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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, 2016, 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 GWh based on forward market implied heat rate as of December 31, 2016, and then combined with power sales to arrive at equivalent GWh 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.

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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, 2016, 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 GWh based on forward market implied heat rate as of December 31, 2016, and then combined with power sales to arrive at equivalent GWh 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.

•

Capacity auctions — The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE, and NYISO. Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time performance, where NRG's actual revenues will be the combination of revenues based on the cleared auction MWs plus the net of any over- and under-performance of NRG's fleet. In addition, MISO has an annual auction, known as the Planning Resource Auction, or PRA. The Gulf Coast assets situated in the MISO market may participate in this auction.  Recent changes have made the decision to import external capacity into the PJM market more complicated, and the Company is evaluating the feasibility of continuing to import.

•

Resource Adequacy and bilateral contracts — In California, there is a resource adequacy requirement that is satisfied through bilateral contracts. The Company's newer generation in California is contracted under long-term tolling agreements. Certain other sites in California have short-term tolling agreements or resource adequacy contracts. In addition, NRG earns demand payments from its long-term full-requirements load contracts with nine Louisiana distribution cooperatives, which expire in 2025. NRG also had full requirements contracts in PJM in 2016.  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. In Texas, capacity and contracted revenues are through bilateral contracts with load serving entities.

•	Long-term PPAs — Output from the majority of renewable energy assets and certain conventional energy plants is sold through long-term PPAs and tolling agreements to a single counterparty, which is often a utility or commercial customer.

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(a)	Includes expected coal inventory draw down.

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(a)	NRG Yield includes thermal generation.

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(a)	MWh information reflects the Company's undivided interest in total MWh generated by STP.

(b)	Total NRG Yield includes thermal heating and chilled water generation.

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(a)	Primarily consists of revenues generated by the Thermal business (NRG Yield segment), operation and maintenance revenues and unrealized trading activities, primarily at BETM (Generation segment).

(b)	Energy revenues include inter-segment sales primarily between Generation and Retail.

(c)	Primarily consists of revenues generated by the Thermal business (NRG Yield segment), operation and maintenance revenues and unrealized trading activities, primarily at BETM (Generation segment).

(d)	Energy revenues include inter-segment sales primarily between Generation and Retail.

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(e)	Primarily consists of revenues generated by the Thermal business (NRG Yield segment), operation and maintenance revenues and unrealized trading activities, primarily at BETM (Generation segment).

(f)	Energy revenues include inter-segment sales primarily between Generation and Retail.

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•	changes in generation capacity in the Company’s markets, including the addition of new supplies of power as a result of the development of new plants, expansion of existing plants, the continued operation of uneconomic power plants due to state subsidies, or additional transmission capacity;

•	environmental regulations and legislation;

•	electric supply disruptions, including plant outages and transmission disruptions;

•	changes in power transmission infrastructure;

•	fuel transportation capacity constraints or inefficiencies;

•	weather conditions, including extreme weather conditions and seasonal fluctuations, including the effects of climate change;

•	changes in commodity prices and the supply of commodities, including but not limited to natural gas, coal and oil;

•	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, new technologies and new forms of competition for the production of power;

•	fuel price volatility;

•	economic and political conditions;

•	regulations and actions of the ISOs and RTOs;

•	federal and state power regulations and legislation;

•	changes in law, including judicial decisions;

•	changes in prices related to RECs; and

•	changes in capacity prices and capacity markets.

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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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•	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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•	inability to obtain sufficient funding on reasonable terms and/or necessary government financial incentives;

•	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, including those related to climate change;

•	unanticipated cost overruns;

•	exchange rate risks; and

•	failure of contracting parties to perform under contracts, including EPC contractors.

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•	multiple and potentially conflicting laws, regulations and policies that are subject to change;

•	imposition of currency restrictions on repatriation of earnings or other restraints;

•	imposition of burdensome tariffs or quotas;

•	national and international conflict, including terrorist acts; and

•	political and economic instability or civil unrest that may severely disrupt economic activity in affected countries.

•	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.

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•	GenOn's and certain of its subsidiaries' ability to continue as a going concern;

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

•	Volatile power supply costs and demand for power;

•

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

•	The effectiveness of NRG's risk management policies and procedures, and the ability of NRG's counterparties to satisfy their financial commitments;

•	Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition;

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

•	NRG's ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;

•	The liquidity and competitiveness of wholesale markets for energy commodities;

•	Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws and increased regulation of carbon dioxide and other GHG emissions;

•	Changes in law, including judicial decisions;

•	Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately and fairly compensate NRG's generation units;

•	NRG's ability to mitigate forced outage risk for units subject to capacity performance requirements in PJM, performance incentives in ISO-NE, and scarcity pricing in ERCOT;

•	NRG's ability to borrow 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 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 2016 Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;

•	Cyber terrorism and inadequate cybersecurity, or the occurrence of a catastrophic loss and the possibility that NRG may not have adequate insurance to cover losses resulting from such hazards or the inability of NRG's insurers to provide coverage;

•	NRG's ability to develop and build new power generation facilities, including new renewable projects;

•	NRG's ability to develop and innovate new products as retail and wholesale markets continue to change and evolve;

•	NRG's ability to implement its strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources while taking advantage of business opportunities;

•	NRG's ability to increase cash from operations through operational and commercial initiatives, corporate efficiencies, asset strategy, and a range of other programs throughout NRG to reduce costs or generate revenues;

•	NRG's ability to sell assets to NRG Yield, Inc. and to close drop-down transactions;

•	NRG's ability to achieve its strategy of regularly returning capital to stockholders;

•	NRG's ability to obtain and maintain retail market share;

•	NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives;

•	NRG's ability to engage in successful mergers and acquisitions activity;

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•	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)	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.

(b)	Generation capacity figure consists of the Company's 44% interest in the two units at STP.

(c)	W.A. Parish Unit Petra Nova GT2 (75 MW of the 1,220 MW at W.A. Parish Natural Gas) was mothballed for part of 2016 in connection with the Petra Nova project and returned to service in the fourth quarter of 2016.

(d)

GenOn Mid-Atlantic leases 100% interests in the Dickerson and Morgantown coal generation units through facility lease agreements expiring in 2029 and 2034, respectively. GenOn Mid-Atlantic owns 312 MW and 248 MW of peaking capacity at the Dickerson and Morgantown generating facilities, respectively. REMA also leases a 100% interest in Shawville through a facility lease agreement expiring in 2026. GenOn operates the Dickerson, Morgantown and Shawville facilities.

(e)	NRG leases 100% interests in the Powerton facility and Units 7 and 8 of the Joliet facility through facility lease agreements expiring in 2034 and 2030, respectively.  NRG owns 100% interest in Joliet Unit 6.  NRG operates the Powerton and Joliet facilities.

(f)	Dual interconnect between TVA and MISO.

(g)	These units are located on property owned by SDG&E under an annual license agreement. The Miramar and El Cajon sites (51 MW) retired on January, 1, 2017.

(h)	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.

(i)	REMA has 16.45% and 16.67% leased interests in the Conemaugh and Keystone facilities, respectively, with NRG holding a 3.7% ownership interest in each facility. GenOn operates the Conemaugh and Keystone facilities.

(j)	Denotes a GenOn or GenOn subsidiary property.

(k)	GenOn Americas Generation deactivated Pittsburg on January 1, 2017.

(l)	NRG plans to deactivate Encina Unit 1 on March 1, 2017.

(m)	Capacity attributable to noncontrolling interest for these Renewables facilities was 638 MWs as of December 31, 2016.

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

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(a)	Excludes impairment losses and impairment losses on investments.

(b)	Includes goodwill impairment as described in Item 15 - Note 11, Goodwill and Other Intangibles, to the Consolidated Financial Statements.

(c)

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 excludes collateral funds deposited by counterparties of $2 million, $106 million, and $271 million as of December 31, 2016, 2015, and 2014, 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.

(d)	Includes debt issuance cost in 2016, 2015 and 2014.

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•	Executive Summary, including the business environment in which NRG operates, a discussion of regulation, weather, competition and other factors that affect the business, and significant events that are important to understanding the results of operations and financial condition;

•	Results of operations, including an explanation of significant differences between the periods in the specific line items of 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.

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•	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.

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•	Acquisitions — During 2016, the Company completed the acquisition of approximately 1,000 MWs of utility-scale solar and wind assets and 29 MWs of distributed generation assets as discussed in more detail in Item 15 - Note 3, Business Acquisitions and Dispositions, to the Consolidated Financial Statements.

•	Dispositions — During 2016, the Company completed the sale of its Seward, Shelby, Rockford and Aurora generating stations. In addition, the Company completed the sale of its majority interest in the EVgo business and the sale of real property at the Potrero site, as discussed in more detail in Item 15 - Note 3,  Business Acquisitions and Dispositions, to the Consolidated Financial Statements.

•	Debt Issuances — During 2016, the Company issued approximately $2.3 billion in recourse debt, approximately $0.5 billion in non-recourse debt and replaced its Term Loan Facility as discussed in more detail in Item 15 - Note 12, Debt and Capital Leases, to the Consolidated Financial Statements.

•	Debt Repurchases — During 2016, the Company repurchased $3.0 billion in aggregate principal of outstanding Senior Notes for $3.1 billion, including accrued interest, as discussed in more detail in Item 15 - Note 12, Debt and Capital Leases, to the Consolidated Financial Statements.

•	Preferred Stock Repurchase — On June 13, 2016, the Company completed the repurchase from Credit Suisse of 100% of the outstanding shares of its $344.5 million 2.822% preferred stock at a price of $226 million.

•	Impairment losses — During 2016, the Company recorded impairment losses of $918 million related to various facilities, as well as goodwill for its Texas reporting units, as discussed in more detail in Item 15 — Note 10, Asset Impairments and Note 11, Goodwill and Other Intangibles, to the Consolidated Financial Statements.

•	Impairment losses on investments — During 2016, the Company recorded impairment losses of $268 million related to various investments as discussed in more detail in Item 15 — Note 10, Asset Impairments to the Consolidated Financial Statements.

•

Transfers of Assets under Common Control — On September 1, 2016, the Company sold its remaining 51.05% interest in CVSR Holdco LLC, which indirectly owns the CVSR solar facility, to NRG Yield, Inc. for total cash consideration of $78.5 million, plus an immaterial working capital adjustment. NRG Yield, Inc. also assumed additional debt of $496 million, which represents 51.05% of the CVSR project level debt and 51.05% of the notes issued under the CVSR Holdco Financing Agreement. In connection with the retrospective adjustment of prior periods, the Company now consolidates CVSR and 100% of its debt, consisting of $771 million of project level debt and $200 million of notes issued under the CVSR Holdco Financing Agreement as of September 1, 2016.

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Fleet Optimization — The Company completed four coal-to-gas projects at the Big Cajun II, Joliet, Shawville and New Castle Generating Stations. Collectively, the modified units can generate more than 2,780 MW. Given the anticipated reductions in carbon emissions resulting from these modifications, combined with the expected operating profiles for the units, the four plants are expected to reduce their combined carbon footprint by more than 80%.

•	Petra Nova Project Completion — The Company announced that its Petra Nova Carbon Capture Project, or the Petra Nova Project, reached commercial operation in the fourth quarter of 2016. The Petra Nova Project is a commercial-scale carbon capture system that captures CO2 in the processed flue gas from an existing unit at the WA Parish power plant in Fort Bend County, southwest of Houston.

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Cottonwood Flooding — During March 2016, NRG's Cottonwood generating station was damaged by record flooding of the nearby Sabine River.  The generating station was returned to service in the third quarter of 2016.  The Company expects the restoration costs to be reimbursed through insurance recoveries. Through December 31, 2016, the Company has expensed $2 million and collected $27.5 million of insurance proceeds from property damage and $10 million of insurance proceeds from business interruption insurance. The Company is continuing to work with insurers on further property and business interruption insurance recovery. The Company does not anticipate recognizing additional expenses related to restoration costs.

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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 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 intercompany sales of $4 million and $6 million in 2016 and 2015, respectively, representing sales from Retail to the Gulf Coast region.

(b)	Includes intercompany purchases of $994 million and $1,054 million in 2016 and 2015, respectively.

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

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(a)	Includes the results of EME from April 1, 2014, to December 31, 2014

(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)	Includes intercompany sales of $6 million and $7 million in 2015 and 2014, respectively, representing sales from Retail to the Gulf Coast region.

(b)	Includes intercompany purchases of $1,054 million and $1,846 million in 2015 and 2014, respectively.

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

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

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(a)	Includes reserves primarily for debt service, performance obligations, and capital expenditures

(b)	GenOn has the ability to draw on letters of credit associated with their intercompany revolving credit agreement with NRG. As of December 31, 2016, $272 million of letters of credit were outstanding under this agreement for GenOn. Of this amount, $199 million were issued on behalf of GenOn Americas Generation, which includes $128 million issued on behalf of GenOn Mid-Atlantic.

(c)	See Restricted Payments Tests, described below.

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

(b)	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 and EME (including Midwest Generation) acquisitions, assets in NRG Yield, Inc. and NRG's assets that have project-level financing.

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•	Environmental capital expenditures — For the year ended December 31, 2016, the Company's environmental capital expenditures included DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion to satisfy CPS as well as controls to satisfy MATS at the Avon Lake Facility.

•	Growth Investments capital expenditures — For the year ended December 31, 2016, the Company's growth investment capital expenditures included $315 million for solar projects, $32 million for wind projects, $107 million for fuel conversions, $96 million for repowering projects, $4 million for thermal projects and $38 million for the Company's other growth projects.

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(a)	Excludes $34 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 $940 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. 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 consider market prices for the first five-year period and the Company's fundamental view for the longer term, which reflect the Company's long-term view of the price of natural gas. The Company's fundamental view for the longer term reflects the implied power price and heat rate that would support new build of a combined cycle gas plant in the Texas region. The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants. Hedging is included to the extent of contracts already in place;

◦	The Company's estimate of generation, fuel costs, capital expenditure requirements and the existing and anticipated impact of environmental regulations;

◦	The Company's fundamental view for the longer term, cash flows for the plants in the region were included in the fair value calculation through the end of each plants' estimated useful life; and

◦	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 the Texas reporting unit were as follows:

◦	The discount rate applied to internally developed cash flow projections for the 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 Texas for synergies it provides to NRG’s retail businesses. The estimates of annual collateral cost savings resulting from utilizing the Company's wholesale generation assets to provide supply to retail represent the cost of collateral that would otherwise need to be held in reserve to support potential postings to third parties in the case of a significant price move. This is calculated from a combination of the volume the Company would otherwise need to buy from these third parties, based on historical volumes, and historical price movements calibrated to an appropriate probability. The estimates of annual supply cost savings are based on historical volumes of retail purchases from Texas, an average bid-ask spread based on broker quotes and the assumption that Texas will realize half of the benefits associated with this savings.

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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 uranium and coal transportation contracts because of the unavailability of market prices.

(b)	The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts.

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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 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 8, 2014. As of December 31, 2016, there were 667,819 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 240,596 at a weighted-average exercise price of $36.72. See Item 15 — Note 20, Stock-Based Compensation, to Consolidated Financial Statements for a discussion of the NRG GenOn LTIP.

(3)	Consists of 7,487,058 shares of common stock under NRG's LTIP, 960,904 shares of common stock under the NRG GenOn LTIP, and 667,819 shares of treasury stock reserved for issuance under the ESPP. In the first quarter of 2017, 282,530 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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•	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 certain key and highly compensated employees and a total return swap that does not meet the definition of a derivative.

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(a)	Primarily consists of mutual funds held in a rabbi trusts for non-qualified deferred compensation plans for certain former employees and a total return swap that does not meet the definition of a derivative.

(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)	The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts.

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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 counterparties 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; and

•	Weather and hurricane derivative products used to mitigate a portion of retail's lost revenue due to weather.

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•	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 the Company's power plants; and

•	Fixing the price of a portion of anticipated power purchases for the Company's retail sales.

•	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 2031;

•	Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG's generation assets through 2018; and

•	Other energy derivatives instruments extending through 2024.

•	Load-following forward electric sale contracts extending through 2026;

•	Power tolling contracts through 2039;

•	Coal purchase contracts through 2021;

•	Power transmission contracts through 2025;

•	Natural gas transportation contracts and storage agreements through 2030; and

•	Coal transportation contracts through 2029.

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(a)	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, 2016, the Company recorded an impairment loss of $23 million to reduce the value of excess SO2 allowances to zero.

•	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.

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Customer relationships — These intangibles represent the fair value at the acquisition date of acquired businesses' customer base, primarily for Dominion, 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. During the year ended December 31, 2016, the Company recorded an impairment loss of $8 million for certain customer relationships.

•	Marketing partnerships — Established with the acquisition of Energy Plus, 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, Energy Plus and Dominion acquisitions, these intangibles are amortized to depreciation and amortization expense, on a straight-line basis.

•	Power purchase agreements — Established predominantly with the EME and Alta Wind acquisitions, these represent the fair value of PPAs acquired. These will be amortized to revenues, generally on a straight-line basis, over the terms of the PPAs.

•	Other — Consists of renewable energy credits, wind leasehold rights, costs to extend the operating license for STP Units 1 and 2, and the intangible asset related to a purchased ground lease. During the year ended December 31, 2016, the Company recorded an impairment loss of $15 million of other intangible assets.

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(a)	As of December 31, 2016, L+ equals 3 month LIBOR plus x%, with the exception of the Viento term loan, which is 6 month LIBOR plus x% and the Alpine term loan, the NRG Marsh Landing term loan, the Walnut Creek loan, and 2023 Term Loan Facility, which are 1 month LIBOR plus x%.

(a)	Term loan facility, due 2018 replaced with the Term loan facility due 2023. Discount of $1 million was related to current maturities in 2016.

(b)	Repaid in 2016.

(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.

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A $1.9 billion term loan facility, or the 2023 Term Loan Facility, with a maturity date of June 30, 2023, which will pay interest at a rate of LIBOR plus 2.75%, with a LIBOR floor of 0.75%. The debt was issued at 99.50% of face value; the discount will be amortized to interest expense over the life of the loan. Repayments under the 2023 Term Loan Facility will consist of 0.25% of principal per quarter, with the remainder due at maturity. The proceeds of the new term loan facility as well as cash on hand were used to repay the 2018 Term Loan Facility balance outstanding. A $21 million loss on extinguishment of the Term Loan Facility was recorded during the second quarter of 2016, which consisted of the write-off of previously deferred financing costs. On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%, the LIBOR floor remains 0.75%.

•	A $289 million revolving senior credit facility, or the Tranche A Revolving Facility, with a maturity date of July 1, 2018 and a $2.2 billion revolving senior credit facility, or the Tranche B Revolving Facility, with a maturity date of June 30, 2021, which will pay interest at a rate of LIBOR plus 2.25%.

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(a)	As of December 31, 2016, 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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(a)	The ratio coverage for the year ended December 31, 2016, 2015, 2013, and 2012 was less than 1:1. NRG would have needed to generate additional earnings of $575 million, $5,010 million, $567 million, and $137 million, respectively, to achieve a ratio coverage of 1:1 for those years.

(a)	The ratio coverage for the year ended December 31, 2016, 2015, 2013, and 2012 was less than 1:1. NRG would have needed to generate additional earnings of $583 million, $5,042 million, $581 million, and $151 million, respectively, to achieve a ratio coverage of 1:1.

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1.	I have reviewed this annual report on Form 10-K of NRG Energy, Inc.;

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

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

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

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

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

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

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

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

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

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

1.	I have reviewed this annual report on Form 10-K of NRG Energy, Inc.;

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

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

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

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

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

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

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

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

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

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

1.	I have reviewed this annual report on Form 10-K of NRG Energy, Inc.;

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

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

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

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

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

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

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

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

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

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

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

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