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

Set forth below is the transcript for the Third Quarter 2012 NRG Energy, Inc. Earnings Conference Call held on November 2, 2012

Operator: Good day, ladies and gentlemen, and welcome to the Q3 2012 NRG Energy Earnings Conference Call. My name is Laura, and I will be your operator for today. At this time, all participants are in listen-only mode, and we will conduct a question-and-answer session toward the end of the conference.

(Operator Instructions)

As a reminder, this call is being recorded for replay purposes. Now I’d like to turn the call over to Mr. Chad Plotkin, Vice President, Investor Relations. Please proceed, sir.

Chad Plotkin - NRG Energy Inc - VP, IR: Thank you, Laura, and good morning, everyone. I’d like to welcome you to NRG’s Third Quarter 2012 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 one hour. As such, we us that you limit yourself to only one question with just one follow-up.

Before we begin, I urge everyone to review the Safe Harbor information provided in today’s 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 in the press release and this conference call. In addition, please note that the date of this conference call is Friday, November 2, 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 directly comparable GAAP measures, and a quantitative reconciliation of those figures, please refer to today’s press release and this presentation. With that, I would like to turn the call over to David Crane, NRG’s President and Chief Executive Officer.

David Crane - NRG Energy Inc - President and CEO: Thank you, Chad, and good morning, everyone. Today, I am joined, as usual by Mauricio Gutierrez, our Chief Operating Officer, and Kirk Andrews, our Chief Financial Officer, and both of them will be giving part of the presentation today. I am also joined by three other executives of the Company who will be available to answer your questions, Chris Moser, who, as you know, runs the trading operations, will be available to answer any questions you have about the commodity markets that we are involved in. And for the first time, we have with us today Elizabeth Killinger, the President of Reliant, and Jim Steffes, the President of Green Mountain. Elizabeth has just recently become President of Reliant, but she’s been with the Company for ten years, and most recently,

she’s been responsible for the residential business for Reliant and the customer operations business for all of Reliant. Jim joined us several months ago from Direct Energy when Paul Thomas retired from Green Mountain, and I think the important thing about both of them is both of them have been integral to the success of NRG’s retail business in the year to date. So we’ll look forward to them getting to know you and you getting to know them.

So, as we get into it, I first want to say how much I appreciate you joining us on this call and also for your understanding of our interest in moving the call from Wednesday when it was originally scheduled in today. As everyone’s been very busy over the past few days, this call also represents my first opportunity to speak to the NRG staff as a whole since the storm, so I hope you will be patient if I touch upon a couple of points that might naturally be of more interest to employees than to external investors. Obviously, with our headquarters in Princeton, New Jersey, and many of our employees resident in the Princeton area, the functioning of our headquarters was significantly impacted by Hurricane Sandy and its aftermath. Even as we speak, our main headquarters building is running an emergency backup power, and most of us are living in homes without light, heat, or in some cases, running water. So while the obvious purpose of this call is to discuss our financial performance over the course of a quarter which ended more than a month ago, I would be remiss if I did not first address the natural calamity that was visited upon the mid-Atlantic and Northeast states this past week.

First and foremost, we hope that everyone participating on this call and each of your loved ones is safe and sound after Hurricane Sandy. I’m pleased to report that all of our own people and their families are accounted for. But, as we all know, everyone in our home state of New Jersey has not been so fortunate. There’ve been multiple fatalities, and beyond, many more injured, some seriously, and billions and billions of dollars in property damage particularly in our coastal regions. As has been the practice at NRG in the wake of every natural catastrophe since the Indonesian tsunami several years ago, I am pleased to announce today a triple matching program open to NRG employees and benefiting first responder NGOs providing essential aid and services to New Jersey and to those who have lost everything this past week.

Secondly, I am pleased to report that our generation fleet in the Northeast performed very well during and since the storm. Most of our plants were online as the storm approached and performed as they were called upon to do by the system operator. We experienced no material damage to any of our assets, and as such, we do not expect the storm to have a material impact on our financial or operational performance.

Third, I want to express my deep respect, appreciation and my profound admiration for the men and women of NRG who, as these terrible storms approached, voluntarily separated themselves from their families in order to keep our power plants running, our IT systems operating, and our call center staffed to provide full customer service. Even in normal circumstances our employees know that we are engaged in a 7 times 24 business. In the case of Hurricane Sandy, NRG employees too numerable to mention manned their positions and kept our plants running and ready to respond to disruptions to the system. As great an effort as was made by our own people, everyone at NRG recognizes that disruptive weather events like Sandy primarily impact the T&D end of the power sector, and while we at NRG are

not a T&D Company, our hats go off to the work crews from PSE&G and the other T&D utilities in the Northeast and from many other parts of the country who our working around the clock to restore the region’s transmission and distribution system.

Fourth and finally, allow me to make one long-term strategic point. Hurricane Sandy, like the other extreme weather events that have preceded it with increasing frequency in recent years, has vividly demonstrated once again how absolutely vital the constant flow of electricity is to virtually every facet of our society. Electricity is truly the lifeblood that animates our economy. As such, it strikes me as absolutely foolish that in order to energize the 21st century economy, we depend on an archaic poles-and-wires transmission system that remains mired in 1930s technology. I mean seriously, could you imagine that more than a decade into the 21st century, we base our entire electricity delivery system on wooden poles? So new cost-effective and cleaner distribute technologies exist that have the ability to free American consumers and businesses from this system, and NRG expects to be deeply involved in providing these grid-independent solutions to American businesses and residential customers in the future. Already, we have a team within NRG called our Reliability Services Group, which, while still very small relative to the total, is one of the fastest growing businesses within NRG. Today is not the day to elaborate on our plans in this area, but you’ll be hearing more from us in the future.

So, let’s turn to slide four into our performance in the third quarter. As you well know by now, there was a comparative absence of the summer heat in Texas this year, certainly relative to the blistering summer of 2011, yet our results, nonetheless, show the strength and resilience of our wholesale-retail business model, with the third quarter with $657 million of adjusted EBITDA for the quarter and $1.496 billion year to date. So even notwithstanding the mild winter in the Northeast last winter followed by the comparatively mild summer just ended in Texas, I’m pleased to report that we are on track to achieve a full-year financial result around the center of our original guidance range. Beyond EBITDA, there is the familiar, positive NRG story of strong free cash flow generation with $806 million year to date of Free Cash Flow before growth.

Turning to slide 5, as we have posted solid summer results in the face of a non-cooperative weather environment, I believe it’s worthwhile to reinforce the point of why we see premium value in our integrated wholesale-retail business. As you recall after our experience with the Texas summer of 2011, we went into the summer of 2012 with considerable length in our wholesale position in Texas. And as you can see from slide 5, wholesale volumes and spot prices were both dramatically lower year on year as a direct result of the absence of extreme weather, which — and this would’ve had a negative impact on our financial performance had we been only a wholesaler. However, conditions that were unfavorable for wholesale were broadly favorable for retail. While load was down some 5% from 2011, the fact remains that when wholesale prices are depressed and load is strong, retail should and did perform very well. For NRG’s integrated model, the combination of these factors drives strong financial performance across the full commodity price cycle, essentially providing the financial floor to weather a weak wholesale environment while preserving the upside in the event of a robust wholesale price environment. It is this dynamic that largely should enable us to deliver to the midrange of our 2012 EBITDA guidance.

And turning to slide 6 before turning it over to Mauricio, let me make one comment about the still pending GenOn transaction. This should be the last earnings call on which we are reporting NRG on a standalone basis. The approval process is well on track, and no major substantive issue has been raised by or to any of the authorities whose approval of this acquisition is still pending. Integration planning is making great progress under a joint task force led by Anne Cleary of GenOn. She and all of her colleagues from NRG and GenOn engaged in the integration planning our doing a great job, and I’m pleased to report that we are well on track to identifying with great specificity all of the $175 million in cost synergies estimated and publicly disclosed at the time the deal was announced. In short, while a lot of hard work remains to be done in the implementation phase, I couldn’t be more pleased with where we stand as we approach the end of the planning phase. Likewise, I have a very high degree of confidence in the management team and indeed in all the personnel that have been identified to take the combined Company forward post closing. And with that, I will turn it over to Mauricio to talk in more detail about the Company’s performance during the third quarter. Mauricio?

Mauricio Gutierrez - NRG Energy Inc - COO: Thank you, David, and good morning, everyone. Before we go into the results for this quarter, I want to join David on expressing my respect and appreciation to our colleagues in NRG’s Northeast operations that kept our units available throughout the storm. To all of them, thank you, and job well done.

Now, back to the results for the quarter on slide 8, our integrated platform performed well despite low power prices across our Texas region. Our improved risk management activities not only protected the retail business during the few periods of high prices, but also provided an opportunity to price our wholesale portfolio at attractive levels in the weeks and months ahead markets leading and during the summer months. Our operational performance was solid, led by our South Texas Project’s perfect record during the quarter. Noteworthy is the plant record set by Unit 1 with 530 consecutive days in operation before entering a refueling outage this fall. This is a great accomplishment by the STP team and one that makes us all proud of their operating track record.

On the environmental front, I am pleased to announce a reduction in our environmental CapEx from $553 million to $440 million driven primarily by changes to our MATS compliance plan for Big Cajun II Unit 3. We conducted additional stack testing and engineering studies to evaluate the performance of the existing ESP units with activated carbon injection. Based on these results, the need for a back house on Unit 3 has been replaced with an [offering] to the ESP. The remainder of the reduction relates to completing the Indian River Project under budget thanks to the excellent job of our EPC group and changes in smaller air quality and 316(b) projects. The other positive news is that we have come to agreement with EPA on the terms of a settlement for the Big Cajun II NSR litigation. The agreement does include some control technology changes, but I cannot disclose the details as it will not be public until it makes its way through DOJ’s legal approval process. We do not, however, anticipate an increase in environmental capital beyond the $440 million already disclosed. Finally, El Segundo and our solar projects continue to remain on track with now more than 400 megawatts of solar expected by year-end. We have also begun construction of the 75-megawatt peaking plant at Parish which eventually will be used on our carbon capture project, while in the meantime, it will participate in the market during the next few years when reserve margins are expected to be the tightest.

Turning to our normal operational metrics on slide 9 and starting with safety. We are on pace to have the best safety year in our history and well within top decile performance. For the third quarter, 45 out of 51 facilities were without a single recordable injury. This is an outstanding accomplishment and further demonstrates our strong safety culture that leads to best-in-class operational performance. Total generation was down 8% for the quarter compared to last year as a result of both lower gas generation in Texas due to weaker prices and lower coal availability. This decrease was partially offset by higher gas generation in California, our Cottonwood facility, and Arthur Kill.

Moving on to slide 10, our multibrand retail business continued to deliver strong results with EBITDA now at $504 million for the first nine months of the year. In addition, we have now grown our retail portfolio by 124,000 customers in total and 79,000 customers in the Northeast, these driven by successful marketing sales and operations execution. (Inaudible) remains consistent with 2011, and customer acquisition is at our strongest levels. Our affective hedging and supply management strategy, combined with innovation and premium customer service, have enabled us to maintain our margin levels despite sustained low gas prices and rising heat rates as well as intense competition across customer segments. In fact, given the lack of scarcity pricing this summer, unit margins increased quarter over quarter. Outside of Texas, NRG’s retail business continues to innovate and expand by deepening our penetration in new markets where in less than two years, we have entered 11 states and the District of Columbia, and now 10% of our load service in the Northeast. Once again the result for the quarter is that we struck a balance between customer accounts and margin consistent with our long-term strategy. And this strong performance has enabled NRG to remain the largest retailer in Texas with a growing presence in the Northeast.

Based on recent conversations I’ve had with many of you, I want to provide some observations about the Texas summer on slide 11. On the supply side, capacity was relatively unchanged with a net increase of 1% summer over summer. However, on the demand side and with a return to normal weather, total load was lowered by 6% compared to the record summer of 2011. Despite these normal conditions, ERCOT still manage to set multiple monthly peak load records during the summer. We believe this underscores the fundamental strength of the Texas market. The combination of lower demand, unchanged supply, and the lack of sustained heat resulted in disappointingly low prices compared to last year. In fact, in a year with normal weather, prices were the lowest in a decade. This highlights the need for the additional market reforms approved and under consideration by the commission to ensure adequate supply for the growing power needs of Texas.

Turning to slide 12, we continue to see positive developments in both the natural gas and the Texas market. Over the past few months, the gas storage surplus that was alarming at the beginning of the injection season has almost disappeared, and it is heading back to the normal historical range. Production has remained stagnant now for close to 12 months in a row, and demand by the power sector is up by almost 17% for the year. As you can see on the lower left chart, cash prices have continued to increase, and forward prices have firmed up well above coal-to-gas switching territory for PRB generators but remain competitive vis-a-vis Eastern coal generators. As we saw through the previous slide, the PUCT remains focused and committed to ensure long-term resource adequacy solution. On August 1, the system-wide offer cap rates from $3,000 to $4,500 per megawatt hour, and

just last week on October 25, the commission unanimously approved a further increasing price caps up to $9,000 per megawatt hour by 2015. We are encouraged by these actions and will continue to work with the PUCT and other stakeholders to find a long-term solution. We remain very bullish in the Texas market. In fact, even under low economic growth case provided by ERCOT last week and the addition of new generation announced, reserve margins will fall below the target reserve margin by 2014.

Turning to slide 13, you can see from our hedging disclosure that we have increased our baseload gas schedules in 2013. In the short term, we continue to be well insulated from natural gas prices, and given the recent market changes in Texas, we have benefited from our open heat rate position. In the medium to long term, we retain significant exposure, so as the markets improve, we start to benefit from a heat rate expansion and gas recovery.

Since our last quarterly call, I am pleased to report two other items of note. First, our commercial team finalized the Limestone plant’s rail transportation contract under favorable terms. Second, our previously announced extension of our Form C call contracts were ratified by the Louisiana PSC. Both serve to position the Company well for the future.

Finally, and moving on to the GenOn combination on slide 14, as David mentioned in his comments, we are on track to meet our cost synergy targets, and I am pleased to say that we remain very optimistic about the operational synergies that will be gained in the new organization largely driven by the success of our core NRG program. On a standalone basis, we are currently on track to deliver $7 million over this year’s $30 million FORNRG target through a combination of asset optimization, property tax relief, and retail cost initiatives. With respect to the GenOn transaction, we have already identified the specific areas we will further evaluate once the transaction closes which will yield an improvement to our FORNRG targets of $10 million and $25 million respectively over the next two years. Areas where we see significant opportunity include aggressively reducing fixed costs such as property tax, implementing more flexibility in our operations staff through mobile and seasonal operations, evaluating opportunities to add natural gas capabilities, and leveraging a centralized procurement function. Finally and most importantly, after the transaction closes, we will be able to refine our estimates. And if past performance is an indication, we hope to more than deliver on these results. With that, I will turn things over to Kirk for the financial review.

Kirk Andrews - NRG Energy Inc - CFO: Thank you, Mauricio. Beginning with the financial summary on slide 16, NRG is reporting third-quarter 2012 adjusted EBITDA of $657 million with $449 million from our wholesale business, $173 million from our retail platforms, and $35 million from our solar projects which are now a growing part of our financial performance. For the first nine months of 2012, adjusted EBITDA totaled nearly $1.5 billion, with $928 million from wholesale, $504 million from retail, and $64 million from our solar projects. Year-to-date, NRG has generated nearly $1 billion in adjusted cash flow from operations, which drove Free Cash Flow before growth of $806 million through the first nine months of 2012, placing us already within the range of our previous Free Cash Flow guidance for all of 2012. This performance also contributed to an increase of over $600 million in total liquidity since the year-end 2011 after taking into account the redemption of the remaining $270 million of our 2017 senior notes on October 24.

Turning to capital allocation, with the refinancing of the 2017 notes, we’ve now achieved $100 million in debt reduction toward our plan of at least $1 billion of deleveraging announced as a part of the GenOn transaction. Importantly, this reduction in debt combined with the lower coupon on the newly issued 2023 notes will result in an annual interest savings of approximately $14 million. This gives us a head start on realizing the $100 million in annual cash flow benefit driven by balance sheet efficiencies resulting from the GenOn transaction. And as Mauricio previously mentioned, our environmental capital expenditure forecast for 2012 through 2016 has also been reduced by approximately $110 million. This is primarily the result of a decrease in estimated cost related to MATS compliance, in particular at our Big Cajun II facility, as we’ve now completed testing based on the final MATS rules. The anticipated completion of projects below our original budget and shifts in compliance schedules based on regulatory changes also help drive the reduction in the cost estimate.

From an operational perspective, third-quarter highlights include a 21% improvement in Texas realized energy margin which is attributed to our portfolio optimization efforts that helped reduce the overall risk in our portfolio. Meanwhile, NRG’s three retail platforms continue to see strong customer addition with 124,000 total improvement in customer count led by an increase of 79,000 customers in the Northeast.

In summary, consistent with the expectations that I shared with you on our first-quarter call, over the last two quarters, we’ve seen EBITDA out performance from our solar projects, the continued strength of our retail businesses and improved effectiveness of our hedging and portfolio optimization efforts, all of which, despite the relatively milder weather this past summer, have now placed us ahead of pace on EBITDA versus the first nine months of 2011. This strong performance leads us to narrow our 2012 EBITDA guidance to the middle of our previous range. Which takes me to the guidance overview, which you’ll find on slide 17.

As reflected in the first column of the slide, we are narrowing our guidance for 2012 EBITDA to $1.875 billion to $1.925 billion and 2012 Free Cash Flow before growth to $900 million to $950 million. In addition, we are also reaffirming our standalone guidance ranges for 2013 and 2014 EBITDA as well as Free Cash Flow before growth. Specifically, we’re maintaining guidance for standalone adjusted EBITDA of $1.7 billion to $1.9 billion for both of 2013 and 2014, and we expect Free Cash Flow before growth of $650 million to $850 million in ‘13 and $500 million to $700 million for ‘14. As I indicated on our previous calls, the guidance ranges for 2013 and 2014 reflect our expectations for NRG on a standalone basis, excluding the accretive impact of the pending transaction with GenOn, which would then be incremental to these numbers.

As highlighted on this slide, we’ve broken down the expected EBITDA contribution from our wholesale, retail, and solar projects. The wholesale segment, which delivered $928 million in EBITDA through the first nine months of the year, is on pace to contribute $1.17 billion to $1.195 billion in 2012. We continue to expect wholesale to deliver EBITDA of $850 million to $965 million in ‘13 and $705 million to $820 million in ‘14. And these ranges include the impact of the addition of the El Segundo Energy Center Project which will achieve COD in August of 2013. Our wholesale guidance ranges also include the recurring savings from efficiencies and operational improvements resulting from our FORNRG program.

Our retail businesses, having delivered $504 million in EBITDA through the first nine months of the year, are expected to contribute $630 million to $650 million in 2012. These results are driven by both the success of our customer growth initiatives and focus on delivering customer value beyond the mere commodity. Collectively, these efforts both reinforce our leading Texas position and support our expanding presence in the Northeast. We expect retail to deliver EBITDA of $650 million to $725 million in ‘13 and $675 million to $750 million in 2014.

Our solar projects, which continue to exceed our expectations for the pace of EBITDA contribution, have delivered $64 million through the first nine months of ‘12 and are on track to contribute $75 million to $80 million of EBITDA in 2012. This reflects the impact of accelerating the pace of construction at our Tier 1 solar projects. As these projects continue to reach COD, we expect their EBITDA contribution to increase to a range of $200 million to $210 million in ‘13 and $320 million to $330 million in 2014.

Turning to committed growth investments on slide 18, we now expect a total of $690 million of growth investments for 2012, which represents a $220 million increase over our August 8 guidance of $470 million. This increase is solely attributable to changes in our solar investments, nearly all of which are associated with the timing of debt funding for our non-DOE utility projects, which we now expect to occur in the first quarter of 2013. And as a result, by the year end, we now expect to have fully funded in the aggregate our equity contributions to our Tier 1 solar portfolio. Our expectations for conventional growth investments are unchanged from our previous guidance.

And finally, turning to briefly to corporate liquidity on slide 19, as I mentioned earlier, total liquidity improved by more than $600 million since the year end after adjusting for the redemption of the remaining $270 million of the 2017 senior notes which occurred in October. This increase in liquidity is due to both improvements in cash balances as well as increased availability under our revolving credit facility. The $235 million increase in cash and cash equivalents since 2011 was driven by $993 million of adjusted cash from operations, $174 million in proceeds from the sale of Schkopau, $122 million in proceeds from the Agua Caliente Project selldown. That’s partially offset by $707 million of capital investments and $172 million of unsecured note paydowns, which includes the $100 million of deleveraging I mentioned earlier. Increases in our revolver availability remain largely the result of the Agua Caliente selldown in the first quarter which resulted in a $304 million reduction in LC posting.

We entered the final months of 2012 with a stronger balance sheet, including longer debt maturities, streamlined debt covenants, and improved liquidity, driven by successful monetization efforts and a year-over-year increase in EBITDA. These improvements, combined with a head start both on our deleveraging objectives and our cash flow synergies, place us on a solid financial footing to fully realize the substantial benefits of the GenOn transaction in 2013 and beyond. And with that, I will turn it back to David for his closing remarks.

David Crane: Kirk, thank you. In closing, let me say that one of the things we always try to do at NRG is tell the market what we’re going to do and then go out and try and do it. Toward that end, for the nine years that I have been in this job, it’s been my practice during the first quarterly call of the year to lay out for our shareholders what we hope to accomplish during the year ahead and then on the last

quarterly call of the year, to measure our progress against the objectives that were previously announced. Accordingly, on slide 21 you will find our goals for 2012 repeated from our February 2012 earnings presentation together with my personal assessment of how we have performed against those goals. Suffice it to say, I feel that we have substantially advanced and strengthened our position against each of the four pillars of our strategy, enhance core generation, expand retail, lead clean energy, and maintain prudent capital allocation.

Now, as Kirk was saying, we intend to end the year strong, close the GenOn transaction, and hit the ground running in 2013 as a 46,000-megawatt generator with ample liquidity, enviable asset portfolios across each of the three key regional competitive electricity markets in the United States, a robust and growing multimillion base of retail customers in markets that match up nicely with our generation, and a leading first-mover position in the provision of critical consumer-oriented and customer-focused clean energy technologies that we believe may have a disruptive impact on our sector over the medium to long term. The future is indeed bright for NRG. With that, Laura, we’d be happy to answer any questions that anyone might have.

Questions and Answers

Operator: Thank you.  (Operator Instructions)

Your first question comes from the line of Jon Cohen, ISI Group. Please proceed.

Jon Cohen: Hi, good morning.

David Crane: Morning, Jon.

Jon Cohen: My first question is on the Texas resource adequacy project. It seems like the only thing that all three commissioners and Brad (inaudible) can now agree on is that demand response has to be part of the solution in ERCOT, and I know Commissioner Anderson is hopeful that the reps can actually come up with some sort of a market-based solution to that, but I can’t really figure out how that would work. So, if Reliant, for instance, were to figure out some incentive to curtail customer load during the peaks, and that should lower prices for everyone, not just the Reliant customers, and the benefit you get from owning peaking would seem to erode. Have you given any thought to that? And how do you think such a demand response retail product might look, especially if there’s no consensus on a centralized capacity market?

David Crane: Well, Jon, let me first say, and I’m only going to say that we’ve given a lot of thought to it, and it is a competitive environment, and I’m not sure how much detail we want to give you, but I am looking at Mauricio who is shaking his head no. Elizabeth, do you want to say anything about this because, there is a clear opportunity here?

Elizabeth Killinger: We have invested over the years in our e-Sense suite of products, which actually includes everything from time-of-use products to some device-based solutions, and we have thousands of customers on products like that, and we do believe that there will be growing needs and interests in products like that, and we’re continuing to develop those in the months ahead.

Jon Cohen: Okay, thanks for that. And I just had one other question for Kirk on solar. And I guess the question is, once you have the projects up and running, and they reach COD, how much time do you have to sell down a stake to a JV partner or to tax equity before the unutilized tax losses have to be booked on the balance sheet and be taken down over time versus monetized immediately? And is that the end of the tax year? Or do you have another year after that? And the second question is, in your standalone Free Cash Flow guidance, how much of the cash flow can be attributed specifically to the utilization of solar tax losses in ‘13 and ‘14?

Kirk Andrews: Sure to answer your first question, Jon, on the Free Cash Flow side, once we reach the levelized contribution of EBITDA which comports with that range in 2014 of $300, $333 million, the corresponding cash flow associated with that number which we expect from the projects, which is really solely the result of the operating cash flow separate and apart from the benefits of the — on the tax side, is approximately $80 million. Now, above and beyond that, while we are not currently in a position to be a taxpayer given our NOL balance, over time, our utilization of that beyond 2014 will enhance the cash flow benefits above and beyond the number I just shared with you.

As far as selldowns are concerned, the opportunity for us to engage in selldowns really, it’s — speaking specifically to the Agua Caliente project first, it was important to us to monetize that particular project because of the need to be able to realize the benefits fully in the monetization of the selldown around the IGC component of that project, which is a unique relatively other projects in the Tier 1 solar portfolio, which, as you know, are all cash grant projects. It is necessary if we’re going to get paid or provide to our partner the benefits of the IGCs to sell that down before COD. Beyond that point, we have the opportunity to pursue selldowns of the future beyond COD, and we don’t have a necessary limitation from a temporal perspective as far as sharing the benefits from a depreciation standpoint.

Jon Cohen: Okay, thanks very much. And I hope you guys get back up and running soon.

David Crane: Thank you, Jon.

Operator: Thank you for your question. Your next question comes from the line of Keith Stanley, Deutsche Bank. Please proceed.

Keith Stanley: Hi, good morning. I was hoping for some more color on the alternative energy segment. The release said solar has contributed $64 million of EBITDA year to date, but the segment as a whole has only contributed $35 million, and my understanding is that the alternative energy segment is wind and solar, but it seems like there’s also some drags in that segments, so can you just talk about some of those things that are offsetting?

Kirk Andrews: Sure. Our alternative energy segment, in addition to the businesses that you just mentioned, also include some of our new businesses, which are, as you know, in a startup mode, one of which is our eVgo business, which currently we are in the process of ramping up on the customer side. Obviously, we have a significant amount of capital spend which has been increased by virtue of the settlement that took place in California, and as we begin to add customers we expect the EBITDA contribution from that to offset the overhead.

But right now, what you’re seeing reflective, as you say, the difference between the positive EBITDA on the alternative energy along the solar side being offset by some of the early stage costs associated with the ramping up of some of those businesses like eVgo as well as there is a slight amount of overhead associated with the Petra Nova project as well.

Keith Stanley: Okay, thank you. One other follow-up if I can. Just looking at the retail contributions, the projections through 2014, can you talk a little bit more about the increase that you expect there from 2012 to 2014 just given the now rising gas and power prices from a 2012 base? Should we assume you can hold margins flattish on existing customers and then see some EBITDA growth from new customers? Or how should we think about your margin assumptions there for the existing customer base over the next few years?

Kirk Andrews: I’ll answer that in terms of the guidance, and I will let Elizabeth follow up with anything she would like to add. You know from my perspective, looking at the guidance and the growth therein, we certainly would look, given the commodity environment, that the preponderance of that growth would come from the customer side of the equation rather than the margin expansion side of the equation. And certainly, our focus is on growing the customer base in the Northeast where we see the real growth potential for us moving forward. As far as margins are concerned I don’t think we see certainly a lot of expansion on the margin side of things, but I’ll certainly let Elizabeth or Jim address any particulars around what they see moving forward on the margin side of the equation.

Elizabeth Killinger: Yes, thanks, Kirk. No, we don’t expect to see expansion in margins, but to Kirk’s point, we do expect to see customer growth. But that said, we — our long-term strategy is to balance margins and customer count, and so we will do the right thing to make sure we can deliver on those commitments as well as adding additional services to customers who currently have to increase the share of wallet we have for the customers.

David Crane: And Elizabeth, I think your comments about margins and all was sort of focused on the ERCOT market. Jim, do you want to say anything about the Northeast market and margins and customer count and the like?

Jim Steffes: I think we do see growth opportunities in the Northeast, clearly in line with the multibrand, multi-segment business that we have. Building on what Elizabeth said as well, we do have the opportunity to expand share of wallet. We intend to do that to go beyond commodity in the Northeast. We’re just really getting started there, and I think there is a huge opportunity in the Northeast overall.

David Crane: There is a huge opportunity in the Northeast, but, Keith, I would say that what you’re seeing in the projections expects growth in the Northeast, but while we’ll be seeking heroic growth in the Northeast, there’s no assumption of heroic growth in the numbers that we put out there for 2013 and ‘14. It’s more linear growth.

Keith Stanley: Thank you. If I could just follow up quickly. So for just looking at the Texas business and the existing customers, should — it sounds like you’re not embedding any margin expansion for sure, but

should we assume there’s some margin contraction given the rising price environment? Or should we assume more of a flattish outlook on that core customer base?

David Crane: I think you should assume, Keith, that we — our assumptions that margins stay relatively stable on the retail side in Texas. And so we appreciate the question, Keith. I’ve got to tell you, just one. The next question — I’ve been warned by Chad that we have to keep it to one follow-up question because — so unfortunately, Keith, we’ll have to go on. If you have any other questions, though, give us a call.

Keith Stanley: No, that’s it for me. Thank you very much.

Operator: Thank you for your questions. Your next question comes from Neil Mehta from Goldman Sachs. Please proceed.

Neil Mehta: Good morning.

David Crane: Good morning, how are you?

Neil Mehta: I am doing well. So when do you plan on providing more clarity around capital allocation guidance? Is it your 4Q call early next year? And maybe as a sneak preview, can you provide some sort of framework here for buybacks versus dividends versus other sources of capital allocation?

David Crane: Well, I think it’s fair to say that guidance on further capital allocation, the fourth quarter call February next year is a good bet. Depending on when the transaction closes and the circumstances, if we have newsworthy things to talk about, we’ve contemplated maybe having a call after the transaction close that might have more information about capital allocation, but you can’t put that in the bank, so I would say February next year.

The only thing I would tell you, speaking on behalf of the Company about capital allocation is, clearly, you can see from the words that we’ve used consistently for the last nine years, prudent balance sheet management. We’ve tended in terms of returning capital to the stakeholders, to return capital through buyback and debt reduction in equal amounts. Now we have the dividend. We feel that we owe the market a little bit more information about directionally where we’re going to take the dividend, so you certainly can count on that.

But between buybacks and paying down debt, I think I would repeat what I believe I said on the last quarter call is maybe relative to where we were over the last few years, we’ve got a little bit more of a lean towards the debt repayment side just because this combined Company, it’s got a lot of cash flow, but it’s got a lot of debt, as well. So we’d like to get the number down if we could.

Neil Mehta: Got it. And my follow-up question is around Texas here. In 2011, we had, I think it was 27 hours of scarcity pricing. In ‘12 we had almost none. Assuming normal demand levels, how do you think about what is the normal number of scarcity hours as you look at 2014?

David Crane: I’m going to ask Mauricio to answer the question, and then you’re not going to be allowed a follow-up question, so even if Mauricio doesn’t answer the question, you’ll just have to call in and try and get a better answer.

Neil Mehta: Fair enough.

Mauricio Gutierrez: Neil, good morning. Look, I think the amount of scarcity pricing hours that you can see at any given year is, as you know, a function of weather, and you alluded to 2011 spring weather. And we actually felt that in 2012, it was a normal weather. We were surprised to see that many few hours of scarcity pricing. So, I think — and then you have the supply side of the equation to deal with and specific unit outages that may contribute to that.

Instead of answering exactly what is the number of hours, what I can tell you is that if market is a good indication for what the potential impact is in terms of dollars per megawatt hour, we saw in 2013 move anywhere between $3 to $5 per megawatt hour on around-the-clock basis. I think that just gives you little bit of a proxy in terms of the number of scarcity hours, but also the impact of the new price caps that the commission passed — has approved.

Neil Mehta: Thank you.

Operator: Thank you for your question. Your next question comes from the line of Stephen Byrd, Morgan Stanley. Please proceed.

Stephen Byrd: Good morning. Best of luck on continued recovery after the storm.

David Crane: Same to you.

Stephen Byrd: Think you. I just had one question on solar growth outlook. In the past, you’ve talked about tax appetite, and this was discussed earlier a little bit, but as we think about potentially reloading and continuing to grow the solar business, does tax appetite have a — does that play into that decision? In other words, when we think about 2013, ‘14 and into ‘15, should we be thinking about continued ability to greatly expand the solar portfolio?

Kirk Andrews: Well, the first thing I would say is yes, we certainly have the ability to continue to expand the solar portfolio. I think, however, in contrast with the past, our expectations is that the magnitude of individual opportunities that would make up that continued growth on the solar portfolio would certainly be smaller, especially than what we’ve seen in the past for the Tier 1 portfolio, especially as regards — what I tend to refer to as the big three.

In terms of our tax position, I think that it’s safe to say that we will evaluate, and investments in solar will be made under consideration of either our ability to monetize the tax attributes or our ability to efficiently use them given our existing tax position. And so we will make decisions as to investment in solar on the basis of one or the other of those two moving forward, but we don’t see that as being a material constraint on expanding the Business moving forward.

Stephen Byrd: Great. Thank you.

David Crane: Stephen, actually I like to add a little bit more to what Kirk says because you’re — I think you’re touching upon what’s a very important area to this industry and to us as a Company, which is that we obviously are incredibly bullish on solar. We see enormous opportunity for our Company in solar. We also are — we completely recognize that solar is a business that, as you say, is driven by tax matters to some degrees, but it’s a very capital intensive industry with all the capital being required up front. And it requires a lot more capital than we have as a Company.

We’ve been, maybe from your perspective, taking our time to get other people’s money involved in our solar projects because we still think the market is mispricing on a risk-adjusted basis, or I should say on a lack of risk-adjusted basis, the returns that people should be willing to accept in the solar business. Having said that, we see enormous creativity going on in the banks and in the markets in terms of more people being attracted to the solar space, so we’re very confident that during the course of 2013 and beyond, you will see our Company continue on the solar path we’re on and getting other people’s lower-cost capital involved in our projects in a way that’s enhancing for everybody, including and most notably for us, our shareholders.

Stephen Byrd: That’s great color. Thank you very much.

Operator: Thank you for your question. Your next question comes from the line of Anthony Crowdell, Jefferies & Co. Please proceed.

Anthony Crowdell: Good morning. Hopefully just a quick question. I’m wondering if you could break up the wholesale guidance, say, 117 and 119 for 2012. What’s the contribution there from non-baseload assets?

Kirk Andrews: Anthony, were not going to break down the difference between baseload and non-baseload where that’s concerned. I think we are comfortable taking into consideration, but what we see in forward markets, especially with the changes that have most recently come about in ERCOT, and we’ve taken that into consideration in terms of the contribution on the peaking side of the equation, but beyond that, I don’t think we’re going to break that down into any further detail.

Anthony Crowdell: Great. Thank you.

Operator: Thank you for your question. Your next question comes from the line of Julien Dumoulin-Smith, UBS. Please proceed.

Julien Dumoulin-Smith: Hi. Good morning.

David Crane: Good morning, Julien.

Julien Dumoulin-Smith: First, just following on Jason’s departure from Reliant, I was wondering if you could discuss any updates to your strategy. Thus far, it doesn’t sound like anything, but just curious on that. Is there anything we should read from his departure?

David Crane: No. I don’t think there is. What I can do — obviously, no one wants to have their personal situation discussed on this type of public call, but I can assure you that had nothing to do with the type of issues that shareholders usually care about which, would be like the strategic direction of retail. And we see enormous opportunity in retail. We want to grow it from what we want to grow it. We want to grow it aggressively.

Today, we have with us Elizabeth and Jim, and I would tell you, Julien, that probably one of the most significant changes that’s occurred in this Company that no one on the outside would have seen but I can see from the inside is really when we bought Reliant a few years ago, we were basically a generation Company run by generation people and then we had a retail subsidiary, and the business model that we’re talking about in these investor presentations of a generation retail model with equal weight on both is very much the way our management is. And both Elizabeth and Jim are backed up by a very strong retail experienced management team, so I have the highest confidence on both of them and their teams, and there really is nothing that is worth you reading into about Jason’s departure.

Julien Dumoulin-Smith: Right. And maybe a quick follow-up here. Just discussing the year-on-year drivers looking at 3Q for the Reliant segment. Intuitively, I thought a mild summer would drive up higher results. Looks like the release at least alludes to a cost inflation due to customer acquisition perhaps premised on mid-Atlantic expansion. What kind of cost inflation are we talking about? Have we seen thus far going and predictably going forward in your ‘13 and ‘14 guidance if you can talk to that?

David Crane: So cost inflation specifically on the retail side and —

Julien Dumoulin-Smith: Yes, exactly.

David Crane: Well there’s the customer acquisition aspect, and there’s also — I think everyone recognizes that with greater volatility in Texas, there’s greater cost in terms of arranging your wholesale supply on the retail side. And that’s an area where we believe we have a competitive advantage relative to other retail electricity providers because of our own wholesale position. So — but Elizabeth, do you want to talk about cost of acquisition in Texas, or the cost question? And Jim, I don’t know if you have anything to add from the Northeast, you can —

Elizabeth Killinger: Yes, so we do have slight increases in cost, but to David’s point, they really are associated with the growth. Some — the bulk of that this year has been Northeast expansion, but we’ve also added some new products and expanded sales channels in ERCOT and in the Northeast, as well. And I would expect that going forward. Not significant increases. Jim, I don’t know if you’d add anything?

Jim Steffes: We can go into it further if you want to talk about it on a — call us directly.

Julien Dumoulin-Smith: All right. Great. Thank you for the time.

Jim Steffes: Okay.

Operator: Thank you for your question. Your next question comes from the line of Angie Storozynski form Macquarie. Please proceed.

Angie Storozynski: Thank you. First, about the Northeast and your retail business that you’ve added thousands of new customers and you don’t really have much of a generation assets to serve them. So, I understand that you’re using market purchases to meet your load obligations. And how should we think about it now that the Hurricane Sandy hit and then many of those customers are not connected to the grid anymore, and you have purchased the power to serve them? Shouldn’t we imply that actually this should have a negative earnings contribution?

David Crane: Wow, Angie. Mauricio, do you want to take a whack at that?

Mauricio Gutierrez: Yes, Angie, good morning. Keep in mind that we have 7000 megawatts of generation in the Northeast, and many of the products that you use to manage your retail load, like capacity and baseload generation or block generation, we can source it internally from our existing resources. So far, the portfolio, the size of the portfolio is small enough that 7000 megawatts is more than enough to manage that retail obligation.

But clearly, yes, as the retail grows, the need for having additional generation in the Northeast becomes critical, and that’s where the transaction with GenOn we see synergies similar to what we’ve been able to do in ERCOT. So that’s on the supply side. And the impact of Sandy in our Northeast customers, it is, I would say, I would characterize it as immaterial. And what I would say just from what we can tell on the wholesale side, load in general in the Northeast, depending on what state you were, was down anywhere between 20% to 30% for the last couple of days. So, while load was down overall, the impact to our retail franchises was very small and immaterial.

Angie Storozynski: Okay. And the last question. You mentioned the renegotiations of your Limestone coal contract. Could you give us any color of how beneficial to your earnings that is?

Mauricio Gutierrez: Angie, I wish I could, but you know, this is a — we historically haven’t provide specifics around coal transportations because of the confidentiality that we are bound with our counterparties and the competitive nature of them. What I can tell you is that it was in favorable terms, and we have seen the height of the rail contract rates when gas was $10 to $12 from MMBTU. I think they’re behind us. So not only they’re favorable, they’re also more flexible in terms of our operational flexibility of — being redundant — operational flexibility around the rail contract.

David Crane: And let me — we like to give credit where credit is due, and we’ve talked in the past on these calls about the constructive attitude that’s been taken towards these negotiations in terms of the commodity price environment we’re in, and we just want to say that we appreciate Burlington Northern in particular, in terms of the way that they’ve worked with us in a constructive fashion to keep these plants competitive. So — but that’s about as much detail as you’re going to get.

Angie Storozynski: Thank you.

Operator: Thank you for your question. Your next question comes from the line of Gregg Orrill from Barclays. Please proceed.

Gregg Orrill: Thanks. I was wondering if you could talk about the next layer of generation growth opportunities beyond what you talked about earlier in the backlog and understanding that you haven’t completed GenOn transaction yet, just from a what are the conventional buildup opportunities or areas you think you might need to add assets so we can get a sense for how that might play a role in capital allocation over the next few years?

David Crane: Well, Gregg, it’s a good question. I tell, you it’s hard to make a general comment. I guess the most general comment I would say is that there hasn’t been a large build of conventional generation in this country across our core markets, obviously, since the recession. And reserve margins, clearly, we focus here on Texas, and Mauricio talked about how they are tightening, but while we haven’t seen the same level of demand growth over the past few years in the Northeast United States in California, there’s more a question of retirement and how those retired assets get replaced.

And California has in particular the 316(b) issue that could cause the retirement a lot of coastal issues, and the Northeast just has a lot of old assets. And so it’s almost region by region and location by location. We are looking — we think we have a competitive advantage across our fleet in terms of Brownfield versus Greenfield in terms of the cost advantage and other advantages you get by redeveloping at your existing sites, but virtually anything that we are looking to do at this point because of the overall depressed nature of wholesale electricity prices is going to be a long-term PPA basis.

So you would expect normal project financing, and I don’t really see a situation in the next year or two where we get on one of these calls and say, you know what, we just decided to build an 800-megawatt combined cycle plant and we’re going to put the whole thing on balance sheet, so there goes $500 million or $600 million. So again, I think that was your first question, so if you have a follow-up question about a specific area, I’d be happy to talk about the New York energy highway or something like that, but in the interest of time, that’s about as much of an overview as I can give you.

Gregg Orrill: Just maybe to follow-up on your comments about 316(b), and I think you — that was a reduction to the environmental CapEx, and what are some of the solutions you’re finding there?

David Crane: To reduce the environmental — the current —

Gregg Orrill: Yes.

Mauricio Gutierrez: Just to be clear, the main reduction on the environmental CapEx was due to the change from a back house to an ESP operator, and I’m going to say that was 80%, 90% of the total reduction. Some of the changes on the 316(b) were relative to the screens that we have used in the Northeast and that we’ve been very successful on some of our units, so I would say that those are the much smaller dollars on the CapEx reduction.

Gregg Orrill: Great. Congratulations on the quarter.

David Crane: Thank you. Laura, we’ve gone over the hour, but let’s take two more questions, and we’ll try and be quick with the answers.

Operator: Okay. Thank you. Your next question then comes from the line of Brandon Blossman from Tudor. Please proceed.

Brandon Blossman: Good morning, gentlemen, Elizabeth.

David Crane: Brandon.

Brandon Blossman: Let’s see. I will be quick. So, ERCOT baseload, Mauricio, the PRB hedging strategy, no incremental hedges this quarter. A lot of price volatility. What the thought process on a go-forward basis around layering in PRB hedges? And then on the quarter, it looks like there’s an outage on the baseload coal plant in ERCOT. Was that a forced outage or something planned?

Mauricio Gutierrez: No. I mean on the — let me start with ERCOT. We have some (inaudible) that it’s I would say normal operations when you’re running a coal plant in the middle of the summer. While it was a normal summer from a weather standpoint, it still was warm by any other standards, so we had what I consider a solid availability performance by our baseload fleet, but it was not the stellar performance we had in 2011 when, if I recall, we had over 95% availability on our coal fleet. So, that’s — and what was your first question again?

Brandon Blossman: PRB strategy on a go-forward.

Mauricio Gutierrez: Yes. Look, we’ve said that we try to keep balance the hedges on coal and on natural gas. We put the coal hedges in 2013. We just closed that — basically, that dark spread with the additional hedges that we layer on the power when and natural gas has ran off the last few weeks. When you look at 2014 and beyond, we still see a (inaudible) in the PRB market, and given some of the dynamics and some of the price differential between spot prices and the forward price, particularly in 2014, we’re going to continue to evaluate where natural gas prices go, where power prices go, and make a determination in future. But we’re watching that constant.

Brandon Blossman: Thanks, guys.

David Crane: Last question, Laura?

Operator: Your last question comes from the line of Steve Fleishman from Bank of America Merrill Lynch. Please proceed.

Steve Fleishman: Hi, David. Can you hear me?

David Crane: I can, Steve.

Steve Fleishman: Great. Just at a very high level on the retail business, a lot of competitors have complained about lower margins or certainly not the level of — lower customer growth than they expect. How would you characterize your ability to differentiate versus others in the business?

David Crane: Well, how would — I would say look, maybe the lower margins, again, have to (inaudible), for them has to do with how expensive it is for them to arrange their wholesale supply. I don’t really know. We are comfortable with the margins that we are achieving. And I would say that the one thing that we’ve tried to distinguish ourselves from and what’s historically been very much a commoditized business, but I think with each day is becoming a less commoditized business, is that we offer differentiated products.

Reliant offers a full-service product that increasingly is offering, as Elizabeth said, it was very smart meter technologies and the like. If you went to the Reliant website as I did yesterday, you would see a picture of the nest thermostat which I have in my house, and Reliant, Elizabeth, has in our house, so they are offering a differentiated product there with more smart energy technologies in the house.

And Jim and Green Mountain, obviously, with the all green energy and Energy Plus with the frequent flyer miles and other affinity programs, we’re trying to offer something other than just undifferentiated grid power, and it seems to be working, and I completely believe that that’s the direction that retail is going in. And you’re not going to see us cut back on that. You’re going to see us doing more and more of that.

Steve Fleishman: Great. Thank you.

David Crane: Thank you, Steve. So thank you all for being patient, and sorry we took an hour and ten minutes, but we look forward to talking to you on the February call, if not before, hopefully at the time of the closing of the GenOn acquisition. So, thank you.

Operator: Thank you for joining today’s conference. This concludes the presentation. You may now disconnect. Have a 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 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, 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 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 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 does not undertake 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 attributable to NRG, GenOn or any person acting on their behalf are expressly qualified in their entirety by the cautionary statements above.

Additional Information about the Proposed Transaction and Where You Can Find It

In connection with the proposed merger between NRG and GenOn, NRG filed with the Securities and Exchange Commission (“SEC”) a registration statement on Form S-4 that includes a joint proxy statement of NRG and GenOn and that also constitutes a prospectus of NRG. The registration statement was declared effective by the SEC on October 5, 2012. NRG and GenOn first mailed the joint proxy statement/prospectus to their respective stockholders on or about October 10, 2012. NRG and GenOn may also file other documents with the SEC regarding the proposed transaction. INVESTORS AND SECURITY HOLDERS OF NRG AND GENON ARE URGED TO READ THE JOINT PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS THAT ARE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR

ENTIRETY BECAUSE THEY CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. Investors and stockholders may obtain free copies of the joint proxy statement/prospectus and other documents containing important information about NRG and GenOn through the website maintained by the SEC at www.sec.gov. In addition, NRG makes available free of charge at www.nrgenergy.com (in the “Investors” section), copies of materials it files 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 NRG and GenOn in connection with the proposed transaction.  Information about the directors and executive officers of NRG is set forth in its proxy statement for its 2012 annual meeting of stockholders, which was filed with the SEC on March 12, 2012.  Information about the directors and executive officers of GenOn is set forth in its proxy statement for its 2012 annual meeting of stockholders, which was filed with the SEC on March 30, 2012.  Other information regarding the participants in the proxy solicitation can be found in the above-referenced registration statement on Form S-4. These documents can be obtained free of charge from the sources indicated above.