in its long-term best interests. NRG's failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of the Company's indebtedness.
In addition, NRG'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 NRG, its partners and the regional wholesale power markets;	
 	 	
•	NRG's financial performance and the financial performance of its subsidiaries;	
 	 	
•	NRG's level of indebtedness and compliance with covenants in debt agreements;	
 	 	
•	maintenance of acceptable credit ratings;	
 	 	
•	cash flow; and	
 	 	
•	provisions of tax and securities laws that may impact raising capital.	
NRG may not be successful in obtaining additional capital for these or other reasons. The failure to obtain additional capital from time to time may have a material adverse effect on its business and operations.
Goodwill and/or other intangible assets not subject to amortization that NRG has recorded in connection with its acquisitions are subject to mandatory annual impairment evaluations and as a result, the Company could be required to write off some or all of this goodwill and other intangible assets, which may adversely affect the Company's financial condition and results of operations.
In accordance with ASC 350, Intangibles — Goodwill and Other, or ASC 350, goodwill is not amortized but is reviewed annually or more frequently for impairment and other intangibles are also reviewed at least annually or more frequently, if certain conditions exist, and may be amortized. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings which could materially adversely affect NRG's reported results of operations and financial position in future periods.
A valuation allowance may be required for NRG's deferred tax assets.

A valuation allowance may need to be recorded against 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. A valuation allowance related to deferred tax assets can be affected by changes to tax laws, statutory tax rates and future taxable income levels. In the event that the Company determines that it would not be able to realize all or a portion of its 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.

Volatile power supply costs and demand for power could adversely affect the financial performance of NRG's Retail Business.
Although NRG is the primary provider of the Retail Business supply requirements, the Retail Business purchases a significant portion of its supply requirements from third parties. As a result, financial performance depends on its ability to obtain adequate supplies of electric generation from third parties at prices below the prices it charges its customers. Consequently, the Company's earnings and cash flows could be adversely affected in any period in which the Retail Business power supply costs rise at a greater rate than the rates it charges to customers. The price of power supply purchases associated with the Retail Business's energy commitments can be different than that reflected in the rates charged to customers due to, among other factors:
 	 	
•	varying supply procurement contracts used and the timing of entering into related contracts;	
 	 	
•	subsequent changes in the overall price of natural gas;	
 	 	
•	daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;	
 	 	
•	transmission constraints and the Company's ability to move power to its customers; and	
 	 	
•	changes in market heat rate (i.e., the relationship between power and natural gas prices).	

44

The Company's earnings and cash flows could also be adversely affected in any period in which the demand for power significantly varies from the forecasted supply, which could occur due to, among other factors, weather events, competition and economic conditions.
Significant events beyond the Company's control, such as hurricanes and other weather-related problems or acts of terrorism, could cause a loss of load and customers and thus have a material adverse effect on the Company's Retail Business.
The uncertainty associated with events beyond the Company's control, such as significant weather events and the risk of future terrorist activity, could cause a loss of load and customers and may affect the Company's results of operations and financial condition in unpredictable ways. In addition, significant weather events or terrorist actions could damage or shut down the power transmission and distribution facilities upon which the Retail Business is dependent. Power supply may be sold at a loss if these events cause a significant loss of retail customer load.
The Company's Retail Business may lose a significant number of retail customers due to competitive marketing activity by other retail electricity providers which could adversely affect the financial performance of NRG's Retail Business.
The Retail Business faces competition for customers. Competitors may offer lower prices and other incentives, which may attract customers away from the Retail Business. In some retail electricity markets, the principal competitor may be the incumbent retail electricity provider. The incumbent retail electricity provider has the advantage of long-standing relationships with its customers, including well-known brand recognition. Furthermore, the Retail Business may face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop businesses that will compete with NRG and its Retail Business.
The Company's Retail Business is subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to its reputation and/or the results of operations of the Retail Business.
The Retail Business requires access to sensitive customer data in the ordinary course of business. Examples of sensitive customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, drivers license numbers, social security numbers and bank account information. The Retail Business may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the Retail Business. If a significant breach occurred, the reputation of NRG and the Retail Business may be adversely affected, customer confidence may be diminished, or NRG and the Retail Business may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the business and/or results of operations.

45

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION
This Annual Report on Form 10-K of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or 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 NRG'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 Related to NRG Energy, Inc.  and the following:
 	 	
•	General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;	
 	 	
•	Volatile power supply costs and demand for power;	
 	 	
•	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 NRG may not have adequate insurance to cover losses as a result of such hazards;	
 	 	
•	The effectiveness of NRG's risk management policies and procedures, and the ability of NRG's counterparties to satisfy their financial commitments;	
 	 	
•	Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition;	
 	 	
•	NRG's ability to operate its businesses efficiently, manage capital expenditures and costs tightly, and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;	
 	 	
•	NRG's ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;	
 	 	
•	The liquidity and competitiveness of wholesale markets for energy commodities;	
 	 	
•	Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws and increased regulation of carbon dioxide and other greenhouse gas emissions;	
 	 	
•	Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately compensate NRG's generation units for all of its costs;	
 	 	
•	NRG's ability to borrow additional funds and access capital markets, as well as NRG's substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward;	
 	 	
•	NRG's ability to receive Federal loan guarantees or cash grants to support development projects;	
 	 	
•	Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG's outstanding notes, in NRG's Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;	
 	 	
•	NRG's ability to implement its strategy of developing and building new power generation facilities, including new solar projects;	
 	 	
•	NRG's ability to implement its econrg strategy of finding ways to address environmental challenges while taking advantage of business opportunities;	
 	 	
•	NRG's ability to implement its FORNRG strategy to increase cash from operations through operational and commercial initiatives, corporate efficiencies, asset strategy, and a range of other programs throughout the company to reduce costs or generate revenues;	
 	 	
•	NRG's ability to achieve its strategy of regularly returning capital to stockholders;	
 	 	
•	NRG's ability to maintain retail market share;	
 	 	
•	NRG's ability to successfully evaluate investments in new business and growth initiatives;	
 	 	
•	NRG's ability to successfully integrate and manage any acquired businesses;	
 	 	
•	NRG's ability to develop and maintain successful partnering relationships; and	
 	 	
•	NRG's ability to integrate the businesses and realize cost savings related to the merger with GenOn Energy, Inc.	
Forward-looking statements speak only as of the date they were made, and NRG Energy, Inc. 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 NRG'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.

46

Item 2 — Properties
Listed below are descriptions of NRG's interests in facilities, operations and/or projects owned or leased as of December 31, 2012. The MW figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the Company's ownership position excluding capacity from inactive/mothballed units as of December 31, 2012. The following table summarizes NRG's power production and cogeneration facilities by region:

Name and Location of Facility	Power Market	 	% Owned (a)(b)	 	Net
Generation
Capacity (MW)  (c)	 	Primary Fuel-type	
Texas Region:	 	 	 	 	 	 	 	
Cedar Bayou, Baytown, TX	ERCOT	 	100.0	 	1,495	
 	 	Natural Gas	
Cedar Bayou 4, Baytown, TX	ERCOT	 	50.0	 	260	
 	 	Natural Gas	
Greens Bayou, Houston, TX	ERCOT	 	100.0	 	660	
 	 	Natural Gas	
Limestone, Jewett, TX	ERCOT	 	100.0	 	1,690	
 	 	Coal	
San Jacinto, LaPorte, TX	ERCOT	 	100.0	 	160	
 	 	Natural Gas	
South Texas Project, Bay City, TX (d)	ERCOT	 	44.0	 	1,175	
 	 	Nuclear	
S. R. Bertron, Deer Park, TX (e)	ERCOT	 	100.0	 	765	
 	 	Natural Gas	
T. H. Wharton, Houston, TX	ERCOT	 	100.0	 	1,025	
 	 	Natural Gas	
W. A. Parish, Thompsons, TX	ERCOT	 	100.0	 	2,505	
 	 	Coal	
W. A. Parish, Thompsons, TX 	ERCOT	 	100.0	 	1,145	
 	 	Natural Gas	
 	Total Texas Region:	 	10,880	
 	 	 	
East Region:	 	 	 	 	 	 	 	
Arthur Kill, Staten Island, NY	NYISO	 	100.0	 	860	
 	 	Natural Gas	
Astoria Gas Turbines, Queens, NY	NYISO	 	100.0	 	475	
 	 	Natural Gas	
Aurora, IL	PJM	 	100.0	 	880	
 	 	Natural Gas	
Avon Lake, OH (f)	PJM	 	100.0	 	730	
 	 	Coal	
Avon Lake, OH	PJM	 	100.0	 	20	
 	 	Oil	
Blossburg, PA	PJM	 	100.0	 	20	
 	 	Natural Gas	
Bowline, West Haverstraw, NY	NYISO	 	100.0	 	755	
 	 	Natural Gas	
Brunot Island, Pittsburg, PA	PJM	 	100.0	 	260	
 	 	Natural Gas	
Canal, Sandwich, MA	ISO-NE	 	100.0	 	1,110	
 	 	Oil	
Chalk Point, Aquasco, MD	PJM	 	100.0	 	665	
 	 	Coal	
Chalk Point, Aquasco, MD	PJM	 	100.0	 	1,690	
 	 	Natural Gas	
Cheswick, Springdale, PA	PJM	 	100.0	 	565	
 	 	Coal	
Conemaugh, New Florence, PA	PJM	 	20.2	(a) 	340	
 	 	Coal	
Conemaugh, New Florence, PA	PJM	 	20.2	(a) 	5	
 	 	Oil	
Connecticut Jet Power, CT (four sites)	ISO-NE	 	100.0	 	140	
 	 	Oil	
Devon, Milford, CT	ISO-NE	 	100.0	 	135	
 	 	Oil	
Dickerson, MD	PJM	 	100.0	(b) 	535	
 	 	Coal	
Dickerson, MD	PJM	 	100.0	(b) 	310	
 	 	Natural Gas	
Dunkirk, NY	NYISO	 	100.0	 	150	
 	 	Coal	
GenConn Devon, Milford, CT	ISO-NE	 	50.0	 	95	
 	 	Oil	
GenConn Middletown, CT	ISO-NE	 	50.0	 	95	
 	 	Oil	
Gilbert, Milford, NJ (f)	PJM	 	100.0	 	535	
 	 	Natural Gas	
Glen Gardner, NJ (f)	PJM	 	100.0	 	160	
 	 	Natural Gas	
Hamilton, East Berlin, PA	PJM	 	100.0	 	20	
 	 	Oil	
Hunterstown CCGT, Gettysburg, PA	PJM	 	100.0	 	810	
 	 	Natural Gas	
Hunterstown, CTS, Gettysburg, PA	PJM	 	100.0	 	60	
 	 	Natural Gas	
Huntley, Tonawanda, NY	NYISO	 	100.0	 	380	
 	 	Coal	
Indian River, Millsboro, DE (g)	PJM	 	100.0	 	550	
 	 	Coal	

47

 	
 	 	 	 	 	 	 	 	 	
Indian River, Millsboro, DE 	PJM	 	100.0	 	15	
 	 	Oil	
Kendall, Cambridge, MA	ISO-NE	 	100.0	 	260	
 	 	Natural Gas	
Keystone, Shelocta, PA	PJM	 	20.4	(a) 	345	
 	 	Coal	
Keystone, Shelocta, PA	PJM	 	20.4	(a) 	5	
 	 	Oil	
Martha's Vineyard, MA	ISO-NE	 	100.0	 	15	
 	 	Oil	
Middletown, CT	ISO-NE	 	100.0	 	770	
 	 	Oil	
Montville, Uncasville, CT	ISO-NE	 	100.0	 	495	
 	 	Oil	
Morgantown, Newburg, MD	PJM	 	100.0	(b) 	1,230	
 	 	Coal	
Morgantown, Newburg, MD	PJM	 	100.0	(b) 	250	
 	 	Oil	
Mountain, Mount Holly Springs, PA	PJM	 	100.0	 	40	
 	 	Oil	
New Castle, West Pittsburgh, PA (f)	PJM	 	100.0	 	325	
 	 	Coal	
New Castle, West Pittsburgh, PA (f)	PJM	 	100.0	 	5	
 	 	Oil	
Niles, OH	PJM	 	100.0	 	25	
 	 	Oil	
Norwalk Harbor, So. Norwalk, CT	ISO-NE	 	100.0	 	340	
 	 	Oil	
Orrtana, PA	PJM	 	100.0	 	20	
 	 	Oil	
Oswego, NY	NYISO	 	100.0	 	1,630	
 	 	Oil	
Osceola, Holopaw, FL	FRCC	 	100.0	 	460	
 	 	Natural Gas	
Portland, Mouth Bethel, PA (f)	PJM	 	100.0	 	400	
 	 	Coal	
Portland, Mouth Bethel, PA	PJM	 	100.0	 	170	
 	 	Oil	
Sayreville, NJ	PJM	 	100.0	 	225	
 	 	Natural Gas	
Seward, New Florence, PA	PJM	 	100.0	 	525	
 	 	Coal	
Shawnee, East Stroudsburg, PA	PJM	 	100.0	 	20	
 	 	Oil	
Shawville, PA (h)	PJM	 	100.0	(b) 	600	
 	 	Coal	
Shawville, PA	PJM	 	100.0	(b) 	5	
 	 	Oil	
Titus, Birdsboro, PA (f)	PJM	 	100.0	 	245	
 	 	Coal	
Titus, Birdsboro, PA	PJM	 	100.0	 	30	
 	 	Oil	
Tolna, Stewardstown, PA	PJM	 	100.0	 	40	
 	 	Oil	
Vienna, MD	PJM	 	100.0	 	165	
 	 	Oil	
Warren, PA	PJM	 	100.0	 	55	
 	 	Natural Gas	
Werner, South Amboy, NJ (f)	PJM	 	100.0	 	210	
 	 	Oil	
 	Total East Region:	 	21,270	
 	 	 	
South Central Region:	 	 	 	 	 	 	 	
Bayou Cove, Jennings, LA	SERC-Entergy	 	100.0	 	300	
 	 	Natural Gas	
Big Cajun I, Jarreau, LA	SERC-Entergy	 	100.0	 	430	
 	 	Natural Gas	
Big Cajun II, New Roads, LA	SERC-Entergy	 	85.8	(i) 	1,495	
 	 	Coal	
Choctaw, French Camp, MS	SERC-Entergy	 	100.0	 	800	
 	 	Natural Gas	
Cottonwood, Deweyville, TX	SERC-Entergy	 	100.0	 	1,265	
 	 	Natural Gas	
Rockford, IL	PJM	 	100.0	 	450	
 	 	Natural Gas	
Sabine Cogen, Orange, TX	SERC-Entergy	 	50.0	 	55	
 	 	Natural Gas	
Shelby County, Neoga, IL	MISO	 	100.0	 	345	
 	 	Natural Gas	
Sterlington, LA	SERC-Entergy	 	100.0	 	175	
 	 	Natural Gas	
 	Total South Central Region:	 	5,315	
 	 	 	
West Region:	 	 	 	 	 	 	 	
Contra Costa, Antioch, CA (f)	CAISO	 	100.0	 	675	
 	 	Natural Gas	
Coolwater, Dagget, CA	CAISO	 	100.0	 	635	
 	 	Natural Gas	
El Segundo Power, CA (j)	CAISO	 	100.0	 	670	
 	 	Natural Gas	
Ellwood, Goleta, CA	CAISO	 	100.0	 	55	
 	 	Natural Gas	
Encina, Carlsbad, CA	CAISO	 	100.0	 	965	
 	 	Natural Gas	
Etiwanda, Rancho Cucamonga, CA	CAISO	 	100.0	 	640	
 	 	Natural Gas	
Long Beach, CA	CAISO	 	100.0	 	260	
 	 	Natural Gas	

48

 	
 	 	 	 	 	 	 	 	 	
Mandalay, Oxnard, CA	CAISO	 	100.0	 	560	
 	 	Natural Gas	
Ormond Beach, Oxnard, CA	CAISO	 	100.0	 	1,515	
 	 	Natural Gas	
Pittsburg, CA	CAISO	 	100.0	 	1,310	
 	 	Natural Gas	
Saguaro Power Co., Henderson, NV	WECC	 	50.0	 	45	
 	 	Natural Gas	
San Diego Combustion Turbines, CA (three sites) (k)	CAISO	 	100.0	 	190	
 	 	Natural Gas	
 	Total West Region:	 	7,520	
 	 	 	
Alternative Energy:	 	 	 	 	 	 	 	
Agua Caliente, Dateland, AZ	CAISO/WECC	 	51.0	 	130	
 	 	Solar	
Avenal, CA	CAISO	 	50.0	 	25	
 	 	Solar	
Avra Valley, Pima County, AZ	WECC	 	100.0	 	25	
 	 	Solar	
Blythe, CA	CAISO	 	100.0	 	20	
 	 	Solar	
California Valley Solar Ranch, San Luis Obispo County, CA	CAISO/WECC	 	100.0	 	125	
 	 	Solar	
Distributed Solar, AZ	AZNMSN/WECC	 	100.0	 	40	
 	 	Solar	
Roadrunner, Santa Teresa, NM	EPE	 	100.0	 	20	
 	 	Solar	
Elbow Creek Wind Farm, Howard County, TX	ERCOT	 	100.0	 	125	
 	 	Wind	
Langford Wind Farm, Christoval, TX	ERCOT	 	100.0	 	150	
 	 	Wind	
Sherbino Wind Farm, Pecos County, TX	ERCOT	 	50.0	 	75	
 	 	Wind	
South Trent Wind Farm, Sweetwater, TX	ERCOT	 	100.0	 	100	
 	 	Wind	
 	Total Alternative Energy:	 	835	
 	 	 	
Other Conventional Generation:	 	 	 	 	 	 	 	
Paxton Creek Cogeneration, Harrisburg, PA	PJM	 	100.0	 	10	
 	 	Natural Gas	
Dover Cogeneration, DE	PJM	 	100.0	 	15	
 	 	Coal	
Dover Cogeneration, DE	PJM	 	100.0	 	90	
 	 	Natural Gas	
Princeton Hospital, NJ (l)	PJM	 	100.0	 	5	
 	 	Natural Gas	
Gladstone Power Station, Queensland, Australia	Enertrade/Boyne Smelter	 	37.5	 	605	
 	 	Coal	
 	Total Other:	 	725	
 	 	 	
Total NRG Generation Capacity:	 	 	 	 	46,545	

(a)	NRG has 16.5% and 16.7% leased interests in the Conemaugh and Keystone facilities, respectively, as well as 3.7% ownership interests in each facility. NRG operates the Conemaugh and Keystone facilities.	
 	 	
(b)	NRG leases 100% interests in the Dickerson and Morgantown coal generation units through facility lease agreements expiring in 2029 and 2034, respectively. NRG owns 310 MW and 250 MW of peaking capacity at the Dickerson and Morgantown generating facilities, respectively. NRG also leases a 100% interest in Shawville through a facility lease agreement expiring in 2026. NRG operates the Dickerson, Morgantown and Shawville facilities.	
 	 	
(c)	Actual capacity can vary depending on factors including weather conditions, operational conditions, and other factors. Additionally, ERCOT requires periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time.	
 	 	
(d)	Generation capacity figure consists of the Company's 44% individual interest in the two units at STP.	
 	 	
(e)	The four S. R. Bertron steam units and blackstart unit are currently mothballed according to ERCOT protocols, but all operated in 2012.	
 	 	
(f)	NRG expects to deactivate net generation capacity at the following facilities acquired through the GenOn Merger:	

 	 	 	 	
Facility	Expected
Deactivation Date	Net Generation
Capacity (MW)	
Avon Lake	April 2015	730	
 	
Contra Costa	May 2013	675	
 	
Gilbert	May 2015	190	
 	
Glen Gardner	May 2015	160	
 	
New Castle	April 2015	330	
 	
Portland	January 2015	400	
 	
Titus	April 2015	245	
 	
Werner	May 2015	210	

(g)	NRG will deactivate the Indian River 150 MW Unit 3 by December 31, 2013.	
 	 	
(h)	NRG expects to place the coal-fired units at the Shawville generating facility (600 MW) in long-term protective layup in April 2015.	
 	 	
(i)	Units 1 and 2 owned 100.0%, Unit 3 owned 58.0%.	
 	 	
(j)	NRG is required to deactivate the 335 MW unit 3 within 90 days from the date of first fire of the second unit at the El Segundo Energy Center which is under construction.  This deactivation is currently estimated to occur by the end of the second quarter in 2013.	
 	 	
(k)	NRG operates these units, located on property owned by San Diego Gas & Electric, under a license agreement.  The initial term of the license is set to end on December 31, 2013.	
 	 	
(l)	The output of Princeton Hospital is primarily dedicated to serving the hospital.  Excess power is sold to the local utility under its state-jurisdictional tariff. 	

49

Thermal Facilities
The Company's thermal businesses in Pittsburgh, Harrisburg and San Francisco are regulated by their respective state's Public Utility Commission. The other thermal businesses are subject to contract terms with their customers.
The following table summarizes NRG's thermal steam and chilled water facilities as of December 31, 2012:

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	 	334
141	
 	 	Steam: 1,140 MMBtu/hr.
Chilled Water: 40,200 tons	
NRG Energy Center San Francisco, CA	100.0	
 	 	Approx 175 steam customers	 	133	
 	 	Steam: 454 MMBtu/hr.	
NRG Energy Center Harrisburg, PA	100.0	
 	 	Approx 140 steam and 3 chilled water customers	 	129
8	
 	 	Steam: 440 MMBtu/hr.
Chilled water: 2,400 tons	
NRG Energy Center Phoenix, AZ	100.0
0%(a)	
 	 	Approx 30 chilled water customers	 	106
28	
 	 	Chilled water: 30,100 tons
Chilled water: 8,000 tons	
NRG Energy Center Pittsburgh, PA	100.0	
 	 	Approx 25 steam and 25 chilled water customers	 	87
46	
 	 	Steam: 296 MMBtu/hr.
Chilled water: 12,920 tons	
NRG Energy Center San Diego, CA	100.0	
 	 	Approx 20 chilled water customers	 	26	
 	 	Chilled water: 7,425 tons	
NRG Energy Center Dover, DE	100.0	
 	 	Kraft Foods Inc. and Procter & Gamble Company	 	22	
 	 	Steam: 75 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)	 	1,098	

(a)	Capacity available under right-to-use provision of the Chilled Water Service Agreement.	

Other Properties
NRG owns 45 MW of Distributed Solar facilities, 40 MW of which is operational, at various locations throughout the United States, concentrated primarily in the West Region.
In addition, NRG owns several real properties and facilities relating to its generation assets, other vacant real property unrelated to the Company's generation assets, interests in construction projects, and properties not used for operational purposes. NRG believes it has satisfactory title to its plants and facilities in accordance with standards generally accepted in the electric power industry, subject to exceptions that, in the Company's opinion, would not have a material adverse effect on the use or value of its portfolio.
NRG leases its financial and commercial corporate headquarters offices at 211 Carnegie Center, Princeton, New Jersey, its operational headquarters in Houston, TX, its Retail Business offices and call centers, and various other office space.

50

Item 3 — Legal Proceedings
Public Utilities Commission of the State of California v. Long-Term Sellers of Long-Term Contracts to the California Department of Water Resources ,  FERC Docket No. EL02-60 et al.  —  This matter concerns, among other contracts and other defendants, the CDWR and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004.
On December 19, 2006, the Ninth Circuit decided that in the FERC's review of the contracts at issue, the FERC could not rely on the  Mobile-Sierra  standard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCP's appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008, the Supreme Court ruled: (i) that the  Mobile-Sierra  public interest standard of review applied to contracts made under a seller's market-based rate authority; (ii) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (iii) that the  Mobile-Sierra  presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress.
This matter was extensively litigated and on March 22, 2012, NRG reached an agreement in principle with the CPUC to settle and resolve this matter, including all related claims, on behalf of NRG and on behalf of Dynegy. The agreement in principle was announced by the Company on March 23, 2012, as well as by the CPUC and by the California Governor's Office. The documented agreement was executed and submitted to the FERC on April 27, 2012 for its approval. The settlement agreement contains three material elements to be fulfilled over a four to six year period, depending upon several factors. First, the settlement agreement includes a $20 million cash payment due 30 days after the FERC approval. Second, it includes the construction and operation of a fee-based charging network, to be owned and operated by NRG subsidiary, eVgo, which will consist of at least 200 publicly available fast-charging electric vehicle stations installed at locations across California. Last, it calls for the wiring and associated work required to improve at least 10,000 individual parking spaces to allow for the charging of electric vehicles in at least 1,000 multi-family complexes, worksites, and public interest locations such as community colleges, public universities, and public or non-profit hospitals. Although these improved newly wired parking spaces will continue to be owned by the local property owner, eVgo will have an 18-month exclusive right to obtain customers from these locations starting from the date of each completed installation. The expected $20 million cash payment was accrued and expensed in the statement of operations for the three months ended March 31, 2012. In addition, the Company expects to spend approximately $100 million over the next four to six year period, during which the Company will fulfill the other elements of the settlement, and will capitalize a substantial majority of the costs as property, plant and equipment, representing the costs to construct the charging network and the wiring, which will be productive assets. The Company will expense the costs to operate the assets as incurred. On May 24, 2012, ECOtality, Inc. filed a lawsuit against the CPUC challenging the settlement, which was effectively dismissed on October 12, 2012. The settlement agreement was approved by the FERC on November 2, 2012. Final settlement payment of $20 million was made on January 16, 2013. Given that there was no challenge to the FERC order approving the settlement in the statutory period, the order became final and non-appealable.
United States of America v. Louisiana Generating, LLC., U.S.D.C Middle District of Louisiana,Civil Action No. 09-100-RET-CN (filed February 11, 2009) —  On February 11, 2009, the U.S. Department of Justice, or U.S. DOJ, acting at the request of the EPA sued Louisiana Generating, LLC, or LaGen, in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. This is the same matter for which Notices of Violation, or NOVs, were issued to LaGen on February 15, 2005, and on December 8, 2006. Specifically, it is alleged that in the late 1990s, several years prior to NRG's acquisition of the Big Cajun II power plant from the Cajun Electric bankruptcy and several years prior to the NRG bankruptcy, modifications were made to Big Cajun II Units 1 and 2 by the prior owners without appropriate or adequate permits and without installing and employing BACT to control emissions of nitrogen oxides and/or sulfur dioxides. The relief sought in the complaint included a request for an injunction to: (i) preclude the operation of Units 1 and 2 except in accordance with the CAA; (ii) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (iii) obtain all necessary permits for Units 1 and 2; (iv) order the surrender of emission allowances or credits; (v) conduct audits to determine if any additional modifications have been made which would require compliance with the CAA's Prevention of Significant Deterioration program; (vi) award to the U.S. DOJ its costs in prosecuting this litigation; and (vii) assess civil penalties of up to $27,500 per day for each CAA violation found to have occurred between January 31, 1997, and March 15, 2004, up to $32,500 for each CAA violation found to have occurred between March 15, 2004, and January 12, 2009, and up to $37,500 for each CAA violation found to have occurred after January 12, 2009.

51

On January 20, 2012, the court scheduled a liability-phase trial for October 15, 2012, and a remedy-phase trial set to occur at a later date to be determined in the event of an adverse decision in a liability-phase trial. On October 17, 2012, prior to the start of the liability-phase trial which had been temporarily adjourned, the parties notified the court that they had reached an agreement on terms of a settlement. The terms of the agreement generally require LaGen to install certain emission control technologies, as well as pay a civil penalty of $3.5 million and complete mitigation projects of $10.5 million within five years of entry of the Consent Decree. On November 20, 2012, the U.S. DOJ lodged the Consent Decree with the court. On January 14, 2013, the court entered the parties' joint request for a continuance until April 22, 2013, so the Consent Decree could be published for public comment. No objections to the Decree were received during the public comment period. Further discussion on this matter can be found in Item 15 — Note 23,  Environmental Matters - South Central Region .
Louisiana Generating, LLC and NRG Energy, Inc. v. Illinois Union Insurance Company, U.S.D.C. Middle District of Louisiana,  Civil Action No. 10-516-JJB-SCR (filed August 9, 2010) —  In a related matter, soon after the filing of the above referenced U.S. DOJ lawsuit, LaGen sought insurance coverage from its insurance carrier, Illinois Union Insurance Company, or ILU. ILU denied coverage and thereafter LaGen filed a lawsuit (which was consolidated with a prior suit filed by ILU) seeking a declaration that ILU must provide coverage to LaGen for the defense costs incurred in defending the U.S. DOJ lawsuit.  LaGen and ILU both filed motions for summary judgment and on January 30, 2012, the court issued an order granting LaGen's motion finding that ILU has a duty to defend LaGen. The trial court certified the summary judgment for immediate interlocutory appeal, and on May 25, 2012, ILU filed a petition with the U.S. Circuit Court of Appeals for the Fifth Circuit seeking to appeal the trial court's summary judgment ruling. The Fifth Circuit granted the petition on September 4, 2012. ILU filed a related notice of appeal on June 14, 2012, which also seeks review of the trial court's summary judgment ruling. The Company filed a motion to consolidate the two appeals which the court granted on October 24, 2012. The appellate argument before the Fifth Circuit is scheduled for March 6, 2013.
Big Cajun II Alleged Opacity Violations — On September 7, 2012, LaGen received a Consolidated Compliance Order & Notice of Potential Penalty, or CCO&NPP, from the LDEQ with the potential for penalties in excess of $100,000.  The CCO&NPP alleges there were opacity exceedance events from the Big Cajun II Power Plant on certain dates during the years 2007-2012.  On October 8, 2012, LaGen filed a Request for Administrative Adjudicatory hearing and is cooperating with the LDEQ and responding in good faith to the CCO&NPP. 

Global Warming — In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a suit in the United States District Court for the Northern District of California against GenOn and 23 other electric generating and oil and gas companies. The lawsuit sought damages of up to $400 million for the cost of relocating the village allegedly because of global warming caused by the greenhouse gas emissions of the defendants. In late 2009, the District Court ordered that the case be dismissed and the plaintiffs appealed. In September 2012, the United States Court of Appeals for the Ninth Circuit dismissed plaintiffs' appeal. In October 2012, the plaintiffs petitioned for en banc rehearing of the case; which petition was denied in November 2012. In February 2013, plaintiffs filed a petition with the U. S. Supreme Court seeking review of the decision from the U.S. Court of Appeals. The Company believes claims such as this lack legal merit.
Actions Pursued by MC Asset Recovery — Under the plan of reorganization that was approved in conjunction with Mirant Corporation's emergence from bankruptcy protection on January 3, 2006, or the Plan, the rights to certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings.  MC Asset Recovery is now governed by a manager who is independent of GenOn.  Under the Plan, any cash recoveries obtained by MC Asset Recovery from the actions transferred to it, net of fees and costs incurred in prosecuting the actions, are to be paid to the unsecured creditors of GenOn Energy Holdings in the Chapter 11 proceedings and the holders of the equity interests in GenOn Energy Holdings immediately prior to the effective date of the Plan except where such a recovery results in an allowed claim in the bankruptcy proceedings, as described below.  MC Asset Recovery is a disregarded entity for income tax purposes, and NRG, GenOn and GenOn Energy Holdings are responsible for income taxes related to its operations.  The Plan provides that GenOn Energy Holdings may not reduce payments to be made to unsecured creditors and former holders of equity interests from recoveries obtained by MC Asset Recovery for the taxes owed by GenOn Energy Holdings, if any, on any net recoveries up to $175 million. If the aggregate recoveries exceed $175 million net of costs, then GenOn Energy Holdings may reduce the payments by the amount of any taxes it will owe or NOLs it may utilize with respect to taxable income resulting from the amount in excess of $175 million.

52

One of the two remaining actions transferred to MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks (the Commerzbank Defendants) for alleged fraudulent transfers that occurred prior to the filing of GenOn Energy Holdings' bankruptcy proceedings.  In its amended complaint, MC Asset Recovery alleges that the Commerzbank Defendants in 2002 and 2003 received payments totaling approximately €153 million directly or indirectly from GenOn Energy Holdings under a guarantee provided by GenOn Energy Holdings in 2001 of certain equipment purchase obligations.  MC Asset Recovery alleges that at the time GenOn Energy Holdings provided the guarantee and made the payments to the Commerzbank Defendants, GenOn Energy Holdings was insolvent and did not receive fair value for those transactions.  In December 2010, the United States District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants.  In January 2011, MC Asset Recovery appealed the United States District Court's dismissal of its complaint against the Commerzbank Defendants to the United States Court of Appeals for the Fifth Circuit.  In March 2012, the United States Court of Appeals for the Fifth Circuit reversed the United States District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants.  If MC Asset Recovery succeeds in obtaining any recoveries on these avoidance claims, the Commerzbank Defendants have asserted that they will seek to file claims in GenOn Energy Holdings' bankruptcy proceedings for the amount of those recoveries.  GenOn Energy Holdings would vigorously contest the allowance of any such claims on the ground that, among other things, the recovery of such amounts by MC Asset Recovery does not reinstate any enforceable pre-petition obligation that could give rise to a claim.  If such a claim were to be allowed by the Bankruptcy Court as a result of a recovery by MC Asset Recovery, then the Plan provides that the Commerzbank Defendants are entitled to the same distributions as previously made under the Plan to holders of similar allowed claims.  Holders of previously allowed claims similar in nature to the claims that the Commerzbank Defendants would seek to assert have received 43.87 shares of GenOn Energy Holdings common stock for each $1,000 of claim allowed by the Bankruptcy Court.  If the Commerzbank Defendants were to receive an allowed claim as a result of a recovery by MC Asset Recovery on its claims against them, the order entered by the Bankruptcy Court in December 2005, confirming the Plan provides that GenOn Energy Holdings would retain from the net amount recovered by MC Asset Recovery an amount equal to the dollar amount of the resulting allowed claim rather than distribute such amount to the unsecured creditors and former equity holders as described above.
Pending Natural Gas Litigation — GenOn is party to five lawsuits, several of which are class action lawsuits, in state and federal courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in 2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of antitrust and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name a number of unaffiliated energy companies as parties. In July 2011, the judge in the United States District Court for the District of Nevada handling four of the five cases granted the defendants' motion for summary judgment dismissing all claims against GenOn in those cases. The plaintiffs have appealed to the United States Court of Appeals for the Ninth Circuit. In September 2012, the State of Nevada Supreme Court handling one of the five cases affirmed dismissal by the Eighth Judicial District Court for Clark County, Nevada of all plaintiffs' claims against GenOn. In February 2013, the plaintiffs filed a petition for certiorari to the United States Supreme Court. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits.
New Source Review Matters — The EPA and various states are investigating compliance of coal-fueled electric generating facilities with the pre-construction permitting requirements of the CAA known as “new source review.” Since 2000, the EPA has made information requests concerning several of the Company's plants. The Company continues to correspond with the EPA regarding some of these requests. The EPA agreed to share information relating to its investigations with state environmental agencies. In 2005 and 2006, the Company received an NOV from the EPA alleging that past work at Big Cajun II violated regulations regarding new source review. In January 2009, the EPA issued an NOV alleging that past work at the Shawville, Portland and Keystone generating facilities violated regulations regarding new source review. In June 2011, the EPA issued an NOV alleging that past work at the Niles and Avon Lake generating facilities violated regulations regarding new source review.
In December 2007, the NJDEP sued GenOn in the United States District Court for the Eastern District of Pennsylvania, alleging that new source review violations occurred at the Portland generating facility. The suit seeks installation of BACT for each pollutant, to enjoin GenOn from operating the generating facility if it is not in compliance with the CAA and civil penalties. The suit also names past owners of the plant as defendants. In March 2009, the Connecticut Department of Environmental Protection became an intervening party to the suit. The Company believes that the work listed by the EPA and the work subject to the NJDEP suit were conducted in compliance with applicable regulations. However, any final finding that GenOn violated the new source review requirements could result in fines and penalties. This case is currently scheduled for a liability trial on April 22, 2013.

53

In addition, the NJDEP filed two administrative petitions with the EPA in 2010 alleging that the Portland generating facility's emissions were significantly contributing to nonattainment and/or interfering with the maintenance of certain NAAQS in New Jersey. In November 2011, the EPA published a final rule in response to one of the petitions that will require the two coal-fired units to reduce the maximum allowable SO2 emissions by about 60% starting in January 2013 and by about 80% starting in January 2015. In January 2012, the Company challenged the rule in the United States Court of Appeals for the Third Circuit. In 2013 and 2014, the Company has several compliance options that include using lower sulfur coals (although this may at times reduce how much the Company is able to generate) or running just one unit at a time. Starting in January 2015, these units will be subject to more stringent rate limits, which will require either material capital expenditures and higher operating costs or the retirement of these two units. The Company plans to deactivate these units in January 2015.
Cheswick Class Action Complaint — In April 2012, a putative class action lawsuit was filed in the Court of Common Pleas of Allegheny County, Pennsylvania alleging that emissions from the Cheswick generating facility have damaged the property of neighboring residents. The Company disputes these allegations. Plaintiffs have brought nuisance, negligence, trespass and strict liability claims seeking both damages and injunctive relief. Plaintiffs seek to certify a class that consists of people who own property or live within one mile of the Company's plant. In July 2012, the Company removed the lawsuit to the United States District Court for the Western District of Pennsylvania. In October 2012, the court granted the Company's motion to dismiss, which Plaintiffs have appealed to the U.S. Court of Appeals for the Third Circuit.
Cheswick Monarch Mine NOV — In 2008, the PADEP issued an NOV related to the Monarch mine located near the Cheswick generating facility. It has not been mined for many years. The Company uses it for disposal of low-volume wastewater from the Cheswick generating facility and for disposal of leachate collected from ash disposal facilities. The NOV addresses the alleged requirement to maintain a minimum pumping volume from the mine. The PADEP indicated it may assess a civil penalty in excess of $100,000. The Company contests the allegations in the NOV and has not agreed to such penalty. The Company is currently planning capital expenditures in connection with wastewater from Cheswick and leachate from ash disposal facilities.
Ormond Beach Alleged Federal Clean Water Act Violations — In October 2012, the Wishtoyo Foundation, a California-based cultural and environmental advocacy organization, through its Ventura Coastkeeper Program, filed suit in the United States District Court for the Central District of California regarding alleged violations of the Clean Water Act associated with discharges of stormwater from the Ormond Beach generating facility. The Wishtoyo Foundation alleges that elevated concentrations of pollutants in stormwater discharged from the Ormond Beach generating facility are affecting adjacent aquatic resources in violation of (a) the Statewide General Industrial Stormwater permit (a general National Pollution Discharge Elimination System permit issued by the California State Water Resources Control Board that authorizes stormwater discharges from industrial facilities in California) and (b) the state's Porter-Cologne Water Quality Control Act. The Wishtoyo Foundation further alleges that the Company has not implemented effective stormwater control and treatment measures and that the Company has not complied with the sampling and reporting requirements of the General Industrial Stormwater permit. The Company disputes these allegations.
Maryland Fly Ash Facilities — The Company has three fly ash facilities in Maryland: Faulkner, Westland and Brandywine. Fly ash from the Morgantown and Chalk Point generating facilities is disposed of at Brandywine. Fly ash from the Dickerson generating facility is disposed of at Westland. Fly ash is no longer disposed at the Faulkner facility. As described below, the MDE has sued GenOn MidAtlantic regarding Faulkner, Brandywine and Westland. The MDE also had threatened not to renew the water discharge permits for all three facilities.
Faulkner Litigation — In May 2008, the MDE sued GenOn MidAtlantic in the Circuit Court for Charles County, Maryland alleging violations of Maryland's water pollution laws at Faulkner. The MDE contended that the operation of Faulkner had resulted in the discharge of pollutants that exceeded Maryland's water quality criteria and without the appropriate NPDES permit. The MDE also alleged that GenOn MidAtlantic failed to perform certain sampling and reporting required under an applicable NPDES permit. The MDE complaint requested that the court (a) prohibit continuation of the alleged unpermitted discharges, (b) require GenOn MidAtlantic to cease from further disposal of any coal combustion byproducts at Faulkner and close and cap the existing disposal cells and (c) assess civil penalties. In July 2008, GenOn MidAtlantic filed a motion to dismiss the complaint, arguing that the discharges are permitted by a December 2000 Consent Order. In January 2011, the MDE dismissed without prejudice its complaint and informed GenOn MidAtlantic that it intended to file a similar lawsuit in federal court. In May 2011, the MDE filed a complaint in the United States District Court for the District of Maryland alleging violations at Faulkner of the Clean Water Act and Maryland's Water Pollution Control Law. The MDE contends that (a) certain water discharges are not authorized by the existing permit and (b) operation of the Faulkner facility has resulted in discharges of pollutants that violate water quality criteria. The complaint asks the court to, among other things, (a) enjoin further disposal of coal ash; (b) enjoin discharges that are not authorized by the existing permit; (c) require numerous technical studies; (d) impose civil penalties and (e) award MDE attorneys' fees. The Company disputes the allegations.

54

Brandywine Litigation — In April 2010, the MDE filed a complaint against GenOn MidAtlantic in the United States District Court for the District of Maryland asserting violations at Brandywine of the Clean Water Act and Maryland's Water Pollution Control Law. The MDE contends that the operation of Brandywine has resulted in discharges of pollutants that violate Maryland's water quality criteria. The complaint requests that the court, among other things, (a) enjoin further disposal of coal combustion waste at Brandywine, (b) require the existing open disposal cells to be closed and capped within one year, (c) impose civil penalties and (d) award MDE attorneys' fees. The Company disputes the allegations. In September 2010, four environmental advocacy groups became intervening parties in the proceeding.
Westland Litigation — In January 2011, the MDE informed the Company that it intended to sue the Company for alleged violations at Westland of Maryland's water pollution laws, which suit was filed in United States District Court for the District of Maryland in December 2012.
Permit Renewals — In March 2011, the MDE tentatively determined to deny GenOn MidAtlantic's application for the renewal of the water discharge permit for Brandywine, which could result in a significant increase in operating expenses for the Chalk Point and Morgantown generating facilities. The MDE also had indicated that it was planning to deny the applications for the renewal of the water discharge permits for Faulkner and Westland. Denial of the renewal of the water discharge permit for the latter facility could result in a significant increase in operating expenses for the Dickerson generating facility.
Settlement — In June 2011, the MDE agreed to stay the litigation related to Faulkner and Brandywine, not to pursue its tentative denial of the Brandywine water discharge permit and not to act on renewal applications for Faulkner or Westland while settlement discussions occurred. As a condition to obtaining the stay, GenOn MidAtlantic agreed in principle to pay a civil penalty of $1.9 million if the matters were settled. In 2012, GenOn MidAtlantic agreed to pay an additional $0.6 million (for agreed prospective penalties while the settlement is implemented) if a comprehensive settlement is reached. The Company believes it is adequately reserved for such settlement. GenOn MidAtlantic also developed a technical solution, which includes installing synthetic caps on the closed cells of each of the three ash facilities, for which $47 million has been reserved. GenOn MidAtlantic has concluded settlement discussions with the MDE and signed a consent decree that when entered by the court will resolve these issues. In January 2013, the intervenors in the Brandywine case opposed entry of the consent decree. At this time, the Company cannot reasonably estimate the upper range of its obligation for remediating the sites because the Company has not: (a) finished assessing each site including identifying the full impacts to both ground and surface water and the impacts to the surrounding habitat; (b) finalized with the MDE the standards to which it must remediate; and (c) identified the technologies required, if any, to meet the yet to be determined remediation standards at each site nor the timing of the design and installation of such technologies.
Brandywine Storm Damage and Ash Recovery — As a result of Hurricane Irene and Tropical Storm Lee in August and September 2011, an estimated 8,800 cubic yards of coal fly ash stored in one of the cells at the Brandywine ash disposal site flowed onto 18 acres of private property adjacent to the site. The Company has removed the released ash from the private property and completed the remaining clean-up activities. The Company believes it has recorded an adequate reserve in connection with claims associated with the costs to remove and clean up the ash.
Brandywine Filling of Wetlands — While expanding and installing a liner at the Brandywine ash disposal site, GenOn MidAtlantic inadvertently filled wetlands without having all of the requisite permits. The MDE also has alleged that GenOn MidAtlantic violated the notice requirements of the Company's sediment and erosion control plan. In July 2012, the MDE filed a complaint in the Circuit Court for Prince George's County, Maryland for civil penalties and injunctive relief in connection with the storm damage and the filling of the wetlands. GenOn MidAtlantic settled these matters by paying a fine of $300,000 in December 2012.
Energy Plus Holdings, LLC Purported Class Actions — Energy Plus is a defendant in six purported class action lawsuits, two in New York, two in New Jersey, and and two in Pennsylvania. The plaintiffs in those lawsuits generally allege that Energy Plus misrepresents that its rates are competitive in the market; fails to disclose that its rates are substantially higher than those in the market and that Energy Plus has engaged in deceptive practices in its marketing of energy services. Plaintiffs generally seek that these matters be certified as class actions, with treble damages, interest, costs, attorneys' fees, and any other relief that the court deems just and proper. In addition, on July 26, 2012, the Connecticut Attorney General and Office of Consumer Counsel filed a petition with the Connecticut Public Utilities Regulatory Authority seeking to investigate Energy Plus' marketing practices. On August 7, 2012, Energy Plus Holdings LLC and Energy Plus Natural Gas LLC received a subpoena from the State of New York Office of Attorney General which generally seeks information and business records related to Energy Plus' sales, marketing and business practices. While the Company believes that these allegations are without merit, it is cooperating with the attorneys general and is exploring an amicable resolution of all matters. The Company does not currently anticipate any potential resolution to be material in nature and believes it is adequately reserved for any estimated losses.

55

Purported Class Actions related to July 22, 2012 Announcement of NRG/GenOn Merger Agreement — NRG Energy, Inc. has been named as a defendant in eight purported class actions pending in Texas and Delaware, related to its announcement of its agreement to acquire all outstanding shares of GenOn. These cases have been consolidated into one state court case in each of Delaware and Texas and a federal court case in Texas. The plaintiffs generally allege breach of fiduciary duties, as well as conspiracy, aiding and abetting breaches of fiduciary duties. Plaintiffs are generally seeking to: be certified as a class; enjoin the merger; direct the defendant to exercise their fiduciary duties; rescind the acquisition and be awarded attorneys' fees costs and other relief that the court deems appropriate. Plaintiffs have demanded that there be additional disclosures regarding the merger terms. On October 24, 2012, the parties to the Delaware state court case executed a Memorandum of Understanding to resolve the Delaware purported class action lawsuit.
Notice of Intent to File Citizens Suit - Chalk Point, Dickerson and Morgantown — On January 25, 2013, Food & Water Watch, the Patuxent Riverkeeper and the Potomac Riverkeeper, or the Citizens Group, sent NRG a letter alleging that the Chalk Point, Dickerson and Morgantown generating facilities were violating the terms of the three National Pollution Discharge Elimination System Permits by discharging nitrogen and phosphorous into the waters of the United States in excess of the limits in each permit. The Citizens Group threatens to bring a lawsuit if the Company does not bring itself into compliance within 60 days of the letter. The Citizens Group intends to seek civil penalties and injunctive relief against the Company if they file a lawsuit.
Additional Litigation — In addition to the foregoing, NRG is party to other litigation or legal proceedings. The Company believes that it has valid defenses to the legal proceedings and investigations described above and intends to defend them vigorously. However, litigation is inherently subject to many uncertainties. There can be no assurance that additional litigation will not be filed against the Company or its subsidiaries in the future asserting similar or different legal theories and seeking similar or different types of damages and relief. Unless specified above, the Company is unable to predict the outcome these legal proceedings and investigations may have or reasonably estimate the scope or amount of any associated costs and potential liabilities. An unfavorable outcome in one or more of these proceedings could have a material impact on the Company's consolidated financial position, results of operations or cash flows. The Company also has indemnity rights for some of these proceedings to reimburse the Company for certain legal expenses and to offset certain amounts deemed to be owed in the event of an unfavorable litigation outcome.

Item 4 — Mine Safety Disclosures
Not applicable

56

PART II
Item 5 — Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information and Holders
NRG's authorized capital stock consists of 500,000,000 shares of NRG common stock and 10,000,000 shares of preferred stock. A total of 22,000,000 shares of the Company's common stock are available for issuance under the NRG LTIP. A total of 5,558,390 shares of NRG common stock were authorized for issuance under the NRG GenOn LTIP. For more information about the NRG LTIP and the NRG GenOn LTIP, refer to Item 15 —Note 19,  Stock-Based Compensation.   NRG has also filed with the Secretary of State of Delaware a Certificate of Designation for the 3.625% Convertible Perpetual Preferred Stock.
NRG's common stock is listed on the New York Stock Exchange and has been assigned the symbol: NRG. The high and low sales prices, as well as the closing price for the Company's common stock on a per share basis for 2012 and 2011 are set forth below:

Common Stock Price	Fourth
Quarter
2012	 	Third
Quarter
2012	 	Second
Quarter
2012	 	First
Quarter
2012	 	Fourth
Quarter
2011	 	Third
Quarter
2011	 	Second
Quarter
2011	 	First
Quarter
2011	
High	$	23.78	
 	 	$	22.92	
 	 	$	17.49	
 	 	$	18.46	
 	 	$	22.61	
 	 	$	25.66	
 	 	$	25.54	
 	 	$	21.95	
 	
Low	19.15	
 	 	16.66	
 	 	14.29	
 	 	15.53	
 	 	17.47	
 	 	19.98	
 	 	21.05	
 	 	19.09	
 	
Closing	22.99	
 	 	21.39	
 	 	17.36	
 	 	15.67	
 	 	18.12	
 	 	21.21	
 	 	24.58	
 	 	21.54	
 	
Dividends Per Common Share	$	0.09	
 	 	$	0.09	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	
NRG had 322,606,898 shares outstanding as of December 31, 2012. As of February 21, 2013, there were 323,165,879 shares outstanding, and there were 31,630 common stockholders of record.
Dividends
On February 15, 2013, NRG paid a quarterly dividend on the Company's common stock of $0.09 per share.

Repurchase of equity securities
NRG did not repurchase equity securities in the year ended December 31, 2012.

57

Stock Performance Graph
The performance graph below compares NRG's cumulative total stockholder return on the Company's common stock for the period December 31, 2007, through December 31, 2012, 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. NRG's common stock trades on the New York Stock Exchange under the symbol "NRG".
The performance graph shown below is being furnished and compares each period assuming that $100 was invested on December 31, 2007 in each of the common stock of NRG, 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

       

 	Dec-2007	 	Dec-2008	 	Dec-2009	 	Dec-2010	 	Dec-2011	 	Dec-2012	
NRG Energy, Inc. 	$	100.00	
 	 	$	53.83	
 	 	$	54.48	
 	 	$	45.09	
 	 	$	41.81	
 	 	$	53.51	
 	
S&P 500	100.00	
 	 	63.00	
 	 	79.68	
 	 	91.68	
 	 	93.61	
 	 	108.59	
 	
UTY	$	100.00	
 	 	$	72.76	
 	 	$	80.07	
 	 	$	84.63	
 	 	$	100.94	
 	 	$	100.37	

58

Item 6 — Selected Financial Data
The following table presents NRG's historical selected financial data. The data included in the following table has been recast to reflect the assets, liabilities and results of operations of certain projects that have met the criteria for treatment as discontinued operations in 2008.
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.

 	Year Ended December 31,	
 	2012	 	2011	 	2010	 	2009	 	2008	
 	(In millions except ratios and per share data)	
Statement of income data:	 	 	 	 	 	 	 	 	 	
Total operating revenues	$	8,422	
 	 	$	9,079	
 	 	$	8,849	
 	 	$	8,952	
 	 	$	6,885	
 	
Total operating costs and expenses, and other expenses	8,170	
 	 	9,725	
 	 	8,119	
 	 	7,283	
 	 	5,119	
 	
Income from continuing operations, net	579	
 	 	197	
 	 	476	
 	 	941	
 	 	1,053	
 	
Income from discontinued operations, net	—	
 	 	—	
 	 	—	
 	 	—	
 	 	172	
 	
Net income attributable to NRG Energy, Inc. 	$	559	
 	 	$	197	
 	 	$	477	
 	 	$	942	
 	 	$	1,225	
 	
Common share data:	 	 	 	 	 	 	 	 	 	
Basic shares outstanding — average	232	
 	 	240	
 	 	252	
 	 	246	
 	 	235	
 	
Diluted shares outstanding — average	234	
 	 	241	
 	 	254	
 	 	271	
 	 	275	
 	
Shares outstanding — end of year	323	
 	 	228	
 	 	247	
 	 	254	
 	 	234	
 	
Per share data:	 	 	 	 	 	 	 	 	 	
Income attributable to NRG from continuing operations — basic	$	2.37	
 	 	$	0.78	
 	 	$	1.86	
 	 	$	3.70	
 	 	$	4.25	
 	
Income attributable to NRG from continuing operations — diluted	2.35	
 	 	0.78	
 	 	1.84	
 	 	3.44	
 	 	3.80	
 	
Net income attributable to NRG — basic	2.37	
 	 	0.78	
 	 	1.86	
 	 	3.70	
 	 	4.98	
 	
Net income attributable to NRG — diluted	2.35	
 	 	0.78	
 	 	1.84	
 	 	3.44	
 	 	4.43	
 	
Book value	$	32.65	
 	 	$	33.71	
 	 	$	32.65	
 	 	$	29.72	
 	 	$	26.75	
 	
Business metrics:	 	 	 	 	 	 	 	 	 	
Cash flow from operations	$	1,149	
 	 	$	1,166	
 	 	$	1,623	
 	 	$	2,106	
 	 	$	1,479	
 	
Liquidity position (a)	$	3,633	
 	 	$	2,328	
 	 	$	4,660	
 	 	$	3,971	
 	 	$	4,124	
 	
Ratio of earnings to fixed charges	1.17	
 	 	0.77	
 	 	2.03	
 	 	3.27	
 	 	3.65	
 	
Ratio of earnings to fixed charges and preferred dividends	1.16	
 	 	0.76	
 	 	1.99	
 	 	3.04	
 	 	3.19	
 	
Return on equity	5.31	%	 	2.57	%	 	5.91	%	 	12.24	%	 	17.20	%	
Ratio of debt to total capitalization	56.13	%	 	52.43	%	 	42.94	%	 	43.49	%	 	47.50	%	
Balance sheet data:	 	 	 	 	 	 	 	 	 	
Current assets	$	7,956	
 	 	$	7,749	
 	 	$	7,137	
 	 	$	6,208	
 	 	$	8,492	
 	
Current liabilities	4,677	
 	 	5,861	
 	 	4,220	
 	 	3,762	
 	 	6,581	
 	
Property, plant and equipment, net	20,268	
 	 	13,621	
 	 	12,517	
 	 	11,564	
 	 	11,545	
 	
Total assets	35,128	
 	 	26,900	
 	 	26,896	
 	 	23,378	
 	 	24,808	
 	
Long-term debt, including current maturities, capital leases, and funded letter of credit	15,880	
 	 	9,832	
 	 	10,511	
 	 	8,418	
 	 	8,161	
 	
Total stockholders' equity	$	10,533	
 	 	$	7,669	
 	 	$	8,072	
 	 	$	7,697	
 	 	$	7,123	

(a)	Liquidity position is determined as disclosed in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources, Liquidity Position . It includes funds deposited by counterparties of $271 million, $258 million, and $408 million as of December 31, 2012, 2011, and 2010, respectively, which represents cash held as collateral from hedge counterparties in support of energy risk management activities. It is the Company's intention to limit the use of these funds for repayment of the related current liability for collateral received in support of energy risk management activities.	

59

The following table provides the details of NRG's operating revenues:

 	Year Ended December 31,	
 	2012	 	2011	 	2010	 	2009	 	2008	
 	(In millions)	
Energy revenue	$	3,776	
 	 	$	3,804	
 	 	$	4,063	
 	 	$	4,087	
 	 	$	4,408	
 	
Capacity revenue	800	
 	 	750	
 	 	840	
 	 	1,070	
 	 	1,343	
 	
Retail revenue	5,888	
 	 	5,807	
 	 	5,277	
 	 	4,440	
 	 	—	
 	
Mark-to-market for economic hedging activities	(450	)	 	325	
 	 	(199	)	 	(107	)	 	462	
 	
Contract amortization	(97	)	 	(159	)	 	(195	)	 	(179	)	 	278	
 	
Other revenues	302	
 	 	342	
 	 	361	
 	 	62	
 	 	417	
 	
Eliminations	(1,797	)	 	(1,790	)	 	(1,298	)	 	(421	)	 	(23	)	
Total operating revenues	$	8,422	
 	 	$	9,079	
 	 	$	8,849	
 	 	$	8,952	
 	 	$	6,885	
 	
Energy revenue consists of revenues received from third parties for sales of electricity in the day-ahead and real-time markets, as well as bilateral sales. It also includes energy sold through long-term PPAs for renewable facilities. In addition, energy revenue includes revenues from the settlement of financial instruments and net realized trading revenues.
Capacity revenue consists of revenues received from a third party at either the market or negotiated contract rates for making installed generation capacity available in order to satisfy system integrity and reliability requirements. Capacity revenue also includes revenues from the settlement of financial instruments. In addition, capacity revenue includes revenues received under tolling arrangements, which entitle third parties to dispatch NRG's facilities and assume title to the electrical generation produced from that facility.
Retail revenue, representing operating revenues of NRG's Retail Business, consists of revenues from retail sales to residential, small business, commercial, industrial and governmental/institutional customers, as well as revenues from the sale of excess supply into various markets, primarily in Texas.
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges.

Contract amortization revenue consists of the amortization of the intangible assets for net in-market C&I contracts established in connection with the acquisitions of Reliant Energy and Green Mountain Energy, as well as acquired power contracts, gas derivative instruments, and certain power sales agreements assumed at Fresh Start and Texas Genco purchase accounting dates related to the sale of electric capacity and energy in future periods. These amounts are amortized into revenue over the term of the underlying contracts based on actual generation or contracted volumes.
Other revenues include revenues generated by the Thermal business consisting of revenues received from the sale of steam, hot and chilled water generally produced at a central district energy plant and sold to commercial, governmental and residential buildings for space heating, domestic hot water heating and air conditioning. It also includes the sale of high-pressure steam produced and delivered to industrial customers that is used as part of an industrial process. Other revenues also consists of operations and maintenance fees, or O&M fees, construction management services, or CMA fees, sale of natural gas and emission allowances, and revenues from ancillary services. O&M fees consist of revenues received from providing certain unconsolidated affiliates with services under long-term operating agreements. CMA fees are earned where NRG provides certain management and oversight of construction projects pursuant to negotiated agreements such as for the GenConn, Cedar Bayou 4 and certain solar construction projects. Ancillary services are comprised of the sale of energy-related products associated with the generation of electrical energy such as spinning reserves, reactive power and other similar products. Other revenues also includes unrealized trading activities.

60

Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations
The discussion and analysis below has been organized as follows:
 	 	
•	Executive Summary, including business strategy, the business environment in which NRG operates, how regulation, weather, competition and other factors affect the business, and significant events that are important to understanding the results of operations and financial condition for the 2012 period;	
 	 	
•	Results of operations, including an explanation of significant differences between the periods in the specific line items of NRG's Consolidated Statements of Operations;	
 	 	
•	Financial condition addressing credit ratings, liquidity position, sources and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements; 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.	
As you read this discussion and analysis, refer to NRG's Consolidated Statements of Operations to this Form 10-K, which presents the results of the Company's operations for the years ended December 31, 2012, 2011, and 2010, and also refer to Item 1 to this Form 10-K for more detailed discussion about the Company's business.

61

Executive Summary
Business Strategy
NRG is a competitive power and energy company that aspires to be a leader in the way the industry and consumers think about, use, produce and deliver energy and energy services in major competitive power markets in the United States. At its core, NRG is a wholesale power generator engaged in the ownership and operation of power generation facilities; the trading of energy, capacity and related products; and the transacting in and trading of fuel and transportation services. Second, while leveraging its core wholesale power business, NRG is a retail energy company engaged in the supply of energy, services, and innovative, sustainable products to retail customers in competitive markets through multiple channels and brands like Reliant Energy, Green Mountain Energy, and Energy Plus (collectively, the Retail Business). Finally, NRG is a clean energy leader and is focused on the deployment and commercialization of potentially disruptive technologies, like electric vehicles, Distributed Solar and smart meter technology, which have the potential to change the nature of the power supply industry.
The Company's business is focused on: (i) excellence in safety and operating performance of its existing assets; (ii) serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels with a variety of retail energy products and services differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) optimal hedging of coal and nuclear generation and retail load operations, while retaining optionality on the Company's peaking facilities; (iv) repowering of power generation assets at premium sites; (v) investment in, and deployment of, alternative energy technologies both in its wholesale and, particularly, in and around its Retail Business and its customers; (vi) pursuing selective acquisitions, joint ventures, divestitures and investments; and (vii) engaging in a proactive capital allocation plan focused on achieving the regular return of and on stockholder capital within the dictates of prudent balance sheet management.
The Company believes that the American energy industry is going to be increasingly impacted by the long-term societal trend towards sustainability which is both generational and irreversible. Moreover, the information technology-driven revolution which has enabled greater and easier personal choice in other sectors on the consumer economy will do the same in the American energy sector over the years to come. As a result, energy consumers will have increasing personal control over whom they buy their energy from, how that energy is generated and used and what environmental impact these individual choices will have. The Company's initiatives in this area of future growth are focused on: (i) renewables, with a concentration in solar development; (ii) electric vehicle ecosystems; (iii) customer-facing energy products and services, including smart energy services that give consumers individual energy insights, choices and convenience, a variety of renewable and energy efficiency products, and numerous loyalty and affinity options and tailored product and service bundles sold through unique retail sales channels; and (iv) construction of other forms of on-site clean power generation. The Company's advances in each of these areas are driven by select acquisitions, joint ventures, and investments that are more fully described in Item 1,  Business  —  New and On-going Company Initiatives and Development Projects.
Business Environment
The industry dynamics and external influences affecting the Company and the power generation industry in 2012 and for the future medium term include:
Consolidation — There were several mergers and acquisitions in the U.S. power sector in 2012 and 2011. Over the long term, industry consolidation is expected to continue.
Environmental Regulatory Landscape — The MATS rule, finalized in 2012, is the driving regulatory force behind the decision to retrofit, repower or retire uncontrolled coal fired power plants. Across the nation, companies are moving from the planning stages to implementation in order to meet the 2015 compliance date. A number of regulations on GHGs, ambient air quality, coal combustion byproducts and water use with the potential for capital costs or operational impacts are still in development or under review by the EPA. The design, timing and stringency of these regulations will contribute to a framework for the retrofit or retirement of existing fossil plants and deployment of new, cleaner technologies in the next decade. See Item 1, Business —  Environmental Matters , for further discussion.
Public Policy Support and Government Financial Incentives for Clean Infrastructure Development — Policy mechanisms including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, RPS, and carbon trading plans 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 of the Company's development program and expansion into clean energy investments.

62

Natural Gas Market — The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants. Natural gas prices are driven by variables including demand from the industrial, residential, and electric sectors, productivity across natural gas supply basins, costs of natural gas production, changes in pipeline infrastructure, and the financial and hedging profile of natural gas consumers and producers. In 2012, average natural gas prices at Henry Hub were 30% lower than 2011. Supply continues to reflect increased production from low extraction cost resources such as the shale basins. In 2012, a record mild winter and increased production led to spot prices trading below $2.00/MMBtu for twelve days. At these depressed levels, significant coal-to-gas switching was experienced making major changes to the Merit Order in many electric markets.
If long-term gas prices decrease or remain depressed, the Company is likely to encounter lower realized energy prices, leading to lower energy revenues as higher priced hedge contracts mature and are replaced by contracts with lower gas and power prices.  The Retail Business's gross margins have historically improved as natural gas prices decline and are likely to partially offset the impact of declining gas prices on conventional wholesale power generation.  To further mitigate this impact, NRG may increase its percentage of coal and nuclear capacity sold forward using a variety of hedging instruments, as described under the heading Energy Related Commodities in Item 15 — Note 5,  Accounting for Derivative Instruments and Hedging Activities,  to the Consolidated Financial Statements.  The Company also mitigates declines in long term gas prices through its increased investment in renewable power generation supported by PPAs as well as through the increasing portion of the fleet which benefits from capacity payments.
Electricity Price — The price of electricity is a key determinant of the profitability of the Company's generation portfolio. Many variables such as the price of different fuels, weather, load growth and unit availability all coalesce to impact the final price for electricity and the Company's profitability. In 2012, electricity prices in Texas and other regions were lower than 2011. Prices were lower than in 2011 mainly due to lower gas prices, lack of weather and negligible demand growth. The following table summarizes average on-peak power prices for each of the major markets in which NRG operates for the years ended December 31, 2012, 2011, and 2010:

 	Average on Peak Power Price ($/MWh)	
Region	2012	 	2011	 	2010	
Texas(a)	$	29.10	
 	 	$	57.42	
 	 	$	40.40	
 	
East	41.50	
 	 	53.09	
 	 	56.69	
 	
    NY J/NYC	46.90	
 	 	62.34	
 	 	66.59	
 	
    NY A/West NY	36.27	
 	 	42.14	
 	 	44.42	
 	
    Nepool	41.61	
 	 	52.80	
 	 	56.52	
 	
    PJM West Hub	39.87	
 	 	51.33	
 	 	54.57	
 	
South Central(b)	28.72	
 	 	37.38	
 	 	40.25	
 	
West(c)	33.44	
 	 	36.39	
 	 	40.05	
 	
(a) Average on-peak market power prices calculated based on average settled market prices in ERCOT - Houston and ERCOT - North.
(b) Average on-peak market power prices for South Central region are calculated based on average day ahead market prices for "into Entergy" as published in the Platts Megawatt Daily report.
(c) Average on-peak market power prices calculated based on average settled market prices in CAISO - NP15 and CAISO - SP15.
Weather
Weather conditions in the regions of the United States in which NRG does business influence the Company's financial results. Weather conditions can affect the supply and demand for electricity and fuels. Changes in energy supply and demand may impact the price of these energy commodities in both the spot and forward markets, which may affect the Company's results in any given period. Typically, demand for and the price of electricity is higher in the summer and the winter seasons, when temperatures are more extreme. The demand for and price of natural gas are higher in the winter. However, all regions of the United States typically do not experience extreme weather conditions at the same time, thus NRG is typically not exposed to the effects of extreme weather in all parts of its business at once.

63

Other Factors
A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for NRG's business. These factors include:
 	 	
•	seasonal, daily and hourly changes in demand;	
 	 	
•	extreme peak demands;	
 	 	
•	available supply resources;	
 	 	
•	transportation and transmission availability and reliability within and between regions;	
 	 	
•	location of NRG's generating facilities relative to the location of its load-serving opportunities;	
 	 	
•	procedures used to maintain the integrity of the physical electricity system during extreme conditions; and	
 	 	
•	changes in the nature and extent of federal and state regulations.	
These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country as a result of regional differences in:
 	 	
•	weather conditions;	
 	 	
•	market liquidity;	
 	 	
•	capability and reliability of the physical electricity and gas systems;	
 	 	
•	local transportation systems; and	
 	 	
•	the nature and extent of electricity deregulation.	
Environmental Matters, Regulatory Matters and Legal Proceedings
Details of other environmental matters are presented in Item 15 — Note 23, Environmental Matters, to the Consolidated Financial Statements and Item 1,  Business — Environmental Matters,  section. Details of regulatory matters are presented in Item 15 — Note 22,  Regulatory Matters , to the Consolidated Financial Statements and Item 1, Business — Regulatory Matters,  section. Details of legal proceedings are presented in Item 15 — Note 21, Commitments and Contingencies , to the Consolidated Financial Statements. Some of this information relates to costs that may be material to the Company's financial results.
Impact of inflation on NRG's results
Unless discussed specifically in the relevant segment, for the years ended December 31, 2012, 2011 and 2010, the impact of inflation and changing prices (due to changes in exchange rates) on NRG's revenues and net income was immaterial.
Significant events during the year ended December 31, 2012

Results of Operations and Financial Condition
 	 	
•	Higher net income — Net income increased 194% from $197 million to $579 million, as discussed in further detail below.	
 	 	
•	GenOn acquisition — On December 14, 2012, NRG completed the acquisition of GenOn.  GenOn, a generator of wholesale electricity, has baseload, intermediate and peaking power generation facilities using coal, natural gas and oil, totaling approximately 21,440 MW. The Company issued, as consideration for the acquisition, 0.1216 shares of NRG common stock for each outstanding share of GenOn, including restricted stock units outstanding, on the acquisition date, except for fractional shares which were paid in cash.  The Company issued 93.9 million shares of NRG common stock, or 29% of total common shares outstanding following the closing of the transaction, as discussed in more detail in Item 15 — Note 3,  Business Acquisitions and Dispositions.	
 	 	
•	Liquidity position — The Company's total liquidity, excluding collateral received, increased by $1.3 billion in 2012. Cash balances increased by $1.0 billion since the end of 2011, primarily due to the acquisition of GenOn and additional borrowings offset by capital expenditures for solar and other repowering projects.	
 	 	
•	Long-term debt — During 2012, the Company increased its non-recourse debt by approximately $6.3 billion primarily in connection with the acquisition of GenOn, the financing of the construction of various solar facilities, and the construction of El Segundo Energy Center.	

64

Consolidated Results of Operations
2012 compared to 2011 
The following table provides selected financial information for the Company:

 	Year Ended December 31,	 	 	
(In millions except otherwise noted)	2012 (a)	 	2011	 	Change %	
Operating Revenues	 	 	 	 	 	
Energy revenue (b)	$	2,114	
 	 	$	2,069	
 	 	2	 %	
Capacity revenue (b)	762	
 	 	736	
 	 	4	
 	
Retail revenue	5,888	
 	 	5,807	
 	 	1	
 	
Mark-to-market for economic hedging activities	(450	)	 	325	
 	 	238	
 	
Contract amortization	(97	)	 	(159	)	 	39	
 	
Other revenues (c)	205	
 	 	301	
 	 	(32	)	
Total operating revenues	8,422	
 	 	9,079	
 	 	(7	)	
Operating Costs and Expenses	 	 	 	 	 	
Generation cost of sales (b)	2,123	
 	 	2,488	
 	 	(15	)	
Retail cost of sales (b)	2,828	
 	 	2,815	
 	 	—	
 	
Mark-to-market for economic hedging activities	(182	)	 	169	
 	 	208	
 	
Contract and emissions credit amortization (d)	39	
 	 	47	
 	 	(17	)	
Other cost of operations	1,279	
 	 	1,156	
 	 	11	
 	
Total cost of operations	6,087	
 	 	6,675	
 	 	(9	)	
Depreciation and amortization	950	
 	 	896	
 	 	6	
 	
Impairment charge on emission allowances	—	
 	 	160	
 	 	(100	)	
Selling, general and administrative	892	
 	 	668	
 	 	34	
 	
Acquisition-related transaction and integration costs	107	
 	 	—	
 	 	100	
 	
Development costs	36	
 	 	45	
 	 	(20	)	
Total operating costs and expenses	8,072	
 	 	8,444	
 	 	(4	)	
Operating Income	350	
 	 	635	
 	 	(45	)	
Other Income/(Expense)	 	 	 	 	 	
Equity in earnings of unconsolidated affiliates	37	
 	 	35	
 	 	6	
 	
Bargain purchase gain related to GenOn acquisition	560	
 	 	—	
 	 	100	
 	
Impairment charge on investment	(2	)	 	(495	)	 	N/A	
 	
Other income, net	19	
 	 	19	
 	 	—	
 	
Loss on debt extinguishment	(51	)	 	(175	)	 	(71	)	
Interest expense	(661	)	 	(665	)	 	(1	)	
Total other expense	(98	)	 	(1,281	)	 	(92	)	
Income/(Loss) before income tax expense	252	
 	 	(646	)	 	(139	)	
Income tax benefit	(327	)	 	(843	)	 	(61	)	
Net Income	579	
 	 	197	
 	 	194	
 	
Less: Net income attributable to noncontrolling interest	20	
 	 	—	
 	 	100	
 	
Net income attributable to NRG Energy, Inc. 	$	559	
 	 	$	197	
 	 	184	
 	
Business Metrics	 	 	 	 	 	
Average natural gas price — Henry Hub ($/MMBtu)	2.79	
 	 	4.04	
 	 	(31	)%	
 	 	
(a)	Includes the results of GenOn from December 15, 2012 to December 31, 2012.	
 	 	
(b)	Includes realized gains and losses from financially settled transactions.	
 	 	
(b)	Includes unrealized trading gains and losses.	
 	 	
(c)	Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits.	
N/A - Not Applicable

65

Management’s discussion of the results of operations for the years ended December 31, 2012, and 2011 
Income/(Loss) before income tax expense —The pre-tax income of $252 million for the year ended December 31, 2012, compared to a pre-tax loss of $646 million for the year ended December 31, 2011, primarily reflects:
 	 	
•	in the current year, a decrease in operating income of $285 million as compared to the prior year period, which reflects:	
 	 	
◦	a decrease from net mark-to-market results for economic hedging activities of $424 million; and	
 	 	
◦	increased operating costs of $392 million including operations and maintenance expense, depreciation and amortization, selling, general and administrative costs and development costs as well as $107 million of acquisition-related transaction and integration costs; offset by:	
 	 	
◦	an increase in gross margin of $463 million comprised of an increase in Conventional Generation gross margin of $230 million, an increase in Retail gross margin of $124 million and an increase in Alternative Energy gross margin of $109 million; and	
 	 	
◦	in the prior year, a $160 million impairment charge on emissions allowances.	
 	 	
•	in addition, the change in income/(loss) before income tax expense also reflects:	
 	 	
◦	a $560 million bargain purchase gain on the acquisition of GenOn in the current year;	
◦a $495 million loss on the impairment of NRG's investment in NINA in the prior year; and
 	 	
◦	a $175 million loss on the extinguishment of the 2014 Senior Notes, the 2016 Senior Notes and the Senior Credit Facility in the prior year compared to a $51 million loss on the extinguishment of the 2017 Senior Notes in the current year.	
Net income — The increase in net income of $382 million primarily reflects the drivers discussed above and an income tax benefit for the year ended December 31, 2012, of $327 million, primarily due to a benefit of $196 million resulting from the bargain purchase gain related to the GenOn acquisition, the generation of ITCs from the Company's Agua Caliente solar project in Arizona of $158 million and the PTCs generated from certain Texas wind facilities of $14 million, compared with an income tax benefit of $843 million in the comparable period, which primarily reflects the resolution of the federal tax audit in June 2011 and the related recognition of previously uncertain tax benefits.

66

Conventional Generation gross margin
The following is a discussion of gross margin for NRG's Conventional Generation businesses, adjusted to eliminate intersegment activity, primarily with NRG's Retail Business segment.

 	For the Year Ended December 31, 2012	
 	Conventional Generation	 	 	 	 	 	 	 	 	
(In millions except otherwise noted)	Texas	 	East	 	South Central	 	West	 	Other	 	Subtotal	 	Alternative Energy	 	Eliminations/Corporate	 	Consolidated Total	
Energy revenue	$	2,406	
 	 	$	533	
 	 	$	527	
 	 	$	121	
 	 	$	39	
 	 	$	3,626	
 	 	$	150	
 	 	$	(1,662	)	 	$	2,114	
 	
Capacity revenue	81	
 	 	314	
 	 	240	
 	 	124	
 	 	41	
 	 	800	
 	 	—	
 	 	(38	)	 	762	
 	
Other revenue	28	
 	 	19	
 	 	(10	)	 	4	
 	 	241	
 	 	282	
 	 	3	
 	 	(80	)	 	205	
 	
Generation revenue	2,515	
 	 	866	
 	 	757	
 	 	249	
 	 	321	
 	 	4,708	
 	 	153	
 	 	$	(1,780	)	 	$	3,081	
 	
Generation cost of sales	(958	)	 	(440	)	 	(519	)	 	(88	)	 	(136	)	 	(2,141	)	 	—	
 	 	$	18	
 	 	$	(2,123	)	
Generation gross margin	$	1,557	
 	 	$	426	
 	 	$	238	
 	 	$	161	
 	 	$	185	
 	 	$	2,567	
 	 	$	153	

Business Metrics	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
MWh sold (in thousands)	43,707	
 	 	8,172	
 	 	17,935	
 	 	2,146	
 	 	 	 	 	 	1,988	
 	 	 	 	 	
MWh generated (in thousands)	37,695	
 	 	6,630	
 	 	15,927	
 	 	2,146	
 	 	 	 	 	 	1,988	

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	For the Year Ended December 31, 2011	
 	Conventional Generation	 	 	 	 	 	 	 	 	
(In millions except otherwise noted)	Texas	 	East	 	South Central	 	West	 	Other	 	Subtotal	 	Alternative Energy	 	Eliminations/Corporate	 	Consolidated Total	
Energy revenue	$	2,545	
 	 	$	579	
 	 	$	548	
 	 	$	31	
 	 	$	58	
 	 	$	3,761	
 	 	$	43	
 	 	$	(1,735	)	 	$	2,069	
 	
Capacity revenue	28	
 	 	291	
 	 	243	
 	 	118	
 	 	70	
 	 	750	
 	 	—	
 	 	(14	)	 	736	
 	
Other revenue	86	
 	 	26	
 	 	18	
 	 	4	
 	 	196	
 	 	330	
 	 	1	
 	 	(30	)	 	301	
 	
Generation revenue	2,659	
 	 	896	
 	 	809	
 	 	153	
 	 	324	
 	 	4,841	
 	 	44	
 	 	$	(1,779	)	 	$	3,106	
 	
Generation cost of sales	(1,228	)	 	(527	)	 	(547	)	 	(16	)	 	(186	)	 	(2,504	)	 	—	
 	 	$	16	
 	 	$	(2,488	)	
Generation gross margin	$	1,431	
 	 	$	369	
 	 	$	262	
 	 	$	137	
 	 	$	138	
 	 	$	2,337	
 	 	$	44	

Business Metrics	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
MWh sold (in thousands)	48,078	
 	 	9,317	
 	 	17,131	
 	 	215	
 	 	 	 	 	 	1,263	
 	 	 	 	 	
MWh generated (in thousands)	45,165	
 	 	7,361	
 	 	16,000	
 	 	215	
 	 	 	 	 	 	1,263	

 	Years ended December 31,	 	 	 	 	 	 	 	 	 	 	
Weather Metrics	Texas	 	East	 	South Central	 	West	 	 	 	 	 	 	 	 	 	 	
2012	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
CDDs (a)	3,134	
 	 	754	
 	 	1,782	
 	 	904	
 	 	 	 	 	 	 	 	 	 	 	
HDDs (a)	1,452	
 	 	5,317	
 	 	2,861	
 	 	2,988	
 	 	 	 	 	 	 	 	 	 	 	
2011	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
CDDs	3,440	
 	 	750	
 	 	1,817	
 	 	717	
 	 	 	 	 	 	 	 	 	 	 	
HDDs	1,911	
 	 	5,770	
 	 	3,387	
 	 	3,364	
 	 	 	 	 	 	 	 	 	 	 	
30 year average	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
CDDs	2,692	
 	 	540	
 	 	1,554	
 	 	711	
 	 	 	 	 	 	 	 	 	 	 	
HDDs	1,950	
 	 	6,206	
 	 	3,575	
 	 	3,259	

(a)	National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.	

67

Conventional Generation gross margin — increased by $230 million, including intercompany sales, during the years ended December 31, 2012, compared to the same period in 2011, due to:

Increase in Texas region	$	126	
 	
Increase in East region	57	
 	
Decrease in South Central region	(24	)	
Increase in West region	24	
 	
Other (a)	47	
 	
 	$	230	

(a)	Other gross margin primarily represents revenues from the maintenance services business, which are eliminated in consolidation.	
The increase in gross margin in the Texas region was driven by:

Impact of fewer unplanned outages during periods of high scarcity pricing as well as more effective hedging and trading optimization activities	$	96	
 	
Higher gross margin driven by higher average realized energy prices and a decrease in delivered coal costs	93	
 	
Higher revenue due to additional bi-lateral contracts with load serving entities and contracts with the Retail Business	53	
 	
Lower gross margin from a decrease in coal and nuclear generation driven by more unplanned outage hours in 2012	(73	)	
Change in unrealized trading activities	(56	)	
Other	13	
 	
 	$	126	

The increase in gross margin in the East region was driven by:

Higher gross margin from the acquisition of GenOn in December 2012	$	43	
 	
Higher gross margin from favorable pricing on certain load-serving contracts, as well as additional load contracts with the Retail Business	31	
 	
Lower capacity revenue due to 3% lower realized prices, due mainly to an 11% decrease in Nepool FCM prices offset in part by an increase in cleared auction prices in PJM and New York	(19	)	
Higher revenue due to RSS contract revenues in western New York.	18	
 	
Lower gross margin from coal plants due primarily to a 15% increase in delivered coal prices	(12	)	
Other	(4	)	
 	$	57	

The decrease in gross margin in the South Central region was driven by:

Higher gross margin from an increase in gas generation as a result of lower gas prices	$	117	
 	
Lower gross margin from a decrease in average realized merchant prices	(61	)	
Lower gross margin from decrease in coal generation due to several plants switching from coal to gas generation	(51	)	
Change in unrealized trading activities and other	(29	)	
 	$	(24	)	
The increase in gross margin in the West region was driven by:

Higher gross margin from increased run time at Encina driven by competitor's plant outages in the region and increased run time at the remaining plants in the region	$	22	
 	
Higher capacity margin due to the recognition of contingent rent for Long Beach	6	
 	
Decreased capacity revenue due to lower pricing and outage penalties for Encina, El Segundo and Cabrillo II	(6	)	
Higher gross margin from the acquisition of GenOn in December 2012	6	
 	
Decrease in fuel sales compared to 2011	(4	)	
 	$	24	

68

Retail gross margin
The following is a discussion of retail gross margin for NRG's Retail Business.
Selected Income Statement Data

 	Years ended December 31,	
(In millions except otherwise noted)	2012	 	2011	
Operating Revenues	 	 	 	
Mass revenues	$	3,669	
 	 	$	3,545	
 	
Commercial and Industrial revenues	2,074	
 	 	2,079	
 	
Supply management revenues	150	
 	 	188	
 	
Retail operating revenues (a)(b)	5,893	
 	 	5,812	
 	
Retail cost of sales (c)	4,515	
 	 	4,558	
 	
Retail gross margin	$	1,378	
 	 	$	1,254	

Business Metrics	 	 	 	
Electricity sales volume — GWh	 	 	 	
Mass	29,333	
 	 	28,035	
 	
Commercial and Industrial (d)	29,852	
 	 	28,567	
 	
Electricity sales volume — GWh	 	 	 	
Texas	53,451	
 	 	55,085	
 	
All other regions	5,734	
 	 	1,517	
 	
Average retail customers count (in thousands, metered locations)	 	 	 	
Mass (e)	2,036	
 	 	1,946	
 	
Commercial and Industrial (d)	109	
 	 	85	
 	
Retail customers count (in thousands, metered locations)	 	 	
 	
Mass (e)	2,088	
 	 	1,977	
 	
Commercial and Industrial (d)	122	
 	 	91	

Weather Metrics	 	 	 	
CDDs (f)	3,464	
 	 	3,845	
 	
HDDs (f)	1,126	
 	 	1,570	

(a)	Includes customers of the Texas General Land Office for which the Company provides services, as well as sales to utility partner customers.	
 	 	
(b)	Includes intercompany sales of $5 million in both 2012 and 2011, representing sales from Retail to the Texas region.	
 	 	
(c)	Includes intercompany purchases of $1,687 million and $1,743 million, respectively.	
 	 	
(d)	Includes customers of the Texas General Land Office for which the Company provides services.	
 	 	
(e)	Excludes utility partner customers.	
 	 	
(f)	The CDDs/HDDs amounts are representative of the Coast and North Central Zones within the ERCOT market in which Retail serves its customer base.	
 	 	
•	Retail gross margin — Retail gross margin increased $124 million for the year ended December 31, 2012, compared to the same period in 2011, driven by:	

 	 	 	 	
Gross margin for an additional nine months of Energy Plus as it was acquired in September 2011	$	112	
 	
Increase in usage and customer count	54	
 	
Decrease in unit margins driven by the impact of lower pricing and lower supply costs on acquisitions and renewals	(48	)	
Favorable impact of fewer scarcity price increases during times of excessive load compared to prior year, partially offset by generally milder weather in 2012	27	
 	
Unfavorable impact of weather-related risk management activities	(21	)	
 	$	124	

•	Trends — Customer counts increased by approximately 142,000 since December 31, 2011, which was primarily due to expansion into new territories and marketing efforts. While cooling and heating degree days in both periods resulted in higher than normal customer usage, weather in 2012 was milder than in 2011. The weather resulted in higher customer usage of 4% and 13% in 2012 and 2011, respectively, when compared to ten-year normal weather. In addition, there were increases in Texas in Transmission and Distribution Service Provider rates that will remain in effect for several years. These costs are passed through to Retail customers.	

69

Alternative Energy gross margin
NRG's Alternative Energy business segment, which is comprised mainly of the solar and wind businesses, had gross margin of $153 million for the year ended December 31, 2012, compared to gross margin of $44 million for the same period in 2011. The increase in gross margin primarily resulted from the addition of the Roadrunner facility, which began commercial operations in late 2011, the addition of the first 230 MW of Agua Caliente, which reached commercial operations in 2012, the addition of the first 127 MW of the California Valley Solar Ranch facility, or CVSR, and an increase in gross margin from Distributed Solar.
Mark-to-market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results decreased by $424 million during the year ended December 31, 2012, compared to the same period in 2011.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:

 	For the Year Ended December 31, 2012	
 	Retail	 	Texas	 	East	 	South
Central	 	West	 	Alternative Energy	 	Elimination(a)	 	Total	
 	(In millions)	
Mark-to-market results in operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(7	)	 	$	(501	)	 	$	2	
 	 	$	40	
 	 	$	8	
 	 	$	—	
 	 	$	19	
 	 	$	(439	)	
Reversal of gain positions acquired as part of the GenOn acquisition	—	
 	 	—	
 	 	(13	)	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(13	)	
Net unrealized gains/(losses) on open positions related to economic hedges	2	
 	 	60	
 	 	(1	)	 	(10	)	 	2	
 	 	—	
 	 	(51	)	 	2	
 	
Total mark-to-market (losses)/gains in operating revenues	$	(5	)	 	$	(441	)	 	$	(12	)	 	$	30	
 	 	$	10	
 	 	$	—	
 	 	$	(32	)	 	$	(450	)	
Mark-to-market results in operating costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	181	
 	 	$	15	
 	 	$	12	
 	 	$	3	
 	 	$	—	
 	 	$	—	
 	 	$	(19	)	 	$	192	
 	
Reversal of loss positions acquired as part of the Reliant Energy, Green Mountain Energy and GenOn acquisitions	24	
 	 	—	
 	 	9	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	33	
 	
Net unrealized (losses)/gains on open positions related to economic hedges	(34	)	 	(38	)	 	(6	)	 	(16	)	 	—	
 	 	—	
 	 	51	
 	 	(43	)	
Total mark-to-market gains/(losses) in operating costs and expenses	$	171	
 	 	$	(23	)	 	$	15	
 	 	$	(13	)	 	$	—	
 	 	$	—	
 	 	$	32	
 	 	$	182	

(a)	Represents the elimination of the intercompany activity between the Retail Business and the Conventional Generation regions.	
Mark-to-market results consist of unrealized gains and losses. The settlement of these transactions is reflected in the same caption as the items being hedged.
For the year ended December 31, 2012, the net losses on open positions were due primarily to decreases in forward coal prices.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the year ended December 31, 2012, and 2011. The realized and unrealized financial and physical trading results are included in operating revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy.

 	Year ended December 31,	
(In millions)	2012	 	2011	
Trading gains/(losses)	 	 	 	
Realized	$	83	
 	 	$	(31	)	
Unrealized	(14	)	 	63	
 	
Total trading gains	$	69	
 	 	$	32	

70

Contract Amortization Revenue
Contract amortization represents the roll-off of in-market customer contracts valued under acquisition accounting and the favorable change of $62 million, as compared to 2011, related primarily to lower contract amortization of $43 million and $19 million for Reliant Energy and Green Mountain Energy, respectively.
Other Operating Costs

 	Retail	 	Texas	 	East	 	South
Central	 	West	 	Other(a)	 	Alternative Energy	 	Eliminations/Corporate	 	Total	
 	(In millions)	
Year Ended December 31, 2012	$	241	
 	 	$	544	
 	 	$	260	
 	 	$	107	
 	 	$	63	
 	 	$	105	
 	 	$	25	
 	 	$	(66	)	 	$	1,279	
 	
Year Ended December 31, 2011	$	216	
 	 	$	477	
 	 	$	241	
 	 	$	104	
 	 	$	56	
 	 	$	71	
 	 	$	17	
 	 	$	(26	)	 	$	1,156	
 	
Other operating costs increased by $123 million for the year ended December 31, 2012, compared to the same period in 2011, due to:

Increase in Retail operations and maintenance expense	$	25	
 	
Increase in Texas region operations and maintenance expense	67	
 	
Increase in East region operations and maintenance expense	14	
 	
Increase in Alternative Energy operations and maintenance expense	9	
 	
Increase in property tax expense	8	
 	
 	$	123	
 	
(a) The majority of other is intercompany in nature and eliminates in consolidation.
 	 	
◦	Retail operations and maintenance expense — increased $12 million due to the acquisition of Energy Plus in September 2011 and approximately $13 million due to expansion into new markets, products and channels.	
 	 	
◦	Texas operations and maintenance— increased primarily due to maintenance spending and outage work in 2012 at Limestone and W.A. Parish as well as additional costs at S.R. Bertron to return two units to service.	
 	 	
◦	East operations and maintenance expense— increased due to additional costs of $30 million from the acquisition of GenOn, offset by a decrease in part because the prior year reflects incremental costs associated with headcount reductions.	
 	 	
◦	Alternative Energy operations and maintenance expense— increased as additional solar facilities, including 253 MW of Agua Caliente and 127 MW of CVSR, began commercial operations in 2012.	
 	 	
◦	Property tax expense— increased primarily for $5 million in the East region due to a reduction in property tax benefit from the New York State Empire Zone program, which reflects a change in the criteria used in determining the amount of the tax credit and an annual reduction of 20%. The remaining increases are primarily due to the acquisition of GenOn.	
Depreciation and Amortization Expense
Depreciation and amortization expense increased by $54 million for the year ended December 31, 2012, compared to the same period in 2011. This was primarily due to additional depreciation related to solar facilities which commenced commercial operations in late 2011 and in 2012, as well as additional depreciation in the East due to the Indian River AQCS assets placed in service and the acquisition of GenOn.
Impairment Charge on Emission Allowances
As described in Item 15 — Note 23, Environmental Matters, to the Consolidated Financial Statements, NRG recorded an impairment charge of $160 million in the year ended December 31, 2011, on the Company's Acid Rain Program SO 2 emission allowances, which were recorded as an intangible asset on the Company's balance sheet. The impairment charge reflects the write-off of the value of emission allowances in excess of those required for compliance with the Acid Rain Program.

71

Selling, General and Administrative Expenses
Selling, general and administrative expenses increased by $224 million for the year ended December 31, 2012, compared to the same period in 2011, which was due primarily to the following:
 	 	
•	Selling, general and administrative costs of $66 million for an additional nine months of Energy Plus which was acquired in September 2011;	
 	 	
•	Cash payment related to the CDWR settlement of $20 million expensed during the period and paid in January 2013;	
•Transaction costs of $9 million associated with the sale of 49% of Agua Caliente;
 	 	
•	Increase in marketing and selling costs of $51 million associated with customer growth efforts and new market expansion by corporate and the Retail Business;	
•Increase of $13 million related to additional solar projects and acquired Distributed Solar businesses;
•The impact of a settlement with the EPA regarding LaGen of $14 million; and
 	 	
•	Additional costs associated with new business initiatives of $13 million, consulting and legal costs of $15 million and $16 million of additional labor costs, as well an additional $7 million of expense incurred in the post-acquisition period as GenOn was acquired in December 2012.	
Acquisition-related Transaction and Integration Costs
As previously announced, NRG acquired GenOn in December 2012. In connection with the transaction, NRG incurred transaction and integration costs of $107 million in the year ended December 31, 2012, consisting primarily of severance associated with headcount reductions, financial consulting fees and legal expenses.
Bargain purchase gain related to GenOn acquisition
In connection with the acquisition of GenOn in December 2012, the Company recorded a bargain purchase gain of $560 million in the year ended December 31, 2012. The gain is primarily representative of the undiscounted value of the deferred tax assets generated by the reduction in book basis of the net assets recorded in connection with acquisition accounting as well as the undiscounted value of GenOn’s net operating losses and other deferred tax benefits that the combined company has the ability to realize in the post-acquisition period.
Impairment Charge on Investment
As discussed in more detail in Item 15 — Note 2, Summary of Significant Accounting Policies, to the Consolidated Financial Statements, the March 2011 earthquake and tsunami in Japan, which in turn triggered a nuclear incident at the Fukushima Daiichi Nuclear Power Station, caused NRG to evaluate its investment in NINA for impairment. Consequently, NRG deconsolidated its investment in NINA and took an impairment charge in the first quarter of 2011 equal to the balance of its investment in NINA. To support NINA's ongoing work, NRG contributed an additional $14 million into NINA during the year ended December 31, 2011. As a result, NRG recorded an impairment charge of $495 million in the year ended December 31, 2011. During the year ended December 31, 2012, NRG contributed an additional $2 million and recorded this amount as an impairment charge.
Loss on Debt Extinguishment
A loss on debt extinguishment of the 2017 Senior Notes of $51 million was recorded in the year ended December 31, 2012, while a loss on debt extinguishment of the 2014 Senior Notes, the 2016 Senior Notes and the Senior Credit Facility of $175 million was recorded in the year ended December 31, 2011. These losses primarily consisted of the premiums paid on redemption and the write-off of previously deferred financing costs.

72

Interest Expense
NRG's interest expense decreased by $4 million for the year ended December 31, 2012, compared to the same period in 2011 due to the following:

Increase/(decrease) in interest expense	(In millions)	
Increase for 2023 Senior Notes issued in September 2012	$	18	
 	
Increase for 2018 Senior Notes issued in January of 2011 and 2019 and 2021 Senior Notes issued in May of 2011	65	
 	
Decrease for 2017 Senior Notes redeemed in September 2012	(20	)	
Decrease for 2014 Senior Notes and 2016 Senior Notes redeemed in 2011	(82	)	
Decrease for higher capitalized interest	(58	)	
Increase from additional project financings	47	
 	
Increase in derivative interest expense primarily for the Alpine interest rate swaps	10	
 	
Increase for GenOn senior notes	9	
 	
Other	7	
 	
Total	$	(4	)	
Income Tax Benefit
For the year ended December 31, 2012, NRG recorded an income tax benefit of $327 million on pre-tax income of $252 million. For the same period in 2011, NRG recorded an income tax benefit of $843 million on a pre-tax loss of $646 million. The effective tax rate was (129.8)% and 130.5% for the years ended December 31, 2012, and 2011, respectively.
For the year ended December 31, 2012, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to a benefit of $196 million resulting from the gain on bargain purchase of GenOn, the generation of ITCs from the Company's Agua Caliente solar project in Arizona of $158 million and the PTCs generated from certain Texas wind facilities of $14 million.

 	Year Ended December 31,	
 	2012	 	2011	
 	(In millions
except as otherwise stated)	
Income/(Loss) Before Income Taxes	$	252	
 	 	$	(646	)	
Tax at 35%	88	
 	 	(226	)	
State taxes, net of federal benefit	13	
 	 	15	
 	
Foreign operations	(24	)	 	(3	)	
Federal and state tax credits	(158	)	 	(1	)	
Valuation allowance	5	
 	 	(63	)	
Expiration/utilization of capital losses	—	
 	 	45	
 	
Reversal of valuation allowance on expired/utilized capital losses	—	
 	 	(45	)	
Change in state effective tax rate	(12	)	 	—	
 	
Foreign earnings	—	
 	 	4	
 	
Impact of non-taxable entity earnings	(7	)	 	—	
 	
Bargain purchase gain related to GenOn acquisition	(196	)	 	—	
 	
Interest accrued on uncertain tax positions	2	
 	 	2	
 	
Production tax credits	(14	)	 	(14	)	
Reversal of uncertain tax position reserves	(13	)	 	(561	)	
Other	(11	)	 	4	
 	
Income tax benefit	$	(327	)	 	$	(843	)	
Effective income tax rate	(129.8	)%	 	130.5	%	
The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with ASC 740,  Income Taxes,  or ASC 740. These factors and others, including the Company's history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.

73

Consolidated Results of Operations
2011 compared to 2010
The following table provides selected financial information for the Company:

 	Year Ended December 31,	 	 	
(In millions except otherwise noted)	2011	 	2010	 	Change %	
Operating Revenues	 	 	 	 	 	
Energy revenue (a)	$	2,069	
 	 	$	2,854	
 	 	(28	)%	
Capacity revenue (a)	736	
 	 	824	
 	 	(11	)	
Retail revenue	5,807	
 	 	5,277	
 	 	10	
 	
Mark-to-market for economic hedging activities	325	
 	 	(199	)	 	263	
 	
Contract amortization	(159	)	 	(195	)	 	18	
 	
Other revenues (b)	301	
 	 	288	
 	 	5	
 	
Total operating revenues	9,079	
 	 	8,849	
 	 	3	
 	
Operating Costs and Expenses	 	 	 	 	 	
Generation cost of sales (a)	2,488	
 	 	2,170	
 	 	15	
 	
Retail cost of sales (a)	2,815	
 	 	2,822	
 	 	—	
 	
Mark-to-market for economic hedging activities	169	
 	 	(111	)	 	252	
 	
Contract and emissions credit amortization (c)	47	
 	 	15	
 	 	213	
 	
Other cost of operations	1,156	
 	 	1,177	
 	 	(2	)	
Total cost of operations	6,675	
 	 	6,073	
 	 	10	
 	
Depreciation and amortization	896	
 	 	838	
 	 	7	
 	
Impairment charge on emission allowances	160	
 	 	—	
 	 	N/A	
 	
Selling, general and administrative	668	
 	 	598	
 	 	12	
 	
Development costs	45	
 	 	55	
 	 	(18	)	
Total operating costs and expenses	8,444	
 	 	7,564	
 	 	12	
 	
Gain on sale of assets	—	
 	 	23	
 	 	(100	)	
Operating Income	635	
 	 	1,308	
 	 	(51	)	
Other Income/(Expense)	 	 	 	 	 	
Equity in earnings of unconsolidated affiliates	35	
 	 	44	
 	 	(20	)	
Impairment charge on investment	(495	)	 	—	
 	 	N/A	
 	
Other income, net	19	
 	 	33	
 	 	(42	)	
Loss on debt extinguishment	(175	)	 	(2	)	 	N/A	
 	
Interest expense	(665	)	 	(630	)	 	6	
 	
Total other expense	(1,281	)	 	(555	)	 	131	
 	
(Loss)/Income before income tax expense	(646	)	 	753	
 	 	(186	)	
Income tax (benefit)/ expense	(843	)	 	277	
 	 	(404	)	
Net Income	197	
 	 	476	
 	 	(59	)	
Less: Net loss attributable to noncontrolling interest	—	
 	 	(1	)	 	100	
 	
Net income attributable to NRG Energy, Inc. 	$	197	
 	 	$	477	
 	 	(59	)	
Business Metrics	 	 	 	 	 	
Average natural gas price — Henry Hub ($/MMBtu)	4.04	
 	 	4.39	
 	 	(8	)%	
 	 	
(a)	Includes realized gains and losses from financially settled transactions.	
 	 	
(b)	Includes unrealized trading gains and losses.	
 	 	
(c)	Includes amortization of SO2 and NOx credits and excludes amortization of Regional Greenhouse Gas Initiative, or RGGI, credits.	
N/A - Not Applicable

74

Management's discussion of the results of operations for the years ended December 31, 2011 and 2010 
Conventional Generation gross margin
The following is a discussion of gross margin for NRG's Conventional Generation businesses, adjusted to eliminate intersegment activity primarily with the Retail Business.

 	Year Ended December 31, 2011	
 	Conventional Generation	 	 	 	 	 	 	 	 	
(In millions except otherwise noted)	Texas	 	East	 	South Central	 	West	 	Other	 	Subtotal	 	Alternative Energy	 	Eliminations/Corporate	 	Consolidated
Total	
Energy revenue	$	2,545	
 	 	$	579	
 	 	$	548	
 	 	$	31	
 	 	$	58	
 	 	$	3,761	
 	 	$	43	
 	 	$	(1,735	)	 	$	2,069	
 	
Capacity revenue	28	
 	 	291	
 	 	243	
 	 	118	
 	 	70	
 	 	750	
 	 	 	 	(14	)	 	736	
 	
Other revenue	86	
 	 	26	
 	 	18	
 	 	4	
 	 	196	
 	 	330	
 	 	1	
 	 	(30	)	 	301	
 	
Generation revenue	2,659	
 	 	896	
 	 	809	
 	 	153	
 	 	324	
 	 	4,841	
 	 	$	44	
 	 	$	(1,779	)	 	$	3,106	
 	
Generation cost of sales	(1,228	)	 	(527	)	 	(547	)	 	(16	)	 	(186	)	 	(2,504	)	 	 	 	$	16	
 	 	$	(2,488	)	
Generation gross margin	$	1,431	
 	 	$	369	
 	 	$	262	
 	 	$	137	
 	 	$	138	
 	 	$	2,337	
 	 	$	44	

Business Metrics	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
MWh sold (in thousands)	48,078	
 	 	9,317	
 	 	17,131	
 	 	215	

 	 	1,263	

 	
MWh generated (in thousands)	45,165	
 	 	7,361	
 	 	16,000	
 	 	215	

 	 	1,263	

 	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Year Ended December 31, 2010	
 	Conventional Generation	 	 	 	 	 	 	 	 	
(In millions except otherwise noted)	Texas	 	East	 	South Central	 	West	 	Other	 	Subtotal	 	Alternative Energy	 	Eliminations/Corporate	 	Consolidated
Total	
Energy revenue	$	2,840	
 	 	$	726	
 	 	$	387	
 	 	$	25	
 	 	$	46	
 	 	$	4,024	
 	 	$	39	
 	 	$	(1,209	)	 	$	2,854	
 	
Capacity revenue	25	
 	 	396	
 	 	235	
 	 	113	
 	 	71	
 	 	840	
 	 	 	 	(16	)	 	824	
 	
Other revenue	111	
 	 	47	
 	 	10	
 	 	4	
 	 	186	
 	 	358	
 	 	2	
 	 	(72	)	 	288	
 	
Generation revenue	2,976	
 	 	1,169	
 	 	632	
 	 	142	
 	 	303	
 	 	5,222	
 	 	$	41	
 	 	$	(1,297	)	 	$	3,966	
 	
Generation cost of sales	(1,111	)	 	(493	)	 	(403	)	 	(15	)	 	(166	)	 	(2,188	)	 	 	 	$	18	
 	 	$	(2,170	)	
Generation gross margin	$	1,865	
 	 	$	676	
 	 	$	229	
 	 	$	127	
 	 	$	137	
 	 	$	3,034	
 	 	$	41	

Business Metrics	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
MWh sold (in thousands)	45,948	
 	 	10,581	
 	 	13,046	
 	 	217	

 	 	1,030	

MWh generated (in thousands)	43,722	
 	 	9,355	
 	 	11,168	
 	 	217	

 	 	1,030	

 	

 	 	 	 	 	 	 	 	 	 	 	 	
 	Year Ended December 31,	
 	Texas	 	East	 	South Central	 	West	
Weather Metrics	 	 	 	 	 	 	 	
2011	 	 	 	 	 	 	 	
CDDs (a)	3,440	
 	 	750	
 	 	1,817	
 	 	717	
 	
HDDs (a)	1,911	
 	 	5,770	
 	 	3,387	
 	 	3,364	
 	
2010	 	 	 	 	 	 	 	
CDDs	2,884	
 	 	850	
 	 	2,006	
 	 	678	
 	
HDDs	2,161	
 	 	5,720	
 	 	3,929	
 	 	2,753	
 	
30 year average	 	 	 	 	 	 	 	
CDDs	2,647	
 	 	537	
 	 	1,548	
 	 	704	
 	
HDDs	1,997	
 	 	6,257	
 	 	3,601	
 	 	3,218	

(a)	National Oceanic and Atmospheric Administration-Climate Prediction Center — A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.	

75

Conventional Generation gross margin — decreased by $697 million, including intercompany sales, during the year ended December 31, 2011, compared to the same period in 2010, due to:

Decrease in Texas region	$	(434	)	
Decrease in East region	(307	)	
Increase in South Central region	33	
 	
Increase in West region	10	
 	
Other	1	
 	
 	$	(697	)	
The decrease in gross margin in the Texas region was driven by:

Lower energy revenue due to a 14% decrease in average realized energy prices, which reflects lower
    hedged prices in 2011	$	(315	)	
Losses incurred primarily due to hedging and trading optimization activities, and the impact of unplanned outages at gas plants as ERCOT power prices spiked in August 2011	(80	)	
Higher coal costs due to a 9% increase in realized coal prices offset by favorable financial fuel hedges	(40	)	
Favorable gross margin impact from a 2% increase in coal generation driven by higher economic dispatch and fewer planned outages, partially offset by greater unplanned outages	24	
 	
Unfavorable gross margin impact due to a 4% decrease in nuclear generation driven by an increase in unplanned outages	(18	)	
Other	(5	)	
 	$	(434	)	
The decrease in gross margin in the East region was driven by:

Lower gross margin from coal plants due to a 34% decrease in realized energy prices	$	(129	)	
Lower gross margin from coal plants resulting from a 30% decrease in generation, due to the region's power generation switching from coal to gas plants as gas prices decreased and due to the retirement of one unit at Indian River	(81	)	
Lower capacity revenue due to 10% lower volumes from higher forced outage rates and a 12% decrease in realized prices	(71	)	
Lower capacity revenue due to significantly lower LFRM prices and volumes in New England	(27	)	
Other	1	
 	
 	$	(307	)	
The increase in gross margin in the South Central region was driven by:

Higher gross margin from merchant energy due to a 155% increase in MWh sold, primarily related to the addition of the Cottonwood facility	$	29	
 	
Lower merchant revenue related to a 7% decrease in average realized prices	(18	)	
Higher contract revenue from new contracts with three regional municipalities	29	
 	
Higher capacity revenue due primarily to higher cooperative billing peaks	8	
 	
Higher coal costs due to a 1% increase in generation at the region's coal plant which reflects fewer outage hours in 2011 and a 4% increase in price due to higher transportation costs	(16	)	
Other	1	
 	
 	$	33	
 	
The increase in gross margin in the West region was driven by:

Higher capacity revenue due to additional sales at El Segundo and a price increase on the Cabrillo I tolling agreement	$	5	
 	
Increase in other revenue due to fuel oil sales at Encina and financial revenues	6	
 	
Other	(1	)	
 	$	10	

76

Retail gross margin
The Company's Retail Business segment is comprised of Reliant Energy, Green Mountain Energy and Energy Plus. The following is a detailed discussion of retail gross margin for NRG's Retail Business segment. Green Mountain Energy and Energy Plus were acquired on November 5, 2010 and September 30, 2011, respectively.

 	Year ended December 31,	
(In millions except otherwise noted)	2011	 	2010	
Operating Revenues	 	 	 	
Mass revenues	$	3,545	
 	 	$	3,127	
 	
Commercial and Industrial revenues	2,079	
 	 	1,994	
 	
Supply management revenues	188	
 	 	158	
 	
Retail operating revenues (a)(b)	5,812	
 	 	5,279	
 	
Retail cost of sales (c)	4,558	
 	 	4,066	
 	
Retail gross margin	$	1,254	
 	 	$	1,213	

Business Metrics	 	 	 	
Electricity sales volume — GWh	 	 	 	
Mass	28,035	
 	 	22,924	
 	
Commercial and Industrial (a)	28,567	
 	 	26,372	
 	
Electricity sales volume — GWh	 	 	 	
Texas	55,085	
 	 	49,261	
 	
All other regions	1,517	
 	 	35	
 	
Average retail customers count (in thousands, metered locations)	 	 	 	
Mass	1,946	
 	 	1,731	
 	
Commercial and Industrial (a)	85	
 	 	74	
 	
Retail customers count (in thousands, metered locations)	 	 	 	
Mass	1,977	
 	 	1,704	
 	
Commercial and Industrial (a)	91	
 	 	74	
 	
Weather Metrics	 	 	 	
CDDs (d)	3,845	
 	 	3,305	
 	
HDDs (d)	1,570	
 	 	1,812	

(a)	Includes customers of the Texas General Land Office, for whom the Company provides services.	
 	 	
(b)	Includes intercompany sales of $5 million and $2 million, representing sales from Retail to the Texas region for the years ended December 31, 2011 and 2010, respectively.	
 	 	
(c)	Includes intercompany purchases of $1,743 million and $1,244 million, respectively.	
 	 	
(d)	The CDDs/HDDs amounts are representative of the Coast and North Central Zones within the ERCOT market in which Retail serves its customer base.	
 	 	
•	Retail gross margin — Retail gross margin increased $41 million for the year ended December 31, 2011, compared to the same period in 2010, driven by:	

 	 	 	 	
Reliant Energy:	 	
Unfavorable gross margin impact of an unprecedented heat wave which resulted in high supply costs for incremental weather volume in August 2011, offset in part by the favorable impact of weather in the first six months of 2011	$	(50	)	
Favorable volume impact on gross margin of higher average customer usage, offset in part by fewer customers and a change in customer mix	25	
 	
Decrease in retail margins of 8% due to lower pricing on acquisitions and renewals consistent with
    competitive offers	(42	)	
Estimated favorable impact in 2010 as compared to 2011 from the termination of out-of-market supply contracts in conjunction with 2009 CSRA unwind	(68	)	
Acquisition of Green Mountain Energy on November 5, 2010	151	
 	
Acquisition of Energy Plus on September 30, 2011	25	
 	
 	$	41	

•	Trends — Customer counts increased by approximately 102,000 since December 31, 2010, excluding the approximately 188,000 customers acquired in the Energy Plus acquisition, indicating a stabilization of customer attrition at Reliant Energy and customer acquisition efforts at Green Mountain Energy. Higher than normal cooling and heating degree days in both periods resulted in higher customer usage for Reliant Energy of 13% in 2011 and 7% in 2010 when compared to ten-year normal weather.	

77

Alternative Energy gross margin
NRG's Alternative Energy business segment, which is comprised mainly of the solar and wind businesses, had gross margin of $44 million for the year ended December 31, 2011, compared to gross margin of $41 million for the year ended December 31, 2010. The increase in gross margin primarily resulted from the addition of the Roadrunner facility, which began commercial operations in late 2011.

Mark-to-market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results increased by $244 million in the year ended December 31, 2011, compared to the same period in 2010.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region are as follows:

 	Year Ended December 31, 2011	
 	Retail	 	Texas	 	East	 	South
Central	 	West	 	Elimination (a)	 	Total	
 	(In millions)	
Mark-to-market results in operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1	)	 	$	(72	)	 	$	19	
 	 	$	26	
 	 	$	(2	)	 	$	(48	)	 	$	(78	)	
Net unrealized gains/(losses) on open positions related to economic hedges	9	
 	 	245	
 	 	9	
 	 	(38	)	 	(2	)	 	180	
 	 	403	
 	
Total mark-to-market gains/(losses) in operating revenues	$	8	
 	 	$	173	
 	 	$	28	
 	 	$	(12	)	 	$	(4	)	 	$	132	
 	 	$	325	
 	
Mark-to-market results in operating costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	94	
 	 	$	—	
 	 	$	(6	)	 	$	(4	)	 	$	—	
 	 	$	48	
 	 	$	132	
 	
Reversal of loss positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions	107	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	107	
 	
Net unrealized losses on open positions related to economic hedges	(175	)	 	(23	)	 	(17	)	 	(13	)	 	—	
 	 	(180	)	 	(408	)	
Total mark-to-market gains/(losses) in operating costs and expenses	$	26	
 	 	$	(23	)	 	$	(23	)	 	$	(17	)	 	$	—	
 	 	$	(132	)	 	$	(169	)	
 	 	
(a)	Represents the elimination of the intercompany activity between the Retail Business and the Conventional Generation regions and Alternative Energy.	
Mark-to-market results consist of unrealized gains and losses. The settlement of these transactions is reflected in the same caption as the items being hedged.
For the year ended December 31, 2011, the net losses on open positions were due to a decrease in forward power and gas prices. The reversal of loss positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions were valued using forward prices on the acquisition dates. The roll-off amounts were offset by realized losses at the settled prices and higher costs of physical power which are reflected in operating costs and expenses during the same period.

78

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the years ended December 31, 2011, and 2010. The realized and unrealized financial and physical trading results are included in operating revenues. The Company's trading activities are subject to limits within the Company's Risk Management Policy.

 	Year Ended December 31,	
 	2011	 	2010	
 	(In millions)	
Trading gains/(losses)	 	 	 	
Realized	$	(31	)	 	$	(25	)	
Unrealized	63	
 	 	64	
 	
Total trading gains	$	32	
 	 	$	39	
 	
Contract Amortization Revenue
Contract amortization represents the roll-off of in-market customer contracts valued under purchase accounting and the favorable change of $36 million as compared to the prior period in 2010 related primarily to lower contract amortization of $74 million for Reliant Energy, offset by higher contract amortization of $29 million for Green Mountain Energy.
Contract and Emissions Credit Amortization
Contract and emissions credit amortization increased primarily due to lower amortization, which is an offset to expense, of out-of-the-money energy supply contracts that were valued as part of the purchase accounting for Reliant Energy.
Other Operating Costs

 	Retail	 	Texas	 	East	 	South
Central	 	West	 	Other	 	Alternative Energy	 	Corporate/Eliminations	 	Total	
 	(In millions)	
Year ended December 31, 2011	$	216	
 	 	$	477	
 	 	$	241	
 	 	$	104	
 	 	$	56	
 	 	$	71	
 	 	$	17	
 	 	$	(26	)	 	$	1,156	
 	
Year ended December 31, 2010	$	195	
 	 	$	484	
 	 	$	287	
 	 	$	93	
 	 	$	64	
 	 	$	68	
 	 	$	15	
 	 	$	(29	)	 	$	1,177	
 	
Other operating costs decreased by $21 million for the year ended December 31, 2011, compared to the same period in 2010, due to:

 	(In millions)	
Decrease in East region operations and maintenance expense	$	(50	)	
Increase in Retail operations and maintenance expense	22	
 	
Increase in South Central region operations and maintenance expense	6	
 	
Other	1	
 	
 	$	(21	)	
 	 	
◦	East operations and maintenance— decreased due to a $19 million reduction in normal and major maintenance, primarily in Western New York, an $18 million decrease in operational labor from headcount reductions at plants in New England and New York, and prior year write-offs of $21 million of construction-in-progress, including those in connection with the early retirement of Indian River Unit 3, and additional write-offs at Arthur Kill, Keystone and Conemaugh.  These were offset in part by the current year write-off of $12 million of Bluewater Wind assets.	
 	 	
◦	Retail operations and maintenance— increased as a result of the acquisition of Green Mountain Energy in November 2010, resulting in a full year of expense compared to two months in the prior year, as well as the acquisition of Energy Plus on September 30, 2011.	
 	 	
◦	South Central operations and maintenance— increased by $18 million due to increased operations and maintenance related to the addition of the Cottonwood Facility, offset in part by $12 million related to the scope and timing of outage work at Big Cajun II in 2010.	

79

Depreciation and Amortization
NRG's depreciation and amortization expense increased by $58 million during the year ended December 31, 2011, compared to the same period in 2010. This was primarily due to additional depreciation related to a full year of depreciation for Cottonwood, Green Mountain Energy, and Northwind Phoenix which were acquired in 2010, as compared to a partial year of depreciation in 2010.
Impairment Charge on Emission Allowances
As described in Item 15 — Note 23, Environmental Matters, to the Consolidated Financial Statements,the Company recorded an impairment charge of $160 million in the year ended December 31, 2011, on the Company's Acid Rain Program SO 2  emission allowances, which were recorded as an intangible asset on the Company's balance sheet. The impairment charge reflects the write-off of the value of emission allowances in excess of those required for compliance with the Acid Rain Program.
Selling, General and Administrative Expenses
Selling, general and administrative expenses increased by $70 million during the year ended December 31, 2011, compared to the same period in 2010, which was primarily due to:
 	 	
•	The acquisition of Green Mountain Energy in November 2010, and the acquisition of Energy Plus in September 2011, which resulted in additional expense in 2011 of $74 million and $16 million, respectively.	
 	 	
•	Increased marketing costs of $8 million associated with additional advertising campaigns and sponsorship arrangements.	
These increases were offset by:
 	 	
•	A decrease in bad debt expense of $13 million at Reliant Energy due to improved customer payment behavior and decreased revenues.	
 	 	
•	A decrease in employee benefits costs of $24 million.	
 	 	
•	A reduction in charitable contributions, due to $8 million of funding for the Reliant Energy Charitable Foundation which was created and funded in 2010.	
Development Costs
Development costs decreased $10 million during the year ended December 31, 2011, compared to the same period in 2010, as many of the NRG Solar projects are in construction phase in 2011.
Gain on Sale of Assets
On January 11, 2010, NRG sold Padoma to Enel, recognizing a gain on the sale of $23 million.
Equity in Earnings of Unconsolidated Affiliates
NRG's equity earnings from unconsolidated affiliates decreased by $9 million during the year ended December 31, 2011, compared to the same period in 2010. The decrease is due primarily to the changes in fair value of Sherbino's forward gas contract of $10 million and a decrease in equity earnings from Gladstone of $15 million, offset by an increase in equity earnings of $10 million from GenConn, as the Devon and Middletown peaking facilities commenced commercial operations in June 2010 and June 2011, respectively, and an increase of $2 million from Saguaro.
Impairment Charge on Investment
As discussed in more detail in Item 15— Note 2, Summary of Significant Accounting Policies, to the Consolidated Financial Statements, the devastating March 2011 earthquake and tsunami in Japan, which in turn, triggered a nuclear incident at the Fukushima Daiichi Nuclear Power Station, caused NRG to evaluate its investment in NINA for impairment. Consequently, NRG deconsolidated its investment in NINA and recorded an impairment charge of $481 million in the first quarter of 2011 equal to the balance of its investment in NINA. In concurrence with a substantial reduction in NINA's project workforce, and to support NINA's reduced scope of work, NRG contributed an additional $14 million into NINA recorded as an impairment charge for the year ended December 31, 2011.

80

Other Income/(Expense), Net
NRG's other income, net decreased $14 million during the year ended December 31, 2011, compared to the same period in 2010, which relates primarily to foreign exchange gains of $14 million recognized in the prior period.
Loss on Debt Extinguishment
A loss on debt extinguishment of $175 million was recorded in the year ended December 31, 2011, which primarily consisted of the premiums paid on redemption and the write-off of previously deferred financing costs related to the redemptions of the 2014 Senior Notes and the 2016 Senior Notes, and the write-off of previously deferred financing costs related to the replacement of an existing senior credit facility with the Senior Credit Facility.
Interest Expense
NRG's interest expense increased by $35 million during the year ended December 31, 2011, compared to the same period in 2010 due to the following:

 	(In millions)	
Increase/(decrease) in interest expense	 	
Increase for 2020 Senior Notes issued in August 2010	$	58	
 	
Increase for 2018 Senior Notes issued in January 2011	85	
 	
Increase for 2019 and 2021 Senior Notes issued in May 2011	94	
 	
Decrease for 2014 Senior Notes redeemed in January and February 2011	(65	)	
Decrease for 2016 Senior Notes redeemed in May and June 2011	(102	)	
Increase for project financings	15	
 	
Increase for tax-exempt bonds	12	
 	
Decrease for refinancing of term loan and revolving credit facility	(18	)	
Decrease for capitalized interest	(44	)	
Total	$	35	

81

Income Tax (Benefit)/Expense
There was an income tax benefit of $843 million for the year ended December 31, 2011, compared to income tax expense of $277 million for the year ended December 31, 2010. The effective tax rate was 130.5% and 36.8% for the year ended December 31, 2011, and 2010, respectively.

 	Year Ended December 31,	
 	2011	 	2010	
 	(In millions
except as otherwise stated)	
(Loss)/Income Before Income Taxes	$	(646	)	 	$	753	
 	
Tax at 35%	(226	)	 	264	
 	
State taxes, net of federal benefit	15	
 	 	18	
 	
Foreign operations	(3	)	 	(3	)	
Federal and state tax credits	(1	)	 	(7	)	
Valuation allowance	(63	)	 	(34	)	
Expiration/utilization of capital losses	45	
 	 	—	
 	
Reversal of valuation allowance on expired/utilized capital losses	(45	)	 	—	
 	
Foreign earnings	4	
 	 	17	
 	
Non-deductible interest	—	
 	 	4	
 	
Interest accrued on uncertain tax positions	2	
 	 	25	
 	
Production tax credits	(14	)	 	(11	)	
Reversal of uncertain tax position reserves	(561	)	 	—	
 	
Other	4	
 	 	4	
 	
Income tax (benefit)/expense	$	(843	)	 	$	277	
 	
Effective income tax rate	130.5	%	 	36.8	%	
The effective tax rate for the year ended December 31, 2011 differs from the statutory rate of 35% primarily due to a benefit of $633 million resulting from the resolution of the federal tax audit. The benefit is predominantly due to the recognition of previously uncertain tax benefits that were settled upon audit in 2011 and that were mainly composed of net operating losses of $536 million which had been classified as capital loss carryforwards for financial statement purposes.
The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with ASC 740,  Income Taxes,  or ASC 740. These factors and others, including the Company's history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.

82

Liquidity and Capital Resources
Liquidity Position
As of December 31, 2012, and 2011 NRG's liquidity, excluding collateral received, was approximately $3.4 billion and $2.1 billion, respectively, comprised of the following:

 	As of December 31,	
 	2012	 	2011	
 	(In millions)	
Cash and cash equivalents	$	2,087	
 	 	$	1,105	
 	
Funds deposited by counterparties	271	
 	 	258	
 	
Restricted cash	217	
 	 	292	
 	
Total	2,575	
 	 	1,655	
 	
Revolving Credit Facility availability	1,058	
 	 	673	
 	
Total liquidity	3,633	
 	 	2,328	
 	
Less: Funds deposited as collateral by hedge counterparties	(271	)	 	(258	)	
Total liquidity, excluding collateral received	$	3,362	
 	 	$	2,070	
 	
For the year ended December 31, 2012, total liquidity, excluding collateral received, increased by $1.3 billion. The increase in the Revolving Credit Facility availability was primarily due to a $304 million reduction in letters of credit due to the sale of a 49% interest in Agua Caliente in January 2012 to MidAmerican. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading  Cash Flow Discussion . Cash and cash equivalents and funds deposited by counterparties at December 31, 2012 were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.
The line item "Funds deposited by counterparties" represents the amounts that are held by NRG as a result of collateral posting obligations from the Company's counterparties due to positions in the Company's hedging program. These amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of NRG's general corporate obligations. Depending on market fluctuation and the settlement of the underlying contracts, the Company will refund this collateral to the counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities.
Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's common and preferred stockholders, and other liquidity commitments. 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.

83

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 NRG Energy, Inc., its Term Loan Facility and its Senior Notes, GenOn Senior Notes, and GenOn Americas Generation Senior Notes as of December 31, 2012:

 	S&P	 	Moody's	 	Fitch	
NRG Energy, Inc. 	BB-	 	Ba3	 	B+	
7.375% Senior Notes, due 2017	BB-	 	B1	 	BB	
7.625% Senior Notes, due 2018	BB-	 	B1	 	BB	
7.625% Senior Notes, due 2019	BB-	 	B1	 	BB	
8.5% Senior Notes, due 2019	BB-	 	B1	 	BB	
8.25% Senior Notes, due 2020	BB-	 	B1	 	BB	
7.875% Senior Notes, due 2021	BB-	 	B1	 	BB	
6.625% Senior Notes, due 2023	BB-	 	B1	 	BB	
Term Loan Facility, due 2018	BB+	 	Baa3	 	BB+	
GenOn 7.625% Senior Notes, due 2014	B	 	B2	 	B-	
GenOn 7.875% Senior Notes, due 2017	B	 	B2	 	B-	
GenOn 6.000% Senior Notes, due 2017	B	 	B2	 	B-	
GenOn 9.500% Senior Notes, due 2018	B	 	B2	 	B-	
GenOn 9.875% Senior Notes, due 2020	B	 	B2	 	B-	
GenOn Americas Generation 8.500% Senior Notes, due 2017	BB-	 	B3	 	BB-	
GenOn Americas Generation 9.125% Senior Notes, due 2031	BB-	 	B3	 	BB-	
Sources of Liquidity
The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from new and existing financing arrangements, existing cash on hand and cash flows from operations. As described in Item 15 — Note 11,  Debt and Capital Leases,  to the Consolidated Financial Statements, the Company's financing arrangements consist mainly of the Senior Credit Facility, the Senior Notes, the GenOn Senior Notes, the GenOn Americas Generation Senior Notes, and project-related financings.
In addition, NRG has granted first liens to certain counterparties on substantially all of the Company's assets, excluding assets acquired in the GenOn acquisition. NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or gas used as a proxy for power. To the extent that the underlying hedge positions for a counterparty are in-the-money to NRG, the counterparty would have no claim under the lien program. The lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first lien structure, the Company can hedge up to 80% of its coal and nuclear capacity, excluding GenOn coal capacity, and 10% of its other assets, excluding GenOn's other assets, with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.
The Company's lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of December 31, 2012, all hedges under the first liens were in-the-money on a counterparty aggregate basis.

84

The following table summarizes the amount of MWs hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of December 31, 2012:

Equivalent Net Sales Secured by First Lien Structure  (a)	2013	 	2014	 	2015	 	2016	 	2017	
In MW (b)	1,340	
 	 	1,445	
 	 	460	
 	 	592	
 	 	178	
 	
As a percentage of total net coal and nuclear capacity  (c)	21	%	 	22	%	 	7	%	 	10	%	 	3	%	
 	 	
(a)	Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region.	
 	 	
(b)	2013 MW value consists of February through December positions only.	
 	 	
(c)	Net coal and nuclear capacity represents 80% of the Company's total coal and nuclear assets eligible under the first lien, which excludes coal assets acquired in the GenOn acquisition.	
Uses of Liquidity
The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations, as described more fully in Item 15 — Note 11,  Debt and Capital Leases , to the Consolidated Financial Statements; (iii) capital expenditures, including repowering and renewable development, and environmental; and (iv) corporate financial transactions including return of capital to stockholders, as described in Item 15 — Note 14,  Capital Structure , to the Consolidated Financial Statements.
Commercial Operations
The Company's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of December 31, 2012, commercial operations had total cash collateral outstanding of $300 million, and $702 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions (includes a $42 million letter of credit relating to deposits at the PUCT that cover outstanding customer deposits and residential advance payments). As of December 31, 2012, total collateral held from counterparties was $271 million in cash, and $61 million of letters of credit.
Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on the Company's credit ratings and general perception of its creditworthiness.

85

Debt Service Obligations
Principal payments on debt and capital leases as of December 31, 2012, are due in the following periods:

Description	2013	 	2014	 	2015	 	2016	 	2017	 	Thereafter	 	Total	
 	(In millions)	
NRG Recourse Debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior notes, due 2018	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	1,200	
 	 	$	1,200	
 	
Senior notes, due 2019 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	800	
 	 	800	
 	
Senior notes, due 2019	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	700	
 	 	700	
 	
Senior notes, due 2020	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	1,100	
 	 	1,100	
 	
Senior notes, due 2021	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	1,128	
 	 	1,128	
 	
Senior notes, due 2023	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	990	
 	 	990	
 	
Term loan facility, due 2018	16	
 	 	16	
 	 	16	
 	 	16	
 	 	16	
 	 	1,496	
 	 	1,576	
 	
Indian River Power LLC, tax exempt bonds, due 2040 and 2045	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	247	
 	 	247	
 	
Dunkirk Power LLC, tax exempt bonds, due 2042	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	59	
 	 	59	
 	
Fort Bend County, tax-exempt bonds, due 2038 and 2042	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	28	
 	 	28	
 	
Subtotal NRG Recourse Debt	16	
 	 	16	
 	 	16	
 	 	16	
 	 	16	
 	 	7,748	
 	 	7,828	
 	
NRG Non-Recourse Debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	
GenOn senior notes, due 2014	—	
 	 	575	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	575	
 	
GenOn senior notes, due 2017	—	
 	 	—	
 	 	—	
 	 	—	
 	 	725	
 	 	—	
 	 	725	
 	
GenOn senior notes, due 2018	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	675	
 	 	675	
 	
GenOn senior notes, due 2020	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	550	
 	 	550	
 	
GenOn Americas Generation senior notes, due 2021	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	450	
 	 	450	
 	
GenOn Americas Generation senior notes, due 2031	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	400	
 	 	400	
 	
GenOn Marsh Landing senior secured term loans, due 2017 and 2023	27	
 	 	42	
 	 	43	
 	 	41	
 	 	17	
 	 	220	
 	 	390	
 	
CVSR - High Plains Ranch II LLC, due 2037 (a)	34	
 	 	331	
 	 	9	
 	 	12	
 	 	13	
 	 	387	
 	 	786	
 	
NRG West Holdings LLC, term loan, due 2023	—	
 	 	32	
 	 	37	
 	 	41	
 	 	—	
 	 	240	
 	 	350	
 	
Agua Caliente Solar, LLC, due 2037	—	
 	 	18	
 	 	20	
 	 	21	
 	 	21	
 	 	560	
 	 	640	
 	
Ivanpah financing, due 2014 and 2038 (a)	—	
 	 	408	
 	 	30	
 	 	33	
 	 	36	
 	 	930	
 	 	1,437	
 	
South Trent Wind LLC, financing agreement, due 2020	4	
 	 	4	
 	 	4	
 	 	4	
 	 	4	
 	 	52	
 	 	72	
 	
NRG Peaker Finance Co. LLC, bonds, due 2019 	23	
 	 	29	
 	 	31	
 	 	33	
 	 	35	
 	 	37	
 	 	188	
 	
NRG Energy Center Minneapolis LLC, senior secured notes, due 2013, 2017, and 2025 	10	
 	 	6	
 	 	12	
 	 	12	
 	 	13	
 	 	84	
 	 	137	
 	
Other	32	
 	 	14	
 	 	14	
 	 	14	
 	 	41	
 	 	153	
 	 	268	
 	
Subtotal NRG Non-Recourse Debt	130	
 	 	1,459	
 	 	200	
 	 	211	
 	 	905	
 	 	4,738	
 	 	7,643	
 	
Capital Lease:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Chalk Point capital lease, due 2015	4	
 	 	5	
 	 	5	
 	 	—	
 	 	—	
 	 	—	
 	 	14	
 	
Total Debt and Capital Leases	$	150	
 	
 	$	1,480	
 	 	$	221	
 	 	$	227	
 	 	$	921	
 	 	$	12,486	
 	 	$	15,485	
 	
(a) Principal payments in 2014 include the expected repayment of cash grant loans upon receipt of cash grants.
In addition to the debt and capital leases shown in the preceding table, NRG had issued $1.2 billion of letters of credit under the Company's $2.3 billion Revolving Credit Facility as of December 31, 2012.

86

Capital Expenditures
The following tables and descriptions summarize the Company's capital expenditures, including accruals, for maintenance, environmental, and growth investments, for the year ended December 31, 2012, and the estimated capital expenditure and growth investments forecast for 2013. 

 	Maintenance	 	Environmental	 	Growth Investments	 	Total	
 	(In millions)	
East	$	39	
 	 	$	31	
 	 	$	—	
 	 	$	70	
 	
Texas	116	
 	 	2	
 	 	—	
 	 	118	
 	
South Central	30	
 	 	6	
 	 	—	
 	 	36	
 	
West	11	
 	 	—	
 	 	233	
 	 	244	
 	
Other Conventional	9	
 	 	—	
 	 	32	
 	 	41	
 	
Alternative Energy	1	
 	 	—	
 	 	3,152	
 	 	3,153	
 	
Retail	22	
 	 	—	
 	 	—	
 	 	22	
 	
Corporate	9	
 	 	—	
 	 	—	
 	 	9	
 	
Total capital expenditures for the year ended
December 31, 2012	237	
 	 	39	
 	 	3,417	
 	 	3,693	
 	
Accrual impact	(17	)	 	8	
 	 	(288	)	 	(297	)	
Total cash capital expenditures for the year ended
December 31, 2012	220	
 	 	47	
 	 	3,129	
 	 	3,396	
 	
Other investments(a)	—	
 	 	—	
 	 	(59	)	 	(59	)	
Funding from debt financing, net of fees	(5	)	 	(42	)	 	(2,111	)	 	(2,158	)	
Funding from third party equity partners	—	
 	 	—	
 	 	(226	)	 	(226	)	
Total capital expenditures and investments, net	$	215	
 	 	$	5	
 	 	$	733	
 	 	$	953	

Estimated capital expenditures for 2013	$	463	
 	 	$	200	
 	 	$	1,853	
 	 	$	2,516	
 	
Other investments(a)	—	
 	 	—	
 	 	(37	)	 	(37	)	
Funding from debt financing, net of fees	(33	)	 	(13	)	 	(1,496	)	 	(1,542	)	
Funding from third party equity partners	—	
 	 	—	
 	 	(94	)	 	(94	)	
NRG estimated capital expenditures for 2013, net of financings	$	430	
 	 	$	187	
 	 	$	226	
 	 	$	843	
 	
(a) Other investments includes restricted cash activity and proceeds from cash grants.
 	 	
•	Maintenance and Environmental capital expenditures — For the year ended December 31, 2012, the Company's environmental capital expenditures includes $25 million related to a project to install selective catalytic reduction systems, scrubbers and fabric filters on Indian River Unit 4.	
 	 	
•	Growth Investments capital expenditures — For the year ended December 31, 2012, the Company's growth investment expenditures included $3.1 billion for solar projects and $213 million for the Company's El Segundo project. In 2013, NRG will continue its efforts on the solar projects.	
Environmental Capital Expenditures Estimate
Based on current rules, technology and plans as well as preliminary plans based on proposed rules, NRG estimates that environmental capital expenditures from 2013 through 2017 required to comply with environmental laws will be approximately $630 million, consisting of $398 million for legacy NRG facilities and $232 million for GenOn facilities. These costs are primarily associated with controls to satisfy MATS at Big Cajun II, W.A. Parish, Limestone, and Conemaugh and NO x  controls for Sayreville and Gilbert. The decrease from NRG's previous estimate is a result of changes in technology related to MATS compliance at Big Cajun II-Unit 3, and shifts in compliance schedules. Testing and engineering to finalize cost estimates related to further changes on the Big Cajun II MATS compliance plan and the recent Consent Decree lodged in  United States of America v. Louisiana Generating, LLC  are underway, but costs are not expected to exceed the current plan. NRG continues to explore cost effective compliance alternatives to reduce costs.

87

The table below summarizes the status of NRG's coal fleet with respect to air quality controls. Planned investments are either in construction or budgeted in the existing capital expenditures budget. Changes to regulations could result in changes to planned installation dates. NRG uses an integrated approach to fuels, controls and emissions markets to meet environmental standards.

 	 	SO2	 	NOx	 	Mercury	 	Particulate	
Units (a)	 	Control Equipment	 	Install Date	 	Control Equipment	 	Install Date	 	Control Equipment	 	Install Date	 	Control Equipment	 	Install Date	
Huntley 67	 	DSI/FF	 	2009	 	SNCR	 	2009	 	 ACI	 	2009	 	FF	 	2009	
Huntley 68	 	DSI/FF	 	2009	 	SNCR	 	2009	 	ACI	 	2009	 	FF	 	2009	
Dunkirk 1	 	DSI/FF	 	2010	 	SNCR	 	2010	 	ACI	 	2010	 	FF	 	2010	
Dunkirk 2	 	DSI/FF	 	2010	 	SNCR	 	2010	 	ACI	 	2010	 	FF	 	2010	
Dunkirk 3	 	DSI/FF	 	2009	 	SNCR	 	2009	 	ACI	 	2009	 	FF	 	2009	
Dunkirk 4	 	DSI/FF	 	2009	 	SNCR	 	2009	 	ACI	 	2009	 	FF	 	2009	
Chalk Point 1	 	FGD	 	2009	 	SCR	 	2008	 	FGD/ESP	 	2009	 	ESP/upgrade	 	1964/1980	
Chalk Point 2	 	FGD	 	2009	 	SACR	 	2006	 	FGD/ESP	 	2009	 	ESP/upgrade	 	1964/1980	
Dickerson 1-3	 	FGD	 	2009	 	SNCR	 	2009	 	FGD/FF	 	2009	 	ESP/FF	 	1959,1960,1962/2003	
Morgantown 1-2	 	FGD	 	2009	 	SCR	 	2007-2008	 	FGD/ESP	 	2009	 	ESP	 	1970, 1971	
Cheswick 1	 	FGD	 	2010	 	SCR	 	2003	 	FGD/ESP	 	2010	 	ESP	 	1970	
Conemaugh 1-2	 	FGD	 	1994, 95	 	SCR	 	2014	 	FGD/ESP/SCR	 	1994,95/2015	 	ESP	 	1970, 1971	
Keystone 1-2	 	FGD	 	2009	 	SCR	 	2003	 	FGD/ESP	 	2009	 	ESP	 	1967, 1968	
Seward	 	FBL/CDS	 	2004	 	SNCR	 	2004	 	FBL/FF	 	2004	 	FF	 	2004	
Indian River 4	 	CDS	 	2011	 	SCR	 	2011	 	ACI	 	2008	 	ESP/FF	 	1980/2011	
Big Cajun II 1	 	DSI	 	2015	 	LNBOFA/ SNCR	 	2005/2014	 	ACI	 	2015	 	ESP/upgrade or FF	 	1981/2015	
Big Cajun II 2	 	Gas Conversion	 	2014	 	LNBOFA/ SNCR	 	2004/2014	 	Gas Conversion	 	2014	 	ESP	 	1981	
Big Cajun II 3	 	PAL	 	2013	 	LNBOFA/ SNCR	 	2002/2017	 	ACI	 	2015	 	ESP/upgrade	 	1983/2015	
Limestone 1-2	 	Wet Scrubbers	 	1985-86	 	LNBOFA/ SNCR	 	2002/2017	 	ACI	 	2015	 	ESP	 	1985-1986	
W.A. Parish 5, 6, 7	 	FF co-benefit	 	1988	 	SCR	 	2004	 	ACI	 	2015	 	FF	 	1988	
W.A. Parish 8	 	Wet Scrubber	 	1982	 	SCR	 	2004	 	ACI	 	2015	 	FF	 	1988	
(a) NRG has planned the retirement of coal units at Avon Lake, Niles, New Castle, Portland, Shawville and Titus for 2015, and the retirement of Indian River Unit 3 for December of 2013.

ACI -  Activated Carbon Injection
CDS - Circulating Dry Scrubber
DSI - Dry Sorbent Injection with Trona
ESP - Electrostatic Precipitator
FGD - Flue Gas Desulfurization (wet)
FF- Fabric Filter	FBL - Fluidized Bed Limestone Injection
LNBOFA - Low NOx Burner with Overfire Air
PAL - Plant Average Limit
SCR - Selective Catalytic Reduction
SACR - Selective Auto-Catalytic Reduction
SNCR - Selective Non-Catalytic Reduction	
The following table summarizes the estimated environmental capital expenditures for the referenced periods by region:

 	 	Texas	East - legacy NRG	 	East - GenOn	 	South Central	Total	
 	 	(in millions)	
2013	 	$	20	
 	 	$	11	
 	 	$	108	
 	 	$	61	
 	 	$	200	
 	
2014	 	20	
 	 	6	
 	 	97	
 	 	133	
 	 	256	
 	
2015	 	17	
 	 	4	
 	 	27	
 	 	74	
 	 	122	
 	
2016	 	28	
 	 	14	
 	 	—	
 	 	—	
 	 	42	
 	
2017	 	8	
 	 	2	
 	 	—	
 	 	—	
 	 	10	
 	
Total	 	$	93	
 	 	$	37	
 	 	$	232	
 	 	$	268	
 	 	$	630	

88

NRG's current contracts with the Company's rural electrical customers in the South Central region allow for recovery of a portion of the regions' capital costs once in operation, along with a capital return incurred by complying with any change in law, including interest over the asset life of the required expenditures. The actual recoveries will depend, among other things, on the timing of the completion of the capital projects and the remaining duration of the contracts.
2012 Capital Allocation Program
On February 28, 2012, the Company announced its intention to initiate an annual common stock dividend of $0.36 per share, and paid its first quarterly dividend on the Company's common stock of $0.09 per share on August 15, 2012. On November 15, 2012, NRG paid a quarterly dividend on the Company's common stock of $0.09 per share.
During the second quarter of 2012, the Company paid $72 million for open market repurchases of the Company's Senior Notes due 2021, at an average price of 98.58% of face value.
On September 24, 2012, NRG issued $990 million aggregate principal amount at par of the 2023 Senior Notes. The Company used the proceeds, net of issuance costs, of $978 million for the 2023 Senior Notes and additional cash on-hand to redeem the Company's Senior Notes due 2017, at an average redemption percentage of 104.016%.
As part of the 2012 program, the Company invested approximately $267 million in maintenance and environmental capital expenditures in existing assets, and approximately $3.1 billion in solar and other projects under development.

2013 Capital Allocation Program
During the first quarter of 2013, the Company paid $80 million, $104 million, and $42 million at an average price of 114.179%, 111.700%, and 113.082% of face value, for open market repurchases of the Company's 2018 Senior Notes, 2019 Senior Notes, and 2020 Senior Notes, respectively.
On February 15, 2013, NRG paid a quarterly dividend on the Company's common stock of $0.09 per share.
On February 27, 2013, the Company announced its intention to increase NRG's annual common stock dividend by 33%, to $0.48 per share, commencing with the next quarterly payment. In addition, the Company is authorized to repurchase $200 million of its common stock. The Company's common stock dividend and share repurchases are subject to available capital, market conditions, and compliance with associated laws and regulations.
Preferred Stock Dividend Payments
For the year ended December 31, 2012, NRG paid $9 million in dividend payments to holders of the Company's 3.625% Preferred Stock.

89

Cash Flow Discussion
The following table reflects the changes in cash flows for the comparative years:

(In millions)	 	 	 	 	 	
Year ended December 31,	2012	 	2011	 	Change	
Net cash provided by operating activities	$	1,149	
 	 	$	1,166	
 	 	$	(17	)	
Net cash used by investing activities	(2,262	)	 	(3,047	)	 	785	
 	
Net cash provided by financing activities	2,099	
 	 	33	
 	 	2,066	
 	
Net Cash Provided By Operating Activities
Changes to net cash provided by operating activities were driven by:

Increase primarily due to operating income adjusted for non-cash charges	$	148	
 	
Decrease from GenOn operations for the post-acquisition period	(167	)	
Other changes in working capital	2	
 	
 	$	(17	)	
 Net Cash Used By Investing Activities
Changes to net cash used by investing activities were driven by:

Increase in capital expenditures due to increased spending on maintenance, repowering and renewable development ,  primarily for solar projects in construction	$	(1,086	)	
Cash acquired in GenOn acquisition	983	
 	
Decrease in restricted cash, which was mainly to support equity requirements for
    U.S. DOE funded projects	348	
 	
Lower cash spent for acquisitions, which primarily reflects three Solar acquisitions and Energy Plus in 2011	296	
 	
Increase in cash for sale of assets, which primarily reflects sale of land in 2011, compared to the sale of Schkopau in 2012	130	
 	
Receipt of cash grants in 2012	62	
 	
Investments in unconsolidated affiliates, primarily related to investments in a clean technology joint venture and Petra Nova in 2011	41	
 	
Decrease in purchases and sales of emissions allowances	18	
 	
Other	(7	)	
 	$	785	
 	
Net Cash Provided By Financing Activities
Changes in net cash provided by financing activities were driven by:

Decrease in cash paid to repurchase shares of NRG common stock	$	430	
 	
Increase in cash proceeds from noncontrolling interests in Agua Caliente and Ivanpah	318	
 	
Decrease in cash paid for debt issuance and hedging costs	172	
 	
Net decrease in cash received for proceeds for issuance of long-term debt	(3,059	)	
Net decrease in the payments of debt, primarily related to payment of secured Senior Notes	4,233	
 	
Increase in the payment of dividends to common and preferred shareholders	(41	)	
Increase in cash receipts for financing element of acquired derivatives	15	
 	
Other	(2	)	
 	$	2,066	

90

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
As of December 31, 2012, the Company had domestic pre-tax book income of $223 million and foreign pre-tax book income of $29 million. For the year ended December 31, 2012, the Company generated an NOL of $558 million which is available to offset taxable income in future periods. As of December 31, 2012, the Company has cumulative domestic Federal NOL carryforwards of $1.7 billion and cumulative state NOL carryforwards of $2.6 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $89 million, of which $18 million will expire starting 2013 through 2020 and of which $71 million do not have an expiration date.
In addition to these amounts, the Company has $193 million of tax effected uncertain tax benefits. As a result of the Company's tax position, and based on current forecasts, NRG anticipates income tax payments, primarily due to foreign, state and local jurisdictions, of up to $40 million in 2013.
However, as the position remains uncertain for the $193 million of tax effected uncertain tax benefits, the Company has recorded a non-current tax liability of $72 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $72 million non-current tax liability for uncertain tax benefits is primarily from positions taken on various state returns, including accrued interest.
Prior to the GenOn acquisition, the Company was not subject to U.S. federal income tax examinations for years prior to 2007. As a result of the merger, NRG is no longer subject to U.S. federal income tax examinations for years prior to 2002. With few exceptions, state and local income tax examinations are no longer open for years before 2003. The Company's significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2004.
Off-Balance Sheet Arrangements
Obligations under Certain Guarantee Contracts
NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See also Item 15 — Note 25,  Guarantees,  to the Consolidated Financial Statements for additional discussion.
Retained or Contingent Interests
NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.
Derivative Instrument Obligation
The Company's 3.625% Preferred Stock includes a feature which is considered an embedded derivative per ASC 815. Although it is considered an embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815. As of December 31, 2012, based on the Company's stock price, the embedded derivative was out-of-the-money and had no redemption value. See also Item 15 — Note 14,  Capital Structure,  to the Consolidated Financial Statements for additional discussion.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in Equity investments — As of December 31, 2012, NRG 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 of accounting. Several of these investments are variable interest entities for which NRG is not the primary beneficiary.
NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $233 million as of December 31, 2012. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Item 15 — Note 15,  Investments Accounted for by the Equity Method and Variable Interest Entities,  to the Consolidated Financial Statements for additional discussion.

91

Contractual Obligations and Commercial Commitments
NRG 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 tables summarize NRG's contractual obligations and contingent obligations for guarantee. See also Item 15 — Note 11,  Debt and Capital Leases , Note 21, Commitments and Contingencies , and Note 25,  Guarantees , to the Consolidated Financial Statements for additional discussion.

 	By Remaining Maturity at December 31,	
 	2012	 	 	
Contractual Cash Obligations	Under
1 Year	 	1-3 Years	 	3-5 Years	 	Over
5 Years	 	Total (a)	 	2011 Total	
 	(In millions)	
Long-term debt and funded letter of credit (including estimated interest)	$	1,129	
 	 	$	3,555	
 	 	$	2,932	
 	 	$	15,156	
 	 	$	22,772	
 	 	$	14,653	
 	
Capital lease obligations (including estimated interest)	6	
 	 	10	
 	 	—	
 	 	—	
 	 	16	
 	 	123	
 	
Operating leases	290	
 	 	526	
 	 	558	
 	 	1,506	
 	 	2,880	
 	 	578	
 	
Fuel purchase and transportation obligations	1,301	
 	 	630	
 	 	483	
 	 	712	
 	 	3,126	
 	 	1,845	
 	
Fixed purchased power commitments	32	
 	 	27	
 	 	18	
 	 	—	
 	 	77	
 	 	96	
 	
Pension minimum funding requirement (b)	61	
 	 	168	
 	 	134	
 	 	112	
 	 	475	
 	 	314	
 	
Other postretirement benefits minimum funding requirement  (c)	11	
 	 	20	
 	 	21	
 	 	34	
 	 	86	
 	 	38	
 	
Other liabilities (d)	147	
 	 	167	
 	 	175	
 	 	746	
 	 	1,235	
 	 	485	
 	
Total	$	2,977	
 	 	$	5,103	
 	 	$	4,321	
 	 	$	18,266	
 	 	$	30,667	
 	 	$	18,132	

(a)	Excludes $72 million non-current payable relating to NRG's uncertain tax benefits under ASC 740 as the period of payment cannot be reasonably estimated. Also excludes $648 million of asset retirement obligations which are discussed in Item 15 — Note 12,  Asset Retirement Obligations , to the Consolidated Financial Statements.	
 	 	
(b)	These amounts represent the Company's estimated minimum pension contributions required under the Pension Protection Act of 2006. These amounts represent estimates that are based on assumptions that are subject to change.	
 	 	
(c)	These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contribution for years after 2020 are currently not available.	
 	 	
(d)	Includes water right agreements, service and maintenance agreements, stadium naming rights, LTSA commitments and other contractual obligations.	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	By Remaining Maturity at December 31,	
 	2012	 	 	
Guarantees	Under
1 Year	 	1-3 Years	 	3-5 Years	 	Over
5 Years	 	Total	 	2011 Total	
 	(In millions)	
Letters of credit and surety bonds	$	1,518	
 	 	$	76	
 	 	$	—	
 	 	$	—	
 	 	$	1,594	
 	 	$	1,670	
 	
Asset sales guarantee obligations	—	
 	 	—	
 	 	275	
 	 	—	
 	 	275	
 	 	635	
 	
Commercial sales arrangements	172	
 	 	142	
 	 	79	
 	 	1,186	
 	 	1,579	
 	 	1,405	
 	
Other guarantees	1	
 	 	—	
 	 	—	
 	 	355	
 	 	356	
 	 	461	
 	
Total guarantees	$	1,691	
 	 	$	218	
 	 	$	354	
 	 	$	1,541	
 	 	$	3,804	
 	 	$	4,171	
 	
Fair Value of Derivative Instruments
NRG may enter into long-term power purchase and sales contracts, 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 generation facilities or retail load obligations. In addition, in order to mitigate interest rate risk associated with the issuance of the Company's variable rate and fixed rate debt, NRG enters into interest rate swap agreements.
NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

92

The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820,  Fair Value Measurements and Disclosures , or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at December 31, 2012, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at December 31, 2012. For a full discussion of the Company's valuation methodology of its contracts, see  Derivative Fair Value Measurements  in Item 15 — Note 4,  Fair Value of Financial Instruments , to the Consolidated Financial Statements.

Derivative Activity Gains/(Losses)	(In millions)	
Fair value of contracts as of December 31, 2011	$	422	
 	
Contracts realized or otherwise settled during the period	(467	)	
Contracts acquired as part of the GenOn acquisition	758	
 	
Changes in fair value	112	
 	
Fair value of contracts as of December 31, 2012	$	825	

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Fair Value of Contracts as of December 31, 2012	
Fair value hierarchy Gains/(Losses)	Maturity
Less Than
1 Year	 	Maturity
1-3 Years	 	Maturity
4-5 Years	 	Maturity
in Excess
4-5 Years	 	Total Fair
Value	
 	(In millions)	
Level 1	$	255	
 	 	$	20	
 	 	$	38	
 	 	$	—	
 	 	$	313	
 	
Level 2	396	
 	 	237	
 	 	(105	)	 	(4	)	 	524	
 	
Level 3	12	
 	 	(24	)	 	—	
 	 	—	
 	 	(12	)	
Total	$	663	
 	 	$	233	
 	 	$	(67	)	 	$	(4	)	 	$	825	
 	
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. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 7A  — Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk , NRG measures the sensitivity of the Company's 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 Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative assets and liability position is a better indicator of NRG's hedging activity. As of December 31, 2012, NRG's net derivative asset was $825 million, an increase to total fair value of $403 million as compared to December 31, 2011. This increase was primarily driven by contracts acquired as part of the GenOn acquisition and an increase in fair value of existing contracts due to the decreases in gas and power prices offset by the roll off of contracts that settled during the period.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in a decrease of approximately $434 million in the net value of derivatives as of December 31, 2012.
The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of the derivative contracts would result in an increase of approximately $382 million in the net value of derivatives as of December 31, 2012.

93

Critical Accounting Policies and Estimates
NRG'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 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 have not changed.
On an ongoing basis, NRG 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.
NRG's significant accounting policies are summarized in Item 15 — Note 2, Summary of Significant Accounting Policies , to the Consolidated Financial Statements. The Company identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain.

 	 	
Accounting Policy	Judgments/Uncertainties Affecting Application	
Derivative Instruments	Assumptions used in valuation techniques	
 	Assumptions used in forecasting generation	
 	Market maturity and economic conditions	
 	Contract interpretation	
 	Market conditions in the energy industry, especially the effects of price volatility on contractual commitments	
Income Taxes and Valuation Allowance for Deferred Tax Assets	Ability to be sustained upon audit examination of taxing authorities	
 	Interpret existing tax statute and regulations upon application 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 investment through future operations	
 	Regulatory and political environments and requirements	
 	Estimated useful lives of assets	
 	Environmental obligations and operational limitations	
 	Estimates of future cash flows	
 	Estimates of fair value	
 	Judgment about triggering events	
Goodwill and Other Intangible Assets	Estimated useful lives for finite-lived intangible assets	
 	Judgment about impairment triggering events	
 	Estimates of reporting unit's fair value	
 	Fair value estimate of intangible assets acquired in business combinations	
Contingencies	Estimated financial impact of event(s)	
 	Judgment about likelihood of event(s) occurring	
 	Regulatory and political environments and requirements	

94

Derivative Instruments
The Company follows the guidance of ASC 815 to account for derivative instruments. ASC 815 requires the Company to mark-to-market all derivative instruments on the balance sheet, and recognize changes in the fair value of non-hedge derivative instruments immediately in earnings. In certain cases, NRG may apply hedge accounting to the Company's derivative instruments. The criteria used to determine if hedge accounting treatment is appropriate are: (i) the designation of the hedge to an underlying exposure; (ii) whether the overall risk is being reduced; and (iii) if there is a correlation between the changes in fair value of the derivative instrument and the underlying hedged item. Changes in the fair value of derivatives instruments accounted for as hedges are either recognized in earnings as an offset to the changes in the fair value of the related hedged item, or deferred and recorded as a component of OCI and subsequently recognized in earnings when the hedged transactions occur.
For purposes of measuring the fair value of derivative instruments, NRG uses quoted exchange prices and broker quotes. When external prices are not available, NRG uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy commodities based on the specific market in which the energy commodity is being purchased or sold, using externally available forward market pricing curves for all periods possible under the pricing model. In order to qualify derivative instruments for hedged transactions, NRG estimates the forecasted generation occurring within a specified time period. Judgments related to the probability of forecasted generation occurring are based on available baseload capacity, internal forecasts of sales and generation, and historical physical delivery on similar contracts. The probability that hedged forecasted generation will occur by the end of a specified time period could change the results of operations by requiring amounts currently classified in OCI to be reclassified into earnings, creating increased variability in the Company's earnings. These estimations are considered to be critical accounting estimates.
Certain derivative instruments that meet the criteria for derivative accounting treatment also qualify for a scope exception to derivative accounting, as they are considered to be NPNS. The availability of this exception is based upon the assumption that NRG has the ability and it is probable to deliver or take delivery of the underlying item. These assumptions are based on available baseload capacity, internal forecasts of sales and generation and historical physical delivery on contracts. Derivatives that are considered to be NPNS are exempt from derivative accounting treatment, and are accounted for under accrual accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception due to changes in estimates, the related contract would be recorded on the balance sheet at fair value combined with the immediate recognition through earnings.
Income Taxes and Valuation Allowance for Deferred Tax Assets
As of December 31, 2012, NRG had a valuation allowance of $191 million. This amount is comprised of foreign net operating loss carryforwards of $88 million, foreign capital loss carryforwards of approximately $1 million and U.S. domestic state NOLs of $102 million. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets, net of valuation allowances. In arriving at this conclusion to utilize projections of future profit before tax in our estimate of future taxable income, the Company considered the profit before tax generated in recent years.
NRG continues 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. NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia. Prior to the GenOn acquisition, the Company was not subject to U.S. federal income tax examinations for years prior to 2007. As a result of the GenOn acquisition, the Company is no longer subject to U.S. federal income tax examinations for years prior to 2002. With few exceptions, state and local income tax examinations are no longer open for years before 2003. The Company's significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2004.

95

Evaluation of Assets for Impairment and Other Than Temporary Decline in Value
In accordance with ASC 360, Property, Plant, and Equipment, or ASC 360, NRG evaluates property, plant and equipment and certain intangible assets 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 the Company. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. NRG 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.
For assets to be held and used, if the Company determines that the undiscounted cash flows from the asset are less than the carrying amount of the asset, NRG must estimate fair value to determine the amount of any impairment loss. Assets held-for-sale are reported at the lower of the carrying amount or fair value less the cost to sell. The estimation of fair value under ASC 360, whether in conjunction with an asset to be held and used or with an asset held-for-sale, and the evaluation of asset impairment are, by their nature, subjective. NRG considers quoted market prices in active markets to the extent they are available. In the absence of such information, the Company may consider prices of similar assets, consult with brokers, or employ other valuation techniques. NRG will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or employ an expected present value method that probability-weights a range of possible outcomes. The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in the Company's estimates, and the impact of such variations could be material.
NRG is also required to evaluate its equity-method and cost-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 NRG makes with respect to its equity and cost-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, NRG 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.
Goodwill and Other Intangible Assets
At December 31, 2012, NRG reported goodwill of $1.9 billion, consisting of $1.7 billion in its Texas operating segment, or NRG Texas, that is associated with the acquisition of Texas Genco in 2006, and $200 million primarily in its retail operating segment that is associated with other business acquisitions. The Company has also recorded intangible assets in connection with its business acquisitions, 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. See Item 15 — Note 3,  Business Acquisitions and Dispositions , and Note 10,  Goodwill and Other Intangibles , to the Consolidated Financial Statements for further discussion.

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The Company applies ASC 805, Business Combinations, or ASC 805, and ASC 350, to account for its goodwill and intangible assets. Under these standards, the Company amortizes all finite-lived intangible assets over their respective estimated weighted-average useful lives, while goodwill has an indefinite life and is not amortized. However, goodwill and all intangible assets not subject to amortization are tested for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Company tests goodwill for impairment at the reporting unit level, which is identified by assessing whether the components of the Company's operating segments constitute businesses for which discrete financial information is available and whether segment management regularly reviews the operating results of those components. The Company performs the annual goodwill impairment assessment as of December 31 or when events or changes in circumstances indicate that the carrying value may not be recoverable. In 2011, NRG adopted the provisions of ASU 2011-08,  Intangibles - Goodwill and Othe r  (Topic 350) Testing Goodwill for Impairment , or ASU 2011-08, which allows the consideration of qualitative factors to determine if it is more likely than not that impairment has occurred. In the absence of sufficient qualitative factors, goodwill impairment is determined utilizing a two-step process. If it is determined that the fair value of a reporting unit is below its carrying amount, where necessary, the Company's goodwill and/or intangible asset with indefinite lives will be impaired at that time.
The Company performed its annual goodwill impairment assessment as of December 31, 2012, and based on its qualitative assessment of macroeconomic, industry, and market events and circumstances as well as the overall financial performance of the Retail Business, the Company determined it was not more likely than not that the fair value of goodwill attributed to the Retail Business reporting units was less than its carrying amount; as such, the annual two-step impairment test was deemed not necessary to be performed for these reporting units for the year ended December 31, 2012.
The Company performed step one of the two-step impairment test for its Texas reporting unit, NRG Texas, which is at the operating segment level. The Company determined the fair value of this reporting unit using primarily an income approach and then applied an overall market approach reasonableness test to reconcile that fair value with NRG's overall market capitalization. The Company believes the methodology and assumptions used in the valuation are consistent with the views of market participants. Significant inputs to the determination of fair value were as follows:
 	 	
•	For the three solid-fuel plants that drive a majority of the value in the reporting unit, and the Cedar Bayou facility, the Company applied a discounted cash flow methodology to their long-term budgets. This approach is consistent with that used to determine fair value in prior years. The significant assumptions used to derive the long-term budgets used in the income approach are affected by the following key inputs:	
 	 	
◦	The Company's views of power and fuel prices considers market prices for the first five year period and the Company's fundamental view for the longer term. Hedging is included to the extent of contracts already in place;	
 	 	
◦	Projected generation in the long-term forecasts is based on management's estimate of supply and demand within the sub-markets for each plant and the physical and economic characteristics of each plant;	
 	 	
◦	The cash flow projections assume gradually rising wholesale power prices reflecting higher forward natural gas prices as well as increasing market heat rates through 2017 due to anticipated decline in reserve margins in the ERCOT market. Reserve margin is the difference between system generation capability and anticipated peak load; and	
 	 	
◦	The terminal value in year 2018 is calculated using the Gordon Growth Model, which assumes that the terminal value grows at a constant rate in perpetuity;	
 	 	
•	For the reporting unit's remaining gas plants, the Company applied a market-derived earnings multiple to the gas plants' aggregate estimated 2012 earnings before interest, taxes, depreciation and amortization. This approach is consistent with that used to determine fair values in prior years; and	
 	 	
•	The additional significant assumptions used in overall valuation of NRG Texas are as follows:	
 	 	
◦	The discount rate applied to internally developed cash flow projections for the NRG Texas reporting unit represents the weighted average cost of capital consistent with the risk inherent in future cash flows and based upon an assumed capital structure, cost of long-term debt and cost of equity consistent with comparable companies in the integrated utility industry.	
 	 	
◦	The intangible value to NRG Texas for synergies it provides to the Retail Business was determined by capitalizing estimated annual collateral charge and supply cost savings.	

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Under step one, if the fair value of a reporting unit exceeds its carrying value, goodwill of the reporting unit is not considered impaired. Under the income approach described above, the Company estimated the fair value of NRG Texas' invested capital to exceed its carrying value by approximately 16% at December 31, 2012. The Company also evaluated various market-derived data including market research forecasts, recent merger and acquisition activity and earnings multiples, and together with its estimate of fair value, concluded that NRG Texas's goodwill is not impaired at December 31, 2012.
To reconcile the fair value determined under the income approach with NRG's market capitalization, the Company considered historical and future budgeted earnings measures to estimate the average percentage of total company value represented by NRG Texas, and applied this percentage to an adjusted business enterprise value of NRG. To derive this adjusted business enterprise value, the Company applied a range of control premiums based on recent market transactions to the business enterprise value of NRG on a non-controlling, marketable basis, and also made adjustments for some non-operating assets and for some of the significant factors that impact NRG differently from NRG Texas, such as environmental capital expenditures outside of the Texas region on NRG's stock price. The Company was able to reconcile the proportional value of NRG Texas to NRG's market capitalization at a value that would not indicate an impairment.
The Company's estimate of fair value under the income approach described above is affected by assumptions about projected power prices, generation, fuel costs, capital expenditure requirements and environmental regulations, and the Company believes that the most significant impact arises from future power prices. The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants. Due to downward trends in natural gas prices, the Company performed a sensitivity scenario by using a hypothetical $0.50 per MMBtu drop in the natural gas market price for the first five year period and a $0.50 per MMBtu drop in the Company's longer-term fundamental view as used in the Company's long-term budgets and the resulting impact to the implied heat rate that would support new build of combined cycle gas plant in the Texas markets, coal and transportation charges, contracted hedges, and the impact on forecasted generation for the baseload plants during the budget period. Under this sensitivity scenario, the fair value of NRG Texas exceeded its carrying value by 3% as of December 31, 2012.
Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the annual goodwill impairment test will prove to be accurate predictions of the future. Examples of events or circumstances that could reasonably be expected to negatively affect the underlying key assumptions and ultimately impact the estimated fair value of the NRG Texas reporting unit may include such items as follows:
 	 	
•	Continued depressed long-term natural gas prices which may result in lower power prices in the markets in which the Texas reporting unit operates;	
 	 	
•	A significant change to power plants' new-build/retirement economics and reserve margins resulting primarily from unexpected environmental or regulatory changes; and/or	
 	 	
•	Macroeconomic factors that significantly differ from the Company's assumptions in timing or degree.	
If long-term natural gas prices for periods beyond 2013 remain depressed for an extended period, the Company's goodwill may become impaired in the future, which would result in a non-cash charge, not to exceed $1.7 billion, related to the NRG Texas reporting unit.
Contingencies
NRG records a loss contingency when management determines it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Gain contingencies are not recorded until management determines it is certain that the future event will become or does become a reality. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. NRG describes in detail its contingencies in Item 15 — Note 21,  Commitments and Contingencies,  to the Consolidated Financial Statements.
Recent Accounting Developments
See Item 15 — Note 2, Summary of Significant Accounting Policies, to the Consolidated Financial Statements for a discussion of recent accounting developments.

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Item 7A — Quantitative and Qualitative Disclosures About Market Risk
NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's merchant 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, credit risk and currency exchange risk. In order to manage these risks the Company uses various fixed-price forward purchase and sales contracts, futures and option contracts traded on NYMEX, and swaps and options traded in the over-the-counter financial markets to:
 	 	
•	Manage and hedge fixed-price purchase and sales commitments;	
 	 	
•	Manage and hedge exposure to variable rate debt obligations;	
 	 	
•	Reduce exposure to the volatility of cash market prices, and	
 	 	
•	Hedge fuel requirements for the Company's generating facilities.	
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, electricity, coal, oil, and emissions credits. NRG manages the commodity price risk of the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as NYMEX and Intercontinental Exchange, or ICE, as well as over-the-counter markets. The portion of forecasted transactions hedged may vary based upon management's assessment of market, weather, operation and other factors.
While some of the contracts the Company uses to manage risk represent commodities or instruments for which prices are available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing sources and modeling techniques to determine expected future market prices, contract quantities, or both. NRG uses the Company's best estimates to determine the fair value of those derivative contracts. However, it is likely that future market prices could vary from those used in recording mark-to-market derivative instrument valuation, and such variations could be material.
NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports, and VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of the Company's energy assets and liabilities, which includes generation assets, load obligations, and bilateral physical and financial transactions. The key assumptions for the Company's VaR model include: (i) lognormal distribution of prices; (ii) one-day holding period; (iii)  95% confidence interval; (iv) rolling 36-month forward looking period; and (v) market implied volatilities and historical price correlations.
As of December 31, 2012, the VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions calculated using the VaR model, was $92 million.
The following table summarizes average, maximum and minimum VaR for NRG for the years ended December 31, 2012, and 2011:

(In millions)	2012	 	2011	
VaR as of December 31,	$	92	
 	 	$	45	
 	
For the year ended December 31,	 	 	 	
Average	$	66	
 	 	$	60	
 	
Maximum	96	
 	 	77	
 	
Minimum	24	
 	 	44	
 	
Due to the inherent limitations of statistical measures such as VaR, the evolving nature of the competitive markets for electricity and related derivatives, and the seasonality of changes in market prices, the VaR calculation may not capture the full extent of commodity price exposure. As a result, actual changes in the fair value of mark-to-market energy assets and liabilities could differ from the calculated VaR, and such changes could have a material impact on the Company's financial results.
In order to provide additional information, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of December 31, 2012, for the entire term of these instruments entered into for both asset management and trading, was $66 million, primarily driven by asset-backed transactions.

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Interest Rate Risk
NRG is exposed to fluctuations in interest rates through the Company's issuance of fixed rate and 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.
NRG entered into interest rate swaps, which became effective on April 1, 2011, and were intended to hedge the risks associated with floating interest rates. For the interest rate swaps, the Company paid its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG received the monthly equivalent of a floating interest payment based on a 1-month LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its counterparties were made monthly and the LIBOR was determined in advance of each interest period. The total notional amount of the swaps, which matured on February 1, 2013, was $900 million.
In addition to those discussed above, 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 11,  Debt and Capital Leases , to the Consolidated Financial Statements, 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, 2012, the Company would have owed the counterparties $150 million. Based on the investment grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.
As part of the CVSR financing, the Company entered into swaptions with a notional value of $686 million in order to hedge the project interest rate risk, of which $342 million notional value remained outstanding as of December 31, 2012. If the swaptions were discontinued on December 31, 2012, the counterparty would have owed the Company approximately $2 million.
NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of December 31, 2012, a 1% change in interest rates would result in a $15 million change in interest expense on a rolling twelve month basis.
As of December 31, 2012, the Company's debt fair value was $16.5 billion and the carrying value was $15.9 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $1.2 billion.
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. The Company is currently exposed to additional collateral posting if natural gas prices decline primarily due to the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations.
Based on a sensitivity analysis for power and gas positions under marginable contracts, a $0.50 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $83 million as of December 31, 2012 and a 1.00 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $39 million as of December 31, 2012. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of December 31, 2012.
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; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at the Company to cover the credit risk of the counterparty until positions settle.

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As of December 31, 2012, aggregate counterparty credit exposure to a significant portion of the Company's counterparties totaled $1.3 billion, of which the Company held collateral (cash and letters of credit) against those positions of $74 million resulting in a net exposure of $1.2 billion. Approximately 91% of the Company's exposure before collateral is expected to roll off by the end of 2014. The following table highlights the Company's portfolio credit quality and aggregated net counterparty credit exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net asset position with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. As of December 31, 2012, the aggregate credit exposure is shown net of collateral held, and includes amounts net of receivables or payables.

Category	Net Exposure (a)
(% of Total)	
Financial institutions	63	%	
Utilities, energy merchants, marketers and other	29	
 	
Coal and emissions	1	
 	
ISOs	7	
 	
Total	100	%	

 	 	 	
Category	Net Exposure (a)
(% of Total)	
Investment grade	95	%	
Non-rated (b)	1	
 	
Non-Investment grade	4	
 	
Total	100	%	
 	 	
(a)	Counterparty credit exposure excludes coal transportation contracts because of the unavailability of market prices.	
 	 	
(b)	For non-rated counterparties, the majority are related to ISO and municipal public power entities, which are considered investment grade equivalent ratings based on NRG's internal credit ratings.	
The Company has credit exposure to certain wholesale counterparties representing more than 10% of the total net exposure discussed above and the aggregate credit exposure to such counterparties was $565 million. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, the Company does not anticipate a material impact on its financial position or results of operations from nonperformance by any counterparty.
Counterparty credit exposure described above excludes credit risk exposure under certain long term contracts, including California tolling agreements, South Central load obligations, solar PPAs and a coal supply agreement. As external sources or observable market quotes are not available to estimate such exposure, the Company valued 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, 2012, credit exposure to these counterparties is approximately $1.2 billion for the next five years. This amount excludes potential credit exposures for projects with long term PPAs that have not reached commercial operations. Many of these power contracts are with utilities or public power entities that have strong credit quality and specific public utility commission or other regulatory support. In the case of the coal supply agreement, NRG holds a lien against the underlying asset. These factors significantly reduce the risk of loss.
Retail Customer Credit Risk
NRG is exposed to retail credit risk through its retail electricity providers, which serve C&I customers and the Mass market. Retail credit risk results when a customer fails to pay for services rendered. The losses could be incurred from nonpayment of customer accounts receivable and any in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.
As of December 31, 2012, the Company's credit exposure to C&I customers was diversified across many customers and various industries, with a significant portion of the exposure with government entities.
NRG is also exposed to credit risk relating to its Mass customers, which may result in a write-off of bad debt. During 2012, the Company continued to experience improved customer payment behavior, but current economic conditions may affect the Company's customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense.

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Credit Risk Related Contingent Features
Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed "adequate assurance" under the agreements, or require the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts that have adequate assurance clauses that are in a net liability position as of December 31, 2012, was $78 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of December 31, 2012, was $42 million. The Company is also a party to certain marginable agreements under which it has a net liability position but the counterparty has not called for the collateral due, which is approximately $28 million as of December 31, 2012.
Currency Exchange Risk
NRG's foreign earnings and investments may be subject to foreign currency exchange risk, which NRG generally does not hedge. As these earnings and investments are not material to NRG's consolidated results, the Company's foreign currency exposure is limited.
 
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 NRG's management, including its principal executive officer, principal financial officer and principal accounting officer, NRG 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 annual report on Form 10-K. Management's report on the Company's internal control over financial reporting and the report of the Company's independent registered public accounting firm are incorporated under the caption "Management's Report on Internal Control over Financial Reporting" and under the caption "Report of Independent Registered Public Accounting Firm" in this Annual Report on Form 10-K for the fiscal year ended December 31, 2012.
Changes in Internal Control over Financial Reporting
On December 14, 2012, NRG Energy, Inc. acquired GenOn Energy, Inc., as described in Item 15 — Note 3, Business Acquisitions and Dispositions  to the Consolidated Financial Statements. Prior to the acquisition date, there were no changes in either 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 2012 that materially affected, or are reasonably likely to materially affect, either company's internal control over financial reporting.
Post acquisition, management maintained the effectiveness of each company's legacy controls over the design and operation of its disclosure controls and procedures. In addition, management designed and tested additional controls over the financial reporting process, which support the preparation of NRG's consolidated financial statements in accordance with U.S. GAAP.
The Company plans to further integrate GenOn and NRG's internal control over financial reporting in 2013.
Inherent Limitations over Internal Controls
NRG'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.
Item 9B — Other Information
None.

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PART III
Item 10 — Directors, Executive Officers and Corporate Governance
Directors
E. Spencer Abrahamhas been a director of NRG since December 2012. Previously, he served as a director of GenOn Energy, Inc. from January 2012 to December 2012. He is Chairman and Chief Executive Officer of The Abraham Group, an international strategic consulting firm based in Washington, D.C which he founded in 2005. Prior to that, Secretary Abraham served as Secretary of Energy under President George W. Bush from 2001 through January 2005 and was a U.S. Senator for the State of Michigan from 1995 to 2001. Secretary Abraham serves on the board of Occidental Petroleum Corporation, PBF Energy, and the following private companies: C3 Energy Resource Management, International Battery and Sindicatum Sustainable Resources. Secretary Abraham also serves as chairman of the advisory committee of Lynx Global Realty Asset Fund and Uranium Energy Corporation. Secretary Abraham previously served as the non-executive chairman of AREVA, Inc., the U.S. subsidiary of the French-owned nuclear company, and as a director of Deepwater Wind LLC, International Battery, Green Rock Energy, ICx Technologies and PetroTiger. He also previously served on the advisory board or committees of Midas Medici (Utilipoint), Millennium Private Equity, Sunovia and Wetherly Capital.
Kirbyjon H. Caldwell has been a director of NRG since March 2009. He was a director of Reliant Energy, Inc. from August 2003 to March 2009. Since 1982, he has served as Senior Pastor at the 16,000-member Windsor Village United Methodist Church in Houston, Texas. Pastor Caldwell was also a director of United Continental Holdings, Inc. (formerly Continental Airlines, Inc.) from 1999 to September 2011.
John F. Chlebowski has been a director of NRG since December 2003. 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.
Lawrence S. Coben has been a director of NRG since December 2003. He is currently Chairman and Chief Executive Officer of Tremisis Energy Corporation LLC. Dr. Coben was Chairman and Chief Executive Officer of Tremisis Energy Acquisition Corporation II, a publicly held company, from July 2007 through March 2009 and of Tremisis Energy Acquisition Corporation from February 2004 to May 2006. From January 2001 to January 2004, he was a Senior Principal of Sunrise Capital Partners L.P., a private equity firm. From 1997 to January 2001, Dr. Coben was an independent consultant. From 1994 to 1996, Dr. Coben was Chief Executive Officer of Bolivian Power Company. Dr. Coben is also Executive Director of the Sustainable Preservation Initiative and a Consulting Scholar at the University of Pennsylvania Museum of Archaeology and Anthropology.
Howard E. Cosgrove has served as Chairman of the Board and a director of NRG since December 2003. He was Chairman and Chief Executive Officer of Conectiv and its predecessor Delmarva Power and Light Company from December 1992 to August 2002. Prior to December 1992, Mr. Cosgrove held various positions with Delmarva Power and Light including Chief Operating Officer and Chief Financial Officer. Mr. Cosgrove serves on the Board of Trustees of the University of Delaware and previously served as Chairman.
David Crane has served as the President, Chief Executive Officer 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.
Terry G. Dallas has been a director of NRG since December 2012. Previously, he served as a director of GenOn Energy, Inc. from December 2010 to December 2012. Mr. Dallas served as a director of Mirant Corporation from 2006 until December 2010. Mr. Dallas was also the former Executive Vice President and Chief Financial Officer of Unocal Corporation, an oil and gas exploration and production company prior to its merger with Chevron Corporation, from 2000 to 2005. Prior to that, Mr. Dallas held various executive finance positions in his 21-year career with Atlantic Richfield Corporation, an oil and gas company with major operations in the United States, Latin America, Asia, Europe and the Middle East.

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William E. Hantke has been a director of NRG since March 2006. Mr. Hantke served as Executive Vice President and Chief Financial Officer of Premcor, Inc., a refining company, from February 2002 until December 2005. Mr. Hantke was Corporate Vice President of Development of Tosco Corporation, a refining and marketing company, from September 1999 until September 2001, and he also served as Corporate Controller from December 1993 until September 1999. Prior to that position, he was employed by Coopers & Lybrand as Senior Manager, Mergers and Acquisitions from 1989 until 1990. He also held various positions from 1975 until 1988 with AMAX, Inc., including Corporate Vice President, Operations Analysis and Senior Vice President, Finance and Administration, Metals and Mining. He was employed by Arthur Young from 1970 to 1975 as Staff/Senior Accountant. Mr. Hantke was Non-Executive Chairman of Process Energy Solutions, a private alternative energy company until March 31, 2008 and served as director and Vice-Chairman of NTR Acquisition Co., an oil refining start-up, until January 2009.
Paul W. Hobby has been a director of NRG since March 2006. Mr. Hobby is the Managing Partner of Genesis Park, L.P., a Houston-based private equity business specializing in technology and communications investments which he helped to form in 2000. In that capacity, he serves as the Chief Executive Officer of Alpheus Communications, Inc., a Texas wholesale telecommunications provider, and as Former Chairman of CapRock Services Corp., the largest provider of satellite services to the global energy business. From November 1992 until January 2001, he served as Chairman and Chief Executive Officer of Hobby Media Services and was Chairman of Columbine JDS Systems, Inc. from 1995 until 1997. He was an Assistant U.S. Attorney for the Southern District of Texas from 1989 to 1992, Chief of Staff to the Lieutenant Governor of Texas, Bob Bullock, in 1991 and an Associate at Fulbright & Jaworski from 1986 to 1989. Mr. Hobby is also a director of Stewart Information Services Corporation (Stewart Title).
Gerald Luterman has been a director of NRG since April 2009. He also served as Interim Chief Financial Officer of the Company from November 2009 through May 2010. Mr. Luterman was Executive Vice President and Chief Financial Officer of KeySpan Corporation from August 1999 to September 2007. Prior to this time, Mr. Luterman had more than 30 years experience in senior financial positions with companies including American Express, Booz Allen & Hamilton, Emerson Electric Company and Arrow Electronics. Mr. Luterman also served as a director of IKON Office Solutions, Inc. from November 2003 until August 2008 and U.S. Shipping Partners L.P. from May 2006 until November 2009.
Kathleen A. McGinty has been a director of NRG since October 2008. Most recently, Ms. McGinty served as Secretary of the Pennsylvania Department of Environmental Protection (“DEP”), a position she held from 2003 until July 2008. Before joining the DEP, Ms. McGinty spent six years in the Clinton White House, where she was chair of the White House Council on Environmental Quality and earlier served as a senior environmental advisor to Vice President Al Gore. She also served as Secretary of the Board of Trustees at Saint Joseph's University in Pennsylvania and is the former Chair of the Pennsylvania Energy Development Authority. Ms. McGinty is also an operating partner of Element Partners, an investor in the clean technology sector. Ms. McGinty is also a director of Iberdrola USA. Recently, Ms. McGinty joined Weston Solutions, Inc. as Senior Vice President and Managing Director for Strategic Growth. Weston is an environmental engineering and remediation firm.
Edward R. Muller has served as Vice Chairman of the Board and a director of NRG since December 2012. Previously, he served as the Chairman and Chief Executive Officer of GenOn Energy, Inc from December 2010 to December 2012. He also served as President of GenOn from August 2011to December 2012. Prior to that, Mr. Muller served as the Chairman, President and Chief Executive Officer of Mirant Corporation from 2005 to December 2010. He served as President and Chief Executive Officer of Edison Mission Energy, a California-based independent power producer from 1993 to 2000. Mr. Muller is also a director of Transocean Ltd.
Anne C. Schaumburg has been a director of NRG since April 2005. From 1984 until her retirement in January 2002, she was employed by Credit Suisse First Boston in the Global Energy Group, where she last served as Managing Director. From 1979 to 1984, she was in the Utilities Group at Dean Witter Financial Services Group, where she last served as Managing Director. From 1971 to 1978, she was at The First Boston Corporation in the Public Utilities Group. Ms. Schaumburg is also a director of Brookfield Infrastructure Partners L.P.
Evan J. Silverstein has been a director of NRG since December 2012. Previously, he served as a director of GenOn Energy, Inc. from August 2006 to December 2012. He served as General Partner and Portfolio Manager of SILCAP LLC, a market-neutral hedge fund that principally invests in utilities and energy companies, from January 1993 until his retirement in December 2005. Previously, he served as portfolio manager specializing in utilities and energy companies and as senior equity utility analyst. Mr. Silverstein has given numerous speeches and has testified before Congress on a variety of energy-related issues. He is an audit committee financial expert.

105

Thomas H. Weidemeyer has been a director of NRG since December 2003. Until his retirement in December 2003, Mr. Weidemeyer served as Director, Senior Vice President and Chief Operating Officer of United Parcel Service, Inc., the world's largest transportation company and President of UPS Airlines. Mr. Weidemeyer became Manager of the Americas International Operation in 1989, and in that capacity directed the development of the UPS delivery network throughout Central and South America. In 1990, Mr. Weidemeyer became Vice President and Airline Manager of UPS Airlines and, in 1994, was elected its President and Chief Operating Officer. Mr. Weidemeyer became Senior Vice President and a member of the Management Committee of United Parcel Service, Inc. that same year, and he became Chief Operating Officer of United Parcel Service, Inc. in January 2001. Mr. Weidemeyer also serves as a director of The Goodyear Tire & Rubber Co., Waste Management, Inc. and Amsted Industries Incorporated.
Walter R. Young has been a director of NRG since December 2003. From May 1990 to June 2003, Mr. Young was Chairman, Chief Executive Officer and President of Champion Enterprises, Inc., an assembler and manufacturer of manufactured homes. Mr. Young has held senior management positions with The Henley Group, The Budd Company and BFGoodrich.
Executive Officers
David Crane has served as the President, Chief Executive Officer and a director of NRG since December 2003. For additional biographical information for Mr. Crane, see above under “Directors.”
Kirkland 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.
Mauricio Gutierrez has served as Executive Vice President and Chief Operating Officer 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 the Company'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.
David R. Hill has served as Executive Vice President and General Counsel since September 2012. Prior to joining NRG, Mr. Hill was a partner and co-head of Sidley Austin LLP's global energy practice group. Prior to this, 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 U.S. Department of Energy. Before his federal government service, Mr. Hill was a partner in major law firms in Washington, D.C. and Kansas City, Missouri, and handled a variety of regulatory, litigation and corporate matters. He received his law degree from Northwestern University School of Law in Chicago.
John W. Ragan has served as Executive Vice President and Regional President, Gulf Coast since July 2010. In this capacity, Mr. Ragan is responsible for managing NRG's largest regional power generation portfolio, totaling over 10,500 megawatts of power in Texas and NRG's retail electric provider, Reliant Energy. He previously served as Executive Vice President and Chief Operating Officer from February 2009 to July 2010, overseeing NRG's Plant Operations, Commercial Operations, Environmental Compliance, as well as the Engineering, Procurement and Construction division. He previously served as Executive Vice President and Regional President, Northeast from December 2006 to February 2009. Prior to joining NRG, Mr. Ragan was Vice President of Trading, Transmission, and Operations at FPL Energy in 2006 and also served as Vice President of Business Management for FPL Energy's Northeast Region from August 2005 through July 2006. Prior to this, Mr. Ragan served as General Manager - Containerboard and Packaging for Georgia Pacific Corporation from October 2004 through July 2005. He also served in increasing roles of responsibility for Mirant Corporation from 1996 through 2004, notably as Senior Vice President and Chief Executive Officer of Mirant's International Group from August 2003 to July 2004.
Ronald B. Stark has served as Vice President and Chief Accounting Officer since March 2012. In this capacity, Mr. Stark is responsible for directing NRG's financial accounting and reporting activities. Prior to this, Mr. Stark served as the Company's Vice President, Internal Audit from August 2011 to February 2012. He previously served as Director, Financial Reporting from October 2007 through July 2011. Mr. Stark joined the Company in January 2007. Mr. Stark previously held various executive and managerial accounting positions at Pegasus Communications and Berlitz International and began his career with Deloitte and Touche.

106

Denise M. Wilson has served as Executive Vice President and President, Alternative Energy Services since July 2011. In this capacity, Ms. Wilson is responsible for the oversight of all alternative energy ventures and development. Prior to this, Ms. Wilson served as Executive Vice President and Chief Administrative Officer (“CAO”) from September 2008 to July 2011. As CAO, Ms. Wilson had oversight for several key corporate functions including Human Resources, Investor Relations, Communications and Information Technology. Ms. Wilson originally joined NRG in 2000 and served as Vice President, Human Resources from 2004 until she was named CAO in July 2006. She served in that position until March 2007 when she joined Nash-Finch Company, a leading national food distributor as Senior Vice President, Human Resources. Ms. Wilson left Nash-Finch in June 2008 to retire and then rejoined NRG in September 2008. Ms. Wilson has also served as Vice President, Human Resources Operations with Metris Companies Inc. and Director, Human Resources with General Electric ITS.
Code of Ethics
NRG has adopted a code of ethics entitled "NRG Code of Conduct" that applies to directors, officers and employees, including the chief executive officer and senior financial officers of NRG. It may be accessed through the Corporate Governance section of the Company's website at  http://www.nrgenergy.com/investor/corpgov.htm.   NRG Energy, Inc. 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 Energy, Inc. Code of Conduct" is available in print to any stockholder who requests it.
Other information required by this Item will be incorporated by reference to the similarly named section of NRG's definitive Proxy Statement for its 2013 Annual Meeting of Stockholders.

Item 11 — Executive Compensation
Other information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2013 Annual Meeting of Stockholders.

107

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	11,154,603	
 	(1)	$	22.75	
 	 	8,599,188	
 	 	
Equity compensation plans not approved by security holders	2,116,317	
 	(2)	24.29	
 	 	2,126,892	
 	 	
Total	13,270,920	
 	 	$	22.99	
 	 	10,726,080	
 	(3)	
 	 	
(1)	Consists of shares issuable under the NRG LTIP and the ESPP. The NRG LTIP became effective upon the Company's emergence from bankruptcy. On July 28, 2010, the NRG LTIP was amended to increase the number of shares available for issuance to 22,000,000. The ESPP was approved by the Company's stockholders on May 14, 2008. As of December 31, 2011, there were 500,000 shares reserved from the Company's treasury shares for the ESPP. On April 25, 2012, NRG stockholders approved an increase of 1,000,000 shares available for issuance under the ESPP.	
 	 	
(2)	Consists of shares issuable under the NRG GenOn LTIP. On December 14, 2012, in connection with the Merger, NRG assumed the GenOn Energy, Inc. 2010 Omnibus Incentive Plan, and changed the name to the NRG 2010 Stock Plan for GenOn Employees, or the NRG GenOn LTIP. While the GenOn Energy, Inc. 2010 Omnibus Incentive Plan was previously approved by stockholders of RRI Energy, Inc. before it became GenOn, the plan is listed as “not approved” because the NRG GenOn LTIP was not subject to separate line item approval by NRG's stockholders when the Merger (which included the assumption of this plan) was approved. NRG intends to make subsequent grants under the NRG GenOn LTIP. As part of the Merger, NRG also assumed the GenOn Energy, Inc. 2002 Long-Term Incentive Plan, the GenOn Energy, Inc. 2002 Stock Plan, and the Mirant Corporation 2005 Omnibus Incentive Compensation Plan. NRG has no intention of making any grants or awards of its own equity securities under these plans. The number of securities to be issued upon the exercise of outstanding awards under these plans is 1,053,757 at a weighted-average exercise price of $59.66. See Item 15  —  Note 19,  Stock-Based Compensation , to Consolidated Financial Statements for a discussion of the NRG GenOn LTIP.	
 	 	
(3)	Consists of 7,580,318 shares of common stock under NRG's LTIP, 2,126,892 shares of common stock under the NRG GenOn LTIP, and 1,018,870 shares of treasury stock reserved for issuance under the ESPP. In the first quarter of 2013, 61,219 shares were issued to employees' accounts from the treasury stock reserve for the ESPP.	
Both the NRG LTIP and the NRG GenOn LTIP provide for grants of stock options, stock appreciation rights, restricted stock, performance units, deferred stock units and dividend equivalent rights. NRG's directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by the Company, are eligible to receive grants under the NRG LTIP and the NRG GenOn LTIP. However, participants eligible for the NRG LTIP at the time of the Merger are not eligible to receive grants under the NRG GenOn LTIP. The purpose of the NRG LTIP and the NRG GenOn LTIP is to promote the Company's long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to the Company's success and to enable the Company to attract, retain and reward the best available persons for positions of responsibility. The Compensation Committee of the Board of Directors administers the NRG LTIP and the NRG GenOn LTIP.
Other information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2013 Annual Meeting of Stockholders.
Item 13 — Certain Relationships and Related Transactions, and Director Independence
Other information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2013 Annual Meeting of Stockholders.
Item 14 — Principal Accounting Fees and Services
Other information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive Proxy Statement for its 2013 Annual Meeting of Stockholders.

108

PART IV
Item 15 — Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
The following consolidated financial statements of NRG Energy, Inc. and related notes thereto, together with the reports thereon of KPMG LLP, are included herein:
Consolidated Statements of Operations — Years ended December 31, 2012, 2011, and 2010 
Consolidated Statements of Comprehensive Income/(Loss) — Years ended December 31, 2012, 2011, and 2010
Consolidated Balance Sheets — December 31, 2012 and 2011 
Consolidated Statements of Cash Flows — Years ended December 31, 2012, 2011, and 2010 
Consolidated Statement of Stockholders' Equity — Years ended December 31, 2012, 2011, and 2010 
Notes to Consolidated Financial Statements
(a)(2) Financial Statement Schedule
The following Consolidated Financial Statement Schedule of NRG Energy, Inc. is filed as part of Item 15(d) of this report and should be read in conjunction with the Consolidated Financial Statements.
Schedule II — Valuation and Qualifying Accounts
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted.
(a)(3) Exhibits: See Exhibit Index submitted as a separate section of this report.
(b) Exhibits
See Exhibit Index submitted as a separate section of this report.
(c) Not applicable

109

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
NRG Energy Inc.'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 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, the Company's management concluded that its internal control over financial reporting was effective as of December 31, 2012.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2012, 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.

110

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

NRG Energy, Inc.:
We have audited NRG Energy, Inc.'s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). NRG Energy, 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 Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of NRG Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income/(loss), cash flows, and stockholders' equity for each of the years in the three-year period ended December 31, 2012, and our report dated February 27, 2013 expressed an unqualified opinion on those consolidated financial statements.

 	 	
 	/s/ KPMG LLP	
 	KPMG LLP	
Philadelphia, Pennsylvania	 	
February 27, 2013	 	

111

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

NRG Energy, Inc.:

We have audited the accompanying consolidated balance sheets of NRG Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income/(loss), cash flows, and stockholders' equity for each of the years in the three-year period ended December 31, 2012. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule “Schedule II. Valuation and Qualifying Accounts.” These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NRG Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, 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), the effectiveness of NRG Energy, Inc. and subsidiaries internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2013 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

 	
 	 	
 	/s/ KPMG LLP	
 	KPMG LLP	
Philadelphia, Pennsylvania	 	
February 27, 2013	 	

112

NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

 	For the Year Ended December 31,	
(In millions, except per share amounts)	2012	 	2011	 	2010	
Operating Revenues	 	 	 	 	 	
Total operating revenues	$	8,422	
 	 	$	9,079	
 	 	$	8,849	
 	
Operating Costs and Expenses	

Cost of operations	6,087	
 	 	6,675	
 	 	6,073	
 	
Depreciation and amortization	950	
 	 	896	
 	 	838	
 	
Impairment charge on emission allowances	—	
 	 	160	
 	 	—	
 	
Selling, general and administrative	892	
 	 	668	
 	 	598	
 	
GenOn acquisition-related transaction and integration costs	107	
 	 	—	
 	 	—	
 	
Development costs	36	
 	 	45	
 	 	55	
 	
Total operating costs and expenses	8,072	
 	 	8,444	
 	 	7,564	
 	
Gain on sale of assets	—	
 	 	—	
 	 	23	
 	
Operating Income	350	
 	 	635	
 	 	1,308	
 	
Other Income/(Expense)	

Equity in earnings of unconsolidated affiliates	37	
 	 	35	
 	 	44	
 	
Bargain purchase gain related to GenOn acquisition	560	
 	 	—	
 	 	—	
 	
Impairment charge on investment	(2	)	 	(495	)	 	—	
 	
Other income, net	19	
 	 	19	
 	 	33	
 	
Loss on debt extinguishment	(51	)	 	(175	)	 	(2	)	
Interest expense	(661	)	 	(665	)	 	(630	)	
Total other expense	(98	)	 	(1,281	)	 	(555	)	
Income/(Loss) Before Income Taxes	252	
 	 	(646	)	 	753	
 	
Income tax (benefit)/expense	(327	)	 	(843	)	 	277	
 	
Net Income	579	
 	 	197	
 	 	476	
 	
Less: Net income/(loss) attributable to noncontrolling interest	20	
 	 	—	
 	 	(1	)	
Net Income Attributable to NRG Energy, Inc.	559	
 	 	197	
 	 	477	
 	
Dividends for preferred shares	9	
 	 	9	
 	 	9	
 	
Income Available for Common Stockholders	$	550	
 	 	$	188	
 	 	$	468	
 	
Earnings Per Share Attributable to NRG Energy, Inc. Common Stockholders	 	 	 	 	 	
Weighted average number of common shares outstanding — basic	232	
 	 	240	
 	 	252	
 	
Net Income per Weighted Average Common Share — Basic	$	2.37	
 	 	$	0.78	
 	 	$	1.86	
 	
Weighted average number of common shares outstanding — diluted	234	
 	 	241	
 	 	254	
 	
Net Income per Weighted Average Common Share — Diluted	$	2.35	
 	 	$	0.78	
 	 	$	1.84	
 	
Dividends Per Common Share	$	0.18	
 	 	$	—	
 	 	$	—	
 	
See notes to Consolidated Financial Statements.

113

NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

 	For the Year Ended December 31,	
 	2012	 	2011	 	2010	
 	(In millions)	
Net Income	$	579	
 	 	$	197	
 	 	$	476	
 	
Other comprehensive (loss)/income, net of tax	 	 	 	 	 	
Unrealized (loss)/gain on derivatives, net of income tax benefit/(expense) of $94, $181, and ($20)	(163	)	 	(309	)	 	35	
 	
Foreign currency translation adjustments, net of income tax benefit of $1, $1, and $1	(1	)	 	(2	)	 	(3	)	
Reclassification adjustment for translation gain realized upon sale of Schkopau, net of income tax benefit of $6, $0, and $0	(11	)	 	—	
 	 	—	
 	
Available-for-sale securities, net of income tax expense of $1, $0, and $0	3	
 	 	(1	)	 	—	
 	
Defined benefit plan, net of income tax benefit of $21, $27, and $9	(52	)	 	(46	)	 	(16	)	
Other comprehensive (loss)/income	(224	)	 	(358	)	 	16	
 	
Comprehensive income/(loss)	355	
 	 	(161	)	 	492	
 	
Less: Comprehensive income/(loss) attributable to noncontrolling interest	20	
 	 	—	
 	 	(1	)	
Comprehensive income/(loss) attributable to NRG Energy, Inc.	335	
 	 	(161	)	 	493	
 	
Dividends for preferred shares	9	
 	 	9	
 	 	9	
 	
Comprehensive income/(loss) available for common stockholders	$	326	
 	 	$	(170	)	 	$	484	
 	
See notes to Consolidated Financial Statements.

114

NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

 	As of December 31,	
 	2012	 	2011	
 	(In millions)	
ASSETS	 	 	 	
Current Assets	 	 	 	
Cash and cash equivalents	$	2,087	
 	 	$	1,105	
 	
Funds deposited by counterparties	271	
 	 	258	
 	
Restricted cash	217	
 	 	292	
 	
Accounts receivable — trade, less allowance for doubtful accounts of $32 and $23	986	
 	 	834	
 	
Inventory	931	
 	 	308	
 	
Derivative instruments	2,644	
 	 	4,427	
 	
Cash collateral paid in support of energy risk management activities	229	
 	 	311	
 	
Deferred income taxes	56	
 	 	—	
 	
Prepayments and other current assets	535	
 	 	214	
 	
Total current assets	7,956	
 	 	7,749	
 	
Property, Plant and Equipment	 	 	 	
In service	21,316	
 	 	15,704	
 	
Under construction	4,369	
 	 	2,487	
 	
Total property, plant and equipment	25,685	
 	 	18,191	
 	
Less accumulated depreciation	(5,417	)	 	(4,570	)	
Net property, plant and equipment	20,268	
 	 	13,621	
 	
Other Assets	 	 	 	
Equity investments in affiliates	676	
 	 	640	
 	
Capital leases and notes receivable, less current portion	79	
 	 	342	
 	
Goodwill	1,956	
 	 	1,886	
 	
Intangible assets, net of accumulated amortization of $1,706 and $1,452	1,200	
 	 	1,419	
 	
Nuclear decommissioning trust fund	473	
 	 	424	
 	
Derivative instruments	662	
 	 	483	
 	
Deferred income taxes	1,261	
 	 	—	
 	
Other non-current assets	597	
 	 	336	
 	
Total other assets	6,904	
 	 	5,530	
 	
Total Assets	$	35,128	
 	 	$	26,900	
 	
See notes to Consolidated Financial Statements.

115

NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Continued)

 	As of December 31,	
 	2012	 	2011	
 	(In millions, except share data)	
LIABILITIES AND STOCKHOLDERS' EQUITY	 	 	 	
Current Liabilities	 	 	 	
Current portion of long-term debt and capital leases	$	147	
 	 	$	87	
 	
Accounts payable 	1,170	
 	 	808	
 	
Derivative instruments	1,981	
 	 	4,029	
 	
Deferred income taxes	—	
 	 	127	
 	
Cash collateral received in support of energy risk management activities	271	
 	 	258	
 	
Accrued interest expense	191	
 	 	165	
 	
Other accrued expenses	567	
 	 	281	
 	
Other current liabilities	350	
 	 	106	
 	
Total current liabilities	4,677	
 	 	5,861	
 	
Other Liabilities	 	 	 	
Long-term debt and capital leases	15,733	
 	 	9,745	
 	
Nuclear decommissioning reserve	354	
 	 	335	
 	
Nuclear decommissioning trust liability	273	
 	 	254	
 	
Postretirement and other benefit obligations	803	
 	 	400	
 	
Deferred income taxes	55	
 	 	1,389	
 	
Derivative instruments	500	
 	 	459	
 	
Out-of-market contracts	1,216	
 	 	183	
 	
Other non-current liabilities	735	
 	 	356	
 	
Total non-current liabilities	19,669	
 	 	13,121	
 	
Total Liabilities	24,346	
 	 	18,982	
 	
3.625% convertible perpetual preferred stock; $0.01 par value; 250,000 shares issued and outstanding (at liquidation value of $250, net of issuance costs)	249	
 	 	249	
 	
Commitments and Contingencies	 	 	 	
Stockholders' Equity	 	 	 	
Common stock; $0.01 par value; 500,000,000 shares authorized; 399,112,616 and 304,183,720 shares issued and 322,606,898 and 227,519,521 shares outstanding at December 31, 2012 and 2011	4	
 	 	3	
 	
Additional paid-in capital	7,587	
 	 	5,346	
 	
Retained earnings	4,494	
 	 	3,987	
 	
Less treasury stock, at cost — 76,505,718 and 76,664,199 shares at
  December 31, 2012 and 2011	(1,920	)	 	(1,924	)	
Accumulated other comprehensive (loss)/income	(150	)	 	74	
 	
Noncontrolling interest	518	
 	 	183	
 	
Total Stockholders' Equity	10,533	
 	 	7,669	
 	
Total Liabilities and Stockholders' Equity	$	35,128	
 	 	$	26,900	
 	
See notes to Consolidated Financial Statements.

116

NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

 	For the Year Ended December 31,	
 	2012	 	2011	 	2010	
 	(In millions)	
Cash Flows from Operating Activities	 	 	 	 	 	
Net income	$	579	
 	 	$	197	
 	 	$	476	
 	
Adjustments to reconcile net income to net cash provided by operating activities:	 	 	 	 	 	
Distributions and equity in earnings of unconsolidated affiliates	2	
 	 	9	
 	 	(19	)	
Bargain purchase gain related to GenOn acquisition	(560	)	 	—	
 	 	—	
 	
Depreciation and amortization	950	
 	 	896	
 	 	838	
 	
Provision for bad debts	45	
 	 	59	
 	 	54	
 	
Amortization of nuclear fuel	39	
 	 	39	
 	 	40	
 	
Amortization of financing costs and debt discount/premiums	31	
 	 	32	
 	 	32	
 	
Loss on debt extinguishment	9	
 	 	58	
 	 	—	
 	
Amortization of intangibles and out-of-market commodity contracts	146	
 	 	167	
 	 	4	
 	
Amortization of unearned equity compensation	41	
 	 	28	
 	 	30	
 	
Loss on disposals and sales of assets, net	11	
 	 	14	
 	 	4	
 	
Impairment charges and asset write downs	—	
 	 	657	
 	 	25	
 	
Changes in derivative instruments	124	
 	 	(138	)	 	(114	)	
Changes in deferred income taxes and liability for uncertain tax benefits	(353	)	 	(859	)	 	255	
 	
Changes in nuclear decommissioning trust liability	37	
 	 	20	
 	 	34	
 	
Cash (used)/provided by changes in other working capital, net of acquisition and disposition effects:	 	 	 	 	 	
Accounts receivable - trade	(131	)	 	(119	)	 	138	
 	
Inventory	(172	)	 	145	
 	 	91	
 	
Prepayments and other current assets	(26	)	 	59	
 	 	(51	)	
Accounts payable	(132	)	 	9	
 	 	(261	)	
Accrued expenses and other current liabilities	231	
 	 	(111	)	 	(48	)	
Other assets and liabilities	278	
 	 	4	
 	 	95	
 	
Net Cash Provided by Operating Activities	1,149	
 	 	1,166	
 	 	1,623	
 	
Cash Flows from Investing Activities	 	 	 	 	 	
Acquisition of businesses, net of cash acquired	(81	)	 	(377	)	 	(1,006	)	
Cash acquired in GenOn acquisition	983	
 	 	—	
 	 	—	
 	
Capital expenditures	(3,396	)	 	(2,310	)	 	(706	)	
Increase in restricted cash, net	(66	)	 	(35	)	 	(4	)	
Decrease/(increase) in restricted cash to support equity requirements for U.S. DOE funded projects	164	
 	 	(215	)	 	—	
 	
(Increase)/decrease in notes receivable	(24	)	 	12	
 	 	39	
 	
Proceeds from renewable energy grants	62	
 	 	—	
 	 	102	
 	
Purchases of emission allowances, net of proceeds	(1	)	 	(19	)	 	(34	)	
Investments in nuclear decommissioning trust fund securities	(436	)	 	(406	)	 	(341	)	
Proceeds from sales of nuclear decommissioning trust fund securities	399	
 	 	385	
 	 	307	
 	
Proceeds from sale of assets, net	137	
 	 	7	
 	 	43	
 	
Investments in unconsolidated affiliates	(25	)	 	(66	)	 	(23	)	
Other	22	
 	 	(23	)	 	—	
 	
Net Cash Used by Investing Activities	(2,262	)	 	(3,047	)	 	(1,623	)	
Cash Flows from Financing Activities	 	 	 	 	 	
Payment of dividends to preferred and common stockholders	(50	)	 	(9	)	 	(9	)	
(Payments for)/net receipts from settlement of acquired derivatives that include financing elements	(68	)	 	(83	)	 	137	
 	
Payment for treasury stock	—	
 	 	(430	)	 	(180	)	
Sales proceeds and other contributions from noncontrolling interests in subsidiaries	347	
 	 	29	
 	 	50	
 	
Proceeds from issuance of common stock	—	
 	 	2	
 	 	2	
 	
Proceeds from issuance of long-term debt	3,165	
 	 	6,224	
 	 	1,484	
 	
(Payments for)/proceeds from term loan for funded letter of credit facility	—	
 	 	(1,300	)	 	1,300	
 	
Decrease/(increase) in restricted cash supporting funded letter of credit facility	—	
 	 	1,300	
 	 	(1,300	)	
Payment of debt issuance and hedging costs	(35	)	 	(207	)	 	(75	)	
Payments for short and long-term debt	(1,260	)	 	(5,493	)	 	(758	)	
Net Cash Provided by Financing Activities	2,099	
 	 	33	
 	 	651	
 	
Effect of exchange rate changes on cash and cash equivalents	(4	)	 	2	
 	 	(4	)	
Net Increase/(Decrease) in Cash and Cash Equivalents	982	
 	 	(1,846	)	 	647	
 	
Cash and Cash Equivalents at Beginning of Period	1,105	
 	 	2,951	
 	 	2,304	
 	
Cash and Cash Equivalents at End of Period	$	2,087	
 	 	$	1,105	
 	 	$	2,951	
 	
See notes to Consolidated Financial Statements.

117

NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

 	Preferred
Stock	 	Common
Stock	 	Additional
Paid-In
Capital	 	Retained
Earnings	 	Treasury
Stock	 	Accumulated
Other
Comprehensive
Income/(Loss)	 	Noncon-trolling
Interest	 	Total
Stockholders'
Equity	
 	(In millions)	
Balances at December 31, 2009	$	149	
 	 	$	3	
 	 	$	4,948	
 	 	$	3,332	
 	 	$	(1,163	)	 	$	416	
 	 	$	12	
 	 	$	7,697	
 	
Net income/(loss)	 	

 	 	477	

 	 	(1	)	 	476	
 	
Other comprehensive income	

 	

 	 	

 	
 	 	16	

 	 	16	
 	
Equity-based compensation	 	
 	 	 	
 	 	28	

 	 	 	
 	 	 	
 	 	28	
 	
Purchase of treasury stock	 	

 	 	 	
 	 	(180	)	 	 	
 	 	 	
 	 	(180	)	
Preferred stock dividends	 	

 	 	(9	)	 	 	

 	 	(9	)	
ESPP share purchases	 	
 	 	 	
 	 	3	

 	 	 	
 	 	 	
 	 	3	
 	
NINA contribution, net of $17 tax	 	
 	 	 	
 	 	27	

 	 	 	
 	 	6	
 	 	33	
 	
4.00% preferred stock conversion to common stock	(149	)	 	 	
 	 	149	

 	 	 	
 	 	 	
 	 	—	
 	
Shares returned from affiliate of CS	 	
 	 	 	
 	 	160	
 	 	 	
 	 	(160	)	 	 	
 	 	 	
 	 	—	
 	
Other	 	
 	 	 	
 	 	8	

 	

 	 	8	
 	
Balances at December 31, 2010	$	—	
 	 	$	3	
 	 	$	5,323	
 	 	$	3,800	
 	 	$	(1,503	)	 	$	432	
 	 	$	17	
 	 	$	8,072	
 	
Net income	

 	

 	 	197	

 	 	

 	
 	 	197	
 	
Other comprehensive loss	

 	

 	 	

 	
 	 	(358	)	 	
 	
 	 	(358	)	
Equity-based compensation	

 	
 	 	28	

 	 	

 	

 	 	28	
 	
Purchase of treasury stock	

 	

 	 	
 	
 	 	(430	)	 	

 	
 	 	(430	)	
Preferred stock dividends	

 	

 	 	(9	)	 	

 	

 	 	(9	)	
ESPP share purchases	

 	
 	 	(5	)	 	(1	)	 	9	

 	 	
 	
 	 	3	
 	
NINA deconsolidation	

 	

 	 	

 	

 	 	(17	)	 	(17	)	
Ivanpah contribution	

 	

 	 	

 	

 	 	183	
 	 	183	
 	
Balances at December 31, 2011	$	—	
 	 	$	3	
 	 	$	5,346	
 	 	$	3,987	
 	 	$	(1,924	)	 	$	74	
 	 	$	183	
 	 	$	7,669	
 	
Net income	

 	

 	 	559	

 	 	
 	
 	 	20	
 	 	579	
 	
Other comprehensive loss	

 	

 	 	

 	
 	 	(224	)	 	
 	
 	 	(224	)	
Issuance of shares for acquisition of GenOn	
 	
 	 	1	
 	 	2,176	

 	 	

 	

 	 	2,177	
 	
Equity-based compensation	

 	
 	 	34	

 	 	

 	

 	 	34	
 	
Preferred stock dividends	

 	

 	 	(9	)	 	

 	

 	 	(9	)	
Common stock dividends	

 	

 	 	(41	)	 	

 	

 	 	(41	)	
ESPP share purchases	

 	
 	 	(1	)	 	(2	)	 	4	

 	 	
 	
 	 	1	
 	
Sales proceeds and other contributions from noncontrolling interests	 	 	 	 	32	
 	 	 	 	 	 	 	 	315	
 	 	347	
 	
Balances at December 31, 2012	$	—	
 	 	$	4	
 	 	$	7,587	
 	 	$	4,494	
 	 	$	(1,920	)	 	$	(150	)	 	$	518	
 	 	$	10,533	
 	
See notes to Consolidated Financial Statements.

118

NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Nature of Business 
General
NRG Energy, Inc., or NRG or the Company, is an integrated wholesale power generation and retail electricity company in the United States. At its core, NRG is a wholesale power generator engaged in the ownership and operation of power generation facilities; the trading of energy, capacity and related products; and the transacting in and trading of fuel and transportation services. Second, while leveraging its core wholesale power business, NRG is a retail energy company engaged in the supply of energy, services, and innovative, sustainable products to retail customers in competitive markets through multiple channels and brands like Reliant Energy, Green Mountain Energy, and Energy Plus (collectively, the Retail Business). Finally, NRG is focused on the deployment and commercialization of potentially disruptive technologies, like electric vehicles, Distributed Solar and smart meter technology, which have the potential to change the nature of the power supply industry.
NRG's domestic generation facilities consist of intermittent, baseload, intermediate, and peaking power generation facilities. The following table summarizes NRG's global generation portfolio by operating segment, which includes 89 fossil fuel plants, four Utility Scale Solar facilities and four wind farms, as well as Distributed Solar facilities. Also included are three natural gas plants, three Utility Scale Solar facilities and additional Distributed Solar facilities currently under construction, and two Utility Scale Solar facilities partially in-service. All Utility Scale Solar and Distributed Solar facilities are described in megawatts on an alternating current, or AC, basis:

 	 	Fossil Fuel, Nuclear, and Renewable	
 	 	(In MW)	
Generation Type	 	Texas	 	East	 	South Central	 	West	 	Other (Thermal)	 	Alter-
native Energy	 	Total Domestic	 	Other (Inter-national)	 	Total Global	
Natural gas	 	5,510	
 	 	7,655	
 	 	3,820	
 	 	7,520	
 	 	105	
 	 	—	
 	 	24,610	
 	 	—	
 	 	24,610	
 	
Coal	 	4,195	
 	 	7,585	
 	 	1,495	
 	 	—	
 	 	15	
 	 	—	
 	 	13,290	
 	 	605	
 	 	13,895	
 	
Oil	 	—	
 	 	6,030	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	6,030	
 	 	—	
 	 	6,030	
 	
Nuclear	 	1,175	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	1,175	
 	 	—	
 	 	1,175	
 	
Wind	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	450	
 	 	450	
 	 	—	
 	 	450	
 	
Utility Scale Solar	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	345	
 	 	345	
 	 	—	
 	 	345	
 	
Distributed Solar	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	40	
 	 	40	
 	 	—	
 	 	40	
 	
Total generation capacity	 	10,880	
 	 	21,270	
 	 	5,315	
 	 	7,520	
 	 	120	
 	 	835	
 	 	45,940	
 	 	605	
 	 	46,545	

Under Construction	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas	 	—	
 	 	—	
 	 	—	
 	 	1,270	
 	 	—	
 	 	75	
 	 	1,345	
 	 	—	
 	 	1,345	
 	
Utility Scale Solar	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	430	
 	 	430	
 	 	—	
 	 	430	
 	
Distributed Solar	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	5	
 	 	5	
 	 	—	
 	 	5	
 	
Total under construction	 	—	
 	 	—	
 	 	—	
 	 	1,270	
 	 	—	
 	 	510	
 	 	1,780	
 	 	—	
 	 	1,780	
 	
In addition, the Company's thermal assets provide steam and chilled water capacity of approximately 1,098 MWt through its district energy business.
NRG sells power from its generation portfolio and offers capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability.
NRG's Retail Business arranges for the transmission and delivery of electricity to customers, bill customers, collect payments for electricity sold and maintain call centers to provide customer service. Based on metered locations, as of December 31, 2012, the Retail Business combined to serve approximately 2.2 million residential, small business, commercial and industrial customers.
NRG was incorporated as a Delaware corporation on May 29, 1992. NRG's common stock is listed on the New York Stock Exchange under the symbol "NRG". The Company's principal executive offices are located at 211 Carnegie Center, Princeton, New Jersey 08540. With the Merger completed, NRG is now dual headquartered, with financial and commercial headquarters in Princeton, New Jersey and operational headquarters in Houston, Texas. NRG's telephone number is (609) 524-4500. The address of the Company's website is  www.nrgenergy.com . NRG's recent annual reports, quarterly reports, current reports, and other periodic filings are available free of charge through the Company's website.

119

Note 2 — Summary of Significant Accounting Policies 
Principles of Consolidation and Basis of Presentation
The Company's consolidated financial statements have been prepared in accordance with U.S. GAAP. The ASC, established by the FASB, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants.
The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of ASC 810,  Consolidations,  or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a VIE should be consolidated.
2012 Business Segment Realignment
Effective in fiscal year 2012, NRG's segment structure and its allocation of corporate expenses were updated to reflect how management currently makes financial decisions and allocates resources. The Company has recast the data from prior periods to reflect this change in reportable segments to conform to the current year presentation. The Company's businesses are primarily segregated based on the Retail Business, conventional power generation, alternative energy businesses and corporate activities.  Within NRG's conventional power generation operations, there are distinct components with separate operating results and management structures for the following geographical regions: Texas, East, South Central, West, and Other, which includes its international businesses, thermal and chilled water business and maintenance services.  The Company's alternative energy businesses include solar and wind assets, electric vehicle services and carbon capture business. 
Cash and Cash Equivalents
Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.
Funds Deposited by Counterparties
Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Some amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities. Changes in funds deposited by counterparties are closely associated with the Company's operating activities, and are classified as an operating activity in the Company's consolidated statements of cash flows.
Restricted Cash
Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use. These funds are used to pay for 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 in the balance sheet at outstanding principal adjusted for any write-offs and the allowance for doubtful accounts. For its Retail Business, the Company accrues an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings (for commercial and industrial customers), historical collections, accounts receivable aging and other factors. The Retail Business writes-off accounts receivable balances against the allowance for doubtful accounts when it determines a receivable is uncollectible.

120

Inventory
Inventory is valued at the lower of weighted average cost or market, and consists principally of fuel oil, coal and raw materials used to generate electricity or steam. The Company removes these inventories as they are used in the production of electricity or steam. Spare parts inventory is valued at a weighted average cost, since the Company expects to recover these costs in the ordinary course of business. The Company removes these inventories when they are used for repairs, maintenance or capital projects. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows.
Property, Plant and Equipment
Property, plant and equipment are stated at cost; however impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. NRG also classifies nuclear fuel related to the Company's 44% ownership interest in STP as part of the Company's property, plant, and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation other than nuclear fuel is computed using the straight-line method, while nuclear fuel is amortized based on units of production over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of operations.
Asset Impairments
Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the statements of operations. Fair values are determined by a variety of valuation methods, including 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.
NINA is majority-owned subsidiary of NRG established to develop, finance and invest in new advanced design nuclear projects in select markets across North America, including the planned South Texas Project Units 3 and 4 Project, or STP 3 & 4. On March 11, 2011, Japan was hit by a devastating earthquake and tsunami which, in turn, triggered a nuclear incident at the Fukushima Daiichi Nuclear Power Station. The nuclear incident in Japan introduced multiple and substantial uncertainties around new nuclear development in the United States and the availability of debt and equity financing to NINA. Consequently, NINA announced, on March 21, 2011, that it was reducing the scope of development at the STP 3 & 4 expansion and suspended indefinitely all detailed engineering work and other pre-construction activities. As a result, NRG announced that, while it will cooperate with and support its current partners and any prospective future partners in attempting to develop STP 3 & 4 successfully, it was withdrawing from further financial participation in NINA's development of STP 3 & 4.
Due to the events described above, NRG evaluated its investment in NINA for impairment. As part of this process, NRG evaluated the contractual rights and economic interests held by the various stakeholders in NINA, and concluded that while it continues to hold majority legal ownership, NRG ceased to have a controlling financial interest in NINA at the end of the first quarter of 2011. Consequently, NRG deconsolidated NINA as of March 31, 2011, in accordance with ASC 810. This resulted in the removal of the following amounts from NRG's consolidated balance sheet: $930 million of construction in progress; $154 million of accounts payable and accrued expenses; $297 million of long-term debt; $17 million of non-controlling interest; and $19 million of other assets and liabilities. Furthermore, NRG concluded it was remote that NRG would recover any portion of the carrying amount of its equity investment in NINA and, consequently, recorded impairment charges related to the full amount of its investment, as well as additional contributions made to support the reduced scope of work. The impairment charges totaled $495 million for the year ended December 31, 2011. In 2012, NRG recorded an additional impairment charge related to additional contributions made of $2 million.

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Project Development Costs and Capitalized Interest
Project development costs are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset.
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, 2012, 2011, and 2010, was $104 million, $80 million, and $36 million, respectively.
When a project is available for operations, capitalized interest and project development costs are reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.
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. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, marketing partnerships, development rights, trade names, emission allowances, and fuel contracts when specific rights and contracts are acquired. In addition, NRG also established values for emission allowances and power contracts upon adoption of Fresh Start reporting. These intangible assets are amortized based on expected volumes, expected delivery, expected discounted future net cash flows, straight line or units of production basis.
Intangible assets determined to have indefinite lives are not amortized, but rather are tested for impairment at least annually or more frequently if events or changes in circumstances indicate that such acquired intangible assets have been determined to have finite lives and should now be amortized over their useful lives. NRG had no intangible assets with indefinite lives recorded as of December 31, 2012.
Emission allowances held-for-sale, which are included in other non-current assets on the Company's consolidated balance sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360.
Goodwill
In accordance with ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed. NRG performs goodwill impairment tests annually, during the fourth quarter, and when events or changes in circumstances indicate that the carrying value may not be recoverable.
In September 2011, the FASB issued ASU No. 2011-08, Intangibles - Goodwill and Other (Topic 350) Testing Goodwill for Impairment , or ASU No. 2011-08. The objective of ASU 2011-08 is to simplify how entities test goodwill for impairment. The amendments in ASU No. 2011-08 permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in Topic 350. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. ASU No. 2011-08 is effective for annual and interim goodwill impairment tests performed in fiscal years beginning after December 15, 2011. Early adoption is permitted. The Company adopted the provisions of ASU No. 2011-08, effective January 1, 2011, with no impact on its results of operations, financial position or cash flows.
In the absence of sufficient qualitative factors, goodwill impairment is determined using a two step process:

 	Step one —	Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two.	
 	Step two —	Compare the implied fair value of the reporting unit's goodwill to the book value of the reporting unit goodwill. If the book value of goodwill exceeds fair value, an impairment charge is recognized for the sum of such excess.	

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Income Taxes
NRG accounts for income taxes using the liability method in accordance with ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.
NRG has two categories of income tax expense or benefit — current and deferred, as follows:
 	 	
•	Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and	
 	 	
•	Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income.	
NRG reports some of the Company's revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. NRG measures the Company's deferred income tax assets and deferred income tax liabilities using income tax rates that are currently in effect. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets, net of valuation allowances. In arriving at this conclusion to utilize projections of future profit before tax in our estimate of future taxable income, the Company considered the profit before tax generated in recent years. A valuation allowance is recorded to reduce the Company's net deferred tax assets to an amount that is more-likely-than-not to be realized.
NRG reduces its current income tax expense in the consolidated statement of operations for any investment tax credits, or ITCs, that are not convertible into cash grants, as well as other tax credits, in the period the tax credit is generated. ITCs that are convertible into cash grants, as well as the deferred income tax benefit generated by the difference in the financial statement and tax basis of the related assets, are recorded as a reduction to the carrying value of the underlying property and subsequently amortized to earnings on a straight-line basis over the useful life of each underlying property.
The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense.
In accordance with ASC 805 and as discussed further in Note 18, Income Taxes, changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax expense.
Revenue Recognition
Energy — Both physical and financial transactions are entered into to optimize the financial performance of NRG's generating facilities. Electric energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. Financial transactions, or the buying and selling of energy for trading purposes, are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815.
Capacity — Capacity revenues are recognized when contractually earned, and consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements.
Sale of Emission Allowances — NRG records the Company's bank of emission allowances as part of the Company's intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of usage from the Company's emission bank to intangible assets held-for-sale for trading purposes. NRG records the sale of emission allowances on a net basis within operating revenue in the Company's consolidated statements of operations.
Contract Amortization — Assets and liabilities recognized from power sales agreements assumed at Fresh Start and through acquisitions related to the sale of electric capacity and energy in future periods for which the fair value has been determined to be significantly less (more) than market are amortized to revenue over the term of each underlying contract based on actual generation and/or contracted volumes.

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Retail revenues — Gross revenues for energy sales and services to retail customers are recognized upon delivery under the accrual method. Energy sales and services that have been delivered but not billed by period end are estimated. Gross revenues also includes energy revenues from resales of purchased power, which were $151 million, $186 million and $158 million for the years ended December 31, 2012, 2011, and 2010, respectively. These revenues represent the sale of excess supply to third parties in the market.
Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed. NRG recorded receivables for unbilled revenues of $338 million, $318 million and $282 million as of December 31, 2012, 2011, and 2010, respectively, for retail energy sales and services.
PPAs —Certain of the Company's revenues are currently obtained through PPAs or other contractual arrangements. All of these PPAs are recorded as operating leases in accordance with ASC 840,  Leases,  or ASC 840. ASC 840 requires 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. These leases have no minimum lease payments and all the rent is recorded as contingent rent on an actual basis when the electricity is delivered.
Gross Receipts and Sales Taxes
In connection with its Retail Business, the Company records gross receipts taxes on a gross basis in revenues and cost of operations in its consolidated statements of operations. During the years ended December 31, 2012, 2011, and 2010, NRG's revenues and cost of operations included gross receipts taxes of $67 million, $64 million, and $67 million respectively. Additionally, the Retail Business records sales taxes collected from its taxable customers and remitted to the various governmental entities on a net basis, thus, there is no impact on the Company's consolidated statement of operations.
Cost of Energy for Retail Operations
The cost of energy for electricity sales and services to retail customers is based on estimated supply volumes for the applicable reporting period. A portion of the cost of energy ($97 million, $87 million and $61 million as of December 31, 2012, 2011, and 2010, respectively) was accrued and consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities. In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees are estimated using the same method used for electricity sales and services to retail customers. In addition, ISO fees are estimated based on historical trends, estimated supply volumes and initial ERCOT ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.
Derivative Financial Instruments
NRG accounts for derivative financial instruments under ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value unless they qualify for a NPNS exception. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as hedges, if elected for hedge accounting, are either:
 	 	
•	Recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments; or	
 	 	
•	Deferred and recorded as a component of accumulated OCI until the hedged transactions occur and are recognized in earnings.	
NRG's primary derivative instruments are power sales contracts, fuels purchase contracts, other energy related commodities, and interest rate instruments used to mitigate variability in earnings due to fluctuations in market prices and interest rates. On an ongoing basis, NRG assesses the effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. Internal analyses that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such an energy 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. Hedge accounting will also be discontinued on contracts related to commodity price risk previously accounted for as cash flow hedges when it is probable that delivery will not be made against these contracts. In this case, the gain or loss previously deferred in accumulated 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.

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Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.
NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.
Foreign Currency Translation and Transaction Gains and Losses
The local currencies are generally the functional currency of NRG's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the Company's statements of operations for the period, but are accumulated and reported as a separate component of stockholders' equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign currency transaction gains or losses are reported within other income/(expense) in the Company's statements of operations. For the years ended December 31, 2012, 2011, and 2010, amounts recognized as foreign currency transaction gains (losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2012, 2011, and 2010 were $53 million, $72 million and $76 million, respectively.
Concentrations of Credit Risk
Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of trust funds, accounts receivable, notes receivable, derivatives, and investments in debt securities. Trust funds are held in accounts managed by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling agreements. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of its customer base. See Note 4,  Fair Value of Financial Instruments,  for a further discussion of derivative concentrations.
Fair Value of Financial Instruments
The carrying amount of cash and cash equivalents, funds deposited by counterparties, receivables, accounts payables, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. See Note 4,  Fair Value of Financial Instruments  for a further discussion of fair value of financial instruments.
Asset Retirement Obligations
NRG accounts for its AROs in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made.
Upon initial recognition of a liability for an ARO, NRG capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. See Note 12,  Asset Retirement Obligations,  for a further discussion of AROs.

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Pensions
NRG offers pension benefits through either a defined benefit pension plan or a cash balance plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. NRG accounts for pension and other postretirement benefits in accordance with ASC 715,  Compensation — Retirement Benefits.   NRG recognizes the funded status of the Company's defined benefit plans in the statement of financial position and records an offset for gains and losses as well as all prior service costs that have not been included as part of the Company's net periodic benefit cost to other comprehensive income. The determination of NRG's obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. NRG's actuarial consultants determine assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company.
NRG measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820.
Stock-Based Compensation
NRG accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock Compensation, or ASC 718 .   The fair value of the Company's non-qualified stock options and performance units are estimated on the date of grant using the Black-Scholes option-pricing model and the Monte Carlo valuation model, respectively. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's restricted stock units and deferred stock units. Forfeiture rates are estimated based on an analysis of NRG's historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award.
Investments Accounted for by the Equity Method
NRG has investments in various domestic energy projects, as well as one Australian project. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents NRG from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of domestic partnerships and, generally, in the net income or losses of its Australian project, are reflected as equity in earnings of unconsolidated affiliates.
Marketing and Advertising Costs
The Company expenses its advertising and marketing costs as incurred. The costs of tangible assets used in advertising campaigns are recorded as fixed assets or deferred advertising costs and amortized as advertising costs over the shorter of the useful life of the asset or the advertising campaign. The Company has several long-term sponsorship arrangements. Payments related to these arrangements are deferred and expensed over the term of the arrangement. Marketing and advertising expenses included within selling, general and administrative expense for the years ended December 31, 2012, 2011, and 2010 were $197 million, $127 million, and $81 million respectively.
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 financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

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In recording transactions and balances resulting from business operations, NRG uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, and the valuation of energy commodity contracts, environmental liabilities, legal costs incurred in connection with recorded loss contingencies, and assets acquired and liabilities assumed in business combinations, among others. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Reclassifications
Certain prior-year amounts have been reclassified for comparative purposes.
Recent Accounting Developments
ASU 2011-05 —In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220) Presentation of Comprehensive Income , or ASU No. 2011-05, which was further amended by ASU No. 2011-12, Comprehensive Income (Topic 220) Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05,  issued in December 2011. The amendments in ASU No. 2011-05 require the Company to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single statement of comprehensive income or in two separate but consecutive statements. The Company is required to present, in either option, each component of net income, total net income, each component of other comprehensive income, total other comprehensive income and total comprehensive income. Effective January 1, 2012, the Company adopted the provisions of ASU No. 2011-05 and began presenting the total of comprehensive income, the components of net income and the components of other comprehensive income in two separate but consecutive statements. The provisions of ASU No. 2011-05 are required to be adopted retroactively. As this guidance provides only presentation requirements, the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.
ASU 2013-02 — In February 2013, the FASB issued ASU No. 2013-02, Other Comprehensive Income (Topic 220) Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income , or ASU No. 2013-02. The amendments in ASU No. 2013-02 require the Company to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income, either on the face of the income statement or in the notes, if the amount being reclassified is required under U.S. GAAP to be reclassified in its entirety to net income in the same reporting period. For other amounts not required by U.S. GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures which provide additional information about the amounts. The guidance is effective prospectively for reporting periods beginning after December 15, 2012. As this guidance provides only presentation requirements, the adoption of this standard will not impact the Company's results of operations, cash flows or financial position.
Other —The following accounting standard was issued in 2011 and was adopted on January 1, 2013 with no impact on the Company's results of operations, financial position or cash flows:
 	 	
•	ASU No. 2011-11, Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities	
Note 3 — Business Acquisitions and Dispositions 
GenOn Acquisition
On December 14, 2012, NRG completed the acquisition of GenOn Energy, Inc., or GenOn.  GenOn, a generator of wholesale electricity, has baseload, intermediate and peaking power generation facilities using coal, natural gas and oil, totaling approximately 21,440 MW.  The Company issued, as consideration for the acquisition, 0.1216 shares of NRG common stock for each outstanding share of GenOn, including restricted stock units outstanding, on the acquisition date, except for fractional shares which were paid in cash.  The Company issued 93.9 million shares of NRG common stock, or 29% of total common shares outstanding following the closing of the transaction. The acquisition is expected to enable the combined company to capitalize on the strategic advantages and opportunities resulting from diversification and scale as well as cost and operational efficiency synergies.
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. Any changes to the fair value assessments will affect the gain on bargain purchase. 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 $2.2 billion was provisionally allocated as follows:

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 	(In millions)	
Assets	 	
Cash	$	983	
 	
Current and non-current assets	1,385	
 	
Property, plant and equipment	3,936	
 	
Derivative assets	1,157	
 	
Deferred income taxes	2,265	
 	
Total assets acquired	$	9,726	

Liabilities	 	
Current and non-current liabilities	$	1,312	
 	
Out-of-market contracts and leases	1,064	
 	
Derivative liabilities	399	
 	
Long-term debt and capital leases	4,203	
 	
Total liabilities assumed	6,978	
 	
Net assets acquired	2,748	
 	
Consideration paid	2,188	
 	
Gain on bargain purchase	$	560	
 	
The gain on bargain purchase is primarily representative of the undiscounted value of the deferred tax assets generated by the reduction in book basis of the net assets recorded in connection with acquisition accounting as well as the undiscounted value of GenOn’s net operating losses and other deferred tax benefits that the combined company has the ability to realize in the post-acquisition period.
The Company incurred acquisition-related transaction and integration cost of $107 million, including $49 million of personnel related costs, of which $42 million is accrued for as of December 31, 2012.
Current and non-current assets include accounts receivable with a preliminary fair value of $221 million and gross contractual amounts of $222 million at the time of the acquisition.
Fair value measurements
The provisional fair values of the property, plant and equipment, commodity, transportation and storage contracts and leases at the acquisition date was 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 based on consideration of both an income method using discounted cash flows and a market approach based on recent transactions of comparable assets. The income approach was primarily relied upon as the forecasted cash flows as it more appropriately incorporates differences in regional markets, plant type, age, useful life, equipment condition and environmental controls of each asset. Furthermore, the income approach allows for a more accurate reflection of current and expected market dynamics such as supply and demand, commodity prices, and regulatory environment as of the valuation date. Under this approach, the expected future cash flows associated with each plant were estimated and then discounted to present value at the weighted average cost of capital derived from an independent power producer peer group and risk adjusted to reflect the individual characteristics of each plant. The market approach was computed based on data for transactions announced proximate to the valuation date and analyzed on a $/kW basis for fuel/dispatch type and region. Due to the limited volume of recent transactions and amount of financial and operating characteristics that are publicly disclosed, that market approach was given less weight.
•Contracts — The estimated fair values of acquired contracts were determined based on a form of the income approach which measures the contract relative to a replacement contract or the current market with consideration of the counterparty risk. Acquired contracts such as gas transportation contracts were determined to have an unfavorable fair value compared to the original contract terms and were recorded in out-of-market commodity contracts.
•Operating leases — The estimated fair values of the acquired leases for REMA and Mid-Atlantic were determined utilizing a variation of the income approach under which the fair value of the lease was determined by discounting the future lease payments at an appropriate discount rate and comparing it to the fair value of the property, plant and equipment being leased.

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The fair values of derivative assets and liabilities and long-term debt and capital leases as of the acquisition date were determined in accordance with ASC 820, as discussed in Note 4,  Fair Value of Financial Instruments . The breakdown of Level 1, 2, and 3 is as follows:

 	 	Fair Value	
 	 	Level 1	 	Level 2	 	Level 3	 	Total	
 	 	(in millions)	
Assets	 	 	 	 	 	 	 	 	
Derivative assets	 	$	146	
 	 	$	978	
 	 	$	33	
 	 	$	1,157	
 	
Liabilities	 	 	 	 	 	 	 	 	
Derivative liabilities	 	50	
 	 	334	
 	 	15	
 	 	399	
 	
Long-term debt and capital leases	 	3,799	
 	 	—	
 	 	404	
 	 	4,203	
 	
Deferred income taxes
In connection with the accounting for the GenOn acquisition, the Company recorded the realizable deferred tax assets and liabilities acquired, primarily consisting of net operating losses and other temporary differences. In addition, the excess of GenOn's historical tax basis of assets and liabilities over the amount assigned to the fair value of the assets acquired and liabilities assumed generated deferred tax assets and liabilities that were recorded on the acquisition date.
Supplemental Pro-Forma Information
Since the acquisition date, GenOn contributed $73 million in operating revenues and $72 million in net losses attributable to NRG. The following supplemental pro-forma information represents the results of operations as if NRG and GenOn had combined on January 1, 2011:

 	For the Year Ended December 31,	
 	2012	 	2011	
 	(In millions, except per share amounts)	
Operating revenues	$	10,986	
 	 	$	12,693	
 	
Net income attributable to NRG Energy, Inc.	48	
 	 	201	
 	
Income per share attributable to NRG common stockholders:	

Basic	$	0.12	
 	 	$	0.57	
 	
Diluted	$	0.12	
 	 	$	0.57	
 	
The supplemental pro-forma information has been adjusted to include the pro-forma impact of depreciation of property, plant and equipment, amortization of lease obligations and out-of-market contracts and amortization of debt discounts, based on the preliminary purchase price allocations. The pro-forma data has also been adjusted to eliminate the bargain purchase gain recorded and non-recurring transaction costs incurred by NRG, as well as the related tax impact. Transactions between NRG and GenOn have not been eliminated. 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. Certain cost savings may result from the acquisition; however, there can be no assurance that these cost savings will be achieved.
2012 Dispositions
Agua Caliente—On January 18, 2012, the Company completed the sale of a 49% interest in NRG Solar AC Holdings LLC, the indirect owner of the Agua Caliente project, to MidAmerican Energy Holdings Company, or MidAmerican. A majority of the $122 million of cash consideration received at closing represented 49% of construction costs funded by NRG's equity contributions. The excess of the consideration over the carrying value of the divested interest was recorded to additional paid-in capital. MidAmerican will fund its proportionate share of future equity contributions and other credit support for the project. NRG continues to hold a majority interest in and consolidate the project.

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Saale Energie GmbH — On July 17, 2012, the Company completed the sale of its 100% interest in Saale Energie GmbH, or SEG, which holds a 41.9% interest in Kraftwerke Schkopau GbR and a 44.4% interest in Kraftwerke Schkopau Betriebsgesllschaft mbH, collectively, Schkopau. Schkopau holds a fixed 400 MW participation in the 900 MW Schkopau Power Station located in Germany. In connection with the sale of Schkopau, NRG entered into a foreign currency swap contract to hedge the impact of exchange rate fluctuations on the sale proceeds of €141 million. The Company received cash consideration, net of selling expenses, of $174 million, which included $4 million related to the settlement of the swap contract that was recorded as a gain within Other income, net in the quarter ended September 30, 2012. The cash consideration approximated the book value of the net assets, including cash of $38 million, on the date of the sale.
2011 Acquisitions
Energy Plus— On September 30, 2011, NRG acquired Energy Plus for $194 million in cash, net of $5 million cash acquired, funded from cash on hand. Energy Plus is a retail electricity provider with 188,000 customers as of December 31, 2011, concentrated in the Northeast markets, and a unique sales channel involving exclusive loyalty and affinity program partnerships. 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 customer relationships of $63 million, marketing partnerships of $88 million, trade names of $10 million and goodwill of $29 million. The factors that resulted in goodwill arising from the acquisition include the revenues associated with expanding the Energy Plus retail business and its unique sales channel in new regions, expanding its loyalty and affinity program partnerships and the synergies associated with combining the business with NRG's generation assets. The accounting for the Energy Plus acquisition was completed as of March 31, 2012, at which point the provisional fair values became final with no material changes.
Solar Acquisitions—During the year ended December 31, 2011, NRG acquired stakes in three Utility Scale Solar facilities for approximately $165 million in cash consideration, as part of the Company's initiative to capture opportunities for future growth in renewables. During 2011, subsequent to the acquisition dates, and 2012, NRG made capital contributions into these projects of $420 million and $262 million, respectively. In addition, NRG has a commitment to contribute additional amounts into the projects, comprised of $133 million in restricted cash and $321 million in letters of credit as of December 31, 2012. The Company may increase its letters of credit to replace the restricted cash at its discretion. NRG's minority partners had contributed approximately $29 million and $316 million of equity during 2011, subsequent to the acquisition date, and 2012, respectively, and had additional equity commitments of $37 million as of December 31, 2012. These acquisitions were recorded as business combinations under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date.
The acquisitions of these three solar facilities are further described below:
California Valley Solar Ranch— On September 30, 2011, NRG Solar LLC, a wholly-owned subsidiary of NRG, acquired 100% of the 250 MW California Valley Solar Ranch project, or CVSR, in eastern San Luis Obispo County, California. During the second quarter of 2012, the Company met the conditions necessary to permit loan disbursements under the CVSR Financing Agreement, as discussed in Note 11,  Debt and Capital Leases . Operations commenced on the first 22 MW phase in September and 105 MWs for Phases 2 and 4 in December 2012, with the final phase expected during the fourth quarter of 2013. Power generated from CVSR is sold to PG&E under a 25 year PPA.
Agua Caliente— On August 5, 2011, NRG, through its wholly-owned subsidiary, NRG Solar PV LLC, acquired 100% of the 290 MW Agua Caliente solar project in Yuma, AZ. On January 18, 2012, the Company completed the sale of a 49% interest to MidAmerican Energy Holdings Company as discussed above. Operations are scheduled to commence in phases through the first quarter of 2014, with 253 MW achieving commercial operations from January through December 2012. Power generated from Agua Caliente is sold to PG&E under a 25 year PPA. While full commercial operations of the entire project will be achieved in early 2014, the maximum capacity deliverable under the PPA of 290 MWs is expected to be on-line by the third quarter of 2013.
Ivanpah— On April 5, 2011, NRG acquired a 50.1% stake in the 392 MW Ivanpah Solar Electric Generation System, or Ivanpah, from BrightSource Energy, Inc., or BSE. BSE maintained a 21.8% interest in Ivanpah and the remaining 28.1% was acquired by a wholly-owned subsidiary of Google. Ivanpah is composed of three separate facilities - Ivanpah 1 (126 MW), Ivanpah 2 (133 MW), and Ivanpah 3 (133 MW), all of which are expected to be fully operational by the end of 2013. The first unit of the Ivanpah project is expected to be completed and producing power in July of 2013. The second and third units are expected to be completed in the third and fourth quarters of 2013. Power generated from Ivanpah will be sold to Southern California Edison and Pacific Gas and Electric, under multiple 20 to 25 year PPAs.
The purchase price for these acquisitions, considered business combinations, was primarily allocated to $767 million of property, plant and equipment, $489 million of accrued expenses, $60 million of other assets, including restricted cash, and $19 million of other liabilities. The accounting for these acquisitions was completed as of March 31, 2012, at which point the provisional fair values became final with no material changes.

130

2010 Acquisitions
The Company made several acquisitions in 2010, which were recorded as business combinations under ASC 805, which are briefly summarized below. See Note 3,  Business Acquisitions and Dispositions,  and Note 12,  Debt and Capital Leases , in the Company's 2010 Form 10-K for additional information related to these acquisitions.
Green Mountain Energy — On November 5, 2010, NRG acquired Green Mountain Energy for $357 million in cash, net of $75 million cash acquired, funded from cash on hand. 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 customer relationships of $158 million, trade names of $130 million, favorable commercial customer contracts of $54 million, net deferred tax liabilities of $78 million, net derivative liabilities of $60 million, and goodwill of $155 million. The factors that resulted in goodwill arising from the acquisition include the revenues associated with expanding the Green Mountain Energy business of providing renewable energy products and services to new customers in new regions and through new providers and the synergies associated with combining a renewable retail business with NRG's renewable generation assets. The accounting for the Green Mountain Energy acquisition was completed as of September 30, 2011, at which point the provisional fair values became final with no material changes.
Cottonwood — On November 15, 2010, NRG acquired the Cottonwood Generating Station, or Cottonwood, a 1,265 MW combined cycle natural gas plant in the Entergy zone of east Texas for $507 million in cash, funded from cash on hand. The acquisition was recorded as a business combination under ASC 805 and the purchase price was allocated to the assets acquired and liabilities assumed, which were recorded at provisional fair value on the acquisition date. The purchase price was primarily allocated to fixed assets. The accounting for the Cottonwood acquisition was completed as of March 31, 2011, at which point the provisional fair values became final with no material changes.
2010 Disposition
Padoma— On January 11, 2010, NRG sold its terrestrial wind development company, Padoma Wind Power LLC, or Padoma to Enel North America, Inc.  NRG recognized a gain on the sale of Padoma of $23 million, which was recorded as a component of operating income in the statement of operations during the year ended December 31, 2010.
Note 4 — Fair Value of Financial Instruments 
For cash and cash equivalents, funds deposited by counterparties, accounts receivable, accounts payable, accrued liabilities, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.
The estimated carrying values and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:

 	As of December 31,	
 	2012	 	2011	
 	Carrying Amount	 	Fair Value	 	Carrying Amount	 	Fair Value	
 	(In millions)	
Assets	 	 	 	 	 	 	 	
Notes receivable	$	88	
 	 	$	88	
 	 	$	156	
 	 	$	161	
 	
Liabilities	 	 	 	 	 	 	 	
Long-term debt, including current portion	15,866	
 	 	16,492	
 	 	9,729	
 	 	9,716	
 	
The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level 1 within the fair value hierarchy. The fair value of debt securities, non publicly-traded long-term debt, and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates, or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy.

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Fair Value Accounting under ASC 820
ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
 	 	
•	Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG's financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments.	
 	 	
•	Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG's financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over the counter derivatives such as swaps, options and forward contracts.	
 	 	
•	Level 3 — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date. NRG's financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models.	
In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety.
Recurring Fair Value Measurements
Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value.
The following tables present assets and liabilities measured and recorded at fair value on the Company's consolidated balance sheet on a recurring basis and their level within the fair value hierarchy:

 	As of December 31, 2012	
 	Fair Value	
 	Level 1	 	Level 2	 	Level 3	 	Total	
 	(In millions)	
Investment in available-for-sale securities (classified within other non-current assets):	 	 	 	 	 	 	 	
Debt securities	$	—	
 	 	$	—	
 	 	$	12	
 	 	$	12	
 	
Other (a)	22	
 	 	—	
 	 	—	
 	 	22	
 	
Trust fund investments:	 	 	 	 	 	 	 	
Cash and cash equivalents	10	
 	 	—	
 	 	—	
 	 	10	
 	
U.S. government and federal agency obligations	34	
 	 	—	
 	 	—	
 	 	34	
 	
Federal agency mortgage-backed securities	—	
 	 	59	
 	 	—	
 	 	59	
 	
Commercial mortgage-backed securities	—	
 	 	9	
 	 	—	
 	 	9	
 	
Corporate debt securities	—	
 	 	80	
 	 	—	
 	 	80	
 	
Equity securities	233	
 	 	—	
 	 	47	
 	 	280	
 	
Foreign government fixed income securities	—	
 	 	2	
 	 	—	
 	 	2	
 	
Derivative assets:	 	 	 	 	 	 	 	
Commodity contracts	1,457	
 	 	1,711	
 	 	135	
 	 	3,303	
 	
Interest rate contracts	—	
 	 	3	
 	 	—	
 	 	3	
 	
Total assets	$	1,756	
 	 	$	1,864	
 	 	$	194	
 	 	$	3,814	
 	
Derivative liabilities:	 	 	 	 	 	 	 	
Commodity contracts	$	1,144	
 	 	$	1,047	
 	 	$	147	
 	 	$	2,338	
 	
Interest rate contracts	—	
 	 	143	
 	 	—	
 	 	143	
 	
Total liabilities	$	1,144	
 	 	$	1,190	
 	 	$	147	
 	 	$	2,481	

(a)	Consists primarily of mutual funds held in a Rabbi Trust for non-qualified deferred compensation plans for some key and highly compensated employees.	

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 	As of December 31, 2011	
 	Fair Value	
 	Level 1	 	Level 2	 	Level 3	 	Total	
 	(In millions)	
Investment in available-for-sale securities (classified within other non-current assets):	 	 	 	 	 	 	
 	
Debt securities	$	—	
 	 	$	—	
 	 	$	7	
 	 	$	7	
 	
Marketable equity securities	1	
 	 	—	
 	 	—	
 	 	1	
 	
Trust fund investments:	

 	

 	 	

Cash and cash equivalents	2	
 	 	—	
 	 	—	
 	 	2	
 	
 U.S. government and federal agency obligations	44	
 	 	—	
 	 	—	
 	 	44	
 	
Federal agency mortgage-backed securities	—	
 	 	63	
 	 	—	
 	 	63	
 	
Commercial mortgage-backed securities	—	
 	 	7	
 	 	—	
 	 	7	
 	
 Corporate debt securities	—	
 	 	54	
 	 	—	
 	 	54	
 	
Equity securities	209	
 	 	—	
 	 	42	
 	 	251	
 	
Foreign government fixed income securities	—	
 	 	4	
 	 	—	
 	 	4	
 	
Derivative assets:	 	 	 	 	 	 	 	
Commodity contracts	2,868	
 	 	1,937	
 	 	75	
 	 	4,880	
 	
Interest rate contracts	—	
 	 	30	
 	 	—	
 	 	30	
 	
Total assets	$	3,124	
 	 	$	2,095	
 	 	$	124	
 	 	$	5,343	
 	
Derivative liabilities:	

 	

 	
Commodity contracts	$	3,033	
 	 	$	1,292	
 	 	$	67	
 	 	$	4,392	
 	
Interest rate contracts	—	
 	 	96	
 	 	—	
 	 	96	
 	
Total liabilities	$	3,033	
 	 	$	1,388	
 	 	$	67	
 	 	$	4,488	
 	
There have been no transfers during the year ended December 31, 2012, between Levels 1 and 2. The following tables reconcile, for the years ended December 31, 2012, and 2011, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:

 	For the Year Ended December 31, 2012	
 	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)	
 	Debt
Securities	 	Trust Fund
Investments	 	Derivatives (a)	 	Total	
 	(In millions)	
Beginning balance as of January 1, 2012	$	7	
 	 	$	42	
 	 	$	8	
 	 	$	57	
 	
Total gains and losses (realized/unrealized):	 	 	 	 	 	 	 	
Included in OCI	5	
 	 	—	
 	 	—	
 	 	5	
 	
Included in earnings	—	
 	 	—	
 	 	(13	)	 	(13	)	
Included in nuclear decommissioning obligations	—	
 	 	5	
 	 	—	
 	 	5	
 	
Purchases	—	
 	 	—	
 	 	8	
 	 	8	
 	
Contracts acquired in GenOn acquisition	—	
 	 	—	
 	 	18	
 	 	18	
 	
Transfers into Level 3 (b)	—	
 	 	—	
 	 	(33	)	 	(33	)	
Transfers out of Level 3 (b)	—	
 	 	—	
 	 	—	
 	 	—	
 	
Ending balance as of December 31, 2012	$	12	
 	 	$	47	
 	 	$	(12	)	 	$	47	
 	
The amount of the total losses for the period included in earnings attributable to the change in unrealized derivatives relating to assets still held as of December 31, 2012	$	—	
 	 	$	—	
 	 	$	(3	)	 	$	(3	)	
 	 	
(a)	Consists of derivatives assets and liabilities, net.	
 	 	
(b)	Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2.	

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 	For the Year Ended December 31, 2011	
 	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)	
 	Debt
Securities	 	Trust Fund
Investments	 	Derivatives (a)	 	Total	
 	(In millions)	
Beginning balance as of January 1, 2011	$	8	
 	 	$	39	
 	 	$	(27	)	 	$	20	
 	
Total gains and losses (realized/unrealized):	

 	 	 	
Included in OCI	(1	)	 	—	
 	 	—	
 	 	(1	)	
Included in earnings	—	
 	 	—	
 	 	28	
 	 	28	
 	
Included in nuclear decommissioning obligations	—	
 	 	(6	)	 	—	
 	 	(6	)	
Purchases	—	
 	 	9	
 	 	4	
 	 	13	
 	
Transfers into Level 3 (b)	—	
 	 	—	
 	 	(3	)	 	(3	)	
 Transfer out of Level 3 (b)	—	
 	 	—	
 	 	6	
 	 	6	
 	
Ending balance as of December 31, 2011	$	7	
 	 	$	42	
 	 	$	8	
 	 	$	57	
 	
The amount of the total gains for the period included in earnings attributable to the change in unrealized derivatives relating to assets still held as of December 31, 2011
	$	—	
 	 	$	—	
 	 	$	3	
 	 	$	3	

(a)	Consists of derivatives assets and liabilities, net.	
 	 	
(b)	Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2.	
Realized and unrealized gains and losses included in earnings that are related to the energy derivatives are recorded in operating revenues and cost of operations.
Non-derivative fair value measurements
NRG's investments in debt securities are classified as Level 3 and consist of non-traded debt instruments that are valued based on third-party market value assessments.
The trust fund investments are held primarily to satisfy NRG's nuclear decommissioning obligations. These trust fund investments hold debt and equity securities directly and equity securities indirectly through commingled funds. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. In addition, U.S. government and federal agency obligations are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of corporate debt securities are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized in Level 2. Certain equity securities, classified as commingled funds, are analogous to mutual funds, are maintained by investment companies, and hold certain investments in accordance with a stated set of fund objectives. The fair value of the equity securities classified as commingled funds are based on net asset values per fund share (the unit of account), derived from the quoted prices in active markets of the underlying equity securities. However, because the shares in the commingled funds are not publicly quoted, not traded in an active market and are subject to certain restrictions regarding their purchase and sale, the commingled funds are categorized in Level 3. See also Note 6,  Nuclear Decommissioning Trust Fund.

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Derivative fair value measurements
A majority of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A portion of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company's prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote, then the mid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of the Company's derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate those transactions and the Company believes such price quotes are executable. The Company does not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities represents contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up 4% of derivative assets and 6% of derivative liabilities. The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk which is calculated based on published default probabilities. To the extent that NRG's net exposure under a specific master agreement is an asset, the Company uses the counterparty's default swap rate. If the exposure under a specific master agreement is a liability, the Company uses NRG's default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG's liabilities or that a market participant would be willing to pay for NRG's assets. As of December 31, 2012, the credit reserve resulted in a $6 million increase in fair value which is composed of a $3 million gain in operating revenue and cost of operations and a $3 million increase in OCI.
The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2012, and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.
Under the guidance of ASC 815, entities may choose to offset cash collateral paid or received against the fair value of derivative positions executed with the same counterparties under the same master netting agreements. The Company has chosen not to offset positions as defined in ASC 815. As of December 31, 2012, the Company recorded $229 million of cash collateral paid and $271 million of cash collateral received on its balance sheet.
Concentration of Credit Risk
In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, the following item is a discussion of the concentration of credit risk for the Company's financial instruments. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle.

135

As of December 31, 2012, aggregate counterparty credit exposure to a significant portion of the Company's counterparties totaled $1.3 billion, of which the Company held collateral (cash and letters of credit) against those positions of $74 million, resulting in a net exposure of $1.2 billion. Approximately 91% of the Company's exposure before collateral is expected to roll off by the end of 2014. The following table highlights the Company's portfolio credit quality and the aggregate net counterparty credit exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net asset position with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. As of December 31, 2012, the aggregate credit exposure is shown net of collateral held, and includes amounts net of receivables or payables.

Category	Net Exposure (a)
(% of Total)	
Financial institutions	63	%	
Utilities, energy merchants, marketers and other	29	
 	
Coal and emissions	1	
 	
ISOs	7	
 	
Total	100	%	

 	 	 	
Category	Net Exposure (a)
(% of Total)	
Investment grade	95	%	
Non-rated (b)	1	
 	
Non-Investment grade	4	
 	
Total	100	%	
 	 	
(a)	Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.	
 	 	
(b)	For non-rated counterparties, the majority of the exposure is related to ISO and municipal public power entities, which are considered investment grade equivalent ratings based on NRG's internal credit ratings.	
The Company has credit risk exposure to certain counterparties representing more than 10% of total net exposure discussed above and the aggregate credit exposure to counterparties was $565 million. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, the Company does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any counterparty.
Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations, solar PPAs, and a coal supply agreement. As external sources or observable market quotes are not available to estimate such exposure, the Company valued 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, 2012, credit exposure to these counterparties is approximately $1.1 billion for the next five years. This amount excludes potential credit exposures for projects with long term PPAs that have not reached commercial operations. Many of these power contracts are with utilities or public power entities that have strong credit quality and specific public utility commission or other regulatory support. In the case of the coal supply agreement, NRG holds a lien against the underlying asset. These factors significantly reduce the risk of loss.
Retail Customer Credit Risk
NRG is exposed to retail credit risk through the Company's retail electricity providers, which serve C&I customers and the Mass market. Retail credit risk results when a customer fails to pay for services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.
As of December 31, 2012, the Company's retail customer credit exposure to C&I customers was diversified across many customers and various industries, with a significant portion of the exposure with government entities.
NRG is also exposed to retail customer credit risk relating to its Mass customers, which may result in a write-off of bad debt. During 2012, the Company continued to experience improved customer payment behavior, but current economic conditions may affect the Company's customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense.

136

Note 5 — Accounting for Derivative Instruments and Hedging Activities 
ASC 815 requires NRG to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a NPNS exception. NRG may elect to designate certain derivatives as cash flow hedges, if certain conditions are met, and defer the effective portion of the change in fair value of the derivatives to accumulated OCI, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings.
For derivatives designated as hedges of the fair value of assets or liabilities, the changes in fair value of both the derivative and the hedged transaction are recorded in current earnings.
For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 applies to NRG's energy related commodity contracts, interest rate swaps, and foreign exchange contracts.
As the Company engages principally in the trading and marketing of its generation assets and Retail Business, some of NRG's commercial activities qualify for hedge accounting. In order for the generation assets to qualify, the physical generation and sale of electricity should be highly probable at inception of the trade and throughout the period it is held, as is the case with the Company's baseload plants. For this reason, many trades in support of NRG's baseload units normally qualify for NPNS or cash flow hedge accounting treatment, and trades in support of NRG's peaking unit's asset optimization will generally not qualify for hedge accounting treatment, with any changes in fair value likely to be reflected on a mark-to-market basis in the statement of operations. Most of the retail load contracts either qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority of the retail supply and fuels supply contracts are recorded under mark-to-market accounting. All of NRG's hedging and trading activities are subject to limits within the Company's Risk Management Policy.
Energy-Related Commodities
To manage the commodity price risk associated with the Company's competitive supply activities and the price risk associated with wholesale power sales from the Company's electric generation facilities and retail power sales from the Retail Business, NRG enters into a variety of derivative and non-derivative hedging instruments, utilizing the following:
 	 	
•	Forward contracts, which commit NRG to purchase or sell energy commodities or purchase fuels in the future.	
 	 	
•	Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument.	
 	 	
•	Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual, or notional, quantity.	
 	 	
•	Option contracts, which convey to the option holder the right but not the obligation to purchase or sell a commodity.	
 	 	
•	Extendable swaps, which include a combination of swaps and options executed simultaneously for different periods. This combination of instruments allows NRG to sell out-year volatility through call options in exchange for natural gas swaps with fixed prices in excess of the market price for natural gas at that time. The above-market swap combined with its later-year call option are priced in aggregate at market at the trade's inception.	
 	 	
•	Weather and hurricane derivative products used to mitigate a portion of Reliant Energy's lost revenue due to weather.	
The objectives for entering into derivative contracts designated as hedges include:
 	 	
•	Fixing the price for a portion of anticipated future electricity sales that provides an acceptable return on the Company's electric generation operations.	
 	 	
•	Fixing the price of a portion of anticipated fuel purchases for the operation of NRG's power plants.	
 	 	
•	Fixing the price of a portion of anticipated power purchases for the Company's retail sales.	
NRG's trading and hedging activities are subject to limits within the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

137

As of December 31, 2012, NRG's derivative assets and liabilities consisted primarily of the following:
 	 	
•	Forward and financial contracts for the purchase/sale of electricity and related products economically hedging NRG's generation assets' forecasted output or NRG's retail load obligations through 2018.	
 	 	
•	Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG's generation assets through 2017.	
 	 	
•	As of December 31, 2012, NRG had cash flow hedge energy-related derivative financial instruments extending through December 2015.	
Also, as of December 31, 2012, NRG had other energy-related contracts that did not meet the definition of a derivative instrument or qualified for the NPNS exception and were therefore exempt from fair value accounting treatment as follows:
 	 	
•	Load-following forward electric sale contracts extending through 2026;	
 	 	
•	Power Tolling contracts through 2039;	
 	 	
•	Coal purchase contract through 2020;	
 	 	
•	Power transmission contracts through 2015;	
 	 	
•	Natural gas transportation contracts and storage agreements through 2023; and	
 	 	
•	Coal transportation contracts through 2017.	
Interest Rate Swaps
NRG is exposed to changes in interest rates through the Company's issuance of variable and fixed rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of December 31, 2012, NRG had interest rate derivative instruments on recourse debt extending through 2013 and on non-recourse debt extending through 2030, the majority of which are designated as cash flow hedges.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of December 31, 2012, and December 31, 2011. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.

 	 	Total Volume	
Commodity	Units	December 31, 2012	 	December 31, 2011	
 	 	(In millions)	
Emissions	Short Ton	(1	)	 	(2	)	
Coal	Short Ton	37	
 	 	37	
 	
Natural Gas	MMBtu	(413	)	 	13	
 	
Oil	Barrel	1	
 	 	1	
 	
Power	MWh	(14	)	 	4	
 	
Interest	Dollars	$	2,612	
 	 	$	2,121	

138

Fair Value of Derivative Instruments
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. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. The Company has chosen not to offset positions as permitted in ASC 815. As of December 31, 2012, the Company recorded $229 million of cash collateral paid and $271 million of cash collateral received on its balance sheet.
The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:

 	Fair Value	
 	Derivative Assets	 	Derivative Liabilities	
(In millions)	December 31, 2012	 	December 31, 2011	 	December 31, 2012	 	December 31, 2011	
Derivatives Designated as Cash Flow or Fair Value Hedges :	 	 	 	 	 	 	 	
Interest rate contracts current	$	—	
 	 	$	—	
 	 	$	29	
 	 	$	39	
 	
Interest rate contracts long-term	3	
 	 	30	
 	 	96	
 	 	56	
 	
Commodity contracts current	—	
 	 	318	
 	 	3	
 	 	—	
 	
Commodity contracts long-term	—	
 	 	—	
 	 	1	
 	 	1	
 	
Total Derivatives Designated as Cash Flow or Fair Value Hedges	3	
 	 	348	
 	 	129	
 	 	96	
 	
Derivatives Not Designated as Cash Flow or Fair Value Hedges :	 	 	 	 	 	 	 	
Interest rate contracts current	—	
 	 	—	
 	 	7	
 	 	—	
 	
Interest rate contracts long-term	—	
 	 	—	
 	 	11	
 	 	1	
 	
Commodity contracts current	2,644	
 	 	4,109	
 	 	1,942	
 	 	3,990	
 	
Commodity contracts long-term	659	
 	 	453	
 	 	392	
 	 	401	
 	
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	3,303	
 	 	4,562	
 	 	2,352	
 	 	4,392	
 	
Total Derivatives	$	3,306	
 	 	$	4,910	
 	 	$	2,481	
 	 	$	4,488	
 	
Accumulated Other Comprehensive Income
The following tables summarize the effects on NRG's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:

 	Year Ended December 31, 2012	
 	Energy
Commodities	 	Interest
Rate	 	Total	
 	(In millions)	
Accumulated OCI balance at December 31, 2011	$	188	
 	 	$	(56	)	 	$	132	
 	
Reclassified from accumulated OCI to income:	 	 	 	 	 	
- Due to realization of previously deferred amounts	(144	)	 	23	
 	 	(121	)	
Mark-to-market of cash flow hedge accounting contracts	(3	)	 	(39	)	 	(42	)	
Accumulated OCI balance at December 31, 2012, net of $7 tax	$	41	
 	 	$	(72	)	 	$	(31	)	
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $19 tax	$	51	
 	 	$	(20	)	 	$	31	
 	
Losses recognized in income from the ineffective portion of cash flow hedges	$	(51	)	 	$	—	
 	 	$	(51	)	

139

 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Year Ended December 31, 2011	
 	Energy
Commodities	 	Interest
Rate	 	Total	
 	(In millions)	
Accumulated OCI balance at December 31, 2010	$	488	
 	 	$	(47	)	 	$	441	
 	
Reclassified from accumulated OCI to income:	 	 	 	 	 	
- Due to realization of previously deferred amounts	(374	)	 	12	
 	 	(362	)	
Mark-to-market of cash flow hedge accounting contracts	74	
 	 	(21	)	 	53	
 	
Accumulated OCI balance at December 31, 2011, net of $87 tax	$	188	
 	 	$	(56	)	 	$	132	
 	
Gains recognized in income from the ineffective portion of cash flow hedges	$	28	
 	 	$	3	
 	 	$	31	

 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Year Ended December 31, 2010	
 	Energy
Commodities	 	Interest
Rate	 	Total	
 	(In millions)	
Accumulated OCI balance at December 31, 2009	$	461	
 	 	$	(55	)	 	$	406	
 	
Reclassified from accumulated OCI to income:	 	 	 	 	
 	
- Due to realization of previously deferred amounts	(474	)	 	1	
 	 	(473	)	
Mark-to-market of cash flow hedge accounting contracts	501	
 	 	7	
 	 	508	
 	
Accumulated OCI balance at December 31, 2010, net of $268 tax	$	488	
 	 	$	(47	)	 	$	441	
 	
Gains recognized in income from the ineffective portion of cash flow hedges	$	—	
 	 	$	1	
 	 	$	1	
 	
Amounts reclassified from accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to operating revenue for commodity contracts and interest expense for interest rate contracts.
Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of April 30, 2012, the Company's regression analysis for natural gas prices to ERCOT power prices, while positively correlated, did not meet the required threshold for cash flow hedge accounting for calendar year 2012. As a result, the Company de-designated its 2012 ERCOT cash flow hedges as of April 30, 2012, and prospectively marked these derivatives to market through the income statement.
The following table summarizes the amount of unrealized gain/(loss) resulting from fair value hedges reflected in interest income/(expense) for interest rate contracts:

 	Year Ended December 31,	
(In millions)	2012	 	2011	 	2010	
Derivative	$	—	
 	 	$	—	
 	 	$	(8	)	
Senior Notes (hedged item)	—	
 	 	—	
 	 	11	

140

Impact of Derivative Instruments on the Statement of Operations
Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges and ineffectiveness of hedge derivatives are reflected in current period earnings.
The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges, and trading activity on NRG's statement of operations. The effect of commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges in included in interest expense.

 	Year Ended December 31,	
 	2012	 	2011	 	2010	
 	(In millions)	
Unrealized mark-to-market results	 	 	 	 	 	
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(247	)	 	$	54	
 	 	$	(171	)	
Reversal of loss positions acquired as part of the Reliant Energy, Green Mountain Energy and GenOn acquisitions	20	
 	 	107	
 	 	236	
 	
Net unrealized gains/(losses) on open positions related to economic hedges	10	
 	 	(33	)	 	(153	)	
(Losses)/gains on ineffectiveness associated with open positions treated as cash flow hedges	(51	)	 	28	
 	 	—	
 	
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(268	)	 	156	
 	 	(88	)	
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(60	)	 	21	
 	 	68	
 	
Net unrealized gains/(losses) on open positions related to trading activity	46	
 	 	42	
 	 	(5	)	
Total unrealized mark-to-market (losses)/gains for trading activity	(14	)	 	63	
 	 	63	
 	
Total unrealized (losses)/gains	$	(282	)	 	$	219	
 	 	$	(25	)	

 	 	 	 	 	 	 	 	 	 	 	 	
 	Year Ended December 31,	
 	2012	 	2011	 	2010	
 	(In millions)	
Revenue from operations — energy commodities	$	(464	)	 	$	388	
 	 	$	(136	)	
Cost of operations	182	
 	 	(169	)	 	111	
 	
Total impact to statement of operations - energy commodities	$	(282	)	 	$	219	
 	 	$	(25	)	
Total impact to statement of operations - interest rate contracts	$	(8	)	 	$	2	
 	 	$	4	
 	
Reliant Energy's loss positions were acquired as of May 1, 2009, and valued using forward prices on that date. Green Mountain Energy's loss positions were acquired as of November 5, 2010, and valued using forward prices on that date. GenOn's gain positions were acquired as of December 14, 2012 and valued using forward prices on that date. The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in revenue or cost of operations during the same period.
For the year ended December 31, 2012, the $10 million gain from economic hedge positions was the result of an increase in value of forward purchases and sales of natural gas and electricity due to a decrease in forward power and gas prices offset by a decrease in value of forward purchases of coal due to a decrease in forward coal prices.
As of June 30, 2012 NRG had interest rate swaps designated as cash flow hedges on the Alpine solar project. The notional amount of the swaps exceeded the actual debt draws on the project. As such, NRG discontinued cash flow hedge accounting for these contracts and $4 million of loss previously deferred in OCI was recognized in earnings for the year ended December 31, 2012.
For the year ended December 31, 2011, the $33 million loss from economic hedge positions was the result of a decrease in value of forward purchases and sales of natural gas, electricity and fuel due to decrease in forward power and gas prices.

141

Credit Risk Related Contingent Features
Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed "adequate assurance" under the agreements, or require the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts that have adequate assurance clauses that are in net liability positions as of December 31, 2012, was $78 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of December 31, 2012, was $42 million. The Company is also a party to certain marginable agreements under which it has a net liability position, but the counterparty has not called for the collateral due, of approximately $28 million as of December 31, 2012.
See Note 4, Fair Value of Financial Instruments, for discussion regarding concentration of credit risk.
Note 6 — Nuclear Decommissioning Trust Fund 
NRG's nuclear decommissioning trust fund assets, which are for the decommissioning of STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. Although NRG is responsible for managing the decommissioning of its 44% interest in STP, the predecessor utilities that owned STP are authorized by the PUCT to collect decommissioning funds from their ratepayers to cover decommissioning costs on behalf of NRG. NRC requirements determine the decommissioning cost estimate which is the minimum required level of funding. In the event that funds from the ratepayers that accumulate in the nuclear decommissioning trust are ultimately determined to be inadequate to decommission the STP facilities, the utilities will be required to collect through rates charged to rate payers all additional amounts, with no obligation from NRG, provided that NRG has complied with PUCT rules and regulations regarding decommissioning trusts. Following completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective ratepayers of the utilities.
NRG accounts for the nuclear decommissioning trust fund in accordance with ASC 980, Regulated Operations, or ASC 980 because the Company's nuclear decommissioning activities are subject to approval by the PUCT, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust Liability and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.
The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities.

 	As of December 31, 2012	 	As of December 31, 2011	
(In millions, except otherwise noted)	Fair
Value	 	Unrealized
Gains (a)	 	Weighted-
average
maturities
(in years)	 	Fair
Value	 	Unrealized
Gains	 	Unrealized
Losses	 	Weighted-
average
maturities
(in years)	
Cash and cash equivalents	$	10	
 	 	$	—	
 	 	—	
 	 	$	2	
 	 	$	—	
 	 	$	—	
 	 	—	
 	
U.S. government and federal agency obligations	33	
 	 	2	
 	 	10	
 	 	43	
 	 	3	
 	 	—	
 	 	10	
 	
Federal agency mortgage-backed securities	59	
 	 	2	
 	 	23	
 	 	63	
 	 	3	
 	 	—	
 	 	23	
 	
Commercial mortgage-backed securities	9	
 	 	—	
 	 	30	
 	 	7	
 	 	—	
 	 	—	
 	 	28	
 	
Corporate debt securities	80	
 	 	4	
 	 	11	
 	 	54	
 	 	3	
 	 	1	
 	 	10	
 	
Equity securities	280	
 	 	143	
 	 	—	
 	 	251	
 	 	113	
 	 	1	
 	 	—	
 	
Foreign government fixed income securities	2	
 	 	—	
 	 	6	
 	 	4	
 	 	—	
 	 	—	
 	 	8	
 	
Total	$	473	
 	 	$	151	
 	 	 	
 	 	$	424	
 	 	$	122	
 	 	$	2	

(a) There are no unrealized losses as of December 31, 2012.

142

The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.

 	Year Ended December 31,	
 	2012	 	2011	 	2010	
 	(In millions)	
Realized gains	$	12	
 	 	$	4	
 	 	$	8	
 	
Realized losses	(7	)	 	(3	)	 	(5	)	
Proceeds from sale of securities	399	
 	 	385	
 	 	307	
 	
Note 7 — Inventory 
Inventory consisted of:

 	As of December 31,	
 	2012	 	2011	
 	(In millions)	
Fuel oil	$	181	
 	 	$	59	
 	
Coal/Lignite	405	
 	 	82	
 	
Natural gas	12	
 	 	10	
 	
Spare parts	329	
 	 	157	
 	
Other	4	
 	 	—	
 	
Total Inventory	$	931	
 	 	$	308	

143

Note 8 — Capital Leases and Notes Receivable 
Notes receivable primarily consisted of fixed and variable rate notes secured by equity interests in partnerships and joint ventures. NRG's notes receivable and capital leases were as follows:

 	As of December 31,	
 	2012	 	2011	
 	(In millions)	
Capital Leases Receivable — non-affiliates	 	 	 	
Vattenfall Europe Generation AG & Co. KG., due August 31, 2021, 11.00% (a)	$	—	
 	 	$	199	
 	
Other	—	
 	 	1	
 	
Capital leases — non-affiliates	—	
 	 	200	
 	
Notes Receivable — non-affiliates (b)	82	
 	 	36	
 	
Notes Receivable — affiliates	 	 	 	
Kraftwerke Schkopau GBR, indefinite maturity date, 6.91%-7.00% (c)	—	
 	 	112	
 	
Avenal Solar Holdings LLC, indefinite maturity date, 4.5% (d)	6	
 	 	8	
 	
Notes receivable — affiliates	6	
 	 	120	
 	
Subtotal — Capital leases and notes receivable	88	
 	 	356	
 	
Less current maturities:	 	 	 	
Notes receivable (e)	9	
 	 	—	
 	
Capital leases (e)	—	
 	 	14	
 	
Total Capital leases and notes receivable — noncurrent	$	79	
 	 	$	342	

(a)	SEG has sold 100% of its share of capacity from the Schkopau power plant to Vattenfall Europe Generation AG & Co. KG under a 25-year contract, which is more than 83% of the useful life of the plant. This direct financing lease receivable amount was calculated based on the present value of the income to be received over the life of the contract. On July 17, 2012, the Company completed the sale of its 100% interest in SEG, as discussed in Note 3,  Business Acquisitions and Dispositions .	
 	 	
(b)	Agua Caliente, Alpine, Borrego and CVSR have entered into agreements with their respective transmission owners to provide financing for required network upgrades. The notes will be repaid within a five year period following the date each facility reaches commercial operations.	
 	 	
(c)	SEG entered into a note receivable with Kraftwerke Schkopau GBR, a partnership between SEG and E.On Kraftwerke GmbH. The note was used to fund SEG's initial capital contribution to the partnership and to cover project liquidity shortfalls during construction of the Schkopau power plant. On July 17, 2012, the Company completed the sale of its 100% interest in SEG, as discussed in Note 3 ,  Business Acquisitions and Dispositions .	
 	 	
(d)	NRG entered into a long-term $35 million note receivable facility with Avenal Solar Holdings LLC, to fund project liquidity needs in 2011.	
 	 	
(e)	The current portion of notes receivable and capital leases is recorded in Prepayments and other current assets on the Consolidated Balance Sheet.	
Note 9 — Property, Plant, and Equipment 
NRG's major classes of property, plant, and equipment were as follows:

 	As of December 31,	 	Depreciable	
 	2012	 	2011	 	Lives	
 	(In millions)	 	 	
Facilities and equipment	$	19,787	
 	 	$	14,483	
 	 	1-40 Years	
Land and improvements	760	
 	 	602	
 	 	 	
Nuclear fuel	414	
 	 	365	
 	 	5 Years	
Office furnishings and equipment	355	
 	 	254	
 	 	2-10 Years	
Construction in progress	4,369	
 	 	2,487	
 	 	 	
Total property, plant, and equipment	25,685	
 	 	18,191	
 	 	 	
Accumulated depreciation	(5,417	)	 	(4,570	)	 	 	
Net property, plant, and equipment	$	20,268	
 	 	$	13,621	

144

Note 10 — Goodwill and Other Intangibles 
Goodwill — NRG's goodwill balance was $2.0 billion and $1.9 billion as of December 31, 2012, and 2011, respectively. The Company recorded approximately $1.7 billion of goodwill in connection with the acquisition of Texas Genco in 2006. The Company recorded $144 million of goodwill in connection with the 2010 acquisition of Green Mountain Energy and $29 million in connection with the 2011 acquisition of Energy Plus. In 2012, the Company recorded additional goodwill for several business acquisitions. The Green Mountain Energy and Energy Plus acquisitions are discussed further in Note 3,  Business Acquisitions and Dispositions . As of December 31, 2012, there was no impairment to goodwill. As of December 31, 2012, 2011, and 2010, NRG had approximately $609 million, $594 million, and $660 million, respectively, of goodwill that is deductible for U.S. income tax purposes in future periods.
Intangible Assets — The Company's intangible assets as of December 31, 2012, primarily reflect intangible assets established with the acquisitions of various companies in 2012, 2011, 2010, 2009, and 2006, and are comprised of the following:
 	 	
•	Emission Allowances — These intangibles primarily consist of SO2 and NOx emission allowances established with the 2012 GenOn acquisition and 2006 Texas Genco acquisition and also include RGGI emission credits which NRG began purchasing in 2009. These emission allowances are held-for-use and are amortized to cost of operations, with NO x  allowances amortized on a straight-line basis and SO 2  allowances and RGGI credits amortized based on units of production. During the year ended December 31, 2011, the Company recorded an impairment charge of $160 million on the Company's Acid Rain Program SO 2  emission allowances in order to comply with the Acid Rain Program as discussed in Note 23,  Environmental Matters .	
 	 	
•	Development rights — Arising primarily from the acquisition of solar businesses in 2010 and 2011, these intangibles are amortizable to depreciation and amortization expense on a straight-line basis over the estimated life of the related project portfolio.	
 	 	
•	Energy supply contracts — Established with the acquisitions of Reliant Energy and Green Mountain Energy, these represent the fair value at the acquisition date of in-market contracts for the purchase of energy to serve retail electric customers. The contracts are amortized to cost of operations based on the expected delivery under the respective contracts.	
 	 	
•	In-market fuel (gas and nuclear) contracts — These intangibles were established with the Texas Genco acquisition in 2006 and are amortized to cost of operations over expected volumes over the life of each contract.	
 	 	
•	Customer contracts — Established with the acquisitions of Reliant Energy, Green Mountain Energy, and Northwind Phoenix ,  these intangibles represent the fair value at the acquisition date of contracts that primarily provide electricity to Reliant Energy's and Green Mountain Energy's C&I customers. These contracts are amortized to revenues based on expected volumes to be delivered for the portfolio.	
 	 	
•	Customer relationships — These intangibles represent the fair value at the acquisition date of acquired businesses' customer base, primarily for Energy Alternatives, Energy Plus, Reliant Energy and Green Mountain Energy. The customer relationships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.	
 	 	
•	Marketing partnerships — Established with the acquisition of Energy Plus, as further discussed in Note 3, Business Acquisitions and Dispositions , these intangibles represent the fair value at the acquisition date of existing agreements with loyalty and affinity partners. The marketing partnerships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year.	
 	 	
•	Trade names — Established with the Reliant Energy, Green Mountain and Energy Plus acquisitions, these intangibles are amortized to depreciation and amortization expense, on a straight-line basis.	
 	 	
•	Other — Consists of renewable energy credits, wind intangible assets, costs to extend the operating license for STP Units 1 and 2, the intangible asset related to a purchased ground lease and the value of acquired power purchase agreements.	

145

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

 	 	 	 	 	Contracts	 	 	 	 	 	 	 	 	 	 	
Year Ended December 31, 2012	Emission
Allowances	 	Development
Rights	 	Energy
Supply	 	Fuel	 	Customer	 	Customer
Relationships	 	Marketing Partnerships	 	Trade
Names	 	Other	 	Total	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	(In millions)	
January 1, 2012	$	783	
 	 	$	24	
 	 	$	54	
 	 	$	72	
 	 	$	859	
 	 	$	634	
 	 	$	88	
 	 	$	318	
 	 	$	39	
 	 	$	2,871	
 	
Purchases	18	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	18	
 	 	36	
 	
Acquisition of businesses	53	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	6	
 	 	—	
 	 	—	
 	 	—	
 	 	59	
 	
Usage	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(13	)	 	(13	)	
Sales	(4	)	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(4	)	
Write-off of fully
    amortized balances	(56	)	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(56	)	
Other	(1	)	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	14	
 	 	13	
 	
Adjusted gross amount	793	
 	 	24	
 	 	54	
 	 	72	
 	 	859	
 	 	640	
 	 	88	
 	 	318	
 	 	58	
 	 	2,906	
 	
Less accumulated amortization (a)	(329	)	 	—	
 	 	(30	)	 	(59	)	 	(794	)	 	(415	)	 	(4	)	 	(72	)	 	(3	)	 	(1,706	)	
Net carrying amount	$	464	
 	 	$	24	
 	 	$	24	
 	 	$	13	
 	 	$	65	
 	 	$	225	
 	 	$	84	
 	 	$	246	
 	 	$	55	
 	 	$	1,200	
 	
(a) Adjusted for write-off of fully amortized emission allowances of $56 million 

 	 	 	 	 	Contracts	 	 	 	 	 	 	 	 	 	 	
Year Ended December 31, 2011	Emission
Allowances	 	Development
Rights	 	Energy
Supply	 	Fuel	 	Customer	 	Customer
Relationships	 	Marketing Partnerships	 	Trade
Names	 	Other	 	Total	
 	(In millions)	
January 1, 2011	$	935	
 	 	$	18	
 	 	$	54	
 	 	$	72	
 	 	$	859	
 	 	$	571	
 	 	$	—	
 	 	$	308	
 	 	$	23	
 	 	$	2,840	
 	
Purchases	8	
 	 	6	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	26	
 	 	40	
 	
Acquisition of businesses	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	63	
 	 	88	
 	 	10	
 	 	13	
 	 	174	
 	
Usage	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(19	)	 	(19	)	
Impairment charge on emission allowances	(160	)	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(160	)	
Other	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(4	)	 	(4	)	
Adjusted gross amount	783	
 	 	24	
 	 	54	
 	 	72	
 	 	859	
 	 	634	
 	 	88	
 	 	318	
 	 	39	
 	 	2,871	
 	
Less accumulated amortization	(335	)	 	—	
 	 	(25	)	 	(57	)	 	(675	)	 	(317	)	 	—	
 	 	(42	)	 	(1	)	 	(1,452	)	
Net carrying amount	$	448	
 	 	$	24	
 	 	$	29	
 	 	$	15	
 	 	$	184	
 	 	$	317	
 	 	$	88	
 	 	$	276	
 	 	$	38	
 	 	$	1,419	
 	
The following table presents NRG's amortization of intangible assets for each of the past three years:

 	Years Ended December 31,	
Amortization	2012	 	2011	 	2010	
 	(In millions)	
Emission allowances	$	50	
 	 	$	66	
 	 	$	70	
 	
Energy supply contracts	5	
 	 	4	
 	 	3	
 	
Fuel contracts	2	
 	 	2	
 	 	7	
 	
Customer contracts	119	
 	 	185	
 	 	232	
 	
Customer relationships	98	
 	 	109	
 	 	91	
 	
Marketing partnerships	4	
 	 	—	
 	 	—	
 	
Trade names	30	
 	 	22	
 	 	12	
 	
Other	2	
 	 	—	
 	 	1	
 	
Total amortization	$	310	
 	 	$	388	
 	 	$	416	

146

The following table presents estimated amortization of NRG's intangible assets for each of the next five years:

 	 	 	 	 	Contracts	 	 	 	 	 	 	 	 	
Year Ended December 31,	Emission
Allowances	 	Development
Rights	 	Energy
Supply	 	Fuel	 	Customer	 	Customer
Relationships	 	Marketing Partnerships	 	Trade
Names	 	Total	
 	(In millions)	
2013	$	77	
 	 	$	1	
 	 	$	6	
 	 	$	2	
 	 	$	53	
 	 	$	68	
 	 	$	9	
 	 	$	21	
 	 	$	237	
 	
2014	71	
 	 	1	
 	 	6	
 	 	2	
 	 	1	
 	 	48	
 	 	15	
 	 	21	
 	 	165	
 	
2015	64	
 	 	1	
 	 	6	
 	 	2	
 	 	1	
 	 	36	
 	 	14	
 	 	21	
 	 	145	
 	
2016	48	
 	 	1	
 	 	6	
 	 	2	
 	 	1	
 	 	26	
 	 	9	
 	 	21	
 	 	114	
 	
2017	41	
 	 	1	
 	 	—	
 	 	2	
 	 	1	
 	 	19	
 	 	5	
 	 	21	
 	 	90	
 	
The following table presents the weighted average remaining amortization period related to NRG's intangible assets purchased in 2012 business acquisitions:

As of December 31, 2012	 	Emission Allowances	
 	 	(In years)	
Weighted average remaining amortization period	 	2	
Intangible assets held for sale — From time to time, management may authorize the transfer from the Company's emission bank of emission allowances held-for-use to intangible assets held-for-sale. Emission allowances held-for-sale are included in other non current assets on the Company's consolidated balance sheet and are not amortized, but rather expensed as sold. As of December 31, 2012, the value of emission allowances held-for-sale is $32 million and is managed within the Corporate segment. Once transferred to held-for-sale, these emission allowances are prohibited from moving back to held-for-use.
Out-of-market contracts — Due primarily to business acquisitions, NRG acquired certain out-of-market contracts, which are classified as non-current liabilities on NRG's consolidated balance sheet. These include out-of-market lease contracts of $728 million and out-of-market gas transportation and storage contracts of $328 million acquired in the acquisition of GenOn. These out-of-market contracts are amortized to cost of operations. In addition, the power and customer contracts are amortized to revenues, while the energy supply contracts are amortized to cost of operations.
The following table summarizes the estimated amortization related to NRG's out-of-market contracts:

 	Contracts	 	 	
Year Ended December 31,	Customer	 	Energy
Supply	 	Power	 	Leases	 	Gas Transportation	 	Total	
 	(In millions)	
2013	$	1	
 	 	$	2	
 	 	$	19	
 	 	35	
 	 	$	32	
 	 	$	89	
 	
2014	—	
 	 	—	
 	 	17	
 	 	35	
 	 	35	
 	 	87	
 	
2015	—	
 	 	—	
 	 	17	
 	 	35	
 	 	37	
 	 	89	
 	
2016	—	
 	 	—	
 	 	18	
 	 	35	
 	 	42	
 	 	95	
 	
2017	—	
 	 	—	
 	 	18	
 	 	35	
 	 	37	
 	 	90	

147

Note 11 — Debt and Capital Leases 
Long-term debt and capital leases consisted of the following:

 	As of December 31,	 	 	
 	2012	 	2011	 	Interest Rate % (a)	
 	(In millions except rates)	
NRG Recourse Debt:	 	 	 	 	 	
Senior notes, due 2017	—	
 	 	1,090	
 	 	7.375	
Senior notes, due 2018	1,200	
 	 	1,200	
 	 	7.625	
Senior notes, due 2019 	800	
 	 	800	
 	 	7.625	
Senior notes, due 2019	693	
 	 	691	
 	 	8.500	
Senior notes, due 2020	1,100	
 	 	1,100	
 	 	8.250	
Senior notes, due 2021	1,128	
 	 	1,200	
 	 	7.875	
Senior notes, due 2023	$	990	
 	 	$	—	
 	 	6.625	
Term loan facility, due 2018 	1,573	
 	 	1,588	
 	 	L+3.00	
Indian River Power LLC, tax exempt bonds, due 2040 and 2045	247	
 	 	205	
 	 	5.375 - 6.00	
Dunkirk Power LLC, tax exempt bonds, due 2042	59	
 	 	59	
 	 	5.875	
Fort Bend County, tax-exempt bonds, due 2038 and 2042	28	
 	 	—	
 	 	4.750	
    Subtotal NRG Recourse Debt	7,818	
 	 	7,933	
 	 	 	
NRG Non-Recourse Debt:	 	 	 	 	 	
GenOn senior notes, due 2014	617	
 	 	—	
 	 	7.625	
GenOn senior notes, due 2017	800	
 	 	—	
 	 	7.875	
GenOn senior notes, due 2018	801	
 	 	—	
 	 	9.500	
GenOn senior notes, due 2020	631	
 	 	—	
 	 	9.875	
GenOn Americas Generation senior notes, due 2021	509	
 	 	—	
 	 	8.500	
GenOn Americas Generation senior notes, due 2031	437	
 	 	—	
 	 	9.125	
GenOn Marsh Landing term loan, due 2017 and 2023	390	
 	 	—	
 	 	L + 2.50 - 2.75	
CVSR - High Plains Ranch II LLC, due 2037	786	
 	 	—	
 	 	0.611 - 2.683	
NRG West Holdings LLC, term loan, due 2023	350	
 	 	159	
 	 	L+2.25 - 2.75	
Agua Caliente Solar, LLC, due 2037	640	
 	 	181	
 	 	2.395 - 3.256	
Ivanpah financing, due 2014 and 2038	1,437	
 	 	874	
 	 	various	
South Trent Wind LLC, financing agreement, due 2020	72	
 	 	75	
 	 	L+ 2.50 - 2.625	
NRG Peaker Finance Co. LLC, bonds, due 2019 	173	
 	 	190	
 	 	L+1.07	
NRG Energy Center Minneapolis LLC, senior secured notes, due 2013, 2017, and 2025 	137	
 	 	151	
 	 	5.95 - 7.31	
NRG Roadrunner LLC, due 2031	46	
 	 	61	
 	 	L+2.01	
NRG Solar Avra Valley LLC	66	
 	 	—	
 	 	L + 2.25	
Other	156	
 	 	105	
 	 	various	
Subtotal NRG Non-Recourse Debt	8,048	
 	 	1,796	
 	 	 	
Subtotal Long Term Debt	15,866	
 	 	9,729	
 	 	 	
Capital leases:	
 	 	 	 	 	
Saale Energie GmbH, Schkopau capital lease, due 2021	—	
 	 	103	
 	 	 	
Chalk Point capital lease, due 2015	14	
 	 	—	
 	 	7.375 - 8.19	
Subtotal Capital Leases	14	
 	 	103	
 	 	 	
Subtotal	15,880	
 	 	9,832	
 	 	 	
Less current maturities 	147	
 	 	87	
 	 	 	
Total long-term debt and capital leases	$	15,733	
 	 	$	9,745	

 	 	
(a)	L+ equals LIBOR plus x%.	

148

Long-term debt includes the following premiums/(discounts):

 	 	As of December 31,	
 	 	2012	 	2011	
 	 	(in millions)	
Senior notes, due 2019	 	$	(7	)	 	$	(9	)	
Term loan facility, due 2018	 	(3	)	 	(3	)	
NRG Peaker Finance Co. LLC, bonds, due 2019 (a)	 	(15	)	 	(20	)	
NRG Energy Center Minneapolis LLC, senior secured notes, due 2013, 2017, and 2025 (b)	 	—	
 	 	1	
 	
GenOn senior notes, due 2014 (c)	 	42	
 	 	—	
 	
GenOn senior notes, due 2017 (c)	 	75	
 	 	—	
 	
GenOn senior notes, due 2018 (c)	 	126	
 	 	—	
 	
GenOn senior notes, due 2020 (c)	 	81	
 	 	—	
 	
GenOn Americas Generation senior notes, due 2021 (c)	 	59	
 	 	—	
 	
GenOn Americas Generation senior notes, due 2031 (c)	 	37	
 	 	—	
 	
Total premium/(discount)	 	$	395	
 	 	$	(31	)	
 	 	
(a)	Discounts of $(5) million and $(5) million are related to current maturities in 2012 and 2011, respectively.	
 	 	
(b)	Premium of $1 million is related to current maturities in 2011.	
 	 	
(c)	Premiums for long-term debt acquired in the GenOn acquisition represent adjustments to record the debt at fair value in connection with the acquisition, as described further in Note 3,  Business Acquisitions and Dispositions .	
NRG Recourse Debt
Senior Notes
Redemption of Senior Notes
In 2012, the Company redeemed its $1.1 billion 2017 Senior Notes through a tender offer and call, at an average early redemption percentage of 104.016%. A $51 million loss on debt extinguishment of the 2017 Senior Notes was recorded, primarily consisting of the premiums paid on the redemption and the write-off of previously deferred financing costs.
In 2011, the Company redeemed its $1.2 billion Senior Notes due 2014 and its $2.4 billion Senior Notes due 2016 at an average redemption percentage of 102.007% and 103.868%, respectively, and recorded a loss on debt extinguishment of $28 million and $115 million, respectively, primarily consisting of the premiums paid on the redemption and the write-off of previously deferred financing costs.
Senior Notes Outstanding
As of December 31, 2012, NRG had six outstanding issuances of senior notes, or Senior Notes, under an Indenture, dated February 2, 2006, or the Indenture, between NRG and Law Debenture Trust Company of New York, as trustee:
(i.)8.500% senior notes, issued June 5, 2009 and due June 15, 2019, or the 2019 Senior Notes;
(ii.)8.250% senior notes, issued August 20, 2010 and due September 1, 2020, or the 2020 Senior Notes;
(iii.)7.625% senior notes, issued January 26, 2011 and due January 15, 2018, or the 2018 Senior Notes;
(iv.)7.625% senior notes, issued May 24, 2011 and due May 15, 2019, or the 7.625% 2019 Senior Notes;
(v.)7.875% senior notes, issued May 24, 2011 and due May 15, 2021, or the 2021 Senior Notes; and
(vi.)6.625% senior notes, issued September 24, 2012 and due March 15, 2023, or the 2023 Senior Notes.
The Company periodically enters into supplemental indentures for the purpose of adding entities under the Senior Notes as guarantors.

149

The Indentures and the form of notes provide, among other things, that the Senior Notes will be senior unsecured obligations of NRG. The Indentures also provide for customary events of default, which include, among others: nonpayment of principal or interest; breach of other agreements in the Indentures; defaults in failure to pay certain other indebtedness; the rendering of judgments to pay certain amounts of money against NRG and its subsidiaries; the failure of certain guarantees to be enforceable; and certain events of bankruptcy or insolvency. Generally, if an event of default occurs, the Trustee or the Holders of at least 25% in principal amount of the then outstanding series of Senior Notes may declare all of the Senior Notes of such series to be due and payable immediately. The terms of the Indentures, among other things, limit NRG's ability and certain of its subsidiaries' ability to return capital to stockholders, grant liens on assets to lenders and incur additional debt. Interest is payable semi-annually on the Senior Notes until their maturity dates.
Senior Notes repurchase agreement
On December 17, 2012, NRG entered into an agreement with a financial institution to repurchase up to $200 million of the Senior Notes in the open market by February 27, 2013.  As of December 31, 2012, no Senior Notes had been repurchased under the program. Through February 27, 2013, the Company paid $80 million, $104 million, and $42 million at an average price of 114.179%, 111.700%, and 113.082% of face value, for repurchases of the Company's 2018 Senior Notes, 2019 Senior Notes, and 2020 Senior Notes, respectively.
2019 Senior Notes
Prior to June 15, 2014, NRG may redeem all or a portion of the 2019 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 104.25% of the note, plus interest payments due on the note from the date of redemption through June 15, 2014, discounted at a Treasury rate plus 0.50%. In addition, on or after June 15, 2014, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:

Redemption Period	Redemption
Percentage	
June 15, 2014 to June 14, 2015	104.250	%	
June 15, 2015 to June 14, 2016	102.830	%	
June 15, 2016 to June 14, 2017	101.420	%	
June 15, 2017 and thereafter	100.000	%	
2020 Senior Notes
Prior to September 1, 2013, NRG may redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 108.25% of the principal amount. Prior to September 1, 2015, NRG may redeem all or a portion of the 2020 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note; or (ii) the excess of the principal amount of the note over the following: the present value of 104.125% of the note, plus interest payments due on the note from the date of redemption through September 1, 2015, discounted at a Treasury rate plus 0.50%. In addition, on or after September 1, 2015, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:

Redemption Period	Redemption
Percentage	
On or after September 1, 2015	104.125	%	
On or after September 1, 2016	102.750	%	
On or after September 1, 2017	101.375	%	
September 1, 2018 and thereafter	100.000	%	
2018 Senior Notes
Prior to maturity, NRG may redeem all or a portion of the 2018 Senior Notes at a redemption price equal to 100% of the principal amount of the notes redeemed plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note or (ii) the excess of the present value of the principal amount at maturity plus all required interest payments due on the note through the maturity date discounted at a Treasury rate plus 0.50%.

150

7.625% 2019 Senior Notes
Prior to May 15, 2014, NRG may redeem up to 35% of the aggregate principal amount of the 7.625% 2019 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.625% of the principal amount. Prior to May 15, 2014, NRG may redeem all or a portion of the 7.625% 2019 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.813% of the note, plus interest payments due on the note from the date of redemption through May 15, 2014, discounted at a Treasury rate plus 0.50%. In addition, on or after May 15, 2014, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:

Redemption Period	Redemption
Percentage	
May 15, 2014 to May 14, 2015	103.813	%	
May 15, 2015 to May 14, 2016	101.906	%	
May 15, 2016 and thereafter	100.000	%	
2021 Senior Notes
Prior to May 15, 2016, NRG may redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.875% of the principal amount. Prior to May 15, 2016, NRG may redeem all or a portion of the 2021 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.938% of the note, plus interest payments due on the note from the date of redemption through May 15, 2016, discounted at a Treasury rate plus 0.50%. In addition, on or after May 15, 2016, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:

Redemption Period	Redemption
Percentage	
May 15, 2016 to May 14, 2017	103.938	%	
May 15, 2017 to May 14, 2018	102.625	%	
May 15, 2018 to May 14, 2019	101.313	%	
May 15, 2019 and thereafter	100.000	%	
2023 Senior Notes
On September 24, 2012, NRG issued $990 million aggregate principal amount at par of 6.625% Senior Notes due 2023, or the 2023 Senior Notes. The 2023 Senior Notes were issued under the Indenture. The Indenture and the form of the notes provide, among other things, that the 2023 Senior Notes will be senior unsecured obligations of NRG. The proceeds, net of issuance costs, of $978 million for the 2023 Senior Notes were used to complete the tender offer of the 2017 Senior Notes.
Prior to September 15, 2015, NRG may redeem up to 35% of the aggregate principal amount of the 2023 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 106.625% of the principal amount. Prior to September 15, 2017, NRG may redeem all or a portion of the 2023 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.313% of the note, plus interest payments due on the note from the date of redemption through September 15, 2017, discounted at a Treasury rate plus 0.50%. In addition, on or after September 15, 2017, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:

Redemption Period	Redemption
Percentage	
September 15, 2017 to September 14, 2018	103.313	%	
September 15, 2018 to September 14, 2019	102.208	%	
September 15, 2019 to September 14, 2020	101.104	%	
September 15, 2020 and thereafter	100.000	%	

151

In connection with the 2023 Senior Notes, NRG entered into a registration payment arrangement. For the first 90-day period immediately following a registration default, additional interest will be paid in an amount equal to 0.25% per annum of the principal amount of 2023 Senior Notes outstanding, as applicable. The amount of interest paid will increase by an additional 0.25% per annum with respect to each subsequent 90-day period until all registration defaults are cured, up to a maximum amount of interest of 1.0% per annum of the principal amount of the 2023 Senior Notes outstanding, as applicable. The additional interest is paid on the next scheduled interest payment date and following the cure of the registration default, the additional interest payment will cease.
Senior Credit Facility
NRG has a senior credit facility, or the Senior Credit Facility, which includes the following:
 	 	
•	A $2.3 billion revolving credit facility, or the Revolving Credit Facility, with a maturity date of July 1, 2016, which will pay interest on amounts drawn at a rate of LIBOR plus 2.75%. As of December 31, 2012, a total of $1.242 billion letters of credit were issued under the Revolving Credit Facility, with $1.058 billion remaining available to be issued. Commitment fees of 0.50% are charged on the unused portion of the Revolving Credit Facility.	
 	 	
•	A $1.6 billion term loan facility, or the Term Loan Facility, with a maturity date of July 1, 2018, which pays interest at a rate of LIBOR plus 3.00%, with a LIBOR floor of 1.00%. The debt was issued at 99.75% of face value; the discount will be amortized to interest expense over the life of the loan. Repayments under the Term Loan Facility will consist of 0.25% per quarter, with the remainder due at maturity. On February 6, 2013, the Company amended the Term Loan Facility to adjust the interest rate to LIBOR plus 2.5%, with a LIBOR floor of 0.75%.	
The Senior Credit Facility replaced an existing senior credit facility in 2011, and NRG recorded a $32 million loss on extinguishment, which consisted of the write-off of previously deferred financing costs.
The Senior Credit Facility is guaranteed by substantially all of NRG's existing and future direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries, and certain other subsidiaries, including GenOn and its subsidiaries. The capital stock of these guarantor subsidiaries has been pledged for the benefit of the Senior Credit Facility's lenders.
The Senior Credit Facility is also secured by first-priority perfected security interests in substantially all of the property and assets owned or acquired by NRG and its subsidiaries, other than certain limited exceptions. These exceptions include assets of certain unrestricted subsidiaries, equity interests in certain of NRG's affiliates that have non-recourse debt financing, including GenOn and its subsidiaries, and voting equity interests in excess of 66% of the total outstanding voting equity interest of certain of NRG's foreign subsidiaries.
The Senior Credit Facility contains customary covenants, which, among other things, require NRG to meet certain financial tests, including minimum interest coverage ratio and a maximum leverage ratio on a consolidated basis, and limit NRG's ability to:
 	 	
•	incur indebtedness and liens and enter into sale and lease-back transactions;	
 	 	
•	make investments, loans and advances; and	
 	 	
•	return capital to stockholders.	
Interest Rate Swaps — NRG entered into interest rate swaps, which became effective on April 1, 2011, and are intended to hedge the risks associated with floating interest rates. The Company pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the monthly equivalent of a floating interest payment based on a 1-month LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its counterparty are made monthly and the LIBOR is determined in advance of each interest period. The total notional amount of the swaps, which matured on February 1, 2013, was $900 million with changes in the fair value through June 30, 2011 recorded in OCI and subsequent changes in the fair value reported in interest expense.

152

Fort Bend County Tax Exempt Bonds
On May 3, 2012, NRG executed a $54 million tax-exempt bond financing with a maturity date of May 1, 2038, issued by the Fort Bend County Industrial Development Corporation, or the Fort Bend County Tranche A Bonds. The Fort Bend County Tranche A Bonds will be used for the construction of a peaking unit with one or more components of a carbon capture system at the W.A. Parish Generating Station in Thompsons, TX, or W.A. Parish. The bonds initially bore weekly interest based on the SIFMA rate, and were enhanced by a letter of credit under the Company's Revolving Credit Facility covering amounts drawn. On October 18, 2012, NRG fixed the rate on the Fort Bend County Tranche A Bonds at 4.75% payable semiannually, and the letter of credit was canceled and replaced with an NRG guarantee. The proceeds drawn through December 31, 2012 were $23 million, and the remaining balance will be drawn over time as construction and other qualifying expenditures are paid.
On October 18, 2012, NRG executed an additional $73 million tax-exempt bond financing, with a maturity date of November 1, 2042, also issued by the Fort Bend County Industrial Development Corporation, or the Fort Bend County Tranche B Bonds. The Fort Bend County Tranche B Bonds will be used for environmental and maintenance upgrades at W.A. Parish. The bonds were issued at a fixed rate of 4.75% payable semiannually, and are supported by an NRG guarantee. The proceeds drawn through December 31, 2012 were $5 million and the remaining balance will be drawn over time as qualifying expenditures are paid.
Indian River Power LLC Tax-Exempt Bonds
On October 12, 2010, NRG executed a $190 million tax-exempt bond financing through its wholly-owned subsidiary, Indian River Power LLC. The bonds were issued by the Delaware Economic Development Authority and will be used for construction of emission control equipment on the Indian River Generating Station in Millsboro, DE, or Indian River. The bonds were issued at a rate of 5.375%, have a maturity date of October 1, 2045, and are supported by an NRG guarantee.
On December 10, 2010, NRG executed an additional $57 million tax-exempt bond financing through Indian River Power LLC. The bonds were issued by Sussex County, Delaware, and will be used for construction of emission control equipment on Indian River. The bonds were issued at a rate of 6.0%, have a maturity date of October 1, 2040, and are supported by an NRG guarantee.
Dunkirk Power LLC Tax-Exempt Bonds
On April 15, 2009, NRG executed a $59 million tax-exempt bond financing, or the Dunkirk bonds, through its wholly-owned subsidiary, Dunkirk Power LLC, whereby all the proceeds were received as of December 31, 2012. The Dunkirk bonds were issued by the County of Chautauqua Industrial Development Agency and are being used for the construction of emission control equipment on the Dunkirk Generating Station in Dunkirk, NY. The Dunkirk bonds have a maturity date of April 1, 2042, and are supported by an NRG guarantee.
NRG Non-Recourse Debt
The following are descriptions of certain indebtedness of NRG's subsidiaries that are outstanding as of December 31, 2012. All of NRG's non-recourse debt is secured by the assets in the respective GenOn subsidiaries and project subsidiaries as further described below. The net assets in the GenOn and project subsidiaries are subject to restrictions, including the ability to transfer assets out of the subsidiaries. As of December 31, 2012, NRG had net assets of $2.6 billion that were deemed restricted for purposes of Rule 4-08(e)(3)(iii) of Regulation S-X.
The indebtedness described below is non-recourse to NRG, unless otherwise noted.
GenOn Senior Notes
Under the GenOn Senior Notes and the related indentures, the GenOn Senior Notes are the sole obligation of GenOn and are not guaranteed by any subsidiary or affiliate of GenOn. The GenOn Senior Notes are senior unsecured obligations of GenOn having no recourse to any subsidiary or affiliate of GenOn. The GenOn Senior Notes restrict the ability of GenOn and its subsidiaries to encumber their assets. The GenOn Senior Notes are subject to acceleration of GenOn's obligations thereunder upon the occurrence of certain events of default, including: (a) default in interest payment for 30 days, (b) default in the payment of principal or premium, if any, (c) failure after 90 days of specified notice to comply with any other agreements in the indenture, (d) certain cross-acceleration events, (e) failure by GenOn or its significant subsidiaries to pay certain final and non‑appealable judgments after 90 days and (f) certain events of bankruptcy and insolvency.

153

2018 and 2020 GenOn Senior Notes
The GenOn Senior Notes due 2018 and 2020 and the related indentures restrict the ability of GenOn to incur additional liens and make certain restricted payments, including dividends. In the event of a default or if restricted payment tests are not satisfied, GenOn would not be able to distribute cash to its parent, NRG. At December 31, 2012, GenOn did not meet the consolidated debt ratio component of the restricted payments test and, therefore, the ability of GenOn to make restricted payments, including dividends, loans and advances to NRG, is limited to specified exclusions, including up to $250 million of such restricted payments. As of December 31, 2012, GenOn net assets of $1.5 billion were deemed restricted for purposes of Rule 4-08(e)(3)(iii) of Regulation S-X.
Prior to maturity, GenOn may redeem the senior notes due 2018, in whole or in part, at a redemption price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the following: the present value of 100% of the note, plus interest payments due on the note through maturity, discounted at a Treasury rate plus 0.50% over the principal amount of the note.
Prior to October 15, 2015, GenOn may redeem the senior notes due 2020, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the following: the present value of 100% of the note, plus interest payments due on the note through maturity, discounted at a Treasury rate plus 0.50% over the principal amount of the note. In addition, on or after October 15, 2015, GenOn may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption rate:

Redemption Period	Redemption
Percentage	
October 15, 2015 to October 14, 2016	104.938	%	
October 15, 2016 to October 14, 2017	103.292	%	
October 15, 2017 to October 14, 2018	101.646	%	
October 15, 2018 and thereafter	100.000	%	
The GenOn Senior Notes due 2018 and 2020, which have a face value of $675 million and $550 million, respectively, were recorded at their fair values of $802 million and $632 million, respectively, on the GenOn acquisition date. The $127 million and $82 million premiums are being amortized to interest expense over the life of the related notes.
2014 and 2017 GenOn Senior Notes
Prior to maturity, GenOn may redeem all or a part of the GenOn Senior Notes due 2014 and 2017 at a redemption price equal to 100% of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the following: the present value of 100% of the note, plus interest payments due on the note through maturity, discounted at a Treasury rate plus 0.50% over the principal amount of the note.
The GenOn Senior Notes due 2014 and 2017, which have a face value of $575 million and $725 million, respectively, were recorded at their fair values of $618 million and $800 million, respectively, on the GenOn acquisition date. The $43 million and $75 million premiums are being amortized to interest expense over the life of the related notes.
GenOn Americas Generation Senior Notes
The GenOn Americas Generation Senior Notes due 2021 and 2031 are senior unsecured obligations of GenOn Americas Generation, a wholly owned subsidiary of NRG, having no recourse to any subsidiary or affiliate of GenOn Americas Generation.
Prior to maturity, GenOn Americas Generation may redeem all or a part of the senior notes due 2021 and 2031 at a redemption price equal to 100% of the notes plus a premium and accrued and unpaid interest. The premium is the greater of: (i) the discounted present value of the then-remaining scheduled payments of principal and interest on the outstanding notes, discounted at a Treasury rate plus 0.375%, less the unpaid principal amount; and (ii) zero.
The GenOn Americas Generation Senior Notes, which have a face value of $450 million and $400 million, respectively, were recorded at their fair values of $510 million and $437 million, respectively, on the GenOn acquisition date. The $60 million and $37 million premiums are being amortized to interest expense over the life of the related notes.

154

Project Financings
The following are descriptions of certain indebtedness of NRG's project subsidiaries that are outstanding as of December 31, 2012.
GenOn Marsh Landing, LLC, or Marsh Landing
Credit Facility — In October 2010, Marsh Landing, an indirect wholly-owned subsidiary of NRG, entered into a credit agreement for up to approximately $650 million of commitments to provide construction and permanent financing for the Marsh Landing generating facility. The credit facility consists of a $155 million tranche A senior secured term loan facility, due 2017, a $345 million tranche B senior secured term loan facility, due 2023, a $50 million senior secured letter of credit facility to support Marsh Landing's debt service reserve requirements and a $100 million senior secured letter of credit facility to support Marsh Landing's collateral requirements under its PPA with PG&E. Prior to the commercial operation date of the project, the collateral requirements under the PPA and construction contracts are being met by a $165 million cash collateralized letter of credit facility entered into by GenOn Energy Holdings Inc., or GenOn Holdings, on behalf of Marsh Landing. At or near the commercial operation date of the project, the GenOn Holdings cash collateralized letter of credit facility will terminate. During the second quarter of 2011, GenOn Holdings satisfied the required initial equity contributions of $147 million and Marsh Landing began borrowing under its credit facility.
The term loans are to be fully amortized by their maturity dates. The tranche A term loan matures on December 31, 2017 and the tranche B term loan matures on the date that is the earlier of the last day of the first fiscal quarter following the tenth anniversary of the conversion of the credit facility from a construction facility to a permanent facility upon commercial operation of the Marsh Landing project and December 31, 2023. The expiry date of the letters of credit is December 31, 2017. Interest on the tranche A term loan is based on a base rate or a LIBOR rate plus an initial applicable margin of 1.5% for base rate loans and 2.5% for LIBOR loans (with such margin increasing 0.25% every three years). Interest on the tranche B term loan is based on a base rate or a LIBOR rate plus an initial applicable margin of 1.75% for base rate loans and 2.75% for LIBOR loans (with such margin increasing 0.25% every three years). Fees on lenders' exposure under the letters of credit accrue at a rate equal to the applicable margin payable on the tranche A term loan that are based on the LIBOR rate. An undrawn commitment fee applies at a rate of 0.75%.
Loans under the credit facility will be subject to mandatory prepayment upon the occurrence of certain events, including an event of damage or an event of taking, the receipt of the proceeds of any claim under any document executed in connection with the Marsh Landing project and any amounts payable as a result of termination of the PPA. The credit facility includes customary affirmative and negative covenants and events of default. Negative covenants include limitations on additional debt, liens, negative pledges, investments, distributions, business activities, stock repurchases, asset dispositions, accounting changes, change orders and affiliate transactions. Events of default include non-performance of covenants, breach of representations, cross‑acceleration of other material indebtedness, bankruptcy and insolvency, undischarged material judgments, a change in control and a failure to achieve commercial operation of the Marsh Landing project by December 31, 2013.
Avra Valley Financing
On August 30, 2012, NRG, through its wholly-owned subsidiary, NRG Solar Avra Valley LLC, or Avra Valley, entered into a credit agreement with a bank, or the Avra Valley Financing Agreement, for a $66 million construction loan that will convert to a term loan upon completion of the project and an $8 million cash grant loan. Both the construction and cash grant loans have interest rates of LIBOR plus an applicable margin of 2.25%. The term loan has an interest rate of LIBOR plus an applicable margin of 2.25%, which escalates 0.25% on the fifth, tenth, and fifteenth anniversary of the term conversion. The term loan, which is secured by all the assets of Avra Valley, matures on the 18th anniversary of the term conversion and amortizes based upon a predetermined schedule. The cash grant loan matures upon the earlier of three days after the receipt of the cash grant or May 2013. The Avra Valley Financing Agreement also includes a letter of credit facility on behalf of Avra Valley of up to $4 million. Avra Valley pays an availability fee of 100% of the applicable margin on issued letters of credit. As of December 31, 2012, $65 million was outstanding under the construction loan, $1 million was outstanding under the cash grant loans, and no letters of credit in support of the project were issued.

155

Alpine Financing
On March 16, 2012, NRG, through its wholly-owned subsidiary, NRG Solar Alpine LLC, or Alpine, entered into a credit agreement with a group of lenders, or the Alpine Financing Agreement, for a $166 million construction loan that will convert 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 .   The construction loan has an interest rate of LIBOR plus an applicable margin of 2.50% and the cash grant loan has an interest rate of LIBOR plus an applicable margin of 2.25%. The term loan has an interest rate of LIBOR plus an applicable margin of 2.50%, which escalates 0.25% on the fifth anniversary of the term conversion. The term loan, which is secured by all the assets of Alpine, matures on the 10 th  anniversary of the term conversion and amortizes based upon a predetermined schedule. The cash grant loan matures upon the earlier of the receipt of the cash grant or June 2013. The Alpine Financing Agreement also includes a letter of credit facility on behalf of Alpine of up to $37 million. Alpine pays an availability fee of 100% of the applicable margin on issued letters of credit. As of December 31, 2012, $2 million was outstanding under the construction loan, nothing was outstanding under the cash grant loans, and $8 million in letters of credit in support of the project were issued.
CVSR Financing
On September 30, 2011, NRG acquired CVSR, as discussed in Note 3, Business Acquisitions and Dispositions. In connection with the acquisition, High Plains Ranch II LLC, a wholly-owned subsidiary of NRG, entered into the CVSR Financing Agreement with the FFB, to borrow up to $1.2 billion to finance the costs of constructing this solar facility. The CVSR Financing Agreement, which matures in 2037, is non-recourse to NRG. Funding requests will be submitted to the FFB on a monthly basis 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, 2012, $786 million was outstanding under the loan.
CVSR intends to submit an application to the U.S. Department of Treasury for a cash grant; any proceeds received will be utilized to repay the borrowings that mature in 2014.
Under the terms of the CVSR Financing Agreement, on November 17, 2011, CVSR entered into a series of swaptions with a notional value of $686 million, or 80% of the guaranteed term loan amount, in order to hedge the project interest rate risk. These swaptions mature over a series of seven scheduled settlement dates to correspond with the completion dates of the project. As of December 31, 2012, $342 million notional value of the swaptions remain outstanding.
NRG West Holdings Credit Agreement
On August 23, 2011, NRG, through its wholly-owned subsidiary, NRG West Holdings LLC, or West Holdings, entered into a credit agreement with a group of lenders in respect to the El Segundo Energy Center, or the West Holdings Credit Agreement. The West Holdings Credit Agreement, which establishes a $540 million, two tranche construction loan facility with additional facilities for the issuance of letters of credit or working capital loans, 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 LIBOR, plus an applicable margin which increases by 0.125% periodically from conversion through year eight for the Tranche A Facility and increases by 0.125% upon term conversion and on the third and sixth anniversary of the term conversion and 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 West Holdings Credit Agreement also provides for the issuance of letters of credit and working capital loans to support the El Segundo Energy Center 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, 2012, under the West Holdings Credit Agreement, West Holdings borrowed $350 million under the Tranche A Facility, issued a $30 million letter of credit in support of the PPA, and issued a $6 million letter of credit under the working capital facility.

156

Agua Caliente Financing
On August 5, 2011, NRG acquired Agua Caliente, as discussed in Note 3, Business Acquisitions and Dispositions.  In connection with the acquisition, Agua Caliente Solar LLC, a wholly-owned subsidiary of NRG, entered into the Agua Caliente Financing Agreement with the FFB, to borrow up to $967 million to finance the costs of constructing this solar facility.  The Agua Caliente Financing Agreement, which matures in 2037, is non-recourse to NRG. Funding requests will be submitted to the FFB on a monthly basis and the loans provided by the FFB are guaranteed by the U.S. DOE. Amounts borrowed under the Agua Caliente Financing Agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of 0.375%, and are secured by the assets of Agua Caliente.  As of December 31, 2012, $640 million had been drawn under this agreement.
Roadrunner Financing
On May 25, 2011, NRG, through its wholly-owned subsidiary, NRG Roadrunner LLC, or Roadrunner, entered into a credit agreement with a bank, or the Roadrunner Financing Agreement, for a $47 million construction loan that converted to a term loan on January 10, 2012 and a $21 million cash grant loan, both of which have an interest rate of LIBOR plus an applicable margin of 2.01%. The term loan has an interest rate of LIBOR plus an applicable margin which escalates 0.25% every five years and ranges from 2.01% at closing to 2.76% in year fifteen through maturity. The term loan, which is secured by all the assets of Roadrunner, matures on September 30, 2031, and amortizes based upon a predetermined schedule. On March 20, 2012, Roadrunner received proceeds of $21 million under its cash grant application. These proceeds were used to repay Roadrunner's outstanding cash grant loan of $17 million plus accrued interest. The remaining cash was returned to NRG under the terms of the accounts agreement. The Roadrunner Financing Agreement also includes a letter of credit facility on behalf of Roadrunner of up to $5 million. Roadrunner pays an availability fee of 100% of the applicable margin on issued letters of credit. As of December 31, 2012, $46 million was outstanding under the term loan, a $3 million letter of credit in support of debt service and a $2 million in letters of credit in support of the PPA were issued.
Ivanpah Financing
On April 5, 2011, NRG acquired a majority interest in Ivanpah, as discussed in Note 3, Business Acquisitions and Dispositions . On April 5, 2011, Ivanpah entered into the Ivanpah Credit Agreement with the FFB to borrow up to $1.6 billion to finance the costs of constructing the Ivanpah solar facilities. Each phase of the project is governed by a separate financing agreement and is non recourse to both the other projects and to NRG. Funding requests are submitted to the FFB on a monthly basis and the loans provided by the FFB are guaranteed by the U.S. DOE.   Amounts borrowed under the Ivanpah Credit Agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of 0.375% and are secured by all the assets of Ivanpah. Ivanpah intends to submit an application to the U.S. Department of Treasury for a cash grant; any proceeds received will be utilized to repay the borrowings that mature in 2014.
The following table reflects the borrowings under the Ivanpah Credit Agreement as of December 31, 2012:

 	Maximum borrowings available under Ivanpah Credit Agreement	 	Amounts borrowed	 	Weighted average interest rate on amounts borrowed	
 	(In millions, except rates)	
Solar Partners I, due June 27, 2014 (a)	$	159	
 	 	$	156	
 	 	1.679	%	
Solar Partners I, due June 27, 2033	392	
 	 	330	
 	 	2.811	%	
Solar Partners II, due February 27, 2014 (a)	132	
 	 	131	
 	 	1.610	%	
Solar Partners II, due February 27, 2038	387	
 	 	347	
 	 	3.144	%	
Solar Partners VIII, due October 27, 2014 (a)	117	
 	 	114	
 	 	1.997	%	
Solar Partners VIII, due October 27, 2038	440	
 	 	359	
 	 	3.121	%	
 	$	1,627	
 	 	$	1,437	

(a)	The cash portion of the loan is fully drawn; additional amounts will be utilized for capitalized interest.	

157

South Trent Financing Agreement
In connection with the acquisition, on June 14, 2010, South Trent Wind LLC entered into a financing agreement, or the South Trent Financing Agreement, with a group of lenders, which matures on June 14, 2020. The South Trent Financing Agreement includes a $79 million term loan, as well as a $10 million letter of credit facility in support of the PPA. The South Trent Financing Agreement also provides for up to $7 million in additional letter of credit facilities. The term loan accrues interest at LIBOR plus a margin based upon a grid, which is initially 2.5% and increases every two years by 12.5 basis points. The term loan amortizes quarterly based upon a predetermined schedule with the unamortized portion due at maturity. As of December 31, 2012, $72 million was outstanding under the term loan and $10 million was issued under the letter of credit facility.
Peakers
In June 2002, NRG Peaker Finance Company LLC, or Peakers, an indirect wholly-owned subsidiary of NRG, issued $325 million in floating rate bonds due June 2019. Peakers subsequently swapped such floating rate debt for fixed rate debt at an all-in cost of 6.67% per annum. Principal, interest, and swap payments were originally guaranteed by Syncora Guarantee Inc., successor in interest to XL Capital Assurance, through a financial guaranty insurance policy. In 2009, Assured Guaranty Mutual Corp assumed the responsibility as the bond insurer and controlling party. Syncora Guarantee Inc. continues to be the swap insurer. These notes are also secured by, among other things, substantially all of the assets of and membership interests in Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Sterlington Power LLC, NRG Rockford LLC, NRG Rockford II LLC, and NRG Rockford Equipment LLC. As of December 31, 2012, $188 million in principal remained outstanding on these bonds. Upon emergence from bankruptcy, NRG issued a $36 million letter of credit to Peakers' collateral agent. The letter of credit may be drawn if the project is unable to meet principal or interest payments. There are no provisions requiring NRG to replenish the letter of credit if it is drawn. On December 10, 2012, the collateral agent drew the remaining $4 million on the letter of credit, and NRG contributed $19 million in equity to Peakers to meet its debt service requirements. As of December 31, 2012, nothing remains available for additional letters of credit issuances.
NRG Thermal
NRG owns and operates its thermal business through a wholly-owned subsidiary holding company, NRG Thermal LLC, or NRG Thermal. In 1993, the predecessor entity to NRG Thermal's largest subsidiary, NRG Energy Center Minneapolis LLC, or NRG Thermal Minneapolis, issued $84 million of 7.31% senior secured notes due June 2013, of which $4 million remained outstanding as of December 31, 2012. In 2002, NRG Thermal Minneapolis issued an additional $55 million of 7.25% Series A notes due August 2017, of which $24 million remained outstanding as of December 31, 2012, and $20 million of 7.12% Series B notes due August 2017, of which $9 million remained outstanding as of December 31, 2012. In 2010, NRG Thermal Minneapolis issued $100 million of 5.95% Series C notes due June 23, 2025, of which $100 million remained outstanding as of December 31, 2012.
The indebtedness under these notes is secured by substantially all of the assets of NRG Thermal Minneapolis. NRG Thermal has guaranteed the indebtedness, and its guarantee is secured by a pledge of the equity interests in all of NRG Thermal's subsidiaries.

158

Interest Rate Swaps — Project Financings
Many of NRG's project subsidiaries entered into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. These swaps amortize in proportion to their respective loans and are floating for fixed where the project subsidiary pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value and will receive quarterly the equivalent of a floating interest payment based on the same notional value. All interest rate swap payments by the project subsidiary and its counterparty are made quarterly and the LIBOR is determined in advance of each interest period. The following table summarizes the swaps, some of which are forward starting as indicated, related to NRG's project level debt as of December 31, 2012.

Non-Recourse Debt	 	% of Principal	 	Fixed Interest Rate	 	Floating Interest Rate	 	Notional
Amount at December 31, 2012
(In millions)	 	Effective Date	 	Maturity Date	
NRG Peaker Finance Co. LLC	 	100	%	 	6.673	%	 	3-mo. LIBOR + 1.07%	 	$	188	
 	 	June 18, 2002	 	June 10, 2019	
NRG West Holdings LLC	 	75	%	 	2.417	%	 	3-mo. LIBOR	 	328	
 	 	November 30, 2011	 	August 31, 2023	
South Trent Wind LLC	 	75	%	 	3.265	%	 	3-mo. LIBOR	 	54	
 	 	June 15, 2010	 	June 14, 2020	
South Trent Wind LLC	 	75	%	 	4.95	%	 	3-mo. LIBOR	 	21	
 	 	June 30, 2020	 	June 14, 2028	
NRG Solar Roadrunner LLC	 	75	%	 	4.313	%	 	3-mo. LIBOR	 	34	
 	 	September 30, 2011	 	December 31, 2029	
NRG Solar Alpine LLC	 	85	%	 	2.744	%	 	3-mo. LIBOR	 	141	
 	 	December 31, 2012	 	December 31, 2029	
NRG Solar Avra Valley LLC	 	90	%	 	2.333	%	 	3-mo. LIBOR	 	59	
 	 	November 30, 2012	 	November 30, 2030	
GenOn Marsh Landing	 	75	%	 	1.085	%	 	1-mo. LIBOR	 	369	
 	 	August 31, 2011	 	June 28, 2013	
GenOn Marsh Landing	 	75	%	 	3.244	%	 	3-mo. LIBOR	 	500	
 	 	June 28, 2013	 	June 30, 2023	
Other	 	75	%	 	various	
 	 	various	 	69	
 	 	various	 	various	
Consolidated Annual Maturities
Annual payments based on the maturities of NRG's debt, for the years ending after December 31, 2012, are as follows:

 	(In millions)	
2013	$	141	
 	
2014	1,514	
 	
2015	213	
 	
2016	224	
 	
2017	993	
 	
Thereafter	12,781	
 	
Total	$	15,866	

159

Note 12 — Asset Retirement Obligations 
NRG's AROs are primarily related to the future dismantlement of equipment on leased property and environmental obligations related to nuclear decommissioning, ash disposal, site closures, and fuel storage facilities. In addition, NRG has also identified conditional AROs for asbestos removal and disposal, which are specific to certain power generation operations.
See Note 6, Nuclear Decommissioning Trust Fund, for a further discussion of NRG's nuclear decommissioning obligations. Accretion for the nuclear decommissioning ARO and amortization of the related ARO asset are recorded to the Nuclear Decommissioning Trust Liability to the ratepayers and are not included in net income, consistent with regulatory treatment.
The following table represents the balance of ARO obligations as of December 31, 2012, and 2011, along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2012:

 	(In millions)	
Balance as of December 31, 2011	$	443	
 	
Additions	11	
 	
Additions for GenOn acquisition	175	
 	
Spending for current obligations	(8	)	
Accretion — Expense	8	
 	
Accretion — Nuclear decommissioning	19	
 	
Balance as of December 31, 2012	$	648	
 	
Note 13 — Benefit Plans and Other Postretirement Benefits 
NRG sponsors and operates defined benefit pension and other postretirement plans. As part of the GenOn acquisition, discussed in Note 3,  Business Acquisitions and Dispositions , NRG assumed GenOn's defined benefit pension plans and other postretirement benefit plans, and GenOn's benefit plan obligations were recorded at fair value at the time of the acquisition. NRG expects to contribute $45 million to the Company's pension plans in 2013.
NRG pension benefits are available to eligible non-union and union employees through various defined benefit pension plans. These benefits are based on pay, service history and age at retirement. Most pension benefits are provided through tax-qualified plans. Certain executive pension benefits that cannot be provided by the tax-qualified plans are provided through unfunded non-tax-qualified plans. NRG also provides postretirement health and welfare benefits for certain groups of employees. Cost sharing provisions vary by the terms of any applicable collective bargaining agreements.
NRG Defined Benefit Plans
The net annual periodic pension cost related to NRG domestic pension and other postretirement benefit plans include the following components:

 	Year Ended December 31,	
 	Pension Benefits	
 	2012	 	2011	 	2010	
 	(In millions)	
Service cost benefits earned	$	14	
 	 	$	14	
 	 	$	14	
 	
Interest cost on benefit obligation	23	
 	 	21	
 	 	21	
 	
Expected return on plan assets	(23	)	 	(21	)	 	(20	)	
Amortization of unrecognized net loss	4	
 	 	—	
 	 	—	
 	
Net periodic benefit cost	$	18	
 	 	$	14	
 	 	$	15	

 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Year Ended December 31,	
 	Other Postretirement Benefits	
 	2012	 	2011	 	2010	
 	(In millions)	
Service cost benefits earned	$	2	
 	 	$	2	
 	 	$	2	
 	
Interest cost on benefit obligation	6	
 	 	6	
 	 	6	
 	
Amortization of unrecognized net loss	1	
 	 	—	
 	 	—	
 	
Net periodic benefit cost	$	9	
 	 	$	8	
 	 	$	8	

160

A comparison of the pension benefit obligation, other postretirement benefit obligations, and related plan assets for NRG's plans on a combined basis is as follows:

 	As of December 31,	
 	Pension Benefits	 	Other Postretirement
Benefits	
 	2012	 	2011	 	2012	 	2011	
 	(In millions)	
Benefit obligation at January 1	$	456	
 	 	$	404	
 	 	$	122	
 	 	$	106	
 	
Obligations assumed in the GenOn acquisition	596	
 	 	—	
 	 	87	
 	 	—	
 	
Service cost	14	
 	 	14	
 	 	2	
 	 	2	
 	
Interest cost	23	
 	 	21	
 	 	6	
 	 	6	
 	
Plan amendments	—	
 	 	—	
 	 	(1	)	 	—	
 	
Actuarial loss	75	
 	 	34	
 	 	6	
 	 	9	
 	
Employee and retiree contributions	—	
 	 	—	
 	 	1	
 	 	1	
 	
Benefit payments	(17	)	 	(17	)	 	(3	)	 	(2	)	
Benefit obligation at December 31	1,147	
 	 	456	
 	 	220	
 	 	122	
 	
Fair value of plan assets at January 1	308	
 	 	297	
 	 	—	
 	 	—	
 	
Assets acquired in the GenOn acquisition	402	
 	 	—	
 	 	—	
 	 	—	
 	
Actual return on plan assets	41	
 	 	10	
 	 	—	
 	 	—	
 	
Employee contributions	—	
 	 	—	
 	 	1	
 	 	1	
 	
Employer contributions	23	
 	 	18	
 	 	2	
 	 	1	
 	
Benefit payments	(17	)	 	(17	)	 	(3	)	 	(2	)	
Fair value of plan assets at December 31	757	
 	 	308	
 	 	—	
 	 	—	
 	
Funded status at December 31 — excess of obligation over assets	$	(390	)	 	$	(148	)	 	$	(220	)	 	$	(122	)	
Amounts recognized in NRG's balance sheets were as follows:

 	As of December 31,	
 	Pension Benefits	 	Other Postretirement
Benefits	
 	2012	 	2011	 	2012	 	2011	
 	(In millions)	
Current liabilities	$	1	
 	 	$	—	
 	 	$	9	
 	 	$	3	
 	
Non-current liabilities	389	
 	 	148	
 	 	211	
 	 	119	
 	
Amounts recognized in NRG's accumulated OCI that have not yet been recognized as components of net periodic benefit cost were as follows:

 	As of December 31,	
 	Pension Benefits	 	Other Postretirement
Benefits	
 	2012	 	2011	 	2012	 	2011	
 	(In millions)	
Unrecognized loss	$	140	
 	 	$	88	
 	 	$	17	
 	 	$	11	
 	
Prior service credit	(2	)	 	(2	)	 	(2	)	 	(1	)	

161

Other changes in plan assets and benefit obligations recognized in OCI were as follows:

 	Year Ended December 31,	
 	Pension
Benefits	 	Other Postretirement
Benefits	
 	2012	 	2011	 	2012	 	2011	
 	(In millions)	
Unrecognized loss	$	56	
 	 	$	46	
 	 	$	7	
 	 	$	9	
 	
Amortization of net actuarial gain	(4	)	 	—	
 	 	(1	)	 	—	
 	
Prior service credit	—	
 	 	—	
 	 	(1	)	 	—	
 	
Total recognized in other comprehensive loss	$	52	
 	 	$	46	
 	 	$	5	
 	 	$	9	
 	
Total recognized in net periodic pension cost and other comprehensive income	$	71	
 	 	$	60	
 	 	$	13	
 	 	$	17	
 	
The Company's estimated unrecognized loss for NRG's domestic pension plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year is approximately $10 million. The Company's estimated unrecognized loss for NRG's postretirement plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year is minimal.
The following table presents the balances of significant components of NRG's domestic pension plan:

 	As of December 31,	
 	Pension Benefits	
 	2012	 	2011	
 	(In millions)	
Projected benefit obligation	$	1,147	
 	 	$	456	
 	
Accumulated benefit obligation	1,024	
 	 	392	
 	
Fair value of plan assets	757	
 	 	308	
 	
NRG's market-related value of its plan assets is the fair value of the assets. The fair values of the Company's pension plan assets by asset category and their level within the fair value hierarchy are as follows:

 	Fair Value Measurements as of December 31, 2012	
 	Quoted Prices in
Active Markets for
Identical Assets
(Level 1)	 	Significant
Observable Inputs
(Level 2)	 	Total	
 	(In millions)	
U.S. equity investment	$	26	
 	 	$	—	
 	 	$	26	
 	
Non-U.S. equity investment	68	
 	 	—	
 	 	68	
 	
Corporate bond investment — fixed income	32	
 	 	—	
 	 	32	
 	
Common/collective trust investment — U.S. equity	—	
 	 	290	
 	 	290	
 	
Common/collective trust investment — non-U.S. equity	—	
 	 	111	
 	 	111	
 	
Common/collective trust investment — fixed income	—	
 	 	228	
 	 	228	
 	
Short-term investment fund	—	
 	 	2	
 	 	2	
 	
Total	$	126	
 	 	$	631	
 	 	$	757	

162

 	
 	 	 	 	 	 	 	 	 	 	 	 	
 	Fair Value Measurements as of December 31, 2011	
 	Quoted Prices in
Active Markets for
Identical Assets
(Level 1)	 	Significant
Observable Inputs
(Level 2)	 	Total	
 	(In millions)	
U.S. equity investment	$	47	
 	 	$	—	
 	 	$	47	
 	
Non-U.S. equity investment	18	
 	 	—	
 	 	18	
 	
Corporate bond investment — fixed income	37	
 	 	—	
 	 	37	
 	
Common/collective trust investment — U.S. equity	—	
 	 	78	
 	 	78	
 	
Common/collective trust investment — non-U.S. equity	—	
 	 	32	
 	 	32	
 	
Common/collective trust investment — fixed income	—	
 	 	96	
 	 	96	
 	
Total	$	102	
 	 	$	206	
 	 	$	308	
 	
In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety. The fair value of the U.S. and non-U.S. equity investments and the corporate bond investment is based on quoted prices in active markets, and is categorized as Level 1. All equity investments are valued at the net asset value of shares held at year end. The fair value of the corporate bond investment is based on the closing price reported on the active market on which the individual securities are traded. The fair value of the common/collective trusts is valued at fair value which is equal to the sum of the market value of all of the fund's underlying investments, and is categorized as Level 2. There are no investments categorized as Level 3.
The following table presents the significant assumptions used to calculate NRG's benefit obligations:

 	As of December 31,	
 	Pension Benefits	 	Other Postretirement Benefits	
Weighted-Average Assumptions	2012	 	2011	 	2012	 	2011	
Discount rate	4.16	%	 	4.98	%	 	4.31	%	 	5.18	%	
Rate of compensation increase	3.57	%	 	4.40	%	 	N/A	
 	 	N/A	
 	
Health care trend rate	—	
 	 	—	
 	 	8% grading to
5% in 2019	
 	 	8% grading to
5% in 2019	
 	
The following table presents the significant assumptions used to calculate NRG's benefit expense:

 	As of December 31,	
 	Pension Benefits	 	Other Postretirement Benefits	
Weighted-Average Assumptions	2012	 	2011	 	2010	 	2012	 	2011	 	2010	
Discount rate	4.95	%	
 	5.47	%	 	5.93	%	 	5.15	%	
 	5.77	%	 	6.14	%	
Expected return on plan assets	6.75-7.50%	
 	
 	7.25%-7.50%	
 	 	7.50	%	 	—	
 	
 	—	
 	 	—	
 	
Rate of compensation increase	4.34	%	
 	4.40	%	 	4.39	%	 	—	
 	
 	—	
 	 	—	
 	
Health care trend rate	—	
 	
 	—	
 	 	—	
 	 	8.0% grading to
5.0% in 2019	
 	
 	8.0% grading to
5.0% in 2019	
 	 	9.5% grading to
5.5% in 2016	

163

NRG uses December 31 of each respective year as the measurement date for the Company's pension and other postretirement benefit plans. The Company sets the discount rate assumptions on an annual basis for each of NRG's retirement related benefit plans at their respective measurement date. This rate is determined by NRG's Investment Committee based on information provided by the Company's actuary. The discount rate assumptions reflect the current rate at which the associated liabilities could be effectively settled at the end of the year. The discount rate assumptions used to determine future pension obligations as of December 31, 2012 and 2011 were based on the Aon Hewitt AA Above Median, or AAM, yield curve, which was designed by Aon Hewitt to provide a means for corporate plan sponsors to value the liabilities of defined benefit and other post retirement benefit plans. The AAM is a hypothetical Aa yield curve represented by a series of annualized individual discount rates from 0.5 to 99 years. Each bond issue is required to have an average rating of AA, when averaging all available ratings by Moody's Investor Services, Standard & Poor's and Fitch. The discount rate assumptions used to determine future pension obligations as of December 31, 2010 were based on the Hewitt Yield Curve, or HYC, which was designed by Hewitt Associates to provide a means for plan sponsors to value the liabilities of their postretirement benefit plans. The HYC is a hypothetical yield curve represented by a series of annualized individual discount rates. Each bond issue underlying the HYC is required to have a rating of Aa or better by Moody's Investor Service, Inc. or a rating of AA or better by Standard & Poor's.
NRG employs a total return investment approach, whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The Investment Committee reviews the asset mix periodically and as the plan assets increase in future years, the Investment Committee may examine other asset classes such as real estate or private equity. NRG employs a building block approach to determining the long-term rate of return for plan assets, with proper consideration given to diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed income are preserved, consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonableness and appropriateness.
The target allocations of NRG's pension plan assets were as follows:

 	2012	 	2011	
U.S. equity	38.5-45.5%	 	38.5-45.5%	
Non-U.S. equity	16.5-28%	 	16.5-19.5%	
U.S. fixed income	30-45%	 	35-45%	
Plan assets are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. equities, as well as among growth, value, small and large capitalization stocks.
NRG's expected future benefit payments for each of the next five years, and in the aggregate for the five years thereafter, are as follows:

 	 	 	Other Postretirement Benefit	
 	Pension
Benefit Payments	 	Benefit Payments	 	Medicare Prescription Drug Reimbursements	
 	(In millions)	
2013	$	44	
 	 	$	9	
 	 	$	—	
 	
2014	47	
 	 	10	
 	 	—	
 	
2015	51	
 	 	11	
 	 	—	
 	
2016	56	
 	 	11	
 	 	—	
 	
2017	61	
 	 	11	
 	 	—	
 	
2018-2022	375	
 	 	63	
 	 	3	

164

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect:

 	1-Percentage-
Point Increase	 	1-Percentage-
Point Decrease	
 	(In millions)	
Effect on total service and interest cost components	$	1	
 	 	$	(1	)	
Effect on postretirement benefit obligation	18	
 	 	(15	)	
STP Defined Benefit Plans
NRG has a 44% undivided ownership interest in STP, as discussed further in Note 26, Jointly Owned Plants. STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. For the years ending December 31, 2012, and 2011 NRG reimbursed STPNOC approximately $15 million and $12 million, respectively, towards its defined benefit plans. In 2013, NRG expects to reimburse STPNOC $17 million for its contributions towards the plans.
The Company has recognized the following in its statement of financial position, statement of operations and accumulated OCI related to its 44% interest in STP:

 	As of December 31,	
 	Pension Benefits	 	Other
Postretirement Benefits	
 	2012	 	2011	 	2012	 	2011	
 	(In millions)	
Funded status — STPNOC benefit plans	$	(76	)	 	$	(67	)	 	$	(56	)	 	$	(49	)	
Net periodic benefit costs	10	
 	 	9	
 	 	8	
 	 	6	
 	
Other changes in plan assets and benefit obligations recognized in other comprehensive income	14	
 	 	15	
 	 	1	
 	 	3	
 	
Defined Contribution Plans
NRG's employees are also eligible to participate in defined contribution 401(k) plans.  Upon completion of the GenOn acquisition, NRG assumed GenOn's defined contribution 401(k) plans and amended the plan covering the majority of employees with NRG 401(k) plan features, effective January 1, 2013. During 2013, the GenOn defined contribution 401(k) plans will be merged into the NRG 401(k) plan.
The Company's contributions to these plans were as follows:

 	Year Ended December 31,	
 	2012 (a)	 	2011	 	2010	
 	(In millions)	
Company contributions to defined contribution plans	$	24	
 	
 	$	24	
 	 	$	28	

(a)	Includes contributions to former GenOn plans for the period of December 15, 2012 to December 31, 2012.	

165

Note 14 — Capital Structure 
For the period from December 31, 2009, to December 31, 2012, the Company had 10,000,000 shares of preferred stock authorized and 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's preferred and common shares issued and outstanding for each period presented:

 	Preferred Stock Issued and Outstanding	 	Common	
 	3.625%	 	4%	 	Issued	 	Treasury	 	Outstanding	
Balance as of December 31, 2009	250,000	
 	 	154,057	
 	 	295,861,759	
 	 	(41,866,451	)	 	253,995,308	
 	
Shares issued under ESPP	—	
 	 	—	
 	 	—	
 	 	120,990	
 	 	120,990	
 	
Shares returned by affiliate of CS	—	
 	 	—	
 	 	—	
 	 	(6,600,000	)	 	(6,600,000	)	
Share repurchases	—	
 	 	—	
 	 	—	
 	 	(8,463,211	)	 	(8,463,211	)	
Shares issued from LTIP	—	
 	 	—	
 	 	442,818	
 	 	—	
 	 	442,818	
 	
4.00% Preferred Stock conversion	—	
 	 	(154,029	)	 	7,701,450	
 	 	—	
 	 	7,701,450	
 	
4.00% Preferred Stock redeemed for cash	—	
 	 	(28	)	 	—	
 	 	—	
 	 	—	
 	
Balance as of December 31, 2010	250,000	
 	 	—	
 	 	304,006,027	
 	 	(56,808,672	)	 	247,197,355	
 	
Shares issued under ESPP	—	
 	 	—	
 	 	—	
 	 	120,127	
 	 	120,127	
 	
Shares issued under LTIP	—	
 	 	—	
 	 	177,693	
 	 	—	
 	 	177,693	
 	
Share repurchases	—	
 	 	—	
 	 	—	
 	 	(19,975,654	)	 	(19,975,654	)	
Balance as of December 31, 2011	250,000	
 	 	—	
 	 	304,183,720	
 	 	(76,664,199	)	 	227,519,521	
 	
Shares issued under ESPP	—	
 	 	—	
 	 	—	
 	 	158,481	
 	 	158,481	
 	
Shares issued under LTIPs	—	
 	 	—	
 	 	996,262	
 	 	—	
 	 	996,262	
 	
Shares issued through GenOn acquisition	—	
 	 	—	
 	 	93,932,634	
 	 	—	
 	 	93,932,634	
 	
Balance as of December 31, 2012	250,000	
 	 	—	
 	 	399,112,616	
 	 	(76,505,718	)	 	322,606,898	
 	
Common Stock
The following table summarizes NRG's common stock reserved for the maximum number of shares potentially issuable based on the conversion and redemption features of outstanding equity instruments and the long-term incentive plans as of December 31, 2012:

Equity Instrument	Common Stock
Reserve Balance	
3.625% Convertible perpetual preferred	16,000,000	
 	
Long-term incentive plans	23,391,552	
 	
Total	39,391,552	
 	
Common stock dividends — On August 15, 2012, NRG paid its first quarterly dividend on the Company's common stock of $0.09 per share. On November 15, 2012, NRG paid a quarterly dividend on the Company's common stock of $0.09 per share. On February 15, 2013, NRG paid a quarterly dividend on the Company's common stock of $0.09 per share.
 Employee Stock Purchase Plan — Under the ESPP eligible employees may elect to withhold up to 10% of their eligible compensation to purchase shares of NRG common stock at 85% of its fair market value on the exercise date. An exercise date occurs each June 30 and December 31. On April 25, 2012, NRG shareholders approved an increase of 1,000,000 shares available for issuance under the ESPP. As of December 31, 2012, there remained 1,018,870 shares of treasury stock reserved for issuance under the ESPP, and in the first quarter of 2013, 61,219 shares of common stock were issued to employee accounts from treasury stock.
Preferred Stock
4% Preferred Stock
The Company's 4% Convertible Perpetual Preferred Stock, or 4% Preferred Stock, had a liquidation preference of $1,000 per share. The 4% Preferred Stock was convertible, at the option of the holder, at any time into shares of NRG's common stock at an initial conversion price of $20.00 per share. In addition, NRG had the ability to redeem, on or after December 20, 2009, and subject to certain limitations, some or all of the 4% Preferred Stock with cash at a redemption price equal to 100% of the liquidation preference, plus accumulated but unpaid dividends, including liquidated damages, if any, to the redemption date. In the fourth quarter of 2009, NRG notified the holders of the Company's intention to redeem the 4% Preferred Stock, and the majority of the holders elected to convert their shares in response to this notification. All conversions and redemptions were completed by January 21, 2010.

166

Redeemable Preferred Stock
3.625% Preferred Stock
On August 11, 2005, NRG issued 250,000 shares of 3.625% Convertible Perpetual Preferred Stock, or 3.625% Preferred Stock, which is treated as Redeemable Preferred Stock, to CS in a private placement. The 3.625% Preferred Stock amount is located after the liabilities but before the stockholders' equity section on the balance sheet, due to the fact that the preferred shares can be redeemed in cash by the stockholder. The 3.625% Preferred Stock has a liquidation preference of $1,000 per share. Holders of the 3.625% Preferred Stock are entitled to receive, out of legally available funds, cash dividends at the rate of 3.625% per annum, or $36.25 per share per year, payable in cash quarterly in arrears commencing on December 15, 2005.
Each share of the 3.625% Preferred Stock is convertible during the 90-day period beginning August 11, 2015, at the option of NRG or the holder. Holders tendering the 3.625% Preferred Stock for conversion shall be entitled to receive, for each share of 3.625% Preferred Stock converted, $1,000 in cash and a number of shares of NRG common stock equal in value to the product of (a) the greater of (i) the difference between the average closing share price of NRG common stock on each of the twenty consecutive scheduled trading days starting on the date thirty exchange business days immediately prior to the conversion date, or the Market Price, and $29.54 and (ii) zero, times (b) 50.77. The number of shares of NRG common stock to be delivered under the conversion feature is limited to 16,000,000 shares. If upon conversion, the Market Price is less than $19.69, then the Holder will deliver to NRG cash or a number of shares of NRG common stock equal in value to the product of (i) $19.69 minus the Market Price, times (ii) 50.77. NRG may elect to make a cash payment in lieu of delivering shares of NRG common stock in connection with such conversion, and NRG may elect to receive cash in lieu of shares of common stock, if any, from the Holder in connection with such conversion. The conversion feature is considered an embedded derivative per ASC 815 that is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815.
If a fundamental change occurs, the holders will have the right to require NRG to repurchase all or a portion of the 3.625% Preferred Stock for a period of time after the fundamental change at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends. The 3.625% Preferred Stock is senior to all classes of common stock, and junior to all of the Company's existing and future debt obligations and all of NRG subsidiaries' existing and future liabilities and capital stock held by persons other than NRG or its subsidiaries.
Note 15 — Investments Accounted for by the Equity Method and Variable Interest Entities 
NRG accounts for the Company's significant investments using the equity method of accounting. NRG's carrying value of equity investments can be impacted by impairments, unrealized gains and losses on derivatives and movements in foreign currency exchange rates, as well as other adjustments.
The following table summarizes NRG's equity method investments as of December 31, 2012:

 	 	 	
Name	Geographic Area	Economic
Interest	
Avenal Solar Holdings LLC	United States	50.0	%	
GenConn Energy LLC	United States	50.0	%	
Saguaro Power Company	United States	50.0	%	
Sherbino I Wind Farm LLC	United States	50.0	%	
Texas Coastal Ventures, LLC	United States	50.0	%	
Sabine CoGen, LP	United States	50.0	%	
Sunora Energy Solutions I LLC
	United States	50.0	%	
Geostellar, Inc.	United States	49.5	%	
Gladstone Power Station	Australia	37.5	%	
Energy Technology Ventures	United States	33.3	%	

 	 	 	 	 	 	 	 	
 	As of December 31,	
 	2012	 	2011	
 	(In millions)	
Undistributed earnings from equity investments	$	149	
 	 	$	150	

167

Variable Interest Entities
NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, but NRG is not the primary beneficiary, under the equity method.
GenConn Energy LLC — Through its subsidiary, NRG Connecticut Peaking Development LLC, NRG owns a 50% interest in GenConn, a limited liability company formed to construct, own and operate two 200MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. Each of these facilities was constructed pursuant to 30-year cost of service type contracts with the Connecticut Light & Power Company. All four units at the GenConn Devon facility reached commercial operation in 2010 and were released to the ISO-NE by July 2010. In June 2011, the GenConn Middletown facility reached commercial operation and was released to the ISO-NE. The project was funded through equity contributions from the owners and non-recourse, project level debt. As of December 31, 2012, NRG had a $125 million equity investment in GenConn. NRG's maximum exposure to loss is limited to its equity investment.
In April 2009, GenConn secured financing for 50% of the Devon and Middletown project construction costs through a seven-year term loan facility, and also entered into a five-year revolving working capital loan and letter of credit facility, which collectively with the term loan is referred to as the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, is $291 million, including $48 million for the working capital facility. In March 2012, the working capital facility was amended to $35 million. As of December 31, 2012, $228 million was outstanding under the GenConn Facility.
As discussed in Note 20, Related Party Transactions, in 2010 and 2011, NRG earned revenues from construction management agreements with Devon and Middletown and interest income from a note receivable with GenConn.
Sherbino I Wind Farm LLC — NRG owns a 50% interest in Sherbino, a joint venture with BP Wind Energy North America Inc. Sherbino is a 150 MW wind farm, which commenced commercial operations in October 2008. In December 2008, Sherbino entered into a 15-year term loan facility which is non-recourse to NRG. As of December 31, 2012, the outstanding principal balance of the term loan facility was $119 million, and is secured by substantially all of Sherbino's assets and membership interests. NRG's maximum exposure to loss is limited to its equity investment, which was $93 million as of December 31, 2012.
Texas Coastal Ventures, LLC — NRG owns a 50% interest in Texas Coastal Ventures, LLC, or TCV, a joint venture with Hilcorp Energy I, L.P., through its subsidiary Petra Nova LLC. Texas Coastal Ventures was formed by Petra Nova and Hilcorp for the purpose of using carbon dioxide captured from flue gas from certain of NRG's coal-generating power plants in the United States Gulf Coast in an enhanced oil recovery process. TCV is managed by the joint venture participants and operated by Hilcorp. TCV entered into service agreements with Petra Nova LLC, which include a management services agreement for the operation and management of the joint venture's pipeline assets, as well as a CO 2  supply agreement having an initial term of twenty years. NRG's maximum exposure to loss is limited to its equity investment, which was $57 million as of December 31, 2012.
Other Equity Investments
Gladstone — Through a joint venture, NRG owns a 37.5% interest in Gladstone, a 1,613 megawatt coal-fueled power generation facility in Queensland, Australia. The power generation facility is managed by the joint venture participants and the facility is operated by NRG. Operating expenses incurred in connection with the operation of the facility are funded by each of the participants in proportion to their ownership interests. Coal is sourced from local mines in Queensland. NRG and the joint venture participants receive their respective share of revenues directly from the off takers in proportion to the ownership interests in the joint venture. Power generated by the facility is primarily sold to an adjacent aluminum smelter, with excess power sold to the Queensland Government owned utility under long term supply contracts. NRG's investment in Gladstone was $322 million as of December 31, 2012.

168

Note 16 — Earnings Per Share 
Basic earnings per common share is computed by dividing net income less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings per share is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period.
Dilutive effect for equity compensation — The outstanding non-qualified stock options, non-vested restricted stock units, deferred stock units and performance units are not considered outstanding for purposes of computing basic earnings per share. However, these instruments are included in the denominator for purposes of computing diluted earnings per share under the treasury stock method.
Dilutive effect for other equity instruments — Prior to its conversion, NRG's 4% Preferred Stock was not considered outstanding for purposes of computing basic earnings per share. However, these instruments were considered for inclusion in the denominator for purposes of computing diluted earnings per share under the if-converted method. The if-converted method is also used to determine the dilutive effect of embedded derivatives in the Company's 3.625% Preferred Stock.
The reconciliation of NRG's basic earnings per share to diluted earnings per share is shown in the following table:

 	Year Ended December 31,	
 	2012	 	2011	 	2010	
 	(In millions, except per share amounts)	
Basic earnings per share attributable to NRG common stockholders	 	 	 	 	 	
Numerator:	 	 	 	 	 	
Net income attributable to NRG Energy, Inc.	$	559	
 	 	$	197	
 	 	$	477	
 	
Preferred stock dividends	(9	)	 	(9	)	 	(9	)	
Net income attributable to NRG Energy, Inc. available to common stockholders	$	550	
 	 	$	188	
 	 	$	468	
 	
Denominator:	 	 	
 	 	 	
Weighted average number of common shares outstanding	232	
 	 	240	
 	 	252	
 	
Basic earnings per share:	 	 	 	 	 	
Net income attributable to NRG Energy, Inc. 	$	2.37	
 	 	$	0.78	
 	 	$	1.86	
 	
Diluted earnings per share attributable to NRG common stockholders	 	 	
 	 	 	
Numerator:	 	 	
 	 	 	
Net income attributable to NRG Energy, Inc. available to common stockholders	$	550	
 	 	$	188	
 	 	$	468	
 	
Denominator:	 	 	 	 	 	
Weighted average number of common shares outstanding	232	
 	 	240	
 	 	252	
 	
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	2	
 	 	1	
 	 	1	
 	
Incremental shares attributable to the assumed conversion features of outstanding preferred stock (if-converted method)	—	
 	 	—	
 	 	1	
 	
Total dilutive shares	234	
 	 	241	
 	 	254	
 	
Diluted earnings per share:	 	 	
 	 	 	
Net income attributable to NRG Energy, Inc. 	$	2.35	
 	 	$	0.78	
 	 	$	1.84	
 	
The following table summarizes NRG's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted earnings per share:

 	Year Ended December 31,	
 	2012	 	2011	 	2010	
 	(In millions of shares)	
Equity compensation	8	
 	
 	7	
 	 	6	
 	
Embedded derivative of 3.625% redeemable perpetual preferred stock	16	
 	
 	16	
 	 	16	
 	
Total	24	
 	 	23	
 	 	22	

169

Note 17 — Segment Reporting 
2012 Business Segment Realignment
Effective in fiscal year 2012, NRG's segment structure and its allocation of corporate expenses were updated to reflect how management currently makes financial decisions and allocates resources. The Company has recast the data from prior periods to reflect this change in reportable segments to conform to the current year presentation. The Company's businesses are primarily segregated based on the Retail Business, conventional power generation, alternative energy businesses and corporate activities.  Within NRG's conventional power generation operations, there are distinct components with separate operating results and management structures for the following geographical regions: Texas, East, South Central, West, and Other, which includes its international businesses, thermal and chilled water business and maintenance services.  The Company's alternative energy businesses include solar and wind assets, electric vehicle services and carbon capture business. 
For the years ended December 31, 2012, 2011, and 2010, there were no customers from whom the Company derived more than 10% of the Company's consolidated revenues.

 	Year Ended December 31, 2012	
 	 	 	Conventional Power Generation	 	 	 	 	 	 	 	 	
 	Retail(a)	 	Texas(a)	 	East(a)(b)	 	South
Central(b)	 	West(b)	 	Other(a)	 	Alternative Energy (a)	 	Corporate	 	Elimination	 	Total	
 	(In millions)	
Operating revenues	$	5,772	
 	 	$	2,074	
 	 	$	854	
 	 	$	807	
 	 	$	259	
 	 	$	320	
 	 	$	153	
 	 	$	17	
 	 	$	(1,834	)	 	$	8,422	
 	
Operating expenses	5,065	
 	 	1,712	
 	 	754	
 	 	695	
 	 	194	
 	 	273	
 	 	86	
 	 	55	
 	 	(1,819	)	 	7,015	
 	
Depreciation and amortization	162	
 	 	458	
 	 	137	
 	 	93	
 	 	12	
 	 	17	
 	 	59	
 	 	12	
 	 	—	
 	 	950	
 	
Acquisition-related transaction and integration costs	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	107	
 	 	—	
 	 	107	
 	
Operating income/(loss)	545	
 	 	(96	)	 	(37	)	 	19	
 	 	53	
 	 	30	
 	 	8	
 	 	(157	)	 	(15	)	 	350	
 	
Equity in earnings/(loss) of unconsolidated affiliates	—	
 	 	—	
 	 	16	
 	 	—	
 	 	7	
 	 	13	
 	 	3	
 	 	(2	)	 	—	
 	 	37	
 	
Impairment charge on investment	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(2	)	 	—	
 	 	(2	)	
Bargain purchase gain related to GenOn acquisition	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	560	
 	 	—	
 	 	560	
 	
Other income, net	—	
 	 	2	
 	 	2	
 	 	1	
 	 	1	
 	 	4	
 	 	1	
 	 	26	
 	 	(18	)	 	19	
 	
Loss on debt extinguishment and refinancing expense	

 	

 	 	

 	

 	 	
 	
 	 	(51	)	 	
 	
 	 	(51	)	
Interest expense	(4	)	 	—	
 	 	(20	)	 	(18	)	 	(2	)	 	(11	)	 	(46	)	 	(578	)	 	18	
 	 	(661	)	
Income/(loss) before income taxes	541	
 	 	(94	)	 	(39	)	 	2	
 	 	59	
 	 	36	
 	 	(34	)	 	(204	)	 	(15	)	 	252	
 	
Income tax expense/(benefit)	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	3	
 	 	—	
 	 	(330	)	 	—	
 	 	(327	)	
Net income/(loss)	$	541	
 	 	$	(94	)	 	$	(39	)	 	$	2	
 	 	$	59	
 	 	$	33	
 	 	$	(34	)	 	$	126	
 	 	$	(15	)	 	$	579	
 	
Less: Net income attributable to noncontrolling interest	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	20	
 	 	$	—	
 	 	$	—	
 	 	$	20	
 	
Net income/(loss) attributable to NRG Energy, Inc.	$	541	
 	 	$	(94	)	 	$	(39	)	 	$	2	
 	 	$	59	
 	 	$	33	
 	 	$	(54	)	 	$	126	
 	 	$	(15	)	 	$	559	

Balance sheet	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	
Equity investments in affiliates	$	—	
 	 	$	—	
 	 	$	131	
 	 	$	19	
 	 	$	27	
 	 	$	322	
 	 	$	167	
 	 	$	10	
 	 	$	—	
 	 	$	676	
 	
Capital expenditures  (c)	22	
 	 	118	
 	 	70	
 	 	36	
 	 	244	
 	 	41	
 	 	3,153	
 	 	9	
 	 	—	
 	 	3,693	
 	
Goodwill	231	
 	 	1,713	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	12	
 	 	—	
 	 	—	
 	 	1,956	
 	
Total assets	$	3,122	
 	 	$	10,988	
 	 	$	5,249	
 	 	$	1,969	
 	 	$	1,825	
 	 	$	794	
 	 	$	6,157	
 	 	$	29,042	
 	 	$	(24,018	)	 	$	35,128	

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Includes intersegment sales of:	$	5	
 	 	$	1,657	
 	 	$	73	
 	 	$	—	
 	 	$	—	
 	 	$	69	
 	 	$	20	
 	 	$	10	
 	
(b) Includes GenOn results for the period December 15, 2012 to December 31, 2012.
(c) Includes accruals.

170

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Year Ended December 31, 2011	
 	 	 	Conventional Power Generation	 	 	 	 	 	 	 	 	
 	Retail(d)(e)	 	Texas(d)	 	East(d)	 	South
Central	 	West	 	Other(d)	 	Alternative Energy (d)	 	Corporate	 	Elimination	 	Total	
 	(In millions)	
Operating revenues	$	5,642	
 	 	$	2,832	
 	 	$	924	
 	 	$	817	
 	 	$	149	
 	 	$	323	
 	 	$	44	
 	 	$	11	
 	 	$	(1,663	)	 	$	9,079	
 	
Operating expenses	5,113	
 	 	1,910	
 	 	858	
 	 	703	
 	 	92	
 	 	282	
 	 	63	
 	 	30	
 	 	(1,663	)	 	7,388	
 	
Depreciation and amortization	159	
 	 	463	
 	 	118	
 	 	89	
 	 	10	
 	 	14	
 	 	31	
 	 	12	
 	 	—	
 	 	896	
 	
Impairment charge on emission allowances	—	
 	 	160	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	160	
 	
Operating income/(loss)	370	
 	 	299	
 	 	(52	)	 	25	
 	 	47	
 	 	27	
 	 	(50	)	 	(31	)	 	—	
 	 	635	
 	
Equity in earnings of unconsolidated affiliates	—	
 	 	—	
 	 	11	
 	 	—	
 	 	9	
 	 	9	
 	 	6	
 	 	—	
 	 	—	
 	 	35	
 	
Impairment charge on investment	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(495	)	 	—	
 	 	(495	)	
Other income, net	—	
 	 	1	
 	 	2	
 	 	2	
 	 	—	
 	 	5	
 	 	3	
 	 	21	
 	 	(15	)	 	19	
 	
Loss on debt extinguishment and refinancing expense	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(175	)	 	—	
 	 	(175	)	
Interest (expense)/income	(4	)	 	16	
 	 	(47	)	 	(41	)	 	(2	)	 	(15	)	 	(16	)	 	(571	)	 	15	
 	 	(665	)	
Income/(loss) before income taxes	366	
 	 	316	
 	 	(86	)	 	(14	)	 	54	
 	 	26	
 	 	(57	)	 	(1,251	)	 	—	
 	 	(646	)	
Income tax (benefit)/expense	(3	)	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	7	
 	 	—	
 	 	(847	)	 	—	
 	 	(843	)	
Net income/(loss)	369	
 	 	316	
 	 	(86	)	 	(14	)	 	54	
 	 	19	
 	 	(57	)	 	(404	)	 	—	
 	 	197	

Balance sheet	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	
Equity investments in affiliates	$	—	
 	 	$	—	
 	 	$	136	
 	 	$	—	
 	 	$	28	
 	 	$	308	
 	 	$	168	
 	 	$	—	
 	 	$	—	
 	 	$	640	
 	
Capital expenditures  (f)	23	
 	 	99	
 	 	188	
 	 	25	
 	 	281	
 	 	40	
 	 	1,809	
 	 	137	
 	 	—	
 	 	2,602	
 	
Goodwill	173	
 	 	1,713	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	1,886	
 	
Total assets	$	2,725	
 	 	$	13,164	
 	 	$	2,042	
 	 	$	1,436	
 	 	$	669	
 	 	$	1,006	
 	 	$	3,143	
 	 	$	19,732	
 	 	$	(17,017	)	 	$	26,900	

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(d) Includes intersegment sales of:	$	5	
 	 	$	1,586	
 	 	$	43	
 	 	$	—	
 	 	$	—	
 	 	$	18	
 	 	$	16	
 	 	$	—	
 	
(e) Includes Green Mountain Energy results and Energy Plus results for the period October 1, 2011 to December 31, 2011.
(f) Includes accruals.

 	Year Ended December 31, 2010	
 	 	 	Conventional Power Generation	 	 	 	 	 	 	 	 	
 	Retail(g)(h)	 	Texas(g)	 	East	 	South
Central	 	West	 	Other(g)	 	Alternative Energy (g)	 	Corporate	 	Elimination	 	Total	
 	 	 	(In millions)	
Operating revenues	$	5,055	
 	 	$	3,040	
 	 	$	1,025	
 	 	$	608	
 	 	$	138	
 	 	$	301	
 	 	$	41	
 	 	$	1	
 	 	$	(1,360	)	 	$	8,849	
 	
Operating expenses	4,547	
 	 	1,749	
 	 	847	
 	 	506	
 	 	98	
 	 	260	
 	 	38	
 	 	41	
 	 	(1,360	)	 	6,726	
 	
Depreciation and amortization	127	
 	 	466	
 	 	122	
 	 	67	
 	 	9	
 	 	12	
 	 	27	
 	 	8	
 	 	—	
 	 	838	
 	
Gain on sale of asset	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	23	
 	 	—	
 	 	23	
 	
Operating income/(loss)	381	
 	 	825	
 	 	56	
 	 	35	
 	 	31	
 	 	29	
 	 	(24	)	 	(25	)	 	—	
 	 	1,308	
 	
Equity in earnings/(loss) of
unconsolidated affiliates	—	
 	 	—	
 	 	1	
 	 	—	
 	 	6	
 	 	24	
 	 	14	
 	 	(1	)	 	—	
 	 	44	
 	
Other income, net	—	
 	 	2	
 	 	4	
 	 	1	
 	 	1	
 	 	18	
 	 	—	
 	 	24	
 	 	(17	)	 	33	
 	
Loss on debt extinguishment and refinancing expense	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(2	)	 	—	
 	 	(2	)	
Interest (expense)/income	(5	)	 	79	
 	 	(57	)	 	(46	)	 	(2	)	 	(14	)	 	(13	)	 	(589	)	 	17	
 	 	(630	)	
Income/(loss) before income taxes	376	
 	 	906	
 	 	4	
 	 	(10	)	 	36	
 	 	57	
 	 	(23	)	 	(593	)	 	—	
 	 	753	
 	
Income tax expense	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	17	
 	 	—	
 	 	260	
 	 	—	
 	 	277	
 	
Net income/(loss)	376	
 	 	906	
 	 	4	
 	 	(10	)	 	36	
 	 	40	
 	 	(23	)	 	(853	)	 	—	
 	 	476	
 	
Less: Net loss attributable to noncontrolling interest	—	
 	 	(1	)	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(1	)	
Net income/(loss) attributable to NRG Energy, Inc . 	376	
 	 	907	
 	 	4	
 	 	(10	)	 	36	
 	 	40	
 	 	(23	)	 	(853	)	 	—	
 	 	477	

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(g) Includes intersegment sales of:	$	2	
 	 	$	1,304	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	25	
 	 	$	23	
 	 	$	—	
 	
(h) Includes Green Mountain Energy results for the period November 5, 2010 to December 31, 2010.

171

Note 18 — Income Taxes 
The income tax provision from continuing operations consisted of the following amounts:

 	Year Ended December 31,	
 	2012	 	2011	 	2010	
 	(In millions, except percentages)	
Current	 	 	 	 	 	
U.S. Federal	$	—	
 	 	$	(538	)	 	$	211	
 	
State	20	
 	 	10	
 	 	35	
 	
Foreign	13	
 	 	16	
 	 	23	
 	
 	33	
 	 	(512	)	 	269	
 	
Deferred	 	 	 	 	 	
U.S. Federal	(326	)	 	(317	)	 	23	
 	
State	(24	)	 	(5	)	 	(9	)	
Foreign	(10	)	 	(9	)	 	(6	)	
 	(360	)	 	(331	)	 	8	
 	
Total income tax (benefit)/expense	$	(327	)	 	$	(843	)	 	$	277	
 	
Effective tax rate	(129.8	)%	 	130.5	%	 	36.8	%	
The following represents the domestic and foreign components of income/(loss) before income tax (benefit)/expense:

 	Year Ended December 31,	
 	2012	 	2011	 	2010	
 	(In millions)	
U.S. 	$	223	
 	 	$	(680	)	 	$	691	
 	
Foreign	29	
 	 	34	
 	 	62	
 	
Total	$	252	
 	 	$	(646	)	 	$	753	

172

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

 	Year Ended December 31,	
 	2012	 	2011	 	2010	
 	(In millions, except percentages)	
Income/(Loss) Before Income Taxes	$	252	
 	 	$	(646	)	 	$	753	
 	
Tax at 35%	88	
 	 	(226	)	 	264	
 	
State taxes, net of federal benefit	13	
 	 	15	
 	 	18	
 	
Foreign operations	(24	)	 	(3	)	 	(3	)	
Federal and state tax credits	(158	)	 	(1	)	 	(7	)	
Valuation allowance	5	
 	 	(63	)	 	(34	)	
Expiration/utilization of capital losses	—	
 	 	45	
 	 	—	
 	
Reversal of valuation allowance on expired/utilized capital losses	—	
 	 	(45	)	 	—	
 	
Impact of non-taxable equity earnings	(7	)	 	—	
 	 	—	
 	
Bargain purchase gain related to GenOn acquisition	(196	)	 	—	
 	 	—	
 	
Change in state effective tax rate	(12	)	 	—	
 	 	—	
 	
Foreign earnings	—	
 	 	4	
 	 	17	
 	
Non-deductible interest	—	
 	 	—	
 	 	4	
 	
Interest accrued on uncertain tax positions	2	
 	 	2	
 	 	25	
 	
Production tax credit	(14	)	 	(14	)	 	(11	)	
Reversal of uncertain tax position reserves	(13	)	 	(561	)	 	—	
 	
Other	(11	)	 	4	
 	 	4	
 	
Income tax (benefit)/expense	$	(327	)	 	$	(843	)	 	$	277	
 	
Effective income tax rate	(129.8	)%	 	130.5	%	 	36.8	%	
The effective tax rate for the year ended December 31, 2012, differs from the statutory rate of 35% primarily due to a benefit of $196 million resulting from the gain on bargain purchase from the GenOn acquisition and the generation of ITCs from the Company's Agua Caliente solar project in Arizona of $158 million and production, tax credits, or PTCs, generated from Texas wind facilities of $14 million.
The effective tax rate for the year ended December 31, 2011, differs from the statutory rate of 35% primarily due to a benefit of $633 million resulting from the resolution of the federal tax audit. The benefit is predominantly due to the recognition of previously uncertain tax benefits that were settled upon audit in 2011 and that were mainly composed of net operating losses of $536 million which had been classified as capital loss carryforwards for financial statement purposes.
The effective income tax rate for the year ended December 31, 2010, differs from the statutory rate of 35% primarily due to the impact of state and local income taxes and interest on uncertain tax positions, which were partially offset by the reduction in the valuation allowance resulting from realized capital gains as well as federal and state tax credits generated during the current year.

173

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

 	As of December 31,	
 	2012	 	2011	
 	(In millions)	
Deferred tax liabilities:	 	 	 	
Discount/premium on notes	$	—	
 	 	$	7	
 	
Emissions allowances	15	
 	 	33	
 	
Difference between book and tax basis of property	123	
 	 	1,604	
 	
Derivatives, net	323	
 	 	244	
 	
Goodwill	165	
 	 	139	
 	
Cumulative translation adjustments	19	
 	 	27	
 	
Intangibles amortization (excluding goodwill)	85	
 	 	229	
 	
Investment in projects	52	
 	 	—	
 	
Other	—	
 	 	8	
 	
Total deferred tax liabilities	782	
 	 	2,291	
 	
Deferred tax assets:	 	 	 	
Deferred compensation, pension, accrued vacation and other reserves	232	
 	 	80	
 	
Discount / premium on notes	156	
 	 	—	
 	
Investment in projects	—	
 	 	72	
 	
Differences between book and tax basis of contracts	343	
 	 	225	
 	
Pension and other postretirement benefits	274	
 	 	137	
 	
Equity compensation	57	
 	 	36	
 	
Bad debt reserve	14	
 	 	15	
 	
U.S. capital loss carryforwards	1	
 	 	1	
 	
U.S. Federal net operating loss carryforwards	605	
 	 	84	
 	
Foreign net operating loss carryforwards	89	
 	 	70	
 	
State net operating loss carryforwards	149	
 	 	53	
 	
Foreign capital loss carryforwards	1	
 	 	1	
 	
Deferred financing costs	33	
 	 	—	
 	
Federal and state tax credits	258	
 	 	64	
 	
Federal benefit on state uncertain tax positions	18	
 	 	20	
 	
Other	5	
 	 	—	
 	
Total deferred tax assets	2,235	
 	 	858	
 	
Valuation allowance	(191	)	 	(83	)	
Net deferred tax assets	2,044	
 	 	775	
 	
Net deferred tax asset (liability)	$	1,262	
 	 	$	(1,516	)	
The following table summarizes NRG's net deferred tax position:

 	As of December 31,	
 	2012	 	2011	
 	(In millions)	
Current deferred tax asset (liability)	$	56	
 	 	$	(127	)	
Non-current net deferred tax asset (liability)	1,206	
 	 	(1,389	)	
Net deferred tax asset (liability)	$	1,262	
 	 	$	(1,516	)	

174

Tax Receivable and Payable
        As of December 31, 2012, NRG recorded a current tax payable of $31 million that represents a tax liability due for Federal taxes of $6 million, domestic state taxes of $17 million, as well as foreign taxes payable of $8 million. NRG has a domestic tax receivable of $174 million, of which $96 million relates to an IRS refund for prior years, $58 million relates to federal cash grants applied for eligible solar energy projects under development in California, New Jersey and Maryland, $20 million is related to property tax refunds due to the New York State Empire Zone program. In addition, a $56 million non-current asset for Empire Zone credits generated in 2010 through 2012, that are being deferred pursuant to New York State law, has been recorded.
Deferred tax assets and valuation allowance
        Net deferred tax balance — As of December 31, 2012, and 2011, NRG recorded a net deferred tax asset (liability) of $1.4 billion and ($1.4 billion), 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, net of valuation allowances. In arriving at this conclusion to utilize projections of future profit before tax in our estimate of future taxable income, we considered the profit before tax generated in recent years. Based on our assessment of positive and negative evidence, including available tax planning strategies, NRG believes that it is more likely than not that a benefit will not be realized on $191 million and $83 million of tax assets as of December 31, 2012 and 2011, respectively, thus a valuation allowance has been recorded. The Company estimates it will need to generate future taxable income of approximately $3.5 billion, to fully realize the net federal and state unitary deferred tax asset before expiration.
In connection with the accounting for the GenOn acquisition, the Company recorded the realizable deferred tax assets and liabilities acquired, primarily consisting of net operating losses and other temporary differences. In addition, the excess of GenOn's historical tax basis of assets and liabilities over the amount assigned to the fair value of the assets acquired and liabilities assumed generated deferred tax assets and liabilities that were recorded on the acquisition date.         
NOL carryforwards — At December 31, 2012, the Company had domestic NOLs consisting of carryforwards for federal income tax purposes of $605 million and cumulative state NOLs of $149 million. In addition, NRG has cumulative foreign NOL carryforwards of $89 million of which $17 million will expire starting 2013 through 2020 and of which $72 million do not have an expiration date.
        Valuation allowance — As of December 31, 2012, the Company's tax effected valuation allowance was $191 million, consisting of $102 million for state deferred tax assets, primarily operating loss carryovers, and $89 million for foreign deferred tax assets, primarily operating loss carryovers for which there is insufficient earnings to support future realization.
Uncertain tax benefits
NRG has identified uncertain tax benefits whose after-tax value was $193 million that if recognized, would impact the Company's income tax expense.
As of December 31, 2012, and 2011, NRG has recorded a non-current tax liability of $72 million and $58 million, respectively. As of December 31, 2012 and 2011, the balance primarily related to positions taken on various state returns, including accrued interest.
The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense. During the year ended December 31, 2012, the Company accrued interest of $3 million. For the year ended December 31, 2011, the Company recognized a benefit of $32 million in interest and penalties and accrued interest of $2 million. As of December 31, 2012, and 2011, NRG had accrued interest and penalties related to these uncertain tax benefits of $15 million and $12 million, respectively.
        Tax jurisdictions — NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia. Prior to the GenOn acquisition, the Company was not subject to U.S. federal income tax examinations for years prior to 2007. As a result of the acquisition, the Company is no longer subject to U.S. federal income tax examinations for years prior to 2002. With few exceptions, state and local income tax examinations are no longer open for years before 2003. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2004.
During 2011, the Company settled the Internal Revenue Service's audit examination for the years 2004 through 2006 and recognized a benefit of $633 million. The benefit is predominantly due to the recognition of previously uncertain tax benefits mainly composed of net operating losses of $536 million which had been classified as capital loss carryforwards for financial statement purposes. The Company continues to be under examination for various state jurisdictions for multiple years.

175

The following table reconciles the total amounts of uncertain tax benefits:

 	As of December 31,	
 	2012	 	2011	
 	(In millions)	
Balance as of January 1	$	178	
 	 	$	663	
 	
Increase due to current year positions	21	
 	 	12	
 	
Decrease due to current year positions	(3	)	 	(6	)	
Increase due to prior year positions	13	
 	 	6	
 	
Decrease due to prior year positions	(21	)	 	(2	)	
Increase due to acquisitions	5	
 	 	—	
 	
Decrease due to settlements and payments	—	
 	 	(495	)	
Uncertain tax benefits as of December 31	$	193	
 	 	$	178	
 	
Included in the balance at December 31, 2012, are $36 million of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductions. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash or use of net operating loss carryforwards to an earlier period.
Note 19 — Stock-Based Compensation 
NRG Energy, Inc. Long-Term Incentive Plan
As of December 31, 2012, and 2011, a total of 22,000,000 shares of NRG common stock were authorized for issuance under the NRG LTIP, subject to adjustments in the event of reorganization, recapitalization, stock split, reverse stock split, stock dividend, and a combination of shares, merger or similar change in NRG's structure or outstanding shares of common stock. There were 7,580,318 and 7,957,697 shares of common stock remaining available for grants under the NRG LTIP as of December 31, 2012, and 2011, respectively.
GenOn Acquisition
Effective December 14, 2012, in connection with the GenOn acquisition, as discussed in Note 3, Business Acquisitions and Dispositions,  NRG assumed the GenOn Energy, Inc. 2010 Omnibus Incentive Plan, and the name was changed to the NRG 2010 Stock Plan for GenOn Employees, or the NRG GenOn LTIP. As of December 31, 2012, 5,558,390 shares of NRG common stock were authorized for issuance under the NRG GenOn LTIP, and there were 2,126,892 shares of common stock remaining available for grants under the NRG GenOn LTIP. In addition, NRG assumed certain other terminated GenOn plans, under which NRG will not grant any further awards. All outstanding awards under the NRG GenOn LTIP and the terminated plans were appropriately adjusted based on the Exchange Ratio, and remain subject to the terms and conditions of the applicable plans prior to the acquisition.
In addition, upon completion of the GenOn acquisition, the following occurred to GenOn's outstanding stock-based incentive awards: (i) each outstanding and unvested RSU that was granted under the GenOn plans before 2012 vested in full and was exchanged for shares of NRG common stock in the acquisition based on the Exchange Ratio; (ii) each outstanding and unvested GenOn NQSO that was granted under the GenOn plans before 2012 vested in full and converted into an option to purchase NRG common stock; (iii) each outstanding and unvested RSU that was granted under the GenOn plans in 2012, was converted into an unvested RSU of NRG, and (iv) each outstanding and unvested GenOn NQSO that was granted under the GenOn plans during 2012 was converted into an NQSO to purchase NRG common stock on the same vesting schedule.
Under the acquisition method of accounting, GenOn employee NQSOs and RSUs which vested upon close of the acquisition were measured and recorded at acquisition-date fair value, resulting in additional purchase price consideration of $28 million. As of December 14, 2012, unvested NQSOs that were converted to options to purchase NRG common stock and RSUs that were converted to NRG RSUs were recorded in NRG's consolidated balance sheet.
Non-Qualified Stock Options
NQSOs granted under the NRG LTIP and the NRG GenOn LTIP typically have three-year graded vesting schedules beginning on the grant date and become exercisable at the end of the requisite service period. NRG recognizes compensation costs for NQSOs over the requisite service period for the entire award. The maximum contractual term is ten years for 4.8 million of NRG's outstanding NQSOs, and six years for the remaining 1.9 million NQSOs. No NQSOs were granted in 2012.

176

The following table summarizes the Company's NQSO activity and changes during the year:

 	Shares	 	Weighted
Average
Exercise Price	 	Weighted
Average
Remaining
Contractual Term
(In years)	 	Aggregate
Intrinsic Value
(In millions)	
 	(In whole)	 	 	 	 	
Outstanding at December 31, 2011	5,583,189	
 	 	$	22.93	
 	 	4	
 	 	$	7	
 	
GenOn acquired	2,169,689	
 	 	41.44	
 	 	 	 	 	
Forfeited	(999,162	)	 	23.94	

 	
Exercised	(75,831	)	 	18.63	

 	
Outstanding at December 31, 2012	6,677,885	
 	 	28.85	
 	 	4	
 	 	17	
 	
Exercisable at December 31, 2012	5,221,523	
 	 	31.19	
 	 	3	
 	 	13	
 	
The following table summarizes the weighted average grant date fair value of options granted, the total intrinsic value of options exercised, and the cash received from the exercises of options:

 	Year Ended December 31,	
 	2012	 	2011	 	2010	
 	(In millions, except for weighted average)	
Weighted average grant date fair value per option granted	$	—	
 	 	$	8.73	
 	 	$	10.22	
 	
Total intrinsic value of options exercised	0.3	
 	 	0.2	
 	 	0.3	
 	
Cash received from options exercised	1	
 	 	2	
 	 	2	
 	
The fair value of the Company's NQSOs is estimated on the date of grant using the Black-Scholes option-pricing model. Significant assumptions used in the fair value model with respect to the Company's NQSOs are summarized below:

 	Year Ended December 31,	
 	2011	 	2010	
Expected volatility	42.38%-42.57%	
 	 	41.28%-42.57%	
Expected term (in years)	6	
 	 	6-6.5	
Risk free rate	1.42%-2.71%	
 	 	1.54%-3.01%	
For the years ended December 31, 2011, and 2010, expected volatility is calculated based on NRG's historical stock price volatility data over the period commensurate with the expected term of the stock option. Typically, the expected term for the Company's NQSOs is based on the simple average of the contractual term and vesting term. The Company uses this simplified method as it does not have sufficient historical exercise data to provide a reasonable basis upon which to estimate the expected term.
Restricted Stock Units
Typically, RSUs granted under the Company's LTIPs fully vest three years from the date of issuance. Fair value of the RSUs is based on the closing price of NRG common stock on the date of grant. The following table summarizes the Company's non-vested RSU awards and changes during the year:

 	Units	 	Weighted Average
Grant-Date Fair
Value per Unit	
 	(In whole)	
Non-vested at December 31, 2011	2,342,515	
 	 	$	23.54	
 	
GenOn acquired (a)	707,632	
 	 	23.00	
 	
Granted	717,235	
 	 	17.90	
 	
Forfeited	(290,500	)	 	21.05	
 	
Vested	(868,331	)	 	26.08	
 	
Non-vested at December 31, 2012	2,608,551	
 	 	21.28	
 	
(a) Excludes 346,613 GenOn RSUs that vested in full and were exchanged for shares of NRG common stock in the acquisition.

177

The total fair value of RSUs vested during the years ended December 31, 2012, 2011, and 2010, was $18 million, $2 million and $9 million, respectively. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2012, 2011, and 2010 was $17.90, $21.22, and $22.78, respectively.
Deferred Stock Units
DSUs represent the right of a participant to be paid one share of NRG common stock at the end of a deferral period established under the terms of the award. DSUs granted under the Company's LTIPs are fully vested at the date of issuance. Fair value of the DSUs, which is based on the closing price of NRG common stock on the date of grant, is recorded as compensation expense in the period of grant.
The following table summarizes the Company's outstanding DSU awards and changes during the year:

 	Units	 	Weighted Average
Grant-Date Fair
Value per Unit	
 	(In whole)	
Outstanding at December 31, 2011	373,684	
 	 	$	20.07	
 	
GenOn acquired	292,377	
 	 	23.00	
 	
Granted	106,027	
 	 	16.33	
 	
Conversions	(74,573	)	 	18.35	
 	
Outstanding at December 31, 2012	697,515	
 	 	20.91	
 	
The aggregate intrinsic values for DSUs outstanding as of December 31, 2012, 2011, and 2010 were approximately $15 million, $8 million, and $7 million respectively. The aggregate intrinsic values for DSUs converted to common stock for the years ended December 31, 2012, 2011, and 2010 were $1.4 million, $0.4 million and $0.7 million, respectively. The weighted average grant date fair value of DSUs granted during the years ended December 31, 2012, 2011, and 2010 was $16.33, $24.31 and $22.18, respectively.
Market Stock Units
MSUs are restricted grants where the quantity of shares increases and decreases alongside the Company's Total Shareholder Return, or TSR. Each MSU represents the potential to receive NRG common stock after the completion of three years of service from the date of grant. The number of shares of NRG common stock to be paid (if any) as of the vesting date for each MSU will depend on the TSR. The number of shares of common stock to be paid as of the vesting date for each MSU is equal to: (i) one half of one share of common stock if the TSR has decreased by no more than 50% of the value of the common stock on the date of grant; (ii) one share of common stock, if the TSR equals the value of the common stock on the date of grant; and (iii) two shares of common stock if the TSR is 200% or greater of the value of the common stock on the date of grant. If the TSR is less than 50% of the value of the common stock on the date of grant, no common stock will be paid. If the TSR is between 50% and 200%, shares awarded are interpolated. The value of the common stock on the date of grant is based on the 20-day average of the common stock closing price. 
The following table summarizes the Company's non-vested MSU awards and changes during the year:

 	Units	 	Weighted Average
Grant-Date Fair
Value per Unit	
 	(in whole)	
Non-vested at December 31, 2011	60,000	
 	 	$	27.59	
 	
Granted	1,138,020	
 	 	22.11	
 	
Vested	(19,240	)	 	24.92	
 	
Forfeited	(174,860	)	 	21.89	
 	
Non-vested at December 31, 2012	1,003,920	
 	 	22.43	
 	
The weighted average grant date fair value of MSUs granted during the years ended December 31, 2012, and 2011, was $22.11 and $27.59, respectively. No MSUs were granted in 2010.

178

The fair value of MSUs is estimated on the date of grant using a Monte Carlo simulation model and expensed over the service period, which equals the vesting period. Significant assumptions used in the fair value model with respect to the Company's MSUs are summarized below:

 	2012	 	2011	
Expected volatility	29.60%-35.98%	
 	 	25.42%-52.30%	
Expected term (in years)	3	
 	 	1-3	
Risk free rate	0.29%-0.40%	
 	 	0.13%-0.33%	
For the years ended December 31, 2012 and 2011, expected volatility is calculated based on NRG's historical stock price volatility data over the period commensurate with the expected term of the MSU, which equals the vesting period.
Performance Units
PUs granted under the Company's LTIP fully vest three years from the date of issuance. PUs are paid out upon vesting if the Measurement Price is equal to or greater than Threshold Price. The Threshold Price, Target Price and Maximum Price are determined on the date of issuance. The payout for each PU will be equal to: (i) a pro-rata amount between 0.5 and 1 share of common stock, if the Measurement Price is equal to or greater than the target Threshold Price but less than the Target Price; (ii) one share of common stock, if the Measurement Price equals the Target Price; (iii) a pro-rata amount between one and two shares of common stock, if the Measurement Price is greater than the Target Price but less than the Maximum Price; and (iv) two shares of common stock, if the Measurement Price is equal to, or greater than, the Maximum Price. 
The following table summarizes the Company's non-vested PU awards and changes during the year:

 	Outstanding
Units	 	Weighted Average
Grant-Date Fair
Value per Unit	
 	(In whole)	
Non-vested at December 31, 2011	1,039,500	
 	 	$	21.95	
 	
Forfeited	(392,300	)	 	22.05	
 	
Non-vested at December 31, 2012	647,200	
 	 	21.88	
 	
The weighted average grant date fair value of PUs granted during the years ended December 31, 2011, and 2010 was $20.80 and $22.70, respectively. No PUs were granted in 2012.
The fair value of PUs is estimated on the date of grant using a Monte Carlo simulation model and expensed over the service period, which equals the vesting period. Significant assumptions used in the fair value model with respect to the Company's PUs are summarized below:

 	Year ended December 31,	
 	2011	 	2010	
Expected volatility	46.96%-53.15%	 	44.77%-53.81%	
Expected term (in years)	3	 	3-5    	
Risk free rate	0.50%-1.41%	 	0.59%-1.66%	
For the years ended December 31, 2011 and 2010, expected volatility is calculated based on NRG's historical stock price volatility data over the period commensurate with the expected term of the PU, which equals the vesting period.

179

Supplemental Information
The following table summarizes NRG's total compensation expense recognized for the years presented as well as total non-vested compensation costs not yet recognized and the period over which this expense is expected to be recognized as of December 31, 2012, for each of the five types of awards issued under the LTIPs. Minimum tax withholdings of $6 million, $1 million, and $4 million for the years ended December 31, 2012, 2011, and 2010, respectively, are reflected as a reduction to Additional Paid-in Capital on the Company's Consolidated Balance Sheet, and are reflected as operating activities on the Company's Consolidated Statement of Cash Flows.

 	 	 	 	 	 	 	Non-vested Compensation Cost	
 	Compensation Expense	 	Unrecognized
Total Cost	 	Weighted Average
Recognition Period
Remaining
(In years)	
 	Year Ended December 31	 	As of December 31	
Award	2012	 	2011	 	2010	 	2012	 	2012	
 	(In millions, except weighted average data)	
NQSOs	$	6	
 	 	$	8	
 	 	$	8	
 	 	$	5	
 	 	$	1.1	
 	
RSUs	21	
 	 	12	
 	 	15	
 	 	26	
 	 	1.9	
 	
DSUs	2	
 	 	2	
 	 	1	
 	 	—	
 	 	—	
 	
MSUs	7	
 	 	—	
 	 	—	
 	 	18	
 	 	2.0	
 	
PUs	4	
 	 	5	
 	 	6	
 	 	—	
 	 	0.6	
 	
Total	$	40	
 	 	$	27	
 	 	$	30	
 	 	$	49	

Tax benefit recognized	$	8	
 	 	$	1	
 	 	$	2	

 	
Note 20 — Related Party Transactions 
The following table summarizes NRG's material related party transactions with affiliates that are included in the Company's operating revenues, operating costs and other income and expense:

 	Year Ended December 31,	
 	2012	 	2011	 	2010	
 	(In millions)	
Revenues from Related Parties Included in Operating Revenues	 	 	 	 	 	
Gladstone	$	7	
 	
 	$	7	
 	 	$	3	
 	
GenConn (a)	—	
 	
 	3	
 	 	5	
 	
Total	$	7	
 	
 	$	10	
 	 	$	8	
 	
Interest income from Related Parties Included in Other Income and Expense	 	
 	 	 	 	
GenConn (a)	$	—	
 	
 	$	1	
 	 	$	3	
 	
Kraftwerke Schkopau GBR (b)	2	
 	
 	4	
 	 	4	
 	
Total	$	2	
 	
 	$	5	
 	 	$	7	

(a)	The period in 2011 is from January 1, 2011 to June 30, 2011.	
 	 	
(b)	The period in 2012 is from January 1, 2012 to July 17, 2012.	
Gladstone — NRG provides services to Gladstone, an equity method investment, under an O&M agreement. Fees for services under this contract primarily include recovery of NRG's costs of operating the plant as approved in the annual budget, as well as a base monthly fee.
GenConn — Under a construction management agreement, or CMA, with GenConn, NRG had received fees for management, design and construction services. The construction at GenConn was completed in June 2011. In addition, NRG entered into a loan agreement with GenConn during 2009, pursuant to which it received interest income, which was converted into equity during 2011. See further discussion in Note 15,  Investments Accounted for by the Equity Method and Variable Interest Entities.
Kraftwerke Schkopau GBR — SEG had a loan agreement with Kraftwerke Schkopau GBR, a partnership between Saale and E.ON Kraftwerke GmbH, pursuant to which NRG received interest income. On July 17, 2012, the Company completed the sale of its 100% interest in SEG, as discussed in Note 3,  Business Acquisitions and Dispositions .

180

Conemaugh and Keystone facilities — The Company operates the Conemaugh and Keystone facilities under five-year agreements that expire in December 2015 that, subject to certain provisions and notifications, could be terminated annually with one year's notice. The Company is reimbursed by the other owners for the cost of direct services provided to the Conemaugh and Keystone facilities. Additionally, the Company received fees of $1 million during 2012. These fees, which are recorded in O&M expense in the consolidated statements of operations, are primarily to cover GenOn REMA LLC's administrative support costs of providing these services.
Other Transactions — The Company paid approximately $36 million  to Sunora Energy Solutions I LLC, an equity method investment, under EPC contracts for one of its Utility Scale solar projects and one of its Distributed Solar projects.
Note 21 — Commitments and Contingencies 
Operating Lease Commitments
GenOn Mid-Atlantic Leases
The Company leases a 100% interest in the Dickerson and Morgantown coal generation units and associated property through 2029 and 2034, respectively, through its indirect subsidiary, GenOn MidAtlantic, LLC. The Company accounts for these leases as operating leases and records lease expense on a straight-line basis over the lease term. As further described in Note 3, Business Acquisitions and Dispositions , in connection with the acquisition of GenOn, the Company recorded the out-of-market value as a liability in out-of-market contracts of $540 million.
Future minimum lease commitments under the GenOn Mid-Atlantic operating leases for the years ending after December 31, 2012, are as follows:

Period	(In millions)	
2013	$	138	
 	
2014	131	
 	
2015	110	
 	
2016	150	
 	
2017	144	
 	
Thereafter	791	
 	
Total	$	1,464	
 	
REMA Leases
The Company, through its indirect subsidiary, GenOn REMA, LLC, leases a 100% interest in the Shawville coal generation facility through 2026 and leases 16.5% and 16.7% interest in the Keystone and Conemaugh coal generation facilities through 2034, and expects to make payments under the lease through 2029. The Company accounts for these leases as operating leases and records lease expense on a straight-line basis over the lease term. As further described in Note 3,  Business Acquisitions and Dispositions , in connection with the acquisition of GenOn, the Company recorded the out-of-market value as a liability in out-of-market contracts of $188 million.
During 2011, GenOn completed an analysis of the cost of environmental controls required for the Shawville generating facility, including the installation of cooling towers. After evaluation of the forecasted energy and capacity prices, expected capital expenditures, operating costs, property taxes and other factors, GenOn concluded that the forecasted returns on investments necessary to comply with the environmental regulations are insufficient. Accordingly, NRG plans to place the coal-fired units at the Shawville generating facility in a long-term protective layup in April 2015. Under the lease agreement for Shawville, NRG's obligations generally are to pay the required rent and to maintain the leased assets in accordance with the lease documentation, including in compliance with prudent competitive electric generating industry practice and applicable laws. NRG will continue to evaluate options under the lease, including termination of the lease for economic obsolescence and/or keeping the facility in long-term protective layup during the term of the lease, or continuing operations with a different fuel.

181

Future minimum lease commitments under the REMA operating leases for the years ending after December 31, 2012, are as follows:

Period	(In millions)	
2013	$	64	
 	
2014	63	
 	
2015	56	
 	
2016	61	
 	
2017	63	
 	
Thereafter	455	
 	
Total	$	762	
 	
Other Operating Leases
NRG leases certain Company facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2041. NRG also has certain tolling arrangements to purchase power which qualifies as operating leases. Certain operating lease agreements over their lease term include provisions such as scheduled rent increases, leasehold incentives, and rent concessions. The Company recognizes the effects of these scheduled rent increases, leasehold incentives, and rent concessions on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Lease expense under operating leases was$67 million, $81 million, and $111 million for the years ended December 31, 2012, 2011, and 2010, respectively.
Future minimum lease commitments under operating leases for the years ending after December 31, 2012, are as follows:

Period	(In millions)	
2013	$	88	
 	
2014	86	
 	
2015	80	
 	
2016	71	
 	
2017	69	
 	
Thereafter	260	
 	
Total	$	654	
 	
Coal, Gas and Transportation Commitments
NRG has entered into long-term contractual arrangements to procure fuel and transportation services for the Company's generation assets and for the years ended December 31, 2012, 2011, and 2010, the Company purchased $1.4 billion, $1.6 billion, and $1.5 billion, respectively, under such arrangements.
As of December 31, 2012, the Company's commitments under such outstanding agreements are estimated as follows:

Period	(In millions)	
2013	$	1,301	
 	
2014	358	
 	
2015	272	
 	
2016	242	
 	
2017	241	
 	
Thereafter	712	
 	
Total	$	3,126	

182

Purchased Power Commitments
NRG has purchased power contracts of various quantities and durations that are not classified as derivative assets and liabilities and do not qualify as operating leases. These contracts are not included in the consolidated balance sheet as of December 31, 2012. Minimum purchase commitment obligations are as follows as of December 31, 2012:

Period	(In millions)	
2013	$	32	
 	
2014	15	
 	
2015	12	
 	
2016	9	
 	
2017	9	
 	
Thereafter	—	
 	
Total (a)	$	77	

(a)	As of December 31, 2012, the maximum remaining term under any individual purchased power contract is five years.	
Lignite Contract with Texas Westmoreland Coal Co.
The lignite used to fuel the Texas region's Limestone facility is obtained from the Jewett mine, a surface mine adjacent to the Limestone facility, under a long-term contract with Texas Westmoreland Coal Co., or TWCC. The contract is based on a cost-plus arrangement with incentives and penalties to ensure proper management of the mine. NRG has the flexibility to increase or decrease lignite purchases from the mine within certain ranges, including the ability to suspend or terminate lignite purchases with adequate notice. The mining period extends through 2018 with an option to further extend the mining period by two five-year intervals.
TWCC is responsible for performing ongoing reclamation activities at the mine until all lignite reserves have been produced. When production is completed at the mine, NRG will be responsible for final mine reclamation obligations. The Railroad Commission of Texas has imposed a bond obligation of $107.5 million on TWCC for the reclamation of this lignite mine. Pursuant to the contract with TWCC, NRG supports this obligation as follows: $76 million is guaranteed by NRG Energy, Inc., and $31.5 million is supported by surety bonds posted by NRG. Additionally, NRG is required to provide additional performance assurance over TWCC's current bond obligations if required by the Railroad Commission of Texas.
First Lien Structure
NRG has granted first liens to certain counterparties on substantially all of the Company's assets, excluding assets acquired in the GenOn acquisition, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of December 31, 2012, all hedges under the first lien were in-the-money for NRG on a counterparty aggregate basis.
Nuclear Insurance
STP maintains required insurance coverage for liability claims arising from nuclear incidents pursuant to the Price-Anderson Amendment to the Energy Policy Act of 2005, referred to as the Price-Anderson Act. As of December 31, 2012, the current liability limit per incident was $12.6 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. An inflation adjustment must be made at least once every five years with the most recent adjustment effective October 29, 2008. Under the Price-Anderson Act, owners of nuclear power plants in the U.S. are required to purchase primary insurance limits of $375 million for each operating site. In addition, the Price-Anderson Act requires an additional layer of protection through mandatory participation in a retrospective rating plan for power reactors resulting in an additional $12.2 billion in funds available for public liability claims. The current maximum assessment per incident, per reactor, is $117.5 million, payable at no more than $17.5 million per year. NRG would be responsible for 44% of the maximum assessment, or $7.7 million per year, per reactor. In addition, the U.S. Congress retains the ability to impose additional financial requirements on the nuclear industry to pay liability claims that exceed $12.6 billion for a single incident. The liabilities of the co-owners of STP with respect to the retrospective premium assessments for nuclear liability insurance are joint and several.

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STP purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Limited, or NEIL, an industry mutual insurance company, of which STP is a member. STP has purchased $2.75 billion in limits, the maximum available from NEIL. The upper $1 billion in limits (excess of the first $1.75 billion in limits) is a single limit blanket policy shared with the DC Cook and Diablo Canyon nuclear reactors, two reactors that have no affiliation with the Company. This shared limit is not subject to automatic reinstatement in the event of a loss. The NEIL policy covers both nuclear and non-nuclear property damage events, and includes coverage for 6 weeks of lost revenue following a property damage event, at a weekly indemnity limit of $3.5 million, subject to a 17 week waiting period. NRG also purchased an Accidental Outage policy from NEIL, which provides additional protection for lost revenue due to an insurable event. This coverage allows for reimbursement up to $3.5 million per week up to a maximum of $473.2 million, and is subject to a 23 week waiting period. Under the terms of the NEIL policies, member companies may be assessed up to 10 times their annual premium if the NEIL Board of Directors determines their surplus has been depleted due to the payment of property losses at any of the licensed reactors in a single policy year. NEIL requires that its members maintain an investment grade credit rating or insure their annual retrospective obligation by providing a financial guarantee, letter of credit, deposit premium, or an insurance policy. NRG has purchased an insurance policy from NEIL to guarantee the Company's obligation; however this insurance will only respond to retrospective premium adjustments assessed within 24 months after the policy term, whereas NEIL's Board of Directors can make such an adjustment up to 6 years after the policy expires.
Contingencies
Set forth below is a description of the Company's material legal proceedings. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. Pursuant to the requirements of ASC 450, Contingencies  and related guidance, NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.
In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
California Department of Water Resources
This matter concerns, among other contracts and other defendants, CDWR and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the FERC abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004.
On December 19, 2006, the Ninth Circuit decided that in the FERC's review of the contracts at issue, the FERC could not rely on the  Mobile-Sierra  standard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCP's appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008, the Supreme Court ruled: (i) that the  Mobile-Sierra  public interest standard of review applied to contracts made under a seller's market-based rate authority; (ii) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (iii) that the  Mobile-Sierra  presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress.

184

This matter was extensively litigated and on March 22, 2012, NRG reached an agreement in principle with the CPUC to settle and resolve this matter, including all related claims, on behalf of NRG and on behalf of Dynegy. The agreement in principle was announced by the Company on March 23, 2012, as well as by the CPUC and by the California Governor's Office. The documented agreement was executed and submitted to the FERC on April 27, 2012 for its approval. The settlement agreement contains three material elements to be fulfilled over a four to six year period, depending upon several factors. First, the settlement agreement includes a $20 million cash payment due 30 days after the FERC approval. Second, it includes the construction and operation of a fee-based charging network, to be owned and operated by NRG subsidiary, eVgo, which will consist of at least 200 publicly available fast-charging electric vehicle stations installed at locations across California. Last, it calls for the wiring and associated work required to improve at least 10,000 individual parking spaces to allow for the charging of electric vehicles in at least 1,000 multi-family complexes, worksites, and public interest locations such as community colleges, public universities, and public or non-profit hospitals. Although these improved newly wired parking spaces will continue to be owned by the local property owner, eVgo will have an 18-month exclusive right to obtain customers from these locations starting from the date of each completed installation. The expected $20 million cash payment was accrued and expensed in the statement of operations for the three months ended March 31, 2012. In addition, the Company expects to spend approximately $100 million over the next four to six year period, during which the Company will fulfill the other elements of the settlement, and will capitalize a substantial majority of the costs as property, plant and equipment, representing the costs to construct the charging network and the wiring, which will be productive assets. The Company will expense the costs to operate the assets as incurred. On May 24, 2012, ECOtality, Inc. filed a lawsuit against the CPUC challenging the settlement, which was effectively dismissed on October 12, 2012. The settlement agreement was approved by the FERC on November 2, 2012. Final settlement payment of $20 million was made on January 16, 2013. Given that there was no challenge to the FERC order approving the settlement in the statutory period, the order became final and non-appealable.
Louisiana Generating, LLC
On February 11, 2009, the U.S. DOJ, acting at the request of the EPA sued Louisiana Generating, LLC, or LaGen, in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. This is the same matter for which NOVs were issued to LaGen on February 15, 2005, and on December 8, 2006. Specifically, it is alleged that in the late 1990's, several years prior to NRG's acquisition of the Big Cajun II power plant from the Cajun Electric bankruptcy and several years prior to the NRG bankruptcy, modifications were made to Big Cajun II Units 1 and 2 by the prior owners without appropriate or adequate permits and without installing and employing BACT to control emissions of nitrogen oxides and/or sulfur dioxides. The relief sought in the complaint included a request for an injunction to: (i) preclude the operation of Units 1 and 2 except in accordance with the CAA; (ii) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (iii) obtain all necessary permits for Units 1 and 2; (iv) order the surrender of emission allowances or credits; (v) conduct audits to determine if any additional modifications have been made which would require compliance with the CAA's Prevention of Significant Deterioration program; (vi) award to the U.S. DOJ its costs in prosecuting this litigation; and (vii) assess civil penalties of up to $27,500 per day for each CAA violation found to have occurred between January 31, 1997, and March 15, 2004, up to $32,500 for each CAA violation found to have occurred between March 15, 2004, and January 12, 2009, and up to $37,500 for each CAA violation found to have occurred after January 12, 2009.
On January 20, 2012, the court scheduled a liability-phase trial for October 15, 2012, and a remedy-phase trial set to occur at a later date to be determined in the event of an adverse decision in a liability-phase trial. On October 17, 2012, prior to the start of the liability-phase trial which had been temporarily adjourned, the parties notified the court that they had reached an agreement on terms of a settlement which requires final approval by the U.S. DOJ. The terms of the agreement generally require LaGen to install certain emission control technologies, as well as pay a civil penalty of $3.5 million and complete mitigation projects of $10.5 million within five years of entry of the Consent Decree. On November 20, 2012 the U.S. DOJ lodged the consent Decree with the court. On January 14, 2013, the court entered the parties joint request for a continuance to April 22, 2013 so the parties could finalize the settlement. No objection to the Decree was entered during the statutory period. Further discussion on this matter can be found in Note 23,  Environmental Matters - South Central Region .
In a related matter, soon after the filing of the above referenced U.S. DOJ lawsuit, LaGen sought insurance coverage from its insurance carrier, Illinois Union Insurance Company, or ILU. ILU denied coverage and thereafter LaGen filed a lawsuit (which was consolidated with a prior suit filed by ILU) seeking a declaration that ILU must provide coverage to LaGen for the defense costs incurred in defending the U.S. DOJ lawsuit.  LaGen and ILU both filed motions for summary judgment and on January 30, 2012, the court issued an order granting LaGen's motion finding that ILU has a duty to defend LaGen. The trial court certified the summary judgment for immediate interlocutory appeal, and on May 25, 2012, ILU filed a petition with the U.S. Circuit Court of Appeals for the Fifth Circuit seeking to appeal the trial court's summary judgment ruling. The Fifth Circuit granted the petition on September 4, 2012. ILU filed a related notice of appeal on June 14, 2012, which also seeks review of the trial court's summary judgment ruling. The Company filed a motion to consolidate the two appeals which the court granted on October 24, 2012. The appellate argument before The Fifth Circuit is scheduled for March 6, 2013.

185

Big Cajun II Alleged Opacity Violations — On September 7, 2012, LaGen received a Consolidated Compliance Order & Notice of Potential Penalty, or CCO&NPP, from the LDEQ with the potential for penalties in excess of $100,000.  The CCO&NPP alleges there were opacity exceedance events from the Big Cajun II Power Plant on certain dates during the years 2007-2012.  On October 8, 2012, LaGen filed a Request for Administrative Adjudicatory hearing and is cooperating with the LDEQ and responding in good faith to the CCO&NPP. 
Global Warming
In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a suit in the United States District Court for the Northern District of California against GenOn and 23 other electric generating and oil and gas companies. The lawsuit sought damages of up to $400 million for the cost of relocating the village allegedly because of global warming caused by the greenhouse gas emissions of the defendants. In late 2009, the District Court ordered that the case be dismissed and the plaintiffs appealed. In September 2012, the United States Court of Appeals for the Ninth Circuit dismissed plaintiffs' appeal. In October 2012, the plaintiffs petitioned for en banc rehearing of the case; which petition was denied in November 2012. In February 2013, plaintiffs filed a petition with the U. S. Supreme Court seeking review of the decision from the U.S. Court of Appeals. The Company believes claims such as this lack legal merit.
Actions Pursued by MC Asset Recovery
Under the plan of reorganization that was approved in conjunction with Mirant Corporation's emergence from bankruptcy protection on January 3, 2006, or the Plan, the rights to certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings.  MC Asset Recovery is now governed by a manager who is independent of GenOn.  Under the Plan, any cash recoveries obtained by MC Asset Recovery from the actions transferred to it, net of fees and costs incurred in prosecuting the actions, are to be paid to the unsecured creditors of GenOn Energy Holdings in the Chapter 11 proceedings and the holders of the equity interests in GenOn Energy Holdings immediately prior to the effective date of the Plan except where such a recovery results in an allowed claim in the bankruptcy proceedings, as described below.  MC Asset Recovery is a disregarded entity for income tax purposes, and NRG, GenOn and GenOn Energy Holdings are responsible for income taxes related to its operations.  The Plan provides that GenOn Energy Holdings may not reduce payments to be made to unsecured creditors and former holders of equity interests from recoveries obtained by MC Asset Recovery for the taxes owed by GenOn Energy Holdings, if any, on any net recoveries up to $175 million. If the aggregate recoveries exceed $175 million net of costs, then GenOn Energy Holdings may reduce the payments by the amount of any taxes it will owe or NOLs it may utilize with respect to taxable income resulting from the amount in excess of $175 million.
One of the two remaining actions transferred to MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks (the Commerzbank Defendants) for alleged fraudulent transfers that occurred prior to the filing of GenOn Energy Holdings' bankruptcy proceedings.  In its amended complaint, MC Asset Recovery alleges that the Commerzbank Defendants in 2002 and 2003 received payments totaling approximately €153 million directly or indirectly from GenOn Energy Holdings under a guarantee provided by GenOn Energy Holdings in 2001 of certain equipment purchase obligations.  MC Asset Recovery alleges that at the time GenOn Energy Holdings provided the guarantee and made the payments to the Commerzbank Defendants, GenOn Energy Holdings was insolvent and did not receive fair value for those transactions.  In December 2010, the United States District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants.  In January 2011, MC Asset Recovery appealed the United States District Court's dismissal of its complaint against the Commerzbank Defendants to the United States Court of Appeals for the Fifth Circuit.  In March 2012, the United States Court of Appeals for the Fifth Circuit reversed the United States District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants.  If MC Asset Recovery succeeds in obtaining any recoveries on these avoidance claims, the Commerzbank Defendants have asserted that they will seek to file claims in GenOn Energy Holdings' bankruptcy proceedings for the amount of those recoveries.  GenOn Energy Holdings would vigorously contest the allowance of any such claims on the ground that, among other things, the recovery of such amounts by MC Asset Recovery does not reinstate any enforceable pre-petition obligation that could give rise to a claim.  If such a claim were to be allowed by the Bankruptcy Court as a result of a recovery by MC Asset Recovery, then the Plan provides that the Commerzbank Defendants are entitled to the same distributions as previously made under the Plan to holders of similar allowed claims.  Holders of previously allowed claims similar in nature to the claims that the Commerzbank Defendants would seek to assert have received 43.87 shares of GenOn Energy Holdings common stock for each $1,000 of claim allowed by the Bankruptcy Court.  If the Commerzbank Defendants were to receive an allowed claim as a result of a recovery by MC Asset Recovery on its claims against them, the order entered by the Bankruptcy Court in December 2005, confirming the Plan provides that GenOn Energy Holdings would retain from the net amount recovered by MC Asset Recovery an amount equal to the dollar amount of the resulting allowed claim rather than distribute such amount to the unsecured creditors and former equity holders as described above.

186

Pending Natural Gas Litigation
GenOn is party to five lawsuits, several of which are class action lawsuits, in state and federal courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in 2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of antitrust and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name a number of unaffiliated energy companies as parties. In July 2011, the judge in the United States District Court for the District of Nevada handling four of the five cases granted the defendants' motion for summary judgment dismissing all claims against GenOn in those cases. The plaintiffs have appealed to the United States Court of Appeals for the Ninth Circuit. In September 2012, the State of Nevada Supreme Court handling one of the five cases affirmed dismissal by the Eighth Judicial District Court for Clark County, Nevada of all plaintiffs' claims against GenOn. In February 2013, the plaintiffs filed a petition for certiorari to the United States Supreme Court. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits.
New Source Review Matters
The EPA and various states are investigating compliance of coal and oil-fueled electric generating facilities with the pre-construction permitting requirements of the CAA known as “new source review.” Since 2000, the EPA has made information requests concerning several of the Company's plants. The Company continues to correspond with the EPA regarding some of these requests. The EPA agreed to share information relating to its investigations with state environmental agencies. In 2005 and 2006, the Company received an NOV from the EPA alleging that past work at Big Cajun II violated regulations regarding new source review. In January 2009, the EPA issued an NOV alleging that past work at the Shawville, Portland and Keystone generating facilities violated regulations regarding new source review. In June 2011, the EPA issued an NOV alleging that past work at its Niles and Avon Lake generating facilities violated regulations regarding new source review.
In December 2007, the NJDEP sued GenOn in the United States District Court for the Eastern District of Pennsylvania, alleging that new source review violations occurred at the Portland generating facility. The suit seeks installation of BACT for each pollutant, to enjoin GenOn from operating the generating facility if it is not in compliance with the CAA and civil penalties. The suit also names past owners of the plant as defendants. In March 2009, the Connecticut Department of Environmental Protection became an intervening party to the suit. The Company believes that the work listed by the EPA and the work subject to the NJDEP suit were conducted in compliance with applicable regulations. However, any final finding that GenOn violated the new source review requirements could result in fines and penalties. This case is currently scheduled for a liability trial on April 22, 2013.
In addition, the NJDEP filed two administrative petitions with the EPA in 2010 alleging that the Portland generating facility's emissions were significantly contributing to nonattainment and/or interfering with the maintenance of certain NAAQS in New Jersey. In November 2011, the EPA published a final rule in response to one of the petitions that will require the two coal-fired units to reduce maximum allowable SO 2  emissions by about 60% starting in January 2013 and by about 80% starting in January 2015. In January 2012, the Company challenged the rule in the United States Court of Appeals for the Third Circuit. In 2013 and 2014, the Company has several compliance options that include using lower sulfur coals (although this may at times reduce how much the Company is able to generate) or running just one unit at a time. Starting in January 2015, these units will be subject to more stringent rate limits, which will require either material capital expenditures and higher operating costs or the retirement of these two units. The Company plans to deactivate these units in January 2015.
Cheswick Class Action Complaint
In April 2012, a putative class action lawsuit was filed in the Court of Common Pleas of Allegheny County, Pennsylvania alleging that emissions from the Cheswick generating facility have damaged the property of neighboring residents. The Company disputes these allegations. Plaintiffs have brought nuisance, negligence, trespass and strict liability claims seeking both damages and injunctive relief. Plaintiffs seek to certify a class that consists of people who own property or live within one mile of the Company's plant. In July 2012, the Company removed the lawsuit to the United States District Court for the Western District of Pennsylvania. In October 2012, the court granted the Company's motion to dismiss, which Plaintiffs have appealed to the U.S. Court of Appeals for the Third Circuit.
Cheswick Monarch Mine NOV
In 2008, the PADEP issued an NOV related to the Monarch mine located near the Cheswick generating facility. It has not been mined for many years. The Company uses it for disposal of low-volume wastewater from the Cheswick generating facility and for disposal of leachate collected from ash disposal facilities. The NOV addresses the alleged requirement to maintain a minimum pumping volume from the mine. The PADEP indicated it may assess a civil penalty in excess of $100,000. The Company contests the allegations in the NOV and has not agreed to such penalty. The Company is currently planning capital expenditures in connection with wastewater from Cheswick and leachate from ash disposal facilities.

187

Ormond Beach Alleged Federal Clean Water Act Violations
In October 2012, the Wishtoyo Foundation, a California-based cultural and environmental advocacy organization, through its Ventura Coastkeeper Program, filed suit in the United States District Court for the Central District of California regarding alleged violations of the CWA associated with discharges of stormwater from the Ormond Beach generating facility. The Wishtoyo Foundation alleges that elevated concentrations of pollutants in stormwater discharged from the Ormond Beach generating facility are affecting adjacent aquatic resources in violation of (a) the Statewide General Industrial Stormwater permit (a general National Pollution Discharge Elimination System permit issued by the California State Water Resources Control Board that authorizes stormwater discharges from industrial facilities in California) and (b) the state's Porter-Cologne Water Quality Control Act. The Wishtoyo Foundation further alleges that the Company has not implemented effective stormwater control and treatment measures and that the Company has not complied with the sampling and reporting requirements of the General Industrial Stormwater permit. The Company disputes these allegations.
Maryland Fly Ash Facilities
The Company has three fly ash facilities in Maryland: Faulkner, Westland and Brandywine. Fly ash from the Morgantown and Chalk Point generating facilities is disposed of at Brandywine. Fly ash from the Dickerson generating facility is disposed of at Westland. Fly ash is no longer disposed of at the Faulkner facility. As described below, the MDE has sued GenOn MidAtlantic regarding Faulkner, Brandywine and Westland. The MDE also had threatened not to renew the water discharge permits for all three facilities.
Faulkner Litigation —In May 2008, the MDE sued GenOn MidAtlantic in the Circuit Court for Charles County, Maryland alleging violations of Maryland's water pollution laws at Faulkner. The MDE contended that the operation of Faulkner had resulted in the discharge of pollutants that exceeded Maryland's water quality criteria and without the appropriate NPDES permit. The MDE also alleged that GenOn MidAtlantic failed to perform certain sampling and reporting required under an applicable NPDES permit. The MDE complaint requested that the court (a) prohibit continuation of the alleged unpermitted discharges, (b) requires GenOn MidAtlantic to cease from further disposal of any coal combustion byproducts at Faulkner and close and cap the existing disposal cells and (c) assess civil penalties. In July 2008, GenOn MidAtlantic filed a motion to dismiss the complaint, arguing that the discharges are permitted by a December 2000 Consent Order. In January 2011, the MDE dismissed without prejudice its complaint and informed GenOn MidAtlantic that it intended to file a similar lawsuit in federal court. In May 2011, the MDE filed in the United States District Court for the District of Maryland alleging violations at Faulkner of the CWA and Maryland's Water Pollution Control Law. The MDE contends that (a) certain water discharges are not authorized by its existing permit and (b) operation of the Faulkner facility has resulted in discharges of pollutants that violate water quality criteria. The complaint asks the court to, among other things, (a) enjoin further disposal of coal ash; (b) enjoin discharges that are not authorized by the existing permit; (c) require numerous technical studies; (d) impose civil penalties and (e) award MDE attorneys' fees. The Company disputes the allegations.
Brandywine Litigation — In April 2010, the MDE filed a complaint against GenOn MidAtlantic in the United States District Court for the District of Maryland asserting violations at Brandywine of the CWA and Maryland's Water Pollution Control Law. The MDE contends that the operation of Brandywine has resulted in discharges of pollutants that violate Maryland's water quality criteria. The complaint requests that the court, among other things, (a) enjoin further disposal of coal combustion waste at Brandywine, (b) requires the existing open disposal cells to be closed and capped within one year, (c) impose civil penalties and (d) award MDE attorneys' fees. The Company disputes the allegations. In September 2010, four environmental advocacy groups became intervening parties in the proceeding.
Westland Litigation —In January 2011, the MDE informed GenOn MidAtlantic that it intended to sue for alleged violations at Westland of Maryland's water pollution laws, which suit was filed in United States District Court for the District of Maryland in December 2012.
Permit Renewals —In March 2011, the MDE tentatively determined to deny the Company's application for the renewal of the water discharge permit for Brandywine, which could result in a significant increase in operating expenses for the Company's Chalk Point and Morgantown generating facilities. The MDE also had indicated that it was planning to deny the Company's applications for the renewal of the water discharge permits for Faulkner and Westland. Denial of the renewal of the water discharge permit for the latter facility could result in a significant increase in operating expenses for the Dickerson generating facility.

188

Settlement — In June 2011, the MDE agreed to stay the litigation related to Faulkner and Brandywine, not to pursue its tentative denial of the Brandywine water discharge permit and not to act on renewal applications for Faulkner or Westland while settlement discussions occurred. As a condition to obtaining the stay, GenOn MidAtlantic agreed in principle to pay a civil penalty of $1.9 million if the matters were settled. In 2012, GenOn MidAtlantic agreed to pay an additional $0.6 million (for agreed prospective penalties while the settlement is implemented) if a comprehensive settlement is reached. The Company believes it is adequately reserved for such settlement. GenOn MidAtlantic also developed a technical solution, which includes installing synthetic caps on the closed cells of each of the three ash facilities, for which $47 million has been reserved. GenOn MidAtlantic has concluded settlement discussions with the MDE and signed a consent decree that when entered by the court will resolve these issues. In January 2013, the intervenors in the Brandywine case opposed entry of the consent decree. At this time, the Company cannot reasonably estimate the upper range of its obligation for remediating the sites the Company has not: (a) finished assessing each site including identifying the full impacts to both ground and surface water and the impacts to the surrounding habitat; (b) finalized with the MDE the standards to which it must remediate; and (c) identified the technologies required, if any, to meet the yet to be determined remediation standards at each site nor the timing of the design and installation of such technologies.
Brandywine Storm Damage and Ash Recovery
As a result of Hurricane Irene and Tropical Storm Lee in August and September 2011, an estimated 8,800 cubic yards of coal fly ash stored in one of the cells at the Brandywine ash disposal site flowed onto 18 acres of private property adjacent to the site. The Company has removed the released ash from the private property and completed the remaining clean-up activities. The Company believes it has recorded an adequate reserve in connection with claims associated with the remaining costs to remove and clean up the ash.
Brandywine Filling of Wetlands —While expanding and installing a liner at the Brandywine ash disposal site, GenOn MidAtlantic inadvertently filled wetlands without having all of the requisite permits. The MDE also has alleged that GenOn MidAtlantic violated the notice requirements of its sediment and erosion control plan. In July 2012, the MDE filed a complaint in the Circuit Court for Prince George's County, Maryland for civil penalties and injunctive relief in connection with the storm damage and the filling of the wetlands. GenOn MidAtlantic settled these matters by paying a fine of $300,000 in December 2012.
Energy Plus Holdings, LLC Purported Class Actions
Energy Plus Holdings, LLC is a defendant in six purported class action lawsuits, two in New York, two in New Jersey, and two in Pennsylvania. The plaintiffs in those lawsuits generally allege that Energy Plus misrepresents that its rates are competitive in the market; fails to disclose that its rates are substantially higher than those in the market and that Energy Plus has engaged in deceptive practices in its marketing of energy services. Plaintiffs generally seek that these matters be certified as class actions, with treble damages, interest, costs, attorneys' fees, and any other relief that the court deems just and proper. In addition, on July 26, 2012, the Connecticut Attorney General and Office of Consumer Counsel filed a petition with the Connecticut Public Utilities Regulatory Authority seeking to investigate Energy Plus' marketing practices. On August 7, 2012, Energy Plus Holdings LLC and Energy Plus Natural Gas LLC received a subpoena from the State of New York Office of Attorney General which generally seeks information and business records related to Energy Plus' sales, marketing and business practices. While the Company believes that these allegations are without merit, it is cooperating with the attorneys general and is exploring an amicable resolution of all matters. The Company does not currently anticipate any potential resolution to be material in nature and believes it is adequately reserved for any estimated losses.
Purported Class Actions related to July 22, 2012 Announcement of NRG/GenOn Merger Agreement
NRG has been named as a defendant in eight purported class actions pending in Texas and Delaware, related to its announcement of its agreement to acquire all outstanding shares of GenOn. These cases have been consolidated into one state court case in each of Delaware and Texas and a federal court case in Texas. The plaintiffs generally allege breach of fiduciary duties, as well as conspiracy, aiding and abetting breaches of fiduciary duties. Plaintiffs are generally seeking to: be certified as a class; enjoin the merger; direct the defendant to exercise their fiduciary duties; rescind the acquisition and be awarded attorneys' fees costs and other relief that the court deems appropriate. Plaintiffs have demanded that there be additional disclosures regarding the merger terms. On October 24, 2012, the parties to the Delaware state court case executed a Memorandum of Understanding to resolve the Delaware purported class action lawsuit.

189

Notice of Intent to File Citizens Suit - Chalk Point, Dickerson and Morgantown
On January 25, 2013, Food & Water Watch, the Patuxent Riverkeeper and the Potomac Riverkeeper, or the Citizens Group, sent NRG a letter alleging that the Chalk Point, Dickerson and Morgantown generating facilities were violating the terms of the three National Pollution Discharge Elimination System Permits by discharging nitrogen and phosphorous into the waters of the United States in excess of the limits in each permit. The Citizens Group threatens to bring a lawsuit if the Company does not bring itself into compliance within 60 days of the letter. The Citizens Group intends to seek civil penalties and injunctive relief against the Company if they file a lawsuit.
Note 22 — Regulatory Matters 
NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail businesses.
In addition to the regulatory proceedings noted below, NRG and its subsidiaries are a party to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
East Region
Reliability Must Run Agreements for Elrama and Niles — In May 2012, GenOn filed with the FERC an RMR rate schedule governing operation of unit 4 of the Elrama generating facility and unit 1 of the Niles generating facility.  PJM determined that each of these units was needed past their planned deactivation date of June 1, 2012 to maintain transmission system reliability on the PJM system pending the completion of transmission upgrades.  The RMR rate schedule sets forth the terms, conditions and cost-based rates under which GenOn operated the units for reliability purposes through September 30, 2012, the date PJM indicated the units would no longer be needed for reliability.  In July 2012, the FERC accepted GenOn's RMR rate schedule subject to hearing and settlement procedures.  In the settlement discussions ordered by the FERC or in any subsequent hearing, the Company's RMR rate schedule may be modified from that which was filed.  The rates GenOn charged are subject to refund pending a ruling or settlement.
Texas and South Central Regions
Retail (Replacement Reserve)—On November 14, 2006, Constellation Energy Commodities Group, or Constellation, filed a complaint with the PUCT alleging that ERCOT misapplied the Replacement Reserve Settlement, or RPRS, Formula contained in the ERCOT protocols from April 10, 2006, through September 27, 2006.  Specifically, Constellation disputed approximately $4 million in under-scheduling charges for capacity insufficiency asserting that ERCOT applied the wrong protocol.  REPS, other market participants, ERCOT, and PUCT staff opposed Constellation's complaint.  On January 25, 2008, the PUCT entered an order finding that ERCOT correctly settled the capacity insufficiency charges for the disputed dates in accordance with ERCOT protocols and denied Constellation's complaint.  On April 9, 2008, Constellation appealed the PUCT order to the Civil District Court of Travis County, Texas and on June 19, 2009, the court issued a judgment reversing the PUCT order, finding that the ERCOT protocols were in irreconcilable conflict with each other.  Under the PUCT ordered formula, QSEs who under-scheduled capacity within any of ERCOT's four congestion zones were assessed under-scheduling charges which defrayed the costs incurred by ERCOT for RPRS that would otherwise be spread among all load-serving QSEs.  Under the Court's decision, all RPRS costs would be assigned to all load-serving QSEs based upon their load ratio share without assessing any separate charge to those QSEs who under-scheduled capacity.  If under-scheduling charges for capacity insufficient QSEs were not used to defray RPRS costs, REPS's share of the total RPRS costs allocated to QSEs would increase.  On July 20, 2009, REPS filed an appeal to the Third Court of Appeals in Travis County, Texas, thereby staying the effect of the trial court's decision.  On October 6, 2010, the parties argued the appeal before the Court of Appeals for the Third District in Austin, Texas.  On September 28, 2011, the Court of Appeals reversed the trial court decision, reinstating the PUCT's order, consistent with REPS's position.  On January 13, 2012, Constellation filed a Petition for Review in the Supreme Court of Texas asking the Court to grant review of and reverse the Court of Appeals decision. On December 14, 2012, the Texas Supreme Court rejected Constellation's petition, resulting in a favorable outcome for the Company. The period to seek further review of the Texas Supreme Court decision has passed.

190

Retail (Midwest ISO SECA) — Green Mountain Energy previously provided competitive retail energy supply in the Midwest ISO region during the relevant period of January 1, 2002, to December 31, 2005.  By order dated November 18, 2004, the FERC eliminated certain regional through-and-out transmission rates charged by transmission owners in MISO and PJM. In order to temporarily compensate the transmission owners for lost revenues, FERC ordered MISO, PJM and their respective transmission owners to provide for the recovery of certain Seams Elimination Charge/Cost Adjustments/Assignments, or SECA, charges effective December 1, 2004, through March 31, 2006.  The tariff amendments filed by MISO and the MISO transmission owners allocated certain SECA charges to various zones and sub-zones within MISO, including a sub-zone called the Green Mountain Energy Company Sub-zone.  During several years of extensive litigation before the FERC, several transmission owners sought to recover SECA charges from Green Mountain Energy. Green Mountain Energy denied responsibility for any SECA charges and did not pay any asserted SECA charges.
On May 21, 2010, the FERC issued two orders, including its Order on Initial Decision, in which the FERC determined that approximately $22 million plus interest of SECA charges were owed not by Green Mountain Energy but rather by BP Energy - one of Green Mountain Energy's suppliers during the period at issue.  On August 19, 2010, the transmission owners and MISO made compliance filings in accordance with the FERC's Orders allocating SECA charges to a BP Energy Sub-zone, and making no allocation to a Green Mountain Energy sub-zone.  The FERC has not yet ruled on those compliance filings. 
On September 30, 2011, the FERC issued orders denying all requests for rehearing and again determined that SECA charges were not owed by Green Mountain Energy.  Numerous parties, including BP Energy, sought judicial review of the FERC's orders, and Green Mountain Energy was granted intervenor status in the consolidated appeals. Most appellants subsequently settled with the transmission owners and withdrew their appeals, including BP Energy, which agreed to pay approximately $24 million to the three transmission owners signing the agreement, with another $1 million offered to the remaining PJM transmission owners, should they choose to join the settlement; all chose to do so. FERC approved the settlement, and BP Energy moved to dismiss its appeals; its motions to dismiss were granted by the Court.
West Region
California — On December 18, 2012, in Calpine Corporation v. FERC, the U.S. Court of Appeals for the D.C. Circuit upheld a decision by the FERC disclaiming jurisdiction over how the states impose retail station power charges. This decision paves the way for the CPUC to establish retail charges for future station power consumption. Due to reservation-of-rights language in the California utilities' state-jurisdictional station power tariffs, the Court's ruling arguably requires California generators to pay state-imposed retail charges back to the date of enrollment by the facilities in the CAISO's station period program (February 1, 2009, for the Company's Encina and El Segundo facilities; March 1, 2009, for the Company's Long Beach facility).
On November 18, 2011, Southern California Edison Company filed with the CPUC, seeking authorization to begin charging generators station power charges, and to assess such charges retroactively, which the Company and other generators have challenged. On August 13, 2012, the CPUC Energy Division issued a draft resolution in which it rejected the Company's arguments and approved Southern California Edison's proposed station power charges, including retroactive implementation, but proposing a credit to generators for some portion of their retail station power bill. However, the CPUC withdrew the draft resolution from the calendar and consideration of the measure has not yet been rescheduled. The Company believes it has established an appropriate reserve.
Note 23 — Environmental Matters 
NRG is subject to a wide range of environmental regulations across a broad number of jurisdictions in the development, ownership, construction and operation of projects in the United States and Australia. These laws and regulations generally require that governmental permits and approvals be obtained before construction and during operation of power plants. Environmental regulations have become increasingly stringent and NRG expects this trend to continue. The electric generation industry is likely to face new requirements to address various emissions, including greenhouse gases, as well as combustion byproducts, water discharge and use, and threatened and endangered species. In general, future laws and regulations are expected to require the addition of emissions controls or other environmental quality equipment or the imposition of certain restrictions on the operations of the Company's facilities, which could have a material effect on the Company's operations.

191

Environmental Capital Expenditures
Based on current rules, technology and plans as well as preliminary plans based on proposed rules, NRG estimates that environmental capital expenditures from 2013 through 2017 required to comply with environmental laws will be approximately $630 million, consisting of $398 million for legacy NRG facilities and $232 million for GenOn facilities. These costs are primarily associated with controls to satisfy the MATS at Big Cajun II, W.A. Parish, Limestone, and Conemaugh and NO x controls for Sayreville and Gilbert. The decrease from NRG's previous estimate is related to changes in technology related to MATS compliance at Big Cajun II-Unit 3, and shifts in compliance schedules. Testing and engineering to finalize cost estimates related to further changes on the Big Cajun II MATS compliance plan and the recent Consent Decree lodged in  United States of America v. Louisiana Generating, LLC  are underway, but costs are not expected to exceed the current plan. NRG continues to explore cost effective compliance alternatives to reduce costs.
NRG's contracts with the Company's rural electric cooperative customers in the South Central region allow for recovery of a portion of the region's environmental capital costs incurred as the result of complying with any change in environmental law. Cost recoveries begin once the environmental equipment becomes operational and include a capital return. The actual recoveries will depend, among other things, on the timing of the completion of the capital projects and the remaining duration of the contracts.
The EPA released CSAPR on July 7, 2011, which was scheduled to replace CAIR on January 1, 2012. On December 30, 2011, the U.S. Court of Appeals for the D.C. Circuit stayed the rule pending resolution of the numerous petitions for judicial review. Under CSAPR, use of discounted Acid Rain SO 2  and CAIR NO x  allowances would have been discontinued and replaced with completely distinct allowance programs. Acid Rain allowances would still be required on a 1:1 basis under the Acid Rain Program. Consequently, in the third quarter 2011, the Company recorded an impairment charge of $160 million on the Company's Acid Rain Program SO 2  emission allowances, which were recorded as an intangible asset on the Company's balance sheet. The impairment charge reflects the write-off of the value of emission allowances in excess of those required for compliance with the Acid Rain Program.

On August 21, 2012, the court issued an opinion vacating CASPR and keeping CAIR in place until the EPA can replace it. This decision was beneficial to the combined Company as it eliminated an SO 2  allowance reduction which was to have occurred before the MATS compliance date. While NRG is unable to predict the final outcome of the replacement rule, the investment in pollution controls and cleaner technologies coupled with planned strategic plant retirements positions the fleet for compliance.

East Region
The EPA and various states are investigating compliance of coal-fueled electric generating facilities with the pre-construction permitting requirements of the CAA known as “new source review”, or NSR. In January 2009, GenOn received an NOV from the EPA alleging that past work at Keystone, Portland and Shawville generating facilities violated regulations regarding NSR. In June 2011, GenOn received an NOV from the EPA alleging that past work at Avon Lake and Niles generating stations violated NSR. In December 2007, the NJDEP, filed suit alleging that NSR violations occurred at the Portland generating station. NRG believes the suits are without merit and the subject work was conducted in compliance with applicable regulations. However, any final findings or settlement agreement could result in fines, penalties or capital expenditures associated with the reduction of emissions on an accelerated basis. It should be noted that all but the Keystone generating units are scheduled for retirement by April 2015. Please refer to Note 21,  Commitments and Contingencies .
In 2008, the PADEP issued an NOV related to the inactive Monarch mine where low-volume wastewater from the Cheswick Generating Station and ash leachate was historically disposed. Resolution of the NOV could result in operational requirements such as pumping a minimum volume of water from the mine and a penalty in excess of $100,000.
In January 2006, NRG's Indian River Operations, Inc. received a letter of informal notification from DNREC stating that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself required a Remedial Investigation and Feasibility Study to determine the type and scope of any additional required work. The DNREC approved the Feasibility Study in December 2012 and a proposed Plan of Remediation is under development at the DNREC. A final remedy based on the approved study should be consistent with the NRG reserve and should not be material. On May 29, 2008, DNREC requested that NRG's Indian River Operations, Inc. participate in the development and performance of a Natural Resource Damage Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG is currently working with DNREC and other trustees to close out the assessment process.

192

The MDE sued GenOn for alleged violations of water pollution laws at three fly ash disposal sites in Maryland: Falkner (2008/2011), Brandywine (2010), and Westland (2012). The plants have since discontinued use of the Faulkner disposal site and opened a new, state of the art carbon burnout facility at its Morgantown plant that allows greater beneficial reuse (as a cement substitute). For a detailed discussion on the legal proceedings, please refer to Note 21,  Commitments and Contingencies .
South Central Region
On February 11, 2009, the U.S. DOJ acting at the request of the EPA commenced a lawsuit against LaGen in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. This is the same matter for which NOVs were issued to LaGen on February 15, 2005, and on December 8, 2006. On November 20, 2012, the U.S. DOJ lodged a Consent Decree to resolve the complaint. In addition to a fine of $3.5 million and mitigation projects totaling $10.5 million, the terms of the agreement include: (a) annual emission caps for NO x  and SO 2 ; (b) installation of SNCRs on Units 1, 2 and 3 by May 1, 2014; (c) installation of DSI on Unit 1 by April 15, 2015 followed by a further reduction in SO 2  in March 2025; (d) conversion of Unit 2 to gas to meet MATS requirements; and (e) surrender of any excess allowances associated with the NRG owned portion of the plant. For further discussion of this matter, please refer to Note 21,  Commitments and Contingencies.
Note 24 — Cash Flow Information 
Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:

 	 	 	 	 	 	 	 	 	 	 	 	
 	Year Ended December 31,	
 	2012	 	2011	 	2010	
 	(In millions)	
Interest paid, net of amount capitalized	$	579	
 	 	$	642	
 	 	$	609	
 	
Income taxes paid (a)	17	
 	 	26	
 	 	20	
 	
Non-cash investing and financing activities:	 	 	 	 	 	
Additions to fixed assets for accrued capital expenditures	563	
 	 	292	
 	 	393	
 	
Decrease to fixed assets for accrued grants and related tax impact	(87	)	 	(32	)	 	—	
 	
Decrease to 4.0% preferred stock from conversion to common stock	—	
 	 	—	
 	 	149	
 	
Decrease to notes receivable for equity conversion	—	
 	 	63	
 	 	56	
 	
Increase to treasury stock from shares returned by affiliates of CS	—	
 	 	—	
 	 	(160	)	
Issuance of shares for GenOn acquisition	(2,188	)	 	—	
 	 	—	

(a)	2011 and 2010 income taxes paid are net of $8 million, and $14 million, respectively, of income tax refunds received. For 2012, no tax refunds were received.	
Note 25 — Guarantees 
NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of the Company's business activities. Examples of these contracts include asset purchases and sale agreements, commodity sale and purchase agreements, retail contracts, joint venture agreements, EPC agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. The Company is obligated with respect to customer deposits associated with the Retail Business. NRG has also assumed guarantees for some non-qualified benefits of existing retirees resulting from the acquisition of GenOn. In some cases, NRG's maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential liability.
In accordance with ASC 460, Guarantees, or ASC 460, NRG has estimated that the current fair value for issuing these guarantees was $6 million as of December 31, 2012, and the liability in this amount is included in the Company's non-current liabilities.

193

The following table summarizes the maximum potential exposures that can be estimated for NRG's guarantees, indemnities, and other contingent liabilities by maturity:

 	By Remaining Maturity at December 31,	
 	2012	 	 	
Guarantees	Under
1 Year	 	1-3 Years	 	3-5 Years	 	Over
5 Years	 	Total	 	2011
Total	
 	(In millions)	
Letters of credit and surety bonds	$	1,518	
 	 	$	76	
 	 	$	—	
 	 	$	—	
 	 	$	1,594	
 	 	$	1,670	
 	
Asset sales guarantee obligations	—	
 	 	—	
 	 	275	
 	 	—	
 	 	275	
 	 	635	
 	
Commercial sales arrangements	172	
 	 	142	
 	 	79	
 	 	1,186	
 	 	1,579	
 	 	1,405	
 	
Other guarantees	1	
 	 	—	
 	 	—	
 	 	355	
 	 	356	
 	 	461	
 	
Total guarantees	$	1,691	
 	 	$	218	
 	 	$	354	
 	 	$	1,541	
 	 	$	3,804	
 	 	$	4,171	
 	
Letters of credit and surety bonds — As of December 31, 2012, NRG and its consolidated subsidiaries were contingently obligated for a total of $1.6 billion under letters of credit and surety bonds. Most of these letters of credit and surety bonds are issued in support of the Company's obligations to perform under commodity agreements and in support of equity contribution requirements for solar projects in construction, as well as for financing or other arrangements. A majority of these letters of credit and surety bonds expire within one year of issuance, and it is typical for the Company to renew them on similar terms.
The material indemnities, within the scope of ASC 460, are as follows:
Asset purchases and divestitures — The purchase and sale agreements which govern NRG's asset or share investments and divestitures customarily contain guarantees and indemnifications of the transaction to third parties. The contracts indemnify the parties for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party, or as a result of a change in tax laws. These obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or estimate at the time of the transaction. In several cases, the contract limits the liability of the indemnifier. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations.
Commercial sales arrangements — In connection with the purchase and sale of fuel, emission allowances and power generation products to and from third parties with respect to the operation of some of NRG's generation facilities in the United States, the Company may be required to guarantee a portion of the obligations of certain of its subsidiaries. These obligations may include liquidated damages payments or other unscheduled payments.
Other guarantees — NRG has issued guarantees of obligations that its subsidiaries may incur as a provision for environmental site remediation, payment of debt obligations, rail car leases, performance under purchase, EPC and operating and maintenance agreements. The Company does not believe that it will be required to perform under these guarantees.
Other indemnities — Other indemnifications NRG has provided cover operational, tax, litigation and breaches of representations, warranties and covenants. NRG has also indemnified, on a routine basis in the ordinary course of business, consultants or other vendors who have provided services to the Company. NRG's maximum potential exposure under these indemnifications can range from a specified dollar amount to an indeterminate amount, depending on the nature of the transaction. Total maximum potential exposure under these indemnifications is not estimable due to uncertainty as to whether claims will be made or how they will be resolved. NRG does not have any reason to believe that the Company will be required to make any material payments under these indemnity provisions.
Because many of the guarantees and indemnities NRG issues to third parties and affiliates do not limit the amount or duration of its obligations to perform under them, there exists a risk that the Company may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit the Company's liability exposure, it may not be able to estimate what the Company's liability would be, until a claim is made for payment or performance, due to the contingent nature of these contracts.

194

Note 26 — Jointly Owned Plants 
Certain NRG subsidiaries own undivided interests in jointly-owned plants, as described below. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. NRG is responsible for its subsidiaries' share of operating costs and direct expenses and includes its proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of the Company's consolidated financial statements.
The following table summarizes NRG's proportionate ownership interest in the Company's jointly-owned facilities:

As of December 31, 2012	Ownership
Interest	 	Property, Plant &
Equipment	 	Accumulated
Depreciation	 	Construction in
Progress	
 	(In millions unless otherwise stated)	
South Texas Project Units 1 and 2, Bay City, TX	44.00	%	 	$	3,162	
 	 	$	(1,140	)	 	$	10	
 	
Big Cajun II Unit 3, New Roads, LA	58.00	%	 	175	
 	 	(84	)	 	11	
 	
Cedar Bayou Unit 4, Baytown, TX	50.00	%	 	214	
 	 	(38	)	 	—	
 	
Keystone, Shelocta, PA	3.70	%	 	92	
 	 	(31	)	 	1	
 	
Conemaugh, New Florence, PA	3.72	%	 	80	
 	 	(34	)	 	7	
 	
Note 27 — Unaudited Quarterly Financial Data 
Summarized unaudited quarterly financial data is as follows:

 	Quarter Ended	
 	2012	
 	December 31	 	September 30	 	June 30	 	March 31	
 	(In millions, except per share data)	
Operating revenues	$	2,063	
 	 	$	2,331	
 	 	$	2,166	
 	 	$	1,862	
 	
Operating income/(loss)	37	
 	 	86	
 	 	397	
 	 	(170	)	
Net income/(loss) attributable to NRG Energy, Inc. 	$	516	
 	 	$	(1	)	 	$	251	
 	 	$	(207	)	
Weighted average number of common shares outstanding — basic	247	
 	 	228	
 	 	228	
 	 	228	
 	
Net income/(loss) per weighted average common share — basic	$	2.08	
 	 	$	(0.01	)	 	$	1.09	
 	 	$	(0.92	)	
Weighted average number of common shares outstanding — diluted	249	
 	 	228	
 	 	229	
 	 	228	
 	
Net income/(loss) per weighted average common share — diluted	$	2.06	
 	 	$	(0.01	)	 	$	1.08	
 	 	$	(0.92	)	

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Quarter Ended	
 	2011	
 	December 31	 	September 30	 	June 30	 	March 31	
 	(In millions, except per share data)	
Operating revenues	$	2,132	
 	 	$	2,674	
 	 	$	2,278	
 	 	$	1,995	
 	
Operating income	9	
 	 	43	
 	 	269	
 	 	314	
 	
Net (loss)/income attributable to NRG Energy, Inc. 	$	(109	)	 	$	(55	)	 	$	621	
 	 	$	(260	)	
Weighted average number of common shares outstanding — basic	229	
 	 	240	
 	 	243	
 	 	247	
 	
Net (loss)/income per weighted average common share — basic	$	(0.48	)	 	$	(0.24	)	 	$	2.54	
 	 	$	(1.06	)	
Weighted average number of common shares outstanding — diluted	229	
 	 	240	
 	 	244	
 	 	247	
 	
Net (loss)/income per weighted average common share — diluted	$	(0.48	)	 	$	(0.24	)	 	$	2.53	
 	 	$	(1.06	)	

195

Note 28 — Condensed Consolidating Financial Information 
As of December 31, 2012, the Company had outstanding $5.9 billion of Senior Notes due 2018 - 2023, as shown in Note 11,  Debt and Capital Leases.  These Senior Notes are guaranteed by certain of NRG's current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries.
Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of December 31, 2012:

Arthur Kill Power LLC	NEO Freehold-Gen LLC	NRG Power Marketing LLC	
Astoria Gas Turbine Power LLC	NEO Power Services Inc.	NRG Reliability Solutions LLC	
Cabrillo Power I LLC	New Genco GP, LLC	NRG Renter's Protection LLC	
Cabrillo Power II LLC	Norwalk Power LLC	NRG Retail LLC	
Carbon Management Solutions LLC	NRG Affiliate Services Inc.	NRG Rockford Acquisition LLC	
Clean Edge Energy LLC	NRG Artesian Energy LLC	NRG Saguaro Operations Inc.	
Conemaugh Power LLC	NRG Arthur Kill Operations Inc.	NRG Security LLC	
Connecticut Jet Power LLC	NRG Astoria Gas Turbine Operations Inc.	NRG Services Corporation	
Cottonwood Development LLC	NRG Bayou Cove LLC	NRG SimplySmart Solutions LLC	
Cottonwood Energy Company LP	NRG Cabrillo Power Operations Inc.	NRG South Central Affiliate Services Inc.	
Cottonwood Generating Partners I LLC	NRG California Peaker Operations LLC	NRG South Central Generating LLC	
Cottonwood Generating Partners II LLC	NRG Cedar Bayou Development Company, LLC	NRG South Central Operations Inc.	
Cottonwood Generating Partners III LLC	NRG Connecticut Affiliate Services Inc.	NRG South Texas LP	
Cottonwood Technology Partners LP	NRG Construction LLC	NRG Texas C&I Supply LLC	
Devon Power LLC	NRG Development Company Inc.	NRG Texas Holding Inc.	
Dunkirk Power LLC	NRG Devon Operations Inc.	NRG Texas LLC	
Eastern Sierra Energy Company LLC	NRG Dispatch Services LLC	NRG Texas Power LLC	
El Segundo Power, LLC	NRG Dunkirk Operations Inc.	NRG Unemployment Protection LLC	
El Segundo Power II LLC	NRG El Segundo Operations Inc.	NRG Warranty Services LLC	
Elbow Creek Wind Project LLC	NRG Energy Labor Services LLC	NRG West Coast LLC	
Energy Alternatives Wholesale, LLC	NRG Energy Services Group LLC	NRG Western Affiliate Services Inc.	
Energy Plus Holdings LLC	NRG Energy Services LLC	O'Brien Cogeneration, Inc. II	
Energy Plus Natural Gas LLC	NRG Generation Holdings, Inc.	ONSITE Energy, Inc.	
Energy Protection Insurance Company	NRG Home & Business Solutions LLC	Oswego Harbor Power LLC	
Everything Energy LLC	NRG Home Solutions Product LLC	RE Retail Receivables, LLC	
GCP Funding Company LLC	NRG Homer City Services LLC	Reliant Energy Northeast LLC	
Green Mountain Energy Company	NRG Huntley Operations Inc.	Reliant Energy Power Supply, LLC	
Green Mountain Energy Company	NRG Identity Protect LLC	Reliant Energy Retail Holdings, LLC	
  (NY Com) LLC	NRG Ilion Limited Partnership	Reliant Energy Retail Services, LLC	
Green Mountain Energy Company	NRG Ilion LP LLC	RERH Holdings LLC	
  (NY Res) LLC	NRG International LLC	Saguaro Power LLC	
Huntley Power LLC	NRG Maintenance Services LLC	Somerset Operations Inc.	
Independence Energy Alliance LLC	NRG Mextrans Inc.	Somerset Power LLC	
Independence Energy Group LLC	NRG MidAtlantic Affiliate Services Inc.	Texas Genco Financing Corp.	
Independence Energy Natural Gas LLC	NRG Middletown Operations Inc.	Texas Genco GP, LLC	
Indian River Operations Inc.	NRG Montville Operations Inc.	Texas Genco Holdings, Inc.	
Indian River Power LLC	NRG New Jersey Energy Sales LLC	Texas Genco LP, LLC	
Keystone Power LLC	NRG New Roads Holdings LLC	Texas Genco Operating Services, LLC	
Langford Wind Power, LLC	NRG North Central Operations Inc.	Texas Genco Services, LP	
Louisiana Generating LLC	NRG Northeast Affiliate Services Inc.	US Retailers LLC	
Meriden Gas Turbines LLC	NRG Norwalk Harbor Operations Inc.	Vienna Operations, Inc.	
Middletown Power LLC	NRG Operating Services, Inc.	Vienna Power LLC	
Montville Power LLC	NRG Oswego Harbor Power Operations Inc.	WCP (Generation) Holdings LLC	
NEO Corporation	NRG PacGen Inc.	West Coast Power LLC	

196

The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries, including GenOn and its subsidiaries. NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. Except for NRG Bayou Cove, LLC, which is subject to certain restrictions under the Company's Peaker financing agreements, there are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. In addition, there may be restrictions for certain non-guarantor subsidiaries.
The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the Securities and Exchange Commission's Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.
In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.
In addition, the condensed parent company financial statements are provided in accordance with Rule 12-04, Schedule I of Regulation S‑X, as the restricted net assets of NRG Energy, Inc.’s subsidiaries exceed 25 percent of the consolidated net assets of NRG Energy, Inc. These statements should be read in conjunction with the consolidated statements and notes thereto of NRG Energy, Inc. For a discussion of NRG Energy, Inc.'s long-term debt, see Note 11,  Debt and Capital Leases to the consolidated financial statements. For a discussion of NRG Energy, Inc.'s contingencies, see Note 21,  Commitments and Contingencies  to the consolidated financial statements. For a discussion of NRG Energy, Inc.'s guarantees, see Note 25, Guarantees  to the consolidated financial statements.

197

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2012 

 	Guarantor
Subsidiaries	 	Non-Guarantor
Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations (a)	 	Consolidated
Balance	
 	(In millions)	
Operating Revenues	 	 	 	 	 	 	 	 	 	
Total operating revenues	$	7,998	
 	 	$	509	
 	 	$	—	
 	 	$	(85	)	 	$	8,422	
 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	
Cost of operations	5,864	
 	 	299	
 	 	—	
 	 	(76	)	 	6,087	
 	
Depreciation and amortization	860	
 	 	79	
 	 	11	
 	 	—	
 	 	950	
 	
Impairment charge on emission allowances	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	
Selling, general and administrative	543	
 	 	53	
 	 	307	
 	 	(11	)	 	892	
 	
GenOn acquisition-related transactions and integration costs	—	
 	 	53	
 	 	54	
 	 	—	
 	 	107	
 	
Development costs	—	
 	 	—	
 	 	36	
 	 	—	
 	 	36	
 	
Total operating costs and expenses	7,267	
 	 	484	
 	 	408	
 	 	(87	)	 	8,072	
 	
Operating Income/(Loss)	731	
 	 	25	
 	 	(408	)	 	2	
 	 	350	
 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	
Equity in earnings/(losses) of consolidated subsidiaries	30	
 	 	(15	)	 	620	
 	 	(635	)	 	—	
 	
Equity in earnings/(losses) of unconsolidated affiliates	8	
 	 	31	
 	 	(2	)	 	—	
 	 	37	
 	
Bargain purchase gain related to GenOn acquisition	—	
 	 	—	
 	 	560	
 	 	—	
 	 	560	
 	
Impairment charge on investment	(2	)	 	—	
 	 	—	
 	 	—	
 	 	(2	)	
Other income, net	6	
 	 	6	
 	 	9	
 	 	(2	)	 	19	
 	
Loss on debt extinguishment and refinancing	—	
 	 	—	
 	 	(51	)	 	—	
 	 	(51	)	
Interest expense	(26	)	 	(90	)	 	(545	)	 	—	
 	 	(661	)	
Total other income/(expense)	16	
 	 	(68	)	 	591	
 	 	(637	)	 	(98	)	
Income/(Loss) Before Income Taxes	747	
 	 	(43	)	 	183	
 	 	(635	)	 	252	
 	
Income tax expense/(benefit)	237	
 	 	(188	)	 	(376	)	 	—	
 	 	(327	)	
Net Income  	510	
 	 	145	
 	 	559	
 	 	(635	)	 	579	
 	
Less: Net income attributable to noncontrolling interest	—	
 	 	20	
 	 	—	
 	 	—	
 	 	20	
 	
Net Income attributable to NRG Energy, Inc	$	510	
 	 	$	125	
 	 	$	559	
 	 	$	(635	)	 	$	559	

 	 	
(a)	All significant intercompany transactions have been eliminated in consolidation.	

198

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the Year Ended December 31, 2012 

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated Balance	
 	(In millions)	
Net Income	$	510	
 	 	$	145	
 	 	$	559	
 	 	$	(635	)	 	$	579	
 	
Other comprehensive (loss)/income, net of tax	

 	 	
 	 	 	
Unrealized loss on derivatives, net	(160	)	 	(30	)	 	(214	)	 	241	
 	 	(163	)	
Foreign currency translation adjustments, net	—	
 	 	(2	)	 	1	
 	 	—	
 	 	(1	)	
Reclassification adjustment for translation loss realized upon sale of Schkopau, net	—	
 	 	(11	)	 	—	
 	 	—	
 	 	(11	)	
Available-for-sale securities, net	—	
 	 	—	
 	 	3	
 	 	—	
 	 	3	
 	
Defined benefit plan, net	(38	)	 	—	
 	 	(14	)	 	—	
 	 	(52	)	
Other comprehensive loss	(198	)	 	(43	)	 	(224	)	 	241	
 	 	(224	)	
Comprehensive income	312	
 	 	102	
 	 	335	
 	 	(394	)	 	355	
 	
Less: Comprehensive income attributable to noncontrolling interest	—	
 	 	20	
 	 	—	
 	 	—	
 	 	20	
 	
Comprehensive income attributable to NRG Energy, Inc.	312	
 	 	82	
 	 	335	
 	 	(394	)	 	335	
 	
Dividends for preferred shares	—	
 	 	—	
 	 	9	
 	 	—	
 	 	9	
 	
Comprehensive income available for common stockholders	$	312	
 	 	$	82	
 	 	$	326	
 	 	$	(394	)	 	$	326	

 	 	
(a)	All significant intercompany transactions have been eliminated in consolidation.	

199

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2012 

 	Guarantor
Subsidiaries	 	Non-Guarantor
Subsidiaries	 	NRG Energy, Inc.	 	Eliminations (a)	 	Consolidated Balance	
 	(In millions)	
ASSETS	 	 	 	 	 	 	 	 	 	
Current Assets	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	$	78	
 	 	$	1,258	
 	 	$	751	
 	 	$	—	
 	 	$	2,087	
 	
Funds deposited by counterparties	131	
 	 	140	
 	 	—	
 	 	—	
 	 	271	
 	
Restricted cash	11	
 	 	196	
 	 	10	
 	 	—	
 	 	217	
 	
Accounts receivable-trade, net	807	
 	 	179	
 	 	—	
 	 	—	
 	 	986	
 	
Inventory	472	
 	 	459	
 	 	—	
 	 	—	
 	 	931	
 	
Derivative instruments	2,058	
 	 	604	
 	 	—	
 	 	(18	)	 	2,644	
 	
Deferred income taxes	(153	)	 	10	
 	 	199	
 	 	—	
 	 	56	
 	
Cash collateral paid in support of energy risk management activities	81	
 	 	148	
 	 	—	
 	 	—	
 	 	229	
 	
Prepayments and other current assets	2,966	
 	 	77	
 	 	(2,518	)	 	10	
 	 	535	
 	
Total current assets	6,451	
 	 	3,071	
 	 	(1,558	)	 	(8	)	 	7,956	
 	
Net Property, Plant and Equipment	9,905	
 	 	10,262	
 	 	121	
 	 	(20	)	 	20,268	
 	
Other Assets	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	244	
 	 	(102	)	 	17,655	
 	 	(17,797	)	 	—	
 	
Equity investments in affiliates	33	
 	 	633	
 	 	10	
 	 	—	
 	 	676	
 	
Capital leases and notes receivable, less current portion	3	
 	 	74	
 	 	531	
 	 	(529	)	 	79	
 	
Goodwill	1,944	
 	 	12	
 	 	—	
 	 	—	
 	 	1,956	
 	
Intangible assets, net	1,042	
 	 	177	
 	 	33	
 	 	(52	)	 	1,200	
 	
Nuclear decommissioning trust fund	473	
 	 	—	
 	 	—	
 	 	—	
 	 	473	
 	
Deferred income taxes	(915	)	 	1,823	
 	 	353	
 	 	—	
 	 	1,261	
 	
Derivative instruments	149	
 	 	515	
 	 	—	
 	 	(2	)	 	662	
 	
Other non-current assets	85	
 	 	302	
 	 	210	
 	 	—	
 	 	597	
 	
Total other assets	3,058	
 	 	3,434	
 	 	18,792	
 	 	(18,380	)	 	6,904	
 	
Total Assets	$	19,414	
 	 	$	16,767	
 	 	$	17,355	
 	 	$	(18,408	)	 	$	35,128	
 	
LIABILITIES AND STOCKHOLDERS' EQUITY	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt and capital leases	$	1	
 	 	$	137	
 	 	$	15	
 	 	$	(6	)	 	$	147	
 	
Accounts payable	486	
 	 	2,004	
 	 	(1,320	)	 	—	
 	 	1,170	
 	
Derivative instruments	1,726	
 	 	271	
 	 	2	
 	 	(18	)	 	1,981	
 	
Cash collateral received in support of energy risk management activities	131	
 	 	140	
 	 	—	
 	 	—	
 	 	271	
 	
Accrued expenses and other current liabilities	354	
 	 	511	
 	 	243	
 	 	—	
 	 	1,108	
 	
Total current liabilities	2,698	
 	 	3,063	
 	 	(1,060	)	 	(24	)	 	4,677	
 	
Other Liabilities	 	 	 	 	 	 	 	 	 	
Long-term debt and capital leases	310	
 	 	8,456	
 	 	7,496	
 	 	(529	)	 	15,733	
 	
Nuclear decommissioning reserve	354	
 	 	—	
 	 	—	
 	 	—	
 	 	354	
 	
Nuclear decommissioning trust liability	273	
 	 	—	
 	 	—	
 	 	—	
 	 	273	
 	
Postretirement and other benefit obligations	431	
 	 	326	
 	 	46	
 	 	—	
 	 	803	
 	
Deferred income taxes	—	
 	 	55	
 	 	—	
 	 	—	
 	 	55	
 	
Derivative instruments	312	
 	 	190	
 	 	—	
 	 	(2	)	 	500	
 	
Out-of-market contracts	180	
 	 	1,067	
 	 	—	
 	 	(31	)	 	1,216	
 	
Other non-current liabilities	187	
 	 	459	
 	 	89	
 	 	—	
 	 	735	
 	
Total non-current liabilities	2,047	
 	 	10,553	
 	 	7,631	
 	 	(562	)	 	19,669	
 	
Total liabilities	4,745	
 	 	13,616	
 	 	6,571	
 	 	(586	)	 	24,346	
 	
3.625% Preferred Stock	—	
 	 	—	
 	 	249	
 	 	—	
 	 	249	
 	
Stockholders' Equity	14,669	
 	 	3,151	
 	 	10,535	
 	 	(17,822	)	 	10,533	
 	
Total Liabilities and Stockholders' Equity	$	19,414	
 	 	$	16,767	
 	 	$	17,355	
 	 	$	(18,408	)	 	$	35,128	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

200

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2012 

 	Guarantor
Subsidiaries	 	Non-Guarantor
Subsidiaries	 	NRG Energy, Inc.	 	Eliminations (a)	 	Consolidated
Balance	
 	(In millions)	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	
Net income	$	510	
 	 	$	145	
 	 	$	559	
 	 	$	(635	)	 	$	579	
 	
Adjustments to reconcile net income to net cash provided/(used) by operating activities:	 	 	 	 	 	 	 	 	 	
Distributions and equity in earnings of unconsolidated affiliates and consolidated subsidiaries	(29	)	 	14	
 	 	(440	)	 	457	
 	 	2	
 	
Gain on bargain purchase	—	
 	 	—	
 	 	(560	)	 	—	
 	 	(560	)	
Depreciation and amortization	860	
 	 	79	
 	 	11	
 	 	—	
 	 	950	
 	
Provision for bad debts	45	
 	 	—	
 	 	—	
 	 	—	
 	 	45	
 	
Amortization of nuclear fuel	39	
 	 	—	
 	 	—	
 	 	—	
 	 	39	
 	
Amortization of financing costs and debt discounts/premiums	—	
 	 	7	
 	 	24	
 	 	—	
 	 	31	
 	
Loss on debt extinguishment	—	
 	 	—	
 	 	9	
 	 	—	
 	 	9	
 	
Amortization of intangibles and out-of-market contracts. 	146	
 	 	—	
 	 	—	
 	 	—	
 	 	146	
 	
Changes in deferred income taxes and liability for uncertain tax benefits	237	
 	 	(188	)	 	(402	)	 	—	
 	 	(353	)	
Changes in nuclear decommissioning liability	37	
 	 	—	
 	 	—	
 	 	—	
 	 	37	
 	
Changes in derivative instruments	119	
 	 	7	
 	 	(2	)	 	—	
 	 	124	
 	
Loss on disposals and sales of assets	11	
 	 	—	
 	 	—	
 	 	—	
 	 	11	
 	
Amortization of unearned equity compensation	—	
 	 	6	
 	 	35	
 	 	—	
 	 	41	
 	
Other assets and liabilities	188	
 	 	(4	)	 	(136	)	 	—	
 	 	48	
 	
Net Cash Provided/(Used) by Operating Activities	2,163	
 	 	66	
 	 	(902	)	 	(178	)	 	1,149	
 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	
Intercompany loans to subsidiaries	(1,792	)	 	792	
 	 	—	
 	 	1,000	
 	 	—	
 	
Acquisition of business, net of cash acquired	—	
 	 	(17	)	 	(64	)	 	—	
 	 	(81	)	
Cash acquired in GenOn acquisition	—	
 	 	983	
 	 	—	
 	 	—	
 	 	983	
 	
Capital expenditures	(241	)	 	(3,091	)	 	(64	)	 	—	
 	 	(3,396	)	
Increase in restricted cash, net	(3	)	 	(63	)	 	—	
 	 	—	
 	 	(66	)	
Decrease in restricted cash - U.S. DOE projects	—	
 	 	121	
 	 	43	
 	 	—	
 	 	164	
 	
Increase in notes receivable	(1	)	 	(21	)	 	(2	)	 	—	
 	 	(24	)	
Proceeds from renewable energy grants	3	
 	 	59	
 	 	—	
 	 	—	
 	 	62	
 	
Purchases of emission allowances, net of proceeds	(1	)	 	—	
 	 	—	
 	 	—	
 	 	(1	)	
Investments in nuclear decommissioning trust fund securities	(436	)	 	—	
 	 	—	
 	 	—	
 	 	(436	)	
Proceeds from sales of nuclear decommissioning trust fund securities	399	
 	 	—	
 	 	—	
 	 	—	
 	 	399	
 	
Proceeds/(purchases) from sale of assets, net	133	
 	 	—	
 	 	4	
 	 	—	
 	 	137	
 	
Equity investment in unconsolidated affiliates	(1	)	 	(12	)	 	(12	)	 	—	
 	 	(25	)	
Other	24	
 	 	—	
 	 	(2	)	 	—	
 	 	22	
 	
Net Cash Used by Investing Activities	(1,916	)	 	(1,249	)	 	(97	)	 	1,000	
 	 	(2,262	)	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	
Proceeds/(payments) from intercompany loans	—	
 	 	—	
 	 	1,000	
 	 	(1,000	)	 	—	
 	
Payment of dividends to preferred stockholders	—	
 	 	—	
 	 	(50	)	 	—	
 	 	(50	)	
Payments of intercompany dividends	(172	)	 	(6	)	 	—	
 	 	178	
 	 	—	
 	
Payments for settlement of acquired derivatives that include financing elements	(83	)	 	15	
 	 	—	
 	 	—	
 	 	(68	)	
Proceeds from issuance of long-term debt	42	
 	 	2,105	
 	 	1,018	
 	 	—	
 	 	3,165	
 	
Sale proceeds and other contributions from noncontrolling interests in subsidiaries	—	
 	 	347	
 	 	—	
 	 	—	
 	 	347	
 	
Payment of debt issuance and hedging costs	—	
 	 	(19	)	 	(16	)	 	—	
 	 	(35	)	
Payments for short and long-term debt	—	
 	 	(82	)	 	(1,178	)	 	—	
 	 	(1,260	)	
Net Cash (Used)/Provided by Financing Activities	(213	)	 	2,360	
 	 	774	
 	 	(822	)	 	2,099	
 	
Effect of exchange rate changes on cash and cash equivalents	—	
 	 	(4	)	 	—	
 	 	—	
 	 	(4	)	
Net Increase/(decrease) in Cash and Cash Equivalents	34	
 	 	1,173	
 	 	(225	)	 	—	
 	 	982	
 	
Cash and Cash Equivalents at Beginning of Period	44	
 	 	85	
 	 	976	
 	 	—	
 	 	1,105	
 	
Cash and Cash Equivalents at End of Period	$	78	
 	 	$	1,258	
 	 	$	751	
 	 	$	—	
 	 	$	2,087	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

201

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2011 

 	Guarantor
Subsidiaries	 	Non-Guarantor
Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations (a)	 	Consolidated
Balance	
 	(In millions)	
Operating Revenues	 	 	 	 	 	 	 	 	 	
Total operating revenues	$	8,730	
 	 	$	381	
 	 	$	—	
 	 	$	(32	)	 	$	9,079	
 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	
Cost of operations	6,430	
 	 	266	
 	 	—	
 	 	(21	)	 	6,675	
 	
Depreciation and amortization	843	
 	 	40	
 	 	13	
 	 	—	
 	 	896	
 	
Impairment charge on emission allowances	160	
 	 	—	
 	 	—	
 	 	—	
 	 	160	
 	
Selling, general and administrative	393	
 	 	27	
 	 	252	
 	 	(4	)	 	668	
 	
Development costs	—	
 	 	(1	)	 	46	
 	 	—	
 	 	45	
 	
Total operating costs and expenses	7,826	
 	 	332	
 	 	311	
 	 	(25	)	 	8,444	
 	
Operating Income/(Loss)	904	
 	 	49	
 	 	(311	)	 	(7	)	 	635	
 	
Other (Expense)/Income	 	 	 	 	 	 	 	 	 	
Equity in earnings/(losses) of consolidated subsidiaries	24	
 	 	(7	)	 	593	
 	 	(610	)	 	—	
 	
Equity in earnings of unconsolidated affiliates	10	
 	 	25	
 	 	—	
 	 	—	
 	 	35	
 	
Impairment charge on investment	(495	)	 	—	
 	 	—	
 	 	—	
 	 	(495	)	
Other income, net	2	
 	 	13	
 	 	4	
 	 	—	
 	 	19	
 	
Loss on debt extinguishment and refinancing expense	—	
 	 	—	
 	 	(175	)	 	—	
 	 	(175	)	
Interest expense	(59	)	 	(56	)	 	(550	)	 	—	
 	 	(665	)	
Total other expense	(518	)	 	(25	)	 	(128	)	 	(610	)	 	(1,281	)	
Income/(Loss) Before Income Taxes	386	
 	 	24	
 	 	(439	)	 	(617	)	 	(646	)	
Income tax (benefit)/expense	(214	)	 	7	
 	 	(636	)	 	—	
 	 	(843	)	
Net Income attributable to NRG Energy, Inc. 	$	600	
 	 	$	17	
 	 	$	197	
 	 	$	(617	)	 	$	197	

 	 	
(a)	All significant intercompany transactions have been eliminated in consolidation.	

202

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the Year Ended December 31, 2011 

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated Balance	
 	(In millions)	
Net Income	$	600	
 	 	$	17	
 	 	$	197	
 	 	$	(617	)	 	$	197	
 	
Other comprehensive income/(loss), net of tax	

 	 	
 	 	 	
Unrealized loss on derivatives, net	(303	)	 	(27	)	 	(345	)	 	366	
 	 	(309	)	
Foreign currency translation adjustments, net	—	
 	 	(2	)	 	—	
 	 	—	
 	 	(2	)	
Available-for-sale securities, net	—	
 	 	—	
 	 	(1	)	 	—	
 	 	(1	)	
Defined benefit plan, net	(34	)	 	—	
 	 	(12	)	 	—	
 	 	(46	)	
Other comprehensive loss	(337	)	 	(29	)	 	(358	)	 	366	
 	 	(358	)	
Comprehensive income/(loss) attributable to NRG Energy, Inc.	263	
 	 	(12	)	 	(161	)	 	(251	)	 	(161	)	
Dividends for preferred shares	—	
 	 	—	
 	 	9	
 	 	—	
 	 	9	
 	
Comprehensive income/(loss) available for common stockholders	$	263	
 	 	$	(12	)	 	$	(170	)	 	$	(251	)	 	$	(170	)	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

203

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2011 

 	Guarantor
Subsidiaries	 	Non-Guarantor
Subsidiaries	 	NRG Energy, Inc.	 	Eliminations (a)	 	Consolidated
Balance	
 	(In millions)	
ASSETS	 	 	 	 	 	 	 	 	 	
Current Assets	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	$	44	
 	 	$	85	
 	 	$	976	
 	 	$	—	
 	 	$	1,105	
 	
Funds deposited by counterparties	258	
 	 	—	
 	 	—	
 	 	—	
 	 	258	
 	
Restricted cash	8	
 	 	231	
 	 	53	
 	 	—	
 	 	292	
 	
Accounts receivable-trade, net	789	
 	 	45	
 	 	—	
 	 	—	
 	 	834	
 	
Inventory	300	
 	 	8	
 	 	—	
 	 	—	
 	 	308	
 	
Derivative instruments	4,433	
 	 	—	
 	 	—	
 	 	(6	)	 	4,427	
 	
Cash collateral paid in support of energy risk management activities	311	
 	 	—	
 	 	—	
 	 	—	
 	 	311	
 	
Prepayments and other current assets	1,212	
 	 	(14	)	 	(983	)	 	(1	)	 	214	
 	
Total current assets	7,355	
 	 	355	
 	 	46	
 	 	(7	)	 	7,749	
 	
Net Property, Plant and Equipment	10,456	
 	 	3,116	
 	 	67	
 	 	(18	)	 	13,621	
 	
Other Assets	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	225	
 	 	491	
 	 	16,169	
 	 	(16,885	)	 	—	
 	
Equity investments in affiliates	33	
 	 	607	
 	 	—	
 	 	—	
 	 	640	
 	
Notes receivable - affiliate and capital leases, less current portion	1	
 	 	341	
 	 	172	
 	 	(172	)	 	342	
 	
Goodwill	1,886	
 	 	—	
 	 	—	
 	 	—	
 	 	1,886	
 	
Intangible assets, net	1,340	
 	 	84	
 	 	33	
 	 	(38	)	 	1,419	
 	
Nuclear decommissioning trust fund	424	
 	 	—	
 	 	—	
 	 	—	
 	 	424	
 	
Derivative instruments	452	
 	 	31	
 	 	—	
 	 	—	
 	 	483	
 	
Other non-current assets	55	
 	 	72	
 	 	209	
 	 	—	
 	 	336	
 	
Total other assets	4,416	
 	 	1,626	
 	 	16,583	
 	 	(17,095	)	 	5,530	
 	
Total Assets	$	22,227	
 	 	$	5,097	
 	 	$	16,696	
 	 	$	(17,120	)	 	$	26,900	
 	
LIABILITIES AND STOCKHOLDERS' EQUITY	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt and capital leases	$	—	
 	 	$	72	
 	 	$	15	
 	 	$	—	
 	 	$	87	
 	
Accounts payable	(407	)	 	122	
 	 	1,093	
 	 	—	
 	 	808	
 	
Derivative instruments	3,990	
 	 	23	
 	 	22	
 	 	(6	)	 	4,029	
 	
Deferred income taxes	534	
 	 	(51	)	 	(356	)	 	—	
 	 	127	
 	
Cash collateral received in support of energy risk management activities	258	
 	 	—	
 	 	—	
 	 	—	
 	 	258	
 	
Accrued expenses and other current liabilities	283	
 	 	23	
 	 	247	
 	 	(1	)	 	552	
 	
Total current liabilities	4,658	
 	 	189	
 	 	1,021	
 	 	(7	)	 	5,861	
 	
Other Liabilities	 	 	 	 	 	 	 	 	 	
Long-term debt and capital leases	264	
 	 	1,999	
 	 	7,654	
 	 	(172	)	 	9,745	
 	
Nuclear decommissioning reserve	335	
 	 	—	
 	 	—	
 	 	—	
 	 	335	
 	
Nuclear decommissioning trust liability	254	
 	 	—	
 	 	—	
 	 	—	
 	 	254	
 	
Postretirement and other benefit obligations	367	
 	 	—	
 	 	33	
 	 	—	
 	 	400	
 	
Deferred income taxes	950	
 	 	273	
 	 	166	
 	 	—	
 	 	1,389	
 	
Derivative instruments	400	
 	 	55	
 	 	4	
 	 	—	
 	 	459	
 	
Out-of-market commodity contracts	208	
 	 	6	
 	 	—	
 	 	(31	)	 	183	
 	
Other non-current liabilities	177	
 	 	96	
 	 	83	
 	 	—	
 	 	356	
 	
Total non-current liabilities	2,955	
 	 	2,429	
 	 	7,940	
 	 	(203	)	 	13,121	
 	
Total liabilities	7,613	
 	 	2,618	
 	 	8,961	
 	 	(210	)	 	18,982	
 	
3.625% Preferred Stock	—	
 	 	—	
 	 	249	
 	 	—	
 	 	249	
 	
Stockholders' Equity	14,614	
 	 	2,479	
 	 	7,486	
 	 	(16,910	)	 	7,669	
 	
Total Liabilities and Stockholders' Equity	$	22,227	
 	 	$	5,097	
 	 	$	16,696	
 	 	$	(17,120	)	 	$	26,900	

 	 	
(a)	All significant intercompany transactions have been eliminated in consolidation.	

204

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2011 

 	Guarantor
Subsidiaries	 	Non-Guarantor
Subsidiaries	 	NRG Energy, Inc.	 	Eliminations (a)	 	Consolidated
Balance	
 	(In millions)	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	
Net income	$	600	
 	 	$	17	
 	 	$	197	
 	 	$	(617	)	 	$	197	
 	
Adjustments to reconcile net income to net cash provided by operating activities:	 	 	 	 	 	 	 	 	 	
Distributions and equity (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries	(11	)	 	3	
 	 	776	
 	 	(759	)	 	9	
 	
Depreciation and amortization	843	
 	 	40	
 	 	13	
 	 	—	
 	 	896	
 	
Provision for bad debts	59	
 	 	—	
 	 	—	
 	 	—	
 	 	59	
 	
Amortization of nuclear fuel	39	
 	 	—	
 	 	—	
 	 	—	
 	 	39	
 	
Amortization of financing costs and debt discounts/premiums	—	
 	 	6	
 	 	26	
 	 	—	
 	 	32	
 	
Loss on debt extinguishment	—	
 	 	—	
 	 	58	
 	 	—	
 	 	58	
 	
Amortization of intangibles and out-of-market contracts. 	166	
 	 	1	
 	 	—	
 	 	—	
 	 	167	
 	
Changes in deferred income taxes and liability for uncertain tax benefits	(214	)	 	7	
 	 	(652	)	 	—	
 	 	(859	)	
Changes in nuclear decommissioning liability	20	
 	 	—	
 	 	—	
 	 	—	
 	 	20	
 	
Changes in derivatives	(137	)	 	(1	)	 	—	
 	 	—	
 	 	(138	)	
Impairment charges and asset write downs	648	
 	 	9	
 	 	—	
 	 	—	
 	 	657	
 	
Loss gain on disposals and sales of assets	13	
 	 	1	
 	 	—	
 	 	—	
 	 	14	
 	
Amortization of unearned equity compensation	—	
 	 	—	
 	 	28	
 	 	—	
 	 	28	
 	
Other assets and liabilities	(1,405	)	 	211	
 	 	1,174	
 	 	7	
 	 	(13	)	
Net Cash Provided by Operating Activities	621	
 	 	294	
 	 	1,620	
 	 	(1,369	)	 	1,166	
 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	
Intercompany loans to subsidiaries	796	
 	 	—	
 	 	287	
 	 	(1,083	)	 	—	
 	
Investment in subsidiaries	—	
 	 	(1,300	)	 	—	
 	 	1,300	
 	 	—	
 	
Acquisition of businesses, net of cash acquired	—	
 	 	(115	)	 	(262	)	 	—	
 	 	(377	)	
Capital expenditures	(383	)	 	(1,882	)	 	(45	)	 	—	
 	 	(2,310	)	
Increase in restricted cash, net	(5	)	 	(29	)	 	(1	)	 	—	
 	 	(35	)	
Increase in restricted cash - U.S. DOE projects	—	
 	 	(162	)	 	(53	)	 	—	
 	 	(215	)	
Decrease in notes receivable	—	
 	 	12	
 	 	—	
 	 	—	
 	 	12	
 	
Purchases of emission allowances, net of proceeds	(19	)	 	—	
 	 	—	
 	 	—	
 	 	(19	)	
Investments in nuclear decommissioning trust fund securities	(406	)	 	—	
 	 	—	
 	 	—	
 	 	(406	)	
Proceeds from sales of nuclear decommissioning trust fund securities	385	
 	 	—	
 	 	—	
 	 	—	
 	 	385	
 	
Proceeds/(purchases) from sale of assets, net	13	
 	 	(6	)	 	—	
 	 	—	
 	 	7	
 	
Equity investment in unconsolidated affiliate	(2	)	 	(64	)	 	—	
 	 	—	
 	 	(66	)	
Other	(2	)	 	(8	)	 	(13	)	 	—	
 	 	(23	)	
Net Cash Provided/(Used) by Investing Activities	377	
 	 	(3,554	)	 	(87	)	 	217	
 	 	(3,047	)	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	
(Payments)/proceeds from intercompany loans	(1,112	)	 	825	
 	 	(796	)	 	1,083	
 	 	—	
 	
Payment of dividends to preferred stockholders	—	
 	 	—	
 	 	(9	)	 	—	
 	 	(9	)	
Payment of intercompany dividends	(65	)	 	(4	)	 	—	
 	 	69	
 	 	—	
 	
Payment for treasury stock	—	
 	 	—	
 	 	(430	)	 	—	
 	 	(430	)	
Net receipts from acquired derivatives that include financing elements	(83	)	 	—	
 	 	—	
 	 	—	
 	 	(83	)	
Proceeds from issuance of long-term debt	138	
 	 	1,290	
 	 	4,796	
 	 	—	
 	 	6,224	
 	
Decreases in restricted cash supporting funded letter of credit facility	—	
 	 	1,300	
 	 	—	
 	 	—	
 	 	1,300	
 	
Payment for settlement of funded letter of credit	—	
 	 	—	
 	 	(1,300	)	 	—	
 	 	(1,300	)	
Cash proceeds from sale of noncontrolling interest in subsidiary	—	
 	 	29	
 	 	—	
 	 	—	
 	 	29	
 	
Proceeds from issuance of common stock	—	
 	 	—	
 	 	2	
 	 	—	
 	 	2	
 	
Payment of debt issuance and hedging costs	—	
 	 	(92	)	 	(115	)	 	—	
 	 	(207	)	
Payments of short and long-term debt	—	
 	 	(116	)	 	(5,377	)	 	—	
 	 	(5,493	)	
Net Cash (Used)/Provided by Financing Activities	(1,122	)	 	3,232	
 	 	(3,229	)	 	1,152	
 	 	33	
 	
Effect of exchange rate changes on cash and cash equivalents	—	
 	 	2	
 	 	—	
 	 	—	
 	 	2	
 	
Net Decrease in Cash and Cash Equivalents	(124	)	 	(26	)	 	(1,696	)	 	—	
 	 	(1,846	)	
Cash and Cash Equivalents at Beginning of Period	168	
 	 	111	
 	 	2,672	
 	 	—	
 	 	2,951	
 	
Cash and Cash Equivalents at End of Period	$	44	
 	 	$	85	
 	 	$	976	
 	 	$	—	
 	 	$	1,105	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

205

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2010 

 	Guarantor
Subsidiaries	 	Non-Guarantor
Subsidiaries	 	NRG Energy, Inc.	 	Eliminations (a)	 	Consolidated
Balance	
 	(In millions)	
Operating Revenues	 	 	 	 	 	 	 	 	 	
Total operating revenues	$	8,507	
 	 	$	374	
 	 	$	—	
 	 	$	(32	)	 	$	8,849	
 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	
Cost of operations	5,849	
 	 	256	
 	 	—	
 	 	(32	)	 	6,073	
 	
Depreciation and amortization	796	
 	 	32	
 	 	10	
 	 	—	
 	 	838	
 	
Selling, general and administrative	325	
 	 	12	
 	 	261	
 	 	—	
 	 	598	
 	
Development costs	—	
 	 	10	
 	 	45	
 	 	—	
 	 	55	
 	
Total operating costs and expenses	6,970	
 	 	310	
 	 	316	
 	 	(32	)	 	7,564	
 	
Gain on sale of assets	—	
 	 	—	
 	 	23	
 	 	—	
 	 	23	
 	
Operating Income/(Loss)	1,537	
 	 	64	
 	 	(293	)	 	—	
 	 	1,308	
 	
Other Income	 	 	 	 	 	 	 	 	 	
Equity in earnings/(losses) of consolidated subsidiaries	38	
 	 	(1	)	 	979	
 	 	(1,016	)	 	—	
 	
Equity in earnings of unconsolidated affiliates	6	
 	 	38	
 	 	—	
 	 	—	
 	 	44	
 	
Other income, net	4	
 	 	25	
 	 	4	
 	 	—	
 	 	33	
 	
Loss on debt extinguishment and refinancing expense	—	
 	 	—	
 	 	(2	)	 	—	
 	 	(2	)	
Interest expense	(11	)	 	(52	)	 	(567	)	 	—	
 	 	(630	)	
Total other income	37	
 	 	10	
 	 	414	
 	 	(1,016	)	 	(555	)	
Income Before Income Taxes	1,574	
 	 	74	
 	 	121	
 	 	(1,016	)	 	753	
 	
Income tax expense/(benefit)	593	
 	 	40	
 	 	(356	)	 	—	
 	 	277	
 	
Net Income	981	
 	 	34	
 	 	477	
 	 	(1,016	)	 	476	
 	
Less: Net loss attributable to noncontrolling interest	(1	)	 	—	
 	 	—	
 	 	—	
 	 	(1	)	
Net Income attributable to NRG Energy, Inc . 	$	982	
 	 	$	34	
 	 	$	477	
 	 	$	(1,016	)	 	$	477	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

206

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the Year Ended December 31, 2010 

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated Balance	
 	(In millions)	
Net Income	$	981	
 	 	$	34	
 	 	$	477	
 	 	$	(1,016	)	 	$	476	
 	
Other comprehensive income/(loss), net of tax	

 	 	
 	 	 	
Unrealized gain/(loss) on derivatives, net	21	
 	 	(11	)	 	10	
 	 	15	
 	 	35	
 	
Foreign currency translation adjustments, net	—	
 	 	(6	)	 	3	
 	 	—	
 	 	(3	)	
Defined benefit plan, net	(19	)	 	—	
 	 	3	
 	 	—	
 	 	(16	)	
Other comprehensive income/(loss)	2	
 	 	(17	)	 	16	
 	 	15	
 	 	16	
 	
Comprehensive income	983	
 	 	17	
 	 	493	
 	 	(1,001	)	 	492	
 	
Less: Comprehensive loss attributable to noncontrolling interest	(1	)	 	—	
 	 	—	
 	 	—	
 	 	(1	)	
Comprehensive income attributable to NRG Energy, Inc.	984	
 	 	17	
 	 	493	
 	 	(1,001	)	 	493	
 	
Dividends for preferred shares	—	
 	 	—	
 	 	9	
 	 	—	
 	 	9	
 	
Comprehensive income available for common stockholders	$	984	
 	 	$	17	
 	 	$	484	
 	 	$	(1,001	)	 	$	484	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

207

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2010

 	Guarantor
Subsidiaries	 	Non-Guarantor
Subsidiaries	 	NRG Energy, Inc.	 	Elimin-ations (a)	 	Consolidated
Balance	
 	(In millions)	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	
Net income	$	981	
 	 	$	34	
 	 	$	477	
 	 	$	(1,016	)	 	$	476	
 	
Adjustments to reconcile net income to net cash provided/(used) by operating activities:	 	 	 	 	 	 	 	 	 	
Distributions and equity (earnings)/losses of unconsolidated affiliates	14	
 	 	(12	)	 	(914	)	 	893	
 	 	(19	)	
Depreciation and amortization	796	
 	 	32	
 	 	10	
 	 	—	
 	 	838	
 	
Provision for bad debts	54	
 	 	—	
 	 	—	
 	 	—	
 	 	54	
 	
Amortization of nuclear fuel	40	
 	 	—	
 	 	—	
 	 	—	
 	 	40	
 	
Amortization of financing costs and debt discount/premiums	—	
 	 	6	
 	 	26	
 	 	—	
 	 	32	
 	
Amortization of intangibles and out-of-market contracts	4	
 	 	—	
 	 	—	
 	 	—	
 	 	4	
 	
Impairment charges and asset write downs	20	
 	 	—	
 	 	5	
 	 	—	
 	 	25	
 	
Changes in deferred income taxes and liability for uncertain tax benefits	593	
 	 	27	
 	 	(365	)	 	—	
 	 	255	
 	
Change in nuclear decommissioning trust liability	34	
 	 	—	
 	 	—	
 	 	—	
 	 	34	
 	
Changes in derivatives	(113	)	 	(1	)	 	—	
 	 	—	
 	 	(114	)	
Loss/(gain) on disposals and sales of assets	27	
 	 	—	
 	 	(23	)	 	—	
 	 	4	
 	
Amortization of unearned equity compensation	—	
 	 	—	
 	 	30	
 	 	—	
 	 	30	
 	
Other assets and liabilities	(625	)	 	(187	)	 	776	
 	 	—	
 	 	(36	)	
Net Cash Provided/(Used) by Operating Activities	1,825	
 	 	(101	)	 	22	
 	 	(123	)	 	1,623	
 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	
Intercompany loans to subsidiaries	(1,620	)	 	—	
 	 	(195	)	 	1,815	
 	 	—	
 	
Investment in subsidiaries	—	
 	 	1,727	
 	 	(1,727	)	 	—	
 	 	—	
 	
Capital expenditures	(308	)	 	(323	)	 	(75	)	 	—	
 	 	(706	)	
Acquisition of business, net of cash acquired	—	
 	 	(142	)	 	(864	)	 	—	
 	 	(1,006	)	
Decrease/(increase) in restricted cash	1	
 	 	(5	)	 	—	
 	 	—	
 	 	(4	)	
(Increase)/decrease in notes receivable	—	
 	 	39	
 	 	—	
 	 	—	
 	 	39	
 	
Purchases of emission allowances, net of proceeds	(34	)	 	—	
 	 	—	
 	 	—	
 	 	(34	)	
Investments in nuclear decommissioning trust fund securities	(341	)	 	—	
 	 	—	
 	 	—	
 	 	(341	)	
Proceeds from sales of nuclear decommissioning trust fund securities	307	
 	 	—	
 	 	—	
 	 	—	
 	 	307	
 	
Proceeds from renewable energy grants	84	
 	 	18	
 	 	—	
 	 	—	
 	 	102	
 	
Proceeds from sale of assets, net	14	
 	 	—	
 	 	29	
 	 	—	
 	 	43	
 	
Equity investment in unconsolidated affiliates, net	4	
 	 	(22	)	 	(5	)	 	—	
 	 	(23	)	
Net Cash (Used)/Provided by Investing Activities	(1,893	)	 	1,292	
 	 	(2,837	)	 	1,815	
 	 	(1,623	)	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	
Proceeds from intercompany loans	69	
 	 	126	
 	 	1,620	
 	 	(1,815	)	 	—	
 	
Payment of intercompany dividends	(58	)	 	(65	)	 	—	
 	 	123	
 	 	—	
 	
Payment for dividends to preferred stockholders	—	
 	 	—	
 	 	(9	)	 	—	
 	 	(9	)	
Net receipts from acquired derivatives including financing elements	137	
 	 	—	
 	 	—	
 	 	—	
 	 	137	
 	
Payment for treasury stock	—	
 	 	—	
 	 	(180	)	 	—	
 	 	(180	)	
Installment proceeds from sale of noncontrolling interest of subsidiary	—	
 	 	50	
 	 	—	
 	 	—	
 	 	50	
 	
Proceeds from issuance of common stock	—	
 	 	—	
 	 	2	
 	 	—	
 	 	2	
 	
Proceeds from issuance of long-term debt	73	
 	 	306	
 	 	1,105	
 	 	—	
 	 	1,484	
 	
Proceeds from issuance of term loan for funded letter of credit facility	—	
 	 	—	
 	 	1,300	
 	 	—	
 	 	1,300	
 	
Increase in restricted cash supporting funded letter of credit facility	—	
 	 	(1,300	)	 	—	
 	 	—	
 	 	(1,300	)	
Payment of debt issuance and hedging costs	(5	)	 	(9	)	 	(61	)	 	—	
 	 	(75	)	
Payments of short and long-term debt	—	
 	 	(304	)	 	(454	)	 	—	
 	 	(758	)	
Net Cash Provided/(Used) by Financing Activities	216	
 	 	(1,196	)	 	3,323	
 	 	(1,692	)	 	651	
 	
Effect of exchange rate changes on cash and cash equivalents	—	
 	 	(4	)	 	—	
 	 	—	
 	 	(4	)	
Net Increase/(Decrease) in Cash and Cash Equivalents	148	
 	 	(9	)	 	508	
 	 	—	
 	 	647	
 	
Cash and Cash Equivalents at Beginning of Period	20	
 	 	120	
 	 	2,164	
 	 	—	
 	 	2,304	
 	
Cash and Cash Equivalents at End of Period	$	168	
 	 	$	111	
 	 	$	2,672	
 	 	$	—	
 	 	$	2,951	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

208

SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2012, 2011, and 2010 

 	Balance at
Beginning of
Period	 	Charged to
Costs and
Expenses	 	Charged to
Other Accounts	 	Deductions	 	Balance at
End of Period	
 	(In millions)	
Allowance for doubtful accounts, deducted from accounts receivable	 	 	 	 	 	 	 	 	 	
Year Ended December 31, 2012	$	23	
 	 	$	46	

 	 	$	(37	)	(a) 	$	32	
 	
Year Ended December 31, 2011	25	
 	 	60	
 	 	—	
 	 	(62	)	(a) 	23	
 	
Year Ended December 31, 2010	29	
 	 	54	
 	 	—	
 	 	(58	)	(a) 	25	
 	
Income tax valuation allowance, deducted from deferred tax assets	 	 	 	 	 	 	 	 	 	
Year Ended December 31, 2012	$	83	
 	 	$	5	
 	 	$	103	
 	(b) 	$	—	
 	 	$	191	
 	
Year Ended December 31, 2011	191	
 	 	(63	)	 	(45	)	 	—	
 	 	83	
 	
Year Ended December 31, 2010	233	
 	 	(34	)	 	(8	)	 	—	
 	 	191	

(a)	Represents principally net amounts charged as uncollectible.	
 	 	
(b)	Includes amounts associated with the GenOn acquisition.	

209

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 ENERGY, INC.
(Registrant)	 	
 	 	 	 	
 	By:	/s/ DAVID W. CRANE  	 	
 	 	 	
 	 	David W. Crane
Chief Executive Officer	 	

Date: February 27, 2013 

210

POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints David W. Crane, David R. Hill and Brian 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, 2013.

Signature	 	Title	 	Date	 	
/s/ DAVID W. CRANE  	 	President, Chief Executive Officer and	 	February 27, 2013	 	
David W. Crane	 	Director (Principal Executive Officer)	 	 	 	
 	 	 	 	 	 	
/s/ KIRKLAND B. ANDREWS 	 	Chief Financial Officer	 	February 27, 2013	 	
Kirkland B. Andrews	 	(Principal Financial Officer)	 	 	 	
 	 	 	 	 	 	
/s/ RONALD B. STARK  	 	Chief Accounting Officer	 	February 27, 2013	 	
Ronald B. Stark	 	(Principal Accounting Officer)	 	 	 	
 	 	 	 	 	 	
/s/ HOWARD E. COSGROVE  	 	Chairman of the Board	 	February 27, 2013	 	
Howard E. Cosgrove	 	 	 	 	 	 	
 	 	 	 	 	 	 	
/s/ EDWARD R. MULLER	 	Vice Chairman of the Board	 	February 27, 2013	 	 	
Edward R. Muller	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	
/s/ E. SPENCER ABRAHAM	 	Director	 	February 27, 2013	 	 	 	
E. Spencer Abraham	 	 	 	 	 	 	 	 	
/s/ KIRBYJON H. CALDWELL	 	Director	 	February 27, 2013	 	 	 	 	
Kirbyjon H. Caldwell	 	 	 	 	 	 	 	 	 	
/s/ JOHN F. CHLEBOWSKI  	 	Director	 	February 27, 2013	 	 	 	 	 	
John F. Chlebowski	 	 	 	 	 	 	 	 	 	 	
/s/ LAWRENCE S. COBEN  	 	Director	 	February 27, 2013	 	 	 	 	 	 	
Lawrence S. Coben	 	 	 	 	 	 	 	 	 	 	 	
/s/ TERRY G. DALLAS	 	Director	 	February 27, 2013	 	 	 	 	 	 	 	
Terry G. Dallas	 	 	 	 	 	 	 	 	 	 	 	 	
/s/ WILLIAM E. HANTKE  	 	Director	 	February 27, 2013	 	 	 	 	 	 	 	 	
William E. Hantke	 	 	 	 	 	 	 	 	 	 	 	 	 	
/s/ PAUL W. HOBBY  	 	Director	 	February 27, 2013	 	 	 	 	 	 	 	 	 	
Paul W. Hobby	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
/s/ GERALD LUTERMAN  	 	Director	 	February 27, 2013	 	 	 	 	 	 	 	 	 	 	
Gerald Luterman	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
/s/ KATHLEEN A. MCGINTY  	 	Director	 	February 27, 2013	 	 	 	 	 	 	 	 	 	 	 	
Kathleen A. McGinty	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
/s/ ANNE C. SCHAUMBURG  	 	Director	 	February 27, 2013	 	 	 	 	 	 	 	 	 	 	 	 	
Anne C. Schaumburg	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
/s/ EVAN J. SILVERSTEIN	 	Director	 	February 27, 2013	 	 	 	 	 	 	 	 	 	 	 	 	 	
Evan J. Silverstein	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
/s/ THOMAS H. WEIDEMEYER  	 	Director	 	February 27, 2013	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Thomas H. Weidemeyer	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
/s/ WALTER R. YOUNG	    	Director	 	February 27, 2013	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Walter R. Young	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

211

EXHIBIT INDEX

Number	 	Description	 	Method of Filing	
2.1	 	Third Amended Joint Plan of Reorganization of NRG Energy, Inc., NRG Power Marketing, Inc., NRG Capital LLC, NRG Finance Company I LLC, and NRGenerating Holdings (No. 23) B.V.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on November 19, 2003.	
2.2	 	First Amended Joint Plan of Reorganization of NRG Northeast Generating LLC (and certain of its subsidiaries), NRG South Central Generating (and certain of its subsidiaries) and Berrians I Gas Turbine Power LLC.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on November 19, 2003.	
2.3	 	Acquisition Agreement, dated as of September 30, 2005, by and among NRG Energy, Inc., Texas Genco LLC and the Direct and Indirect Owners of Texas Genco LLC.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on October 3, 2005.	
2.4	 	Purchase and Sale Agreement by and between Denali Merger Sub and NRG Energy, Inc. dated as of August 13, 2010.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on August 13, 2010.	
2.5	 	Agreement and Plan of Merger, dated as of July 20, 2012, by and among NRG Energy, Inc., Plus Energy Corporation and GenOn Energy, Inc.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on July 23, 2012.	
3.1	 	Amended and Restated Certificate of Incorporation.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on May 3, 2012.	
3.2	 	Certificate of Amendment of Amended and Restated Certificate of Incorporation.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on December 14, 2012.	
3.3	 	Second Amended and Restated By-Laws.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on December 14, 2012.	
3.4	 	Certificate of Designations of 3.625% Convertible Perpetual Preferred Stock, as filed with the Secretary of State of the State of Delaware on August 11, 2005.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on August 11, 2005.	
3.5	 	Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on August 4, 2006.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on August 10, 2006.	
3.6	 	Certificate of Amendment to Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on February 27, 2008.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008.	
3.7	 	Second Certificate of Amendment to Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on August 8, 2008.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on October 30, 2008.	
4.1	 	Supplemental Indenture dated as of December 30, 2005, among NRG Energy, Inc., the subsidiary guarantors named on Schedule A thereto and Law Debenture Trust Company of New York, as trustee.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on January 4, 2006.	
4.2	 	Amended and Restated Common Agreement among XL Capital Assurance Inc., Goldman Sachs Mitsui Marine Derivative Products, L.P., Law Debenture Trust Company of New York, as Trustee, The Bank of New York, as Collateral Agent, NRG Peaker Finance Company LLC and each Project Company Party thereto dated as of January 6, 2004, together with Annex A to the Common Agreement.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on March 16, 2004.	
4.3	 	Amended and Restated Security Deposit Agreement among NRG Peaker Finance Company, LLC and each Project Company party thereto, and the Bank of New York, as Collateral Agent and Depositary Agent, dated as of January 6, 2004.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on March 16, 2004.	
4.4	 	NRG Parent Agreement by NRG Energy, Inc. in favor of the Bank of New York, as Collateral Agent, dated as of January 6, 2004.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on March 16, 2004.	
4.5	 	Indenture dated June 18, 2002, between NRG Peaker Finance Company LLC, as Issuer, Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Rockford LLC, NRG Rockford II LLC and Sterlington Power LLC, as Guarantors, XL Capital Assurance Inc., as Insurer, and Law Debenture Trust Company, as Successor Trustee to the Bank of New York.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on March 31, 2003.	
4.6	 	Specimen of Certificate representing common stock of NRG Energy, Inc.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on August 4, 2006.	
4.7	 	Indenture, dated February 2, 2006, among NRG Energy, Inc. and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on February 6, 2006.	

212

 	
 	 	 	 	 	
4.8	 	First Supplemental Indenture, dated February 2, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.250% Senior Notes due 2014.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on February 6, 2006.	
4.9	 	Second Supplemental Indenture, dated February 2, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2016.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on February 6, 2006.	
4.10	 	Form of 7.250% Senior Note due 2014.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on February 6, 2006.	
4.11	 	Form of 7.375% Senior Note due 2016.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on February 6, 2006.	
4.12	 	Form of 7.375% Senior Note due 2017.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on November 27, 2006.	
4.13	 	Form of 8.5% Senior Note due 2019.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on June 5, 2009.	
4.14	 	Third Supplemental Indenture, dated March 14, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.250% Senior Notes due 2014.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on March 16, 2006.	
4.15	 	Fourth Supplemental Indenture, dated March 14, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2016.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on March 16, 2006.	
4.16	 	Fifth Supplemental Indenture, dated April 28, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.250% Senior Notes due 2014.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 3, 2006.	
4.17	 	Sixth Supplemental Indenture, dated April 28, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2016.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 3, 2006.	
4.18	 	Seventh Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.250% Senior Notes due 2014.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on November 14, 2006.	
4.19	 	Eighth Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2016.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on November 14, 2006.	
4.20	 	Ninth Supplemental Indenture, dated November 21, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2017.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on November 27, 2006.	
4.21	 	Tenth Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.250% Senior Notes due 2014.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on July 20, 2007.	
4.22	 	Eleventh Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2016.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on July 20, 2007.	
4.23	 	Twelfth Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2017.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on July 20, 2007.	
4.24	 	Thirteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.250% Senior Notes due 2014.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on September 4, 2007.	
4.25	 	Fourteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2016.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on September 4, 2007.	

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4.26	 	Fifteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2017.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on September 4, 2007.	
4.27	 	Sixteenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.250% Senior Notes due 2014.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 4, 2009.	
4.28	 	Seventeenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2016.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 4, 2009.	
4.29	 	Eighteenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2017.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 4, 2009.	
4.30	 	Nineteenth Supplemental Indenture, dated May 8, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.250% Senior Notes due 2014.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 14, 2009.	
4.31	 	Twentieth Supplemental Indenture, dated May 8, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2016.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 14, 2009.	
4.32	 	Twenty-First Supplemental Indenture, dated May 8, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2017.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 14, 2009.	
4.33	 	Twenty-Second Supplemental Indenture, dated June 5, 2009, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 8.5% Senior Notes due 2019.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on June 5, 2009.	
4.34	 	Twenty-Third Supplemental Indenture, dated July 14, 2009, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 8.5% Senior Notes due 2019.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on July 15, 2009.	
4.35	 	Twenty-Fourth Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.250% Senior Notes due 2014.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on October 6, 2009.	
4.36	 	Twenty-Fifth Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2016.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on October 6, 2009.	
4.37	 	Twenty-Sixth Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2017.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on October 6, 2009.	
4.38	 	Twenty-Seventh Supplemental Indenture, dated October 5, 2009, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 8.5% Senior Notes due 2019.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on October 6, 2009.	
4.39	 	Twenty-Eighth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.250% Senior Notes due 2014.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on April 21, 2010.	
4.40	 	Twenty-Ninth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2016.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on April 21, 2010.	

214

 	
 	 	 	 	 	
4.41	 	Thirtieth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2017.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on April 21, 2010.	
4.42	 	Thirty-First Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 8.50% Senior Notes due 2019.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on April 21, 2010.	
4.43	 	Thirty-Second Supplemental Indenture, dated as of June 23, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.250% Senior Notes due 2014.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on June 29, 2010.	
4.44	 	Thirty-Third Supplemental Indenture, dated as of June 23, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2016.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on June 29, 2010.	
4.45	 	Thirty-Fourth Supplemental Indenture, dated as of June 23, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2017.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on June 29, 2010.	
4.46	 	Thirty-Fifth Supplemental Indenture, dated as of June 23, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 8.50% Senior Notes due 2019.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on June 29, 2010.	
4.47	 	Thirty-Sixth Supplemental Indenture, dated August 20, 2010, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 8.25% Senior Notes due 2020.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on August 20, 2010.	
4.48	 	Form of 8.25% Senior Note due 2020.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on August 20, 2010.	
4.49	 	Registration Rights Agreement, dated August 20, 2010, among NRG Energy, Inc., the guarantors named therein and Citigroup Global Markets Inc., Banc of America Securities LLC and Deutsche Bank Securities Inc., as representatives of the several initial purchasers.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on August 20, 2010.	
4.50	 	Thirty-Seventh Supplemental Indenture, dated as of December 15, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.250% Senior Notes due 2014.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on December 16, 2010.	
4.51	 	Thirty-Eighth Supplemental Indenture, dated as of December 15, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2016.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on December 16, 2010.	
4.52	 	Thirty-Ninth Supplemental Indenture, dated as of December 15, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 7.375% Senior Notes due 2017.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on December 16, 2010.	
4.53	 	Fortieth Supplemental Indenture, dated as of December 15, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 8.50% Senior Notes due 2019.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on December 16, 2010.	
4.54	 	Forty-First Supplemental Indenture, dated as of December 15, 2010, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 8.25% Senior Notes due 2020.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on December 16, 2010.	
4.55	 	Forty-Second Supplemental Indenture, dated January 26, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on January 28, 2011.	

215

 	
 	 	 	 	 	
4.56	 	Form of 7.625% Senior Note due 2018.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on January 28, 2011.	
4.57	 	Registration Rights Agreement, dated January 26, 2011, among NRG Energy, Inc., the guarantors named therein and J.P. Morgan Securities LLC, as initial purchaser.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on January 28, 2011.	
4.58	 	Forty-Third Supplemental Indenture, dated April 22, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's Registration Statement on Form S-4 filed on July 11, 2011.	
4.59	 	Forty-Fourth Supplemental Indenture, dated May 9, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's Registration Statement on Form S-4 filed on July 11, 2011.	
4.60	 	Forty-Fifth Supplemental Indenture, dated May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 25, 2011.	
4.61	 	Forty-Sixth Supplemental Indenture, dated May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 25, 2011.	
4.62	 	Forty-Seventh Supplemental Indenture, dated May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 25, 2011.	
4.63	 	Forty-Eighth Supplemental Indenture, dated May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 25, 2011.	
4.64	 	Forty-Ninth Supplemental Indenture, dated May 20, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 25, 2011.	
4.65	 	Fiftieth Supplemental Indenture, dated May 24, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 25, 2011.	
4.66	 	Form of 7.625% Senior Note due 2019.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 25, 2011.	
4.67	 	Fifty-First Supplemental Indenture, dated May 24, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 25, 2011.	
4.68	 	Form of 7.875% Senior Note due 2021.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 25, 2011.	
4.69	 	Registration Rights Agreement, dated May 24, 2011, among NRG Energy, Inc., the guarantors named therein and Morgan Stanley & Co. Incorporated, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Goldman, Sachs & Co., J.P. Morgan Securities LLC and RBS Securities Inc., as representatives of the initial purchasers.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 25, 2011.	
4.70	 	Fifty-Second Supplemental Indenture, dated November 8, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on November 8, 2011.	
4.71	 	Fifty-Third Supplemental Indenture, dated November 8, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on November 8, 2011.	
4.72	 	Fifty-Fourth Supplemental Indenture, dated November 8, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on November 8, 2011.	
4.73	 	Fifty-Fifth Supplemental Indenture, dated November 8, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on November 8, 2011.	

216

 	
 	 	 	 	 	
4.74	 	Fifty-Sixth Supplemental Indenture, dated November 8, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on November 8, 2011.	
4.75	 	Fifty-Seventh Supplemental Indenture, dated November 8, 2011, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on November 8, 2011.	
4.76	 	Fifty-Eighth Supplemental Indenture, dated April 5, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on April 6, 2012.	
4.77	 	Fifty-Ninth Supplemental Indenture, dated April 5, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on April 6, 2012.	
4.78	 	Sixtieth Supplemental Indenture, dated April 5, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on April 6, 2012.	
4.79	 	Sixty-First Supplemental Indenture, dated April 5, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on April 6, 2012.	
4.80	 	Sixty-Second Supplemental Indenture, dated April 5, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on April 6, 2012.	
4.81	 	Sixty-Third Supplemental Indenture, dated April 5, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on April 6, 2012.	
4.82	 	Sixty-Fourth Supplemental Indenture, dated May 9, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 11, 2012.	
4.83	 	Sixty-Fifth Supplemental Indenture, dated May 9, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 11, 2012.	
4.84	 	Sixty-Sixth Supplemental Indenture, dated May 9, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 11, 2012.	
4.85	 	Sixty-Seventh Supplemental Indenture, dated May 9, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 11, 2012.	
4.86	 	Sixty-Eighth Supplemental Indenture, dated May 9, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 11, 2012.	
4.87	 	Sixty-Ninth Supplemental Indenture, dated May 9, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on May 11, 2012.	
4.88	 	Seventieth Supplemental Indenture, dated September 24, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on September 24, 2012.	
4.89	 	Form of 6.625% Senior Note due 2023.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on September 24, 2012.	
4.90	 	Seventy-First Supplemental Indenture, dated October 9, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on October 12, 2012.	

217

 	
 	 	 	 	 	
4.91	 	Seventy-Second Supplemental Indenture, dated October 9, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on October 12, 2012.	
4.92	 	Seventy-Third Supplemental Indenture, dated October 9, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on October 12, 2012.	
4.93	 	Seventy-Fourth Supplemental Indenture, dated October 9, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on October 12, 2012.	
4.94	 	Seventy-Fifth Supplemental Indenture, dated October 9, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on October 12, 2012.	
4.95	 	Seventy-Sixth Supplemental Indenture, dated October 9, 2012, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on October 12, 2012.	
4.96	 	Fourth Supplemental Indenture relating to the 7.625% Senior notes due 2014, among Reliant Energy, Inc., the Guarantors listed therein and Wilmington Trust Company, dated at June 13, 2007.	 	Incorporated herein by reference to GenOn Energy Inc.'s current report on Form 8-K filed on June 15, 2007.
	
4.97	 	Fifth Supplemental Indenture relating to the 7.875% Senior notes due 2017, among Reliant Energy, Inc., the Guarantors listed therein and Wilmington Trust Company, dated at June 13, 2007.
	 	Incorporated herein by reference to Exhibit 4.2 to GenOn Energy Inc.'s current report on Form 8-K filed June 15, 2007.	
4.98	 	Indenture between Mirant Americas Generation, Inc. and Bankers Trust Company, as trustee, relating to Senior Notes, dated at May 1, 2001.	 	Incorporated herein by reference to Exhibit 4.1 to Mirant Americas Generation, Inc.'s Registration Statement on Form S-4 filed on June 18, 2001.
	
4.99	 	Third Supplemental Indenture from Mirant Americas Generation, Inc. to Bankers Trust Company, relating to 9.125 % Senior Notes due 2031, dated at May 1, 2001.
	 	Incorporated herein by reference to Exhibit 4.4 to Mirant Americas Generation, Inc.'s Registration Statement on Form S-4 filed on June 18, 2001.
	
4.100	 	Fifth Supplemental Indenture from Mirant Americas Generation, Inc. to Bankers Trust Company, dated at October 9, 2001.
	 	Incorporated herein by reference to Exhibit 4.6 to Mirant Americas Generation, Inc.'s Registration Statement on Form S-4/A filed on May 7, 2002.
	
4.101	 	Form of Sixth Supplemental Indenture from Mirant Americas Generation LLC to Bankers Trust Company, dated at November 1, 2001.
	 	Incorporated herein by reference to Exhibit 4.6 to Mirant Corporation's annual report on Form 10-K filed on February 27, 2009.
	
4.102	 	Senior Notes Indenture, relating to the 9.5% Senior Notes Due 2018 and the 9.875% Senior Notes Due 2020, by GenOn Escrow Corp. and Wilmington Trust Company as trustee, dated at October 4, 2010.
	 	Incorporated by reference to Exhibit 4.4 to Mirant Corporation's quarterly report on Form 10-Q filed on November 5, 2010.
	
4.103	 	Supplemental Indenture, relating to the 9.5% Senior Notes due 2018 and the 9.875% Senior Notes Due 2020, by GenOn Energy, Inc. and Wilmington Trust Company as trustee, dated at December 3, 2010.
	 	Incorporated by reference to Exhibit 4.2 to GenOn Energy Inc.'s current report on Form 8-K filed on December 7, 2010.
	
4.104	 	Form of Seventh Supplemental Indenture from Mirant Americas Generation LLC to Wells Fargo Bank National Association, dated at January 3, 2006.
	 	Incorporated herein by reference to Exhibit 4.1 to Mirant Americas Generation, LLC's quarterly report on Form 10-Q filed on May 14, 2007.	
10.1	 	Note Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc. and each of the purchasers named therein.	 	Incorporated herein by reference to the Registrant's Registration Statement on Form S-1, as amended, Registration No. 333-33397.	
10.2	 	Master Shelf and Revolving Credit Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc., The Prudential Insurance Registrants of America and each Prudential Affiliate, which becomes party thereto.	 	Incorporated herein by reference to the Registrant's Registration Statement on Form S-1, as amended, Registration No. 333-33397.	
10.3*	 	Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Officers and Key Management.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on March 30, 2005.	
10.4*	 	Form of NRG Energy, Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Directors.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on March 30, 2005.	
10.5*	 	Form of NRG Energy, Inc. Long-Term Incentive Plan Non-Qualified Stock Option Agreement.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on November 9, 2004.	
10.6*	 	Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted Stock Unit Agreement.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on November 9, 2004.	
10.7*	 	Form of NRG Energy, Inc. Long Term Incentive Plan Performance Unit Agreement.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on February 23, 2010.	

218

 	
 	 	 	 	 	
10.8*	 	Amended and Restated Annual Incentive Plan for Designated Corporate Officers.	 	Incorporated herein by reference to the Registrant's 2009 proxy statement on Schedule 14A filed on June 16, 2009.	
10.9	 	Railroad Car Full Service Master Leasing Agreement, dated as of February 18, 2005, between General Electric Railcar Services Corporation and NRG Power Marketing Inc.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K for the quarter ended March 30, 2005.	
10.10	 	Purchase Agreement (West Coast Power) dated as of December 27, 2005, by and among NRG Energy, Inc., NRG West Coast LLC (Buyer), DPC II Inc. (Seller) and Dynegy, Inc.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on December 28, 2005.	
10.11	 	Purchase Agreement (Rocky Road Power), dated as of December 27, 2005, by and among Termo Santander Holding, L.L.C.(Buyer), Dynegy, Inc., NRG Rocky Road LLC (Seller) and NRG Energy, Inc.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on December 28, 2005.	
10.12	 	Stock Purchase Agreement, dated as of August 10, 2005, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on August 11, 2005.	
10.13	 	Agreement with respect to the Stock Purchase Agreement, dated December 19, 2008, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on February 12, 2009.	
10.14	 	Investor Rights Agreement, dated as of February 2, 2006, by and among NRG Energy, Inc. and Certain Stockholders of NRG Energy, Inc. set forth therein.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on February 8, 2006.	
10.15†	 	Terms and Conditions of Sale, dated as of October 5, 2005, between Texas Genco II LP and Freight Car America, Inc., (including the Proposal Letter and Amendment thereto).	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on March 7, 2006.	
10.16*	 	Amended and Restated Employment Agreement, dated December 4, 2008, between NRG Energy, Inc. and David Crane.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on February 12, 2009.	
10.17*	 	CEO Compensation Table.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on December 9, 2009.	
10.18	 	Limited Liability Company Agreement of NRG Common Stock Finance I LLC.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on August 10, 2006.	
10.19	 	Note Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse International and Credit Suisse Securities (USA) LLC.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on August 10, 2006.	
10.20	 	Amendment Agreement, dated February 27, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008.	
10.21	 	Amendment Agreement, dated December 19, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on February 12, 2009.	
10.22	 	Amendment Agreement, dated December 19, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on February 12, 2009.	
10.23	 	Agreement with respect to Note Purchase Agreement, dated December 19, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on February 12, 2009.	
10.24	 	Preferred Interest Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse Capital LLC and Credit Suisse Securities (USA) LLC, as agent.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on August 10, 2006.	
10.25	 	Preferred Interest Amendment Agreement, dated February 27, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008.	
10.26	 	Preferred Interest Amendment Agreement, dated December 19, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on February 12, 2009.	
10.27	 	Preferred Interest Amendment Agreement, dated December 19, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on February 12, 2009.	
10.28	 	Agreement with respect to Preferred Interest Purchase Agreement, dated December 19, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on February 12, 2009.	

219

 	
 	 	 	 	 	
10.29	 	Second Amended and Restated Credit Agreement, dated June 8, 2007, by and among NRG Energy, Inc., the lenders party thereto, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Citicorp North America Inc. and Credit Suisse.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on June 13, 2007.	
10.30*	 	Amended and Restated Long-Term Incentive Plan.	 	Incorporated herein by reference to the Registrant's 2009 proxy statement on Schedule 14A filed on June 16, 2009.	
10.31*	 	NRG Energy, Inc. Executive Change-in-Control and General Severance Agreement, dated December 9, 2008.	 	Incorporated herein by reference to the Registrant's annual report on Form 10-K filed on February 12, 2009.	
10.32†	 	Amended and Restated Contribution Agreement (NRG), dated March 25, 2008, by and among Texas Genco Holdings, Inc., NRG South Texas LP and NRG Nuclear Development Company LLC and Certain Subsidiaries Thereof.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008.	
10.33†	 	Contribution Agreement (Toshiba), dated February 29, 2008, by and between Toshiba Corporation and NRG Nuclear Development Company LLC.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008.	
10.34†	 	Multi-Unit Agreement, dated February 29, 2008, by and among Toshiba Corporation, NRG Nuclear Development Company LLC and NRG Energy, Inc.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008.	
10.35†	 	Amended and Restated Operating Agreement of Nuclear Innovation North America LLC, dated May 1, 2008.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on May 1, 2008.	
10.36	 	Credit Agreement by and among Nuclear Innovation North America LLC, Nuclear Innovation North America Investments LLC, NINA Texas 3 LLC and NINA Texas 4 LLC, as Borrowers and Toshiba America Nuclear Energy Corporation, as Administrative Agent and as Collateral Agent.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on February 27, 2009.	
10.37†	 	LLC Membership Purchase Agreement between Reliant Energy, Inc. and NRG Retail LLC, dated as of February 28, 2009.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on April 30, 2009.	
10.38	 	Project Agreement, Settlement Agreement and Mutual Release, dated March 1, 2010, by and among by and among Nuclear Innovation North America LLC, the City of San Antonio acting by and through the City Public Service Board of San Antonio, a Texas municipal utility, NINA Texas 3 LLC and NINA Texas 4 LLC, and solely for purposes of certain sections of the Settlement Agreement, by NRG Energy, Inc and NRG South Texas LP.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on March 2, 2010.	
10.39†	 	STP 3 & 4 Owners Agreement, dated March 1, 2010, by and among Nuclear Innovation North America LLC, the City of San Antonio, NINA Texas 3 LLC and NINA Texas 4 LLC.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on March 2, 2010.	
10.40*	 	2009 Executive Change-in-Control and General Severance Plan.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on April 1, 2010.	
10.41†	 	Investment and Option Agreement by and among Nuclear Innovation North America LLC, Nuclear Innovation North America Investments Holdings LLC and TEPCO Nuclear Energy America LLC, dated as of May 10, 2010.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on August 2, 2010.	
10.42†	 	Parent Company Agreement by and among NRG Energy, Inc., Nuclear Innovation North America LLC, TEPCO and TEPCO Nuclear Energy America LLC, dated as of May 10, 2010.	 	Incorporated herein by reference to the Registrant's quarterly report on Form 10-Q filed on August 2, 2010.	
10.43	 	Third Amended and Restated Credit Agreement, dated as of June 30, 2010.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on July 1, 2010.	
10.44(a)	 	Letter of Credit and Reimbursement Agreement, dated as of June 30, 2010.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on July 1, 2010.	
10.44(b)	 	Letter of Credit and Reimbursement Agreement, dated as of June 30, 2010.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on July 1, 2010.	
10.45*	 	The NRG Energy, Inc. Amended and Restated Long Term Incentive Plan.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on August 3, 2010.	
10.46	 	Amended and Restated Credit Agreement, dated July 1, 2011, by and among NRG Energy, Inc., the lenders party thereto, and the joint lead bookrunners and joint lead arrangers party thereto.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on July 5, 2011.	
10.47*	 	Form of Market Stock Unit Grant Agreement.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K/A filed on September 12, 2011.	

220

 	
 	 	 	 	 	
10.48	 	Registration Rights Agreement, dated September 24, 2012, among NRG Energy, Inc., the guarantors named therein and Deutsche Bank Securities Inc., Merrill, Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Goldman, Sachs & Co., J.P. Morgan Securities LLC, Morgan Stanley & Co. Incorporated and RBS Securities Inc., as initial purchasers.	 	Incorporated herein by reference to the Registrant's current report on Form 8-K filed on September 24, 2012.	
10.49*	 	NRG 2010 Stock Plan for GenOn Employees	 	Filed herewith.	
10.50	 	Revolving Credit Agreement among GenOn Energy, Inc., as Borrower, GenOn Americas, Inc., as Borrower, the several lenders from time to time parties hereto, and NRG Energy, Inc., as Administrative Agent, dated as of December 14, 2012.	 	Filed herewith.	
12.1	 	NRG Energy, Inc. Computation of Ratio of Earnings to Fixed Charges.	 	Filed herewith.	
12.2	 	NRG Energy, Inc. Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements.	 	Filed herewith.	
21.1	 	Subsidiaries of NRG Energy. Inc.	 	Filed herewith.	
23.1	 	Consent of KPMG LLP.	 	Filed herewith.	
31.1	 	Rule 13a-14(a)/15d-14(a) certification of David W. 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.	

 	 	 	
*	 	Exhibit relates to compensation arrangements.	
†
	 	Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Secretary of the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.	

221

EXHIBIT 10.49

NRG 2010 STOCK PLAN
FOR GENON EMPLOYEES

NRG 2010 STOCK PLAN
FOR GENON EMPLOYEES

Table of Contents

 	Page	
 	
1. Plan	3	
 	
2. Objectives	3	
 	
3. Definitions	3	
 	
4. Eligibility	6	
 	
5. Common Stock Available for Awards	6	
 	
6. Administration	7	
 	
7. Delegation of Authority	8	
 	
8. Employee Awards	8	
 	
9. Consultant and Director Awards	12	
 	
10. Award Payment; Dividends and Dividend Equivalents	12	
 	
11. Option Exercise	13	
 	
12. Taxes	13	
 	
13. Amendment, Modification, Suspension or Termination	13	
 	
14. Assignability	14	
 	
15. Adjustments	14	
 	
16. Restrictions	15	
 	
17. Unfunded Plan	15	
 	
18. Code Section 409A	16	
 	
19. Awards to Foreign Nationals and Employees Outside the United States	16	
 	
20. Governing Law	16	
 	
21. Right to Continued Service or Employment	16	
 	
22. Usage	16	
 	
23. Headings	16	

NRG 2010 STOCK PLAN
FOR GENON EMPLOYEES

1.Plan. GenOn Energy, Inc., a Delaware corporation (“GenOn”), established the GenOn Energy, Inc. 2010 Omnibus Incentive Plan (this “ Plan ”), effective as of December 3, 2010 (the “ Effective Date ”) in connection with the consummation of the transactions contemplated by the Agreement and Plan of Merger by and among RRI Energy, Inc., RRI Energy Holdings, Inc. and Mirant Corporation, dated as of April 11, 2010, as amended. This Plan was approved by stockholders of RRI Energy, Inc. on October 25, 2010.
On December 14, 2012 the consummation of the transactions contemplated by the Agreement and Plan of Merger dated as of July 20, 2012 by and among NRG Energy, Inc., a Delaware corporation (the “ Company ”), GenOn and Plus Merger Corporation was completed (the “ Closing ”). In connection with the Closing, the Company assumed this Plan and changed its name to the “NRG 2010 Stock Plan for GenOn Employees.”
This Plan shall continue in effect until December 2, 2020 unless sooner terminated by action of the Board of Directors of the Company.
2.Objectives. This Plan is designed to attract and retain eligible employees and consultants of the Company and its Subsidiaries (as defined herein), to attract and retain eligible non-employee directors of the Company, to encourage the sense of proprietorship of such employees, consultants and directors and to stimulate the active interest of such persons in the development and financial success of the Company and its Subsidiaries. These objectives are to be accomplished by making Awards under this Plan and thereby providing Participants (as defined herein) with a proprietary interest in the growth and performance of the Company and its Subsidiaries.
3.Definitions. As used herein, the terms set forth below shall have the following respective meanings:
“Authorized Officer” means the Chairman of the Board, the Chief Executive Officer of the Company or the senior human resources officer of the Company (or any other senior officer of the Company to whom any of such individuals shall delegate the authority to execute any Award Agreement).
“Award” means the grant of any Option, Stock Appreciation Right, Stock Award, or Cash Award, any of which may be structured as a Performance Award, whether granted singly, in combination or in tandem, to a Participant pursuant to such applicable terms, conditions, and limitations as the Committee may establish in accordance with the objectives of this Plan.
“Award Agreement” means the document (in written or electronic form) communicating the terms, conditions and limitations applicable to an Award. The Committee may, in its discretion, require that the Participant execute such Award Agreement, or may provide for procedures through which Award Agreements are made available but not executed. Any Participant who is granted an Award and who does not affirmatively reject the applicable Award Agreement shall be deemed to have accepted the terms of Award as embodied in the Award Agreement.
“Board” means the Board of Directors of the Company.
“Cash Award” means an Award denominated in cash.
“Change in Control” means a Change in Control as defined in Attachment A to this Plan.
“Code” means the Internal Revenue Code of 1986, as amended from time to time.

3

“Committee” means the Compensation Committee of the Board, and any successor committee thereto or such other committee of the Board as may be designated by the Board to administer this Plan in whole or in part including any subcommittee of the Board as designated by the Board.
“Common Stock” means the Common Stock, par value $0.01 per share, of the Company.
“Company” means NRG Energy, Inc., a Delaware corporation, or any successor thereto.
“Consultant” means an individual providing services to the Company or any of its Subsidiaries, other than an Employee or a Director.
“Consultant Award” means the grant of any Award (other than an Incentive Stock Option), whether granted singly, in combination, or in tandem, to a Participant who is a Consultant pursuant to such applicable terms, conditions, and limitations established by the Committee.
“Covered Employee” means any Employee who is or may be a “covered employee,” as defined in Code Section 162(m).
“Director” means an individual serving as a member of the Board who is not an Employee or a Consultant.
“Director Award” means the grant of any Award (other than an Incentive Stock Option), whether granted singly, in combination, or in tandem, to a Participant who is a Director pursuant to such applicable terms, conditions, and limitations established by the Board.
“Disability” means (1) if the Participant is an Employee, a disability that entitles the Employee to benefits under the Company's long-term disability plan, as may be in effect from time to time, as determined by the plan administrator of the long-term disability plan or (2) if the Participant is a Director or a Consultant, a disability whereby the Director or Consultant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months. Notwithstanding the foregoing, if an Award is subject to Code Section 409A, the definition of Disability shall conform to the requirements of Treasury Regulation § 1.409A-3(i)(4)(i).
“Dividend Equivalents” means, in the case of Restricted Stock Units or Performance Units, an amount equal to all dividends and other distributions (or the economic equivalent thereof) that are payable to shareholders of record during the Restriction Period or performance period, as applicable, on a like number of shares of Common Stock that are subject to the Award.
“Employee” means an employee of the Company or any of its Subsidiaries.
“Employee Award” means the grant of any Award, whether granted singly, in combination, or in tandem, to an Employee pursuant to such applicable terms, conditions, and limitations established by the Committee.
“Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time.
“Exercise Price” means the price at which a Participant may exercise his right to receive cash or Common Stock, as applicable, under the terms of an Award.

4

“Fair Market Value” of a share of Common Stock means, as of a particular date, (1) if shares of Common Stock are listed on a national securities exchange, the closing sales price per share of Common Stock on the consolidated transaction reporting system for the principal national securities exchange on which shares of Common Stock are listed on that date, or, if there shall have been no such sale so reported on that date, on the last preceding date on which such a sale was so reported, (2) if the Common Stock is not so listed, the average of the closing bid and asked price on that date, or, if there are no quotations available for such date, on the last preceding date on which such quotations shall be available, as reported by an inter-dealer quotation system, (3) if shares of Common Stock are not publicly traded, the most recent value determined by an independent appraiser appointed by the Committee for such purpose, or (4) if none of the above are applicable, the fair market value of a share of Common Stock as determined in good faith by the Committee.
“Grant Date” means the date an Award is granted to a Participant pursuant to this Plan.
“IncentiveStockOption” means an Option that is intended to comply with the requirements set forth in Code Section 422.
“Nonqualified Stock Option” means an Option that is not intended to comply with the requirements set forth in Code Section 422.
“Option” means a right to purchase a specified number of shares of Common Stock at a specified Exercise Price, which is either an Incentive Stock Option or a Nonqualified Stock Option.
“Participant” means an Employee, Consultant or Director to whom an Award has been made under this Plan.
“Performance Award” means an Award made pursuant to this Plan to a Participant which is subject to the attainment of one or more Performance Goals.
“Performance Goal” means one or more standards established by the Committee to determine in whole or in part whether a Performance Award shall be earned.
“Performance Unit” means a unit evidencing the right to receive in specified circumstances one share of Common Stock or equivalent value in cash, the value of which at the time it is settled is determined as a function of the extent to which established performance criteria have been satisfied.
“Performance Unit Award” means an Award in the form of Performance Units.
“Qualified Performance Awards” has the meaning set forth in Paragraph 8(a)(vii)(B).
“Restricted Stock” means a share of Common Stock that is restricted or subject to forfeiture provisions.
“Restricted Stock Award” means an Award in the form of Restricted Stock.
“Restricted Stock Unit” means a unit evidencing the right to receive in specified circumstances one share of Common Stock or equivalent value in cash that is restricted or subject to forfeiture provisions.
“Restricted Stock Unit Award” means an Award in the form of Restricted Stock Units.
“Restriction Period” means a period of time beginning as of the date upon which a Restricted Stock Award or Restricted Stock Unit Award is made pursuant to this Plan and ending as of the date upon which such Award is no longer restricted or subject to forfeiture provisions.

5

“Stock Appreciation Right” or “SAR” means a right to receive a payment, in cash or Common Stock, equal to the excess of the Fair Market Value of a specified number of shares of Common Stock on the date the right is exercised over a specified Exercise Price.
“Stock Award” means an Award in the form of shares of Common Stock, including a Restricted Stock Award, and a Restricted Stock Unit Award or Performance Unit Award that may be settled in shares of Common Stock, and excluding Options and SARs.
“Stock-Based Award Limitations” has the meaning set forth in Paragraph 5.
“Subsidiary” means (1) in the case of a corporation, any corporation of which the Company directly or indirectly owns shares representing 50% or more of the combined voting power of the shares of all classes or series of capital stock of such corporation which have the right to vote generally on matters submitted to a vote of the stockholders of such corporation, and (2) in the case of a partnership or other business entity not organized as a corporation, any such business entity of which the Company directly or indirectly owns 50% or more of the voting, capital or profits interests (whether in the form of partnership interests, membership interests or otherwise).
4.Eligibility.
(a)Employees. The only Employees eligible for Employee Awards under this Plan are Employees who were not employed by the Company or its Subsidiaries immediately prior to the Closing.
(b)Consultants. The only Consultants eligible for Consultant Awards under this Plan are Consultants who were not consultants of the Company or its Subsidiaries immediately prior to the Closing.
(c)Directors. The only Directors eligible for Director Awards under this Plan are Directors who were not directors of the Company or its Subsidiaries immediately prior to the Closing.
The Committee (or the Board, in the case of Director Awards) shall determine the type or types of Awards to be made under this Plan and shall designate from time to time the Employees, Consultants or Directors who are to be granted Awards under this Plan.
5.Common Stock Available for Awards. Subject to the provisions of Paragraph 15 hereof, there shall be available for Awards under this Plan granted wholly or partly in Common Stock (including rights or Options that may be exercised for or settled in Common Stock) an aggregate of 4,504,633 shares of Common Stock (the “Maximum Share Limit”), all of which shall be available for Incentive Stock Options. Each Stock Award granted under this Plan shall be counted against the Maximum Share Limit as 1.50 shares of Common Stock; each Option and SAR shall be counted against the Maximum Share Limit as 1 share of Common Stock.
Awards settled in cash shall not reduce the Maximum Share Limit under the Plan. If an Award expires or is terminated, cancelled or forfeited, the shares of Common Stock associated with the expired, terminated, cancelled or forfeited Awards shall again be available for Awards under the Plan, and the Maximum Share Limit shall be increased by the same amount as such shares were counted against the Maximum Share Limit ( i.e ., increased by 1.50 shares of Common Stock, if a Stock Award, and 1 share of Common Stock, if an Option or SAR). The following shares of Common Stock shall not become available again for issuance under the Plan:

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(i)    Shares of Common Stock that are tendered by a Participant or withheld as full or partial payment of minimum withholding taxes or as payment for the Exercise Price of an Award; and
(ii)    Shares of Common Stock reserved for issuance upon grant of an SAR, to the extent the number of reserved shares of Common Stock exceeds the number of shares of Common Stock actually issued upon exercise or settlement of such SAR.
The Board and the appropriate officers of the Company shall from time to time take whatever actions are necessary to file any required documents with governmental authorities, stock exchanges and transaction reporting systems to ensure that shares of Common Stock are available for issuance pursuant to Awards.
Notwithstanding anything to the contrary contained in this Plan, the following limitations shall apply to any Awards made hereunder:
(a)No Employee may be granted during any calendar year Awards consisting of Options or SARs that are exercisable for more than 912,000 shares of Common Stock;
(b)No Employee may be granted during any calendar year Stock Awards covering or relating to more than 912,000 shares of Common Stock (the limitation set forth in this clause (b), together with the limitation set forth in clause (a) above, being hereinafter collectively referred to as the “Stock-Based Award Limitations”); and
(c)No Employee may be granted during any calendar year (1) Cash Awards or (2) Restricted Stock Unit Awards or Performance Unit Awards that may be settled solely in cash having a value determined on the Grant Date in excess of $30,000,000.
6.Administration.
(a)Authority of the Committee. Except as otherwise provided in this Plan with respect to actions or determinations by the Board, this Plan shall be administered by the Committee;  provided, however , that (i) any and all members of the Committee shall satisfy any independence requirements prescribed by any stock exchange on which the Company lists its Common Stock; (ii) Awards may be granted to individuals who are subject to Section 16(b) of the Exchange Act only if the Committee is comprised solely of two or more “Non-Employee Directors” as defined in Securities and Exchange Commission Rule 16b-3 (as amended from time to time, and any successor rule, regulation or statute fulfilling the same or similar function); and (iii) any Award intended to qualify for the “performance-based compensation” exception under Code Section 162(m) shall be granted only if the Committee is comprised solely of two or more “outside directors” within the meaning of Code Section l62(m) and regulations pursuant thereto. Subject to the provisions hereof, the Committee shall have full and exclusive power and authority to administer this Plan and to take all actions that are specifically contemplated hereby or are necessary or appropriate in connection with the administration hereof. The Committee shall also have full and exclusive power to interpret this Plan and to adopt such rules, regulations and guidelines for carrying out this Plan as it may deem necessary or proper, all of which powers shall be exercised in the best interests of the Company and in keeping with the objectives of this Plan. Subject to Paragraph 6(c) hereof, the Committee may, in its discretion, (x) provide for the extension of the exercisability of an Award, or (y) in the event of death, Disability, retirement or Change in Control, accelerate the vesting or exercisability of an Award, eliminate or make less restrictive any restrictions contained in an Award, waive any restriction or other provision of this Plan or an Award or otherwise amend or modify an Award in any manner that is, in either case, (1) not adverse to the Participant to whom such Award was granted, (2) consented to by such Participant or (3) authorized by Paragraph 15(c) hereof;  provided, however , that no such action shall permit the

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term of any Option to be greater than 10 years from its Grant Date. The Committee may correct any defect or supply any omission or reconcile any inconsistency in this Plan or in any Award Agreement in the manner and to the extent the Committee deems necessary or desirable to further this Plan's purposes. Any decision of the Committee in the interpretation and administration of this Plan shall lie within its sole and absolute discretion and shall be final, conclusive and binding on all parties concerned. The Board shall have the same powers as the Committee with respect to Director Awards.
(b)Indemnity. No member of the Board or the Committee or officer of the Company to whom the Committee has delegated authority in accordance with the provisions of Paragraph 7 of this Plan shall be liable for anything done or omitted to be done by him, by any member of the Board or the Committee or by any officer of the Company in connection with the performance of any duties under this Plan, except for his own willful misconduct or as expressly provided by statute.
(c)Prohibition on Repricing of Awards. Subject to the provisions of Paragraph 15 hereof, the terms of outstanding Award Agreements may not be amended without the approval of the Company's stockholders so as to (i) reduce the Exercise Price of any outstanding Options or SARs or (ii) cancel any outstanding Options or SARs in exchange for cash or other Awards, or Options or SARs with an Exercise Price that is less than the Exercise Price of the original Options or SARs.
7.Delegation of Authority. The Committee may delegate any of its authority to grant Awards to Employees who are not subject to Section 16(b) of the Exchange Act and Consultants, subject to Paragraph 6(a) above, to the Board or to any other committee of the Board, provided such delegation is made in writing and specifically sets forth such delegated authority. The Committee may also delegate to an Authorized Officer authority to execute on behalf of the Company any Award Agreement. The Committee and the Board, as applicable, may engage or authorize the engagement of a third party administrator to carry out administrative functions under this Plan. Any such delegation hereunder shall only be made to the extent permitted by applicable law.
8.Employee Awards.
(a)The Committee shall determine the type or types of Employee Awards to be made under this Plan and shall designate from time to time the Employees who are to be the recipients of such Awards. Each Award shall be embodied in an Award Agreement, which shall contain such terms, conditions and limitations as shall be determined by the Committee, in its sole discretion, and, if required by the Committee, shall be signed by the Participant to whom the Award is granted and by an Authorized Officer for and on behalf of the Company. Awards may consist of those listed in this Paragraph 8(a) hereof and may be granted singly, in combination or in tandem. Awards may also be made in combination or in tandem with, in replacement of, or as alternatives to, grants or rights under this Plan or any other plan of the Company or any of its Subsidiaries, including the plan of any acquired entity;  provided, however , that, except as contemplated in Paragraph 15 hereof, no Option or SAR may be issued in exchange for the cancellation of an Option or SAR with a higher Exercise Price nor may the Exercise Price of any Option or SAR be reduced. All or part of an Award may be subject to conditions established by the Committee. Upon the termination of employment by a Participant who is an Employee, any unexercised, unvested or unpaid Awards shall be treated as set forth in the applicable Award Agreement or in any other written agreement the Company has entered into with the Participant.

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Except as otherwise provided in this Paragraph 8(a), any Stock Award that (a) is not a Performance Award shall have a minimum Restriction Period of three years from the date of grant or (b) is a Performance Award shall have a minimum performance period of one year from the date of grant;  provided, however , that (1) the Committee may provide for earlier vesting upon an Employee's termination of employment by reason of death, Disability or Change in Control and (2) vesting of a Stock Award may occur incrementally over the three-year Restriction Period or one-year minimum performance period, as applicable. The foregoing notwithstanding, 5% of the total number of shares of Common Stock available for issuance under this Plan shall not be subject to the minimum Restriction Period or performance period, as applicable, described in the preceding sentence.
(i)Options. An Employee Award may be in the form of an Option. An Option awarded pursuant to this Plan may consist of either an Incentive Stock Option or a Nonqualified Stock Option. The price at which shares of Common Stock may be purchased upon the exercise of an Option shall be not less than the Fair Market Value of the Common Stock on the Grant Date. The term of an Option shall not exceed 10 years from the Grant Date. Options may not include provisions that “reload” the Option upon exercise. Subject to the foregoing provisions, the terms, conditions and limitations applicable to any Option, including, but not limited to, the term of any Option and the date or dates upon which the Option becomes vested and exercisable, shall be determined by the Committee.
(ii)Stock Appreciation Rights. An Employee Award may be in the form of an SAR. The Exercise Price for an SAR shall not be less than the Fair Market Value of the Common Stock on the Grant Date. The holder of a tandem SAR may elect to exercise either the Option or the SAR, but not both. The exercise period for an SAR shall extend no more than 10 years after the Grant Date. SARs may not include provisions that “reload” the SAR upon exercise.  Subject to the foregoing provisions, the terms, conditions, and limitations applicable to any SAR, including, but not limited to, the term of any SAR and the date or dates upon which the SAR becomes vested and exercisable, shall be determined by the Committee.
(iii)Stock Awards. An Employee Award may be in the form of a Stock Award. The terms, conditions and limitations applicable to any Stock Award, including, but not limited to, vesting or other restrictions, shall be determined by the Committee, and subject to the minimum Restriction Period and performance period requirements and any other applicable requirements described in this Paragraph 8(a) hereof.
(iv)Restricted Stock Unit Awards. An Employee Award may be in the form of a Restricted Stock Unit Award. The terms, conditions and limitations applicable to a Restricted Stock Unit Award, including, but not limited to, the Restriction Period and the right to Dividend Equivalents, if any, shall be determined by the Committee. Subject to the terms of this Plan, the Committee, in its sole discretion, may settle Restricted Stock Units in the form of cash or in shares of Common Stock (or in a combination thereof) equal to the value of the vested Restricted Stock Units;  provided, however , that a Restricted Stock Unit Award that may be settled all or in part in shares of Common Stock shall be subject to the minimum Restriction Period and performance period requirements and any other applicable requirements described in this Paragraph 8(a) hereof.

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(v)Performance Unit Awards. An Employee Award may be in the form of a Performance Unit Award. Each Performance Unit shall have an initial value that is established by the Committee on the Grant Date. Subject to the terms of this Plan, after the applicable performance period has ended, the Participant shall be entitled to receive settlement of the value and number of Performance Units earned by the Participant over the performance period, to be determined as a function of the extent to which the corresponding performance goals have been achieved. Settlement of earned Performance Units shall be as determined by the Committee and as evidenced in an Award Agreement. Subject to the terms of this Plan, the Committee, in its sole discretion, may settle earned Performance Units in the form of cash or in shares of Common Stock (or in a combination thereof) equal to the value of the earned Performance Units as soon as practicable after the end of the performance period and following the Committee's determination of actual performance against the performance measures and related goals established by the Committee;  provided, however , that a Performance Unit Award that may be settled all or in part in shares of Common Stock shall be subject to the minimum Restriction Period and performance period requirements and any other applicable requirements described in this Paragraph 8(a) hereof.
(vi)Cash Awards. An Employee Award may be in the form of a Cash Award. The terms, conditions and limitations applicable to a Cash Award, including, but not limited to, vesting or other restrictions, shall be determined by the Committee.
(vii)Performance Awards. Without limiting the type or number of Awards that may be made under the other provisions of this Plan, an Employee Award may be in the form of a Performance Award. The terms, conditions and limitations applicable to an Award that is a Performance Award shall be determined by the Committee. The Committee shall set Performance Goals in its discretion which, depending on the extent to which they are met, will determine the value and/or amount of Performance Awards that will be paid out to the Participant and/or the portion of an Award that may be exercised.
(A)    Nonqualified Performance Awards. Performance Awards granted to Employees that are not intended to qualify as qualified performance-based compensation under Code Section 162(m) shall be based on achievement of such Performance Goals and be subject to such terms, conditions and restrictions as the Committee or its delegate shall determine.
(B)    Qualified Performance Awards. Performance Awards granted to Employees under this Plan that are intended to qualify as qualified performance-based compensation under Code Section 162(m) shall be paid, vested or otherwise deliverable solely on account of the attainment of one or more pre-established, objective Performance Goals established by the Committee prior to the earlier to occur of (1) 90 days after the commencement of the period of service to which the Performance Goal relates and (2) the lapse of 25% of the period of service (as scheduled in good faith at the time the goal is established), and in any event while the outcome is substantially uncertain. A Performance Goal is objective if a third party having knowledge of the relevant facts could determine whether the goal is met. One or more of such goals may apply to the Employee, one or more business units, divisions or sectors of the Company, or the Company as a whole, and if so desired by the Committee, by comparison with a peer group of companies. A Performance Goal shall include one or more of the following:

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•revenue and income measures (which include various revenue, gross margin, income from operations, net income, net sales, earnings per share, earnings before interest, taxes, depreciation and amortization (“EBITDA”), earnings before interest and taxes (“EBIT”) and economic value added (“EVA”) measures;
•expense measures (which include various costs of goods sold, selling, finding and development costs, operating and maintenance expenses, general and administrative expenses and overhead costs measures);
•operating measures (which include various productivity, total costs, operating income, funds from operations, cash from operations, after-tax operating income, market share, margin, sales volumes, availability, commercial capacity factor and total margin capture factor measures);
•cash flow measures (which include various net cash flow from operating activities and working capital, adjusted cash flow and free cash flow measures);
•liquidity measures (which include various earnings before or after the effect of certain items such as interest, taxes, depreciation and amortization measures);
•leverage measures (which include various debt-to-equity ratio, gross debt and net debt measures);
•market measures (which include various market share, stock price, growth measure, total shareholder return and market capitalization measures);
•return measures (which include various return on equity, return on assets and return on invested capital measures);
•corporate value measures (which include various compliance, safety, environmental and personnel measures); and
•other measures such as those relating to acquisitions, dispositions or customer satisfaction.
Unless otherwise stated, such a Performance Goal need not be based upon an increase or positive result under a particular business criterion and could include, for example, maintaining the status quo or limiting economic losses (measured, in each case, by reference to specific business criteria). In interpreting Plan provisions applicable to Qualified Performance Awards, it is the intent of this Plan to conform with the standards of Code Section 162(m) and Treasury Regulation § 1.162-27(e)(2)(i), as to grants to Covered Employees and the Committee in establishing such goals and interpreting this Plan shall be guided by such provisions. Prior to the payment of any compensation based on the achievement of Performance Goals applicable to Qualified Performance Awards, the Committee must certify in writing that applicable Performance Goals and any of the material terms thereof were, in fact, satisfied. For this purpose, approved minutes of the Committee meeting in which the certification is made shall be treated as such written certification. Subject to the foregoing provisions, the terms, conditions and limitations applicable to any Qualified Performance Awards made pursuant to this Plan shall be determined by the Committee. The Committee may provide in any such Performance Award that any evaluation of performance may include or exclude any of the following

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events that occurs during a Performance Period: (a) asset write-downs, (b) litigation or claim judgments or settlements, (c) the effect of changes in tax laws, accounting principles, or other laws or provisions affecting reported results, (d) any reorganization and restructuring programs, (e) extraordinary nonrecurring items as described in Accounting Principles Board Opinion No. 30 and/or in management's discussion and analysis of financial condition and results of operations appearing in the Company's annual report to shareholders for the applicable year, (f) acquisitions or divestitures, (g) foreign exchange gains and losses, (h) unrealized gains and losses on energy derivatives, (i) settlement of hedging activities, and (j) gains and losses from asset sales and emission and exchange allowance sales.
(D)    Adjustment of Performance Awards. Awards that are intended to qualify as Performance Awards may not be adjusted upward. The Committee may retain the discretion to adjust such Performance Awards downward, either on a formula or discretionary basis or any combination, as the Committee determines.
9.Consultant and Director Awards.
(a)Consultant Awards. The Committee has the sole authority to grant Consultant Awards from time to time in accordance with this Paragraph 9(a). Consultant Awards may consist of the forms of Award described in Paragraph 8, with the exception of Incentive Stock Options, may be granted singly, in combination, or in tandem and shall be granted subject to such terms and conditions as specified in Paragraph 8. Each Consultant Award shall be embodied in an Award Agreement, which shall contain such terms, conditions, and limitations as shall be determined by the Committee, in its sole discretion.
(b)Director Awards. The Board has the sole authority to grant Director Awards from time to time in accordance with this Paragraph 9(b). Director Awards may consist of the forms of Award described in Paragraph 8, with the exception of Incentive Stock Options, may be granted singly, in combination, or in tandem and shall be granted subject to such terms and conditions as specified in Paragraph 8. Each Director Award may, in the discretion of the Board, be embodied in an Award Agreement, which shall contain such terms, conditions, and limitations as shall be determined by the Board, in its sole discretion.
10.Award Payment; Dividends and Dividend Equivalents.
(a)General. Payment of Awards may be made in the form of cash or Common Stock, or a combination thereof, and may include such restrictions as the Committee (or the Board, in the case of Director Awards) shall determine, including, but not limited to, in the case of Common Stock, restrictions on transfer and forfeiture provisions. For a Restricted Stock Award, the certificates evidencing the shares of such Restricted Stock (to the extent that such shares are so evidenced) shall contain appropriate legends and restrictions that describe the terms and conditions of the restrictions applicable thereto. For a Restricted Stock Unit Award that may be settled in shares of Common Stock, the shares of Common Stock that may be issued at the end of the Restriction Period shall be evidenced by book entry registration or in such other manner as the Committee may determine.

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(b)Dividends and Dividend Equivalents. Rights to (1) dividends will be extended to and made part of any Restricted Stock Award and (2) Dividend Equivalents may be extended to and made part of any Restricted Stock Unit Award and Performance Unit Award, subject in each case to such terms, conditions and restrictions as the Committee may establish;  provided, however , that no such dividends or Dividend Equivalents shall be paid with respect to unvested Stock Awards, including Stock Awards subject to Performance Goals. Dividends and/or Dividend Equivalents shall not be made part of any Options or SARs.
11.Option Exercise. The Exercise Price shall be paid in full at the time of exercise in cash or, if permitted by the Committee and elected by the Participant, the Participant may purchase such shares by means of the Company withholding shares of Common Stock otherwise deliverable on exercise of the Award or tendering Common Stock valued at Fair Market Value on the date of exercise, or any combination thereof. The Committee, in its sole discretion, shall determine acceptable methods for Participants to tender Common Stock or other Awards. The Committee may provide for procedures to permit the exercise or purchase of such Awards by use of the proceeds to be received from the sale of Common Stock issuable pursuant to an Award (including cashless exercise procedures approved by the Committee involving a broker or dealer approved by the Committee). The Committee may adopt additional rules and procedures regarding the exercise of Options from time to time, provided that such rules and procedures are not inconsistent with the provisions of this Paragraph 11.
12.Taxes. The Company shall have the right to deduct applicable taxes from any Award payment and withhold, at the time of delivery or vesting of cash or shares of Common Stock under this Plan, an appropriate amount of cash or number of shares of Common Stock or a combination thereof for payment of required withholding taxes or to take such other action as may be necessary in the opinion of the Company to satisfy all obligations for withholding of such taxes;  provided, however , that the number of shares of Common Stock withheld for payment of required withholding taxes must equal no more than the required minimum withholding taxes. The Committee may also permit withholding to be satisfied by the transfer to the Company of shares of Common Stock theretofore owned by the holder of the Award with respect to which withholding is required. If shares of Common Stock are used to satisfy tax withholding, such shares shall be valued based on the Fair Market Value when the tax withholding is required to be made.
13.Amendment, Modification, Suspension or Termination. The Board may amend, modify, suspend or terminate this Plan (and the Committee may amend an Award Agreement) for the purpose of meeting or addressing any changes in legal requirements or for any other purpose permitted by law, except that (1) no amendment or alteration that would adversely affect the rights of any Participant under any Award previously granted to such Participant shall be made without the consent of such Participant and (2) no amendment or alteration shall be effective prior to its approval by the stockholders of the Company to the extent stockholder approval is otherwise required by applicable legal requirements or the requirements of the securities exchange on which the Company's stock is listed, including any amendment that expands the types of Awards available under this Plan, materially increases the number of shares of Common Stock available for Awards under this Plan, materially expands the classes of persons eligible for Awards under this Plan, materially extends the term of this Plan, materially changes the method of determining the Exercise Price of Options, deletes or limits any provisions of this Plan that prohibit the repricing of Options or SARs, or decreases any minimum vesting requirements for any Stock Award.

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14.Assignability. Unless otherwise determined by the Committee (or the Board in the case of Director Awards) and expressly provided for in an Award Agreement, no Award or any other benefit under this Plan shall be assignable or otherwise transferable except (1) by will or the laws of descent and distribution or (2) pursuant to a domestic relations order issued by a court of competent jurisdiction that is not contrary to the terms and conditions of this Plan or applicable Award and in a form acceptable to the Committee. The Committee may prescribe and include in applicable Award Agreements other restrictions on transfer. Any attempted assignment of an Award or any other benefit under this Plan in violation of this Paragraph 14 shall be null and void. Notwithstanding the foregoing, no Award may be transferred for value or consideration.
15.Adjustments.
(a)The existence of outstanding Awards shall not affect in any manner the right or power of the Company or its stockholders to make or authorize any or all adjustments, recapitalizations, reorganizations or other changes in the capital stock of the Company or its business or any merger or consolidation of the Company, or any issue of bonds, debentures, preferred or prior preference stock (whether or not such issue is prior to, on a parity with or junior to the Common Stock) or the dissolution or liquidation of the Company, or any sale or transfer of all or any part of its assets or business, or any other corporate act or proceeding of any kind, whether or not of a character similar to that of the acts or proceedings enumerated above.
(b)In the event of any subdivision or consolidation of outstanding shares of Common Stock, declaration of a dividend payable in shares of Common Stock or other stock split, then (1) the number of shares of Common Stock reserved under this Plan, (2) the number of shares of Common Stock covered by outstanding Awards in the form of Common Stock or units denominated in Common Stock, (3) the Exercise Price or other price in respect of such Awards, (4) the Stock-Based Award Limitations, and (5) the appropriate Fair Market Value and other price determinations for such Awards shall each be proportionately adjusted by the Committee as appropriate to reflect such transaction. In the event of any other recapitalization or capital reorganization of the Company, any consolidation or merger of the Company with another corporation or entity, the adoption by the Company of any plan of exchange affecting the Common Stock or any distribution to holders of Common Stock of securities or property (other than normal cash dividends or dividends payable in Common Stock), the Committee shall make appropriate adjustments to (i) the number and kind of shares of Common Stock covered by Awards in the form of Common Stock or units denominated in Common Stock, (ii) the Exercise Price or other price in respect of such Awards, (iii) the appropriate Fair Market Value and other price determinations for such Awards, and (iv) the Stock-Based Award Limitations to reflect such transaction; provided that such adjustments shall only be such as are necessary to maintain the proportionate interest of the holders of the Awards and preserve, without increasing, the value of such Awards.

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(c)In the event of a corporate merger, consolidation, acquisition of property or stock, separation, reorganization or liquidation, the Committee may make such adjustments to Awards or other provisions for the disposition of Awards as it deems equitable, and shall be authorized, in its discretion, (1) to provide for the substitution of a new Award or other arrangement (which, if applicable, may be exercisable for such property or stock as the Committee determines) for an Award or the assumption of the Award, regardless of whether in a transaction to which Code Section 424(a) applies, (2) to provide, prior to the transaction, for the acceleration of the vesting and exercisability of, or lapse of restrictions with respect to, the Award and, if the transaction is a cash merger, provide for the termination of any portion of the Award that remains unexercised at the time of such transaction, or (3) to cancel any such Awards and to deliver to the Participants cash in an amount that the Committee shall determine in its sole discretion is equal to the fair market value of such Awards on the date of such event, which in the case of Options or Stock Appreciation Rights shall be the excess of the Fair Market Value of Common Stock on such date over the Exercise Price of such Award.
(d)No adjustment or substitution pursuant to this Paragraph 15 shall be made in a manner that results in noncompliance with the requirements of Code Section 409A, to the extent applicable.
16.Restrictions. No Common Stock or other form of payment shall be issued with respect to any Award unless the Company shall be satisfied based on the advice of its counsel that such issuance will be in compliance with applicable federal and state securities laws. Certificates evidencing shares of Common Stock delivered under this Plan (to the extent that such shares are so evidenced) may be subject to such stop transfer orders and other restrictions as the Committee may deem advisable under the rules, regulations and other requirements of the Securities and Exchange Commission, any securities exchange or transaction reporting system upon which the Common Stock is then listed or to which it is admitted for quotation and any applicable federal or state securities law. The Committee may cause a legend or legends to be placed upon such certificates (if any) to make appropriate reference to such restrictions.
17.Unfunded Plan. This Plan is unfunded. Although bookkeeping accounts may be established with respect to Participants who are entitled to cash, Common Stock or rights thereto under this Plan, any such accounts shall be used merely as a bookkeeping convenience. The Company shall not be required to segregate any assets that may at any time be represented by cash, Common Stock or rights thereto, nor shall this Plan be construed as providing for such segregation, nor shall the Company, the Board or the Committee be deemed to be a trustee of any cash, Common Stock or rights thereto to be granted under this Plan. Any liability or obligation of the Company to any Participant with respect to an Award of cash, Common Stock or rights thereto under this Plan shall be based solely upon any contractual obligations that may be created by this Plan and any Award Agreement, and no such liability or obligation of the Company shall be deemed to be secured by any pledge or other encumbrance on any property of the Company. None of the Company, the Board or the Committee shall be required to give any security or bond for the performance of any obligation that may be created by this Plan. With respect to this Plan and any Awards granted hereunder, Participants are general and unsecured creditors of the Company and have no rights or claims except as otherwise provided in this Plan or any applicable Award Agreement.

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18.Code Section 409A.
(a)Awards made under this Plan are intended to comply with or be exempt from Code Section 409A, and ambiguous provisions hereof, if any, shall be construed and interpreted in a manner consistent with such intent. No payment, benefit or consideration shall be substituted for an Award if such action would result in the imposition of taxes under Code Section 409A. Notwithstanding anything in this Plan to the contrary, if any Plan provision or Award under this Plan would result in the imposition of an additional tax under Code Section 409A, that Plan provision or Award shall be reformed, to the extent permissible under Code Section 409A, to avoid imposition of the additional tax, and no such action shall be deemed to adversely affect the Participant's rights to an Award.
(b)Unless the Committee provides otherwise in an Award Agreement, each Restricted Stock Unit Award, Performance Unit Award or Cash Award (or portion thereof if the Award is subject to a vesting schedule) shall be settled no later than the 15th day of the third month after the end of the first calendar year in which the Award (or such portion thereof) is no longer subject to a “substantial risk of forfeiture” within the meaning of Code Section 409A. If the Committee determines that a Restricted Stock Unit Award, Performance Unit Award or Cash Award is intended to be subject to Code Section 409A, the applicable Award Agreement shall include terms that are designed to satisfy the requirements of Code Section 409A.
(c)If the Participant is identified by the Company as a “specified employee” within the meaning of Code Section 409A(a)(2)(B)(i) on the date on which the Participant has a “separation from service” (other than due to death) within the meaning of Treasury Regulation § 1.409A-1(h), any Award payable or settled on account of a separation from service that is deferred compensation subject to Code Section 409A shall be paid or settled on the earliest of (1) the first business day following the expiration of six months from the Participant's separation from service, (2) the date of the Participant's death, or (3) such earlier date as complies with the requirements of Code Section 409A.
19.Awards to Foreign Nationals and Employees Outside the United States. The Committee may, without amending this Plan, (1) establish special rules applicable to Awards granted to Participants who are foreign nationals, are employed or otherwise providing services outside the United States, or both, including rules that differ from those set forth in this Plan, and (2) grant Awards to such Participants in accordance with those rules.
20.Governing Law. This Plan and all determinations made and actions taken pursuant hereto, to the extent not otherwise governed by mandatory provisions of the Code or the securities laws of the United States, shall be governed by and construed in accordance with the laws of the State of Delaware.
21.Right to Continued Service or Employment. Nothing in this Plan or an Award Agreement shall interfere with or limit in any way the right of the Company or any of its Subsidiaries to terminate any Participant's employment or other service relationship with the Company or its Subsidiaries at any time, nor confer upon any Participant any right to continue in the capacity in which he is employed or otherwise serves the Company or its Subsidiaries.
22.Usage. Words used in this Plan in the singular shall include the plural and in the plural the singular, and the gender of words used shall be construed to include whichever may be appropriate under any particular circumstances of the masculine, feminine or neuter genders.
23.Headings. The headings in this Plan are inserted for convenience of reference only and shall not affect the meaning or interpretation of this Plan.

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ATTACHMENT A

NRG 2010 STOCK PLAN FOR GENON EMPLOYEES
DEFINITION OF
CHANGE IN CONTROL
For purposes of this Plan, a “Change in Control”shall be deemed to have occurred upon the occurrence of any of the following:
 	 	
(a)	30% Ownership Change: Any Person, other than an ERISA-regulated pension plan established by the Company, the Employer, or an Affiliate, makes an acquisition of Outstanding Voting Stock and is, immediately thereafter, the beneficial owner of 30% or more of the then Outstanding Voting Stock, unless such acquisition is made directly from the Company in a transaction approved by a majority of the Incumbent Directors; or any group is formed that is the beneficial owner of 30% or more of the Outstanding Voting Stock; or	
 	 	
(b)	Board Majority Change:  Individuals who are Incumbent Directors cease for any reason to constitute a majority of the members of the Board; or	
 	 	
(c)	Major Mergers and Acquisitions:  Consummation of a Business Combination unless, immediately following such Business Combination, (i) all or substantially all of the individuals and entities that were the beneficial owners of the Outstanding Voting Stock immediately before such Business Combination beneficially own, directly or indirectly, more than 70% of the then outstanding shares of voting stock of the parent corporation resulting from such Business Combination in substantially the same relative proportions as their ownership, immediately before such Business Combination, of the Outstanding Voting Stock, (ii) if the Business Combination involves the issuance or payment by the Company of consideration to another entity or its shareholders, the total fair market value of such consideration plus the principal amount of the consolidated long-term debt of the entity or business being acquired (in each case, determined as of the date of consummation of such Business Combination by a majority of the Incumbent Directors) does not exceed 50% of the sum of the fair market value of the Outstanding Voting Stock plus the principal amount of the Company's consolidated long-term debt (in each case, determined immediately before such consummation by a majority of the Incumbent Directors), (iii) no Person (other than any corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 30% or more of the then outstanding shares of voting stock of the parent corporation resulting from such Business Combination and (iv) a majority of the members of the board of directors of the parent corporation resulting from such Business Combination were Incumbent Directors of the Company immediately before consummation of such Business Combination; or	
 	 	
(d)	Major Asset Dispositions: Consummation of a Major Asset Disposition unless, immediately following such Major Asset Disposition, (i) individuals and entities that were beneficial owners of the Outstanding Voting Stock immediately before such Major Asset Disposition beneficially own, directly or indirectly, more than 70% of the then outstanding shares of voting stock of the Company (if it continues to exist) and of the entity that acquires the largest portion	

of such assets (or the entity, if any, that owns a majority of the outstanding voting stock of such acquiring entity) and (ii) a majority of the members of the Board (if it continues to exist) and of the entity that acquires the largest portion of such assets (or the entity, if any, that owns a majority of the outstanding voting stock of such acquiring entity) were Incumbent Directors of the Company immediately before consummation of such Major Asset Disposition.
Anything in this definition to the contrary notwithstanding, no Change in Control shall be deemed to have occurred unless such event constitutes an event specified in Code Section 409A(2)(A)(v) and the Treasury Regulations promulgated thereunder.
For purposes of the definition of a “Change in Control”,
 	 	
(1)	“Person” means an individual, entity or group;	
 	 	
(2)	“Group” is used as it is defined for purposes of Section 13(d)(3) of the Exchange Act;	
 	 	
(3)	“Beneficial Owner” is used as it is defined for purposes of Rule 13d-3 under the Exchange Act;	
 	 	
(4)	“Outstanding Voting Stock” means outstanding voting securities of the Company entitled to vote generally in the election of directors; and any specified percentage or portion of the Outstanding Voting Stock (or of other voting stock) is determined based on the combined voting power of such securities;	
 	 	
(5)	“Incumbent Director” means a director of the Company (x) who was a director of the Company on the effective date of the Award Agreement or (y) who becomes a director after such date and whose election, or nomination for election by the Company's shareholders, was approved by a vote of a majority of the Incumbent Directors at the time of such election or nomination, except that any such director will not be deemed an Incumbent Director if his or her initial assumption of office occurs as a result of an actual or threatened election contest or other actual or threatened solicitation of proxies by or on behalf of a Person other than the Board;	
 	 	
(6)	“Election Contest” is used as it is defined for purposes of Rule 14a-11 under the Exchange Act;	
 	 	
(7)	“Business Combination”  means	
 	 	
(x)	a merger or consolidation involving the Company or its stock or	
 	 	
(y) 	an acquisition by the Company, directly or through one or more subsidiaries, of another entity or its stock or assets;	
 	 	
(8)	“Parent Corporation Resulting From a Business Combination” means the Company if its stock is not acquired or converted in the Business Combination and otherwise means the entity which as a result of such Business Combination owns the Company or all or substantially all the Company's assets either directly or through one or more subsidiaries; and	

 	 	
(9)	“Major Asset Disposition” means the sale or other disposition in one transaction or a series of related transactions of 70% or more of the assets of the Company and its subsidiaries on a consolidated basis; and any specified percentage or portion of the assets of the Company will be based on fair market value, as determined by a majority of the Incumbent Directors.	
 	 	
(10)	“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.	
 	 	
(11)	“Employer” means NRG Energy, Inc., and any successor thereto.	
 	 	
(12)	“Affiliate” means an Affiliate within the meaning of Rule 12b-2 promulgated under Section 12 of the Exchange Act.	

EXHIBIT 10.50

$500,000,000.00
REVOLVING CREDIT AGREEMENT
among
GENON ENERGY, INC.,
as a Borrower,
GENON AMERICAS, INC.,
as a Borrower,

The Several Lenders from Time to Time Parties Hereto,
NRG ENERGY, INC.,
as Administrative Agent

Dated as of December 14, 2012

____________________________________
$500,000,000.00 Revolving Facility

1

TABLE OF CONTENTS

Section 1.	DEFINITIONS	6	
 	
 	1.1 Defined Terms	6	
 	
 	1.2 Other Definitional Provisions	24	
 	
Section 2	AMOUNT AND TERMS OF COMMITMENTS	24	
 	
 	2.1 Existing Obligations	24	
 	
 	2.2 [Reserved]	24	
 	
 	2.3 [Reserved]	24	
 	
 	2.4 Commitments	24	
 	
 	2.5 Procedure for Loan Borrowing	25	
 	
 	2.6 Commitment Fees, etc.	25	
 	
 	2.7 Termination or Reduction of Commitments	26	
 	
 	2.8 Optional Prepayments	26	
 	
 	2.9 Mandatory Prepayments	26	
 	
 	2.10 Conversion and Continuation Options	27	
 	
 	2.11 Limitations on Eurodollar Tranches	27	
 	
 	2.12 Interest Rates and Payment Dates	27	
 	
 	2.13 Computation of Interest and Fees	28	
 	
 	2.14 Inability to Determine Interest Rate	28	
 	
 	2.15 Pro Rata Treatment and Payments	28	
 	
 	2.16 Requirements of Law	29	
 	
 	2.17 Taxes	30	
 	
 	2.18 Indemnity	32	
 	
 	2.19 Joint and Several Liability	32	
 	
Section 3	LETTERS OF CREDIT	32	
 	
 	3.1 L/C Commitment	32	
 	
 	3.2 Procedure for Issuance of Letters of Credit	33	
 	
 	3.3 L/C Fees and Other Charges	33	
 	
 	3.4 L/C Participations	33	
 	
 	3.5 L/C Reimbursement Obligation of the Borrowers	34	
 	
 	3.6 Obligations Absolute	34	
 	
 	3.7 Letter of Credit Payments	35	
 	
 	3.8 Applications	35	
 	
 	3.9 Existing Letters of Credit	35	
 	
Section 4	REPRESENTATIONS AND WARRANTIES	35	
 	
 	4.1 Organization; Power and Authority	35	
 	
 	4.2 Due Authorization	36	
 	
 	4.3 Governmental Approval	36	
 	
 	4.4 Binding and Enforceable	36	
 	
 	4.5 No Violation	36	
 	
 	4.6 No Default	36	
 	
 	4.7 Litigation	36	
 	
 	4.8 [Reserved]	36	
 	
 	4.9 Material Adverse Change	36	
 	
 	4.10 Investment Company Act	36	

2

 	
 	 	 	 	
 	4.11 Environmental Matters	36	
 	
 	4.12 Accuracy of Information, etc.	37	
 	
 	4.13 Employee Benefit Plans	37	
 	
 	4.14 Tax Returns and Payments	37	
 	
 	4.15 Security Documents	37	
 	
 	4.16 Ownership of Property	37	
 	
Section 5	CONDITIONS PRECEDENT	37	
 	
 	5.1 Conditions of Initial Extension of Credit	37	

 	5.2 Conditions to Each Extension of Credit	39	
 	
Section 6	AFFIRMATIVE COVENANTS	40	
 	
 	6.1 Compliance with Law; Maintenance of Existence	40	
 	
 	6.2 [Reserved]	40	
 	
 	6.3 Certificates; Other Information	40	
 	
 	6.4 Notices	40	
 	
 	6.5 Inspection	41	
 	
 	6.6 Maintenance of Property; Insurance	41	
 	
 	6.7 [Subsequent Acquired Property; New Subsidiaries	41	
 	
 	6.8 Collateral Information	43	
 	
 	6.9 Further Assurances	43	
 	
 	6.10 Use of Proceeds	43	
 	
Section 7	 [RESERVED]	43	
 	
Section 8	NEGATIVE COVENANTS	43	
 	
 	8.1 Debt	43	
 	
 	8.2 Restricted Payments	43	
 	
 	8.3 Liens	44	
 	
 	8.4 Mergers	47	
 	
 	8.5 Asset sales	47	
 	
 	8.6 Investments	47	
 	
 	8.7 Transactions with Affiliates	49	
 	
 	8.8 Sales and Leasebacks	49	
 	
 	8.9 Changes in Fiscal Periods	49	
 	
 	8.10 NRG Credit Agreement	49	
 	
Section 9	EVENTS OF DEFAULT	50	
 	
Section 10	THE ADMINISTRATIVE AGENT	52	
 	
 	10.1 Appointment	52	
 	
 	10.2 Delegation of Duties	53	
 	
 	10.3 Exculpatory Provisions	53	
 	
 	10.4 Reliance by Administrative Agent	53	
 	
 	10.5 Notice of Default	54	
 	
 	10.6 Non-Reliance on Administrative Agent and Other Lenders	54	
 	
 	10.7 Indemnification	54	
 	
 	10.8 Agent in Its Individual Capacity	55	
 	
 	10.9 Successor Administrative Agent	55	
 	
Section 11	MISCELLANEOUS	55	
 	
 	11.1 Amendments and Waivers	55	
 	
 	11.2 Notices	56	

3

 	
 	 	 	 	
 	11.3 No Waiver; Cumulative Remedies	58	
 	
 	11.4 Survival of Representations and Warranties	58	
 	
 	11.5 Payment of Expenses and Taxes	58	
 	
 	11.6 Successors and Assigns; Participations and Assignments	60	
 	
 	11.7 Adjustment and Set-Off	63	
 	
 	11.8 Counterparts	63	
 	
 	11.9 Severability	63	
 	
 	11.10 Integration	64	
 	
 	11.11 Governing Law	64	
 	
 	11.12 Submission To Jurisdiction; Waivers	64	
 	
 	11.13 Acknowledgements	64	
 	
 	11.14 Releases of Guarantees and Liens	65	
 	
 	11.15 Confidentiality	65	
 	
 	11.16 WAIVERS OF JURY TRIAL	65	
 	
 	11.17 Delivery of Addenda	65	

 	
 	 	
SCHEDULES	
1.1A	Commitments	
1.1B	Mortgaged Property	
1.1D	Unrestricted Subsidiaries	

 	
 	 	
EXHIBITS:	
A	Form of Guarantee Agreement	
B	Form of Joinder, Acknowledgment, and Reaffirmation of Security Agreement	
C	Form of Accession Agreement to Collateral Trust Agreement	
D	Form of Closing Certificate	
E	Form of Assignment and Assumption	
F	Form of Lender Addendum	

4

REVOLVING CREDIT AGREEMENT (this “Agreement”), dated as of December 14, 2012, among GENON ENERGY, INC., a Delaware corporation (the “ Company ”), GENON AMERICAS, INC., a Delaware corporation (“ GAI ”, each of GAI and the Company, a “ Borrower ” and, together, the “ Borrowers ”), the banks, financial institutions and/or other financial or non-financial entities or other Persons from time to time parties to this Agreement (the “ Lenders ”), and NRG ENERGY, INC., a Delaware corporation, (“ NRG ”) as administrative agent for the Lenders under this Agreement and the other Loan Documents, or any successor thereto ( “ Administrative Agent ”).
RECITALS
WHEREAS, the Company, NRG, and Plus Merger Corporation (“Merger Sub”) have entered into that certain Agreement and Plan of Merger dated as of July 20, 2012 (as amended, amended and restated, supplemented or otherwise modified from time to time, the “ Merger Agreement ”) whereby NRG will acquire 100% of the capital stock of the Company by means of a merger between Merger Sub and the Company, with the Company as the surviving corporation (the “ Merger ”);
WHEREAS, until immediately prior to the effective time of the Merger and this Agreement, the Borrowers are parties to that certain Credit Agreement dated as of September 20, 2010 by and among the Borrowers, the several banks and other financial institutions or entities from time to time parties thereto, Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as co-syndication agents, Goldman Sachs Bank USA and Morgan Stanley Senior Funding, Inc., as co-documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent (as amended, amended and restated, extended, supplemented or otherwise modified from time to time, the “ Existing Credit Agreement ”) and the Loan Documents (as such term is defined in the Existing Credit Agreement) (as amended, amended and restated, extended, supplemented or otherwise modified from time to time, the “ Existing Loan Documents ”);
WHEREAS, concurrently with the Merger, the Borrowers desire to (i) repay, discharge and satisfy in full all principal, interest, fees, expenses and other Obligations (as such term is defined in the Existing Credit Agreement) outstanding under the Existing Credit Agreement and Existing Loan Documents (the “ Existing Obligations ”) and (ii) terminate all commitments under the Existing Loan Documents (clauses (i) and (ii), the “ Pay-Off ”);
WHEREAS, the Borrowers desire to Refinance (as such term is defined in the Collateral Trust Agreement) the Existing Obligations substantially concurrently with the Pay-Off (the “ Refinancing ” and together with the Merger and the Pay-Off, the “ Transactions ”) in order to finance certain working capital and other general corporate purposes (including, without limitation, acquisitions and distributions permitted hereunder and the providing of credit support in the form of Letters of Credit) of the Borrower and its Subsidiaries from time to time;
WHEREAS, the Borrowers have requested that the Lenders make Loans and other extensions of credit available to them to achieve the Refinancing;
WHEREAS, the Lenders have agreed to extend such Loans and extensions of credits subject to the terms and conditions set forth herein and in the other Loan Documents;
WHEREAS, the parties hereto acknowledge and agree that this Agreement constitutes a Refinancing (as defined in the Collateral Trust Agreement) of the Existing Credit Obligations and a Replacement Credit Agreement (as such term is defined in the Collateral Trust Agreement) for all purposes under the Collateral Trust Agreement and that the Obligations hereunder and under the other Loan Documents constitute Credit Agreement Obligations (as such term is defined in the Collateral Trust Agreement) secured

5

by a First Lien (as such term is defined in the Collateral Trust Agreement) in all of the Collateral (as such term is defined in the Collateral Trust Agreement);
Accordingly, in consideration of the mutual agreements contained herein and other good and valuable consideration, the sufficiency and receipt of which are hereby acknowledged, the parties hereto hereby agree as follows:
SECTION 1. DEFINITIONS
1.1 Defined Terms. As used in this Agreement, the terms listed in this Section 1.1 shall have the respective meanings set forth in this  Section 1.1 .
“ABR”: for any day, a rate per annum (rounded upwards, if necessary, to the next 1/16 of 1%) equal to the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day  plus  ½ of 1% and (c) the Eurodollar Rate for a one-month Interest Period beginning on such day (or if such day is not a Business Day, the immediately preceding Business Day)  plus  1%. For purposes hereof, “ Prime Rate ” shall mean the rate of interest per annum publicly announced from time to time by one or more New York-based banks (as determined by the Administrative Agent in its sole discretion), as its prime rate in effect at its principal office in New York City (the Prime Rate not being intended to be the lowest rate of interest charged by such banks, in connection with extensions of credit to debtors). Any change in the ABR due to a change in the Prime Rate, the Federal Funds Effective Rate or the Eurodollar Rate shall be effective as of the opening of business on the effective day of such change in the Prime Rate, the Federal Funds Effective Rate or the Eurodollar Rate, respectively.
“ABR Loans”: Loans the rate of interest applicable to which is based upon the ABR.
“Addendum”: an instrument, substantially in the form of Exhibit F, by which a Lender becomes a party to this Agreement on or prior to or as of the Closing Date.
“Administrative Agent”: as defined in the Preamble hereto.
“Affiliate”: as to any Person (other than an individual), any other Person (other than an individual) that, directly or indirectly through one or more intermediaries, is in Control of, is Controlled by, or is under common Control with, such Person.
“Agent Indemnitee”: as defined in Section 10.7.
“Aggregate Exposure”: with respect to any Lender at any time, an amount equal to the amount of such Lender's Commitment then in effect or, if the Commitments have been terminated, the amount of such Lender's Extensions of Credit then outstanding.
“Aggregate Exposure Percentage”: with respect to any Lender at any time, the ratio (expressed as a percentage) of such Lender's Aggregate Exposure at such time to the Aggregate Exposure of all Lenders at such time.
“Agreement”: as defined in the Preamble hereto.
“Applicable Margin”: with respect to each Type of Loan, the rate per annum set forth under the relevant column heading below:

 	ABR Loans	Eurodollar Loans	
Loans	2.50%	3.50%	

6

“Application”: with respect to any Lender, an application in such form as such Lender may specify from time to time in connection with any request for a Letter of Credit.
“Approved Fund”: as defined in Section 11.6(b).
“Asset Sale”: any Disposition or series of related Dispositions other than any Excluded Asset Sale.
“Assignee”: as defined in Section 11.6(b).
“Assignment and Assumption”: an Assignment and Assumption, substantially in the form of Exhibit E.
“Attributable Debt”: on any date, (a) in respect of a sale and leaseback transaction, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended (such present value to be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP;  provided , that if such sale and leaseback transaction results in a Capital Lease Obligation, the amount of Debt represented thereby will be determined in accordance with the definition of “Capital Lease Obligation”) and (b) in respect of any Synthetic Lease Obligation or financing lease, the amount of the remaining lease payments under the relevant lease that would as of such date be required to be capitalized on a balance sheet in accordance with GAAP if such lease were accounted for as a Capital Lease Obligation.
“Available Commitment”: as to any Lender at any time, an amount equal to the excess, if any, of (a) such Lender's Commitment then in effect  over  (b) such Lender's Extensions of Credit then outstanding.
“Bankruptcy Event”: with respect to any Person, such Person becomes the subject of a bankruptcy or insolvency proceeding, or has had a receiver, conservator, trustee, administrator, custodian, assignee for the benefit of creditors or similar Person charged with the reorganization or liquidation of its business appointed for it, has taken any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any such proceeding or appointment.
“Benefitted Lender”: as defined in Section 11.7(a).
“Board”: the Board of Governors of the Federal Reserve System of the United States (or any successor).
“Borrower” and “Borrowers”: as defined in the Preamble hereto.
“Borrowing Date”: any Business Day specified by the Company as a date on which the Company requests the relevant Lenders to make Loans hereunder.
“Business Day”: a day other than a Saturday, Sunday or other day on which commercial banks in New York City are authorized or required by law to close,  provided , that with respect to notices and determinations in connection with, and payments of principal and interest on, Eurodollar Loans, such day is also a day for trading by and between banks in Dollar deposits in the interbank eurodollar market.
“Capital Expenditures”: for any period, with respect to any Person, the aggregate of all expenditures by such Person and its Subsidiaries for the acquisition or leasing (pursuant to a capital lease) of fixed or capital assets or additions to equipment (including replacements, repairs and improvements during such period) that should be capitalized under GAAP on a consolidated balance sheet of such Person and its Subsidiaries. For purposes of this definition, the purchase price of equipment that is purchased simultaneously

7

with the trade-in of existing equipment or with insurance proceeds shall be included in Capital Expenditures only to the extent of the gross amount of such purchase price less the credit granted by the seller of such equipment for the equipment being traded in at such time or the amount of such proceeds, as the case may be.
“Capital Lease Obligation”: as applied to any Person, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet of such Person in accordance with GAAP in the reasonable judgment of such Person, and the stated maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be prepaid by the lessee without payment of a penalty.
“Capital Stock”: any and all shares, interests, participations or other equivalents (however designated) of capital stock of a corporation, any and all equivalent ownership interests in a Person (other than a corporation) and any and all warrants, rights or options to purchase any of the foregoing.
“Cash Equivalents”: (a) marketable direct obligations issued by, or unconditionally guaranteed by, the United States Government or issued by any agency thereof and backed by the full faith and credit of the United States, in each case maturing within one year from the date of acquisition; (b) certificates of deposit, time deposits, eurodollar time deposits or overnight bank deposits having maturities of six months or less from the date of acquisition issued by any Lender or by any commercial bank organized under the laws of the United States or any state thereof having combined capital and surplus of not less than $500,000,000; (c) commercial paper of an issuer rated at least A-1 by S&P or P-1 by Moody's, or carrying an equivalent rating by a nationally recognized rating agency, if both of the two named rating agencies cease publishing ratings of commercial paper issuers generally, and maturing within six months from the date of acquisition; (d) repurchase obligations of any Lender or of any commercial bank satisfying the requirements of clause (b) of this definition, having a term of not more than 30 days, with respect to securities issued or fully guaranteed or insured by the United States government; (e) securities with maturities of one year or less from the date of acquisition issued or fully guaranteed by any state, commonwealth or territory of the United States, by any political subdivision or taxing authority of any such state, commonwealth or territory or by any foreign government, the securities of which state, commonwealth, territory, political subdivision, taxing authority or foreign government (as the case may be) are rated at least A by S&P or A by Moody's; (f) securities with maturities of six months or less from the date of acquisition backed by standby letters of credit issued by any Lender or any commercial bank satisfying the requirements of clause (b) of this definition; (g) money market mutual or similar funds that invest exclusively in assets satisfying the requirements of clauses (a) through (f) of this definition; or (h) money market funds that (i) (x) comply with the criteria set forth in SEC Rule 2a-7 under the Investment Company Act of 1940, as amended and are rated A by S&P and A by Moody's or (y) are rated AAA by S&P and Aaa by Moody's and (ii) have portfolio assets of at least $2,500,000,000.
“Change of Control”: the occurrence after the Closing Date of any of the following:
 	 	
(i)	the direct or indirect sale, transfer, conveyance or other Disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Company and its Subsidiaries taken as a whole to any “person” (as that term is used in Section 13(d) of the Exchange Act, but excluding any employee benefit plan of the Company or any of the Restricted Subsidiaries, and any Person or entity acting in its capacity as trustee, agent or other fiduciary or administrator of any such plan) that is not 100% owned, directly or indirectly, by NRG (other than the Company and its Subsidiaries); or	

8

 	 	
(ii)	the consummation of any transaction (including any merger or consolidation) the result of which is that any “person” (as defined above) that is not 100% owned, directly or indirectly, by NRG (other than the Company and its Subsidiaries) becomes the beneficial owner, directly or indirectly, of more than 50% of the voting stock of the Company, measured by voting power rather than number of shares.	
“Closing Date”: the date designated as the Closing Date by the Company and the Administrative Agent, on which the conditions precedent set forth in  Section 5.1  shall have been satisfied or waived.
“Code”: the Internal Revenue Code of 1986, as amended from time to time, and the regulations promulgated thereunder.
“Collateral”: all property of the Loan Parties, now owned or hereafter acquired, upon which a Lien is purported to be created by any Security Document.
“Collateral Trust Agreement”: the Collateral Trust Agreement dated on or about December 3, 2010 by and among the Borrowers, the Subsidiary Guarantors, the Administrative Agent, the Collateral Trustee, and the other parties named therein, as amended, amended and restated, supplemented or otherwise in effect from time to time.
“Collateral Trustee”: U.S. Bank National Association or any successor thereto and, as the context may require, any co-trustee appointed pursuant to the terms of the Collateral Trust Agreement.
“Commitment”: as to any Lender, the obligation of such Lender, if any, to make Loans and participate in Letters of Credit in an aggregate principal and/or face amount not to exceed the amount set forth under the heading “Commitment” opposite such Lender's name on Schedule 1.1A or in the Assignment and Assumption pursuant to which such Lender became a party hereto, as the same may be changed from time to time pursuant to the terms hereof.
“Commitment Fee Rate”: 0.750% per annum.
“Commitment Period”: the period from and including the Closing Date to the Termination Date.
“Commodity Agreement”: any contract for commercial and trading activities (including any option, exchange, swap, forward contract or futures contract, whether for physical delivery or financial settlement) for the purchase, transmission, transportation, distribution, sale, lease or hedge of any emissions or fuel-related or energy- or capacity-related commodity or service.
“Common Stock”: with respect to any Person, any and all shares, interests or other participations in, and other equivalents (however designated and whether voting or non-voting) of such Person's common stock whether or not outstanding on the Closing Date, including all series and classes of such common stock.
“Company”: as defined in the Preamble hereto.
“Contractual Obligation”: as to any Person, any provision of any security issued by such Person or of any agreement, instrument or other undertaking to which such Person is a party or by which it or any of its property is bound.

9

“Control”: with respect to any Person, the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise; and the terms “controlling,” “controlled by” and “under common control with” have correlative meanings.
“Debt”: with respect to any specified Person, any indebtedness of such Person (excluding accrued expenses or trade payables), whether or not contingent (without duplication):
 	 	
(i)	in respect of borrowed money;	
 	 	
(ii)	evidenced by bonds, notes, debentures or similar instruments or letters of credit or reimbursement agreements in respect thereof;	
 	 	
(iii)	in respect of banker's acceptances;	
 	 	
(iv)	representing Capital Lease Obligations or Attributable Debt in respect of sale and leaseback transactions (excluding the REMA Lease and the GMA Lease which shall not constitute Debt), Synthetic Lease Obligations or financing leases;	
 	 	
(v)	representing all obligations of such Person in respect of the deferred purchase price of property or services due more than six months after such property is acquired or such services are completed;	
 	 	
(vi)	representing any Hedging Obligations; or	
 	 	
(vii)	consisting of Disqualified Stock;	
whether or not any of the preceding items appear as a liability on a balance sheet of the specified Person prepared in accordance with GAAP;  provided ,  however , “Debt” shall not include indebtedness which has been irrevocably defeased. In addition, the term “Debt” includes all Debt of others secured by a Lien on any asset of the specified Person (whether or not such Debt is assumed by the specified Person, but excluding Liens securing Project Finance Debt and Liens on Capital Stock of any Unrestricted Subsidiary) and, to the extent not otherwise included, the Guarantee by the specified Person of any Debt of any other Person.
The amount of any Debt outstanding as of any date will be:
 	 	
(i)	the accreted value of the Debt, in the case of any Debt issued with original issue discount;	
 	 	
(ii)	the principal amount of and premium (if any) on the Debt, in the case of any other Debt;	
 	 	
(iii)	in respect of Debt of other Persons secured by a Lien on the assets of the specified Person, the lesser of: (A) the Fair Market Value of such asset at such date of determination, and (B) the amount of such Debt of such other Persons;	
 	 	
(iv)	in respect of any Guarantee, an amount equal to the stated or determinable amount of the related primary obligation, or portion thereof, in respect of which such Guarantee is made or, if not stated or determinable, the maximum reasonably anticipated liability in respect thereof as determined by the guaranteeing Person in good faith;	
 	 	
(v)	zero for undrawn letters of credit and undrawn revolvers; and	
 	 	
(vi)	in respect of any Hedging Obligations, the amount, if any, which is then due and payable thereunder.	

10

“Default”: any of the events specified in Section 9, whether or not any requirement for the giving of notice, the lapse of time, or both, has been satisfied.
“Designated Party”: has the meaning set forth in Section 9(i).
“Disposition”: (a) with respect to any assets, any sale, lease (other than an operating lease), conveyance or other disposition thereof and (b) the sale or issuance of Capital Stock in any of the Restricted Subsidiaries (other than to another Restricted Subsidiary or the Company). The terms “ Dispose ” and “ Disposed of ” shall have correlative meanings.
“Disqualified Stock”: with respect to any Person, any Capital Stock of such Person which, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case, at the option of the holder of such Capital Stock), (i) matures or is subject to a scheduled redemption, pursuant to a sinking fund obligation or otherwise, on or prior to the date that is 91 days after the Termination Date or (ii) matures or is subject to mandatory redemption upon the happening of any event unless such maturity or mandatory redemption is conditioned on the prior repayment in full of the Facilities. The amount of Disqualified Stock deemed to be outstanding at any time for purposes of this Agreement shall be equal to the maximum amount that the Borrowers and the Restricted Subsidiaries may become obligated to pay upon the maturity of, or pursuant to any mandatory redemption provisions of, such Disqualified Stock, exclusive of accrued dividends.
“Dollars” and “$”: dollars in lawful currency of the United States.
“Domestic Subsidiary”: any Subsidiary of the Company organized in or under the laws of the United States, any state thereof or the District of Columbia other than (1) a Subsidiary in which a Foreign Subsidiary directly or indirectly owns a majority of the voting equity interests or (2) a Subsidiary that owns no material assets other than the equity interests of one or more Foreign Subsidiaries.
“Eligible Assignee”: any assignee permitted under Section 11.6.
“Eligible Commodity Hedging Agreement”: any Commodity Agreement entered into by any Loan Party from time to time which (i) is intended to reduce risk to the Company or any Restricted Subsidiary associated with fluctuations in the price or availability of any emissions or fuel-related or energy- or capacity-related commodity or service (“commodity”), and (ii) is structured such that the net mark-to-market credit exposure of (a) the counterparties to such Commodity Agreements (taken as a whole) to (b) the Company or any other Loan Party, is (x) positively correlated with the price of the relevant commodity or (y) positively correlated with changes in the relevant fuel to energy spread.
“Eligible Commodity Hedging Obligations”: with respect to any Loan Party, the obligations of such Person under an Eligible Commodity Hedging Agreement. For purposes of designating obligations as Eligible Commodity Hedging Obligations secured by the Collateral pursuant to the Security Agreement, such designation shall be deemed effective if accompanied by a certification by the Company representing that such obligations meet the definition of Eligible Commodity Hedging Obligations.
“Environmental Capital Expenditures”: Capital Expenditures required by, or reasonably related to the Company's or its Subsidiaries' compliance with, Environmental Laws.
“Environmental Laws”: any and all foreign, Federal, state, local or municipal laws, rules, orders, regulations, statutes, ordinances, codes, decrees, requirements of any Governmental Authority or other Requirements of Law (including common law) regulating, relating to or imposing liability or standards of conduct concerning protection of human health or the environment, as now or may at any time hereafter be in effect.

11

“ERISA”: the Employee Retirement Income Security Act of 1974, as amended from time to time, and the regulations promulgated thereunder.
“ERISA Affiliate”: all members of a group of corporations and all members of a group of trades or businesses (whether or not incorporated) under common control which, together with the Company, are treated as a single employer under Section 414(b) or (c) of the Code.
“ERISA Event”: any of the following events: (i) the appointment of a trustee to administer or terminate any Plan, (ii) the termination of a Plan, (iii) any failure by any Plan to satisfy the minimum funding standards (within the meaning of Sections 412 or 430 of the Code or Section 302 of ERISA), whether or not waived, (iv) the filing pursuant to Section 412(c) of the Code or Section 302(c) of ERISA of an application for a waiver of the minimum funding standard with respect to any Plan, the failure to make by its due date a required installment under Section 430(j) of the Code with respect to any Plan or the failure by the Company or any of its ERISA Affiliates to make any required contribution to a Multiemployer Plan, (v) a determination that any Plan is, or is expected to be, in “at risk” status (within the meaning of Section 430 of the Code or Section 303 of ERISA), (vi) the imposition of a Lien under the Code or ERISA on the assets of the Company on account of any Plan, (vii) the occurrence of a reportable event described in Section 4043(c) of ERISA (other than those events as to which the 30-day notice period is waived) with respect to a Plan, or (viii) the incurrence by the Company of any liability in connection with a withdrawal from a Multiemployer Plan, or the determination that a Multiemployer Plan is, or is expected to be, insolvent (within the meaning of Section 4245 of ERISA), in reorganization (within the meaning of Section 4241 of ERISA) or in endangered or critical status (within the meaning of Section 432 of the Code or Section 305 or Title IV of ERISA).
“Eurocurrency Reserve Requirements”: for any day as applied to a Eurodollar Loan, the aggregate (without duplication) of the maximum rates (expressed as a decimal fraction) of reserve requirements in effect on such day (including basic, supplemental, marginal and emergency reserves) under any regulations of the Board or other Governmental Authority having jurisdiction with respect thereto dealing with reserve requirements prescribed for eurocurrency funding (currently referred to as “Eurocurrency Liabilities” in Regulation D of the Board) maintained by a member bank of the Federal Reserve System.
“Eurodollar Loans”: Loans the rate of interest applicable to which is based upon the Eurodollar Rate.
“Eurodollar Rate”: with respect to each day during each Interest Period pertaining to a Eurodollar Loan, the rate per annum determined on the basis of the rate for deposits in Dollars for a period equal to such Interest Period commencing on the first day of such Interest Period appearing on the Reuters Screen LIBOR01 Page (or any successor page as determined by the Administrative Agent) as of 11:00 A.M., London time, two Business Days prior to the beginning of such Interest Period; provided , that in no event shall the Eurodollar Rate (including for the purpose of determining ABR) be less than 1.75% per annum. In the event that such rate does not appear on such page (or otherwise on such screen), the “ Eurodollar Rate ” shall be determined by reference to such other comparable publicly available service for displaying eurodollar rates as may be selected by the Administrative Agent or, in the absence of such availability, by reference to the rate at which the Administrative Agent is offered Dollar deposits at or about 11:00 A.M., New York City time, two Business Days prior to the beginning of such Interest Period in the interbank eurodollar market where its eurodollar and foreign currency and exchange operations are then being conducted for delivery on the first day of such Interest Period for the number of days comprised therein.
“Eurodollar Tranche”: the collective reference to Eurodollar Loans the then current Interest Periods with respect to all of which begin on the same date and end on the same later date (whether or not such Loans shall originally have been made on the same day).

12

“Event of Default”: any of the events specified in Section 9, provided that any requirement for the giving of notice, the lapse of time, or both, has been satisfied.
“Exchange Act”: the Securities Exchange Act of 1934, as amended from time to time.
“Excluded Asset Sale”: each of the following transactions:
 	 	
(i)	the Disposition of damaged, obsolete, uneconomic or worn out property, or property which in the good faith judgment of the Company is no longer useful in its or the Restricted Subsidiaries' business, in each case, in the ordinary course of business;	
 	 	
(ii)	Dispositions (a) among the Company and Restricted Subsidiaries, (b) among Restricted Subsidiaries, or (c) to the NRG Parent Group;	
(iii)    Dispositions of Cash Equivalents or other short-term investments;
 	 	
(iv)	Dispositions by the Company or any Restricted Subsidiary of fuel or emission or environmental credits;	
 	 	
(v)	any Disposition or series of related Dispositions resulting in proceeds not in excess of $50,000,000;	
 	 	
(vi)	Restricted Payments permitted by Section 8.2 ;	
 	 	
(vii)	any Disposition in connection with a foreclosure, transfer or deed in lieu of foreclosure or other exercise of remedial action;	
 	 	
(viii)	Dispositions, not resulting in the Disposing of all or substantially all of the assets of the Company and the Restricted Subsidiaries, of inventory, products, electric energy, commodities, capacity, ancillary services, fuel, rights, services or accounts receivable;	
(ix) Investments permitted by Section 8.6;
 	 	
(x)	a Disposition resulting from any condemnation; provided, if such Disposition involves assets with gross cash proceeds in excess of $50,000,000, that any cash proceeds received in connection therewith are treated as Net Cash Proceeds of an Asset Sale;	
 	 	
(xi)	compromises and settlements of claims against third-parties and Dispositions of assets in connection with the settlement of claims and litigation; and	
 	 	
(xii)	grants by the Company or any of its Subsidiaries of licenses, sublicenses, leases or subleases or easements to other Persons not materially interfering with the conduct by the Company or such Subsidiary of its business on or at the property that is the subject of such license, sublicense, lease or sublease or easement.	
“Excluded Proceeds”: Net Cash Proceeds from Asset Sales or Recovery Events in an amount not to exceed $300,000,000 in the aggregate in any fiscal year and $1,000,000,000 in the aggregate during the term of this Agreement.
“Existing Credit Agreement”: as defined in the Recitals hereto.
“Existing Letters of Credit”: the letters of credit assigned from the Borrowers to NRG pursuant to those certain L/C Assignment and Assumption Agreements.
“Existing Loan Documents”: as defined in the Recitals hereto.

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“Existing Obligations”: as defined in the Recitals hereto.
“Expected Net Proceeds”: the Net Cash Proceeds that the Company expects to receive in connection with a pending and binding Asset Sale or issuance or sale of Capital Stock.
“Extensions of Credit”: as to any Lender at any time, an amount equal to the sum of (a) the aggregate principal amount of all Loans held by such Lender then outstanding and (b) such Lender's Revolving Percentage of the L/C Obligations then outstanding.
“Facility”: the Commitments and the extensions of credit made thereunder.
“Fair Market Value”: the value that would be paid by a willing buyer to a willing seller in a transaction not involving distress or necessity of either party, determined in good faith by the chief financial officer, treasurer, assistant treasurer, controller or board of directors of the Company or the selling entity.
“FATCA”: Sections 1471 through 1474 of the Code, as of the date of this Agreement.
“Federal Funds Effective Rate”: for any day, the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System arranged by federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average of the quotations for the day of such transactions received by Administrative Agent from three federal funds brokers of recognized standing selected by it.
“Fee Payment Date”: (a) the third Business Day following the last day of each March, June, September and December and (b) the last day of the Commitment Period.
“Foreign Subsidiary”: any Subsidiary of the Company that is not a Domestic Subsidiary.
“Foundation”: RRI Energy Foundation, Inc, a Texas non-profit corporation, or any successor thereto.
“Funding Office”: the office of the Administrative Agent specified in Section 11.2  or such other office as may be specified from time to time by the Administrative Agent as its funding office by written notice to the Company and the Lenders.
“GAAP”: those generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession, which are in effect from time to time.
“GAI”: as defined in the Preamble hereto.
“GEM”: GenOn Energy Management, LLC, a Delaware limited liability company, or any successor thereto.
“GMA”: GenOn Mid-Atlantic, LLC, a Delaware limited liability company, or any successor thereto.
“GMA Lease”: collectively, the obligations of GMA as facility lessee under the eleven facility lease agreements, each dated as of December 19, 2000, and under the related participation agreements and other documents executed in connection therewith, in each case as amended, modified or supplemented from time to time.

14

“GMGEN”: GenOn Americas Generation, LLC, a Delaware limited liability company.
“Governmental Authority”: any nation or government, any state or other political subdivision thereof, any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative functions of or pertaining to government, any securities exchange and any self-regulatory organization (including the National Association of Insurance Commissioners).
“Group Members”: the collective reference to the Company and the Restricted Subsidiaries.
“Guarantee”: a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Debt (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services, to take or pay or to maintain financial statement conditions or otherwise). The term “Guarantee” as a verb has a corresponding meaning.
“Guarantee Agreement”: the Guarantee Agreement dated as of the date hereof executed and delivered by the Subsidiary Guarantors in favor of the Administrative Agent, as amended, restated, amended and restated, supplemented or otherwise modified from time to time.
“Hedging Agreement”: any agreement or arrangement referred to in the definition of “Hedging Obligations” entered into between any Loan Party and any Hedging Counterparty.
“Hedging Counterparties”: with respect to any Hedging Agreement, any Specified Hedging Counterparty or Non-Specified Hedging Counterparty thereunder.
“Hedging Obligations”: with respect to any Loan Party, the net obligations of such Person under: (a) interest rate swap agreements (whether from fixed to floating or from floating to fixed), interest rate cap agreements and interest rate collar agreements; (b) other agreements or arrangements designed to manage interest rate risk; and (c) other agreements or arrangements designed to protect such Person against fluctuations in currency exchange rates.
“Joinder to Security Agreement”: as defined in Section 5.1(a).
“Indemnified Liabilities”: as defined in Section 11.5(a).
“Indemnitee”: as defined in Section 11.5(a).
“Interest Payment Date”: (a) as to any ABR Loan, the last day of each March, June, September and December to occur while such Loan is outstanding and the final maturity date of such Loan, (b) as to any Eurodollar Loan having an Interest Period of three months or less, the last day of such Interest Period, (c) as to any Eurodollar Loan having an Interest Period longer than three months, each day that is three months, or a whole multiple thereof, after the first day of such Interest Period and the last day of such Interest Period and (d) as to any Loan (other than any Loan that is an ABR Loan), the date of any repayment or prepayment made in respect thereof.

15

“Interest Period”: as to any Eurodollar Loan, (a) initially, the period commencing on the borrowing or conversion date, as the case may be, with respect to such Eurodollar Loan and ending one, two, three or six months thereafter (or such other period as the Company and all Lenders may agree), as selected by the Company in its notice of borrowing or notice of conversion, as the case may be, given with respect thereto; and (b) thereafter, each period commencing on the last day of the next preceding Interest Period applicable to such Eurodollar Loan and ending one, two, three or six months (or such other period as the Company and all Lenders may agree) thereafter, as selected by the Company by irrevocable notice to the Administrative Agent not later than 11:00 A.M., New York City time, on the date that is three Business Days prior to the last day of the then current Interest Period with respect thereto; provided  that, all of the foregoing provisions relating to Interest Periods are subject to the following:
 	 	
(i)	if any Interest Period would otherwise end on a day that is not a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless the result of such extension would be to carry such Interest Period into another calendar month in which event such Interest Period shall end on the immediately preceding Business Day;	
 	 	
(ii)	the Borrowers may not select an Interest Period that would extend beyond the Termination Date; and	
(iii) any Interest Period that begins on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period) shall end on the last Business Day of a calendar month.
“Investments”: as defined in Section 8.6.
“Issuing Bank”: with respect to (a) the Existing Letters of Credit, JPMorgan Chase Bank, N.A., Deutsche Bank AG New York Branch or any of their Affiliates and (b) each Letter of Credit issued on or after the date hereof, each of Bank of America, N.A., Citibank, N.A., Deutsche Bank, AG New York, Morgan Stanley Bank, and each of their Affiliates, in each case, as long as qualifying as “Issuing Banks” pursuant to the NRG Credit Agreement, and any Lender, any other financial institution from time to time designated by the Company as an Issuing Bank with the consent of the Administrative Agent, and/or any Affiliate, in each case, in its capacity as issuer of any Letter of Credit; collectively, the “ Issuing Banks ”.
“L/C Assignment and Assumption Agreements”: that certain (a) Assignment and Assumption Agreement dated on or about the date hereof by and among the Borrowers, NRG and JPMorgan Chase Bank, N.A. and (b) Assignment and Assumption Agreement dated on or about the date hereof by and among the Borrowers, NRG and Deutsche Bank AG New York Branch.
“L/C Commitment”: at any time, the aggregate amount of the Commitments then in effect.
“L/C Obligations”: at any time, an amount equal to the sum of (a) the aggregate then undrawn and unexpired amount of the then outstanding Letters of Credit pursuant to  Section 3  herein and (b) the aggregate amount of drawings under Letters of Credit that have not then been reimbursed pursuant to  Section 3.5 .
“L/C Participants”: as to any Letter of Credit, the collective reference to all the Lenders other than the Lender that caused an Issuing Bank to issue such Letter of Credit.
“Lenders”: as defined in the Preamble hereto.
“Letters of Credit”: any letter of credit issued pursuant to this Agreement. As of the Closing Date, each Existing Letter of Credit shall be deemed to be a Letter of Credit hereunder as though issued hereunder on the Closing Date and the Company shall be the account party thereunder.

16

“Lien”: any mortgage, pledge, lien, hypothecation, security interest or other charge, encumbrance or other arrangement in the nature of a security interest in property;  provided , however , that the term “Lien” shall not mean any easements, survey exceptions, reservations (including those for, rights-of-way, sewers, electric lines, telegraph and telephone lines, other utilities, mineral reservations and rights), zoning restrictions, encroachments, minor title deficiencies, leases, subleases, licenses, sublicenses, or other restrictions on the use of property or other similar encumbrances.
“Loan”: any loan made by any Lender pursuant to Section 2.4(a) of this Agreement, including, without limitation, the loans made on the Closing Date.
“Loan Documents”: this Agreement, the Guarantee Agreement, the Security Documents, the Notes and any amendment, amendment and restatement, waiver, supplement or other modification to any of the foregoing.
“Loan Parties”: the Borrowers and each of the Subsidiary Guarantors.
“Majority Lenders”: at any time, the holders of more than 50% of the Total Commitments then in effect or, if the Commitments have been terminated, the Total Extensions of Credit then outstanding.
“Material Adverse Effect”: a material adverse change in, or material adverse effect on, (i) the financial condition, operations, business or assets of the Company or its Subsidiaries, taken as a whole, which would have a material adverse effect on the ability of the Borrowers to pay amounts owed by it from time to time under the Facilities, or (ii) the validity or enforceability of this Agreement or any of the other Loan Documents against the Company or any Subsidiary Guarantor which would have a material adverse effect on the rights, remedies and benefits available to, or conferred upon, the Administrative Agent or the Lenders, taken as a whole.
“Material Agreement”: a Contractual Obligation to which a Loan Party is a party or affecting a Loan Party or the properties of a Loan Party or its Subsidiaries (y) where such Contractual Obligation is identified in the exhibit list from time to time in filings made by the Company with the SEC as material to the Company or (z) the termination or suspension of which, without its prompt replacement, or the failure of any party thereto to perform its obligations thereunder, without prompt cure, in each case, would reasonably be expected to have a Material Adverse Effect.
“Merger”: as defined in the Recitals hereto.
“Merger Agreement”: as defined in the Recitals hereto.
“Merger Sub”: as defined in the Recitals hereto.
“Moody's”: Moody's Investors Service, Inc. or any successor thereto.
“Mortgaged Properties”: the real properties listed on Schedule 1.1B and designated as properties for which a Mortgage will be delivered.
“Mortgages”: each of the mortgages and deeds of trust made by any Loan Party in favor of, or for the benefit of, the Collateral Trustee for the benefit of the Secured Parties, in form and substance reasonably satisfactory to the Administrative Agent.
“Multiemployer Plan”: as defined in Section 4001(a)(3) of ERISA.

17

“Net Cash Proceeds”: (a) in connection with any Asset Sale or any Recovery Event, the proceeds thereof in the form of cash and Cash Equivalents (including any such proceeds received by way of deferred payment of principal pursuant to a note or installment receivable or purchase price adjustment receivable or otherwise, but only as and when received), net of attorneys' fees, accountants' fees, investment banking fees, amounts required to be applied to the repayment of Debt secured by a Lien expressly permitted hereunder on any asset that is the subject of such Asset Sale or Recovery Event (other than any Lien pursuant to a Security Document) and other customary fees and expenses actually incurred in connection therewith and net of Taxes paid or reasonably estimated to be payable as a result thereof (after taking into account any available tax credits or deductions and any tax sharing arrangements) and (b) in connection with any issuance or sale of Capital Stock or any incurrence of Debt, the cash proceeds received from such issuance or incurrence, net of attorneys' fees, investment banking fees, accountants' fees, underwriting discounts and commissions and other customary fees and expenses actually incurred in connection therewith.
“Non-Excluded Taxes”: as defined in Section 2.17(a).
“Non-Specified Hedging Counterparty”: with respect to any Hedging Agreement, any counterparty thereto other than a Specified Hedging Counterparty.
“Notes”: the collective reference to any promissory note evidencing Loans.
“NRG”: as defined in the Recitals hereto.
“NRG Credit Agreement”: that certain Amended and Restated Credit Agreement, dated as of July 1, 2011, among NRG, the lenders from time to time party thereto, Citicorp North America, Inc., Bank of America, N.A., Deutsche Bank AG New York Branch, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital, The Investment Banking Division of Barclays Bank PLC, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Goldman Sachs Bank USA, J.P. Morgan Securities LLC, RBS Securities Inc., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and Union Bank, N.A., as amended, amended and restated, refinanced, extended, supplemented or otherwise modified or replaced from time to time.
“NRG Parent Group”: NRG and its Subsidiaries from time to time (other than the Company and its Subsidiaries).
“Obligations”: the unpaid principal of and interest on (including interest accruing after the maturity of the Loans and Reimbursement Obligations and interest accruing after the filing of any petition in bankruptcy, or the commencement of any insolvency, reorganization or like proceeding, relating to either Borrower, whether or not a claim for post-filing or post-petition interest is allowed in such proceeding) the Loans and all other obligations (including guarantee obligations) and liabilities of the Borrowers or any other Loan Party to the Administrative Agent or to any Lender (or, in the case of Hedging Agreements, any Specified Hedging Counterparty), whether direct or indirect, absolute or contingent, due or to become due, or now existing or hereafter incurred, which may arise under, out of, or in connection with, this Agreement, the Guarantee Agreement, any other Loan Document, the Letters of Credit, any Hedging Agreement or any other document made, delivered or given in connection herewith or therewith, whether on account of principal, interest, reimbursement obligations, fees, indemnities, costs, expenses (including all fees, charges and disbursements of counsel to the Administrative Agent or to any Lender that are required to be paid by either Borrower pursuant hereto) or otherwise.
“Other Taxes”: any and all present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies arising from any payment made hereunder or from the execution, delivery or enforcement of, or otherwise with respect to, this Agreement or any other Loan Document, including any interest, additions to tax or penalties applicable thereto.

18

“Participant”: as defined in Section 11.6(c).
“Participant Register”: as defined in Section 11.6(c).
“Patriot Act”: The Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001, as amended.
“Pay-Off”: as defined in the Recitals.
“Permitted Debt”:
(i) (A) the Loans and other obligations of any Loan Party under any Loan Document and (B) Debt of the Borrowers and the Restricted Subsidiaries (which may be secured as to the extent currently secured) existing on the Closing Date and not refinanced with the proceeds of the Debt referred to in clause (v) below;
(ii) up to $800,000,000 of additional Debt;
(iii) [reserved];
(iv) Debt incurred to finance environmental Capital Expenditures and other Capital Expenditures made to comply with law and, additionally, with respect to GMA and its Subsidiaries and REMA and its Subsidiaries, to finance Required Improvements (which may be secured by the capital assets or Required Improvements and related assets) of such Persons;
(v) new senior unsecured notes in an amount not exceeding $1,200,000,000;
(vi) Hedging Obligations consistent with industry practice;
(vii) Debt in respect of workers' compensation claims, self-insurance obligations, bankers' acceptances, performance and surety bonds;
(viii) Debt arising from overdrafts, so long as such Debt is repaid within five Business Days;
(ix) Debt arising from agreements providing for indemnification, adjustment of purchase price or similar obligations incurred in connection with the sales of assets,  provided  that the maximum aggregate liability in respect of all such debt shall not exceed the gross proceeds (including non-cash proceeds) actually received;
(x) Debt of REMA and its Subsidiaries of up to $60,000,000;
(xi) Debt of a Person existing at the time such Person first became a Subsidiary of the Company;  provided  that such Debt was not incurred in contemplation of such acquisition (it being agreed that, in the case of a fluctuating balance facility, the Debt permitted hereunder will include amounts later drawn on unfunded commitments existing at the time such Person first became a Subsidiary of the Company);
(xii) Project Finance Debt;

19

(xiii) Debt between or among the Company and any of its Subsidiaries; provided, that (A) any such Debt of a Loan Party owed to an Unrestricted Subsidiary shall be subordinated to the prior payment in full in cash of the obligations under this Agreement in a customary manner (it being agreed that no blockage of payments will apply except after written notice by the Administrative Agent given while an Event of Default has occurred and is continuing); and (B) (x) any subsequent issuance or transfer of Capital Stock that results, (1) in any such Debt of a Restricted Subsidiary that is not a Subsidiary Guarantor being held by a Person other than the Company or a Restricted Subsidiary or (2) in any such Debt of any Subsidiary Guarantor being held by a Person other than the Company or any Subsidiary and (y) any sale or other transfer of any such Debt (1) of a Restricted Subsidiary that is not a Subsidiary Guarantor to a Person other than the Company or a Restricted Subsidiary or (2) of a Loan Party to a Person other than the Company or any other Subsidiary shall be deemed, in each case, to constitute an incurrence of such Debt by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause;
(xiv) Debt secured by Liens permitted under clauses (f) and (g) of Section 8.3; and
(xv) Debt owing to any entity of the NRG Parent Group;
(xvi) Refinancing, renewals or replacements of Debt permitted under this Agreement (which may be secured by the same assets as the refinanced or renewed Debt);  provided , that any such refinancing, renewal or replacement of Debt (A) is either in an amount not in excess of the principal amount outstanding or committed under the Debt being refinanced, renewed or replaced immediately prior to such refinancing, renewal or replacement (plus, in each case, any applicable fees or expenses and redemption or repurchase premiums or penalties), or such excess amount is otherwise permitted to be incurred under this Agreement without reference to this clause (xvi), (B) provides for a final maturity date no earlier than the existing scheduled maturity date of the Debt being refinanced or renewed and (C) if the Debt refinanced, renewed or replaced is subordinated to the Obligations, is subordinated in a like manner and extent.
“Person”: an individual, company, corporation, firm, partnership, joint venture, undertaking, association, organization, trust, state or agency of a state or limited liability company (in each case whether or not having separate legal personality).
“Plan”: any plan described in Section 3(2) of ERISA that is subject to Title IV of ERISA, maintained or contributed to by the Company or any ERISA Affiliate.
“Proceedings”: as defined in Section 11.5(b).
“Project Finance Debt”: Debt (not exceeding the cost of the acquisition, construction or creation of the relevant asset or project) of the Company or a Restricted Subsidiary incurred or existing in connection with the financing or refinancing of any asset or project, the repayment of which Debt is to be made from the revenues arising out of, or other proceeds of realization from, the acquired or created asset or project, with recourse to those revenues and proceeds and assets forming the subject matter of such asset or project (including, without limitation, insurance, contracts and shares or other rights of ownership in the entity(ies) which own the relevant assets or project) and other assets ancillary thereto but without substantial recourse to any other asset or otherwise to any Person other than the borrower under such Project Finance Debt;  provided  that substantial recourse shall not be deemed to exist by reason of (i) normal and customary sponsor support arrangements, including, without limitation, services and operational and administrative support, (ii) recourse against any Project Subsidiary including any direct or indirect parent entity of any

20

Project Subsidiary, substantially all of the assets of which consist of the equity of one or more Project Subsidiaries, or (iii) recourse against the equity of a Project Subsidiary pledged by the Company or any of the Restricted Subsidiaries to secure the debt of such Project Subsidiary or any Subsidiary of such Project Subsidiary.
“Project Subsidiary”: any Person other than the Company obligated in respect of any Project Finance Debt.
“Recovery Event”: any settlement of or payment in respect of any insurance or indemnity claim or any condemnation proceeding relating to any asset of any Group Member.
“Refinancing”: as defined in the Recitals hereto.
“Register”: as defined in Section 11.6(b).
“Regulation U”: Regulation U of the Board as in effect from time to time.
“Reimbursement Obligation”: the obligation of the Borrowers to reimburse the Administrative Agent or any Lender pursuant to  Section 3.5  for amounts drawn under Letters of Credit.
“Reimbursement Payment”: as defined in Section 2.5(b).
“Reinvestment Event”: any Asset Sale or Recovery Event in respect of which the Company has delivered a Reinvestment Notice.
“Reinvestment Notice”: a written notice executed by a Responsible Officer stating (i) in the case of an Asset Sale only, that no Event of Default has occurred and is continuing and (ii) that the Company (directly or indirectly through a Restricted Subsidiary) intends and expects to use all or a specified portion of the Net Cash Proceeds of an Asset Sale or Recovery Event to acquire or repair assets useful in its business.
“REMA”: GenOn REMA, LLC, a Delaware limited liability company, or any successor thereto.
“REMA Lease”: collectively, the obligations of REMA as facility lessee under the three facility lease agreements, each dated as of August 24, 2000, and under the related participation agreements and other documents executed in connection therewith, in each case as amended, amended and restated, modified or supplemented from time to time.
“Required Improvements”: modifications, alterations, additions or improvements to any GMA or REMA owned or leased project facility required (x) by Requirements of Law or by any Governmental Authority having jurisdiction thereon, (y) by any insurance policy required to be maintained by GMA or REMA, as applicable, under any document related to the GMA Lease or REMA Lease, as applicable, or (z) by the terms of any document related to the GMA Lease or REMA Lease, as applicable.
“Requirement of Law”: as to any Person, any law, treaty, rule or regulation or determination of an arbitrator or a court or other Governmental Authority, in each case applicable to or binding upon such Person or any of its property or to which such Person or any of its property is subject.
“RES”: RRI Energy Services, Inc., a Delaware corporation, or any successor thereto.
“Responsible Officer”: as to each Borrower, the chief executive officer, president, chief financial officer, treasurer, assistant treasurer or controller of such Borrower.
“Restricted Payments”: as defined in Section 8.2.

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“Restricted Subsidiaries”: all Subsidiaries of the Company other than Unrestricted Subsidiaries.
“Returns”: as defined in Section 4.14.
“Revolving Percentage”: as to any Lender at any time, the percentage which such Lender's Commitment then constitutes of the Total Commitments or, at any time after the Commitments shall have expired or terminated, the percentage which the aggregate principal amount of such Lender's Loans then outstanding constitutes of the aggregate principal amount of the Loans then outstanding, provided , that, in the event that the Loans are paid in full prior to the reduction to zero of the Total Extensions of Credit, the Revolving Percentages shall be determined in a manner designed to ensure that the other outstanding Extensions of Credit shall be held by the Lenders on a comparable basis.
“S&P”: Standard & Poor's Ratings Services, a division of the McGraw Hill Companies, Inc., or any successor thereto.
“SEC”: the Securities and Exchange Commission, any successor thereto and any analogous Governmental Authority.
“Secured Parties”: as defined in the Security Agreement.
“Security Agreement”: the Security Agreement dated as of September 20, 2010 executed and delivered by the Borrowers and each Subsidiary Guarantor in favor of Collateral Trustee, as amended, amended and restated, supplemented or otherwise modified from time to time (including, without limitation, pursuant to that certain Joinder to Security Agreement).
“Security Documents”: the collective reference to the Security Agreement, the Collateral Trust Agreement, the Mortgages, any intercreditor agreement in respect of second-lien or subordinated Debt and all other security documents delivered to the Collateral Trustee granting a Lien on any property of any Person to secure the obligations and liabilities of any Loan Party under any Loan Document.
“Specified Hedging Counterparty”: with respect to any Hedging Agreement, any counterparty thereto that, at the time any such Hedging Agreement was entered into, was a Lender or an Affiliate of a Lender.
“Subsidiary”: as to any Person, any corporation, partnership, joint venture, limited liability company, trust or estate of which (or in which) more than 50% of (a) the voting stock, (b) the interest in the capital or profits of such limited liability company, partnership or joint venture or (c) the beneficial interest in such trust or estate is at the time directly or indirectly owned or controlled by such Person, by such Person and one or more of its Subsidiaries or by one or more of such Person's other Subsidiaries. Unless otherwise qualified, all references to a “Subsidiary” or to “Subsidiaries” in this Agreement shall refer to a Subsidiary or Subsidiaries of the Company.
“Subsidiary Guarantor”: each Restricted Subsidiary of the Company other than (a) any Foreign Subsidiary, (b) GEM, (c) GMA, (d) REMA, (e) MC Asset Recovery, LLC, (f) RES and (g) GMGEN (including, with respect to the Persons referred to in clauses (b) through (g), each of their respective Subsidiaries) and (h) each of the entities from time to time designated to Administrative Agent (so long as after the date hereof, such Subsidiary does not acquire any material assets), attached hereto; provided ,  however , that Subsidiaries of GMGEN (other than GEM and GMA and their respective Subsidiaries, which shall not be Subsidiary Guarantors), shall be Subsidiary Guarantors to the extent permitted by Section 102 of that certain Seventh Supplemental Indenture, dated as of January 3, 2006, between GMGEN and Wells Fargo Bank, National Association.

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“Swap Agreement”: any agreement, including any Hedging Agreement, with respect to any swap, forward, future or derivative transaction or option or similar agreement involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions;  provided  that no phantom stock or similar plan providing for payments only on account of services provided by current or former directors, officers, employees or consultants of the Company or any of its Subsidiaries shall be a “Swap Agreement”.
“Synthetic Lease Obligation”: the monetary obligation of a Person under a so-called synthetic, off-balance sheet or tax retention lease.
"Taxes": any present or future taxes, levies, imposts, duties, deductions, withholdings, assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.
“Termination Date”: the third anniversary of the Closing Date.
“Total Commitments”: at any time, the aggregate amount of the Commitments then in effect. The original amount of the Total Commitments is $500,000,000.00.
“Total Extensions of Credit”: at any time, the aggregate amount of the Extensions of Credit of the Lenders outstanding at such time.
“Tranche”: the respective Facility and commitments utilized in making Loans hereunder.
“Transaction”: as defined in the Recitals.
“Transferee”: any Assignee or Participant.
“Type”: as to any Loan, its nature as an ABR Loan or a Eurodollar Loan.
“United States”: the United States of America.
“Unrestricted Subsidiaries”: The entities listed on Schedule 1.1D and any Subsidiary of the Company that is designated by the Company as an Unrestricted Subsidiary, but only to the extent that such Subsidiary (i) has no Debt with substantial recourse to the Company or a Restricted Subsidiary;  provided  that substantial recourse shall not be deemed to exist by reason of normal and customary sponsor support arrangements, including, without limitation, services and operational and administrative support, (ii) except as permitted under  Section 8.7 , is not party to any agreement or contract with the Company or a Restricted Subsidiary unless the terms of such agreement are no less favorable to the Company or such Restricted Subsidiary than those that might be obtained from an unaffiliated third-party, and (iii) is a Person with respect to which neither the Company nor any Restricted Subsidiary has any direct or indirect obligation to make capital contributions or to maintain such Subsidiary's financial condition.
“Weighted Average Life to Maturity”: when applied to any Debt at any date, the number of years obtained by dividing:
(i) the sum of the products obtained by multiplying (A) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Debt, by (B) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by
(ii) the then outstanding principal amount of such Debt.

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“Withholding Agent”: any Loan Party and the Administrative Agent.
1.2 Other Definitional Provisions. (a)  Unless otherwise specified therein, all terms defined in this Agreement shall have the same defined meanings when used in the other Loan Documents or any certificate or other document made or delivered pursuant hereto or thereto.
(b) As used herein and in the other Loan Documents, and any certificate or other document made or delivered pursuant hereto or thereto, accounting terms relating to any Group Member not defined in  Section 1.1  and accounting terms partly defined in  Section 1.1 , to the extent not defined, shall have the respective meanings given to them under GAAP. Unless otherwise specified, all accounting determinations and computations made hereunder shall be made in accordance with GAAP.
(c) As used herein and in the other Loan Documents, and any certificate or other document made or delivered pursuant hereto or thereto, (i) the words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”, (ii) the word “incur” shall be construed to mean incur, create, issue, assume, become liable in respect of or suffer to exist (and the words “incurred” and “incurrence” shall have correlative meanings), (iii) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, Capital Stock, securities, accounts, leasehold interests and contract rights, and (iv) references to agreements or other Contractual Obligations shall, unless otherwise specified, be deemed to refer to such agreements or Contractual Obligations as amended, supplemented, restated or otherwise modified from time to time.
(d) The words “hereof”, “herein” and “hereunder” and words of similar import, when used in this Agreement, shall refer to this Agreement as a whole and not to any particular provision of this Agreement, and Section, Schedule and Exhibit references are to this Agreement unless otherwise specified.
(e) The meanings given to terms defined herein shall be equally applicable to both the singular and plural forms of such terms.
(f) Notwithstanding any other provision contained herein, all computations of amounts and ratios referred to in this Agreement shall be made without giving effect to any election under FASB ASC Topic 825 “Financial Instruments” (or any other financial accounting standard having a similar result or effect) to value any Debt or other liabilities of the Borrowers at “fair value” as defined therein.
SECTION 2. AMOUNT AND TERMS OF COMMITMENTS
2.1 Existing Obligations. Each of the Borrowers hereby acknowledges and confirms that (a) immediately prior to giving effect to this Agreement, the Existing Obligations equaled an aggregate amount of principal and interest of $694,384,379.67, (b) substantially concurrent with giving effect to this Agreement, Borrowers repaid, discharged and satisfied in full the Existing Obligations, and (c) except for indemnities and other contingent obligations not due and payable or for which no claims have been made, no Existing Obligations exist and all underlying commitments have been terminated.
2.2 [Reserved].
2.3 [Reserved].
2.4 Commitments. (a) Subject to the terms and conditions hereof, each Lender severally agrees to make revolving credit loans to each Borrower from time to time during the Commitment Period in an aggregate principal amount at any one time outstanding which, when added to such Lender's Revolving Percentage of the L/C Obligations then outstanding, does not exceed the amount of such Lender's Commitment. During the Commitment Period each Borrower may use the Commitments by borrowing, prepaying the Loans in whole or in part, and reborrowing, all in accordance with the terms and conditions hereof. The Loans may

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from time to time be Eurodollar Loans or ABR Loans, as determined by the Company and notified to the Administrative Agent in accordance with  Sections 2.5  and  2.10 .
(b) The Borrowers shall repay all outstanding Loans on the Termination Date.
2.5. Procedure for Loan Borrowing. (a) The Borrowers may borrow under the Commitments during the Commitment Period on any Business Day, provided the Company shall give the Administrative Agent irrevocable notice (which notice must be received by the Administrative Agent (i) prior to 12:00 Noon, New York City time, five Business Days (or such later time as may be agreed to by Administrative Agent in its sole discretion) prior to the requested Borrowing Date, in the case of Eurodollar Loans, or (ii) prior to 12:00 Noon, New York City time three Business Days (or such later time as may be agreed to by Administrative Agent in its sole discretion) prior to the requested Borrowing Date, in the case of ABR Loans (including for purposes of financing payments required by  Section 3.5 ), specifying (A) the amount and Type of Loans to be borrowed, (B) the requested Borrowing Date, (C) the account to which such Borrowing should be credited or wired, and (D) in the case of Eurodollar Loans, the respective amounts of each such Type of Loan and the respective lengths of the initial Interest Period therefor. Notwithstanding the foregoing, the Borrowers may notify Administrative Agent by telephone or electronic communication of any such request within the time periods set forth herein as long as Borrower thereafter promptly sends written notice containing the information specified in this  Section 2.5 . Any Loans made on the Closing Date shall initially be ABR Loans. Each borrowing under the Commitments shall be in an amount equal to $5,000,000 or a whole multiple of $1,000,000 in excess thereof (or, if the then aggregate Available Commitments are less than $1,000,000, such lesser amount). Upon receipt of any such notice from a Borrower, the Administrative Agent shall promptly notify each Lender thereof. Each Lender will make the amount of its pro rata share of each borrowing available to the Administrative Agent for the account of the Borrowers at the Funding Office prior to 12:00 Noon, New York City time, on the Borrowing Date (or such later time as may be agreed to by Administrative Agent in its sole discretion) requested by the Company in funds immediately available to the Administrative Agent. The Administrative Agent will then make the borrowings available to the Borrowers in accordance with this Section in such amounts as made available to the Administrative Agent by the Lenders and in like funds as received by the Administrative Agent from the Lenders.
(b) In the event that either Borrower fails to reimburse any Lender in accordance with Section 3.5 for the amount of any draft paid by such Lender under any Letter of Credit issued by it, and for all other amounts due in connection therewith pursuant to  Section 3.5  (the “ Reimbursement Payment ”), then on the date that the Reimbursement Payment is due, the Borrowers shall be deemed to have made a request for a borrowing of ABR Loans in an amount equal to the Reimbursement Payment, which deemed request shall not be subject to any condition precedent set forth in  Section 5.2  and shall be irrevocable. Each Lender acknowledges and agrees that its obligation to make its pro rata share of any such borrowing available to the Administrative Agent is absolute and unconditional and shall not be affected by any event, happening or circumstance whatsoever, including the failure of any condition precedent set forth in  Section 5.2  to be satisfied at the time of such deemed request.
2.6 Commitment Fees, etc. The Company agrees to pay to the Administrative Agent for the account of each Lender a commitment fee for the period from and including the Closing Date to the Termination Date, computed at the Commitment Fee Rate on the average daily amount of the Available Commitment of such Lender during the period for which payment is made, payable quarterly in arrears on each Fee Payment Date, commencing on the first such date to occur after the Closing Date..
2.7 Termination or Reduction of Commitments. The Company shall have the right, upon not less than three Business Days'(or such shorter period as may be agreed to by Administrative Agent in its sole discretion) notice to the Administrative Agent, to terminate the Commitments or, from time to time, to reduce the amount of the Commitments;  provided  that no such termination or reduction of Commitments shall be

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permitted if, after giving effect thereto and to any prepayments of the Loans made on the effective date thereof, the Total Extensions of Credit would exceed the Total Commitments. Any such reduction shall be in an amount equal to $1,000,000, or a whole multiple thereof, and shall reduce permanently the Commitments then in effect.
2.8 Optional Prepayments. The Borrowers may at any time and from time to time prepay the Loans, in whole or in part, without premium or penalty, upon irrevocable notice delivered to the Administrative Agent no later than 11:00 A.M., New York City time, one Business Day prior thereto, in the case of Eurodollar Loans (or such shorter time as Administrative Agent accepts in its sole discretion), and no later than 11:00 A.M., New York City time, on the same Business Day, in the case of ABR Loans (or such shorter time as Administrative Agent accepts in its sole discretion), which notice shall specify the date and amount of prepayment and whether the prepayment is of Eurodollar Loans or ABR Loans;  provided , that if a Eurodollar Loan is prepaid on any day other than the last day of the Interest Period applicable thereto, the Borrowers shall also pay any amounts owing pursuant to  Section 2.18 . Upon receipt of any such notice the Administrative Agent shall promptly notify each relevant Lender thereof. If any such notice is given, the amount specified in such notice shall be due and payable on the date specified therein, together with (except in the case of Loans that are ABR Loans) accrued interest to such date on the amount prepaid, unless, in each case, such notice is rescinded in writing. Partial prepayments of Loans shall be in an aggregate principal amount of $1,000,000 or a whole multiple thereof.
2.9 Mandatory Prepayments. (a) (i)  If within ten (10) Business Days of any date the Company or any Restricted Subsidiary shall receive Net Cash Proceeds from any Asset Sale or Recovery Event (other than Excluded Proceeds), then, if the Company shall not have delivered a Reinvestment Notice in respect thereof on or prior to such date, the Company shall apply such Net Cash Proceeds on such date to the prepayment of the Loans as set forth in  Section 2.9(c) . If the Company shall have delivered a Reinvestment Notice in respect thereof, then on the tenth (10 th ) Business Day after the date of receipt of such Net Cash Proceeds, the Borrowers shall apply the portion thereof, if any, that neither the Company nor any Restricted Subsidiary intends to use to acquire or repair assets useful in its business to such prepayment.
(ii) If on or prior to the date falling 365 days after the receipt of Net Cash Proceeds (other than Excluded Proceeds) from a Reinvestment Event, the Company shall not have delivered a Reinvestment Commitment Notice in respect of the Net Cash Proceeds described in clause (i) above not constituting Excluded Proceeds, the Borrowers shall apply such Net Cash Proceeds on such date (to the extent not previously so applied or expended) to the prepayment of the Loans as set forth in  Section 2.9(c) . If on or prior to the date falling 365 days after the receipt of Net Cash Proceeds (other than Excluded Proceeds) from a Reinvestment Event, the Company shall have delivered a Reinvestment Commitment Notice in respect of the Net Cash Proceeds not constituting Excluded Proceeds described in clause (i) above, then (x) on the date of such notice, the Borrowers shall apply (to the extent not previously so applied or expended) the portion, if any, of such Net Cash Proceeds that the Company or any Restricted Subsidiary has not committed in such notice to use to acquire or to repair assets useful in its business to such prepayment and (y) on the date falling 18 months from the date of receipt of such Net Cash Proceeds, the Borrowers shall apply any Net Cash Proceeds not applied to the acquisition or repair of assets useful in its business to such prepayment as set forth in  Section 2.9(c)  (to the extent not previously so applied).
(b) If any Debt shall be issued or incurred by any Loan Party (other than Debt permitted to be issued or incurred under  Section 8.1 ), an amount equal to 100% of the Net Cash Proceeds thereof shall be applied on the date of such issuance or incurrence toward the prepayment of the Loans as set forth in  Section 2.9(c) .
(c) Amounts to be applied in connection with prepayments made pursuant to Section 2.9 shall be applied to the prepayment of the Loans in accordance with  Section 2.15(c) , with a permanent reduction in the Commitments thereof. The application of any prepayment pursuant to  Section 2.9  shall be made,  first ,

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to ABR Loans and, second, to Eurodollar Loans. Each prepayment of the Loans under Section 2.9 shall be accompanied by accrued interest to the date of such prepayment on the amount prepaid.
2.10 Conversion and Continuation Options. (a) The Borrowers may elect from time to time to convert Eurodollar Loans to ABR Loans by the Company giving the Administrative Agent prior irrevocable notice of such election no later than 11:00 A.M., New York City time, on the Business Day (or such later time as may be agreed to by Administrative Agent in its sole discretion) immediately preceding the proposed conversion date,  provided  that any such conversion of Eurodollar Loans may only be made on the last day of an Interest Period with respect thereto. The Company may elect from time to time to convert ABR Loans to Eurodollar Loans by the Company giving the Administrative Agent prior irrevocable notice of such election no later than 11:00 A.M., New York City time, on the third Business Day (or such later time as may be agreed to be Administrative Agent in its sole discretion) immediately preceding the proposed conversion date (which notice shall specify the length of the initial Interest Period therefor),  provided  that no ABR Loan may be converted into a Eurodollar Loan when any Event of Default has occurred and is continuing and the Administrative Agent or the Majority Lenders have determined in its or their sole discretion not to permit such conversions. Upon receipt of any such notice the Administrative Agent shall promptly notify each relevant Lender thereof.
(b) Any Eurodollar Loan may be continued as such upon the expiration of the then current Interest Period with respect thereto by the Company giving irrevocable notice to the Administrative Agent, in accordance with the applicable provisions of the term “Interest Period” set forth in  Section 1.1 , of the length of the next Interest Period to be applicable to such Loans,  provided  that no Eurodollar Loan may be continued as such when any Event of Default has occurred and is continuing and the Administrative Agent has or the Majority Lenders have determined in its or their sole discretion not to permit such continuations, and  provided ,  further , that if the Company shall fail to give any required notice as described above in this paragraph or if such continuation is not permitted pursuant to the preceding proviso such Loans shall be automatically converted to ABR Loans on the last day of such then expiring Interest Period. Upon receipt of any such notice the Administrative Agent shall promptly notify each relevant Lender thereof.
2.11 Limitations on Eurodollar Tranches. Notwithstanding anything to the contrary in this Agreement, all borrowings, conversions and continuations of Eurodollar Loans and all selections of Interest Periods shall be in such amounts and be made pursuant to such elections so that, (a) after giving effect thereto, the aggregate principal amount of the Eurodollar Loans comprising each Eurodollar Tranche shall be equal to $5,000,000 or a whole multiple of $1,000,000 in excess thereof and (b) no more than ten Eurodollar Tranches shall be outstanding at any one time.
2.12 Interest Rates and Payment Dates. (a) Each Eurodollar Loan shall bear interest for each day during each Interest Period with respect thereto at a rate per annum equal to the Eurodollar Rate determined for such day plus the Applicable Margin.
(b)Each ABR Loan shall bear interest at a rate per annum equal to the ABR plus the Applicable Margin.
(c) (i) If (x) all or a portion of the principal amount of any Loan or Reimbursement Obligation shall not be paid when due (whether at the stated maturity, by acceleration or otherwise) or (y) all or a portion of any interest payable on any Loan or Reimbursement Obligation or any commitment fee or other amount payable hereunder shall not be paid when due (whether at the stated maturity, by acceleration or otherwise), such overdue amounts shall bear interest at a rate per annum equal to the rate that would otherwise be applicable thereto under this Agreement  plus  2%, in each case, with respect to sub-clauses (x) and (y) above, from the date of such non‑payment until such amount is paid in full (as well after as before judgment).

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(d) Interest shall be payable in arrears on each Interest Payment Date, provided that interest accruing pursuant to paragraph  (c)  of this Section shall be payable from time to time on demand.
2.13 Computation of Interest and Fees. (a) Interest and fees payable pursuant hereto shall be calculated on the basis of a 360-day year for the actual days elapsed, except that, with respect to ABR Loans the rate of interest on which is calculated on the basis of the Prime Rate, the interest thereon shall be calculated on the basis of a 365- (or 366-, as the case may be) day year for the actual days elapsed. The Administrative Agent shall promptly upon the Company's or any Lender's written request notify the Company and the relevant Lenders of each determination of a Eurodollar Rate. Any change in the interest rate on a Loan resulting from a change in the ABR or the Eurocurrency Reserve Requirements shall become effective as of the opening of business on the day on which such change becomes effective. The Administrative Agent shall promptly upon the Company's or any Lender's written request notify the Company and Lenders of the effective date and the amount of each such change in interest rate.
(b) Each determination of an interest rate by the Administrative Agent pursuant to any provision of this Agreement shall be conclusive and binding on the Borrowers and the Lenders in the absence of manifest error. The Administrative Agent shall, at the request of the Company, deliver to the Company a statement showing the quotations used by the Administrative Agent in determining any interest rate pursuant to  Section 2.12(a) .
2.14 Inability to Determine Interest Rate. If prior to the first day of any Interest Period:
(a) the Administrative Agent shall have determined (which determination shall be conclusive and binding upon the Borrowers) that, by reason of circumstances affecting the relevant market, adequate and reasonable means do not exist for ascertaining the Eurodollar Rate for such Interest Period, or
(b) the Administrative Agent shall have received notice from the Majority Lenders that the Eurodollar Rate determined or to be determined for such Interest Period will not adequately and fairly reflect the cost to such Lenders (as conclusively certified by such Lenders) of making or maintaining their affected Loans during such Interest Period,
the Administrative Agent shall give telecopy or telephonic notice thereof to the Company and Lenders promptly thereafter. If such notice is given (x) any Eurodollar Loans requested to be made on the first day of such Interest Period shall be made as ABR Loans, (y) any Loans that were to have been converted on the first day of such Interest Period to Eurodollar Loans shall be continued as ABR Loans and (z) any outstanding Eurodollar Loans shall be converted, on the last day of the then-current Interest Period, to ABR Loans. Until such notice has been withdrawn by the Administrative Agent, no further Eurodollar Loans shall be made or continued as such, nor shall the Borrowers have the right to convert Loans to Eurodollar Loans.
2.15 Pro Rata Treatment and Payments. (a) Each borrowing by the Borrowers from the Lenders hereunder, each payment by the Company on account of any commitment fee and any reduction of the Commitments of the Lenders shall be made  pro rata  according to the respective Revolving Percentages of the relevant Lenders.
(b) [Reserved].
(c) Each payment (including each prepayment) by the Borrowers on account of principal of and interest on the Loans shall be made  pro rata  according to the respective outstanding principal amounts of the Loans then held by the Lenders.
(d) All payments (including prepayments) to be made by the Borrowers hereunder, whether on account of principal, interest, fees or otherwise, shall be made without setoff or counterclaim and shall be made prior

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to 2:00 p.m., New York City time, on the due date thereof to the Administrative Agent, for the account of the Lenders, at the Funding Office, in Dollars and in immediately available funds. The Administrative Agent shall distribute such payments to the Lenders promptly upon receipt in like funds as received. If any payment hereunder (other than payments on the Eurodollar Loans) becomes due and payable on a day other than a Business Day, such payment shall be extended to the next succeeding Business Day. If any payment on a Eurodollar Loan becomes due and payable on a day other than a Business Day, the maturity thereof shall be extended to the next succeeding Business Day unless the result of such extension would be to extend such payment into another calendar month, in which event such payment shall be made on the immediately preceding Business Day. In the case of any extension of any payment of principal pursuant to the preceding two sentences, interest thereon shall be payable at the then applicable rate during such extension.
(e) Unless the Administrative Agent shall have been notified in writing by any Lender prior to a borrowing that such Lender will not make the amount that would constitute its share of such borrowing available to the Administrative Agent, the Administrative Agent may assume that such Lender is making such amount available to the Administrative Agent, and the Administrative Agent may, in reliance upon such assumption, make available to the relevant Borrower a corresponding amount. If such amount is not made available to the Administrative Agent by the required time on the Borrowing Date therefor, such Lender shall pay to the Administrative Agent, on demand, such amount with interest thereon, at a rate equal to the greater of (i) the Federal Funds Effective Rate and (ii) a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation, for the period until such Lender makes such amount immediately available to the Administrative Agent. A certificate of the Administrative Agent submitted to any Lender with respect to any amounts owing under this paragraph shall be conclusive in the absence of manifest error. If such Lender's share of such borrowing is not made available to the Administrative Agent by such Lender within three Business Days after such Borrowing Date, the Administrative Agent shall also be entitled to recover such amount with interest thereon at the rate per annum applicable to ABR Loans under the relevant Facility, on demand, from the Borrowers.
(f) Unless the Administrative Agent shall have been notified in writing by the Company prior to the date of any payment due to be made by the Borrowers hereunder that the Borrowers will not make such payment to the Administrative Agent, the Administrative Agent may assume that the Borrowers are making such payment, and the Administrative Agent may, but shall not be required to, in reliance upon such assumption, make available to the Lenders their respective  pro rata  shares of a corresponding amount. If such payment is not made to the Administrative Agent by the Borrowers within three Business Days after such due date, the Administrative Agent shall be entitled to recover, on demand, from each Lender to which any amount was made available pursuant to the preceding sentence, such amount with interest thereon at the rate per annum equal to the daily average Federal Funds Effective Rate. Nothing herein shall be deemed to limit the rights of the Administrative Agent or any Lender against the Borrowers.
2.16 Requirements of Law. (a) If the adoption of or any change in any Requirement of Law or in the interpretation or application thereof or compliance by any Lender with any request or directive (whether or not having the force of law) from any central bank or other Governmental Authority made subsequent to the date hereof:
(i)shall change the basis of taxation of payments to such Lender in respect of this Agreement, any Letter of Credit, any Application or any Eurodollar Loan made by it (except for changes in the rate of tax on, or determined by reference to, the overall net income or gross income of such Lender); or
(ii)shall impose, modify or hold applicable any reserve, special deposit, compulsory loan or similar requirement against assets held by, deposits or other liabilities in or for the account of,

29

advances, loans or other extensions of credit by, or any other acquisition of funds by, any office of such Lender that is not otherwise included in the determination of the Eurodollar Rate
and the result of any of the foregoing is to increase the cost to such Lender, of making, converting into, continuing or maintaining Eurodollar Loans or issuing or participating in Letters of Credit, or to reduce any amount receivable hereunder in respect thereof, then, in any such case, the Borrowers shall promptly pay such Lender, upon its demand, any additional amounts necessary to compensate such Lender for such increased cost or reduced amount receivable. If any Lender becomes entitled to claim any additional amounts pursuant to this paragraph, it shall promptly notify the Company (with a copy to the Administrative Agent) of the event by reason of which it has become so entitled.
(b) If any Lender shall have determined that the adoption of or any change in any Requirement of Law regarding capital adequacy or in the interpretation or application thereof or compliance by such Lender or any corporation controlling such Lender with any request or directive regarding capital adequacy (whether or not having the force of law) from any Governmental Authority made subsequent to the date hereof shall have the effect of reducing the rate of return on such Lender's or such corporation's capital as a consequence of its obligations hereunder or under or in respect of any Letter of Credit to a level below that which such Lender or such corporation could have achieved but for such adoption, change or compliance (taking into consideration such Lender's or such corporation's policies with respect to capital adequacy) by an amount deemed by such Lender to be material, then from time to time, after submission by such Lender to the Company (with a copy to the Administrative Agent) of a written request therefor, the Borrowers shall pay to such Lender such additional amount or amounts as will compensate such Lender or such corporation for such reduction.
(c) A certificate as to any additional amounts payable pursuant to this Section submitted by any Lender to the Company (with a copy to the Administrative Agent) shall be conclusive in the absence of manifest error. Notwithstanding anything to the contrary in this Section, the Borrowers shall not be required to compensate a Lender pursuant to this Section for any amounts incurred more than four months prior to the date that such Lender notifies the Company of such Lender's intention to claim compensation therefor; provided  that, if the circumstances giving rise to such claim have a retroactive effect, then such four-month period shall be extended to include the period of such retroactive effect. The obligations of the Borrowers pursuant to this Section shall survive the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.
2.17 Taxes. (a) All payments made by or on account of any Loan Party under this Agreement or any other Loan Document shall be made free and clear of, and without deduction or withholding for or on account of, any present or future income, stamp or other taxes, levies, imposts, duties, charges, fees, deductions or withholdings, now or hereafter imposed, levied, collected, withheld or assessed by any Governmental Authority, excluding any tax imposed on or measured by the net income or net profits or capital (or any franchise or similar tax imposed in lieu thereof) of the Administrative Agent or any Lender as a result of a present or former connection between the Administrative Agent or such Lender or the principal office or applicable lending office of such Lender or any subdivision thereof or therein and the jurisdiction of the Governmental Authority imposing such tax or any political subdivision or taxing authority thereof or therein (other than any such connection arising solely from the Administrative Agent or such Lender having executed, delivered or performed its obligations or received a payment under, or enforced, this Agreement or any other Loan Document);  provided  that, if any such non-excluded taxes, levies, imposts, duties, charges, fees, deductions or withholdings (“ Non-Excluded Taxes ”) or Other Taxes are required to be withheld or deducted from any amounts payable to the Administrative Agent or any Lender hereunder (as determined by the applicable Withholding Agent in good faith), (i) the applicable Withholding Agent shall deduct such amounts and (ii) the amounts so payable by the applicable Loan Party to the Administrative Agent or such Lender

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shall be increased to the extent necessary to yield to the Administrative Agent or such Lender (including any Non-Excluded Taxes and Other Taxes imposed on additional amounts payable pursuant to this Section 2.17(a) ) interest or any such other amounts payable hereunder at the rates or in the amounts specified in this Agreement as if such withholding or deduction had not been made,  provided ,  further , however , that no Loan Party shall be required to increase any such amounts payable to any Lender with respect to any Non-Excluded Taxes that are United States withholding taxes resulting from any Requirement of Law in effect (including FATCA) on (and, in the case of FATCA, including any regulations or official interpretations thereof issued after) the date such Lender becomes a party to this Agreement, except to the extent that such Lender's assignor (if any) was entitled, at the time of assignment, to receive additional amounts from the Loan Party with respect to such Non-Excluded Taxes pursuant to this  Section 2.17(a) .
(b) In addition, the Borrowers shall pay, or at the option of the Administrative Agent timely reimburse it for the payment of, any Other Taxes to the relevant Governmental Authority in accordance with applicable law.
(c) Whenever any Non-Excluded Taxes or Other Taxes are payable by a Loan Party, within thirty (30) days (or such longer period of time as agreed to by the Administrative Agent in its sole discretion) thereafter such Loan Party shall send to the Administrative Agent for its own account or for the account of the relevant Lender, as the case may be, a certified copy of a tax receipt received by such Loan Party showing payment thereof or such other document reasonably satisfactory to the Administrative Agent showing payment thereof. If (i) any Non-Excluded Taxes or Other Taxes are imposed directly on the Administrative Agent or any Lender, (ii) a Loan Party fails to pay any Non-Excluded Taxes or Other Taxes when due to the appropriate Governmental Authority or (iii) a Loan Party fails to remit to the Administrative Agent the required receipts or other required documentary evidence, the applicable Loan Party shall indemnify the Administrative Agent and the Lenders upon their written request for such amounts, incremental taxes, interest, penalties and reasonable expenses arising therefrom or with respect thereto that may become payable by the Administrative Agent or any Lender as a result of any such failure in the case of (ii) or (iii), or any such direct imposition in the case of (i).
(d) Each Lender shall severally indemnify the Administrative Agent for any Taxes (but in the case of Non-Excluded Taxes, only to the extent that the Borrowers have not already indemnified the Administrative Agent for any such Non-Excluded Taxes and without limiting the obligation of the Borrowers to do so) attributable to such Lender that are paid or payable by the Administrative Agent in connection with this Agreement and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. The indemnity under this  Section 2.17(d)  shall be paid within 10 days after the Administrative Agent delivers to the applicable Lender a certificate stating the amount of Taxes so paid or payable by the Administrative Agent. Such certificate shall be conclusive of the amount so paid or payable absent manifest error.
(e) [Reserved].
(f) [Reserved].
(g) [Reserved].
(h) The agreements in this Section shall survive the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.
2.18 Indemnity. Each Borrower agrees, jointly and severally, to indemnify each Lender for, and to hold each Lender harmless from, any actual and documented loss or expense determined in accordance with this  Section 2.18  that such Lender may sustain or incur as a consequence of (a) default by either Borrower in making a borrowing of, conversion into or continuation of Eurodollar Loans after the Company has given

31

a notice requesting the same in accordance with the provisions of this Agreement, (b) default by either Borrower in making any prepayment of or conversion from Eurodollar Loans after the Company has given a notice thereof in accordance with the provisions of this Agreement or (c) the making of a prepayment of Eurodollar Loans on a day that is not the last day of an Interest Period with respect thereto. Such indemnification may include an amount equal to the excess, if any, of (i) the amount of interest that would have accrued on the amount so prepaid, or not so borrowed, converted or continued, for the period from the date of such prepayment or of such failure to borrow, convert or continue to the last day of such Interest Period (or, in the case of a failure to borrow, convert or continue, the Interest Period that would have commenced on the date of such failure) in each case at the applicable rate of interest for such Loans provided for herein (excluding, however, the Applicable Margin included therein, if any)  over  (ii) the amount of interest (as reasonably determined by such Lender) that would have accrued to such Lender on such amount by placing such amount on deposit for a comparable period with leading banks in the interbank eurodollar market. A certificate as to any amounts payable pursuant to this Section submitted to the Company by any Lender shall be conclusive in the absence of manifest error. Notwithstanding anything to the contrary in this Section, neither Borrower shall be required to compensate a Lender pursuant to this Section for any loss or expense resulting from any event set forth in clauses (a), (b) or (c) of the first sentence of this Section if such event occurred more than sixty (60) days prior to any demand for indemnification by such Lender. This covenant shall survive the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.
2.19 Joint and Several Liability. The Borrowers shall be jointly and severally liable for the Obligations.
SECTION 3. LETTERS OF CREDIT
3.1 L/C Commitment. (a) Subject to the terms and conditions hereof, each Lender, in reliance on the agreements of the other Lenders set forth in  Section 3.4(a) , agrees to cause one or more of the Issuing Banks to issue Letters of Credit for the account of one or more of the Borrowers on any Business Day during the Commitment Period in such form as may be approved from time to time by such Lender and such Issuing Bank;  provided  that any Lender is entitled to conclusively rely on advice from the Administrative Agent that causing the Issuing Bank to issue the Letters of Credit is permitted under the Agreement without further inquiry; and  provided ,  further , that no Lender shall have any obligation to cause any Issuing Bank to issue any Letter of Credit if, after giving effect to such issuance, (i) the L/C Obligations would exceed the L/C Commitment, (ii) the aggregate amount of the Available Commitments would be less than zero or (iii) the L/C Obligations with respect to all Letters of Credit issued on behalf of such Lender by any Issuing Bank would exceed such Lender's Commitment. Each Letter of Credit shall (i) be denominated in Dollars and payable on an “at sight” basis and (ii) expire no later than the earlier of (x) the first anniversary of its date of issuance and (y) the date that is five Business Days prior to the Termination Date;  provided ,  however , that any Letter of Credit, whether newly requested or an existing Letter of Credit that is extended or automatically renewed, may have an expiration date up to 90 days after the Termination Date so long as the Borrowers cash collateralize such Letter of Credit for the benefit of the applicable Lender or for the benefit of the Issuing Bank (as determined by such Lender in its sole discretion) on or prior to the date which is five Business Days prior to the Termination Date and the relevant Lender shall have agreed in its sole discretion to cause an Issuing Bank to provide such Letter of Credit (and an Issuing Bank shall have so agreed in its sole discretion) at the time such Letter of Credit or extension is requested or at the time such existing Letter of Credit is to be automatically renewed, as applicable;  provided ,  further , that any Letter of Credit with a one-year term may provide for the automatic renewal thereof for additional one-year periods (which shall only extend beyond the date referred to in clause (y) above if the condition described in the first proviso of this sentence is satisfied). In the event of any inconsistency between the terms and conditions of this Agreement and the terms and conditions of any form of Application or other agreement submitted by the Company to, or entered

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into by the Company with, the Lender relating to any Letter of Credit, the terms and conditions of this Agreement shall control.
(b) No Lender shall at any time be obligated to cause any Issuing Bank to issue any Letter of Credit if such issuance would conflict with, or cause such Lender, any L/C Participant or any Issuing Bank to exceed any limits imposed by, any applicable Requirement of Law.
3.2 Procedure for Issuance of Letters of Credit. The Company may from time to time request that the relevant Lender cause an Issuing Bank to issue a Letter of Credit by delivering to such Lender at its address for notices specified herein an Application therefor. Upon receipt of a duly completed and executed Application and any certificates, documents and other papers and information (referred to herein or in the Application) delivered to the Lender in connection therewith, the relevant Lender shall (and shall cause the applicable Issuing Bank to) process such Application in accordance with their respective customary procedures and cause the applicable Issuing Bank to promptly issue the Letter of Credit requested thereby (but in no event shall any Lender be required to cause an Issuing Bank to issue any Letter of Credit earlier than three (3) Business Days (or such shorter period as such Lender may agree in its sole discretion) after its receipt of the duly completed and executed Application therefor and all such other certificates, documents and other papers and information referred to herein and therein and relating thereto) by issuing the original of such Letter of Credit to the beneficiary thereof or as otherwise may be agreed to by such Lender and the Company. Such Lender shall furnish a copy of such Letter of Credit to the Borrowers promptly following the issuance thereof. Each Lender shall promptly furnish to the Administrative Agent, which shall in turn promptly furnish to the Lenders, notice of the issuance of each Letter of Credit (including the amount thereof).
3.3 L/C Fees and Other Charges. (a) The Borrowers shall pay a fee on all the average daily aggregate maximum amount available to be drawn under all outstanding Letters of Credit at a per annum rate equal to the Applicable Margin then in effect with respect to Eurodollar Loans shared ratably among the Lenders and payable quarterly in arrears on each Fee Payment Date after the issuance date. In addition, the Borrowers shall pay to each Lender for its own account a fronting fee in an amount to be agreed by the Company and the relevant Lender not to exceed 0.125% per annum on the stated amount of each Letter of Credit caused to be issued by such Lender, payable quarterly in arrears on each Fee Payment Date after the issuance date;  provided  that such fronting fee shall be at least $100 per quarter for each Letter of Credit.
(b) In addition to the foregoing fees, the Borrowers shall pay or reimburse the Lender for such normal and customary costs and expenses as are incurred or charged by such Lender (or incurred or charged by any Issuing Bank and charged to Lender) in issuing, negotiating, effecting payment under, amending or otherwise administering any Letter of Credit.
3.4 L/C Participations. (a) Each Lender irrevocably agrees to grant and hereby grants to each L/C Participant, and, to induce such Lender to cause an Issuing Bank to issue Letters of Credit, each L/C Participant irrevocably agrees to accept and purchase and hereby accepts and purchases from such Lender, on the terms and conditions set forth below, for such L/C Participant's own account and risk an undivided interest equal to such L/C Participant's Revolving Percentage in such Lender's obligations and rights under and in respect of each Letter of Credit caused to be issued by such Lender and the amount of each draft paid by such Lender thereunder. Each L/C Participant agrees with each Lender that, if a draft is paid under any Letter of Credit caused to be issued by such Lender for which such Lender is not reimbursed in full by the Borrowers in accordance with the terms of this Agreement, the Administrative Agent (acting at the direction of the relevant Lender) shall make a demand on such L/C Participant to pay to such Lender upon demand at such Lender's address for notices specified herein an amount equal to such L/C Participant's Revolving Percentage of the amount of such draft, or any part thereof, that is not so reimbursed. Each L/C Participant's obligation to pay such amount shall be absolute and unconditional and shall not be affected by any circumstance, including (i) any setoff, counterclaim, recoupment, defense or other right that such L/C Participant may have against

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any Lender, either Borrower or any other Person for any reason whatsoever, (ii) the occurrence or continuance of a Default or an Event of Default or the failure to satisfy any of the other conditions specified in  Section 5 , (iii) any adverse change in the condition (financial or otherwise) of either Borrower, (iv) any breach of this Agreement or any other Loan Document by either Borrower, any other Loan Party or any other L/C Participant or (v) any other circumstance, happening or event whatsoever, whether or not similar to any of the foregoing.
(b) If any amount required to be paid by any L/C Participant to any Lender pursuant to Section 3.4(a)  in respect of any unreimbursed portion of any payment made by such Lender under any Letter of Credit is paid to such Lender within three Business Days after the date such payment is due, such L/C Participant shall pay to such Lender on demand an amount equal to the product of (i) such amount, times (ii) the daily average Federal Funds Effective Rate during the period from and including the date such payment is required to the date on which such payment is immediately available to such Lender, times (iii) a fraction the numerator of which is the number of days that elapse during such period and the denominator of which is 360. If any such amount required to be paid by any L/C Participant pursuant to  Section 3.4(a)  is not made available to the relevant Lender by such L/C Participant within three Business Days after the date such payment is due, such Lender shall be entitled to recover from such L/C Participant, on demand, such amount with interest thereon calculated from such due date at the rate per annum applicable to ABR Loans under the Facility. A certificate of the relevant Lender submitted to any L/C Participant with respect to any amounts owing under this Section shall be conclusive in the absence of manifest error.
(c) Whenever, at any time after any Lender has made payment under any Letter of Credit and has received from any L/C Participant its  pro rata  share of such payment in accordance with  Section 3.4(a) , such Lender receives any payment related to such Letter of Credit (whether directly from a Borrower or otherwise, including proceeds of collateral applied thereto by such Lender), or any payment of interest on account thereof, such Lender will distribute to such L/C Participant its  pro rata  share thereof;  provided , however , that in the event that any such payment received by such Lender shall be required to be returned by such Lender, such L/C Participant shall return to such Lender the portion thereof previously distributed by such Lender to it.
3.5 L/C Reimbursement Obligation of the Borrowers. If any draft is paid under any Letter of Credit, the Borrowers shall reimburse the Lender for the amount of (a) the draft so paid and (b) any Taxes, fees, charges or other costs or expenses incurred by such Lender (or incurred by Issuing Bank and charged to such Lender) in connection with such payment, not later than 12:00 Noon, New York City time, on the Business Day that the Company receives notice of such draft. Each such payment shall be made to the relevant Lender at its address for notices referred to herein in Dollars and in immediately available funds. Interest shall be payable on any such amounts from the date on which the relevant draft is paid until payment in full at the rate set forth in (x) until the Business Day next succeeding the date of the relevant notice,  Section 2.12(b)  and (y) thereafter,  Section 2.12(c) . If the Borrowers fail to reimburse any Lender in accordance with this  Section 3.5 , the Borrowers shall be deemed to have made a request for a borrowing of ABR Loans pursuant to  Section 2.5(b)  as provided in such Section.
3.6 Obligations Absolute. The Borrowers' obligations under this Section 3 shall be absolute, unconditional and irrevocable under any and all circumstances and irrespective of any setoff, counterclaim or defense to payment that either Borrower may have or have had against any Lender, any beneficiary of a Letter of Credit or any other Person. Each Borrower also agrees with each Lender that such Lender shall not be responsible for, and the Borrowers' Reimbursement Obligations under  Section 3.5  shall not be affected by, among other things, the validity, genuineness or enforceability of drafts, documents, Letters of Credit or this Agreement, or any term or provision therein or of any endorsements thereon, even though such drafts or documents shall in fact prove to be invalid, fraudulent or forged in any respect or any statement therein

34

being untrue or inaccurate in any respect, any dispute between or among either Borrower and any beneficiary of any Letter of Credit or any other party to which such Letter of Credit may be transferred or any claims whatsoever of either Borrower against any beneficiary of such Letter of Credit or any such transferee or any other event or circumstance whatsoever, whether or not similar to any of the foregoing, that might, but for the provisions of this Section, constitute a legal or equitable discharge of, or provide a right of setoff against, any Borrowers' obligations hereunder. No Lender shall be liable for any error, omission, interruption or delay in transmission, dispatch or delivery of any message or advice, however transmitted, in connection with any Letter of Credit, except for errors or omissions found by a final and nonappealable decision of a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of such Lender. Each Borrower agrees that any action taken or omitted by any Lender under or in connection with any Letter of Credit or the related drafts or documents, if done in the absence of gross negligence or willful misconduct, shall be binding on the Borrowers and shall not result in any liability of such Lender to the Borrowers.
3.7 Letter of Credit Payments. If any draft shall be presented for payment under any Letter of Credit, the Lender that caused such Letter of Credit to be issued shall promptly upon receiving notice from the applicable Issuing Bank notify the Company of the date and amount thereof. The responsibility of each Lender to the Borrowers in connection with any draft presented for payment under any Letter of Credit shall, in addition to any payment obligation expressly provided for in such Letter of Credit, be limited to causing the applicable Issuing Bank to determine that the documents (including each draft) delivered under such Letter of Credit in connection with such presentment are substantially in conformity with such Letter of Credit.
3.8 Applications. To the extent that any provision of any Application related to any Letter of Credit is inconsistent with the relevant provisions of this  Section 3 , the provisions of this  Section 3  shall apply.
3.9 Existing Letters of Credit. On the Closing Date, each Existing Letter of Credit shall, automatically and without further action, as between Borrower and the Lender, be deemed to be a Letter of Credit that has been issued hereunder as of the Closing Date for all purposes hereunder and under the other Loan Documents. Without limiting the foregoing, (i) each such Existing Letter of Credit shall be included in the calculation of L/C Obligations, (ii) all liabilities of the Borrowers and the other Loan Parties with respect to such Existing Letters of Credit shall constitute Obligations and shall be secured by a First Lien (as such term is defined in the Collateral Trust Agreement) in all of the Collateral (as such term is defined in the Collateral Trust Agreement), and (iii) each Lender shall have reimbursement obligations with respect to such Existing Letters of Credit as provided in  Section 3.4 .
SECTION 4. REPRESENTATIONS AND WARRANTIES
To induce the Administrative Agent and the Lenders to enter into this Agreement and to make the Loans and issue or participate in the Letters of Credit, each of the Company and GAI hereby represents and warrants to the Administrative Agent and each Lender that:
4.1 Organization; Power and Authority. The Company and each Restricted Subsidiary (a) is duly organized, validly existing and in good standing under the laws of the state of its organization and (b) has all requisite corporate, limited partnership or limited liability company power and authority to own its assets and to carry on its business as now conducted and as proposed to be conducted and is qualified to do business, and is in good standing in every jurisdiction where such qualification is required, except where the failure to have such power and authority and so to qualify would not reasonably be expected to result in a Material Adverse Effect. Each Loan Party has the corporate, limited partnership or limited liability company power to execute, deliver and perform its obligations under each Loan Document to which it is a party, and each

35

Loan Party has the corporate, limited partnership or limited liability company power to take all action necessary to consummate the transactions contemplated by the Loan Documents to which it is a party.
4.2 Due Authorization. The execution, delivery and performance by each Loan Party of the Loan Documents to which it is a party has been duly authorized by all necessary corporate, limited partnership or limited liability company action, as applicable. The Loan Documents have been duly executed and delivered by each Loan Party party thereto.
4.3 Governmental Approval. Except as would not reasonably be expected to have a Material Adverse Effect, no authorization or approval or other action by, and no notice to or filing with, any Governmental Authority is required for the due execution, delivery and performance by any Loan Party of any Loan Document to which it is a party or the conduct by any Loan Party of its business as conducted on the date such representation is made or deemed made, except, in any such case, for those which have been duly obtained or made and are in full force and effect.
4.4 Binding and Enforceable. This Agreement constitutes, and each other Loan Document upon execution will constitute, a legal, valid and binding obligation of each Loan Party party thereto, enforceable against each such Loan Party in accordance with its terms subject to applicable bankruptcy, insolvency, fraudulent conveyance, moratorium, reorganization or similar laws affecting the enforcement of creditors' rights generally and to general principles of equity.
4.5 No Violation. The execution, delivery and performance by any Loan Party of this Agreement and the other Loan Documents to which it is a party, the borrowings hereunder and the use of the proceeds thereof does not violate (i) its organizational documents or (ii) any Material Agreement, in any manner which has had or would reasonably be expected to have a Material Adverse Effect.
4.6 No Default. No Default or Event of Default has occurred and is continuing, other than any Default or Event of Default which has been waived pursuant to  Section 11.1 . As of the Closing Date, no Loan Party is in default in any material respect under or with respect to any Material Agreement binding on it that would reasonably be expected to have a Material Adverse Effect.
4.7 Litigation. No litigation, arbitration or administrative proceeding is currently pending or, to such Borrower's knowledge, threatened against it or any Restricted Subsidiary (i) to restrain the entry by any Loan Party into, the enforcement of or exercise of any rights by the Lenders or the Administrative Agent under, or the performance or compliance by any Loan Party with any obligations under, the Loan Documents to which it is a party or (ii) which has had or would reasonably be expected to have a Material Adverse Effect.
4.8 [Reserved].
4.9 Material Adverse Change. Since December 31, 2011, there has been no Material Adverse Effect.
4.10 Investment Company Act. No Loan Party is an “investment company” required to be registered as such under the Investment Company Act of 1940, as amended.
4.11 Environmental Matters. There has been no matter with respect to environmental compliance which has had or would reasonably be expected to have a Material Adverse Effect.
4.12 Accuracy of Information, etc. No written information, report, financial statement, exhibit or schedule furnished by or on behalf of the Borrowers or any Restricted Subsidiary to Administrative Agent or any Lender for use in connection with the Refinancing or the other transactions contemplated by the Loan Documents or in connection with the negotiation of any Loan Document or included therein or delivered pursuant thereto contained, contains or will, when furnished, contain any material misstatement of fact or omitted, omits or will, when furnished, omit to state any material fact necessary to make the statements

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therein, in the light of the circumstances under which they were, are or will be made, not misleading; provided  that to the extent any such written information, report, financial statement, exhibit or schedule is based upon or constitutes a forecast or projection (including pro forma financial statements) or is information of a general economic or industry nature, the Borrowers represent only that they acted in good faith and upon assumptions believed to be reasonable at the time made and at the time such information, report, financial statement, exhibit or schedule is made available to Administrative Agent or any Lender (it being understood that (i) projections and forecasts are subject to significant uncertainties and contingencies, many of which are beyond the control of the Borrowers and their Restricted Subsidiaries, (ii) no assurance can be given that such projections or forecasts will be realized, and (iii) actual results may differ and such differences may be material)..
4.13 Employee Benefit Plans. Each Plan is in compliance in all material respects with the applicable provisions of ERISA and the Code and the regulations and published interpretations thereunder, except as would not reasonably be expected to result in a Material Adverse Effect. No ERISA Event has occurred that, when taken together with all other such ERISA Events, would reasonably be expected to result in a Material Adverse Effect.
4.14 Tax Returns and Payments. Except as would not reasonably be expected to have a Material Adverse Effect, each of the Company and its Restricted Subsidiaries has filed or caused to be filed with the appropriate taxing authority, all tax returns, statements, forms and reports for taxes (the “ Returns ”) that are required to be filed by, or with respect to the income, properties or operations of, the Company and/or any of its Restricted Subsidiaries, and all such Returns are complete and accurate, and have paid or caused to be paid all taxes shown to be due and payable on said Returns (other than those the amount or validity of which is contested in good faith by appropriate proceedings and with respect to which reserves in conformity with GAAP have been provided on the books and records of the relevant entities).
4.15 Security Documents. The provisions of the Security Documents are effective to create a legal, valid and enforceable security interest in all right, title and interest of the Borrowers and each Subsidiary Guarantor in the assets subject thereto subject to no other Liens (except Liens permitted by  Section 8.3 ) which, upon completion of the filings and other actions required by the Loan Documents, will constitute valid perfected security interests in such of the Collateral as to which such perfection is required under the Loan Documents in favor of the Collateral Trustee for the ratable benefit of the Secured Parties.
4.16 Ownership of Property. Except as would not reasonably be expected to have a Material Adverse Effect, such Borrower and each Restricted Subsidiary has good and marketable title to, or a subsisting leasehold interest in or right to use, all material real property necessary for its operations free and clear of all Liens, except as permitted by  Section 8.3 .
SECTION 5. CONDITIONS PRECEDENT
5.1 Conditions to Initial Extension of Credit. The agreement of each Lender to make the initial extension of credit (including, in the case of any Lender, to cause an Issuing Bank to issue any Letters of Credit or to accept assignment of the Existing Letters of Credit pursuant to the L/C Assignment and Assumption Agreement) on the Closing Date is subject to the satisfaction or waiver, prior to or concurrently with the making of such extension of credit or issuance of a Letter of Credit on the Closing Date, of the following conditions precedent:
(a)Credit Agreement; Guarantee Agreement, etc. The Administrative Agent shall have received (i) this Agreement or, in the case of the Lenders, an Addendum, executed and delivered by the Administrative Agent, the Borrowers and each Person listed on Schedule 1.1A, (ii) a Guarantee Agreement, substantially in the form of Exhibit A, executed and delivered by each Subsidiary Guarantor, (iii) a Joinder, Acknowledgement, and Reaffirmation of the Security Agreement,

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substantially in the form of Exhibit B, executed and delivered by the Borrowers, each Subsidiary Guarantor, the Administrative Agent, and Collateral Trustee (“ Joinder to Security Agreement ”), (iv) evidence that the notice required by Section 5.6(b)(2) of the Collateral Trust Agreement, in form and substance reasonably satisfactory to the Administrative Agent, has been executed and delivered by the Company to the Collateral Trustee, and (iv) an Accession Agreement to the Collateral Trust Agreement, substantially in the form of Exhibit C, executed and delivered by the Borrowers, each Subsidiary Guarantor, the Administrative Agent, and Collateral Trustee.
(b)Closing Certificate. The Company shall have executed and delivered to the Administrative Agent a certificate, substantially in the form of Exhibit D, which shall include a customary certification by the chief financial officer as to the solvency of the Company and its Subsidiaries, on a consolidated basis, after giving effect to the Transactions.
(c)Representations and Warranties. Each of the representations and warranties made by any Loan Party in or pursuant to the Loan Documents shall be true and correct in all material respects ( provided that, any representation and warranty that is qualified by “materiality,” “Material Adverse Effect” or similar language shall be true and correct in all respects (after giving effect to any such qualification therein)) on and as of the Closing Date, except to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct in all material respects ( provided  that, any representation and warranty that is qualified by “materiality,” “Material Adverse Effect” or similar language shall be true and correct in all respects (after giving effect to any such qualification therein)) as of such earlier date.
(d)No Default or Event of Default. No Default or Event of Default shall have occurred and be continuing on the Closing Date or would result immediately after giving effect to the Transactions and the extensions of credit requested to be made on the Closing Date and the application of proceeds therefrom.
(e)Transactions. The Transactions shall be consummated substantially concurrent with the initial funding hereunder in accordance in all material respects with applicable law.
(f)Fees. The Lenders and the Administrative Agent shall have received all fees required in accordance with any Loan Document to be paid on or before the Closing Date, and the Administrative Agent shall have received reimbursement for all of its documented out-of-pocket expenses payable by the Company in accordance with this Agreement and billed prior to the Closing Date (it being understood and agreed that any such amounts may be paid with proceeds of Loans made on the Closing Date).
(g)Payment of Debt. All amounts due or outstanding in respect of the Debt outstanding under the Existing Credit Agreement shall have been (or substantially simultaneously with the initial funding hereunder shall be) paid in full and all commitments (if any) in respect thereof terminated.
(h)[Reserved].
(i)Governmental Approvals. Except as would not reasonably be expected to have a Material Adverse Effect, all governmental and third party approvals necessary in connection with the Transaction shall have been obtained and be in full force and effect.
(j)Lien Searches. The Lenders shall have received the results of a recent Lien search in each relevant jurisdiction with respect to the Loan Parties, and such search shall reveal no Liens on any of the assets of the Loan Parties except for Liens permitted by the Loan Documents or Liens to

38

be discharged on or prior to the Closing Date pursuant to documentation reasonably satisfactory to the Administrative Agent.
(k)Filings, Registrations and Recordings. Each document (including, without limitation, any Uniform Commercial Code financing statement) required by the Loan Documents to be filed, registered, recorded or delivered to the Collateral Trustee in order to create in favor of the Collateral Trustee, for the benefit of the Secured Parties, a perfected Lien on the Collateral described therein shall, on or prior to the date hereof, have been filed, registered or recorded or delivered to such Collateral Trustee in proper form for filing, registration or recordation, including, without limitation: (i) if certificated, the certificates representing the Capital Sock pledged pursuant to the Security Documents, together with an undated stock power for each such certificate executed in blank by a duly authorized officer of the pledgor thereof, and (ii) in connection with Collateral consisting of real estate, customary documentation (including Mortgages with respect to the Mortgaged Properties) to the extent reasonably requested by the Administrative Agent, in each case as and to the extent required by the Loan Documents;  provided ,  however , to the extent, after the exercise by the Company of its commercially reasonable efforts without undue burden or expense, any Collateral cannot be granted or perfected on the Closing Date (other than the grant of security interests in, and delivery of items required for perfection with respect to, (i) material assets with respect to which a Lien may be perfected solely by the filing of a financing statement under the Uniform Commercial Code and (ii) Capital Stock issued by any Domestic Subsidiary required to be pledged under the terms of the Security Agreement with respect to which a Lien may be perfected by the delivery of a stock certificate ), then the provision of such Collateral shall not constitute a condition precedent, but may instead be provided after the Closing Date pursuant to arrangements reasonably satisfactory to the Administrative Agent.
(l)[Reserved].
(m)No Material Adverse Effect. Since December 31, 2011, there shall not have occurred any event, development, condition or circumstance that has had a Material Adverse Effect.
5.2 Conditions to Each Extension of Credit. The agreement of each Lender to make any extension of credit and to cause the Issuing Banks to issue Letters of Credit (other than, in each case, continuations or conversions of Interest Periods and the funding of drawings under Letters of Credit) requested to be made by it on any date (including its initial extension of credit) is subject to the satisfaction or waiver of the following conditions precedent:
(a) Representations and Warranties. Each of the representations and warranties made by any Loan Party in or pursuant to the Loan Documents shall be true and correct in all material respects ( provided that, any representation and warranty that is qualified by “materiality,” “Material Adverse Effect” or similar language shall be true and correct in all respects (after giving effect to any such qualification therein)) on and as of such date as if made on and as of such date, except to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct in all material respects ( provided that, any representation and warranty that is qualified by “materiality,” “Material Adverse Effect” or similar language shall be true and correct in all respects (after giving effect to any such qualification therein)) as of such earlier date.
(b) No Default. No Default or Event of Default shall have occurred and be continuing on such date or immediately after giving effect to the extensions of credit requested to be made on such date and the application of proceeds therefrom.

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Each borrowing by and issuance of a Letter of Credit on behalf of a Borrower hereunder shall constitute a representation and warranty by the Borrowers as of the date of such extension of credit that the conditions contained in this  Section 5.2  have been satisfied.
SECTION 6 AFFIRMATIVE COVENANTS
Each Borrower hereby agrees that, from and after the Closing Date and so long as the Commitments remain in effect, any Letter of Credit remains outstanding (if neither (x) cash collateralized in accordance with the terms of this Agreement nor (y) supported with a back-to-back letter of credit reasonably acceptable to the relevant Lender and Issuing Bank) or any Loan is due and owing to any Lender or the Administrative Agent hereunder:
6.1 Compliance with Law; Maintenance of Existence. (a) Each Loan Party and its Subsidiaries shall comply with all Requirements of Law (including Environmental Laws) applicable to such Loan Party and such Subsidiaries in the conduct of their respective businesses except where (x) such requirements are being contested in good faith by appropriate proceedings diligently conducted or (y) the failure to do so would not reasonably be expected to have a Material Adverse Effect; and (b) each Loan Party shall preserve, renew and keep in full force and effect its organizational existence except as otherwise permitted by  Section   8.4 .
6.2 [Reserved].
6.3 Certificates; Other Information. The Company shall furnish to the Administrative Agent:
(a)[reserved]
(b)[reserved]
(c)promptly after the request by any Lender, all documentation and other information that such Lender reasonably requests in order to comply with applicable “know your customer” and anti-money laundering rules and regulations, including the Patriot Act;
(d)as soon as reasonably practicable, such additional financial and other information relating to the then existing financial condition of the Company and the Restricted Subsidiaries as the Administrative Agent may from time to time reasonably request; and
(e) upon reasonable request of the Administrative Agent, the Loan Parties shall, or shall cause any of their ERISA Affiliates, to promptly make a request for documents described in Sections 101(k) or 101(l) of ERISA with respect to any Multiemployer Plan from the applicable administrator or sponsor and the Company shall provide copies of such documents and notices to the Administrative Agent (on behalf of each Lender) promptly after receipt thereof.
6.4 Notices. The Company shall, after a Responsible Officer obtains knowledge thereof (and, in any case, within 10 Business Days of obtaining such knowledge (or such longer period as the Administrative Agent may agree to in its sole discretion)), promptly give notice to the Administrative Agent of:
(a) the occurrence of any Default or Event of Default that is continuing;
(b) the occurrence of any ERISA Event that, alone or together with any other ERISA Event, would reasonably be expected to have a Material Adverse Effect;
(c) any litigation, investigation or proceeding affecting any Loan Party that may exist at any time that would reasonably be expected to have a Material Adverse Effect.

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Each notice pursuant to this Section 6.4 shall be accompanied by a statement of a Responsible Officer setting forth details of the occurrence referred to therein and stating what action the Company proposes to take or cause to be taken with respect thereto.
6.5 Inspection. Each Borrower shall permit the Administrative Agent or any other Lender or any agents or representatives thereof, to examine and make copies of and abstracts from records and books of, and visit the properties of, such Borrower to discuss the affairs, finances and accounts of such Borrower with any of its officers or directors and with its independent certified public accountants (in the presence of such Borrower) from time to time during normal business hours upon reasonable advance notice;  provided that as long as no Default or Event of Default has occurred and is continuing, the Borrowers shall not bear the cost of more than one such examination and visit during any 12-month period. The Administrative Agent and the Lenders agree to coordinate and consolidate their visits (and their agents' and representatives' visits) pursuant to this  Section 6.5  (including the examination of books and records and the making of copies and abstracts of books and records) at mutually convenient times and in such a manner so as to cause minimum disruption to the operations of the Borrower and to minimize costs associated with such visits.
6.6 Maintenance of Property; Insurance. The Company shall, and shall cause each Restricted Subsidiary to (a) keep all material property useful and necessary in its business in good working order and condition, ordinary wear and tear excepted except (x) if in the good faith business judgment of the Company it is in its economic interest not to preserve and maintain such property or (y) the failure to do so would not reasonably be expected to have a Material Adverse Effect and (b) maintain with financially sound and reputable insurance companies (or through prudent self-insurance programs or prudent captive insurance arrangements) insurance on all its property in at least such amounts and against at least such risks as are usually insured against in the same general area by companies engaged in the same or a similar business to the extent available on commercially reasonable terms.
6.7 Subsequent Acquired Property; New Subsidiaries. (a) The Company shall with respect to any material property acquired after the date hereof by the Company or any other Loan Party (other than to the extent (i) the applicable Loan Party is prohibited from granting such Lien by applicable law or any contractual limitation applicable to such Loan Party not incurred in contemplation of such acquisition or (ii) such property constitutes an Excluded Asset (as such term is defined in the Security Agreement) ) as to which the Collateral Trustee, for the benefit of the Secured Parties, does not have a perfected Lien, to the extent required by the Security Agreement, promptly (or on the Closing Date, if acquired before the Closing Date) (i) execute and deliver to the Collateral Trustee (with copies to the Administrative Agent) such amendments to the Security Documents or such other documents as the Administrative Agent reasonably deems necessary or advisable to grant to the Collateral Trustee, for the benefit of the Secured Parties, a security interest in such property and (ii) take all actions necessary or advisable or reasonably requested by the Administrative Agent to grant to the Collateral Trustee, for the benefit of the Secured Parties, a perfected first priority security interest in such property, including, without limitation, the filing of Uniform Commercial Code financing statements in such jurisdictions as may be required by the Security Documents or by law or as may be requested by the Administrative Agent);  provided  that the Company and its Subsidiaries shall not be required to take any action to (A) perfect the security interests in deposit and investment accounts; (B) perfect any security interest in vehicles; (C) perfect any security interest in government contracts or commercial tort claims; (D) perfect any security interests in any Collateral (other than Capital Stock of Subsidiaries that is certificated) by possession; (E) grant or perfect any security interest under any law other than the laws of the United States, any state thereof or the District of Columbia; or (F) take any other steps to perfect security interests where the cost of perfection is not reasonably justified by the practical value of the Collateral (as reasonably agreed to by the Administrative Agent).

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(b) The Company shall, with respect to any fee interest in any real property having a value (together with improvements thereof) of at least $25,000,000 acquired after the date hereof by any Loan Party (other than to the extent the applicable Loan Party is prohibited from granting such Lien by applicable law or any contractual limitation applicable to such Subsidiary Guarantor not incurred in contemplation of such acquisition), promptly (and, in any event, within 120 days of acquisition thereof) (or such later time as the Administrative Agent may agree to in its sole discretion)) (i) execute and deliver a first priority Mortgage in favor of the Collateral Trustee, for the benefit of the Secured Parties, covering such real property and (ii) if reasonably requested by the Administrative Agent, provide the Lenders with title and extended coverage insurance covering such real property in an amount at least equal to the purchase price of such real property (or such other amount as shall be reasonably specified by the Administrative Agent);  provided , that no environmental surveys or assessments will be required in connection with any Mortgages. Administrative Agent agrees to cooperate with the Company to reduce mortgage recording taxes in states with high recording taxes.
(c) If any additional Subsidiary is formed or acquired after the date hereof or any Subsidiary ceases to be an Unrestricted Subsidiary or a Foreign Subsidiary, the Company shall promptly notify the Administrative Agent thereof (and, in any event, within 15 days of the date thereof or such later time as the Administrative Agent may agree to in its sole discretion)). The Company shall with respect to any new Subsidiary (other than a Foreign Subsidiary or a new Subsidiary prohibited from granting such Lien by applicable law or any contractual limitation applicable to such Subsidiary Guarantor at the time it becomes a Subsidiary and not incurred in contemplation thereof) created or acquired directly after the date hereof by any Loan Party (which, for the purposes of this paragraph  (c) , shall be deemed to include (x) any existing Subsidiary that ceases to be a Foreign Subsidiary and (y) any existing Domestic Subsidiary that is no longer an Unrestricted Subsidiary), promptly (and, in any event, within 30 days of the date of creation or acquisition thereof or such later time as the Administrative Agent may agree to in its sole discretion)) (i) execute and deliver to the Collateral Trustee (with copies to the Administrative Agent) such amendments to the Security Agreement as the Administrative Agent reasonably deems necessary or advisable to grant to the Collateral Trustee, for the benefit of the Secured Parties, a perfected first priority security interest in the Capital Stock of such Subsidiary that is owned by any Loan Party ( provided ,  however , that (A) in the case of a Foreign Subsidiary, in no event shall more than 65% of the total outstanding voting Capital Stock of any such new Subsidiary be required to be so pledged and (B) no such grant or perfection of security interests shall be required to be made under any law other than laws of the United States, any state thereof or the District of Columbia), (ii) deliver to the Collateral Trustee (with copies to the Administrative Agent) any certificates representing such Capital Stock, together with undated stock powers, in blank, executed and delivered by a duly authorized officer of the relevant Loan Party, (iii) if such new Subsidiary is a Restricted Subsidiary (other than any new Subsidiary of GMA, GEM, or REMA), cause such new Restricted Subsidiary (A) to execute an Assumption Agreement in the form attached as Annex 1 to the Guarantee Agreement, (B) to take such actions as are required by the Security Agreement to grant to the Collateral Trustee for the benefit of the Secured Parties a perfected first priority security interest in the Collateral described in the Security Agreement with respect to such new Restricted Subsidiary, including the filing of Uniform Commercial Code financing statements in such jurisdictions as may be required by the Security Agreement or by law or as may be reasonably requested by the Administrative Agent and (C) [reserved], and (iv) if such new Subsidiary is a Foreign Subsidiary, subject to the proviso in clause (i) above, cause such new Subsidiary to take such other action as the Administrative Agent may reasonably request necessary or, in the opinion of the Administrative Agent, desirable to perfect the Collateral Trustee's security interest therein.
(d) The Company shall promptly (i) notify the Administrative Agent in writing of the designation of any Subsidiary as an “Unrestricted Subsidiary” and (ii) deliver to the Administrative Agent a certificate signed by a Responsible Officer certifying that such designation complied with the conditions set forth in the definition of “Unrestricted Subsidiary”.

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6.8 Collateral Information. The Company shall, and shall cause each Restricted Subsidiary to, furnish to the Administrative Agent five (5) Business Days (or such shorter period of time as may be agreed to by the Administrative Agent in its sole discretion) prior written notice of any change (i) in any Loan Party's corporate name, (ii) in the jurisdiction of organization or formation of any Loan Party from that referred to in  Section 3.2  of the Security Agreement, or (iii) in any Loan Party's Federal Taxpayer Identification Number.
6.9 Further Assurances. The Company shall, and shall cause each Restricted Subsidiary to, execute any and all further documents, financing statements, agreements and instruments, and take all further action (including filing Uniform Commercial Code and other financing statements, Mortgages and deeds of trust and delivering to the Collateral Trustee (with copies to the Administrative Agent) certificates representing securities pledged under the Security Documents) that may be required under applicable law, or that the Majority Lenders or the Administrative Agent may reasonably request, in order to grant, preserve, protect and perfect the validity and priority of the security interests created or intended to be created by the Security Documents.
6.10 Use of Proceeds. The proceeds of the Loans and the Letters of Credit shall be used for working capital and general corporate purposes (including, without limitation, acquisitions and distributions permitted hereunder). No part of the proceeds of any Loan or other extension of credit under this Agreement, shall be used for any purpose that violates the provisions of the Regulation T, U or X of the Board.
SECTION 7. [RESERVED]
SECTION 8 NEGATIVE COVENANTS
Each of the Company and GAI hereby agrees that, from and after the Closing Date and so long as the Commitments remain in effect, any Letter of Credit remains outstanding (if neither (x) cash collateralized in accordance with the terms of this Agreement nor (y) supported with a back-to-back letter of credit reasonably acceptable to the relevant Lender and Issuing Bank) or any Loan is due and owing to any Lender or the Administrative Agent hereunder:
8.1 Debt. The Borrowers shall not, and shall not permit any Restricted Subsidiary to incur in respect of or suffer to exist any Debt, except Permitted Debt.
8.2 Restricted Payments. The Borrowers shall not, and shall not permit any Restricted Subsidiary, to (i) declare or make any dividend payment or other distribution of assets, properties, cash, rights, obligations or securities on account of any shares of any class of Capital Stock of such Borrower or such Restricted Subsidiary, (ii) make any pre-payments with respect to principal of, or redemption or repurchase of, any Debt that is subordinated to the Obligations, or (iii) purchase, redeem or otherwise acquire for value any shares of any class of Capital Stock of the Company or any Subsidiary of the Company or any warrants, rights or options to acquire any such shares, now or hereafter outstanding, or reduce its capital (collectively, “ Restricted Payments ”);  provided ,  however , that the foregoing shall not prohibit:
(a)the declaration and making of any dividend payment or other distribution by either Borrower or any Restricted Subsidiary payable in Common Stock of such Borrower or such Restricted Subsidiary, as applicable;
(b)with respect to any Restricted Subsidiary, the declaration and making of any dividend payment or other distribution (A) payable to either Borrower or any Restricted Subsidiary ( provided , that, if the payor is a Loan Party, such dividend payment or distribution must be payable to either Borrower or a Subsidiary Guarantor), or (B) where the Borrowers or the Restricted Subsidiary which owns the Capital Stock in the payor receives at least its proportionate share thereof (after giving effect to the relative rights and preferences of the various classes of Capital Stock of such payor);

43

(c)the payment of any dividend or other distribution within 60 days after the date of declaration of the dividend or other distribution, if at the date of declaration the dividend or distribution would have complied with the provisions of this Agreement;
(d)so long as no Default or Event of Default has occurred and is continuing or would be caused thereby, the making of any Restricted Payment in exchange for, or out of the Net Cash Proceeds of, the substantially concurrent sale (other than to a Subsidiary of the Company) of, Capital Stock of the Company (other than Disqualified Stock) or of the substantially concurrent contribution of common equity capital or surplus to the Company;
(e)[reserved];
(f)so long as no Default or Event of Default has occurred and is continuing or would be caused thereby, the repurchase, redemption or other acquisition or retirement for value of any Capital Stock of the Company or any Restricted Subsidiary in connection with any management equity subscription agreement, stock option agreement, shareholders' agreement, severance agreement, employee benefit plan or agreement or similar agreement;
(g)the repurchase of Capital Stock deemed to occur upon the exercise of stock options to the extent such Capital Stock represents a portion of the exercise price of those stock options;
(h)the purchase by the Company of fractional shares upon conversion of any securities of the Company into Capital Stock of the Company;
(i)so long as no Default or Event of Default has occurred and is continuing or would be caused thereby, the declaration and payment of dividends to holders of any class or series of Disqualified Stock;
(j)the issuance of Capital Stock of the Company (other than Disqualified Stock) for other Capital Stock of the Company in connection with any rights offering and payments for the redemption of fractional shares in connection with any rights offering;
(k)dividends, distributions, redemptions, repurchases and prepayments of Capital Stock and Debt as contemplated by the Merger Agreement; and
(l)any Restricted Payments to the NRG Parent Group.
8.3 Liens. The Borrowers shall not, and shall not permit any Restricted Subsidiary to, create or have outstanding any Lien upon any of its property, whether now owned or hereafter acquired, except:
(a)Liens arising solely by operation of law;
(b)Liens in respect of overdue amounts not constituting Debt which either (A) have not been overdue for more than thirty (30) days or (B) are being contested in good faith;
(c)Liens securing (x) up to $500,000,000 of Debt described in clause (ii) of the definition of Permitted Debt, which may be secured on a basis pari passu with the obligations under this Agreement, and (y) Debt described in clauses (iv) or (viii) of the definition of Permitted Debt;
(d)Liens arising out of title retention or like provisions in relation to the acquisition of goods or equipment relating only to such goods or equipment;
(e)Liens on deposits to secure, or any Lien otherwise securing, the performance of bids, contracts (other than for borrowed money or commodity hedging obligations and Hedging

44

Obligations), leases, statutory obligations, surety bonds, appeal bonds, performance bonds, reimbursement or indemnity obligations arising out of surety, performance, or other similar bonds, and other obligations of a like nature;
(f)Liens granted over any asset which is acquired, constructed, created or improved by the Company or a Restricted Subsidiary, but only if (x) such Lien secures only principal amounts (not exceeding the cost of such acquisition, construction or creation) raised for the purposes of such acquisition, construction or creation, together with any costs, expenses, interest and fees incurred in relation thereto or a guarantee given in respect thereof (including amounts constituting Attributable Debt in respect of sale leaseback transactions, Capital Lease Obligations and Synthetic Lease Obligations), (y) such Lien is created or arises on or before ninety (90) days after the completion of such acquisition, construction, creation or improvement ( provided  that in the case of tax exempt financing, such time limitation shall not apply) and (z) such Lien is confined solely to the property so acquired, constructed, created or improved;
(g)Liens (x) outstanding on or over any asset acquired after the Closing Date, (y) in existence at the date of such acquisition but not incurred in contemplation of such acquisition (including, without limitation, existing Liens on the category of the asset acquired which automatically attach upon such acquisition) and (z) where neither the Company nor any Restricted Subsidiary takes any step to increase the principal amount secured thereby from that so secured and outstanding at the time of such acquisition (it being agreed that, in the case of a fluctuating balance facility, the Liens permitted hereunder will include Liens in existence at the time of the acquisition securing amounts later drawn on unfunded commitments existing at the time of acquisition);
(h)Liens on cash and Cash Equivalents (a) deposited by the Company or any of the Restricted Subsidiaries in margin accounts with or on behalf of futures contract brokers or paid over to other counterparties or (b) pledged or deposited as collateral to a contract counterparty or issuer of surety bonds or issuer of letters of credit by the Company or any of the Restricted Subsidiaries, in each case to secure obligations with respect to (x) Commodity Agreements and (y) Hedging Agreements;
(i)Liens on assets of REMA and its Subsidiaries securing Debt of REMA and its Subsidiaries permitted to be incurred pursuant to clause (x) of the definition of Permitted Debt;
(j)Liens in favor of a plaintiff or defendant in any action before a court or tribunal as security for costs or expenses where such action is being prosecuted or defended in the bona fide interest of the Company or any of its Restricted Subsidiaries;
(k)[reserved];
(l)Liens on the property of a Person existing at the time such Person is merged into or consolidated with, or acquired by, the Company or a Restricted Subsidiary and not incurred in contemplation with such merger, consolidation or acquisition (including, without limitation, Liens on a category of assets which may automatically attach to assets in such category acquired after such merger, consolidation or acquisition);
(m)Liens created pursuant to the Security Agreement, including Liens securing Eligible Commodity Hedging Obligations and Hedging Agreements;
(n)pledges or deposits in connection with workers' compensation, unemployment insurance and other social security legislation, or to secure the payment or performance of statutory

45

or public obligations (including environmental, municipal and public utility commission obligations and requirements);
(o)Liens for Taxes not yet delinquent or that are being contested in good faith by appropriate proceedings,  provided  that adequate reserves with respect thereto are maintained on the books and records of the Company or the Restricted Subsidiaries, as the case may be, in conformity with GAAP;
(p)Liens securing Project Finance Debt and Liens on Capital Stock of any Unrestricted Subsidiary;
(q)Liens arising under Section 9.343 of the Texas Uniform Commercial Code or similar statutes of states other than Texas;
(r)[reserved];
(s)Liens to secure any Debt permitted under this Agreement that refinances, extends, renews or replaces any secured Debt;  provided , that: (a) the new Lien shall be limited to all or part of the same categories of property and assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure the original Debt (plus improvements and accessions to, such property or proceeds or distributions thereof); and (b) the Debt secured by the new Lien is not increased to any amount greater than the sum of (i) the outstanding principal amount plus undrawn commitments of the Debt that is refinanced, extended, renewed or replaced (including any fees, interests and expenses capitalized thereon), (ii) an amount necessary to pay any fees and expenses, including premiums, related to such refinancings, extension, renewal or replacement and (iii) any protective advances with respect to the property and assets that secure such Debt;
(t)financing statements (including precautionary statements) filed in connection with a Capital Lease Obligation, financing lease, Synthetic Lease Obligation or an operating lease, in each case, not prohibited hereunder;  provided , that no such financing statement extends to, covers or refers to as collateral, any property or assets of such Borrower or a Restricted Subsidiary, other than the property or assets which are subject to such Capital Lease Obligation, financing lease, Synthetic Lease Obligation, or operating lease;
(u)banker's liens, rights of set off or similar rights, contractual rights of setoff or netting arrangements and similar rights with respect to deposit accounts, commodity accounts and/or securities accounts;
(v)Liens granted in favor of a commercial counterparty or system operator pursuant to a netting agreement or right of setoff, which Liens encumber rights under agreements and tariffs that are subject to such netting agreement or right of setoff and which Liens secure such Person's obligations to such counterparty or system operator under such netting agreement or right of setoff; provided , that such Liens, when granted, do not secure obligations which are past due;
(w)Liens in favor of such Borrower, any other Loan Party or any member of the NRG Parent Group;
(x)Liens on cash deposited, escrowed or entrusted in connection with the defeasance or discharge of any Debt;  provided  that such defeasance or discharge is not otherwise prohibited under this Agreement;

46

(y)Liens on cash and Cash Equivalents not exceeding $150,000,000 in the aggregate pledged or deposited as collateral to an issuer of letters of credit by the Company or any of the Restricted Subsidiaries, in each case to secure obligations with respect to such letters of credit; and
(z)Liens securing Debt or other obligations that do not exceed $50,000,000 in the aggregate at any one time outstanding.
8.4 Mergers. The Borrowers shall not, and shall not permit any Restricted Subsidiary to, merge, consolidate or amalgamate, or liquidate, wind up or dissolve itself (or suffer any liquidation or dissolution), or Dispose of all or substantially all of its assets, except that:
(a) the Merger and all other transactions contemplated by the Merger Agreement shall be permitted;
(b) any Loan Party may merge, consolidate or amalgamate with, or liquidate, wind up, or dissolve itself into, or Dispose of all or substantially all of its assets to, another Loan Party or any Person which, immediately following such transaction, shall be a Loan Party;
(c) any Restricted Subsidiary (other than a Subsidiary Guarantor) may merge, consolidate or amalgamate with, or liquidate, wind up, or dissolve itself into, or Dispose of all or substantially all of its assets to, the Company or any other Restricted Subsidiary; and
(d) Any transaction which does not violate Section 8.5.
8.5 Asset Sales. The Borrowers shall not, and shall not permit any Restricted Subsidiary to, conduct any Asset Sale other than:
(a) asset swaps for Fair Market Value not exceeding $500,000,000; and
(b) the Disposition of assets for Fair Market Value and for which at least 75% of the consideration received (excluding any Debt or liabilities as shown on the most recent consolidated balance sheet of the Company assumed in connection with any such sale or Disposition) is in cash (which, for purposes of this  Section 8.5 , shall include liabilities, securities, notes or other obligations received by such Borrower or any Restricted Subsidiary that are convertible into cash (to the extent are so converted within 180 days after the completion of the Asset Sale), reserves for indemnities and purchase price adjustments, and certain replacement and other capital assets and operating assets received by such Borrower or a Restricted Subsidiary).
8.6 Investments. The Borrowers shall not, and shall not permit any Restricted Subsidiary to, make any advance, loan, extension of credit (by way of Guarantee or otherwise) or capital contribution to, or purchase any Capital Stock, bonds, notes, debentures or other debt securities of, any other Person (all of the foregoing, “ Investments ”), except:
(a) extensions of trade credit in the ordinary course of business;
(b) Investments in cash and Cash Equivalents;
(c) Guarantee Obligations of Debt permitted to be incurred under Section 8.1;
(d) loans and advances to employees of the Company or any Subsidiary in the ordinary course of business (including for travel, entertainment and relocation expenses) up to $10,000,000 in the aggregate at any time outstanding;

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(e) Investments useful in the business of the Company and the Restricted Subsidiaries made by such Borrower or any of the Restricted Subsidiaries with the Net Cash Proceeds of any Recovery Event or Disposition permitted under  Section 8.5 ;
(f) Investments which constitute proceeds of any Disposition permitted under Section 8.5;
(g) Investments by the Company or any Restricted Subsidiary in the Company, a Restricted Subsidiary or MML, including, without limitation, the purchase of any outstanding Debt of any such Person;  provided , that, any such Investment made in a Restricted Subsidiary other than a Subsidiary Guarantor or MML pursuant to this clause (g) shall not take the form of a contribution of power generation assets, or Capital Stock of any Person owning power generation assets;
(h) any acquisition of assets or Capital Stock solely in exchange for the issuance of Capital Stock (other than Disqualified Stock) of the Company;
(i) Investments represented by obligations under Hedging Agreements or Commodity Agreements;
(j) any Investment in a Person, if as a result of such Investment, such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated, dissolved, or wound up into, the Company or a Restricted Subsidiary or will immediately following such Investment be a Restricted Subsidiary;
(k) any Investments received (i) in compromise or resolution of obligations of trade creditors or customers, including (A) obligations of financially troubled account debtors to the extent reasonably expected to prevent or limit loss as determined by the Company in its good faith business judgment and (B) pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer, (ii) in compromise or resolution of litigation, arbitration or other disputes, or (iii) on account of any claim against, or an interest in, any other Person (A) acquired in good faith in connection with or as a result of a bankruptcy, workout, reorganization or recapitalization of such other Person or (B) as a result of a bona fide foreclosure by the Company or any of the Restricted Subsidiaries with respect to any claim against any other Person;
(l) [reserved];
(m) Investments in the form of, or pursuant to, working interests, royalty interests, mineral leases, processing agreements, farm-out agreements, unitization agreements, pooling agreements, area of mutual interest agreements, production sharing agreements or other similar or customary agreements, transactions, properties, interests or arrangements, and Investments and expenditures in connection therewith or pursuant thereto in each case, made or entered into in the ordinary course of business;
(n) [reserved];
(o) payment of consolidated Taxes pursuant to tax allocation agreements among the Company and its Subsidiaries;
(p) Investments consisting of assets contributed to any joint venture in an aggregate amount not to exceed $500,000,000 at any time outstanding;  provided  that promptly and in any event within thirty (30) Business Days after the making of such Investments (or such longer period as may be agreed to by Administrative Agent in its sole discretion), the equity interests in such joint venture held by the Company or any Restricted Subsidiary making such Investment shall be pledged to secure the Obligations of the Loan Parties under the Loan Documents;
(q) [reserved];

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(r) in addition to Investments otherwise expressly permitted by this Section 8.6, Investments by the Company or any of the Restricted Subsidiaries in an aggregate amount (valued at cost) not to exceed $500,000,000 at any time outstanding;
(s) Investments in Foundation or any other Person for charitable purposes in an aggregate amount not to exceed $25,000,000 in the aggregate over the term hereof;
(t) [reserved]; and
(u) Investments in the NRG Parent Group.
8.7 Transactions with Affiliates. The Borrowers shall not, and shall not permit any Restricted Subsidiary to, enter into any transaction, including, without limitation, any purchase, sale, lease or exchange of property, the rendering of any service or the payment of any management, advisory or similar fees, with any Affiliate (other than the Company, any Restricted Subsidiary or any member of the NRG Parent Group) unless such transaction is (i) otherwise permitted under this Agreement or (ii) either (x) upon fair and reasonable terms no less favorable to the Company or such Restricted Subsidiary, as the case may be, than it would obtain in a comparable arm's length transaction with a Person that is not an Affiliate or (y) structured as a commercially reasonable and fair allocation of costs, including corporate overhead costs;  provided , however , that the foregoing shall not prohibit (a) any employment agreement or director's engagement agreement, employee benefit plan, officer and director indemnification agreement or any similar arrangement entered into by the Company or any of the Restricted Subsidiaries in the ordinary course of business or approved by the board of directors of the Company or such Restricted Subsidiary; (b) transactions between or among the Company and/or the Restricted Subsidiaries that are evidenced or contemplated by licensing, servicing or trust agreements in effect on the Closing Date; (c) payment of reasonable directors' fees; (d) any issuance of Capital Stock (other than Disqualified Stock) of the Company to Affiliates of the Company; (e) Restricted Payments permitted under  Section 8.2 ; (f) loans or advances to employees in the ordinary course of business not to exceed $10,000,000 in the aggregate outstanding at any time; (g) any agreement, instrument or arrangement as in effect as of the Closing Date, or any amendment thereto or any transaction contemplated thereby (including pursuant to any amendment thereto) in any replacement agreement thereto so long as any such amendment or replacement agreement is not more disadvantageous to the Lenders in any material respect than the original agreement as in effect on the Closing Date as reasonably determined by the Company; (h) any  pro rata  distribution (including a rights offering) to all holders of a class of Capital Stock or Debt of the Company or any of the Restricted Subsidiaries, including Persons who are Affiliates of the Company or any of the Restricted Subsidiaries and (i) transactions otherwise expressly permitted hereunder.
8.8 Sales and Leasebacks. The Borrowers shall not, and shall not permit any Restricted Subsidiaries to, directly or indirectly lease any property as lessee in connection with a sale and leaseback transaction except to the extent that the sale of the relevant Assets is permitted under  Section 8.5 , if then applicable, and such lease, to the extent treated as Debt, does not violate  Section 8.1  and, to the extent treated as a Lien, does not violate  Section 8.3 .
8.9 Changes in Fiscal Periods. The Company shall not change its fiscal year.
8.10 NRG Credit Agreement. The Borrowers shall not, and shall not permit any Restricted Subsidiary, to (a) become a borrower under the NRG Credit Agreement, (b) guarantee or otherwise directly or indirectly provide credit support for, or with respect to, any of the Obligations (as such term is defined in the NRG Credit Agreement), (c) grant a Lien in any of its property or assets to secure any of the Obligations (as such term is defined in the NRG Credit Agreement), or (d) allow any of the Capital Stock or equity interests issued by it or owned by it to be pledged in favor of the Collateral Trustee (as such term is defined in the NRG Credit Agreement).

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SECTION 9. EVENTS OF DEFAULT
If any of the following events shall occur and be continuing on or after the Closing Date:
(a)either Borrower shall fail to pay any principal of any Loan or Reimbursement Obligation when due in accordance with the terms hereof; or either Borrower shall fail to pay any interest on any Loan or Reimbursement Obligation, or any other amount payable hereunder, within three (3) Business Days after any such interest becomes due in accordance with the terms hereof or five (5) Business Days after any such other amount becomes due in accordance with the terms hereof; or
(b)(i) any Loan Party shall default in the observance or performance of any agreement contained in  Section 8  of this Agreement (other than  Section 8.3 ) or (ii) any Loan Party shall default in the observance or performance of any agreement contained in  Section 8.3 , and, in each case, such default shall continue unremedied for a period of 15 days after written notice to the Company from the Administrative Agent or the Majority Lenders; or
(c)[reserved]; or
(d)any representation or warranty made or deemed made by any Loan Party herein or in any other Loan Document or in any certificate delivered or required to be delivered pursuant hereto or thereto shall prove to have been inaccurate in any material respect on or as of the date made or deemed made and, in the case of any representation or warranty made in any such certificate, such inaccuracy could reasonably be expected to have a Material Adverse Effect; or
(e)any Loan Party shall default in the observance or performance in any material respect of any other agreement contained in this Agreement or any other Loan Document (other than as provided in paragraphs  (a)  through  (d)  of this Section), and such default shall continue unremedied for a period of 30 days after written notice to the Company from the Administrative Agent or the Majority Lenders; or
(f)the Company or any of its material Restricted Subsidiaries shall fail to pay any principal of or premium or interest on any Debt of such entity that is outstanding in a principal or notional amount equal to or in excess of $20,000,000 when the same becomes due and payable (whether by maturity, required prepayment, acceleration, demand or otherwise), and such failure shall continue after the applicable grace period, if any, specified in the agreement or instrument relating to such Debt; or any other event shall occur or condition shall exist under the agreement or instrument relating to any such Debt and shall continue after the applicable grace period, if any, specified in such agreement or instrument, if the effect of such event or condition is to accelerate, or to permit the holders thereof (or a trustee or other representative on their behalf) to accelerate, the maturity of such Debt by reason of default; or
(g)the Company or any of the Restricted Subsidiaries shall fail to pay an amount which is due and not subject to a good faith dispute in excess of $20,000,000 in respect of Eligible Commodity Hedging Obligations secured by pari passu Liens on the Collateral and, as a result of such failure, the counterparty thereunder shall be entitled to and shall have given notice of its intent to exercise any remedies against the Company or any of the Restricted Subsidiaries in respect of the Collateral as a result of such failure; or
(h)any judgment or order for the payment of money in excess of $20,000,000 shall be rendered against the Company or any of its material Restricted Subsidiaries and there shall be any

50

period of sixty (60) consecutive days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect; or
(i)the Company or any of its material Restricted Subsidiaries (each a “Designated Party ”) shall (i) apply for or consent to the appointment of, or the taking of possession by, a receiver, custodian, trustee or liquidator of itself or of all or a substantial part of its property, (ii) make a general assignment for the benefit of its creditors, (iii) commence a voluntary case under the U.S. Bankruptcy Code (as now or hereafter in effect) or any similar law of any applicable jurisdiction, (iv) file a petition seeking to take advantage of any other law relating to bankruptcy, insolvency, reorganization, winding-up, or composition or readjustment of debts, or (v) fail to controvert in a timely and appropriate manner, or acquiesce in writing to, any petition filed against it in an involuntary case under the U.S. Bankruptcy Code or any similar law of any applicable jurisdiction; or a proceeding or case shall be commenced, without the application or consent of such Designated Party, in any court of competent jurisdiction, seeking (x) its liquidation, reorganization, dissolution or winding up, or the composition or readjustment of its debts, (y) the appointment of a trustee, receiver, custodian, liquidator or the like of such Designated Party or of all or any substantial part of its assets, or (z) similar relief in respect of such Designated Party under any law relating to bankruptcy, insolvency, reorganization, winding-up, or composition or adjustment of debts, and such proceeding or case shall continue unstayed and in effect for a period of sixty (60) or more days; or
(j)any Change of Control occurs; or
(k)(i) any Security Document shall for any reason be asserted in writing by the Company or any material Subsidiary Guarantor not to be a legal, valid and binding obligation of any party thereto, (ii) any security interest purported to be created by any Security Document and to extend to assets that are material to the Company and its Subsidiaries on a consolidated basis shall cease to be, or shall be asserted in writing by the Company or any other Loan Party not to be, a valid and perfected security interest (having the priority required by this Agreement or the relevant Security Document) in the securities, assets or properties covered thereby, except to the extent that any such loss of perfection or priority results from the failure of the Administrative Agent to maintain possession of certificates actually delivered to it representing securities pledged under the Security Documents or from a transaction otherwise permitted hereunder; or (iii) the Collateral Trust Agreement or any intercreditor agreement or subordination agreement in respect of second-lien Debt or Debt that is subordinated to the Obligations shall for any reason be asserted in writing by the Company or any material Subsidiary Guarantor not to be a legal, valid and binding obligation of any party thereto or shall otherwise cease to be enforceable; or
(l)the guarantee contained in Section 2 of the Guarantee Agreement of any Subsidiary Guarantor that holds material assets shall cease, for any reason, to be in full force and effect (other than as a result of a transaction permitted hereunder) or any Loan Party shall so assert in writing; or
(m)an ERISA Event shall occur and be continuing that, when taken together with all other such ERISA Events, would result in a Material Adverse Effect.
then, and in any such event, (A) if such event is an Event of Default specified in paragraph (i)  above with respect to either Borrower, automatically the Commitments shall immediately terminate and the Loans (with accrued and unpaid interest thereon) and all other amounts owing under this Agreement and the other Loan Documents (including all amounts of L/C Obligations, whether or not the beneficiaries of the then outstanding Letters of Credit shall have presented the documents required thereunder) shall immediately become due and payable, and (B) if such event is any other Event of Default, either or both of the following actions may be taken: (i) with the consent of the Majority Lenders, the Administrative Agent may, or upon

51

the request of the Majority Lenders, the Administrative Agent shall, by notice to the Company declare the Commitments to be terminated forthwith, whereupon the Commitments shall immediately terminate; and (ii) with the consent of the Majority Lenders, the Administrative Agent may, or upon the request of the Majority Lenders, the Administrative Agent shall, by notice to the Company, declare the Loans (with accrued and unpaid interest thereon) and all other amounts owing under this Agreement and the other Loan Documents (including all amounts of L/C Obligations, whether or not the beneficiaries of the then outstanding Letters of Credit shall have presented the documents required thereunder) to be due and payable forthwith, whereupon the same shall immediately become due and payable. With respect to all Letters of Credit with respect to which presentment for honor shall not have occurred at the time of an acceleration pursuant to this paragraph, the Company shall at such time deposit in a cash collateral account opened by the Administrative Agent an amount equal to 103% of the aggregate then undrawn and unexpired amount of such Letters of Credit plus any accrued and unpaid interest thereon and fees with respect thereto. Amounts held in such cash collateral account shall be applied by the Administrative Agent to the payment of drafts drawn under such Letters of Credit, and the unused portion thereof after all such Letters of Credit shall have expired or been fully drawn upon, if any, shall be applied to repay other Obligations of the Borrowers hereunder and under the other Loan Documents. After all such Letters of Credit shall have expired or been fully drawn upon, all Reimbursement Obligations shall have been satisfied and all other Obligations of the Borrowers hereunder and under the other Loan Documents shall have been paid in full, the balance, if any, in such cash collateral account shall be returned to the Company (or such other Person as may be lawfully entitled thereto). Except as expressly provided above in this Section, presentment, demand, protest and all other notices of any kind are hereby expressly waived by the Borrowers.
SECTION 10. THE ADMINISTRATIVE AGENT
10.1 Appointment. (a) Each Lender hereby irrevocably designates and appoints the Administrative Agent as the agent of such Lender under this Agreement and the other Loan Documents, and each such Lender irrevocably authorizes the Administrative Agent, in such capacity, to take such action on its behalf under the provisions of this Agreement and the other Loan Documents and to exercise such powers and perform such duties as are expressly delegated to the Administrative Agent by the terms of this Agreement and the other Loan Documents, together with such other powers as are reasonably incidental thereto. Notwithstanding any provision to the contrary elsewhere in this Agreement, the Administrative Agent shall not have any duties or responsibilities, except those expressly set forth herein, or any fiduciary relationship with any Lender, and no implied covenants, functions, responsibilities, duties, obligations or liabilities shall be read into this Agreement or any other Loan Document or otherwise exist against the Administrative Agent.
(b) The Administrative Agent and each Lender hereby irrevocably (I) designates and appoints the Collateral Trustee as its agent under the Collateral Trust Agreement and the other Loan Documents, and irrevocably authorizes the Collateral Trustee, in such capacity, to (i) take such action on its behalf under the provisions of the Collateral Trust Agreement and the other Loan Documents and to exercise such powers and perform such duties as are expressly delegated to the Collateral Trustee by the terms of the Collateral Trust Agreement and the other Loan Documents, together with such other powers as are reasonably incidental thereto and (ii) enter into any and all Security Documents and the Collateral Trust Agreement and such other documents and instruments as shall be necessary to give effect to (A) the ranking and priority of Debt and other extensions of credit and obligations contemplated hereunder and under the Collateral Trust Agreement, (B) the security interests in the Collateral purported to be created by the Security Documents and (C) the other terms and conditions of the Collateral Trust Agreement and (II) ratifies, approves and affirms any and all such actions described in foregoing clause (I)(ii) that occurred prior to the date. Each Lender further hereby agrees to be bound by the terms of the Collateral Trust Agreement and such other documents and instruments to the same extent as if it were a party thereto and authorizes the Administrative Agent to enter

52

into the Collateral Trust Agreement and such other documents and instruments on its behalf. Notwithstanding any provision to the contrary elsewhere in this Agreement, the Collateral Trustee shall not have any duties or responsibilities, except those expressly set forth herein, in the Collateral Trust Agreement or in any other Loan Document to which it is a party, or any fiduciary relationship with the Administrative Agent or any Lender, and no implied covenants, functions, responsibilities, duties, obligations or liabilities shall be read into this Agreement, the Collateral Trust Agreement or any other Loan Document or otherwise exist against the Collateral Trustee.
10.2 Delegation of Duties. The Administrative Agent may execute any of its duties under this Agreement and the other Loan Documents by or through agents or attorneys-in-fact and shall be entitled to advice of counsel concerning all matters pertaining to such duties. The Administrative Agent shall not be responsible for the negligence or misconduct of any agents or attorneys-in-fact selected by it with reasonable care.
10.3 Exculpatory Provisions. Neither the Administrative Agent nor any of its Affiliates (other than the Company and its Subsidiaries) nor any of its or their respective officers, directors, employees, agents, advisors, attorneys-in-fact or controlling persons shall be (i) liable for any action lawfully taken or omitted to be taken by it or such Person under or in connection with this Agreement or any other Loan Document (except to the extent that any of the foregoing are found by a final and nonappealable decision of a court of competent jurisdiction to have resulted from its or such Person's own gross negligence or willful misconduct) or (ii) responsible in any manner to any of the Lenders for any Recitals, statements, representations or warranties made by any Loan Party or any officer thereof contained in this Agreement or any other Loan Document or in any certificate, report, statement or other document referred to or provided for in, or received by the Administrative Agent under or in connection with, this Agreement or any other Loan Document or for the value, validity, effectiveness, genuineness, enforceability or sufficiency of this Agreement or any other Loan Document or for any failure of any Loan Party a party thereto to perform its obligations hereunder or thereunder. The Administrative Agent shall not be under any obligation to any Lender to ascertain or to inquire as to the observance or performance of any of the agreements contained in, or conditions of, this Agreement or any other Loan Document, or to inspect the properties, books or records of any Loan Party.
10.4 Reliance by Administrative Agent. The Administrative Agent shall be entitled to rely, and shall be fully protected in relying, upon any instrument, writing, resolution, notice, consent, certificate, affidavit, letter, telecopy, email message, statement, order or other document or conversation believed by it to be genuine and correct and to have been signed, sent or made by the proper Person or Persons or upon advice and statements of legal counsel (including counsel to the Borrowers), independent accountants and other experts selected by the Administrative Agent. The Administrative Agent may deem and treat the payee of any Note as the owner thereof for all purposes unless a written notice of assignment, negotiation or transfer thereof shall have been filed with the Administrative Agent. The Administrative Agent shall be fully justified in failing or refusing to take any action under this Agreement or any other Loan Document unless it shall first receive such advice or concurrence of the Majority Lenders (or, if so specified by this Agreement, all Lenders) as it deems appropriate or it shall first be indemnified to its satisfaction by the Lenders against any and all liability and expense that may be incurred by it by reason of taking or continuing to take any such action. The Administrative Agent shall in all cases be fully protected in acting, or in refraining from acting, under this Agreement and the other Loan Documents in accordance with a request of the Majority Lenders (or, if so specified by this Agreement, all Lenders), and such request and any action taken or failure to act pursuant thereto shall be binding upon all the Lenders and all future holders of the Loans.

53

10.5 Notice of Default. The Administrative Agent shall not be deemed to have knowledge or notice of the occurrence of any Default or Event of Default unless the Administrative Agent has received notice from a Lender or a Borrower referring to this Agreement, describing such Default or Event of Default and stating that such notice is a “notice of default”. In the event that the Administrative Agent receives such a notice, the Administrative Agent shall give notice thereof to the Lenders. The Administrative Agent shall take such action with respect to such Default or Event of Default as shall be reasonably directed by the Majority Lenders (or, if so specified by this Agreement, all Lenders);  provided  that unless and until the Administrative Agent shall have received such directions, the Administrative Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default or Event of Default as it shall deem advisable in the best interests of the Lenders.
10.6 Non-Reliance on Administrative Agent and Other Lenders. Each Lender expressly acknowledges that neither the Administrative Agent nor any of its Affiliates (other than the Company and its Subsidiaries) nor any of its or their respective officers, directors, employees, agents, advisors, attorneys-in-fact or controlling persons have made any representations or warranties to it and that no act by Administrative Agent hereafter taken, including any review of the affairs of a Loan Party or any Affiliate of a Loan Party, shall be deemed to constitute any representation or warranty by Administrative Agent to any Lender. Each Lender represents to Administrative Agent that it has, independently and without reliance upon Administrative Agent or any other Lender, and based on such documents and information as it has deemed appropriate, made its own appraisal of and investigation into the business, operations, property, financial and other condition and creditworthiness of the Loan Parties and their Affiliates and made its own decision to make its Loans hereunder and enter into this Agreement. Each Lender also represents that it will, independently and without reliance upon Administrative Agent or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit analysis, appraisals and decisions in taking or not taking action under this Agreement and the other Loan Documents, and to make such investigation as it deems necessary to inform itself as to the business, operations, property, financial and other condition and creditworthiness of the Loan Parties and their Affiliates. Except for notices, reports and other documents expressly required to be furnished to the Lenders by the Administrative Agent hereunder, the Administrative Agent shall not have any duty or responsibility to provide any Lender with any credit or other information concerning the business, operations, property, condition (financial or otherwise), prospects or creditworthiness of any Loan Party or any Affiliate of a Loan Party that may come into the possession of the Administrative Agent or its Affiliates or any of its or their officers, directors, employees, agents, advisors, attorneys-in-fact or controlling persons.
10.7 Indemnification. The Lenders agree to indemnify Administrative Agent in its capacity as such, its Affiliates (other than the Company and its Subsidiaries) and its and such Affiliates' officers, directors, employees, agents, advisors, attorneys-in-fact and controlling persons (each, an “ Agent Indemnitee ”) (to the extent not reimbursed by the Borrowers and without limiting the obligation of the Borrowers to do so), ratably according to their respective Aggregate Exposure Percentages in effect on the date on which indemnification is sought under this Section (or, if indemnification is sought after the date upon which the Commitments shall have terminated and the Loans shall have been paid in full, ratably in accordance with such Aggregate Exposure Percentages immediately prior to such date), from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind whatsoever that may at any time (whether before or after the payment of the Loans) be imposed on, incurred by or asserted against any Agent Indemnitee in any way relating to or arising out of, the Commitments, this Agreement, any of the other Loan Documents or any documents contemplated by or referred to herein or therein or the transactions contemplated hereby or thereby or any action taken or omitted by such Agent Indemnitee under or in connection with any of the foregoing; provided  that no Lender shall be liable for the payment of any portion of such liabilities, obligations,

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losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements that are found by a final and nonappealable decision of a court of competent jurisdiction to have resulted from such Agent Indemnitee's gross negligence or willful misconduct. The agreements in this Section shall survive the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.
10.8 Agent in Its Individual Capacity. The Administrative Agent and its Affiliates may make loans to, accept deposits from and generally engage in any kind of business with any Loan Party as though Administrative Agent were not the Administrative Agent. With respect to its Loans made or renewed by it and with respect to any Letter of Credit issued or participated in by it, Administrative Agent shall have the same rights and powers under this Agreement and the other Loan Documents as any Lender and may exercise the same as though it were not the Administrative Agent, and the terms “Lender” and “Lenders” shall include Administrative Agent in its individual capacity.
10.9 Successor Administrative Agent. The Administrative Agent may resign as Administrative Agent upon 10 days' notice to the Lenders and the Company. If the Administrative Agent shall resign as Administrative Agent under this Agreement and the other Loan Documents, then the Majority Lenders shall appoint from among the Lenders a successor agent for the Lenders, which successor agent shall (unless an Event of Default under  Section 9(a)  or  Section 9(i)  with respect to a Borrower shall have occurred and be continuing) be subject to approval by the Company (which approval shall not be unreasonably withheld or delayed), whereupon such successor agent shall succeed to the rights, powers and duties of the Administrative Agent, and the term “Administrative Agent” shall mean such successor agent effective upon such appointment and approval, and the former Administrative Agent's rights, powers and duties as Administrative Agent shall be terminated, without any other or further act or deed on the part of such former Administrative Agent or any of the parties to this Agreement or any holders of the Loans. If no successor agent has accepted appointment as Administrative Agent by the date that is ten (10) days following a retiring Administrative Agent's notice of resignation, the retiring Administrative Agent's resignation shall nevertheless thereupon become effective, and the Lenders shall assume and perform all of the duties of the Administrative Agent hereunder until such time, if any, as the Majority Lenders appoint a successor agent as provided for above. After any retiring Administrative Agent's resignation as Administrative Agent, the provisions of this  Section 10  shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Administrative Agent under this Agreement and the other Loan Documents.
SECTION 11. MISCELLANEOUS
11.1 Amendments and Waivers. Neither this Agreement, any other Loan Document, nor any terms hereof or thereof may be amended, supplemented or modified except in accordance with the provisions of this  Section 11.1 . The Majority Lenders and each Loan Party party to the relevant Loan Document may, or, with the written consent of the Majority Lenders, the Administrative Agent and each Loan Party party to the relevant Loan Document may, from time to time, (a) enter into written amendments, supplements or modifications hereto and to the other Loan Documents for the purpose of changing any provisions to this Agreement or the other Loan Documents or changing in any manner the rights of the Lenders or of the Loan Parties hereunder or thereunder or (b) waive, on such terms and conditions as the Majority Lenders or the Administrative Agent, as the case may be, may specify in such instrument, any of the requirements of this Agreement or the other Loan Documents or any Default or Event of Default and its consequences; provided ,  however , that no such waiver and no such amendment, supplement or modification shall (i) forgive the principal amount or extend the final scheduled date of maturity of any Loan, reduce the stated rate of any interest or fees payable hereunder (except (x) in connection with any reduction in the post-default rate of interest set forth in  Section 2.12(c) ; (y) in connection with the waiver of applicability of any post-default increase in interest rates (which waiver shall be effective with the consent of the Majority

55

Lenders); and (z) that any amendment or modification of defined terms used in the financial covenants in this Agreement shall not constitute a reduction in the rate of interest or fees for purposes of this clause (i)) or extend the scheduled date of any payment thereof, or increase the amount or extend the expiration date of any Lender's Commitment, or otherwise change the time, place or the currency of payments to be made on the Loans, in each case without the written consent of each Lender directly affected thereby; (ii) reduce any percentage specified in the definition of Majority Lenders without the written consent of all Lenders, (iii) except to the extent contemplated by the Loan Documents, release all or substantially all of the Collateral or release a Subsidiary Guarantor or Subsidiary Guarantors owning all or substantially all of the Collateral from their obligations under the Security Agreement or Guarantee Agreement, respectively, in each case without the written consent of all Lenders; (iv) [reserved]; (v) [reserved], (vi) amend, modify or waive any provision of  Section 10  without the written consent of the Administrative Agent; or (vii) amend, modify or waive any provision of  Sections 2.5(b) ,  3 ,  11.1 ,  11.5 , or  11.6(b)(i)(B) , or extend the Termination Date without the written consent of each Lender affected thereby. Any such waiver and any such amendment, supplement or modification shall apply equally to each of the Lenders and shall be binding upon the Loan Parties, the Lenders, the Administrative Agent and all future holders of the Loans. In the case of any waiver, the Loan Parties, the Lenders and the Administrative Agent shall be restored to their former position and rights hereunder and under the other Loan Documents, and any Default or Event of Default waived shall be deemed to be cured and not continuing; but no such waiver shall extend to any subsequent or other Default or Event of Default, or impair any right consequent thereon.
Notwithstanding anything to the contrary contained in this Section 11.1:
(a)the Guarantee Agreement, the Security Documents and related documents executed by the Borrowers or Subsidiaries in connection with this Agreement may be in a form reasonably determined by the Administrative Agent and may be, together with this Agreement, amended, supplemented and waived with the consent of the Administrative Agent at the request of the Company without the need to obtain the consent of any other Lender if such amendment, supplement or waiver is delivered in order (i) to comply with local Law or advice of local counsel, (ii) to cure ambiguities, omissions, mistakes or defects or (iii) to cause the Guarantee Agreement, any Security Document or any related document to be consistent with this Agreement and the other Loan Documents; and
(b)this Agreement may be amended (or amended and restated) with the written consent of the Majority Lenders, the Administrative Agent and the Borrowers (i) to add one or more additional credit facilities to this Agreement and to permit the extensions of credit from time to time outstanding thereunder and the accrued interest and fees in respect thereof to share ratably in the benefits of this Agreement and the other Loan Documents with the Loans and the accrued interest and fees in respect thereof and (ii) to include appropriately the Lenders holding such credit facilities in any determination of the Majority Lenders.
11.2 Notices. All notices, requests and demands to or upon the respective parties hereto to be effective shall be in writing (including by telecopy), and, unless otherwise expressly provided herein, shall be deemed to have been duly given or made when delivered, or three Business Days after being deposited in the mail, postage prepaid, or, in the case of telecopy notice, when received, addressed as follows in the case of the Borrowers, the Administrative Agent and the Lenders identified below, and as set forth in an administrative questionnaire delivered to the Administrative Agent in the case of the Lenders, or to such other address as may be hereafter notified by the respective parties hereto:

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Company and GAI:	GenOn Energy, Inc.	
 	GenOn Americas, Inc.
Subsidiary Guarantors	
 	c/o NRG Energy, Inc.
211 Carnegie Center
Princeton, NJ 08540
Facsimile No.:  609-524-4501
Telephone No.: 609-524-4500
Attention:   Treasurer, Chief Financial Officer and General Counsel	
Administrative Agent:	NRG Energy, Inc.	
 	211 Carnegie Center	
 	Princeton, NJ 08540	
 	Facsimile No.: 609-524-4501
Telephone No.: 609-524-4500	
 	Attention of Treasurer, Chief Financial Officer and General Counsel 	
 	With a copy to:	
 	Kirkland & Ellis LLP
601 Lexington Avenue
New York, NY 10022
Facsimile No.:  212-446-6460
Telephone No.: 212-446-4737	
 	Attention: Andres Mena	
 	With a copy to:	
 	Kirkland & Ellis LLP
300 North LaSalle St.
Chicago, IL 60654
Facsimile No.:  312-862-2200
Telephone No.: 312-862-2075
Attention: Gerald Nowak	

57

 	
 	 	
NRG, as Lender:	NRG Energy, Inc.	
 	211 Carnegie Center	
 	Princeton, NJ 08540	
 	Facsimile No.: 609-524-4501
Telephone No.: 609-524-4500	
 	Attention of Treasurer, Chief Financial Officer and General Counsel 	
 	With a copy to:	
 	Kirkland & Ellis LLP
601 Lexington Avenue
New York, NY 10022
Facsimile No.:  212-446-6460
Telephone No.: 212-446-4737	
 	Attention: Andres Mena	
 	With a copy to:	
 	Kirkland & Ellis LLP
300 North LaSalle St.
Chicago, IL 60654
Facsimile No.:  312-862-2200
Telephone No.: 312-862-2075
Attention: Gerald Nowak	
provided that any notice, request or demand to or upon the Administrative Agent or any Lender shall not be effective until received.
Notices and other communications to the Lenders hereunder may be delivered or furnished by electronic or telephonic communications pursuant to procedures approved by the Administrative Agent; provided  that the foregoing shall not apply to notices pursuant to  Section   2  unless otherwise agreed by the Administrative Agent and the applicable Lender or otherwise provided for therein. The Administrative Agent or the Company may, in its discretion, agree to accept notices and other communications to it hereunder by electronic or telephonic communications pursuant to procedures approved by it;  provided  that approval of such procedures may be limited to particular notices or communications.
11.3 No Waiver; Cumulative Remedies. No failure to exercise and no delay in exercising, on the part of the Administrative Agent or any Lender, any right, remedy, power or privilege hereunder or under the other Loan Documents shall operate as a waiver thereof; nor shall any single or partial exercise of any right, remedy, power or privilege hereunder preclude any other or further exercise thereof or the exercise of any other right, remedy, power or privilege. The rights, remedies, powers and privileges herein provided are cumulative and not exclusive of any rights, remedies, powers and privileges provided by law.
11.4 Survival of Representations and Warranties. All representations and warranties made hereunder, in the other Loan Documents and in any document, certificate or statement delivered pursuant hereto or in connection herewith shall survive the execution and delivery of this Agreement and the making of the Loans and other extensions of credit hereunder.
11.5 Payment of Expenses and Taxes. (a) The Company agrees, if the Closing Date occurs, (i) to pay or reimburse the Administrative Agent and each Lender (A) for all their out-of-pocket costs and expenses incurred in connection with the development, preparation and execution of, and any amendment, supplement or modification to, this Agreement and the other Loan Documents and any other documents prepared in connection herewith or therewith, and the consummation and administration of the

58

transactions contemplated hereby and thereby, including the reasonable fees and disbursements of counsel to the Administrative Agent and each Lender and filing and recording fees and expenses and (B) for all of its costs and expenses incurred in connection with the enforcement or preservation of any rights under this Agreement, the other Loan Documents and any such other documents, including the fees and disbursements of counsel to the Administrative Agent, (ii) to pay or reimburse the Administrative Agent, Collateral Trustee, and each Lender for all their costs and expenses incurred in connection with the enforcement or preservation of any rights under this Agreement, the other Loan Documents and any such other documents, in each case, during the continuance of a Default or an Event of Default, including the fees and disbursements of counsel (including the allocated fees and expenses of in-house counsel) to each Lender, (iii) to pay, indemnify, and hold each Lender and the Administrative Agent harmless from, any and all recording and filing fees and any and all liabilities with respect to, or resulting from any delay in paying, stamp, excise and other taxes, if any, that may be payable or determined to be payable in connection with the execution and delivery of, or consummation or administration of any of the transactions contemplated by, or any amendment, supplement or modification of, or any waiver or consent under or in respect of, this Agreement, the other Loan Documents and any such other documents, and (iv) to pay, indemnify, and hold each Lender, the Administrative Agent, their Affiliates (other than the Company and its Subsidiaries) and each of their respective officers, directors, trustees, employees, agents, advisors and controlling persons (each, an “ Indemnitee ”) harmless from and against any and all other liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever with respect to the execution, delivery, enforcement, performance and administration of this Agreement, the other Loan Documents and any such other documents, including any of the foregoing relating to the use of proceeds of the Loans or the violation of, noncompliance with or liability under, any Environmental Law applicable to the operations of the Company or any of its Subsidiaries or any real property currently or formerly owned, leased, operated or otherwise used (including properties to which wastes or other materials were sent for treatment, storage or disposal) by the Company or any of its Subsidiaries or any of their predecessors and the reasonable fees and expenses of legal counsel in connection with claims, actions or proceedings by any Indemnitee against any Loan Party under any Loan Document (all the foregoing in this clause (iv), collectively, the “ Indemnified Liabilities ”),  provided , that the Company shall have no obligation hereunder to any Indemnitee with respect to Indemnified Liabilities to the extent such Indemnified Liabilities are found by a final and nonappealable decision of a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of such Indemnitee. Without limiting the foregoing, and to the extent permitted by applicable law, the Company agrees not to assert and to cause its Subsidiaries not to assert, and hereby waives and agrees to cause its Subsidiaries to waive, all rights for contribution or any other rights of recovery with respect to all claims, demands, penalties, fines, liabilities, settlements, damages, costs and expenses of whatever kind or nature, under or related to Environmental Laws, that any of them might have by statute or otherwise against any Indemnitee.
(b) Promptly after receipt by an Indemnitee of notice of the commencement of any claim, litigation, investigation, responding to or proceedings against it relating to any Indemnified Liability (“ Proceedings ”), such Indemnitee will, if a claim is to be made hereunder against the Company in respect thereof, notify the Company in writing of the commencement thereof;  provided , however , that (i) the omission so to notify the Company will not relieve it from any liability that it may have hereunder and (ii) the omission so to notify the Company will not relieve the Company from any liability that it may have to an Indemnitee otherwise than on account hereof. Thereafter, the Indemnitee and the Company shall consult, to the extent appropriate, with a view to minimizing the (A) cost to the Company of the obligations under this  Section 11.5  and (B) potential liabilities with respect to such Proceedings. In case any such Proceedings are brought against any Indemnitee and it notifies the Company of the commencement thereof, the Company will be entitled to participate therein, and, to the extent that it may elect by written notice delivered to such Indemnitee, to

59

assume the defense thereof, with counsel reasonably satisfactory to such Indemnitee, provided that if the defendants in any such Proceedings include both such Indemnitee and the Company and such Indemnitee shall have concluded that there may be legal defenses available to it that are different from or additional to those available to the Company, such Indemnitee shall have the right to select separate counsel to assert such legal defenses and to otherwise participate in the defense of such Proceedings on behalf of such Indemnitee(it being understood that the Company shall be liable for the expenses of such separate counsel representing the Indemnitees who are parties to such Proceedings).
(c) The Company shall not be liable for any settlement of any Proceedings effected without its written consent (which consent shall not be unreasonably withheld, delayed or conditioned). If any settlement of any Proceeding is consummated with the written consent of the Company or if there is a final judgment for the plaintiff in any such Proceedings, the Company agrees to indemnify and hold harmless each Indemnitee from and against any and all losses, claims, damages, liabilities and expenses by reason of such settlement or judgment in accordance with the provisions of this  Section 11.5(c) . Notwithstanding anything in this  Section 11.5(c)  to the contrary, if at any time an Indemnitee shall have requested the Company to reimburse such Indemnitee for legal or other expenses in connection with investigating, responding to or defending any Proceedings as contemplated by this  Section 11.5(c) , the Company shall be liable for any settlement of any Proceedings effected without its written consent if (i) such settlement is entered into more than 30 days after receipt by the Company of such request for reimbursement and (ii) the Company shall not have reimbursed such Indemnitee in accordance with such request prior to the date of such settlement. The Company shall not, without the prior written consent of an Indemnitee (which consent shall not be unreasonably withheld, delayed or conditioned), effect any settlement of any pending or threatened Proceedings in respect of which indemnity could have been sought hereunder by such Indemnitee unless such settlement (i) includes an unconditional release of such Indemnitee in form and substance satisfactory to such Indemnitee from all liability on claims that are the subject matter of such Proceedings and (ii) does not include any statement as to or any admission of fault, culpability or a failure to act by or on behalf of any Indemnitee.
(d) All amounts due under this Section 11.5 shall be payable not later than 10 days after written demand therefor (or such later date as Administrative Agent may agree to in its sole discretion). Statements payable by the Company pursuant to this  Section 11.5  shall be submitted to the Treasurer, Chief Financial Officer or General Counsel of Agent (Telephone No. 609-524-4500, Telecopy No. 609-524-4501), at the address of the Company set forth in  Section 11.2 , or to such other Person or address as may be hereafter designated by the Company in a written notice to the Administrative Agent. The agreements in this  Section 11.5  shall survive repayment of the Loans and all other amounts payable hereunder.
11.6 Successors and Assigns; Participations and Assignments. (a) The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby, except that (i) no Borrower may assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of each Lender (and any attempted assignment or transfer by the Company without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section.
(b) (i) Subject to the conditions set forth in paragraph (b)(ii) below, any Lender may assign to one or more assignees (each, an “ Assignee ”) all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitments and the Loans at the time owing to it) with the prior written consent of:
(A) the Company (such consent not to be unreasonably withheld, delayed or conditioned),  provided  that no consent of the Company shall be required for an assignment

60

to a Lender, an Affiliate of a Lender or an Approved Fund (as defined below) or, if an Event of Default has occurred and is continuing, to any other Person; and
(B) the Administrative Agent and each Lender (such consent not to be unreasonably withheld, delayed or conditioned),  provided  that no consent of the Administrative Agent shall be required for assignments of Commitments and/or Loans among Lenders, Affiliates of Lenders or Approved Funds.
(ii) Assignments shall be subject to the following additional conditions:
(A) except in the case of an assignment to a Lender, an Affiliate of a Lender or an Approved Fund or an assignment of the entire remaining amount of the assigning Lender's Commitments or Loans, the amount of the Commitments or Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent) shall not be less than $10,000,000, unless each of the Company and the Administrative Agent otherwise consent (such consent, in the case of the Company, not to be unreasonably withheld, delayed or conditioned);  provided  that such amounts shall be aggregated in respect of each Lender and its Affiliates or Approved Funds, if any;
(B) the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500 (unless waived by the Administrative Agent in its sole discretion);  provided  that only one such fee shall be payable to the Administrative Agent in connection with simultaneous assignments by a Lender to two or more related Approved Funds;
(C) the Assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an administrative questionnaire; and
(D) without the prior written consent of the Administrative Agent, no assignment shall be made to a prospective Assignee that bears a relationship to the Company described in Section 108(e)(4) of the Code, except to any member of the NRG Parent Group.
For the purposes of this Section 11.6, “Approved Fund” means any Person (other than a natural person) that is engaged in making, purchasing, holding or investing in bank loans and similar extensions of credit in the ordinary course and that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender or (d) the Company or any of its Affiliates.
(iii) Subject to acceptance and recording thereof pursuant to paragraph (b)(iv) below, from and after the effective date specified in each Assignment and Assumption the Assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender's rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of  Sections 2.16 ,  2.17 ,  2.18  and  11.5  with respect to facts and circumstances occurring prior to the effective date of such assignment). Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this  Section 11.6  shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with paragraph  (c)  of this Section.

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(iv) The Administrative Agent, acting for this purpose as an agent of the Borrowers, shall maintain at one of its offices a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, and principal amount of the Loans and L/C Obligations owing to, each Lender pursuant to the terms hereof from time to time (the “ Register ”). The entries in the Register shall be conclusive absent manifest error, and the Borrowers, the Administrative Agent, and the Lenders shall treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. With respect to any Lender, the transfer of the Commitments of such Lender and the rights to the principal of, and the interest on, any Loan made pursuant to such Commitments shall not be effective until such transfer is recorded on the Register maintained by the Administrative Agent with respect to ownership of such Commitments and Loans. The Register shall be available for inspection by the Borrowers and any Lender, at any reasonable time and from time to time upon reasonable prior notice.
(v) Upon its receipt of a duly completed Assignment and Assumption executed by an assigning Lender and an Assignee, the Assignee's completed administrative questionnaire (unless the Assignee shall already be a Lender hereunder), the processing and recordation fee referred to in paragraph  (b)  of this Section (to the extent required) and any written consent to such assignment required by paragraph  (b)  of this Section, the Administrative Agent shall accept such Assignment and Assumption and record the information contained therein in the Register. No assignment shall be effective for purposes of this Agreement unless it has been recorded in the Register as provided in this paragraph.
(c) (i) Any Lender may, without the consent of either Borrower or the Administrative Agent, sell participations to one or more banks or other entities (a “ Participant ”) in all or a portion of such Lender's rights and obligations under this Agreement (including all or a portion of its Commitments and the Loans owing to it);  provided  that (A) such Lender's obligations under this Agreement shall remain unchanged, (B) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, (C) the Borrowers, the Administrative Agent, and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender's rights and obligations under this Agreement, and (D) without the prior written consent of the Administrative Agent, no assignment shall be made to a prospective Assignee that bears a relationship to a Borrower described in Section 108(e)(4) of the Code (other than any member of the NRG Parent Group). Any agreement pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement;  provided  that such agreement may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver that (1) requires the consent of each Lender directly affected thereby pursuant to the proviso to the second sentence of  Section 11.1  and directly affects such Participant or (2) requires the consent of all Lenders. Subject to paragraph (c)(ii) of this Section, each Borrower agrees that each Participant shall be entitled to the benefits of, and subject to the limitations of,  Sections 2.16  and  2.17 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to paragraph (b)  of this Section. Each Lender that sells a participation shall, acting solely for this purpose as an agent of the Borrowers, maintain a register on which it enters the name and address of each Participant to whom such Lender sells participations and the principal amounts (and stated interest) of each participant's interest in the Loans or other obligations under this Agreement (the “ Participant Register ”). As between the Lender and such Participant, the entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary.
(ii) A Participant shall not be entitled to receive any greater payment under Section 2.16 or 2.17 than the applicable Lender would have been entitled to receive with respect to the participation sold to such

62

Participant, unless the sale of the participation to such Participant is made with the Borrowers' prior written consent.
(d) Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank, and this Section shall not apply to any such pledge or assignment of a security interest;  provided  that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or Assignee for such Lender as a party hereto.
(e) Each Borrower, upon receipt of written notice from the relevant Lender, agrees to issue Notes to any Lender requiring Notes to facilitate transactions of the type described in paragraph  (d)  above.
11.7 Adjustment and Set-Off. (a) Except to the extent that this Agreement expressly permits for payments to be made, directed or allocated to a particular Lender, if any Lender (a “ Benefitted Lender ”) shall receive any payment of all or part of the Obligations owing to it, or receive any Collateral in respect thereof (whether voluntarily or involuntarily, by set-off, pursuant to events or proceedings of the nature referred to in  Section 9(i) , or otherwise), in a greater proportion than any such payment to or collateral received by any other Lender, if any, in respect of the Obligations owing to such other Lender, such Benefitted Lender shall purchase for cash from the other Lenders a participating interest in such portion of the Obligations owing to each such other Lender, or shall provide such other Lenders with the benefits of any such collateral, as shall be necessary to cause such Benefitted Lender to share the excess payment or benefits of such collateral ratably with each of the Lenders;  provided ,  however , that if all or any portion of such excess payment or benefits is thereafter recovered from such Benefitted Lender, such purchase shall be rescinded, and the purchase price and benefits returned, to the extent of such recovery, but without interest.
(b) In addition to any rights and remedies of the Lenders provided by law, each Lender shall have the right, without prior notice to either Borrower, any such notice being expressly waived by each Borrower to the extent permitted by applicable law, upon any amount becoming due and payable by the Borrowers hereunder (whether at the stated maturity, by acceleration or otherwise), to set off and appropriate and apply against such amount any and all deposits (general or special, time or demand, provisional or final), in any currency, and any other credits, Debt or claims, in any currency, in each case whether direct or indirect, absolute or contingent, matured or unmatured, at any time held or owing by such Lender or any branch or agency thereof to or for the credit or the account of the Borrowers, as the case may be. Each Lender agrees promptly to notify the Company and the Administrative Agent after any such setoff and application made by such Lender,  provided  that the failure to give such notice shall not affect the validity of such setoff and application.
11.8 Counterparts. This Agreement may be executed by one or more of the parties to this Agreement on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of an executed signature page of this Agreement by facsimile transmission shall be effective as delivery of a manually executed counterpart hereof. A set of the copies of this Agreement signed by all the parties shall be lodged with the Company and the Administrative Agent.
11.9 Severability. Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

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11.10 Integration. This Agreement and the other Loan Documents represent the entire agreement of the Borrowers, the Administrative Agent and the Lenders with respect to the subject matter hereof and thereof, and there are no promises, undertakings, representations or warranties by the Administrative Agent or any Lender relative to the subject matter hereof not expressly set forth or referred to herein or in the other Loan Documents.
11.11GOVERNING LAW. THIS AGREEMENT AND ANY CLAIM, CONTROVERSY OR DISPUTE ARISING UNDER OR RELATED TO THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.
11.12 Submission To Jurisdiction; Waivers. Each Borrower hereby irrevocably and unconditionally:
(a) submits for itself and its property in any legal action or proceeding relating to this Agreement and the other Loan Documents to which it is a party, or for recognition and enforcement of any judgment in respect thereof, to the non-exclusive general jurisdiction of the courts of the State of New York, the courts of the United States for the Southern District of New York, and appellate courts from any thereof;
(b) consents that any such action or proceeding may be brought in such courts and waives any objection that it may now or hereafter have to the venue of any such action or proceeding in any such court or that such action or proceeding was brought in an inconvenient court and agrees not to plead or claim the same;
(c) agrees that service of process in any such action or proceeding may be effected by mailing a copy thereof by registered or certified mail (or any substantially similar form of mail), postage prepaid, to such Borrower at its address set forth in  Section 11.2  or at such other address of which the Administrative Agent shall have been notified pursuant thereto;
(d) agrees that nothing herein shall affect the right to effect service of process in any other manner permitted by law or shall limit the right to sue in any other jurisdiction; and
(e) waives, to the maximum extent not prohibited by law, any right it may have to claim or recover in any legal action or proceeding referred to in this Section any special, exemplary, punitive or consequential damages.
11.13 Acknowledgements. Each Borrower hereby acknowledges that:
(a) it has been advised by counsel in the negotiation, execution and delivery of this Agreement and the other Loan Documents;
(b) neither the Administrative Agent nor any Lender has any fiduciary relationship with or duty to either Borrower arising out of or in connection with this Agreement or any of the other Loan Documents, and the relationship between Administrative Agent and Lenders, on one hand, and the Borrowers, on the other hand, in connection herewith or therewith is solely that of debtor and creditor; and
(c) no joint venture is created hereby or by the other Loan Documents or otherwise exists by virtue of the transactions contemplated hereby among the Lenders or among the Borrowers and the Lenders.

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11.14 Releases of Guarantees and Liens. (a) Notwithstanding anything to the contrary contained herein or in any other Loan Document, each of the Administrative Agent and the Collateral Trustee are hereby irrevocably authorized by each Lender (without requirement of notice to or consent of any Lender except as expressly required by  Section 11.1 ) to take any action requested by the Company having the effect of releasing any Collateral or guarantee obligations (i) to the extent necessary to permit consummation of any transaction not prohibited by any Loan Document (it being agreed, without limiting the foregoing, that such release shall be permitted with respect to any Subsidiary Guarantor if, after giving effect to any such transaction or designation as an Unrestricted Subsidiary, such Person would not be required to become a Guarantor Subsidiary pursuant to  Section 6.7 ) or that has been consented to in accordance with  Section 11.1 or (ii) under the circumstances described in paragraph  (b)  below. The Administrative Agent and the Collateral Trustee agree to take such actions as are reasonably requested by the Company and permitted by this  Section 11.14 , at the Company's sole expense.
(b) At such time as the Loans, the Reimbursement Obligations and the other obligations under the Loan Documents shall have been paid in full, the Commitments have been terminated and no Letters of Credit shall be outstanding (or any outstanding Letters of Credit shall have been fully cash collateralized), the Collateral shall be released from the Liens created by the Security Documents, and the Security Documents and all obligations (other than those expressly stated to survive such termination) of the Administrative Agent, the Collateral Trustee and each Loan Party under the Security Documents shall terminate, all without delivery of any instrument or performance of any act by any Person.
11.15 Confidentiality. Each of the Administrative Agent and each Lender agrees to keep confidential all non-public information provided to it by any Loan Party, the Administrative Agent or any Lender pursuant to or in connection with this Agreement that is designated by the provider thereof as confidential; provided  that nothing herein shall prevent the Administrative Agent or any Lender from disclosing any such information (a) to the Administrative Agent, any other Lender or any Affiliate thereof, (b) subject to an agreement to comply with the provisions of this Section, to any actual or prospective Transferee or any direct or indirect counterparty to any Swap Agreement (or any professional advisor to such counterparty), (c) to its and its Affiliates' employees, officers, directors, shareholders, trustees, agents, attorneys, accountants and other professional advisors, (d) upon the request or demand of any Governmental Authority, (e) in response to any order of any court or other Governmental Authority or as may otherwise be required pursuant to any Requirement of Law, (f) if requested or required to do so in connection with any litigation or similar proceeding, (g) that has been publicly disclosed, (h) to the National Association of Insurance Commissioners or any similar organization or any nationally recognized rating agency that requires access to information about a Lender's investment portfolio in connection with ratings issued with respect to such Lender, or (i) in connection with the exercise of any remedy hereunder or under any other Loan Document.
11.16WAIVERS OF JURY TRIAL. EACH BORROWER, THE ADMINISTRATIVE AGENT AND THE LENDERS HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVE TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT AND FOR ANY COUNTERCLAIM THEREIN.
11.17 Delivery of Addenda. Each initial Lender shall become a party to this Agreement by delivering to the Administrative Agent an Addendum duly executed by such Lender.

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IN WITNESS WHEREOF, the undersigned has caused this Agreement to be duly executed and delivered by their proper and duly authorized officers as of the day and year first above written.
GENON ENERGY, INC.

By:    /s/ G. Gary Garcia            
Name: G. Gary Garcia
Title: Treasurer

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IN WITNESS WHEREOF, the undersigned has caused this Agreement to be duly executed and delivered by its proper and duly authorized officers as of the Closing Date.

GENON AMERICAS, INC.

By:    /s/ G. Gary Garcia                
Name: G. Gary Garcia
Title:     Treasurer

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NRG Energy, Inc., as Administrative Agent

By:    /s/ G. Gary Garcia            
Name: G. Gary Garcia
Title:     Senior Vice President and Treasurer

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EXHIBIT 12.1
NRG ENERGY, INC. AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	For the Year Ended December 31,	
 	2012	 	2011(a)	 	2010	 	2009	 	2008	
 	
 	(in millions except ratio)	
Earnings:	 	 	 	 	 	 	 	 	 	
Income/(loss) from continuing operations before income tax	$	252	
 	 	$	(646	)	 	$	753	
 	 	$	1,669	
 	 	$	1,766	
 	
Net income/(loss) attributable to noncontrolling interest	20	
 	 	—	
 	 	(1	)	 	(1	)	 	—	
 	
Less:	 	 	 	 	 	 	 	 	 	
Distributions and equity in earnings of unconsolidated affiliates	2	
 	 	9	
 	 	(19	)	 	(41	)	 	(44	)	
Impairment charge on equity method investment	2	
 	 	495	
 	 	—	
 	 	—	
 	 	—	
 	
Capitalized interest	(140	)	 	(80	)	 	(36	)	 	(37	)	 	(45	)	
Add:	 	 	 	 	 	 	 	 	 	
Fixed charges	864	
 	 	931	
 	 	678	
 	 	703	
 	 	634	
 	
Amortization of capitalized interest	11	
 	 	7	
 	 	4	
 	 	3	
 	 	1	
 	
Total Earnings:	$	1,011	
 	 	$	716	
 	 	$	1,379	
 	 	$	2,296	
 	 	$	2,312	

Fixed Charges:	 	 	 	 	 	 	 	 	 	
Interest expense	$	671	
 	 	$	808	
 	 	$	600	
 	 	$	610	
 	 	$	546	
 	
Interest capitalized	140	
 	 	80	
 	 	36	
 	 	37	
 	 	45	
 	
Amortization of debt issuance costs	32	
 	 	26	
 	 	25	
 	 	31	
 	 	22	
 	
Amortization of debt discount	9	
 	 	6	
 	 	7	
 	 	13	
 	 	15	
 	
Approximation of interest in rental expense	12	
 	 	11	
 	 	10	
 	 	12	
 	 	6	
 	
Total Fixed Charges:	$	864	
 	 	$	931	
 	 	$	678	
 	 	$	703	
 	 	$	634	
 	
Ratio of Earnings to Combined Fixed Charges	1.17	
 	 	0.77	
 	 	2.03	
 	 	3.27	
 	 	3.65	

 	 	
(a)	The ratio coverage for the year ended December 31, 2011 was less than 1:1. NRG would have needed to generate additional earnings of $215 million to achieve a ratio coverage of 1:1.	

EXHIBIT 12.2
NRG ENERGY, INC. AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
AND PREFERRED STOCK DIVIDEND REQUIREMENTS

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	For the Year Ended December 31,	
 	2012	 	2011(a)	 	2010	 	2009	 	2008	
 	(in millions except ratio)	
Earnings:	 	 	 	 	 	 	 	 	 	
Income/(loss) from continuing operations before income tax	$	252	
 	 	$	(646	)	 	$	753	
 	 	$	1,669	
 	 	$	1,766	
 	
Net income/(loss) attributable to noncontrolling interest	20	
 	 	—	
 	 	(1	)	 	(1	)	 	—	
 	
Less:	 	 	 	 	 	 	 	 	 	
Distributions and equity in earnings of unconsolidated affiliates	2	
 	 	9	
 	 	(19	)	 	(41	)	 	(44	)	
Impairment charge on equity method investment	2	
 	 	495	
 	 	—	
 	 	—	
 	 	—	
 	
Capitalized interest	(140	)	 	(80	)	 	(36	)	 	(37	)	 	(45	)	
Preference dividends - tax effected	(9	)	 	(9	)	 	(14	)	 	(52	)	 	(90	)	
Add:	 	 	 	 	 	 	 	 	 	
Fixed charges	873	
 	 	940	
 	 	692	
 	 	755	
 	 	724	
 	
Amortization of capitalized interest	11	
 	 	7	
 	 	4	
 	 	3	
 	 	1	
 	
Total Earnings:	$	1,011	
 	 	$	716	
 	 	$	1,379	
 	 	$	2,296	
 	 	$	2,312	

Fixed Charges:	 	 	 	 	 	 	 	 	 	
Interest expense	$	671	
 	 	$	808	
 	 	$	600	
 	 	$	610	
 	 	$	546	
 	
Interest capitalized	140	
 	 	80	
 	 	36	
 	 	37	
 	 	45	
 	
Amortization of debt issuance costs	32	
 	 	26	
 	 	25	
 	 	31	
 	 	22	
 	
Amortization of debt discount	9	
 	 	6	
 	 	7	
 	 	13	
 	 	15	
 	
Approximation of interest in rental expense	12	
 	 	11	
 	 	10	
 	 	12	
 	 	6	
 	
Preference dividends - tax effected	9	
 	 	9	
 	 	14	
 	 	52	
 	 	90	
 	
Total Fixed Charges:	$	873	
 	 	$	940	
 	 	$	692	
 	 	$	755	
 	 	$	724	
 	
Ratio of Earnings to Combined Fixed Charges and
Preference Dividends	1.16	
 	 	0.76	
 	 	1.99	
 	 	3.04	
 	 	3.19	

 	 	
(a)	The ratio coverage for the year ended December 31, 2011 was less than 1:1. NRG would have needed to generate additional earnings of $224 million to achieve a ratio coverage of 1:1.	

EXHIBIT 21.1
SUBSIDIARIES OF NRG ENERGY, INC.

 	 	 	
Entity Name	 	Jurisdiction	
AC Solar Holdings LLC	 	Delaware	
AFE Marquette LLC	 	Wisconsin	
Agua Caliente Solar Holdings LLC	 	Delaware	
Agua Caliente Solar, LLC	 	Delaware	
Allied Home Warranty GP LLC	 	Delaware	
Allied Warranty LLC	 	Texas	
Alta Vista SunTower, LLC	 	Delaware	
Arthur Kill Gas Turbines LLC	 	Delaware	
Arthur Kill Power LLC	 	Delaware	
Astoria Gas Turbine Power LLC	 	Delaware	
Avenal Park LLC	 	Delaware	
Avenal Solar Holdings LLC	 	Delaware	
Bayou Cove Peaking Power, LLC	 	Delaware	
Berrians I Gas Turbine Power LLC	 	Delaware	
Big Cajun I Peaking Power LLC	 	Delaware	
Big Cajun II Unit 4 LLC	 	Delaware	
Big Rock SunTower, LLC	 	Delaware	
bioNRG Tonawanda Inc.	 	Delaware	
Bluewater Wind Delaware LLC	 	Delaware	
Bluewater Wind Maryland LLC	 	Delaware	
Bluewater Wind New Jersey Energy LLC	 	Delaware	
Cabrillo Power I LLC	 	Delaware	
Cabrillo Power II LLC	 	Delaware	
Camas Power Boiler Limited Partnership	 	Oregon	
Camas Power Boiler, Inc.	 	Oregon	
Carbon Management Solutions LLC	 	Delaware	
Carlsbad Energy Center LLC	 	Delaware	
Cheng Power Systems, Inc.	 	Delaware	
Chickahominy River Energy Corp.	 	Virginia	
Clean Edge Energy LLC	 	Delaware	
Cody SunTower, LLC	 	Delaware	
Commonwealth Atlantic Power LLC	 	Delaware	
Conemaugh Fuels, LLC	 	Delaware	
Conemaugh Power LLC	 	Delaware	
Connecticut Jet Power LLC	 	Delaware	
Continental Energy, LLC	 	Arizona	
Cottonwood Development LLC	 	Delaware	
Cottonwood Energy Company LP	 	Delaware	
Cottonwood Generating Partners I LLC	 	Delaware	
Cottonwood Generating Partners II LLC	 	Delaware	
Cottonwood Generating Partners III LLC	 	Delaware	
Cottonwood Technology Partners LP	 	Delaware	
Delaware Power Development LLC	 	Delaware	

 	
 	 	 	
Desert View SunTower, LLC	 	Delaware	
Devon Power LLC	 	Delaware	
Dunkirk Power LLC	 	Delaware	
Eastern Sierra Energy Company LLC	 	California	
El Mirage Energy, LLC	 	Arizona	
El Segundo Energy Center II LLC	 	Delaware	
El Segundo Energy Center LLC	 	Delaware	
El Segundo Power II LLC	 	Delaware	
El Segundo Power, LLC	 	Delaware	
Elbow Creek Wind Project LLC	 	Texas	
Energy Alternatives Wholesale, LLC	 	Delaware	
Energy Investors Fund, L.P.	 	Delaware	
Energy National, Inc.	 	Utah	
Energy Plus Holdings LLC	 	Delaware	
Energy Plus Natural Gas LLC	 	Delaware	
Energy Protection Insurance Company	 	Vermont	
Enifund, Inc.	 	Utah	
Enigen, Inc.	 	Utah	
ESOCO Molokai, Inc.	 	Utah	
ESOCO, Inc.	 	Utah	
eV2g LLC	 	Delaware	
Everything Energy LLC	 	Delaware	
Fairmont SunTower, LLC	 	Delaware	
FUSD Energy, LLC	 	Arizona	
GCE Holding LLC	 	Connecticut	
GCP Funding Company, LLC	 	Delaware	
GenConn Devon LLC	 	Connecticut	
GenConn Energy LLC	 	Connecticut	
GenConn Middletown LLC	 	Connecticut	
GenOn Americas Generation, LLC	 	Delaware	
GenOn Americas Procurement, Inc.	 	Delaware	
GenOn Americas, Inc.	 	Delaware	
GenOn Asset Management, LLC	 	Delaware	
GenOn Bowline, LLC	 	Delaware	
GenOn California North, LLC	 	Delaware	
GenOn Canal, LLC	 	Delaware	
GenOn Capital Inc.	 	Delaware	
GenOn Chalk Point, LLC	 	Delaware	
GenOn Delta, LLC	 	Delaware	
GenOn Energy Holdings, Inc.	 	Delaware	
GenOn Energy Management, LLC	 	Delaware	
GenOn Energy Services, LLC	 	Delaware	
GenOn Energy, Inc.	 	Delaware	
GenOn Florida GP, LLC	 	Delaware	
GenOn Florida, LP	 	Delaware	
GenOn Fund 2001 LLC	 	Delaware	

 	
 	 	 	
GenOn Gibbons Road, LLC	 	Delaware	
GenOn Kendall, LLC	 	Delaware	
GenOn Key/Con Fuels, LLC	 	Delaware	
GenOn Lovett, LLC	 	Delaware	
GenOn Marsh Landing Holdings, LLC	 	Delaware	
GenOn Marsh Landing, LLC	 	Delaware	
GenOn MD Ash Management, LLC	 	Delaware	
GenOn Mid-Atlantic Development, LLC	 	Delaware	
GenOn Mid-Atlantic, LLC	 	Delaware	
GenOn New York, LLC	 	Delaware	
GenOn North America, LLC	 	Delaware	
GenOn Northeast Generation, Inc.	 	Delaware	
GenOn Northeast Holdings, Inc.	 	Delaware	
GenOn Northeast Management Company	 	Pennsylvania	
GenOn Piney Point, LLC	 	Delaware	
GenOn Potomac River, LLC	 	Delaware	
GenOn Potrero, LLC	 	Delaware	
GenOn Power Generation Assets, LLC	 	Delaware	
GenOn Power Generation, LLC	 	Delaware	
GenOn Power Midwest GP, LLC	 	Delaware	
GenOn Power Midwest, LP	 	Delaware	
GenOn Power Operating Services Midwest, Inc.	 	Delaware	
GenOn REMA Services, Inc.	 	Delaware	
GenOn REMA, LLC	 	Delaware	
GenOn Sabine (Delaware), Inc.	 	Delaware	
GenOn Sabine (Texas), Inc.	 	Delaware	
GenOn Special Procurement, Inc.	 	Delaware	
GenOn Tank Farm, LLC	 	Delaware	
GenOn West GP, LLC	 	Delaware	
GenOn West, LP	 	Delaware	
GenOn Wholesale Generation GP, LLC	 	Delaware	
GenOn Wholesale Generation, LP	 	Delaware	
GenOn Willow Pass, LLC	 	Delaware	
Geostellar, Inc.	 	Delaware	
Gladstone Power Station Joint Venture	 	Australia	
Granite II Holding, LLC	 	Delaware	
Granite Power Partners II, L.P.	 	Delaware	
Green Mountain Energy Company	 	Delaware	
Green Mountain Energy Company (NY COM) LLC	 	Delaware	
Green Mountain Energy Company (NY RES) LLC	 	Delaware	
Gröbener Logistick GmbH - Spedition, Handel und Transport	 	Germany	
Hanover Energy Company	 	California	
High Plains Ranch II, LLC	 	Delaware	
HLE Solar Holdings, LLC	 	Delaware	
HSD Solar Holdings, LLC	 	California	
Hudson Valley Gas Corporation	 	New York	

 	
 	 	 	
Huntley IGCC LLC	 	Delaware	
Huntley Power LLC	 	Delaware	
Independence Energy Alliance LLC	 	Delaware	
Independence Energy Group LLC	 	Delaware	
Independence Energy Natural Gas LLC	 	Delaware	
Indian River Operations Inc.	 	Delaware	
Indian River Power LLC	 	Delaware	
Ivanpah Master Holdings, LLC	 	Delaware	
Ivanpah Project I Holdings, LLC	 	Delaware	
Ivanpah Project II Holdings, LLC	 	Delaware	
Ivanpah Project III Holdings, LLC	 	Delaware	
Jackson Valley Energy Partners, L.P.	 	California	
James River Power LLC	 	Delaware	
Kaufman Cogen LP	 	Delaware	
Keystone Fuels, LLC	 	Delaware	
Keystone Power LLC	 	Delaware	
Lake Erie Properties Inc.	 	Delaware	
Lambique Beheer B.V.	 	Netherlands	
Langford Wind Power, LLC	 	Texas	
Long Beach Generation LLC	 	Delaware	
Long Beach Peakers LLC	 	Delaware	
Long Beach Power LLC	 	Delaware	
Longhorn Energy, LLC	 	Arizona	
Lot 59, LLC	 	Arizona	
Louisiana Generating LLC	 	Delaware	
LSP-Nelson Energy, LLC	 	Delaware	
MC Asset Recovery LLC	 	Delaware	
Meriden Gas Turbines LLC	 	Delaware	
Middletown Power LLC	 	Delaware	
Mirant (Bermuda), Ltd.	 	Bermuda	
Mirant (Navotas II) Corporation	 	Philippines	
Mirant AP Investments Limited	 	British Virgin Islands	
Mirant Asia-Pacific Construction Limited (Hong Kong)	 	Hong Kong	
Mirant Asia-Pacific Ventures, LLC	 	Delaware	
Mirant Intellectual Asset Management and Marketing, LLC	 	Delaware	
Mirant International Investments, Inc.	 	Delaware	
Mirant Navotas Corporation	 	Philippines	
Mirant New York Services, LLC	 	Delaware	
Mirant Power Purchase, LLC	 	Delaware	
Mirant Trust I	 	Delaware	
Mirant Wrightsville Investments, Inc.	 	Delaware	
Mirant Wrightsville Management, Inc.	 	Delaware	
MNA Finance Corp.	 	Delaware	
Monster Energy, LLC	 	Arizona	
Montville IGCC LLC	 	Delaware	
Montville Power LLC	 	Delaware	

 	
 	 	 	
Natural Gas Repowering LLC	 	Delaware	
NEO Chester-Gen LLC	 	Delaware	
NEO Corporation	 	Minnesota	
NEO Freehold-Gen LLC	 	Delaware	
NEO Power Services Inc.	 	Delaware	
Netherlands Antilles Holdco	 	Netherlands Antilles	
Netherlands Holdco	 	Netherlands	
New Genco GP, LLC	 	Delaware	
New Jersey Power Development LLC	 	Delaware	
NINA Construction LLC	 	Delaware	
NINA Investments Holdings LLC	 	Delaware	
NINA Modularization LLC	 	Delaware	
NINA Nuclear Training LLC	 	Delaware	
NINA Steel Investments LLC	 	Delaware	
NINA Texas 3 LLC	 	Delaware	
NINA Texas 4 LLC	 	Delaware	
Norwalk Power LLC	 	Delaware	
NRG Affiliate Services Inc.	 	Delaware	
NRG Alta Vista LLC	 	Delaware	
NRG Artesian Energy LLC	 	Delaware	
NRG Arthur Kill Operations Inc.	 	Delaware	
NRG Asia-Pacific, Ltd.	 	Delaware	
NRG Astoria Gas Turbine Operations Inc.	 	Delaware	
NRG Astoria Power LLC	 	Delaware	
NRG Audrain Generating LLC	 	Delaware	
NRG Audrain Holding LLC	 	Delaware	
NRG Bayou Cove LLC	 	Delaware	
NRG Bluewater Holdings LLC	 	Delaware	
NRG Bluewater Wind Massachusetts LLC	 	Delaware	
NRG Bourbonnais Equipment LLC	 	Delaware	
NRG Bourbonnais LLC	 	Illinois	
NRG Brazos Valley GP LLC	 	Delaware	
NRG Brazos Valley LP LLC	 	Delaware	
NRG Cabrillo Power Operations Inc.	 	Delaware	
NRG Cadillac Inc.	 	Delaware	
NRG Cadillac Operations Inc.	 	Delaware	
NRG California Peaker Operations LLC	 	Delaware	
NRG Capital II LLC	 	Delaware	
NRG Caymans Company	 	Cayman Islands	
NRG Caymans-C	 	Cayman Islands	
NRG Caymans-P	 	Cayman Islands	
NRG Cedar Bayou Development Company, LLC	 	Delaware	
NRG CleanTech Investments LLC	 	Delaware	
NRG Coal Development Company LLC	 	Delaware	
NRG ComLease LLC	 	Delaware	
NRG Common Stock Finance I LLC	 	Delaware	

 	
 	 	 	
NRG Common Stock Finance II LLC	 	Delaware	
NRG Connecticut Affiliate Services Inc.	 	Delaware	
NRG Connecticut Peaking Development LLC	 	Delaware	
NRG Construction LLC	 	Delaware	
NRG Development Company Inc.	 	Delaware	
NRG Devon Operations Inc.	 	Delaware	
NRG DISPATCH SERVICES LLC	 	Delaware	
NRG Dunkirk Operations Inc.	 	Delaware	
NRG El Segundo Operations Inc.	 	Delaware	
NRG Electricity Sales Princeton LLC	 	Delaware	
NRG Energy Center Dover LLC	 	Delaware	
NRG Energy Center Eagles LLC	 	Delaware	
NRG Energy Center Harrisburg LLC	 	Delaware	
NRG Energy Center HCEC LLC	 	Delaware	
NRG Energy Center Minneapolis LLC	 	Delaware	
NRG Energy Center Paxton LLC	 	Delaware	
NRG Energy Center Phoenix LLC	 	Delaware	
NRG Energy Center Pittsburgh LLC	 	Delaware	
NRG Energy Center Princeton LLC	 	Delaware	
NRG Energy Center San Diego LLC	 	Delaware	
NRG Energy Center San Francisco LLC	 	Delaware	
NRG Energy Center Smyrna LLC	 	Delaware	
NRG Energy Center Tucson LLC	 	Arizona	
NRG Energy Jackson Valley I, Inc.	 	California	
NRG Energy Jackson Valley II, Inc.	 	California	
NRG Energy Labor Services LLC	 	Delaware	
NRG Energy Services Group LLC	 	Delaware	
NRG Energy Services LLC	 	Delaware	
NRG Equipment Company LLC	 	Nevada	
NRG ESA Joint Development LLC	 	Delaware	
NRG EV Services LLC	 	Delaware	
NRG Gas Development Company, LLC	 	Delaware	
NRG Gaskell LLC	 	Delaware	
NRG Generation Holdings, Inc.	 	Delaware	
NRG Gladstone Operating Services Pty Ltd	 	Australia	
NRG Granite Acquisition LLC	 	Delaware	
NRG Harrisburg Cooling LLC	 	Delaware	
NRG Holdings, Inc.	 	Delaware	
NRG Home & Business Solutions LLC	 	Delaware	
NRG Home Solutions LLC	 	Delaware	
NRG Home Solutions Product LLC	 	Delaware	
NRG Homer City Services LLC	 	Delaware	
NRG Huntley Operations Inc.	 	Delaware	
NRG Identity Protect LLC	 	Delaware	
NRG Ilion Limited Partnership	 	Delaware	
NRG Ilion LP LLC	 	Delaware	

 	
 	 	 	
NRG Independence Solar LLC	 	Delaware	
NRG International II Inc.	 	Delaware	
NRG International III Inc.	 	Delaware	
NRG International LLC	 	Delaware	
NRG Kaufman LLC	 	Delaware	
NRG Latin America Inc.	 	Delaware	
NRG LC Facility Company LLC	 	Delaware	
NRG Limestone 3, LLC	 	Delaware	
NRG Maintenance Services LLC	 	Delaware	
NRG Merger Sub, Inc.	 	Delaware	
NRG Mesquite LLC	 	Delaware	
NRG Mextrans Inc.	 	Delaware	
NRG MidAtlantic Affiliate Services Inc.	 	Delaware	
NRG Middletown Operations Inc.	 	Delaware	
NRG Montville Operations Inc.	 	Delaware	
NRG Nelson Turbines LLC	 	Delaware	
NRG New Jersey Energy Sales LLC	 	Delaware	
NRG New Roads Holdings LLC	 	Delaware	
NRG NM Suntower LLC	 	Delaware	
NRG North Central Operations Inc.	 	Delaware	
NRG Northeast Affiliate Services Inc.	 	Delaware	
NRG Norwalk Harbor Operations Inc.	 	Delaware	
NRG Operating Services, Inc.	 	Delaware	
NRG Oswego Harbor Power Operations Inc.	 	Delaware	
NRG PacGen Inc.	 	Delaware	
NRG Peaker Finance Company LLC	 	Delaware	
NRG Power Marketing LLC	 	Delaware	
NRG Procurement Company LLC	 	Nevada	
NRG Reliability Solutions LLC	 	Delaware	
NRG Renter's Protection LLC	 	Delaware	
NRG Repowering Holdings LLC	 	Delaware	
NRG Residential Solar Solutions Leasing II LLC	 	Delaware	
NRG Residential Solar Solutions LLC	 	Delaware	
NRG Retail LLC	 	Delaware	
NRG Rockford Acquisition LLC	 	Delaware	
NRG Rockford Equipment II LLC	 	Illinois	
NRG Rockford Equipment LLC	 	Illinois	
NRG Rockford II LLC	 	Illinois	
NRG Rockford LLC	 	Illinois	
NRG Rocky Road LLC	 	Delaware	
NRG Saguaro Operations Inc.	 	Delaware	
NRG SanGencisco LLC	 	Delaware	
NRG Security LLC	 	Delaware	
NRG Services Corporation	 	Delaware	
NRG Sherbino LLC	 	Delaware	
NRG Silver CIty Bond Purchaser LLC	 	Delaware	

 	
 	 	 	
NRG SimplySmart Solutions LLC	 	Delaware	
NRG Solar Alpine II LLC	 	Delaware	
NRG Solar Alpine LLC	 	Delaware	
NRG Solar Anasco LLC	 	Delaware	
NRG Solar Apple II LLC	 	Delaware	
NRG Solar Apple LLC	 	Delaware	
NRG Solar Arrowhead LLC	 	Delaware	
NRG Solar Asset Management LLC	 	Delaware	
NRG Solar AV Holdco LLC	 	Delaware	
NRG Solar Avra Valley LLC	 	Delaware	
NRG Solar Blythe II LLC	 	Delaware	
NRG Solar Blythe III LLC	 	Delaware	
NRG Solar Blythe IV LLC	 	Delaware	
NRG Solar Blythe LLC	 	Delaware	
NRG Solar Blythe V LLC	 	Delaware	
NRG Solar Borrego Holdco LLC	 	Delaware	
NRG Solar Borrego I LLC	 	Delaware	
NRG Solar Borrego II LLC	 	Delaware	
NRG Solar Caribe LLC	 	Delaware	
NRG Solar CVSR Holdings LLC	 	Delaware	
NRG Solar Desert Center II LLC	 	Delaware	
NRG Solar Desert Center LLC	 	Delaware	
NRG Solar DG LLC	 	Delaware	
NRG Solar DOD 1 LLC	 	Delaware	
NRG Solar Green Valley LLC	 	Delaware	
NRG Solar Hyder I LLC	 	Delaware	
NRG Solar Hyder II LLC	 	Delaware	
NRG Solar Hyder III LLC	 	Delaware	
NRG Solar Iguana LLC	 	Delaware	
NRG Solar Isabela LLC	 	Delaware	
NRG Solar Ivanpah LLC	 	Delaware	
NRG Solar Juncos LLC	 	Delaware	
NRG Solar LLC	 	Delaware	
NRG Solar Montecristi LLC	 	Delaware	
NRG Solar Pacific LLC	 	Delaware	
NRG Solar PV LLC	 	Delaware	
NRG Solar Ring LLC	 	Delaware	
NRG Solar Roadrunner Holdings LLC	 	Delaware	
NRG Solar Roadrunner LLC	 	Delaware	
NRG Solar Sabana Grande LLC	 	Delaware	
NRG Solar Santiago LLC	 	Delaware	
NRG Solar SBV LLC	 	Delaware	
NRG Solar SC Stadium LLC	 	Delaware	
NRG Solar Sunora LLC	 	Delaware	
NRG Solar Sunrise LLC	 	Delaware	
NRG Solar Tabernacle LLC	 	Delaware	

 	
 	 	 	
NRG Solar Ventures LLC	 	Delaware	
NRG Solar Wharton LLC	 	Delaware	
NRG South Central Affiliate Services Inc.	 	Delaware	
NRG South Central Generating LLC	 	Delaware	
NRG South Central Operations Inc.	 	Delaware	
NRG South Texas LP	 	Texas	
NRG South Trent Holdings LLC	 	Delaware	
NRG Southaven LLC	 	Delaware	
NRG Sterlington Power LLC	 	Delaware	
NRG SunCap Leasing I LLC	 	Delaware	
NRG Switchyard Energy LLC	 	Delaware	
NRG Telogia Power LLC	 	Delaware	
NRG Texas C&I Supply LLC	 	Delaware	
NRG Texas Holding Inc.	 	Delaware	
NRG Texas LLC	 	Delaware	
NRG Texas Power LLC	 	Delaware	
NRG Texas Retail LLC	 	Delaware	
NRG Thermal LLC	 	Delaware	
NRG Thermal Solar LLC	 	Delaware	
NRG Transmission Holdings LLC	 	Delaware	
NRG UNEMPLOYMENT PROTECTION LLC	 	Delaware	
NRG Victoria I Pty Ltd	 	Australia	
NRG WARRANTY SERVICES LLC	 	Delaware	
NRG West Coast LLC	 	Delaware	
NRG West Holdings LLC	 	Delaware	
NRG West Procurement Company LLC	 	Delaware	
NRG Western Affiliate Services Inc.	 	Delaware	
NRG Wind Development Company, LLC	 	Delaware	
NRG Yieldco, Inc.	 	Delaware	
NRGenerating German Holdings GmbH	 	Switzerland	
NRGenerating International B.V.	 	Netherlands	
NRGenerating Luxembourg (No. 1) S.a.r.l.	 	Luxembourg	
NRGenerating Luxembourg (No. 2) S.a.r.l.	 	Luxembourg	
Nuclear Innovation North America Investments LLC	 	Delaware	
Nuclear Innovation North America LLC	 	Delaware	
O Brien Cogeneration, Inc. II	 	Delaware	
OC Solar 2010, LLC	 	California	
ONSITE Energy, Inc.	 	Oregon	
Orion Power New York GP, Inc.	 	Delaware	
Orion Power New York LP, LLC	 	Delaware	
Orion Power New York, L.P.	 	Delaware	
Oswego Harbor Power LLC	 	Delaware	
P.T. Dayalistrik Pratama	 	Indonesia	
Pacific Crockett Holdings, Inc.	 	Oregon	
Pacific Generation Company	 	Oregon	
Pacific Generation Holdings Company	 	Oregon	

 	
 	 	 	
Pacific-Mt. Poso Corporation	 	Oregon	
PESD Energy, LLC	 	Arizona	
Petra Nova CCS I LLC	 	Delaware	
Petra Nova Holdings LLC	 	Delaware	
Petra Nova LLC	 	Delaware	
Petra Nova Parish Holdings LLC	 	Delaware	
Petra Nova Power I LLC	 	Delaware	
PFMG 2011 Finance Holdco, LLC	 	Delaware	
PFMG Apple I LLC	 	Delaware	
PM Solar Holdings, LLC	 	California	
Project Finance Fund III, L.P.	 	Delaware	
ProSun Solar Development Company, LLC	 	Delaware	
RE Retail Receivables, LLC	 	Delaware	
Reliant Energy Charitable Foundation	 	Delaware	
Reliant Energy Northeast LLC	 	Delaware	
Reliant Energy Power Supply, LLC	 	Delaware	
Reliant Energy Retail Holdings, LLC	 	Delaware	
Reliant Energy Retail Services, LLC	 	Delaware	
RERH Holdings, LLC	 	Delaware	
Roadrunner SunTower, LLC	 	Delaware	
RRI Energy Broadband, Inc.	 	Delaware	
RRI Energy Channelview (Delaware), LLC	 	Delaware	
RRI Energy Channelview (Texas), LLC	 	Delaware	
RRI Energy Channelview LP	 	Delaware	
RRI Energy Communications, Inc.	 	Delaware	
RRI Energy Services Channelview LLC	 	Delaware	
RRI Energy Services Desert Basin, LLC	 	Delaware	
RRI Energy Services, LLC	 	Delaware	
RRI Energy Solutions East, LLC	 	Delaware	
RRI Energy Trading Exchange, Inc.	 	Delaware	
RRI Energy Ventures, Inc.	 	Delaware	
Saale Energie Services GmbH	 	Germany	
Sabine Cogen, L.P.	 	Delaware	
Sachsen Holding B.V.	 	Netherlands	
Saguaro Power Company, a Limited Partnership	 	California	
Saguaro Power LLC	 	Delaware	
San Gabriel Power Generation, LLC	 	Delaware	
San Joaquin Valley Energy I, Inc.	 	California	
San Joaquin Valley Energy IV, Inc.	 	California	
San Joaquin Valley Energy Partners I, L.P	 	California	
Sand Drag LLC	 	Delaware	
SCWFD Energy, LLC	 	Arizona	
Seawall Solar 1 LLC	 	Delaware	
Seawall Solar 10 LLC	 	Delaware	
Seawall Solar 2 LLC	 	Delaware	
Seawall Solar 3 LLC	 	Delaware	

 	
 	 	 	
Seawall Solar 4 LLC	 	Delaware	
Seawall Solar 5 LLC	 	Delaware	
Seawall Solar 6 LLC	 	Delaware	
Seawall Solar 7 LLC	 	Delaware	
Seawall Solar 8 LLC	 	Delaware	
Seawall Solar 9 LLC	 	Delaware	
Seawall Solar Holdings LLC	 	Delaware	
Sherbino I Wind Farm LLC	 	Delaware	
Solar Flagstaff One LLC	 	Delaware	
Solar Pacific LLC	 	Delaware	
Solar Partners I, LLC	 	Delaware	
Solar Partners II, LLC	 	Delaware	
Solar Partners VIII, LLC	 	Delaware	
Solar Power Partners, Inc.	 	Delaware	
Somerset Operations Inc.	 	Delaware	
Somerset Power LLC	 	Delaware	
South Trent Wind LLC	 	Delaware	
SPP AMCo, LLC	 	Delaware	
SPP Asset Holdings, LLC	 	Delaware	
SPP DG DevCo 3a, LLC	 	Delaware	
SPP DG DevCo 4a, LLC	 	Delaware	
SPP DU DevCo, LLC	 	Delaware	
SPP Fund II Holdings, LLC	 	Delaware	
SPP Fund II Master Tenant, LLC	 	Delaware	
SPP Fund II Mgmt, LLC	 	Delaware	
SPP Fund II, LLC	 	Delaware	
SPP Fund II-B, LLC	 	Delaware	
SPP Fund III Construction Holdings, LLC	 	Delaware	
SPP Fund III Holdings, LLC	 	Delaware	
SPP Fund III Master Tenant, LLC	 	Delaware	
SPP Fund III Mgmt, LLC	 	Delaware	
SPP Fund III, LLC	 	Delaware	
SPP GALAXY, INC.	 	Delaware	
SPP III Fundings, LLC	 	Delaware	
SPP Lease Holdings, LLC	 	Delaware	
SPP OpCo, LLC	 	Delaware	
SPP P-IV Construction, LLC	 	Delaware	
SPP P-IV Master Lessee, LLC	 	Delaware	
SPP Selco, LLC	 	Delaware	
Statoil Energy Power/Pennsylvania, Inc.	 	Pennsylvania	
Sun City Project LLC	 	Delaware	
Sunora Energy Construction Holdings LLC	 	Delaware	
Sunora Energy Solutions I LLC	 	Delaware	
Sunora Energy Solutions II LLC	 	Delaware	
Sunora Energy Solutions Limited Partnership	 	Delaware	
Sunora PA Construction Services LLC	 	Delaware	

 	
 	 	 	
Sunshine State Power (No. 2) B.V.	 	Netherlands	
Sunshine State Power B.V.	 	Netherlands	
Tacoma Energy Recovery Company	 	Delaware	
TCV Pipeline, LLC	 	Delaware	
Texas Coastal Ventures, LLC	 	Delaware	
Texas Genco Financing Corp.	 	Delaware	
Texas Genco GP, LLC	 	Texas	
Texas Genco Holdings, Inc.	 	Texas	
Texas Genco LP, LLC	 	Delaware	
Texas Genco Operating Services, LLC	 	Delaware	
Texas Genco Services, LP	 	Texas	
Turners Falls Limited Partnership	 	Delaware	
US Retailers LLC	 	Delaware	
USSV Land Company LLC	 	Delaware	
Vail Energy, LLC	 	Arizona	
Vienna Operations Inc.	 	Delaware	
Vienna Power LLC	 	Delaware	
WCP (Generation) Holdings LLC	 	Delaware	
West Coast Power LLC	 	Delaware	
Wildcat Energy, LLC	 	Arizona	
WSD Solar Holdings, LLC	 	Delaware	

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors
NRG Energy, Inc.:

We consent to the incorporation by reference in the registration statement (No. 333-185501) on Form S-8, (No. 333-182379) on Form S-8, (No. 333-171318) on Form S-8, (No. 333-151992) on Form S-8, (No. 333-135973) on Form S-8, (No. 333-114007) on Form S-8, (No. 333-123677) on Form S-3, (No. 333-183334) on Form S-4, (No. 333-178024) on Form S-4, (No. 333-175470) on Form S-4 and (No. 333-171323) on Form S-4 of NRG Energy, Inc. of our reports dated February 27, 2013, with respect to the consolidated balance sheets of NRG Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income/(loss), cash flows, and stockholders' equity for each of the years in the three-year period ended December 31, 2012, and the related financial statement schedule, and the effectiveness of internal control over financial reporting as of December 31, 2012, which reports appear in the December 31, 2012 annual report on Form 10-K of NRG Energy, Inc.

/s/ KPMG LLP
KPMG LLP

Philadelphia, Pennsylvania
February 27, 2013 

EXHIBIT 31.1
CERTIFICATION
I, David W. Crane, certify that:
 	 	
1.	I have reviewed this annual report on Form 10-K of NRG Energy, Inc.;	
 	 	
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 	 	
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 	 	
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	
 	 	
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 	 	
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 	 	
(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 	 	
(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and	
 	 	
5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):	
 	 	
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and	
 	 	
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.	

 	 	
/s/ DAVID W. CRANE	 	
David W. Crane
Chief Executive Officer
(Principal Executive Officer)	 	
Date: February 27, 2013 

EXHIBIT 31.2
CERTIFICATION
I, Kirkland B. Andrews, certify that:
 	 	
1.	I have reviewed this annual report on Form 10-K of NRG Energy, Inc.;	
 	 	
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 	 	
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 	 	
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	
 	 	
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 	 	
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 	 	
(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 	 	
(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and	
 	 	
5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):	
 	 	
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and	
 	 	
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.	

 	 	
/s/ KIRKLAND B. ANDREWS	 	
Kirkland B. Andrews
Chief Financial Officer
(Principal Financial Officer)	 	
Date: February 27, 2013 

EXHIBIT 31.3
CERTIFICATION
I, Ronald B. Stark, certify that:
 	 	
1.	I have reviewed this annual report on Form 10-K of NRG Energy, Inc.;	
 	 	
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 	 	
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 	 	
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	
 	 	
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 	 	
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 	 	
(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 	 	
(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and	
 	 	
5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):	
 	 	
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and	
 	 	
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.	

 	 	
/s/ RONALD B. STARK	 	
Ronald B. Stark
Chief Accounting Officer
(Principal Accounting Officer)	 	
Date: February 27, 2013 

EXHIBIT 32

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Annual Report of NRG Energy, Inc. on Form 10-K for the year ended December 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer's knowledge:
 	 	
(1)	The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and	
 	 	
(2)	
The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Form 10-K.	
Date: February 27, 2013 

 	 	 	 	 	
 	/s/ DAVID W. CRANE	 	
 	David W. Crane	 	
 	Chief Executive Officer
(Principal Executive Officer) 	 	

 	/s/ KIRKLAND B. ANDREWS	 	
 	Kirkland B. Andrews	 	
 	Chief Financial Officer
(Principal Financial Officer) 	 	

 	/s/ RONALD B. STARK	 	
 	Ronald B. Stark	 	
 	Chief Accounting Officer
(Principal Accounting Officer) 	 	
     The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of this Form 10-K or as a separate disclosure document.
     A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NRG Energy, Inc. and will be retained by NRG Energy, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.