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•	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.

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(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.

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•	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.

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(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.

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(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.

(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.

(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.

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(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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(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).

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(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.

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•	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.

•	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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•	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.

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•	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.

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•	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.

•	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).

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•	General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;

•	Volatile power supply costs and demand for power;

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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.

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(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:

(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.

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

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(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.

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•	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.

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•	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.

•	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.

•	Higher net income — Net income increased 194% from $197 million to $579 million, as discussed in further detail below.

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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.

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(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.

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•	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 $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.

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(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.

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(a)	Other gross margin primarily represents revenues from the maintenance services business, which are eliminated in consolidation.

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(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:

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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.

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(a)	Represents the elimination of the intercompany activity between the Retail Business and the Conventional Generation regions.

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◦	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.

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•	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;

•	Increase in marketing and selling costs of $51 million associated with customer growth efforts and new market expansion by corporate and the Retail Business;

•	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.

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(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.

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(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.

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(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:

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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.

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(a)	Represents the elimination of the intercompany activity between the Retail Business and the Conventional Generation regions and Alternative Energy.

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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.

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•	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.

•	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.

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(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.

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•	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.

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(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.

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•	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.

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•

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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•	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.

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•	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.

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(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.

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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.

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(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.

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•	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.

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•	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.

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•	ASU No. 2011-11, Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities

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•	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.

(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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(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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(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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(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.

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•	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.

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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.

•	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.

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•	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.

•	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.

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(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.

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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 NOx allowances amortized on a straight-line basis and SO2 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 SO2 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.

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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.

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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.

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(a)	L+ equals LIBOR plus x%.

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(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.

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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.

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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%.

•	incur indebtedness and liens and enter into sale and lease-back transactions;

•	make investments, loans and advances; and

•	return capital to stockholders.

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

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

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(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.

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(a)	As of December 31, 2012, the maximum remaining term under any individual purchased power contract is five years.

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(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.

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

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

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

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

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

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

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

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

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

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

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

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(a)	Represents principally net amounts charged as uncollectible.

(b)	Includes amounts associated with the GenOn acquisition.

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