UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

SCHEDULE 14A

Proxy Statement Pursuant to Section 14(a) of the

Securities Exchange Act of 1934

(Amendment No.    )

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GENON ENERGY, INC.
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Third Quarter 2012 Earnings November 9, 2012

Safe Harbor In addition to historical information, the information presented in this communication includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act. These statements involve estimates, expectations, projections, goals, assumptions, known and unknown risks and uncertainties and can typically be identified by terminology such as "may," "will," "should," "could," "objective," "projection," "forecast," "goal," "guidance," "outlook," "expect," "intend," "seek," "plan," "think," "anticipate," "estimate," "predict," "target," "potential" or "continue" or the negative of these terms or other comparable terminology. Such forward-looking statements include, but are not limited to, statements about the anticipated benefits of the proposed transaction between NRG and GenOn, our and the combined company's future revenues, income, indebtedness, capital structure, plans, expectations, objectives, projected financial performance and/or business results and other future events, each party's views of economic and market conditions, and the expected timing of the completion of the proposed transaction. Forward-looking statements are not a guarantee of future performance and actual events or results may differ materially from any forward-looking statement as result of various risks and uncertainties, including, but not limited to, those relating to: the ability to satisfy the conditions to the proposed transaction between NRG and GenOn, the ability to successfully complete the proposed transaction (including any financing arrangements in connection therewith) in accordance with its terms and in accordance with expected schedule, the ability to obtain necessary approvals for the proposed transaction, or an inability to obtain them on the terms proposed or on the anticipated schedule, diversion of management attention on transaction-related issues, impact of the transaction on relationships with customers, suppliers and employees, the ability to finance the combined business post-closing and the terms on which such financing may be available, the financial performance of the combined company following completion of the proposed transaction, the ability to successfully integrate the businesses of NRG and GenOn, the ability to realize anticipated benefits of the proposed transaction (including expected cost savings and other synergies) or the risk that anticipated benefits may take longer to realize than expected, legislative, regulatory and/or market developments, the outcome of pending or threatened lawsuits, regulatory or tax proceedings or investigations, the effects of competition or regulatory intervention, financial and economic market conditions, access to capital, the timing and extent of changes in law and regulation (including environmental), commodity prices, prevailing demand and market prices for electricity, capacity, fuel and emissions allowances, weather conditions, operational constraints or outages, fuel supply or transmission issues, hedging ineffectiveness. Additional information concerning other risk factors is contained in GenOn's most recent Annual Report on Form 10-K, subsequent Quarterly Reports on Form 10-Q, recent Current Reports on Form 8-K, and other Securities and Exchange Commission ("SEC") filings. Many of these risks, uncertainties and assumptions are beyond GenOn's ability to control or predict. Because of these risks, uncertainties and assumptions, you should not place undue reliance on these forward-looking statements. Furthermore, forward-looking statements speak only as of the date they are made, and GenOn undertakes no obligation to update publicly or revise any forward-looking statements to reflect events or circumstances that may arise after the date of this communication. All subsequent written and oral forward-looking statements concerning GenOn, the proposed transaction, the combined company or other matters and attributable to GenOn or any person acting on their behalf are expressly qualified in their entirety by the cautionary statements above. 2

Safe Harbor Additional Information And Where To Find It This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. In connection with the proposed business combination transaction between NRG and GenOn, NRG filed with the SEC a registration statement on Form S-4 that includes a joint proxy statement of NRG and GenOn and that also constitutes a prospectus of NRG. The registration statement was declared effective by the SEC on October 5, 2012. NRG and GenOn first mailed the joint proxy statement to their respective stockholders on or about October 10, 2012. In addition, the joint proxy statement/prospectus was supplemented on October 25, 2012, and GenOn first mailed the supplement to its stockholders on or about October 26, 2012. INVESTORS AND SECURITY HOLDERS OF GENON AND NRG ARE URGED TO READ THE REGISTRATION STATEMENT, INCLUDING THE DEFINITIVE JOINT PROXY STATEMENT/PROSPECTUS AND THE SUPPLEMENT THERETO AND ANY OTHER RELEVANT DOCUMENTS THAT ARE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. Investors and stockholders can obtain free copies of the definitive joint proxy statement/prospectus and other documents containing important information about NRG and GenOn through the website maintained by the SEC at www.sec.gov. NRG and GenOn make available free of charge at www.nrgenergy.com and www.genon.com, respectively (in the "Investor Relations" section), copies of materials they file with, or furnish to, the SEC. Participants In The Merger Solicitation NRG, GenOn, and certain of their respective directors and executive officers may be deemed to be participants in the solicitation of proxies from the stockholders of GenOn and NRG in connection with the proposed transaction. Information about the directors and executive officers of NRG is set forth in its proxy statement for its 2012 annual meeting of stockholders, which was filed with the SEC on March 12, 2012. Information about the directors and executive officers of GenOn is set forth in its proxy statement for its 2012 annual meeting of stockholders, which was filed with the SEC on March 30, 2012. Other information regarding the participants in the proxy solicitation can be found in the above-referenced registration statement on Form S-4. These documents can be obtained free of charge from the sources indicated above. Non-GAAP Financial Information This presentation includes "non-GAAP financial measures" as defined in Regulation G under the Securities Exchange Act of 1934, as amended. Reconciliations of these measures to the most directly comparable GAAP measures are contained in the appendix. This presentation is available in the Investor Relations section of our web site at www.genon.com. Certain factors that could affect GAAP financial measures are not accessible on a forward-looking basis but could be material to future reported earnings and cash flow. 3

Edward R. Muller Chairman and CEO Third Quarter 2012 Earnings November 9, 2012

Merger Progress Merger with NRG: Will deliver $300 million in annual transaction benefits by 2014 Continues to be on track to close by first quarter 2013 Integration efforts going smoothly GenOn and NRG stockholder approvals - special meetings this morning Regulatory approvals Department of Justice Hart-Scott-Rodino review - complete, closing condition met Public Utility Commission of Texas - complete, closing condition met Federal Energy Regulatory Commission - No protests; requested expedited consideration New York State Public Service Commission - filed August 2 Required notices provided Threshold determination by Nuclear Regulatory Commission - complete, closing condition met California Public Utilities Commission - complete, closing condition met 5

GenOn Highlights Deactivations 762 MWs of coal generating capacity deactivated on October 1, 2012, as previously announced Elrama unit 4 Niles unit 1 Potomac River units 1-5 Required investment for Gilbert unit 8 (90 MW steam turbine generator) not economic; plan to deactivate January 2015 Generating fleet continues to run well Marsh Landing is on schedule and on budget 6

7 Hedge Levels Aggregate1 Baseload Coal1 Shaded boxes represent net additions since July 9, 2012; empty boxes represent net decreases since July 9, 2012. 2012 represents balance of year (November and December). Power hedges include hedges with both power and natural gas. Based on expected generation as of October 8, 2012 2012 2013 2014 2015 2016 2012 2013 2014 2015 2016 Power3 Fuel 2 2 2

J. William Holden Executive Vice President and CFO Third Quarter 2012 Earnings November 9, 2012

Financial Results 3Q 3Q 3Q YTD YTD YTD ($ millions) 2012 2011 Variance 2012 2011 Variance Energy1 $ 172 $ 184 $ (12) $ 256 $ 504 $ (248) Contracted and capacity 341 274 67 707 729 (22) Realized value of hedges 60 57 3 336 202 134 Adjusted gross margin1 $ 573 $ 515 $ 58 $ 1,299 $ 1,435 $ (136) Adjusted operating and other expenses (252) (259) 7 (806) (870) 64 Adjusted EBITDA $ 321 $ 256 $ 65 $ 493 $ 565 $ (72) 9 Excludes (a) unrealized gains and losses, (b) lower of cost or market inventory adjustments, net, (c) advance settlement of out-of-market contract obligation and (d) costs to deactivate generating facilities (capacity penalties). Energy - lower generation and contracting dark spreads primarily in Western PJM/MISO partially offset by higher energy marketing contributions and expanding spark spreads in California Contracted and capacity - higher capacity prices in California partially offset by lower PJM capacity prices Adjusted operating and other expenses - lower project, outage and maintenance expenses 3Q Energy - lower generation from contracting dark spreads in Eastern PJM & Western PJM/MISO Contracted and capacity - lower PJM capacity prices partially offset by higher capacity prices in California Realized value of hedges - lower power prices Adjusted operating and other expenses - lower project, outage and maintenance expenses; Mirant/RRI merger cost synergies YTD

Debt and Liquidity ($ millions) September 30, 2012 Amortizing term loan due 2017 $ 686 Senior unsecured notes due 2014 - 2020 2,525 GenOn Americas Generation senior notes due 2021 and 2031 850 GenOn Marsh Landing project finance due 2017 and 2023 350 Capital leases due 2015 16 Total debt1 $ 4,427 Cash and cash equivalents2 $ 1,855 Revolver and letters of credit available3 560 Total available liquidity2,3 $ 2,415 Funds on deposit: Cash collateral for energy trading and marketing $ 150 Cash collateral for other operating activities4 59 Cash collateral for surety bonds 34 Marsh Landing development project cash collateral 80 Environmental compliance deposits 35 Other 36 Total funds on deposit $ 394 10 Excludes unamortized debt discounts and adjustments to fair value of debt of $(56) million. Includes $170 million of collateral posted to GenOn. Excludes availability under GenOn Marsh Landing credit facility. Includes $32 million related to the Potomac River escrow, which was received in October.

Capital Expenditures ($ millions) 2012E 2013E Maintenance $ 115 $ 138 Environmental Maryland Healthy Air Act 108 - Other1 38 118 Construction Marsh Landing 346 65 Other 20 3 Other 14 9 Total capital expenditures2 $ 641 $ 333 Project financings for Marsh Landing (346) (47) Funds on Deposit for MD Healthy Air Act (108) - Capital expenditures to be paid from cash $ 187 $ 286 11 $22 million and $87 million related to MATS, HEDD and water regulations in 2012 and 2013, respectively. Includes capitalized interest related only to Marsh Landing.

Summary 12 Merger with NRG benefits stockholders of both companies $300 million in annual transaction benefits Increased scale Additional geographic diversity Regulatory approval process progressing smoothly Generating fleet continues to run well Marsh Landing is on schedule and on budget

Third Quarter 2012 Earnings November 9, 2012 Appendix

Fixed Contracted and Capacity 14 Includes actual results through September 2012. Includes cleared capacity auction results for PJM and New England through May 2016. ($ millions) As of October 8, 2012 $869 $951

15 Generation Portfolio Total Generation Capacity 21,908 MWs (as of October 1, 2012) CAISO Southeast (SERC, FRCC) PJM ISO - NE NYISO MISO Operating Segment / Market Net Capacity (MW) Net Capacity (MW) Eastern PJM 5,859 5,859 Western PJM/MISO Western PJM 6,462 6,462 MISO 344 Total Western PJM/ MISO 6,806 California 5,391 5,391 Other Southeast 1,317 1,317 NYISO 1,139 1,139 ISO - NE 1,396 Total Other 3,852 3,852 Total 21,908 21,908

Generation Net MWh Generated Net MWh Generated Net MWh Generated Net MWh Generated Net MWh Generated Net MWh Generated Net MWh Generated 3Q 3Q 3Q YTD YTD YTD 2012 2011 2012 2011 Baseload1 Western PJM/MISO 5,560,393 6,301,075 12,595,450 16,066,771 Eastern PJM 2,795,512 3,023,934 5,401,484 9,147,342 California - - - - Other 959,858 671,520 1,901,148 1,535,922 Total Baseload 9,315,763 9,996,529 19,898,082 26,750,035 Intermediate1 Western PJM/MISO 5,843 3,443 14,234 1,323 Eastern PJM 837,646 477,624 2,429,329 743,618 California 915,279 203,568 1,087,309 329,836 Other 282,479 162,325 317,090 248,037 Total Intermediate 2,041,247 846,960 3,847,962 1,322,814 Peaking1 Western PJM/MISO 116,913 54,348 135,217 80,506 Eastern PJM 76,165 62,941 130,843 114,339 California 986 760 2,741 2,320 Other 210,167 214,133 374,435 314,009 Total Peaking 404,231 332,182 643,236 511,174 Total GenOn 11,761,241 11,175,671 24,389,280 28,584,023 16 Based on design capability.

Expected Changes in Generation Fleet 17 Plant Location MWs Planned Deactivation / Commercial Operation Date Driver Units to be deactivated Units to be deactivated Units to be deactivated Units to be deactivated Units to be deactivated Contra Costa CA 674 May 2013 Expiration of PPA Gilbert - Unit 8 NJ 90 January 2015 NJ High Energy Demand Day (HEDD) regulations Portland PA 401 January 2015 Cumulative effect of various environmental regulations Avon Lake OH 732 April 2015 MATS New Castle PA 330 April 2015 MATS Shawville PA 597 April 2015 Cumulative effect of various environmental regulations Titus PA 243 April 2015 MATS Glen Gardner NJ 160 May 2015 NJ High Energy Demand Day (HEDD) regulations Total fleet reductions Total fleet reductions 3,227 Fleet addition Fleet addition Fleet addition Fleet addition Fleet addition Marsh Landing CA 719 Mid-2013 Under construction - on schedule and on budget 19,400 MWs of generating capacity after 2015

Expected Environmental Investments 18 Expect investments of $621 - $738 million in major controls to meet current and anticipated environmental rules Plant Location Control Technology Expected Timing Driver Investments ($ millions) Kendall MA Backpressure steam turbine + air-cooled condenser 2012 - 2015 Water regulations $32 - $35 Gilbert NJ SCR 2012 - 2015 New Jersey HEDD regulations $147 Sayreville NJ SCR 2012 - 2015 New Jersey HEDD regulations $147 Werner NJ SCR 2012 - 2015 New Jersey HEDD regulations $147 Conemaugh PA Scrubber upgrade + SCR 2011 - 2015 MATS $841 Mandalay CA Variable speed pumps 2018 - 2019 Water regulations $17 - $20 Ormond Beach CA Variable speed pumps 2018 - 2019 Water regulations $17 - $20 Chalk Point - Unit 2 MD SCR 2018 - 2021 More stringent PM2.5 and Ozone NAAQS $341 - $452 Dickerson MD SCR 2018 - 2021 More stringent PM2.5 and Ozone NAAQS $341 - $452 Based on GenOn leased percentage.

19 Other PJM/MISO, Southern California and Southeast SEC filers Operating entities Borrowers and guarantors of GenOn Energy secured revolving credit facility & term loan Debt Structure GenOn Energy, Inc.1 GenOn Energy, Inc.1 Unsecured notes 7.625% due 2014 $575 $788 revolver due 20152 - Unsecured notes 7.875% due 2017 725 Amortizing term loan due 20172 686 Unsecured notes 9.5% due 2018 675 Unsecured notes 9.875% due 2020 550 New York, New England and Northern California Generating Assets Excludes $(56) million unamortized debt discounts and adjustments to fair value of debt. GenOn Americas (a direct subsidiary of GenOn Energy) and GenOn Energy are co-borrowers of the credit facility debt. The present values of lease payments for GenOn Mid-Atlantic and REMA operating leases are $846 million and $440 million, respectively. As of September 30, 2012 GenOn Americas Generation1 GenOn Americas Generation1 Senior Notes 8.5% due 2021 $450 Senior Notes 9.125% due 2031 400 GenOn Marsh Landing (project financing) GenOn Marsh Landing (project financing) $150 Senior secured facility due 2017 $ - $155 Senior secured amortizing term loan due 2017 109 $345 Senior secured amortizing term loan due 2023 241 GenOn Mid-Atlantic $16 capital lease Operating leases3 ($ millions) REMA Operating leases3

20 Other PJM/MISO, Southern California and Southeast (9,242 MWs) Organizational Structure GenOn Energy, Inc. (21,908 MWs) GenOn Mid-Atlantic (4,727 MWs) New York, New England and Northern California (4,520 MWs) REMA (3,419 MWs) Blossburg Portland Conemaugh Sayreville Gilbert Shawnee Glen Gardner Shawville Hamilton Titus Hunterstown CT Tolna Keystone Warren Mountain Werner Orrtanna GenOn Marsh Landing (719 MWs)1 Chalk Point Dickerson Morgantown Bowline Kendall Canal Martha's Vineyard Contra Costa Pittsburg Marsh Landing Aurora Mandalay Avon Lake New Castle Brunot Island Niles CT Cheswick Ormond Beach Choctaw Osceola Coolwater Sabine Ellwood Seward Etiwanda Shelby Hunterstown CCGT Under construction, expected to be complete mid-2013; therefore, not included in total MWs. GenOn Americas Generation As of October 1, 2012

Reg G: Adjusted Net Income (Loss) to Adjusted EBITDA and Adjusted Gross Margin ($ millions) 3Q 3Q YTD YTD 2011 2012 2011 2012 Net Loss $ (40) $ (85) $ (289) $ (345) Unrealized (gains) losses (38) 187 59 229 NRG Merger-related costs - 5 - 5 Mirant/RRI Merger-related costs 24 2 61 6 Impairment losses 133 47 133 47 Lower of cost or market inventory adjustments, net (1) (23) (13) 21 Loss on early extinguishment of debt - - 23 - Major litigation costs, net of recoveries 5 - 12 4 Gain on sales of assets (Indian River) - - - (6) Reversal of Montgomery County carbon levy assessment - - (8) - Large scale remediation and settlement costs - (2) 30 (5) Costs to deactivate generating facilities - 8 - 46 Advance settlement of out-of-market contract obligation - - - (20) Reversal of Potomac River settlement obligation - - - (31) Other, net (9) 2 (9) 6 Adjusted Net Income (Loss) $ 74 $ 141 $ (1) $ (43) Provision for income taxes 1 4 4 8 Interest expense, net 85 85 290 259 Depreciation and amortization 96 91 272 269 Adjusted EBITDA $ 256 $ 321 $ 565 $ 493 Adjusted operating and other expenses, net 259 252 870 806 Adjusted Gross Margin $ 515 $ 573 $ 1,435 $ 1,299 Unrealized gains (losses) 38 (187) (59) (229) Lower of cost or market inventory adjustments, net 1 23 13 (21) Costs to deactivate generating facilities (capacity penalties) - - - (2) Advance settlement of out-of-market contract obligation - - - 20 Gross Margin $ 554 $ 409 $ 1,389 $ 1,067 21

Reg G: Operations and maintenance to adjusted operating and other expenses, net ($ millions) 3Q 3Q YTD YTD 2011 2012 2011 2012 Operations and maintenance $ 286 $ 268 $ 963 $ 840 Gain on sales of assets, net (6) (1) (5) (9) Impairment losses 133 47 133 47 Other, net (1) - 21 (2) Operating and other expenses $ 412 $ 314 $ 1,112 $ 876 Impairment losses (133) (47) (133) (47) NRG Merger-related costs - (5) - (5) Mirant/RRI Merger-related costs (24) (2) (61) (6) Costs to deactivate generating facilities (excluding capacity penalties) - (8) - (44) Loss on early extinguishment of debt - - (23) - Gain on sales of assets (Indian River) - - - 6 Major litigation costs, net of recoveries (5) - (12) (4) Reversal of Montgomery County carbon levy assessment - - 8 - Large scale remediation and settlement costs - 2 (30) 5 Reversal of Potomac River settlement obligation - - - 31 Other, net 9 (2) 9 (6) Adjusted operating and other expenses, net $ 259 $ 252 $ 870 $ 806 22