Filed by NRG Energy, Inc.
Commission File No. 001-15891
 
Pursuant to Rule 425 of the Securities Act of 1933, as amended, and
deemed filed pursuant to Rule 14a-6 of the Securities Exchange Act of 1934, as amended
 
Subject Company:
GenOn Energy, Inc.
Commission File No. 001-16455

 
NRG Energy, Inc. Reports Second Quarter 2012 Results
 
Financial Highlights
 
·                 $539 million of adjusted EBITDA including $219 million delivered by NRG’s retail businesses in the second quarter of 2012; $839 million of adjusted EBITDA in the first half of 2012
 
·                 $413 million of free cash flow (FCF) before growth investments in the first half of 2012
 
·                 $2,406 million of total liquidity at the end of the second quarter, an increase of $336 million over 2011 year-end liquidity
 
Guidance
 
·                 Guidance reaffirmed for 2012, 2013 and 2014 ($ millions)
 
 	 	2012	 	2013	 	2014	 	
Adjusted EBITDA	 	$1,825-$2,000	 	$1,700-1,900	 	$1,700-1,900	 	
FCF before growth investments	 	$800-1,000	 	$650-850	 	$500-700	 	
 
Note: 2013 and 2014 guidance is provided on a standalone basis.
 
Business and Operational Highlights
 
·                 Declared first ever quarterly stock dividend on Company’s common stock of $0.09 per share ($0.36 annually). The dividend is payable on August 15, 2012.
 
·                 Sold our minority interest in Schkopau, coal-fueled power station in Germany, for net proceeds of approximately $174 million, increasing NRG’s restricted payment availability by an equivalent amount.
 
·                 Solar construction ahead of plan and on budget with over 260 MW currently in operation and more than 850 MW under construction.
 
PRINCETON, NJ; August 8, 2012—NRG Energy, Inc. (NYSE: NRG) today reported second quarter 2012 adjusted EBITDA of $539 million with Retail contributing $219 million and Wholesale contributing $320 million. The Company reported second quarter 2012 net income of $251

 
million, or $1.08 per diluted common share, compared to net income of $621 million, or $2.53 per diluted common share, for the second quarter of last year (2011 second quarter net income was positively impacted by more than $600 million as a result of the reversal of tax liabilities which resulted from an affirmation of the Company’s net operating loss positions following the completion of a federal tax audit).
 
Adjusted EBITDA for the six months ended June 30, 2012, was $839 million and adjusted cash flow from operations was $541 million. Adjusted cash flow from operations improved $278 million as compared to adjusted cash flow from operations of $263 million for the six month period ended June 30, 2011 due to reduced interest expense and movements in collateral postings. Retail contributed $331 million of adjusted EBITDA while wholesale adjusted EBITDA was $508 million. Year-to-date FCF before growth investments, was $413 million. Net income for the first six months of 2012 was $44 million, or $0.17 per diluted common share, compared to net income of $361 million, or $1.44 per diluted common share, for the first six months of 2011.
 
“NRG’s solid second quarter results demonstrate the benefits of our integrated wholesale-retail model and keep us on course for delivering on our 2012 guidance. With our efforts to close the merger with GenOn well under way, we remain focused on outstanding results for the remainder of 2012 as we look to harness the power of an even stronger and more diversified NRG in 2013,” commented David Crane, NRG’s President and CEO.
 
Segment Results
 
Table 1: Adjusted EBITDA
 
($ in millions)	 	Three Months Ended	 	Six Months Ended	 	
Segment	 	6/30/12	 	6/30/11	 	6/30/12	 	6/30/11	 	
Retail	 	219	 	199	 	331	 	359	 	
Texas	 	227	 	216	 	365	 	453	 	
Northeast	 	20	 	44	 	25	 	51	 	
South Central	 	27	 	37	 	52	 	64	 	
West(1)	 	23	 	12	 	38	 	25	 	
Other	 	18	 	11	 	36	 	29	 	
Alternative Energy	 	9	 	(3	)	11	 	(4	)	
Corporate(2) (3) 	 	(4	)	1	 	(19	)	(5	)	
Adjusted EBITDA(4)	 	539	 	517	 	839	 	972	 	

(1)   2012 excludes the CDWR legal settlement
(2)   2012 results exclude transaction fees; 2011 results exclude asset write-offs and impairment charges
(3)   Includes profit elimination on intercompany revenue
(4)   Detailed adjustments by region are shown in Appendix A
 
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Table 2: Net Income/(Loss)
 
($ in millions)	 	Three Months Ended	 	Six Months Ended	 	
Segment	 	6/30/12	 	6/30/11	 	6/30/12	 	6/30/11	 	
Retail	 	797	 	17	 	804	 	314	 	
Texas	 	(427	)	211	 	(501	)	238	 	
Northeast	 	(10	)	16	 	(53	)	(19	)	
South Central	 	11	 	12	 	(19	)	25	 	
West(1)	 	21	 	11	 	7	 	24	 	
Other	 	8	 	—	 	16	 	9	 	
Alternative Energy	 	(19	)	(11	)	(31	)	(30	)	
Corporate(2)	 	(130	)	365	 	(179	)	(200	)	
Net Income	 	251	 	621	 	44	 	361	 	

(1)   2012 results include the CDWR legal settlements
(2)   2012 results include transaction fees and asset write-offs; 2011 results include the impairment charge on investment
 
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Retail: Adjusted EBITDA for the second quarter of 2012 was $219 million; $20 million higher than in 2011. Gross margin was favorable $52 million driven by the acquisition of Energy Plus, which added $35 million, increased customer usage on higher customer count, and lower supply costs partially offset by unfavorable year over year weather. The Company’s ongoing efforts to expand into new markets and customer growth initiatives within Texas drove an approximate 61,000 increase in customer count since December 31, 2011. Meanwhile, lower supply costs resulting from depressed natural gas prices were partially offset by competitive pricing on acquisitions and renewals and lower rates on index-based customers, resulting in an $8 million net benefit. The higher margin realized in 2012 was offset by an increase in operating costs which were the result of the inclusion of Energy Plus of $23 million and increased marketing to drive market expansion and customer growth totaling $8 million.
 
Texas (Generation): Adjusted EBITDA for the second quarter of 2012 was $227 million; $11 million higher compared to the second quarter of 2011. Gross margin increased $25 million, driven by a combination of 9% higher nuclear generation and improved capacity contracts which together added $36 million. The substantial year-over-year increase in generation at the South Texas Project (STP) in 2012 was the result of a 2011 planned outage at unit 1, resulting in an increase of 0.5 GWh offset partially by a shorter forced outage of unit 2 which negatively impacted April 2012. Meanwhile, additional bilateral capacity contracts in 2012 vs. 2011 led to $13 million of additional revenue. Partially offsetting the increase was a 20% decline in coal generation due to a combination of outages and lower economic dispatch. Also, operating expenses increased $12 million, versus the second quarter of 2011, driven by the Company’s decision to return mothballed units to service ahead of the summer months.
 
Northeast: Adjusted EBITDA for the second quarter of 2012 was $20 million; down $24 million from 2011. The decline was driven by lower gross margin of $16 million, due to a combination of lower average realized prices and a decline in coal generation as the region was significantly impacted by coal-to-gas switching. The addition of physical energy sales to Energy Plus and favorable pricing on load-serving contracts led to an increase in load for the quarter partially offsetting the impact of lower generation. Meanwhile, favorable equity earnings partially offset the lower gross margin due to the addition of the GenConn Middletown facility, which became operational in June 2011.
 
South Central: Adjusted EBITDA for the second quarter of 2012 was $10 million lower than the second quarter 2011. Gross margin in 2012 was lower by $3 million versus the second quarter of 2011 due to a 25% decline in coal generation combined with 15% lower average realized prices. These results were partially offset by NRG’s Cottonwood plant which saw an increase in generation of 81% as it benefitted from coal to gas switching. Operating expenses increased $7 million versus the second quarter of 2011 driven by increased outage work at Big Cajun II.
 
West: Adjusted EBITDA for the second quarter of 2012 was $23 million; up $11 million from 2011. Generation increased by over 175% in the second quarter of 2012, leading to $6 million higher gross margin. In addition, capacity revenue increased $5 million due to recognition of contingent rental income related to the Long Beach PPA, in the second quarter of 2012.
 
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Alternative Energy: Adjusted EBITDA for the second quarter of 2012 was $9 million; up $12 million from 2011. Gross margin was $39 million, up from $14 million in 2011 driven by the addition of the Company’s Agua Caliente solar facility, which as of June 30, 2012 had reached commercial operations on 170 MW, including 110 MW that were activated in the second quarter. Offsetting the improved margin were NRG’s continued development efforts in our other new businesses.
 
Liquidity and Capital Resources
 
Table 3: Corporate Liquidity
 
($ in millions)	 	6/30/12	 	3/31/12	 	12/31/11	 	
Cash and Cash Equivalents	 	1,149	 	1,014	 	1,105	 	
Funds deposited by counterparties	 	135	 	199	 	258	 	
Restricted cash	 	208	 	217	 	292	 	
Total Cash and Funds Deposited	 	1,492	 	1,430	 	1,655	 	
Revolver availability	 	1,049	 	1,141	 	673	 	
Total Liquidity	 	2,541	 	2,571	 	2,328	 	
Less: Funds deposited as collateral by hedge counterparties	 	(135	)	(199	)	(258	)	
Total Current Liquidity	 	2,406	 	2,372	 	2,070	 	
 
Total liquidity as of June 30, 2012, was $2,406 million, an increase of $336 million from December 2011 liquidity driven largely by a $376 million increase in Revolver availability due to the sell-down of the Agua Caliente project. The $84 million decrease in restricted cash is primarily due to reduced collateral requirements for the Company’s solar projects as NRG continues to contribute equity. The decrease in letter of credit (LC) postings resulted from the impact of the Aqua Caliente sell down in January that released $304 million of LC postings. Finally, cash and cash equivalents increased by $44 million due to the following items:
 
·                 $541 million of adjusted cash flow from operations;
·                 $123 million of cash paid for maintenance and environmental capital expenditures (net of financing of $9 million);
·                 $325 million for solar and conventional growth investments (net of debt and third party funding of $1,057 million, including $17 million cash grant debt payment);
·                 $104 million of debt payments including $72 million early paydown of senior notes and $32 million of debt amortization payments; and
·                 $41 million of Schkopau cash reclassified to assets held for sale.
 
Partially offsetting these cash outflows was a net inflow of $96 million from other investing and financing activities including proceeds from the sell down of the Agua Caliente project.
 
Growth Initiatives and Developments
 
NRG continued to advance its leadership position in sustainable energy including:
 
Solar
 
·                Agua Caliente — As of July 3, 200 MW of generation have achieved commercial operation following the U.S. DOE’s permission to accelerate the block completion schedule. This represents a 90 MW improvement as compared to the end of April where the Company had
 
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110 MW in operation. The Company continues to expect to reach commercial operation on 228 MW by year end 2012 and a full commercial operation date by March 2014, three months earlier than originally planned. Power generated by Agua Caliente will be sold under a 25-year power purchase agreement (PPA) with Pacific Gas and Electric Co. (PG&E).
 
·                 CVSR — Construction of the California Valley Solar Ranch project is well advanced, with power generation from the first phase expected in early September. We continue to expect all other phases of the project to be completed earlier than the dates anticipated at the time the project was acquired, with 127 MW on line by the end of 2012 and the remaining 123 MW completed in the fourth quarter of 2013. Power from this project will be sold to PG&E under 25-year PPAs.
 
·                 Ivanpah —Unit 1 (126 MW) is expected to produce its first steam this November and be completed and producing power in early April of next year. The remaining two units (each at 133 MW) are currently expected to be completed in the third and fourth quarter of 2013, several weeks ahead of schedule. Power from units 1 and 3 will be sold to PG&E via two 25-year PPAs, and power from unit 2 will be sold to SoCal Edison under a 20-year PPA.
 
·                 Other Solar —NRG Solar also has several other, smaller projects under construction that are expected to reach commercial operation within 2012, ranging from the Alpine project (66 MW under a 20-year PPA with PG&E) to smaller Distributed Generation scale installations such as our NFL stadium projects.
 
Alternative Energy
 
·                 Petra Nova— On May 3rd, NRG executed a $54 million tax-exempt bond financing in connection with the construction of a peaking unit at our WA Parish Generation Station with an expected COD of May 1, 2013. The peaking unit is to be used as a cogeneration facility dedicated to a Carbon Capture Utilization and Storage (CCUS) Project, sponsored in part by the Department of Energy, at the Parish Station. The project is intended to utilize the captured CO 2  in enhanced oil recovery operations on the Texas Gulf Coast. As of June 30, 2012, NRG had received $1 million in proceeds from the tax-exempt bond financing with the remaining balance to be received over time as construction costs are paid.
 
Conventional Natural Gas
 
·                 El Segundo Generating Station — Our natural gas-fueled fleet also continues to grow, with two new units under construction at our El Segundo facility. These units, totaling 550 MW, are on track to reach commercial operation in August of 2013.
 
Guidance Update
 
NRG is maintaining its EBITDA guidance range for fiscal year 2012 at $1,825-$2,000 million with Wholesale contributing $1,200-$1,300 million and Retail contributing $625-$700 million. The Company is also maintaining free cash flow before growth investments guidance of $800-$1,000 million. NRG is also maintaining its previously disclosed EBITDA guidance range of $1,700-$1,900 million for each of 2013 and 2014 as well as FCF before growth investments guidance ranges of $650-$850 million for 2013 and $500-$700 million for 2014.
 
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Table 4: 2012 Reconciliation of Adjusted EBITDA Guidance
 
($ in millions)	 	8/8/12	 	5/3/12	 	
Adjusted EBITDA guidance	 	1,825–2,000	 	1,825–2,000	 	
Interest payments	 	(605)	 	(605)	 	
Income tax	 	(50)	 	(50)	 	
Collateral/working capital/other	 	(94)	 	(103)	 	
Adjusted cash flow from operations	 	1,050 –1,250	 	1,050–1,250	 	
Maintenance capital expenditures	 	(240)-(260)	 	(240)-(260)	 	
Environmental capital expenditures, net	 	(5)-(15)	 	(5)-(15)	 	
Preferred dividends	 	(9)	 	(9)	 	
Free cash flow — before growth investments	 	800–1,000	 	800–1,000	 	
 
Note: Subtotals and totals are rounded
 
2012 Capital Allocation Plan
 
The Company’s Board of Directors declared a quarterly dividend on the Company’s common stock of 9 cents per share, or 36 cents per share on an annualized basis. The dividend is payable August 15, 2012, to shareholders of record as of August 1, 2012 and marks NRG’s first ever dividend.
 
Earnings Conference Call
 
On August 8, 2012, NRG will host a conference call at 10:00 am eastern to discuss these results. Investors, the news media and others may access the live webcast of the conference call and accompanying presentation materials by logging on to NRG’s website at http://www.nrgenergy.com and clicking on “Investors.” The webcast will be archived on the site for those unable to listen in real time.
 
About NRG
 
NRG is at the forefront of changing how people think about and use energy. A Fortune 500 company, NRG is a pioneer in developing cleaner and smarter energy choices for our customers: whether as one of the largest solar power developers in the country, or by building the first privately funded electric vehicle charging infrastructure or by giving customers the latest smart energy solutions to better manage their energy use. Our diverse power generating facilities can support over 20 million homes and our retail electricity providers—Reliant, Green Mountain Energy Company and Energy Plus—serve more than two million customers. More information is available at nrgenergy.com. Connect with NRG Energy on Facebook and follow us on Twitter @nrgenergy.
 
Forward Looking Statements
 
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, each party’s and the combined company’s future revenues, income, indebtedness, capital structure, plans, expectations, objectives, projected financial performance
 
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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 stockholder, antitrust, regulatory or other 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 NRG’s most recently filed Annual Reports on Form 10-K, subsequent Quarterly Reports on Form 10-Q, recent Current Reports on Form 8-K, and other SEC filings.
 
Many of these risks, uncertainties and assumptions are beyond NRG’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 NRG 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 NRG, the proposed transaction, the combined company or other matters and attributable to NRG or any person acting on their behalf are expressly qualified in their entirety by the cautionary statements above.
 
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. The proposed business combination transaction between NRG and GenOn will be submitted to the respective stockholders of NRG and GenOn for their consideration. NRG will file with the Securities and Exchange Commission (“SEC”) a registration statement on Form S-4 that will include a joint proxy statement of NRG and GenOn that also constitutes a prospectus of NRG. NRG and GenOn will mail the joint proxy statement/prospectus to their respective stockholders. NRG and GenOn also plan to file other documents with the SEC regarding the proposed transaction. This communication is not a substitute for any prospectus, proxy statement or any other document which NRG or GenOn may file with the SEC in connection with the proposed transaction. INVESTORS AND SECURITY HOLDERS OF GENON AND NRG ARE URGED TO READ THE JOINT PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS THAT WILL BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. Investors and stockholders will be able to obtain free copies of the joint proxy statement/prospectus and other documents containing important information about NRG and GenOn, once such documents are filed with the SEC, 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.
 
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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. These documents can be obtained free of charge from the sources indicated above. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the joint proxy statement/prospectus and other relevant materials to be filed with the SEC when they become available.
 
# # #
 
Contacts:
 
Media:	Investors:	
 	 	
Meredith Moore	Chad Plotkin	
609.524.4522	609.524.4526	
 	 	
Lori Neuman	Stefan Kimball	
609.524.4525	609.524.4527	
 	 	
Dave Knox	 	
713.537.2130	 	
 
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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
 	 	Three months ended June 30,	 	Six months ended June 30,	 	
(In millions, except for per share amounts)	 	2012	 	2011	 	2012	 	2011	 	
 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	
Total operating revenues	 	$	2,166	 	$	2,278	 	$	4,028	 	$	4,273	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	
Cost of operations	 	1,319	 	1,608	 	2,892	 	2,932	 	
Depreciation and amortization	 	234	 	222	 	464	 	427	 	
Selling, general and administrative	 	207	 	167	 	428	 	310	 	
Development costs	 	9	 	12	 	17	 	21	 	
Total operating costs and expenses	 	1,769	 	2,009	 	3,801	 	3,690	 	
Operating Income	 	397	 	269	 	227	 	583	 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	
Equity in earnings of unconsolidated affiliates	 	14	 	12	 	22	 	10	 	
Impairment charge on investment	 	—	 	(11	)	(1	)	(492	)	
Other income, net	 	2	 	3	 	4	 	8	 	
Loss on debt extinguishment	 	—	 	(115	)	—	 	(143	)	
Interest expense	 	(167	)	(167	)	(332	)	(340	)	
Total other expense	 	(151	)	(278	)	(307	)	(957	)	
Income/(Loss) Before Income Taxes	 	246	 	(9	)	(80	)	(374	)	
Income tax benefit	 	(13	)	(630	)	(133	)	(735	)	
Net Income	 	259	 	621	 	53	 	361	 	
Less: Net income attributable to noncontrolling interest	 	8	 	—	 	9	 	—	 	
Net Income Attributable to NRG Energy, Inc.	 	251	 	621	 	44	 	361	 	
Dividends for preferred shares	 	3	 	3	 	5	 	5	 	
Income Available for Common Stockholders	 	$	248	 	$	618	 	$	39	 	$	356	 	
 	 	 	 	 	 	 	 	 	 	
Earnings Per Share Attributable to NRG Energy, Inc. Common Stockholders	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	
Weighted average number of common shares outstanding — basic	 	228	 	243	 	228	 	245	 	
Net Income per weighted average common share — basic	 	$	1.09	 	$	2.54	 	$	0.17	 	$	1.45	 	
Weighted average number of common shares outstanding —diluted	 	229	 	244	 	229	 	247	 	
Net Income per weighted average common share —diluted	 	$	1.08	 	$	2.53	 	$	0.17	 	$	1.44	 	
 
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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE LOSS
(Unaudited)
 
 	 	Three months ended June 30,	 	Six months ended June 30,	 	
 	 	2012	 	2011	 	2012	 	2011	 	
Net Income	 	$	259	 	$	621	 	$	53	 	$	361	 	
Other Comprehensive (Loss)/Income, net of tax	 	 	 	 	 	 	 	 	 	
Unrealized loss on derivatives, net of income tax benefit of $47, $39, $52 and $86	 	(80	)	(67	)	(89	)	(149	)	
Foreign currency translation adjustments, net of income tax benefit (expense) of $5, ($5), $2 and ($12)	 	(8	)	10	 	(2	)	22	 	
Available —for-sale securities, net of income tax benefit of $0, $1, $0 and $0	 	—	 	(1	)	—	 	(1	)	
Defined benefit plans	 	—	 	—	 	—	 	1	 	
Other comprehensive loss	 	(88	)	(58	)	(91	)	(127	)	
Comprehensive Income/(Loss)	 	171	 	563	 	(38	)	234	 	
Less: Comprehensive income attributable to noncontrolling interest	 	8	 	—	 	9	 	—	 	
Comprehensive Income/ (Loss) Attributable to NRG Energy, Inc.	 	163	 	563	 	(47	)	234	 	
Dividends for preferred shares	 	3	 	3	 	5	 	5	 	
Comprehensive Income/ (Loss) available for common stockholders	 	$	160	 	$	560	 	$	(52	)	$	229	 	
 
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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 
(In millions, except shares)	 	June 30, 2012	 	December 31, 2011	 	
 	 	(unaudited)	 	 	 	
ASSETS	 	 	 	 	 	
Current Assets	 	 	 	 	 	
Cash and cash equivalents	 	$	1,149	 	$	1,105	 	
Funds deposited by counterparties	 	135	 	258	 	
Restricted cash	 	208	 	292	 	
Accounts receivable — trade, less allowance for doubtful accounts of $23 and $23	 	1,000	 	834	 	
Inventory	 	416	 	308	 	
Derivative instruments	 	3,670	 	4,216	 	
Cash collateral paid in support of energy risk management activities	 	71	 	311	 	
Prepayments and other current assets	 	606	 	273	 	
Total current assets	 	7,255	 	7,597	 	
Property, plant and equipment, net of accumulated depreciation of $4,976 and $4,570	 	15,318	 	13,621	 	
Other Assets	 	 	 	 	 	
Equity investments in affiliates	 	658	 	640	 	
Note receivable — affiliate and capital leases, less current portion	 	81	 	342	 	
Goodwill	 	1,886	 	1,886	 	
Intangible assets, net of accumulated amortization of $1,559 and $1,452	 	1,256	 	1,419	 	
Nuclear decommissioning trust fund	 	448	 	424	 	
Derivative instruments	 	562	 	450	 	
Other non-current assets	 	392	 	336	 	
Total other assets	 	5,283	 	5,497	 	
Total Assets	 	$	27,856	 	$	26,715	 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	 	 	 	 	 	
Current Liabilities	 	 	 	 	 	
Current portion of long-term debt and capital leases	 	$	71	 	$	87	 	
Accounts payable	 	1,350	 	808	 	
Derivative instruments	 	3,234	 	3,751	 	
Deferred income taxes	 	115	 	127	 	
Cash collateral received in support of energy risk management activities	 	135	 	258	 	
Accrued expenses and other current liabilities	 	793	 	640	 	
Total current liabilities	 	5,698	 	5,671	 	
Other Liabilities	 	 	 	 	 	
Long-term debt and capital leases	 	10,485	 	9,745	 	
Nuclear decommissioning reserve	 	345	 	335	 	
Nuclear decommissioning trust liability	 	263	 	254	 	
Deferred income taxes	 	1,147	 	1,389	 	
Derivative instruments	 	720	 	464	 	
Out-of-market commodity contracts	 	168	 	183	 	
Other non-current liabilities	 	878	 	756	 	
Total non-current liabilities	 	14,006	 	13,126	 	
Total Liabilities	 	19,704	 	18,797	 	
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)	 	249	 	249	 	
Commitments and Contingencies	 	 	 	 	 	
Stockholders’ Equity	 	 	 	 	 	
Common stock	 	3	 	3	 	
Additional paid-in capital	 	5,383	 	5,346	 	
Retained earnings	 	4,026	 	3,987	 	
Less treasury stock, at cost — 76,587,776 and 76,664,199 shares, respectively	 	(1,922	)	(1,924	)	
Accumulated other comprehensive (loss) income	 	(17	)	74	 	
Noncontrolling interest	 	430	 	183	 	
Total Stockholders’ Equity	 	7,903	 	7,669	 	
Total Liabilities and Stockholders’ Equity	 	$	27,856	 	$	26,715	 	
 
12

 
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
 	 	Six months ended June 30,	 	
 	 	2012	 	2011	 	
 	 	(In millions)	 	
Cash Flows from Operating Activities	 	 	 	 	 	
Net income	 	$	53	 	$	361	 	
Adjustments to reconcile net income to net cash provided by operating activities:	 	 	 	 	 	
Distributions less equity in earnings of unconsolidated affiliates	 	(1	)	—	 	
Depreciation and amortization	 	464	 	427	 	
Provision for bad debts	 	17	 	20	 	
Amortization of nuclear fuel	 	16	 	20	 	
Amortization of financing costs and debt discount/premiums	 	17	 	16	 	
Loss on debt extinguishment	 	1	 	26	 	
Amortization of intangibles and out-of-market commodity contracts	 	81	 	92	 	
Amortization of unearned equity compensation	 	18	 	14	 	
Changes in deferred income taxes and liability for uncertain tax benefits	 	(145	)	(748	)	
Changes in nuclear decommissioning trust liability	 	17	 	13	 	
Changes in derivative instruments	 	74	 	(166	)	
Changes in collateral deposits supporting energy risk management activities	 	240	 	69	 	
Impairment charge on investment	 	—	 	481	 	
Cash used by changes in other working capital	 	(267	)	(316	)	
Net Cash Provided by Operating Activities	 	585	 	309	 	
Cash Flows from Investing Activities	 	 	 	 	 	
Acquisitions of business, net of cash acquired	 	—	 	(68	)	
Capital expenditures	 	(1,593	)	(839	)	
Increase in restricted cash, net	 	(58	)	(42	)	
Decrease /(increase) in restricted cash to support equity requirements for U.S. DOE funded projects	 	142	 	(70	)	
(Increase)/decrease in notes receivable	 	(21	)	20	 	
Investments in nuclear decommissioning trust fund securities	 	(236	)	(165	)	
Proceeds from sales of nuclear decommissioning trust fund securities	 	220	 	152	 	
Proceeds from renewable energy grants	 	35	 	—	 	
Other	 	(44	)	(47	)	
Net Cash Used by Investing Activities	 	(1,555	)	(1,059	)	
Cash Flows from Financing Activities	 	 	 	 	 	
Payment of dividends to preferred stockholders	 	(5	)	(5	)	
Payment for treasury stock	 	—	 	(130	)	
Net payments for settlement of acquired derivatives that include financing elements	 	(44	)	(46	)	
Sale proceeds and other contributions from noncontrolling interests in subsidiaries	 	270	 	—	 	
Proceeds from issuance of long-term debt	 	927	 	3,798	 	
Payment of debt issuance and hedging costs	 	(12	)	(52	)	
Payments for short and long-term debt	 	(121	)	(3,833	)	
Net Cash Provided/(Used) by Financing Activities	 	1,015	 	(268	)	
Effect of exchange rate changes on cash and cash equivalents	 	(1	)	6	 	
Net Decrease in Cash and Cash Equivalents	 	44	 	(1,012	)	
Cash and Cash Equivalents at Beginning of Period	 	1,105	 	2,951	 	
Cash and Cash Equivalents at End of Period	 	$	1,149	 	$	1,939	 	
 
13

 
Appendix Table A-1: Second Quarter 2012 Regional Adjusted EBITDA Reconciliation
 
The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/(loss)
 
(dollars in millions)	 	Retail	 	Texas	 	Northeast	 	South
Central	 	West	 	Other
Conventional	 	Alt.
Energy	 	Corp.	 	Total	 	
Net Income/(Loss)	 	797	 	(427	)	(10	)	11	 	21	 	8	 	(11	)	(130	)	259	 	
Plus:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income Attributable to Non-Controlling Interest	 	—	 	—	 	—	 	—	 	—	 	—	 	(8	)	—	 	(8	)	
Income Tax	 	—	 	—	 	—	 	—	 	—	 	2	 	—	 	(15	)	(13	)	
Interest Expense	 	1	 	—	 	5	 	4	 	—	 	3	 	16	 	138	 	167	 	
Depreciation, Amortization and ARO Expense	 	44	 	114	 	33	 	23	 	4	 	4	 	11	 	2	 	235	 	
Amortization of Contracts	 	33	 	11	 	—	 	(5	)	—	 	1	 	—	 	—	 	40	 	
EBITDA	 	875	 	(302	)	28	 	33	 	25	 	18	 	8	 	(5	)	680	 	
Transaction fee on asset sale	 	—	 	—	 	—	 	—	 	—	 	—	 	—	 	1	 	1	 	
MtM (gains)/losses	 	(656	)	529	 	(8	)	(6	)	(2	)	—	 	1	 	—	 	(142	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA	 	219	 	227	 	20	 	27	 	23	 	18	 	9	 	(4	)	539	 	
 
Appendix Table A-2: Second Quarter 2011 Regional Adjusted EBITDA Reconciliation
 
The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/(loss)
 
(dollars in millions)	 	Retail	 	Texas	 	Northeast	 	South
Central	 	West	 	Other
Conventional	 	Alt.
Energy	 	Corp.	 	Total	 	
Net Income/(Loss)	 	17	 	211	 	16	 	12	 	11	 	—	 	(11	)	365	 	621	 	
Plus:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Tax	 	—	 	—	 	—	 	—	 	—	 	2	 	—	 	(632	)	(630	)	
Interest Expense	 	1	 	(1	)	11	 	10	 	1	 	4	 	3	 	138	 	167	 	
Depreciation, Amortization and ARO Expense	 	40	 	115	 	28	 	22	 	3	 	4	 	8	 	4	 	224	 	
Loss on Debt Extinguishment	 	—	 	—	 	—	 	—	 	—	 	—	 	—	 	115	 	115	 	
Amortization of Contracts	 	45	 	14	 	—	 	(5	)	—	 	1	 	—	 	—	 	55	 	
EBITDA	 	103	 	339	 	55	 	39	 	15	 	11	 	—	 	(10	)	552	 	
Asset Write offs and Impairment of a Passive Portfolio Investment	 	—	 	—	 	—	 	—	 	—	 	—	 	—	 	11	 	11	 	
MtM losses/(gains)	 	96	 	(123	)	(11	)	(2	)	(3	)	—	 	(3	)	—	 	(46	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA	 	199	 	216	 	44	 	37	 	12	 	11	 	(3	)	1	 	517	 	
 
14

 
Appendix Table A-3: YTD Second Quarter 2012 Regional Adjusted EBITDA Reconciliation
 
The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/(loss)
 
(dollars in millions)	 	Retail	 	Texas	 	Northeast	 	South
Central	 	West	 	Other
Conventional	 	Alt.
Energy	 	Corp.	 	Total	 	
Net Income/(Loss)	 	804	 	(501	)	(53	)	(19	)	7	 	16	 	(22	)	(179	)	53	 	
Plus:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income Attributable to Non-Controlling Interest	 	—	 	—	 	—	 	—	 	—	 	—	 	(9	)	—	 	(9	)	
Income Tax	 	—	 	—	 	—	 	—	 	—	 	4	 	—	 	(137	)	(133	)	
Interest Expense	 	2	 	—	 	9	 	9	 	—	 	7	 	22	 	283	 	332	 	
Depreciation, Amortization and ARO Expense	 	85	 	229	 	65	 	46	 	7	 	8	 	23	 	5	 	468	 	
Amortization of Contracts	 	67	 	19	 	—	 	(9	)	—	 	1	 	—	 	—	 	78	 	
EBITDA	 	958	 	(253	)	21	 	27	 	14	 	36	 	14	 	(28	)	789	 	
Transaction fee on asset sales	 	—	 	—	 	—	 	—	 	—	 	—	 	—	 	9	 	9	 	
CDWR legal settlement	 	—	 	—	 	—	 	 	 	20	 	—	 	—	 	—	 	20	 	
MtM (gains)/losses	 	(627	)	618	 	4	 	25	 	4	 	—	 	(3	)	—	 	21	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA	 	331	 	365	 	25	 	52	 	38	 	36	 	11	 	(19	)	839	 	
 
Appendix Table A-4: YTD Second Quarter 2011 Regional Adjusted EBITDA Reconciliation
 
The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/(loss)
 
(dollars in millions)	 	Retail	 	Texas	 	Northeast	 	South
Central	 	West	 	Other
Conventional	 	Alt.
Energy	 	Corp.	 	Total	 	
Net Income/(Loss)	 	314	 	238	 	(19	)	25	 	24	 	9	 	(30	)	(200	)	361	 	
Plus:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Tax	 	(3	)	—	 	—	 	—	 	—	 	4	 	—	 	(736	)	(735	)	
Interest Expense	 	2	 	(16	)	27	 	21	 	1	 	8	 	7	 	290	 	340	 	
Depreciation, Amortization and ARO Expense	 	66	 	231	 	57	 	42	 	7	 	7	 	15	 	6	 	431	 	
Loss on Debt Extinguishment	 	—	 	—	 	—	 	—	 	—	 	—	 	—	 	143	 	143	 	
Amortization of Contracts	 	93	 	28	 	—	 	(10	)	—	 	1	 	—	 	—	 	112	 	
EBITDA	 	472	 	481	 	65	 	78	 	32	 	29	 	(8	)	(497	)	652	 	
Asset Write offs and Impairment of a Passive Portfolio Investment	 	—	 	—	 	—	 	—	 	—	 	—	 	—	 	492	 	492	 	
MtM (gains)/losses	 	(113	)	(28	)	(14	)	(14	)	(7	)	—	 	4	 	—	 	(172	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA	 	359	 	453	 	51	 	64	 	25	 	29	 	(4	)	(5	)	972	 	
 
15

 
Appendix Table A-5: YTD Second Quarter 2012 Free Cash Flow before Growth Investments Reconciliation
 
The following table summarizes the calculation of free cash flow before growth investments and adjusted cash flow from operating activities providing a reconciliation to net cash provided by operating activities
 
($ in millions)	 	Six months ended June 30, 2012	 	Six months ended June 30, 2011	 	
Net Cash Provided by Operating Activities	 	585	 	309	 	
Less: Reclassifying of net payments for settlement of acquired derivatives that include financing elements	 	(44	)	(46	)	
Adjusted Cash Flow from Operating Activities	 	541	 	263	 	
Maintenance Capital Expenditures	 	(102	)	(112	)	
Environmental Capital Expenditures, net	 	(21	)	(1	)	
Preferred Dividends	 	(5	)	(5	)	
Free Cash Flow — Before Growth Investments	 	413	 	145	 	
 
Appendix Table A-6: 2013 and 2014 Adjusted EBITDA Reconciliation
 
The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/(loss)
 
($ in millions)	 	2013	 	2014	 	
Adjusted EBITDA guidance	 	1,700 –1,900	 	1,700 –1,900	 	
Interest payments	 	(670)	 	(740)	 	
Income tax	 	(40)	 	(40)	 	
Collateral/working capital/other changes	 	60	 	80	 	
Cash flow from operations	 	1,050 –1,250	 	1,000–1,200	 	
Maintenance capital expenditures	 	(230)-(250)	 	(220)-(240)	 	
Environmental capital expenditures, net	 	(130)-(150)	 	(230)-(250)	 	
Preferred dividends	 	(9)	 	(9)	 	
Free cash flow — before growth investments	 	650–850	 	500–700	 	
 
Note: Subtotals and totals are rounded
 
EBITDA and adjusted EBITDA are non-GAAP financial measures. These measurements are not recognized in accordance with GAAP and should not be viewed as an alternative to GAAP measures of performance. The presentation of adjusted EBITDA should not be construed as an inference that NRG’s future results will be unaffected by unusual or non-recurring items.
 
EBITDA represents net income before interest (including loss on debt extinguishment), taxes, depreciation and amortization. EBITDA is presented because NRG considers it an important supplemental measure of its performance and believes debt-holders frequently use EBITDA to analyze operating performance and debt service capacity. EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are:
 
16

 
·                 EBITDA does not reflect cash expenditures, or future requirements for capital expenditures, or contractual commitments;
·                 EBITDA does not reflect changes in, or cash requirements for, working capital needs;
·                 EBITDA does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt or cash income tax payments;
·                 Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and
·                 Other companies in this industry may calculate EBITDA differently than NRG does, limiting its usefulness as a comparative measure.
 
Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to use to invest in the growth of NRG’s business. NRG compensates for these limitations by relying primarily on our GAAP results and using EBITDA and adjusted EBITDA only supplementally. See the statements of cash flow included in the financial statements that are a part of this news release.
 
Adjusted EBITDA is presented as a further supplemental measure of operating performance. Adjusted EBITDA represents EBITDA adjusted for mark-to-market gains or losses, asset write offs and impairments; and factors which we do not consider indicative of future operating performance. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. As an analytical tool, adjusted EBITDA is subject to all of the limitations applicable to EBITDA. In addition, in evaluating adjusted EBITDA, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release.
 
Adjusted cash flow from operating activities is a non-GAAP measure NRG provides to show cash from operations with the reclassification of net payments of derivative contracts acquired in business combinations from financing to operating cash flow. The Company provides the reader with this alternative view of operating cash flow because the cash settlement of these derivative contracts materially impact operating revenues and cost of sales, while GAAP requires NRG to treat them as if there was a financing activity associated with the contracts as of the acquisition dates.
 
Free cash flow (before growth investments) is adjusted cash flow from operations less maintenance and environmental capital expenditures and preferred stock dividends and is used by NRG predominantly as a forecasting tool to estimate cash available for debt reduction and other capital allocation alternatives. The reader is encouraged to evaluate each of these adjustments and the reasons NRG considers them appropriate for supplemental analysis. Because we have mandatory debt service requirements (and other non-discretionary expenditures) investors should not rely on free cash flow as a measure of cash available for discretionary expenditures.
 
17

 
 	NRG’s Second Quarter 2012 Results Presentation August 8, 2012	

 	Forward Looking Statements 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, each party’s 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 a 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 the expected schedule, the ability to obtain stockholder, antitrust, regulatory or other 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, and hedging ineffectiveness. Additional information concerning other risk factors is contained in NRG's most recently filed Annual Reports on Form 10-K, subsequent Quarterly Reports on Form 10-Q, recent Current Reports on Form 8-K, and other SEC filings. Many of these risks, uncertainties and assumptions are beyond NRG'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 NRG 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 NRG, the proposed transaction, the combined company or other matters attributable to NRG or any person acting on its behalf are expressly qualified in their entirety by the cautionary statements above. 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. The proposed business combination transaction between NRG and GenOn will be submitted to the respective stockholders of NRG and GenOn for their consideration. NRG will file with the Securities and Exchange Commission (“SEC”) a registration statement on Form S-4 that will include a joint proxy statement of NRG and GenOn that also constitutes a prospectus of NRG. NRG and GenOn will mail the joint proxy statement/prospectus to their respective stockholders. NRG and GenOn also plan to file other documents with the SEC regarding the proposed transaction. This communication is not a substitute for any prospectus, proxy statement or any other document which NRG or GenOn may file with the SEC in connection with the proposed transaction. INVESTORS AND SECURITY HOLDERS OF GENON AND NRG ARE URGED TO READ THE JOINT PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS THAT WILL BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. Investors and stockholders will be able to obtain free copies of the joint proxy statement/prospectus and other documents containing important information about NRG and GenOn, once such documents are filed with the SEC, 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. These documents can be obtained free of charge from the sources indicated above. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the joint proxy statement/prospectus and other relevant materials to be filed with the SEC when they become available. Safe Harbor Continued	

 	Agenda Highlights and Strategic Update – D. Crane Operations and Commercial Review – M. Gutierrez Financial Results – K. Andrews Closing Remarks and Q&A – D. Crane	

 	Second Quarter 2012 Highlights Solid Financial Performance Reaffirming Guidance Range1 Key Strategic Highlights Declared first stock dividend of $0.09 per share ($0.36 annually) Sold NRG’s minority interest in Schkopau for proceeds of ~$174 MM Solar construction ahead of plan and on budget Delivering Solid Financial Results While Executing on Strategic Goals 1Preliminary 2013 and 2014 guidance provided on a standalone basis Adjusted EBITDA 2Q2012 1H2012 Total $539 $839 Retail Contribution $219 $331 ($MM) 2012 2013 2014 Adjusted EBITDA $1,825-$2,000 $1,700-$1,900 $1,700-$1,900 Free Cash Flow, before growth $800-$1,000 $650-$850 $500-$700 ($MM)	

 	Significant Value Creation for All Stakeholders Benefits of the NRG / GenOn Combination Significant Financial Accretion by 2014 $300 MM Annual Free Cash Flow Benefits from the Combination $200 MM Annual EBITDA From Cost and Operational Efficiency Synergies While Strengthening NRG’s Competitive Energy Business Model – Retail – – Wholesale – - Clean -Energy	

 	NRG and GenOn Stockholder Approval Special meeting – 4th quarter 2012 Regulatory Approvals FERC – to be filed this week Department of Justice / Hart-Scott-Rodino – in process New York State Public Service Commission – filed August 2nd Public Utility Commission of Texas – filed August 3rd Required Notices California Public Utilities Commission – filed July 31st Nuclear Regulatory Commission – filed August 1st Transaction Process Update Transaction Expected to Close by First Quarter 2013	

 	Operations and Commercial Review	

 	Q2 2012: Plant Operations Update 1Top Decile based on Edison Electric Institute 2009 Total Company Survey results Net Production (TWh)2 2All NRG owned domestic generation production Gas/Oil Units Starting Reliability Top Quartile = 1.02 Top Decile = 0.80 Normalized Planned Outages to 2011 3Equivalent Availability Factor (EAF)–the percentage of maximum equivalent generation available Q2 YTD 2012 Q2 2011 Q2 2012 2011 Q2 YTD 87% 86% Solid operating performance and opportunistic maintenance program Safety – Top Decile OSHA Recordable Rate1 Coal Availability – EAF3 Q2 YTD Starting Reliability 2011 Starts 2012 Starts	

 	Q2 2012: Retail Operations Strong performance by NRG’s multi-brand retail business with growth in customer count, unit margin and volume Highlights Delivered $331 MM in EBITDA YTD Increased unit margins and customer count Improved hedging strategy mitigated impact of high prices in June Continued expansion into the Northeast Continued Retail Customer Growth (000s)1 Higher Retail Load Served (GWhs) Gross Margin ($/MWh) 1Excludes utility partner customers	

 	Source: Bentek, Smith Bits. 2Production is 8-week average Market Update Forwards Do Not Reflect Improving ERCOT Fundamentals Rig Count Improving market fundamentals in ERCOT and natural gas Production Leveling Off with Rig Count Down 50% Production2 Cost of New Entry for CCGT1 Natural Gas Reaching Inflection Point ‘13 ‘14 ‘15 New monthly peak loads NAPP Switch PRB Switch Source: ERCOT Source: NRG estimates. 1Margin required to justify new build economics for a CCGT based on $800-1,000/kW capital cost net of A/S and O&M. Spark Spread=(Houston Hub On-Peak Power - 7 heat rate x Henry Hub Gas) Source: NYMEX and NRG estimates	

 	Managing Commodity Price Risk Coal and Transport Hedge Position (1) (4) (1) Portfolio as of 07/18/2012. 2012 represents August through December months; (2) Retail Priced Loads are 100% hedged; (3) Price sensitivity reflects gross margin change from $0.5/MMBtu gas price, 1 MMBtu/MWh heat rate move; (4) Coal position excludes existing coal inventory; (5) Baseload includes coal and nuclear electric power generation capacity normally expected to serve loads on around-the-clock basis throughout the calendar year Baseload Generation and Retail Hedge Position (1) (2) (5) Change since prior quarter 2012 2013 2014 Continue to implement enhanced integrated wholesale/retail hedging strategy Old Bridge project did not clear 15/16 PJM capacity auction -> Preserve option Reached agreement around Dunkirk RMR contract; approval pending Baseload Gas Price and Heat Rate Sensitivity ($MM) (1) (3) (5) Commercial Highlights	

 	Financial Results	

 	Financial Summary June 30, 2012 Three Months Ended Six Months Ended Wholesale $320 MM $508 MM Retail $219 MM $331 MM Consolidated adjusted EBITDA $539 MM $839 MM Free Cash Flow before Growth $571 MM $413 MM $661 million of cash flow from operations in the second quarter leading to $413 million of free cash flow before growth investments for the first half of 2012 $300+ million improvement in liquidity since year end Capital Allocation Update: Declared first-ever quarterly dividend to be paid August 15th Open market debt repurchases leading to a $72 million Corporate debt reduction	

 	Guidance Overview ($MM) 2012 2013 2014 Wholesale $1,130-$1,225 $850-$965 $705-$820 Solar Projects1 $70-$75 $200-$210 $320-$330 Retail $625-$700 $650-$725 $675-$750 Consolidated adjusted EBITDA $1,825-$2,000 $1,700-$1,900 $1,700-$1,900 Free Cash Flow – before growth investments $800-$1,000 $650-$850 $500-$700 Maintaining EBITDA and Free Cash Flow guidance ranges 1Solar projects include the EBITDA contribution from the projects net of non-controlling interest and excluding development expenses	

 	Committed Growth Investments Growth investments substantially online by 2014 and significant contributors to EBITDA results ($MM) 2012 2013-2014 Conventional Investments, net 107 147 Solar Investments, net 363 232 Total Growth Investments $470 $379 1Ivanpah, Agua Caliente, and California Valley Solar Ranch 2012 2013-2014 May 3, 2012 $324 $240 Big 3 Solar projects 1 24 (13) Other 15 5 August 8, 2012 $363 $232 Change in Solar Investments, net: 2012 2013-2014 May 3, 2012 $101 $149 Repowering Projects 6 (2) August 8, 2012 $107 $147 Change in Conventional Investments, net:	

 	Improved Strength of Corporate Liquidity Continued improvement in liquidity as the Company continues to capitalize on market opportunities Total liquidity improved $336 million since year-end 2011: Strong adjusted cash from operations of $541 million $448 million of capital investments including $325 million of Growth Investments, net Increase in revolver availability due primarily to the Agua Caliente sell-down Current liquidity position continues to reflect full effect of our remaining equity commitments to Tier 1 solar projects Schkopau sale proceeds of $174 million, which closed on July 17th, will benefit third quarter liquidity Liquidity Improvement June 30, Dec 31, ($MM) 2012 2011 Cash and Cash Equivalents $1,149 $1,105 Restricted Cash 208 292 Total Cash $1,357 $1,397 Funds Deposited by Counterparties 135 258 Total Cash and Funds Deposited $1,492 $1,655 Revolver Availability 1,049 673 Total Liquidity $2,541 $2,328 (135) (258) Total Current Liquidity $2,406 $2,070 Less: Collateral Funds Deposited	

 	Closing Remarks and Q&A	

 	Appendix	

 	Capital Expenditures and Growth Investments 1 Includes investments, cash grants, restricted cash and network upgrades 2 Includes net debt proceeds and third party contributions 3Includes investments, cash grants, restricted cash and network upgrades 4 Includes net debt proceeds and third party contributions 2012 YTD Results $ in millions Maintenance Environmental Conventional investments, net Solar investments, net Total Capital Expenditures Northeast 4 $ 22 $ - $ - $ 26 $ Texas 71 - - - 71 South Central 16 1 - - 17 West 3 - 110 - 113 Other Conventional 2 - 12 - 14 Retail 8 - - - 8 Solar - - - 1,875 1,875 Alternative Energy & Corporate 4 - 14 - 18 Accrued CapEx 108 $ 23 $ 136 $ 1,875 $ 2,142 $ Accrual impact (6) 7 (12) (538) (549) Total Cash CapEx 102 $ 30 $ 124 $ 1,337 $ 1,593 $ Other Investments 1 - - 5 (84) (79) Project Funding, net of fees: 2 Solar - - - (965) (965) El Segundo Repowering - - (89) - (89) Indian River bonds - (9) - - (9) Other Growth Other Conventional - - (3) - (3) Total Capital Expenditures and Growth investments, net 102 $ 21 $ 37 $ 288 $ 448 $ Growth investments, net 2012 Guidance $ in millions Maintenance Environmental Conventional investments, net Solar investments, net Total Capital Expenditures Northeast 30 $ 42 $ - $ - $ 72 $ Texas 136 3 - - 139 South Central 30 3 - - 33 West 3 - 272 - 275 Other Conventional 14 - 37 - 51 Retail 18 - - - 18 Solar - - - 3,288 3,288 Alternative Energy & Corporate 28 - 75 - 103 Accrued CapEx 259 $ 48 $ 384 $ 3,288 $ 3,979 $ Accrual impact - - - - - Total Cash CapEx 259 $ 48 $ 384 $ 3,288 $ 3,979 $ Other Investments 3 - - 31 (289) (258) Project Funding, net of fees : 4 Solar - - - (2,636) (2,636) El Segundo Repowering - - (272) - (272) Alternative Energy & Corporate - - (36) - (36) Indian River bonds - (42) - - (42) Total Capital Expenditures and Growth investments, net 259 $ 6 $ 107 $ 363 $ 735 $ Growth investments, net	

 	1Equivalent Availability Factor 2Net Capacity Factor Q2 2012 Generation & Operational Performance Metrics (MWh in thousands) 2012 2011 Change % EAF 1 NCF 2 EAF 1 NCF 2 Texas 12,551 12,544 7 0 82% 44% 87% 51% Northeast 1,606 2,344 (738) (31) 83 8 84 11 South Central 4,551 3,628 923 25 89 43 86 40 West 384 33 351 1,064 79 11 77 5 Alternative 490 378 112 30 Total 19,582 18,927 655 3 83% 31% 85% 35% Texas Nuclear 2,247 2,052 195 10 88% 88% 80% 80% Texas Coal 6,418 8,044 (1,626) (20) 85 71 95 89 NE Coal 775 1,469 (694) (47) 73 21 84 39 SC Coal 1,891 2,538 (647) (25) 82 56 94 77 Baseload 11,331 14,103 (2,772) (20) 83% 62% 91% 76% Solar 169 16 153 956 n/a n/a n/a n/a Wind 321 362 (41) (11) n/a 40 n/a 44 Intermittent 490 378 112 30 n/a 40% n/a 44% Oil 12 14 (2) (14) 84% 1% 78% 0% Gas - Texas 1,862 1,875 (13) (1) 78 16 82 17 Gas - NE 460 396 64 16 85 5 84 4 Gas - SC 2,105 1,124 981 87 93 38 81 20 Gas - West 384 33 351 1,064 79 11 77 5 Intermediate/Peaking 4,823 3,442 1,381 40 83% 15% 82% 11% Purchased Power 2,938 1,004 1,934 193 Total 19,582 18,927 655 3 2012 2011	

 	1Equivalent Availability Factor 2Net Capacity Factor YTD 2012 Generation & Operational Performance Metrics (MWh in thousands) 2012 2011 Change % EAF 1 NCF 2 EAF 1 NCF 2 Texas 20,875 23,629 (2,754) (12) 76% 36% 87% 48% Northeast 2,902 4,902 (2,000) (41) 87 6 86 12 South Central 8,678 7,474 1,204 16 93 45 90 42 West 755 55 700 1,273 86 10 81 5 Alternative 915 663 252 38 Total 34,125 36,723 (2,598) (7) 83% 27% 87% 33% Texas Nuclear 3,517 4,631 (1,114) (24) 69% 69% 90% 91% Texas Coal 10,966 15,133 (4,167) (28) 81 61 91 84 NE Coal 1,404 3,216 (1,812) (56) 73 18 88 42 SC Coal 3,923 5,428 (1,505) (28) 89 59 94 93 Baseload 19,810 28,408 (8,598) (30) 80% 54% 91% 78% Solar 242 28 214 764 n/a n/a n/a n/a Wind 673 635 38 6 n/a 41 n/a 38 Intermittent 915 663 252 38 n/a 41% n/a 38% Oil 20 41 (21) (51) 89% 0% 89% 1% Gas - Texas 2,364 2,595 (231) (9) 73 11 83 12 Gas - NE 723 654 69 11 91 4 85 4 Gas - SC 4,336 2,230 2,106 94 95 38 88 20 Gas - West 755 55 700 1,273 86 10 81 5 Intermediate/Peaking 8,198 5,575 2,623 47 85% 13% 85% 9% Purchased Power 5,202 2,077 3,125 150 Total 34,125 36,723 (2,598) (7) 2012 2011	

 	Fuel Statistics Domestic 2012 2011 2012 2011 Cost of Gas ($/mmBTU) 2.46 $ 4.47 $ 2.59 $ 4.46 $ Coal Consumed (mm Tons) 5.9 7.7 10.5 15.2 PRB Blend 82% 83% 82% 84% Northeast 50% 70% 62% 74% South Central 100% 100% 100% 100% Texas 80% 80% 78% 80% Coal Costs ($/mmBTU) 2.12 $ 2.21 $ 2.15 $ 2.18 $ Coal Costs ($/Ton) 34.80 $ 35.76 $ 35.13 $ 35.50 $ 2nd Quarter Year-to-Date	

 	Recourse / Non-Recourse Debt 12/31/2011 3/31/2012 6/30/2012 COD Date / Comments ($MM) Recourse debt: Term loan facility 1,592 1,588 1,584 Unsecured Notes 6,090 6,090 6,018 Tax Exempt Bonds 264 273 274 Recourse subtotal1 7,946 7,951 7,876 Non-Recourse debt: Ivanpah 874 1,049 1,168 2013 Agua Caliente 181 233 440 2012-2014 CVSR - 138 277 2012-2013 Other solar non-recourse debt 157 141 137 2012 Total Solar Debt 1,212 1,561 2,022 El Segundo 159 198 248 August 2013 Capital Lease - Schkopau2 103 103 - Sold on July 17th Conventional non-recourse debt3 444 438 438 Non-Recourse and Capital Lease Subtotal 1,918 2,300 2,708 Total Debt $9,864 $10,251 $10,584 1 Includes discount of $11M, $12M, and $12M, for 6/30/12, 3/31/12 and 12/31/12, respectively 2 Reclassified to current liabilities held for sale 3 Includes discount on NRG Peaker of $17M, $18M and $20M, for 6/30/12, 3/31/12 and 12/31/11, respectively	

 	Projects Under Construction 2012 2013 2014 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Solar MW 1492 187 424 437 513 707 772 772 772 CCGT MW 0 0 0 0 0 550 550 550 550 Ivanpah 1 63 MW Ivanpah 2 65 MW 65 MW Ivanpah 3 Borrego 26 MW Alpine 66 MW Avra Valley 25 MW 1 Represents NRG’s utility scale development projects only; excludes distributed solar. Includes only NRG’s share in solar projects. Construction period to substantial completion dates shown; COD MWs under PPAs shown by quarter; for some projects, COD is achieved prior to overall substantial completion 2 Includes Blythe (21 MW), Avenal (23 MW), Roadrunner (20 MW), and first blocks of Agua Caliente (85 MW, net NRG), all net NRG ownership share as of end of Q2 2012 Construction Pipeline1 El Segundo 550 MW Agua Caliente 148 MW California Valley Solar Ranch 250 MW	

 	Capacity Revenue Sources: Generation Asset Overview Region and Plant Zone MW Sources of Capacity Revenues: Market Capacity, PPA, and Tolling Arrangements Tenor NEPOOL (ISO NE): Devon SWCT 135 LFRM/FCM1 Connecticut Jet Power SWCT 140 LFRM/FCM1 Montville CT – ROS 500 FCM GenConn Devon SWCT 95 FCM GenConn Middletown CT – ROS 95 FCM Middletown CT – ROS 770 FCM Norwalk Harbor SWCT 340 FCM PJM: Indian River PJM - East 5804 DPL- South Vienna PJM – East 170 DPL- South Conemaugh PJM – West 65 PJM- MAAC Keystone PJM – West 65 PJM- MAAC New York (NYISO): Oswego Zone C 1,635 UCAP - ROS Huntley Zone A 380 UCAP - ROS Dunkirk Zone A 5302 UCAP - ROS Astoria Gas Turbines Zone J 515 UCAP - NYC Arthur Kill Zone J 865 UCAP - NYC California (CAISO): Encina SP-15 965 Toll/RA Toll expired 12/31/2011, One Year RA Start 1/1/2012 Cabrillo II SP-15 190 RA Capacity5 El Segundo SP-15 670 RA Capacity RA on portion of the plant8 Long Beach SP-15 260 Toll6 Expires 8/1/2017 Solar under Long-term PPAs CAISO and NM 150 PPA7 20-25 years Thermal: Dover PJM - East 104 DPL- South Paxton Creek PJM - West 12 PJM- MAAC NRG revenues and free cash flows benefit from capacity sources originating from either market clearing capacity prices, Resource Adequacy (RA) contracts, power purchase agreement (PPA) contracts, and tolling arrangements. The ERCOT (Texas) region does not have a capacity market. In South Central,3 NRG earns significant capacity revenue from its long-term contracts. As of December 31, 2011, NRG had long-term all-requirements contracts with 10 Louisiana distribution cooperatives with initial terms ranging from ten to 25 years. Of the 10 contracts, seven expire in 2025 and account for 57% of cooperative contract load, while the remaining three expire in 2014 and comprise 43% of contract load. Two of these three contracts have been renewed to 2025 subject to regulatory approval. In addition, NRG has all-requirements contracts with three Arkansas municipalities that account for over 500 MW of total load obligations for NRG and the South Central region. The table below reflects the plants and relevant capacity revenue sources for the Northeast, West and Thermal business segments: LFRM payments are net of any FCM payments received On July 20, 2012, Dunkirk Power LLC filed with the NY PSC a proposed term sheet to provide reliability support services to National Grid for two units totaling 200 MW through May 31, 2013. The remaining 330 MW is expected to be put into mothball status in September 2012 for up to three years. If the above contract is not extended then the 200 MW is also expected be mothballed in June 2013. South Central includes Rockford I and II, which is in PJM and receives capacity payments at the RPM wholesale market clearing price for the RPM RTO region On February 3, 2010, NRG and DNREC announced a proposed plan to retire the 155MW unit 3 by December 31, 2013 RA contracts cover 88MW of the Cabrillo II portfolio through November 30, 2013. NRG has purchased back energy and ancillary service value of the toll through July 31, 2014. Toll expires August 1, 2017 Solar projects include Blythe, Avenal Roadrunner and the partially completed Agua Caliente projects. Each project sells all of its of capacity under 20 or 25 year full-requirements PPAs El Segundo includes approximately 596 MW and 530 MW of RA contracts for 2011 and 2012, respectively GenConn’s energy and capacity are sold pursuant to a 30-year cost of service type contract with the Connecticut Light and Power Company under which FCM and LFRM revenues are netted against contracted amounts received	

 	Increase/ (Decreases) Revenue Forecast Non-Cash Contract Amortization Schedules: 2011-2014 Reduce Cost Increase Cost Increase Cost Reduce Cost Increase Cost Increase Cost Increase/ (Decreases) Revenue ($M) 2011 2012 Revenues Q1A Q2A Q3A Q4A Year Q1A Q2A Q3E Q4E Year Power contracts/gas swaps1 (33) (27) (3) (35) (98) (23) (36) (11) (28) (98) Fuel Expense Q1A Q2A Q3A Q4A Year Q1A Q2A Q3E Q4E Year Fuel out-of-market contracts2 6 3 1 2 12 3 2 1 3 9 Fuel in-the-market contracts3 1 1 3 1 6 1 1 2 1 5 Emission Allowances (NOx and SO2) 13 14 15 12 54 8 12 9 9 38 Total Net Expenses 8 12 17 11 48 6 11 10 7 34 ($M) 2013 2014 Revenues Q1E Q2E Q3E Q4E Year Q1E Q2E Q3E Q4E Year Power contracts/gas swaps1 (16) (12) (3) (1) (32) 0 0 0 0 0 Fuel Expense Q1E Q2E Q3E Q4E Year Q1E Q2E Q3E Q4E Year Fuel out-of-market contracts2 1 1 0 0 2 0 0 0 0 0 Fuel in-the-market contracts3 1 1 3 1 6 2 1 3 1 7 Emissions allowances (NOx and SO2) 9 9 9 9 36 8 9 9 8 34 Total Net Expenses 9 9 12 10 40 10 10 12 9 41 1Amortization of power contracts occurs in the revenue line 2Amortization of fuel and energy supply contracts occurs in the fuel and energy supply cost line; includes coal 3Amortization of fuel and energy supply contracts occurs in the fuel and energy supply cost line; includes coal, nuclear, and gas Note: Detailed discussion of the above referenced in-the-money and out-of-the money contracts can be found in the NRG 2011 10-K	

 	Appendix: Reg. G Schedules	

 	Note: see Appendix slide 19 for a Capital Expenditure reconciliation Reg. G: YTD Q2 2012 Free Cash Flow Before Growth Investments Jun 30, Jun 30, $ in millions 2012 2011 Variance Adjusted EBITDA 839 $ 972 $ (133) $ Interest payments (293) (485) 192 Income tax (21) (25) 4 Collateral/working capital/other 60 (153) 213 Cash flow from operations 585 $ 309 $ 276 $ (44) (46) 2 Adjusted Cash flow from operations 541 $ 263 $ 278 $ Maintenance CapEx (102) (112) 10 Environmental CapEx, net (21) (1) (20) Preferred dividends (5) (5) - Free cash flow - before growth investments 413 $ 145 $ 268 $ Reclassifying of net payments for settlement of acquired derivatives that include financing elements	

 	Reg. G: 2012 Guidance 1Solar projects include the EBITDA contribution from the projects net of non-controlling interest and excluding development expenses Note: see Appendix slide 19 for a Capital Expenditure reconciliation $ in millions 8/8/2012 Guidance 5/3/2012 Guidance Wholesale $1,130-$1,225 $1,200-$1,300 Solar Projects 1 70-75 - Retail 625-700 625-700 Consolidated adjusted EBITDA $1,825-$2,000 $1,825-$2,000 Interest Payments (605) (605) Income Tax (50) (50) Collateral/working capital/other (50) (83) Cash flow from operations $1,100-$1,300 $1,050-$1,250 Reclassifying of net payments for settlement of acquired derivatives that include financing elements (44) (20) Adjusted Cash flow from operations $1,050-$1,250 $1,050-$1,250 Maintenance CapEx (240)-(260) (240)-(260) Environmental CapEx, net (5)-(15) (5)-(15) Preferred Dividends (9) (9) Free cash flow - before growth investments $800-$1,000 $800-$1,000	

 	Reg. G: 2013 and 2014 Guidance 1 Solar projects include the EBITDA contribution from the projects net of non controlling interest and excluding development expenses $ in millions 2013 Guidance 2014 Guidance Wholesale $850-$965 $705-$820 Solar Projects 1 200-210 320-330 Retail 650-725 675-750 Consolidated adjusted EBITDA $1,700-$1,900 $1,700-$1,900 Interest Payments (670) (740) Income Tax (40) (40) Collateral/working capital/other 60 80 Cash flow from operations $1,050-$1,250 $1,000-$1,200 Maintenance CapEx (230)-(250) (220)-(240) Environmental CapEx, net (130)-(150) (230)-(250) Preferred Dividends (9) (9) Free cash flow - before growth investments $650-$850 $500-$700	

 	Reg. G Appendix Table A-1: Second Quarter 2012 Regional Adjusted EBITDA Reconciliation The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income: South Other Alt. ($ in millions) Retail Texas Northeast Central West Conventional Energy Corp. Total Net Income/(Loss) $797 ($427) ($10) $11 $21 $8 ($11) ($130) $259 Plus: Net Income Attributable to Non-Controlling Interest - - - - - - (8) - (8) Income Tax - - - - - 2 - (15) (13) Interest Expense 1 - 5 4 - 3 16 138 167 Depreciation, Amortization and ARO Expense 44 114 33 23 4 4 11 2 235 Amortization of Contracts 33 11 - (5) - 1 - - 40 EBITDA 875 (302) 28 33 25 18 8 (5) 680 Transaction fee on asset sale - - - - - - - 1 1 MtM losses/(gains) (656) 529 (8) (6) (2) - 1 - (142) Adjusted EBITDA $219 $227 $20 $27 $23 $18 $9 ($4) $539	

 	Reg. G Appendix Table A-2: Second Quarter 2011 Regional Adjusted EBITDA Reconciliation The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income: South Other Alt. ($ in millions) Retail Texas Northeast Central West Conventional Energy Corp. Total Net Income/(Loss) 17 $ 211 $ 16 $ 12 $ 11 $ - $ (11) $ 365 $ 621 $ Plus: Income Tax - - - - - 2 - (632) (630) Interest Expense 1 (1) 11 10 1 4 3 138 167 Depreciation, Amortization and ARO Expense 40 115 28 22 3 4 8 4 224 Loss on Debt Extinguishment - - - - - - - 115 115 Amortization of Contracts 45 14 - (5) - 1 - - 55 EBITDA 103 339 55 39 15 11 - (10) 552 Asset Write offs and Impairment of a Passive Portfolio Investment - - - - - - - 11 11 MtM losses/(gains) 96 (123) (11) (2) (3) - (3) - (46) Adjusted EBITDA 199 $ 216 $ 44 $ 37 $ 12 $ 11 $ (3) $ 1 $ 517 $ 	

 	Reg. G Appendix Table A-3: YTD 2012 Regional Adjusted EBITDA Reconciliation The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income: South Other Alt. ($ in millions) Retail Texas Northeast Central West Conventional Energy Corp. Total Net Income/(Loss) $804 ($501) ($53) ($19) $7 $16 ($22) ($179) $53 Plus: Net Income Attributable to Non-Controlling Interest - - - - - - (9) - (9) Income Tax - - - - - 4 - (137) (133) Interest Expense 2 - 9 9 - 7 22 283 332 Depreciation, Amortization and ARO Expense 85 229 65 46 7 8 23 5 468 Amortization of Contracts 67 19 - (9) - 1 - - 78 EBITDA 958 (253) 21 27 14 36 14 (28) 789 Transaction fee on asset sales - - - - - - - 9 9 CDWR legal settlement - - - - 20 - - - 20 MtM losses/(gains) (627) 618 4 25 4 - (3) - 21 Adjusted EBITDA $331 $365 $25 $52 $38 $36 $11 ($19) $839	

 	Reg. G Appendix Table A-4: YTD 2011 Regional Adjusted EBITDA Reconciliation The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income: South Other Alt. ($ in millions) Retail Texas Northeast Central West Conventional Energy Corp. Total Net Income/(Loss) $314 $238 ($19) $25 $24 $9 ($30) ($200) $361 Plus: Income Tax (3) - - - - 4 - (736) (735) Interest Expense 2 (16) 27 21 1 8 7 290 340 Depreciation, Amortization and ARO Expense 66 231 57 42 7 7 15 6 431 Loss on Debt Extinguishment - - - - - - - 143 143 Amortization of Contracts 93 28 - (10) - 1 - - 112 EBITDA 472 481 65 78 32 29 (8) (497) 652 Asset Write offs and impairment of a Passive Portfolio Investment - - - - - - - 492 492 MtM losses/(gains) (113) (28) (14) (14) (7) - 4 - (172) Adjusted EBITDA $359 $453 $51 $64 $25 $29 ($4) ($5) $972	

 	35 EBITDA and adjusted EBITDA are non-GAAP financial measures. These measurements are not recognized in accordance with GAAP and should not be viewed as an alternative to GAAP measures of performance. The presentation of adjusted EBITDA should not be construed as an inference that NRG’s future results will be unaffected by unusual or non-recurring items. EBITDA represents net income before interest (including loss on debt extinguishment), taxes, depreciation and amortization. EBITDA is presented because NRG considers it an important supplemental measure of its performance and believes debt-holders frequently use EBITDA to analyze operating performance and debt service capacity. EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are: EBITDA does not reflect cash expenditures, or future requirements for capital expenditures, or contractual commitments; EBITDA does not reflect changes in, or cash requirements for, working capital needs; EBITDA does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt or cash income tax payments; Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and Other companies in this industry may calculate EBITDA differently than NRG does, limiting its usefulness as a comparative measure Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to use to invest in the growth of NRG’s business. NRG compensates for these limitations by relying primarily on our GAAP results and using EBITDA and adjusted EBITDA only supplementally. See the statements of cash flow included in the financial statements that are a part of this news release. Adjusted EBITDA is presented as a further supplemental measure of operating performance. Adjusted EBITDA represents EBITDA adjusted for mark-to-market gains or losses, asset write offs and impairments; and factors which we do not consider indicative of future operating performance. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. As an analytical tool, adjusted EBITDA is subject to all of the limitations applicable to EBITDA. In addition, in evaluating adjusted EBITDA, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release. Adjusted cash flow from operating activities is a non-GAAP measure NRG provides to show cash from operations with the reclassification of net payments of derivative contracts acquired in business combinations from financing to operating cash flow. The Company provides the reader with this alternative view of operating cash flow because the cash settlement of these derivative contracts materially impact operating revenues and cost of sales, while GAAP requires NRG to treat them as if there was a financing activity associated with the contracts as of the acquisition dates. Free cash flow, before growth investments is adjusted cash flow from operations less maintenance and environmental capital expenditures, net of financing for specific environmental projects and preferred stock dividends and is used by NRG predominantly as a forecasting tool to estimate cash available for debt reduction and other capital allocation alternatives. The reader is encouraged to evaluate each of these adjustments and the reasons NRG considers them appropriate for supplemental analysis. Because we have mandatory debt service requirements (and other non-discretionary expenditures) investors should not rely on free cash flow as a measure of cash available for discretionary expenditures. Reg. G	

 
Set forth below is the transcript for the Second Quarter 2012 NRG Energy, Inc. Earnings Conference Call held on August 8, 2012
 
Operator: Good day, ladies and gentlemen and welcome to the second quarter 2012 NRG Energy Incorporated earnings conference call. My name is Erin, and I’ll be your coordinator for today. At this time all participants are in a listen-only mode. We will be facilitating a question-and-answer session toward the end of today’s conference.
 
(Operator Instructions)
 
As a reminder, this conference is being recorded for replay purposes. I will now turn the presentation over to your host for today’s conference, Mr. Chad Plotkin, Vice President Investor Relations. Please proceed, sir.
 
Chad Plotkin: Thank you Erin, and good morning everyone. Welcome to our second quarter earnings call.
 
This morning’s call is being broadcast live over the phone and via webcast, which can be located on our website at www.nrgenergy.com. You can access the call, associated presentation material, as well as a replay of the call in the Investor Relations section of our website. This call including the presentation and Q&A session will be limited to no more than 45 minutes. As such, we ask that you limit yourself to only one question with just one follow-up.
 
Before we begin I urge everyone to review the Safe Harbor statement provided in the presentation which explains the risks and uncertainties associated with future events and the forward-looking statements made in today’s press release and presentation material. We caution you to consider the important risk factors contained in our press release and other filings with the SEC that could cause actual results to differ materially from those in the forward-looking statements, and the press release in this conference call.
 
In addition, please note that the date of this conference call is Wednesday, August 8, 2012, and any forward-looking statements that we make today are based on assumptions that we believe to be reasonable as of this date. We undertake no obligation to update these statements as a result of future events, except as required by law.
 
During this morning’s call, we will refer to both GAAP and non-GAAP financial measures of the Company’s operating and financial results. For complete information regarding our non-GAAP financial information, the most direct comparable GAAP measures, and a quantitative reconciliation of those figures, please refer to today’s press release and this presentation.
 
With that, I’ll turn the call over to your host, David Crane, NRG’s President and Chief Executive Officer.
 
David Crane: Thank you, Chad, and let me add my good morning to everyone, and thank you for joining us on this, our second quarter call. I’m joined as usual by Mauricio Gutierrez, our Chief Operating Officer, who will be

 
presenting, as well as Kirk Andrews, our Chief Financial Officer, who will be presenting. Chris Moser, who runs commercial operations for NRG is with us and available to answer any questions that you might have.
 
As we go into this call, I think that a lot of it may be anticlimactic compared to previous earnings calls, because as everyone I think on the phone is aware, we did speak with everyone just two and-a-half weeks ago, where in the context of announcing the pending transaction with GenOn, we gave a sense of where we would be for the second quarter. We are acutely aware that most of you on the phone were kind enough to give us your time at that point, so we don’t expect — we figure what we can give back to you here is we’re going to keep this call shorter than normal, no more than 45 minutes.
 
One other small matter that I wanted to mention to everyone before we get into the call, which is a little bit unusual, is that I’m actually not physically with my colleagues in the Princeton office, but in fact I’m participating on this call from Nevada where I’ve spent the last two days visiting our Ivanpah project under construction in the desert about 45 miles south of Las Vegas. And since I’ve been down there I’m pleased to report to all of the NRG shareholders on the phone that construction is proceeding smoothly at that site. We expect to start testing the first unit in November of this year and we’re on track for completion in 2013 and it is a truly impressive undertaking there. And our partners in this transaction, our ownership partners, Google and our technology partner, BrightSource, and the construction company, Bechtel, are doing a fabulous job.
 
So let’s get into this. I’m going to refer to the slide presentation that’s on our website, so on slide 4, in terms of second quarter highlights, starting financially. I think as most of you know, given the normal seasonality, the second quarter is not generally the most exciting quarter for competitive power companies, or IPPs.
 
For us, it’s better than most, and this is in part due to the fact that the summer comes earlier in Texas than it does in the northeast United States, and that has a good result on both our wholesale and our retail business. And of course the advantage we have over most others is the fact that we do have a particularly vibrant retail business and our second quarter results, which are listed on this page, and which Kirk is going to go into greater detail on, shows this $539 million of EBITDA for the quarter, which rolls up to $839 million for the first half of the year. Not listed on this page is a very robust free cash flow performance for the quarter, but Kirk’s going to go into that, so I don’t want to steal his thunder.
 
We did list the retail contribution, and this is very important, obviously, in a year where I think to date in the summer, as I’m sure people are wondering about, even as we get into the third quarter, we’ve had sort of broadly good weather, summer weather across most of the United States. We have not had the extreme weather in Texas that we had last year, and so the contribution from retail is very important and very positive.

 
As we mentioned two and-a-half weeks ago, and we will reaffirm yet again today, we are reaffirming our guidance for the year 2012, and in a good position to reach that. We also again reiterating what we talked about two and-a-half weeks ago. We are giving preliminary guidance for 2013 and 2014 and per undertakings that we’ve made since then. Kirk’s going to give a little bit more detail on how we get to those points. Obviously, this guidance in this presentation is given for the Company on a standalone basis, which actually serves as a building block for what we actually expect to achieve when we successfully close the deal with GenOn at the end of the year.
 
I think the important thing to me about this preliminary guidance, and there was a lot of discussion on this in the last quarterly call is that after several years of — in a declining, low commodity price environment with hedges wearing off, which has sort of led to declines in our full year, full Company performance, is that we intend to and expect to stop that decline in terms of the range of outcomes that we expect. And this is largely as people will see when Kirk talks about it, because the other parts of our business are coming on to support our original wholesale business.
 
Beyond our financial results as listed on this page very quickly as everyone knows, we also are moving on several fronts in terms of doing things which we think are in the great interest of our shareholders. We’ll be making our first dividend payment, first ever, record date August 1. Payment to be made on August 15. We increase our overall corporate liquidity position through the sale of Schkopau, which was our last remaining non-core asset in Germany. And as I mentioned with Ivanpah, our other solar projects remain on track, and you may have seen a recent announcement that Agua Caliente is now the largest operating photovoltaic plant in the US, and is massively ahead of schedule.
 
Moving to slide 5, which just, again, a slide which sort of depicts the strategic direction of our Company in the wake of what — of the NRG GenOn proposed combination. I think this is well-known to everyone on the phone. The combination itself is the center of our Management focus, but in the context of our investor outreach over the last couple of weeks, we really didn’t find any investor that had any serious question about how this fit with the strategic direction of NRG, so I’m not going to dwell upon it.
 
Obviously, while the strategic logic is clear and compelling, as Management what we’re paid by our shareholders to do is achieve the financial results that can come out of the combination. So we’re very focused already in terms of integration planning on this $300 million of combination synergies that we expect that we can get out of this transaction, and planning is proceeding very well for that, even though it’s in the early days.
 
So finally, before I turn it over to Mauricio to talk about the second quarter operating performance on page 6, we put down the approvals that we need to achieve in order to get to GenOn. Again, transaction done. Again, it’s early days, but the filings are proceeding on time. We haven’t really come across anything, or had anyone sort of raise their

 
hand and say they see a big problem with this. And so we’re very confident about the direction of this transaction and the timetable, and continue to be on target for closing by the first quarter of 2013.
 
I look forward to answering any questions that you have later and with that I’ll turn over the call to Mauricio.
 
Mauricio Gutierrez: Thank you, David, and good morning. Our integrated platform continued to perform well during the second quarter, despite cooler weather across Texas and lower power prices compared to last year. Our operations group successfully brought the last remaining unit at our Bertron plant in Texas out of mothballed status.
 
On the commercial front we kept our focus on managing the exposure in Texas this summer given the increased volatility in the market. Retail had another strong quarter, growing both customer counts and margins. Finally, our construction projects out west, both solar and conventional, remain on track.
 
Moving on to our operational metrics on slide 8 and starting with safety. 40 of our 51 facilities finished without a single recordable injury, giving us another quarter of top performance across the fleet. We are proud of our strong safety culture and continued commitment to safety excellence, and as such, I am very pleased to inform you that our Big Cajun II plant outside Baton Rouge received VPP Star recognition from OSHA. This is the highest level of recognition in the program, and Big Cajun is our tenth plant in the fleet to receive this honor. I want to congratulate all our colleagues at Big Cajun for achieving this important safety milestone.
 
Our total generation was down 7% for the quarter compared to last year. We continue to see lower production from our coal fleet, primarily due to mild weather, low prices, and additional maintenance outage days compared to last year. As we have said before, the benefit of performing these maintenance outages with little opportunity costs more than offset the negative impact from our availability metrics. The reduction in coal generation was partially offset by higher production from our Encina plant in California, our combined cycle facility in South Central, and the return of STP from its unplanned outage.
 
Our gas portfolio continues to perform exceptionally well with a 98% starting reliability. Longer run times this quarter reduced the number of starts by 30%, leading to less stress on our units.
 
Moving on to slide 9. NRG’s Retail business had another strong quarter. Year-to-date, our combined Retail business grew by over 60,000 customers, while also increasing volumes, even with weather less favorable than the second quarter of 2011. Furthermore, the business added new products and expanded into new geographic markets. We now have a retail presence in 12 states with over 300,000 customers buying more than one service from our retail business.
 
For the quarter, margins increased slightly driven primarily by lower supply costs. Our enhanced retail supply strategy mitigated the impact of

 
price spikes during the heat wave in late June. The result for the quarter is that we struck a balance between customer count and margin, consistent with our long-term strategy, and this strong performance enabled NRG to remain the largest retailer in Texas.
 
Turning to slide 10. I want to share a few observations on two of our key value drivers. Lets me remind you that our generation portfolio, like any other merchant, is significantly leveraged to both heat rates and natural gas prices. Our Retail business provides counter cyclical earnings, which we continue to realize this year. Our risk management framework allows us to be exposed to short-term price spikes with our peaking units. And more broadly, structural commodity changes in the medium to long term.
 
In Texas, so far this summer has been relatively moderate with just a few hot days at the end of June and July. Those were enough to set new peak load records for each month. Leading prices have been low as a result of moderate temperatures. Prices spike when hot weather showed up resulting in volatile week and month ahead markets. These spikes have provided us an opportunity to hedge some of our megawatts at attractive prices while managing our operational risk.
 
We continue to believe the market fundamentals in Texas are very bullish. Load growth is expected to remain robust. Reserve margins continue to tighten and are expected to be single digit as early as 2014. And the market reforms implemented by the PUCT are a good first step towards providing the right economic signal to spur new investments. But as you can see on the lower left chart, more structural improvements to the competitive market are required to achieve ERCOT’s reliability targets.
 
Turning to natural gas. There are some additional signs that the market has started to work off the excess supply and appears on its way back to a sustainable balance. Rig counts are down more than 50% from the peak, year-on-year gas storage surplus has been cut in half, and we’re seeing our sixth straight month of flat production. Gas prices have responded accordingly and have increased more than 50% over the past few months with forward prices also firming up.
 
Moving on to our hedging disclosure on slide 11. As you can see, we did not change significantly how we have positioned our portfolio. In the short term, we remain well insulated from natural gas prices and most of our exposure is to heat rates in Texas, where we believe recovery is imminent. In the medium to long term, we remain largely open, and if the market improves, we will benefit from a heat rate and a gas recovery.
 
Turning to coal, and more specifically transportation. We’re in advanced negotiations around our Limestone coal contract which expires at the end of this year. Our coal inventories remain manageable, and we continue to work with coal suppliers and rail companies to add flexibility into our contracts.
 
As I mentioned to you in prior calls, we are constantly evaluating the economic viability of all our power plants, particularly those in the northeast where capacity and energy prices have been significantly depressed and plant economics are challenged. I am pleased to inform you

 
that we have reached agreement with National Grid to allow two units at Dunkirk to continue operating until May of 2013, and our plant is very well positioned to fulfill the remaining reliability needs identified through 2015. Finally, while in the short term we’re pretty well hedged from gas prices, our integrated wholesale retail model, and our exposure to the Texas market will provide significant upside in the very near future.
 
With that, I will turn it over to Kirk for the financial review.
 
Kirk Andrews: Thanks, Mauricio. Beginning with the financial summary on slide 13, NRG has reported second quarter 2012 adjusted EBITDA of $539 million, with $320 million from our wholesale business, and $219 million from our retail platforms. For the first six months of 2012 adjusted EBITDA totaled $839 million, $508 million from wholesale and $331 million from retail. Cash flow from operations for the quarter was a robust $661 million, which helped drive free cash flow before growth of $413 million through the first half of 2012. Our first half performance also led to a $300 million improvement in liquidity since year end 2011, which I’ll review in greater detail.
 
Turning to capital allocation. On July 22, NRG declared its first ever quarterly dividend of $0.09 per share, which will be paid one week from today on August 15. During the second quarter, we also made open market debt repurchases totaling $72 million, resulting in a commensurate reduction to our corporate debt.
 
Turning now to the guidance overview we provided on slide 14. As reflected in the first column of the slide we’re maintaining our guidance for 2012 EBITDA of $1.825 billion to $2 billion, and 2012 free cash flow before growth of $800 million to $1 billion. In addition, we’re reaffirming the guidance ranges for 2013 and 2014 EBITDA and free cash flow before growth, which we established as a part of our announcement of the GenOn transaction on July 22. Specifically, we are maintaining a guidance for standalone adjusted EBITDA of $1.7 billion to $1.9 billion, and that’s for both 2013 and 2014. And we expect free cash flow before growth of $650 million to $850 million in 2013, and $500 million to $700 million for 2014.
 
Free cash flow before growth in 2014 is impacted by planned environmental capital expenditures, primarily in our south central region, and some modest increases in environmental spend in Texas. As I indicated in my remarks on July 22, the guidance ranges for 2013 and 2014 reflect our expectations for NRG on a standalone basis, and exclude the accretive benefits from the pending transaction with GenOn, which will be incremental to these numbers.
 
Finally, in order to provide some further clarity regarding our EBITDA guidance for each of these years, we’ve broken down the expected EBITDA contribution from our solar projects, retail and wholesale. And we expect our committed solar projects to contribute $70 million to $75 million of EBITDA in 2012. That’s an increase of about $5 million over the range of expected solar EBITDA I discussed during our first quarter call. That’s reflective of the impact of accelerating the pace of the construction in

 
our Tier 1 solar projects. As these projects continue to reach COD, we expect our EBITDA contribution to increase to a range of $200 million to $210 million in 2013 and $320 million to $330 million in 2014.
 
Our retail businesses is having delivered more than $330 million in EBITDA through the first half of the year, despite the milder weather, especially in Texas, remain on pace to contribute $625 million to $700 million in 2012. We expect retail to deliver EBITDA of $650 million to $725 million in 2013 and EBITDA of $675 million to $750 million in 2014, as we continue to reinforce our position as the leading retail provider in ERCOT and our expansion into the northeast delivers additional growth. Importantly, these retail numbers reflect our expectations for standalone growth and are prior to any of the additional benefits from significantly expanded Northeast generation platform resulting from the GenOn merger. The wholesale segment includes the addition of El Segundo, which will achieve COD in August of 2013, with 2014 benefiting from a first full year of operations at the plant.
 
Now turning to slide 15. On committed growth investments, we now expect a total of $470 million of growth investments for 2012, which represents a $45 million increase over our May 3 guidance of $425 million. This increase is primarily due to the accelerated spend in our big three solar projects, which as you know, are Agua Caliente, CVSR and Ivanpah, as well as investments in distributed generation. And for 2013 and 2014, we now expect a total of $379 million of growth investments, and actually that’s a $10 million decrease over our May 3 guidance of $389 million. And that’s largely due to the impact of accelerating that spend in 2012 that I spoke of a few moments ago.
 
Finally, turning briefly to corporate liquidity on slide 16. Our total liquidity increased by $336 million during the quarter, due to higher revolving credit facility availability, partially offset by lower restricted cash balances. The increase in the revolver availability was due largely to the impact of the Agua Caliente sell-down, and changes to cash and cash equivalents are primarily due to the net impact of $540 million of adjusted cash from operations, plus proceeds from the sell down. These items are offset by $448 million of capital investments, $104 million of debt payments and that includes the $72 million of open market purchases I mentioned a few moments ago.
 
Our liquidity position will be further strengthened during the second half of the year by the proceeds from the sale of Schkopau received in the third quarter. And that $174 million in sale proceeds will also increase our RP basket by a commensurate amount, which, when combined with the $250 million in net income for the second quarter, further enhances our ability to support our newly initiated dividend from an RP perspective. With the issuance of shares in connection with the GenOn transaction as I mentioned on July 22, which we expect to close by the first quarter, will further expand RP capacity, eliminating any perceived constraints on capital allocation flexibility on the whole going forward.
 
With that I’ll turn it back to David for some closing remarks.

 
David Crane: Well, thank you, Kirk. Erin, I don’t — I think everything has been said so Erin, if you’re — we’re ready for you to open the lines for any questions.
 
+++ q-and-a
 
Operator: (Operator Instructions)
 
Jon Cohen, ISI Group.
 
Jon Cohen: Hey, good morning. Just had a couple questions. First, on retail. Looks like you’ve had some pretty strong sequential quarter over quarter growth in customer numbers. Can you give us some indication of how much of that is in Texas versus some of the Northeast markets?
 
David Crane: Mauricio, do you have that information available in.
 
Mauricio Gutierrez: David, I don’t have it handy but we can get back to you, Jon, and give you the breakdown on the growth.
 
Jon Cohen: Okay.
 
David Crane: Jon, my rough sense is it’s about equal. It’s not a particularly remarkable outcome, but we will get you the exact numbers.
 
Jon Cohen: Okay. And Mauricio, on the northeast load, is there any rule of thumb or way to think about how much your supply costs would go down by having generation to back up load?
 
Mauricio Gutierrez: Well, I think the way we’ve always portrayed the synergy value between wholesale and retail in ERCOT, which is what we’re trying to replicate in the northeast, one, the collateral savings that we get by cost in generation alone. And then the second is just providing or being more comfortable capturing the load following premium using our retail vehicle as opposed to managing or hedging our portfolio in the wholesale market. So I would say that those are the two main drivers, and it is different depending on the market dynamics. But specific numbers I think it would be very difficult to tell you at this point what is incremental, what is the incremental value. In the past we have provided some guidance in terms of what are those benefits in Texas, and as we continue to integrate the northeast platform and expand our retail business in the northeast, we’ll provide you additional clarity on that.
 
Jon Cohen: Okay. Thanks. One question for Kirk. On page 15 there’s about $250 million or $260 million of conventional CapEx in ‘12 through ‘14. Is there an EBITDA contribution associated with whatever those investments are in your guidance of $1.8 billion?
 
Kirk Andrews: In the $1.825 billion to $2 billion in 2012 —
 
Jon Cohen: I’m thinking more about the ‘14.
 
Kirk Andrews: Okay, yes. Once you get to 2014, the bulk of those repowering projects, which is the biggest component of that is our El Segundo project out in California, which is online in 2014. So that

 
contributes a full boat of EBITDA in 2014. I don’t think we provided specific guidance as to what that is. I think it’s — the best way to think about it is just a little less than $100 million on an annualized basis once it reaches run rate in 2014.
 
Jon Cohen: Okay. But El Segundo I think the remainder of the spend is going to be project financed, right, so this is — should be other stuff as well. I know you’re thinking about expanding some plants in Texas. I was just wondering if there was any EBITDA contribution in there?
 
Kirk Andrews: The bulk of El Segundo or the bulk of the repowering project is El Segundo. There’s some minor degree of capital expenditures around eVgo and some of the new businesses, but the lion’s share of the EBITDA contribution from the repowering investments comes from El Segundo.
 
Jon Cohen: Okay. Thank you.
 
Operator: Angie Storozynski, Macquarie.
 
Angie Storozynski: Thank you. I know I asked this question last time but I just want to go back to it again. So you’re showing us $320 million to $330 million of EBITDA contributions from solar by ‘14. Could you tell me what’s the corresponding total debt for NRG for those projects?
 
David Crane: Kirk?
 
Kirk Andrews: Sure. Once you get out to 2012, total amount of — or 2014, I should say, the total amount of debt or the total capital associated with that is about $4.3 billion. Of that number, about $3 billion of that is the total amount of solar debt.
 
Angie Storozynski: Okay. But what’s your share? Is that $3 billion your share of debt of the solar debt?
 
Kirk Andrews: No. That would be on a consolidated basis.
 
Angie Storozynski: Well, okay. So what is the NRG service portion of the solar debt?
 
Kirk Andrews: If you go through Ivanpah for example, Ivanpah is about $1.5 billion in total debt. We obviously own 50.1% of that particular project. So if you were looking for an allocation of our percentage it’s about 50% of that. Agua Caliente is just under $1 billion worth of debt and we own 51% of that, by virtue of the transaction with MidAmerican. So you deduct basically 50% of those two components from the total.
 
Angie Storozynski: So roughly speaking about $2.1 billion of that debt would be serviced by NRG?
 
Kirk Andrews: Yes, I think that’s probably a good number, yes.
 
Angie Storozynski: Okay. And secondly, I know you’re not trying to give us any more insight into your retail growth prospects in PJM, but, how

 
should we think about it? I just, David and Mauricio, I doubt that you’re merging with GenOn for cost synergies only. I think that there is — there are growth prospects embedded in the plan. Could you give us a sense where we are now for PJM volume wise, and how we should think about it volume wise, not margin wise, but volume wise going forward.
 
David Crane: Mauricio, do you want to give that information?
 
Mauricio Gutierrez: David, I think at this point we’re not prepared to give information around the growth prospects in the northeast. I think that is — Angie, that’s something that we will provide you in the coming months. What I would say, and just to characterize a little bit more the growth that we have seen on our retail business, 50% has been in Texas, 50% has been outside of Texas, particularly in the northeast. Green Mountain, with some of the premium products have been very effective in the northeast market, particularly around mass customers. So we are very encouraged by those results. But, Angie, I think you should expect from us more disclosure around our growth prospects in the northeast. I will say that on the plans that we have provided and the forecast that we have provided through April 2014, the growth assumptions that we have are pretty conservative across the retail businesses.
 
David Crane: Angie, let me add to what Mauricio’s saying. Because I think if there’s any single thing that surprised us in terms of investor and analyst reaction to the proposed combination with GenOn is the extent to which people are interested, and even excited, about what this greater generation platform in the northeast will do for us on the retail side. And we are happy with that, because we agree with that. But I will tell you as we have done the evaluation of the combination with GenOn since the matter first came up a couple months ago, our first focus was on the cost synergies and the other synergies that were announced two weeks ago, and that — the second focus was then on the synergies we could achieve with GenOn just on the generation side of the business. To be frank, no part of the evaluation that the NRG Board did, or NRG Management did, said well wow, if we own all those other megawatts in the northeast, we can grow our northeast retail platform at twice the speed. That’s all going to be upside.
 
We will be evaluating that going forward and talking to you more about that. But I would say most of our customers in the northeast come from Energy Plus. And virtually all of Energy Plus’s customers are on month-to-month basis. One of the advantages this allows us to do is it will make it easier for Energy Plus, through their platform and our other retail platforms, to offer fixed price contracts. And that’s going to be an upside, because how many more customers that will attract and the profitability of that, we will be — we’ll be talking about it in the future. But none of that’s built into the basic calculation of why we want to do this transaction.
 
Angie Storozynski: Okay. Thank you.
 
Operator: Dan Eggers, Credit Suisse.

 
Dan Eggers: Hey, good morning, guys. Mauricio, I was wondering if you could give a little more update on what you guys are seeing in ERCOT, by way of coal to gas switching coming back with the gas price rally, both as the second quarter progressed, and what you guys are seeing as we’ve rolled through July at this point.
 
Mauricio Gutierrez: Well, I think, Dan, if you look at — we tried to provide some specific examples on the earnings slides. With the gas rally, kind of out of the PRB switching area, you’re starting to get — getting closer to the Eastern coal markets, particularly in Texas. I would say the combination of that and some heat rate recovery, we have seen the reversal of that coal to gas switching that we experienced in January. So that’s what I would say in terms of coal to gas switching. Our expectation, and keep in mind, natural gas is one component, but the heat rate, which from our perspective, there is a small relationship between heat rate and natural gas, but to a greater extent heat rates are a function of the tightness in the market. Natural gas has other different drivers. We think that, we don’t expect that to persist I guess in balance of the year. Certainly on the forward market, when you start getting into ‘13, ‘14, ‘15, with gas prices in the high $3s, low $4 territory, you’re significantly out of the PRB switching area.
 
Dan Eggers: Okay. Thanks. And I guess just on ERCOT in general, obviously the price caps you have maybe room for some more volatility in pricing, but probably not enough to attract or sustain attractive and durable investment in new assets. Can you give us an update on conversations you guys are having as far as alternatives are concerned, and what kind of progression, or what steps we should be looking for as you guys see the conversations going.
 
Mauricio Gutierrez: Sure. I think you’re right, Dan. The forward spark spreads do not incentivize new build economics. We believe there is at least $10 per megawatt hour of offsite on the on-peak hours to start getting into that new build economics. And these are not necessarily based on very aggressive overnight cost to build. I think the range that we have provided is $800 to $1,000 per KW.
 
In terms of the conversations that we have been having with ERCOT and the PUCT, we want to see a well-functioning, competitive market that provides the reliability that the state requires. And I think the [Brower] report was very clear that even with the steps that the PUCP have taken in terms of price caps or floor prices on reserves, there is still a gap to incentivize those new builds. And that missing money has to come from somewhere else, whether it’s a research — a capacity market or some other form or type of resource of equity program. And from our perspective, it’s going to be — there’s going to be a lot of conversations around that topic. I think a lot of the constituents recognize that price gaps will not get you to the target reserve margin, that you need something else. Over the next couple of weeks through the ERCOT workshops I think we’re going to be discussing that with other constituents. But I think everybody recognizes that there’s got to be something else done to be able to incentivize those new build economics.

 
Dan Eggers: Mauricio, thinking about kind of the time line between the workshops and people trying to build toward a consensus for something else, what do you think is the realistic conversion from some sort of conclusion here to an implementation and how it could affect the power markets from a tangible, monetary perspective?
 
Mauricio Gutierrez: Look, I mean, if you take your reserve margin as your barometer on how tight is supply, demand. You’re seeing in 2014, basically single digit reserve margins, significantly below the 13.75% target from ERCOT. I think timeline, I think in the next couple of months we’re going to see a pretty good conversation around what other steps need to be taken. But we will be — we would be happy to continue this conversation, Dan, in terms of the clarity and the visibility that we see in the ERCOT process.
 
Dan Eggers: Great.
 
David Crane: Dan, if I could just add to that. Because I never want to predict when government entities or quasi government entities do things so it’s best not to make a prediction on that. But in our conversations with the powers that be down there, they obviously, as Mauricio says, they do have a sense of urgency about this. So hopefully whatever happens will happen in a very timely fashion.
 
Dan Eggers: Thanks, guys.
 
Operator: Gregg Orrill, Barclays.
 
Gregg Orrill: Hi, thanks. Sorry to stick with the last question, but I was wondering if you could elaborate a little bit more on kind of the unwillingness, it seems to — or the trouble that policy makers are having with moving to a capacity market in Texas.
 
David Crane: Well, Gregg, I don’t know if there’s any magic to the words capacity markets. In California they have sort of the resource adequacy, and I think there’s a greater sense among the policy makers in Texas that something akin to capacity market, or something that has the same consequences or impact is necessary. But to be frank, we don’t really care what it’s called and we don’t think it needs to be exactly the same as what they have in PJM or any of the northeast markets, as long as it works and sends the right price signal. So that’s the type of dialogue we’re having with them. As Mauricio said, we’ve been very encouraged that there has been dialogue with the people, the stakeholders in the market with us, and we presume with others, about how things would work and things like that. So I think the historic reluctance to go down that path as a practical matter is modifying. I don’t think that what ERCOT will end up doing is something that — I don’t think you need to worry that you’re going to wake up one day and say we just adopted the PJM capacity market model full stop. I don’t think that’s what will happen.
 
Gregg Orrill: Great. Thank you.
 
Operator: Brian Chin from Citigroup.

 
Brian Chin: Good morning. In the last few weeks we’ve gotten a fair amount of updates on San Onofre out in California. Could you just comment on what does the bilateral capacity market or resource adequacy outlook in California look like over the next few months to year, say? How has that changed? And then can you give us a little bit of color on, particularly on the Encina resource adequacy contract, which I think expires at the end of the year, when we might hear sort of recontracting news around that?
 
David Crane: Well, I mean, yes, I don’t know if Mauricio will be able to answer your second question, but he’ll give it the old college try or else he’ll avoid it. But, just for everyone on the phone, San Onofre, the difficulty at San Onofre has had a very significant impact on our Encina plant, the existing plant, and from my perspective, the prospects for Encina going forward, since it’s located in a very similar position in the grid, and Encina has worked, been online much more this summer. Actually, Brian, I’m sorry, what was the first part of your question about San Onofre and its impact on us?
 
Brian Chin: Just wanted to get a sense of have you seen the resource adequacy values or contracting environment for power plant assets in Southern California tick up as a result of the difficulties at San Onofre?
 
David Crane: Well, I mean, our official position, we don’t comment on anything that might be pending but I would say consistent with my remarks, there has been much greater interest in the power from Encina since San Onofre started with its difficulties. But I think we need to leave it at that on that specific question. But in terms of impact on the market, Mauricio, do you want to talk about that, the resource adequacy market?
 
Chris Moser: This is Chris Moser. I’ll jump on that one, David, if that’s all right.
 
David Crane: That’s fine, Chris.
 
Chris Moser: Okay. What we’ve seen so far is a lot of uncertainty on potential return dates. Obviously, that really has — what it’s done is muddied the water quite a bit. It’s obviously a big unit there that’s missing and no one knows when it’s coming back. So, really that’s thrown a big cloud of uncertainty around that. So what we’ve seen is bid ask on the capacity, or on the resource, has really kind of widened out and that’s about the update that we have right now. I can’t say that it’s tracking one general direction because it’s so wide right now, because no one knows really what’s going to happen out there.
 
Brian Chin: Could I ask what the bid ask numbers actually are.
 
Chris Moser: I can get those for you. I don’t have them — we can go into some details another time. I think we’ve got another couple people we still need to get through. We can chat about that at another point.
 
Brian Chin: Okay. I’ll follow up with you offline. Thanks.

 
Chris Moser: Sounds good.
 
David Crane: Operator, I think we have time for two more questions. We want to adhere to our undertaking to get people on their way earlier this time.
 
Operator: Julien Dumoulin-Smith, UBS.
 
Julien Dumoulin-Smith: Good morning. Firstly, not to beat a dead horse here, but on retail again, in the Mid-Atlantic as you look at the northeast expansion here, is it more of a C&I push. I think that’s what you guys had historically articulated or is it more of a mass market push through Green Mountain and Energy Plus, et cetera?
 
David Crane: Well, Julien, first of all, I think that we’re obviously going to be active in both but in the absence of Jason, I would say that I don’t think we actually ever have historically said it would be more of a C&I push. I think that it would be, if either, a little bit more of a retail push, although we have an active C&I capability that’s working in the region and doing a good job. There’s been more pressure on C&I margins than there has been on the retail side. So as we have done in Texas, we’ll probably pursue both. But since you said more C&I, I wanted to push back and say maybe a little bit more mass market.
 
Julien Dumoulin-Smith: Great. Thanks for the clarity. Perhaps talking about some of the developments in New York, what kind of improvement do you think we could look towards in 2013 in the northeast segment? Not to provide guidance, but just getting a sense on New York, seems like that could be pretty material.
 
David Crane: The New York capacity markets, Mauricio, you want to talk about that?
 
Mauricio Gutierrez: Sure. Julien, as you know, there is a — I would say that there is quite a bit of uncertainty about retirement dates. People pulling in and out plants from mothball status and not so. We actually, in general, we believe that the northeast either because of the economics that are significantly challenged for the plants, or some of the environmental regulations, we believe that the capacity markets will start moving towards a constructive territory. And in terms of the timing, when that’s going to happen, I think there is quite a bit of uncertainty. We saw how I would say digital the price can be in New York, just by virtue of having one unit announced mothball, that they’re retiring and then taking a second look. So I would say that the — I think that the fundamentals are there and it’s just a matter of determining when that will happen.
 
Julien Dumoulin-Smith: Great. Thank you for the clarity.
 
David Crane: Do you have one more caller.
 
Operator: Keith Stanley, Deutsche Bank.

 
Keith Stanley: Good morning. I’ll stick to just one question, given the time here. Can you just provide a little more color on progress and a potential time frame for selling down more of the solar portfolio or looking at the tax equity market? I would think as some of these projects are coming into service, and now more rapidly than you guys initially thought, the amount of the makers and ITC tax benefits are going to start to increase pretty rapidly. And then as a second part of my question, are there any restrictions at all in place on sell downs of solar assets or accessing of the tax equity market under the merger agreement?
 
David Crane: Well, Keith, I think let me — the second question about — it seemed like a three part question for one question. But at least the second part about the sell-downs or — Kirk can answer those questions. What I would say to you is, from our perspective, for us when we sold part of our Agua Caliente to MidAmerican, we demonstrated that we could sort of sell down these assets at value. I think we said at that time, and it continues to be the case, that our testing of that market has indicated that there are many viable players that are interested in positions in these assets. But if you want to sell at maximum value with the broadest possible range of potential buyers, you need to do that as close to — you need to eliminate the sort of tail construction risk to the fullest extent possible. We are happy where we are for now, but as you say, with the plants coming online over the next few months, you could see more activity in that area. But — and on the tax equity side, I mean, I think the short answer is, we are looking at that market on a sort of a continuous basis to deal — to optimize the tax benefits. But Kirk, do you want to elaborate on that?
 
Kirk Andrews: Sure. First of all, Keith, in reverse order of your questions, we have the flexibility in the merger agreement to continue to pursue sell-downs, especially on the larger projects, and I’ll use that as a segue to answer your other question. We’re certainly continuing to pursue straight sell-downs along the lines what you saw Agua Caliente. I think if I had to predict, that is the that is the type of monetization you’d see, more along the lines of our larger solar projects, the big three. We are also in parallel continuing to work on the tax equity front, and that’s more likely to be the case with respect to some of the smaller projects, for example, the remaining six of our Tier 1 solar portfolio. And we would expect to provide some additional updates on that as we progress in those efforts but we have full flexibility to pursue both of those opportunities or avenues during the pendency of the merger.
 
Keith Stanley: Thanks a lot. That’s very helpful.
 
David Crane: Well, Erin, I think we’ve run over our stay, so I just want to thank everyone for participating in this call. Obviously, we will be back with you for our third quarter earnings call at around the beginning of November. But given that we do have the GenOn merger pending, and I think there will be events, approvals, and all you’ll be hearing from us, and we will obviously be involved in the continuous investor outreach that we’re always involved in. And any questions anyone has, please feel free to call Chad and Stefan at NRG’s IR Group. So thank you all very much for participating. We look forward to talking to you soon.

 
Operator: Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.
 
Forward Looking Statements
 
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, each party’s 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 stockholder, antitrust, regulatory or other 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 NRG’s and GenOn’s most recently filed Annual Reports on Form 10-K, subsequent Quarterly Reports on Form 10-Q, recent Current Reports on Form 8-K, and other SEC filings.

 
Many of these risks, uncertainties and assumptions are beyond NRG’s or 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 neither NRG nor GenOn undertakes any 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 NRG, GenOn, the proposed transaction, the combined company or other matters and attributable to NRG or GenOn or any person acting on their behalf are expressly qualified in their entirety by the cautionary statements above.
 
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. The proposed business combination transaction between NRG and GenOn will be submitted to the respective stockholders of NRG and GenOn for their consideration. NRG will file with the Securities and Exchange Commission (“SEC”) a registration statement on Form S-4 that will include a joint proxy statement of NRG and GenOn that also constitutes a prospectus of NRG. NRG and GenOn will mail the joint proxy statement/prospectus to their respective stockholders. NRG and GenOn also plan to file other documents with the SEC regarding the proposed transaction. This communication is not a substitute for any prospectus, proxy statement or any other document which NRG or GenOn may file with the SEC in connection with the proposed transaction. INVESTORS AND SECURITY HOLDERS OF GENON AND NRG ARE URGED TO READ THE JOINT PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS THAT WILL BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. Investors and stockholders will be able to obtain free copies of the joint proxy statement/prospectus and other documents containing important information about NRG and GenOn, once such documents are filed with the SEC, 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. These documents can be obtained free of charge from the sources indicated above. Other information regarding the participants in the proxy solicitation and a description

 
of their direct and indirect interests, by security holdings or otherwise, will be contained in the joint proxy statement/prospectus and other relevant materials to be filed with the SEC when they become available.