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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, 2013, 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, 2013, 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 U.S. Coal and Nuclear sales, including energy revenue and demand charges. For purpose of consistency, rail rates for South Central were held constant.

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(a)	Net Coal 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, 2013, 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, 2013, 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 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 sales as described in (c) above divided by the forecasted Coal capacity.

(e)	Represents U.S. Coal sales, including energy revenue and demand charges, excluding revenues derived from capacity auctions.

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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.

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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 the costs associated with new or changed environmental laws or regulations. MISO has a Resource Adequacy Construct and an annual auction, known as the Planning Resource Auction, or PRA. In April, MISO will conduct the PRA for Planning Year 2014-2015 that will begin on June 1, 2014. The South Central assets situated in the MISO market may participate in this auction.  In certain circumstances, capacity from this region may be sold into the PJM market.

•	West — The region's newer generation is contracted under long-term tolling agreements. Certain other sites have short-term tolling agreements or Resource Adequacy contracts.

•	Texas — The region's sources of capacity and contracted revenues are through bilateral contracts with load serving entities.

•	Other Conventional — 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.

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NRG Yield — NRG Yield's share of renewable and conventional energy plants is generally sold through long-term PPAs and tolling agreements. Its share of the GenConn plants in Connecticut also earns fixed payments under long-term financial contracts with a utility counterparty and output from NRG Yield's share of 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. Two of the PJM generation assets participate in the PJM capacity markets.

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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)	Energy revenues include inter-segment sales primarily between Texas and East, and the Retail Business.

(c)	Primarily consists of revenues generated by the Thermal business, operation and maintenance revenues and unrealized trading activities.

(d)	Total operating revenues includes GenOn revenues of $73 million for the period from December 15, 2012 to December 31, 2012.

(e)	Energy revenues include inter-segment sales primarily between Texas and East, and the Retail Business.

(f)	Retail revenues include Energy Plus revenues of $63 million for the period from October 1, 2011, to December 31, 2011.

(g)	Primarily consists of revenues generated by the Thermal business, operation and maintenance revenues and unrealized trading activities.

(h)	Energy revenues include inter-segment sales primarily between Texas and East, and the Retail Business.

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(a)	NRG Yield excludes thermal generation.

(b)	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.

(c)	Net Generation includes GenOn generation for the period from December 15, 2012 through December 31, 2012.

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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)	Total NRG Yield excludes thermal generation.

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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 51.05% stake of CVSR and owns a 65.5% stake of NRG Yield Inc.'s 48.95% stake of CVSR, for a total 83% stake in the 250 MW CVSR project, of which NRG consolidates its interest.

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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, distributed generation, and more efficient end-use technologies;

•	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.

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•	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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•	inability to receive U.S. DOE loan guarantees, funding or cash grants;

•	delays in obtaining necessary permits and licenses;

•	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.

•	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.

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•	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, realize cost savings and manage any acquired businesses; and

•	NRG's ability to develop and maintain successful partnering relationships.

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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 2013.

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(f)	NRG intends to add natural gas capabilities at the Avon Lake and New Castle facilities, which projects are expected to be completed by the summer of 2016. NRG also intends to add natural gas capabilities at the Big Cajun II and Dunkirk plants which projects are expected to be completed by the spring of 2015 and the fall of 2015, respectively.

(g)	On November 29, 2013, NRG submitted a notice of deactivation to retire Chalk Point Units 1 and 2, and Dickerson Units 1, 2, and 3 on May 31, 2017.  The deactivation is based on draft environmental regulations that, if adopted, could require uneconomic capital investment and render the units uneconomic to operate going forward.

(h)	NRG has submitted deactivation notices for net generation capacity at the following facilities acquired through the GenOn Merger:

(i)	NRG expects to place the coal-fired units at the Shawville generating facility (597 MW) in long-term protective layup in April 2015.

(j)	Units 1 and 2 owned 100.0%, Unit 3 owned 58.0%.

(k)	NRG operates these units, located on property owned by San Diego Gas & Electric, under a license agreement which is set to end on December 31, 2015.

(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.

(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 $63 million, $271 million, and $258 million as of December 31, 2013, 2012, and 2011, 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.

(b)	The Company recorded impairment losses in 2013 and 2011 as further described in Item 15 - Note 10, Asset Impairments.

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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 2013 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.

•	Lower net income — Net income decreased $667 million, as discussed in further detail below.

•	GenOn acquisition — On December 14, 2012, NRG completed the acquisition of GenOn and recorded a bargain purchase gain on the acquisition. In December 2013, the Company finalized acquisition accounting for the acquisition, as discussed in more detail in Item 15 - Note 3 - Business Acquisitions and Dispositions.

•	Long-term debt — During 2013, the Company increased its non-recourse debt by approximately $669 million primarily in connection with the financing of the construction and acquisition of various solar facilities and the construction of the ESEC and Marsh Landing natural gas facilities.

•	Impairment Losses — During the fourth quarter of 2013, the Company recognized impairment losses on its Indian River facility and Gladstone investment, as discussed in more detail in Item 15 - Note 10, Asset Impairments.

•	NRG Yield, Inc. initial public offering — During the third quarter of 2013, NRG Yield, Inc. completed its initial public offering of its Class A common shares at a price of $22 per share, which represents 34.5% of NRG Yield.

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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.

(c)	Includes unrealized trading gains and losses.

(d)	Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits.

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•	in the current year, impairment losses associated with the Indian River facility and the investment in Gladstone;

•	increased operating costs of $1,218 million including operations and maintenance expense, depreciation and amortization, selling, general and administrative costs and development costs as well as acquisition-related transaction and integration costs, primarily associated with the acquisition of GenOn; and

•	a decrease from net mark-to-market results for economic hedging activities of $17 million;

•	an increase in gross margin of $1,599 million comprised of an increase in Conventional Generation gross margin of $1,402 million, primarily associated with the acquisition of GenOn, an increase in NRG Yield gross margin of $135 million and an increase in Alternative Energy gross margin of $101 million, offset by a decrease in Retail gross margin of $39 million; and

•	the bargain purchase gain related to the GenOn acquisition.

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(a)	Yield MWh generated excludes thermal facilities.

(b)	MWh sold excludes generation at facilities that generate revenue under capacity agreements.

(c)

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 2013 and 2012, representing sales from Retail to the Texas region.

(c)	Includes intercompany purchases of $2,097 million and $1,687 million, respectively.

(d)	Includes customers of the Texas General Land Office for which the Company provides services.

(e)	Excludes utility partner and natural gas customers.

•	Retail gross margin — Retail gross margin decreased $39 million for the year ended December 31, 2013, compared to the same period in 2012, driven by

•	Trends — Customer counts increased by approximately 65,000 since December 31, 2012. Competition and higher supply costs based on forward natural gas prices and higher heat rates could drive lower unit margins in the future.

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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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•	Increase in general and administrative costs for GenOn, which was acquired in December 2012, offset by cost savings as a result of realized synergies for the combined company, offset by;

•	Impact of prior year EPA settlement regarding LaGen of $14 million and CDWR settlement of $20 million; and

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(a)	Includes the results of GenOn from December 15, 2012 to December 21, 2012.

(b)	Includes realized gains and losses from financially settled transactions.

(c)	Includes unrealized trading gains and losses.

(d)	Includes amortization of SO2 and NOx credits and excludes amortization of RGGI.

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(a)	Yield MWh generated excludes thermal facilities.

(b)	MWh sold excludes generation at facilities that generate revenue under capacity agreements.

(c)

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, 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 and natural gas customers.

•	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 from 2011 to 2012, 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 and NRG Yield operations and maintenance expense — increased as additional solar facilities, including 253 MW of Agua Caliente and 127 MW of CVSR, and Roadrunner began commercial operations in late 2011 and 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;

•	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.

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(a)	Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region.

(b)	2014 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, 2013, the Company's environmental capital expenditures included $38 million related to the upgrades at Conemaugh including the installation of selective catalytic reduction technology on both units for enhanced mercury oxidation and removal as well as reduction in NOx emissions and the completion of upgrades to the existing flue-gas desulfurization systems for enhanced performance.

•	Growth Investments capital expenditures — For the year ended December 31, 2013, the Company's growth investment expenditures included $1.2 billion for solar projects and $279 million for the Company's other growth projects.

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(a)	Excludes $60 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 $629 million of asset retirement obligations which are discussed in Item 15 — Note 13, 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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The Company applied a discounted cash flow methodology to the long-term budgets for all of the plants in the region. This approach is consistent with that used to determine fair value associated with the Company's three solid-fuel plants and the Cedar Bayou facility in prior years. For the current year, the Company applied this methodology to all of the plants. 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;

◦	The terminal value in year 2019 is calculated using the Gordon Growth Model, which assumes that the terminal value grows at a constant rate in perpetuity;

◦	Projected generation and resulting energy gross margin in the long-term budgets is based on an hourly dispatch that simulates dispatch of each unit into the power market. The dispatch simulation is based on power prices, fuel prices, and the physical and economic characteristics of each plant.

•	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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•	Falling or 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.

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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, 2013, there were 888,388 shares reserved from the Company's treasury shares for 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 1,053,719 at a weighted-average exercise price of $56.79. See Item 15 — Note 20, Stock-Based Compensation, to Consolidated Financial Statements for a discussion of the NRG GenOn LTIP.

(3)	Consists of 7,238,065 shares of common stock under NRG's LTIP, 1,053,485 shares of common stock under the NRG GenOn LTIP, and 888,388 shares of treasury stock reserved for issuance under the ESPP. In the first quarter of 2014, 71,478 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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•	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.

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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.

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(a)	Consists primarily of mutual funds held in a Rabbi Trust for non-qualified deferred compensation plans for some key and highly compensated employees and a total return swap that does not meet the definition of a derivative.

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

(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.

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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 2019.

•	Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG's generation assets through 2017.

•	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 2038;

•	Coal purchase contract through 2020;

•	Power transmission contracts through 2015;

•	Natural gas transportation contracts and storage agreements through 2028; and

•	Coal transportation contracts through 2020.

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(a)	Primarily relates to Agua Caliente, Alpine, Borrego, El Segundo Energy Center and CVSR's 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.

(b)	NRG entered into a long-term $35 million note receivable facility with Avenal Solar Holdings LLC, to fund project liquidity needs in 2011.

(c)	The current portion of notes receivable is recorded in prepayments and other current assets on the consolidated balance sheets.

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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 24, 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, Green Mountain Energy, Energy Systems and Energy Curtailment Specialists. 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.

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(a)	As of December 31, 2013, L+ equals 3 month LIBOR plus x%, with the exception of NRG Solar Alpine LLC cash grant loan and NRG Solar Kansas South LLC and TA - High Desert LLC cash grant bridge loan which are 1 month LIBOR plus x% and NRG Solar Kansas South LLC term loan which is 3 month LIBOR plus x%

(b)	Debt related to projects in NRG Yield

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(a)	Discount of $1 million is related to current maturities in 2013 and 2012.

(b)	Discounts of $4 million and $5 million are related to current maturities in 2013 and 2012, respectively.

(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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•	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, 2013, the maximum remaining term under any individual purchased power contract is five years.

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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.

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