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Executives

Dennis Barber - IR

Ed Muller - Chairman, President & CEO

Bill Holden - EVP & CFO

Analysts

Neil Mehta - Goldman Sachs

Mark Barnett - Morningstar

Rob Gaudette - CCO

Robert Howard - Prospector Partners

Julien Dumoulin-Smith - UBS

Brian Chin - Citigroup

Greg Orrill - Barclays

Jon Cohen - ISI Group

GenOn (GEN) Q2 2012 Earnings Call August 9, 2012 9:00 AM ET

Operator

Greetings and welcome to the GenOn Energy Second Quarter 2012 Earnings Call. (Operator Instructions). It is now my pleasure to introduce your host Dennis Barber, with GenOn Energy. Thank you Mr. Barber. You may begin.

Dennis Barber

Thank you Claudia and good morning everyone. Thank you for participating in GenOn’s Conference Call. Leading the call this morning are Ed Muller, our Chairman and CEO; and Bill Holden, our Chief Financial Officer. Following our prepared remarks, we will have a question-and-answer session. Also in the room and available to answer questions are Rob Gaudette, our Chief Commercial Officer and Gary Garcia, the Treasurer.

In light of our pending merger with NRG we are suspending adjusted EBITDA guidance for GenOn and do not expect to provide the guidance while the transaction is pending. The earnings release as well as the slide presentation we are using today is available on our website at www.GenOn.com in the investor relation section. A replay of this call will also be available on our website about two hours after completion of the call.

Turning to Slide 2, any projections or forward-looking statements made today are based on our current expectations and are subject to the Safe Harbors contained in this slide. Actual results may differ materially from our projections or forward-looking statements as a result of many factors, including those described in this slide and in our SEC filings.

The Safe Harbor in slide three describe how you may obtain copies of the SEC filed materials related to the proposed merger. Information regarding persons who may participants in the merger solicitation are also described in this slide. We urge you to read all these Safe Harbor and the reference materials.

Additionally, we are using non-GAAP measures to provide additional insight into the operating results and reconciliations of the non-GAAP measures to GAAP figures are also available on the website.

I will now turn the call over to Ed.

Ed Muller

Thanks Dennis and good morning everyone. I will start on slide five, and reiterate some of the highlights of our pending merger with NRG which we announced on July 22nd. Like the merger in 2010 of Mirant and RRI that created GenOn. The combination of GenOn and NRG will create substantial value for the stockholders of both companies. Key elements of that value creation will be $175 million of annual cost savings, $25 million of annual operation efficiency synergies and a $100 million of annual balance sheet efficiencies. On slide six, you can see the various approvals we will be obtaining and notices we had given. We continue to expect to close the merger by the first quarter of 2013.

Turning to slide 7, I will address several highlights for GenOn. Since it became clear that various environmental rules will lead us and others to deactivate plants, we have noted that a consequence of those deactivations will be a reduction of supply to meet demand. Reducing supply inexorably means higher prices and that is good news for supplier like GenOn.

One way to think about what is coming is to consider what happened during the recent heat waves in the east. Three of our plants which will be deactivated on October 1 ran hard to meet demand during those heat waves. The seven units of those plants collectively with 762 megawatts listed on slide seven. At times when those units were running most of our peaking units in the same areas were also running.

We think that as these seven units and units owned by others are deactivated as a result of environmental rules, events like the recent heat waves will result in high prices. Notwithstanding the heat wave and significant demand on our fleet. I am pleased to report that our plants ran well.

I am also pleased to report that the construction of Marsh Landing in Northern California continues to remain on schedule to be completed by mid-2013 and the project remains on budget. During more than a 1.5 of construction and with about 500 construction workers currently on-site, we have yet to have a single OSHA-reportable safety incident.

Turning to slide eight, I will address the recent capacity auction in PJM. Overall the $500 million of capacity revenue that we locked in fell within the range of our expectations, we think however that PJMs must offer price rule known as MOPR did function properly. New Jersey offered subsidized contracts for new plants which were permitted to bid prices well below their contractual prices. We don’t think it's appropriate for those new plants to have it in both ways to get rich capacity prices assured by the rate payers in New Jersey and then bid in the RPM auction at substantially lower prices.

We think this is nothing less than manipulation of the market, as a result of this manipulation we are pursuing vigorously various bright line tests for MOPR. We PJM recognizes that the problems with MOPR must be addressed.

Turning to slide nine, we show our hedges as of July 9, both for the fleet and for our baseload coal. For our baseload coal we are fully hedged for this year, heavily hedged for next year and less hedged but nevertheless somewhat hedged from 2014 through 2016. And with that I will turn things to Bill Holden to walk you through the numbers. Bill?

Bill Holden

Thanks Ed and good morning everyone. Starting on slide 11, adjusted EBITDA for the quarter was $72 million a decrease of 32 million from Q2 last year. Adjusted EBITDA was down principally because of lower adjusted energy gross margin and lower contracted and capacity revenue partially offset by higher realized value of hedges and lower adjusted operating and other expenses.

The $89 million reduction in energy gross margin for the quarter reflects lower energy gross margin from generation principally in PJM and a lower contribution from energy marketing. The $32 million reduction in contracted and capacity revenue for the quarter resulted from lower capacity prices in PJM.

The $42 million lower adjusted operating and other expenses for the quarter resulted primarily from lower project outage and maintenance expenses. For the year-to-date adjusted EBITDA was down a 136 million compared to the same period last year.

The factors affecting the year-to-date results for the same as those for the quarter. The added note that adjusted operating and other expenses were also lower because of cost synergy resulting in Mirant and RRI.

Turning to slide 12, the slide summarizes debt and liquidity for GenOn at June 30, 2012. Total debt outstanding was a little over $4.3 billion. The increase of 99 million since March 31 principally resulted from additional borrowings on the Marsh Landing credit facility.

Total cash and cash equivalent is just under 1.7 billion of which approximately 1.5 billion was held at GenOn or if subsidiaries other than GenOn Mid-Atlantic REMA. Including availability under the revolving credit facility, total available liquidity was just under $2.2 billion and funds on the deposit at June 30, were 396 million.

Turning to slide 13, this slide presents a breakdown of our projected capital expenditures for 2012 and 2013. Now that amounts at the table reflect expenditures for the full year 2012 and include expenditures made for the year-to-date. The 1.8 million shown for compliance with the Maryland Healthy Air Act reflects the settlement with Stone & Webster.

Other environmentally expenditure were estimated at $45 million this year and a $119 million for 2013. These expenditures principally relate to environmental projects at Conemaugh, Kendall, Sayreville and Werner.

Construction expenditures include the estimated amounts for the construction of our Marsh Landing generating facility, which will commence operations in mid-2013. Other construction expenditures are primarily related to the completion of the ash beneficiation facility which is now operating at our Morgan Town plant.

And finally we expect normalized maintenance capital expenditures to drop from approximately 115 million per year to approximately 110 million per year after the plant deactivations plan for 2012 through 2015.

And with that I will turn the call back over to Ed to wrap up and open the call to your questions. Ed?

Ed Muller

Thanks Bill, I will turn to slide 14 to sum-up, the big news for GenOn is the pending merger with NRG. The merger will deliver substantial and immediate value to the stockholders of both companies that value will come from 300 million in annual synergies and balance sheet efficiencies from the creation of the largest competitive power company in the nature with approximately 47,000 megawatts of capacity and from geographical diversity.

We are also pleased that our generating fleet has been performing well especially during the recent heat waves in the east and we are very pleased the Marsh Landing remains on-schedule and on budget and now Claudia we will be glad to questions.

Question-and-Answer Session

Operator

(Operator Instructions). Our first question is coming from the line of Neil Mehta with Goldman Sachs. Please state your question.

Neil Mehta - Goldman Sachs

Bill this might be a question for you, can you walk us through the counting of the $107 million settlement with Stone & Webster, how did this flow through your cash flow and balance sheet payment from the quarter.

Bill Holden

I can tell you the 107 million was paid from the funds on deposit that we had previously had noted on the balance sheet. So if you look at last quarter's debt and liquidity slide we had a 166 million set aside that related to the (inaudible) that’s done in Webster has been granted.

When the settlement occurred we paid the funds, those liens were removed and so the difference between a 107 million and a 166 million returned to cash and cash equivalents. I think in terms of the way it runs to the cash flow statement, you would see that an operating cash is changed and funds on deposit or changes in other payables and receivables.

Neil Mehta - Goldman Sachs

And do you have any weighted average hedged price data for either the coal side or the power side here, we used to get that debt and I didn’t see that in the slide there.

Bill Holden

And I think since we removed it since we are not providing guidance.

Neil Mehta - Goldman Sachs

Okay and my final question is how should we size the impact of Casper if it remerges here, and you are pleased to say it was a $85 million annual head wind, conceptually what would be the pluses and minuses to that number today.

Bill Holden

We haven’t run that number I think given the prices are generally lower and volumes, generation volumes are lower, the effect would be lower than the 85 million but I don’t have a calculation that we have done that I can give you a better number than that.

Operator

Our next question is coming from the line of Mark Barnett with Morningstar. Please state your question.

Mark Barnett - Morningstar

Couple of quick questions, on the MOPR, when you talk about addressing some of the issues there, what kind of options do you realistically have?

Bill Holden

Well the options would include as I said let me back up, as I said PJM we think understands the need to address how the MOPR functioned and how it didn’t function in the last auction and so the I think the most expeditious would be for PJM in assessing improvements and bright line test to make a filing with FIRC which is in a nature of the tariff adjustment and that would be the preferred route and the most expeditious route.

Mark Barnett - Morningstar

Okay and I guess just looking at your fuel, your hedging slide, you took out some fuel hedges in 2013, can you just talk about what’s going on there a little bit.

Rob Gaudette

We haven’t off, hedging or I am sorry, we haven’t changed the amount of the fuel that we have contracted, as our out in ’13 or beyond, what you could attribute that to is fluctuations and expected generation over the time period and it could mean we saw more burn (ph) in a year prior to the one you are asking questions about, so in this case ’12 or it could mean that we are expecting more or less burn in the year that you see the moment. So over the time period we haven’t changed our hedge structure, what we have seen is some fluctuations and expected generation, does that make sense?

Mark Barnett - Morningstar

That’s helpful and I guess just one last question if you don’t mind, just wondering how the trading liquidity is I mean around you key hubs, is there been much movement and basis for volumes over the first two quarters of the year or are we pretty flat with 2011?

Rob Gaudette

Your question is about the volumes of trading basis?

Mark Barnett - Morningstar

Sure and how that’s impacted.

Rob Gaudette

Year-over-year the volumes are probably flat, the amount of liquidity out there, there is some, it's been limited as we have talked about in the past. The ability to go out on basis beyond a year gets limited but we are active in those markets, the primary basis for us is the Pepco to West Hub and then AD Hub to West Hub and those fluctuate with time but I wouldn’t say that there is material change between what we saw last year and what we see this year, did that help?

Operator

Our next question is coming from the line of Robert Howard with Prospector Partners. Please state your question.

Robert Howard - Prospector Partners

Just wanted to some thoughts on the surface the upcoming consolation plant sales were comparable to some of the GenOn assets and we obviously don’t where that’s going to come out but you know I was wondering how should NRG and GenOn shareholders view the results when voting to approve the merger whether or not, is that auction makes it appear that either NRG take too much or maybe it will make it appear NRG didn’t pay enough and just kind of, how should we be looking at that as we are making our decision.

Ed Muller

Well I think Rob this the underlying driver for the value that is created by the combination of GenOn with NRG is not what those plants maybe, we are not talking about a cash transaction here, it is a stock for stock transaction and all the shareholders of both companies will get to benefit, there is a premium built in for the shareholders of GenOn to reflect how the transaction was negotiated and the sharing of the synergies. So whether that goes to the constellation assets, go at a high price or low price or anywhere along the spectrum, it all moves through among the shareholders the same way.

Robert Howard - Prospector Partners

And then just jumping over to the plant deactivations. Have you guys stated a cost or how much that would cost to closing down?

Ed Muller

I don't think we've given an estimate for deactivation cost.

Robert Howard - Prospector Partners

Okay. How much would that help on just operating expense? Is there sort of an operating expense? I know you guys just talked about the maintenance CapEx reduction because of that closing. Is there any other benefits?

Ed Muller

I think we said basically that and Gary (inaudible) showing the word around here but when all the plant deactivations have been announced, are done, that the O&M cost will be in the range of $80 million below 2013.

Operator

Our next question is coming from the line of Julien Dumoulin-Smith with UBS. Please state your question.

Julien Dumoulin-Smith - UBS

So first question, just curious on the coal markets and transportation of rail contracts. Like all of that is moving favorably, curious to see what you guys are seeing on your side, any success in signing any deals in the quarter that you might want to point to or anything like that?

Rob Gaudette

Julien you're right, the coal market has definitely moved into the direction of coal burst. Prices are obviously considerably down from where they were a year ago or even a quarter ago. We look at our coal supply to regular RFPs. We contract from short term to up to three or four years and we're always working with our suppliers. What we've seen over the last quarter is suppliers dealing with the same struggles that you'd expect in a market where not much coal got burst. So suppliers are looking to restructure contracts with us and others and I think that ultimately this is going to benefit the company in a way that we figured out how to use the coal that we've already contracted to fill in the holes we have into the future as well as still gas we get the opportunity to do that. But we regularly are in the market. We're always looking at that. We're always taking care of that. On the transportation side, we have long term contracts with our rail suppliers and we are in negotiations now, too early for me to give you anything but to re-contract our CSX contract for the mid-Atlantic which we've talked about in the past. And so we're in talks with them. Their volumes are down. They are regulated not oftenly so (ph) though. So I'll point that out. So we think that our contracts currently are at market rates and we would expect that we'll be able to contract around those same levels. Helpful?

Julien Dumoulin-Smith - UBS

Then to follow-up there, because with respect to plants that are deactivating and have how it ties in to your renegotiation going on. How you're dealing with the obligation that you had against those assets originally? I mean is there any way to call a force majority well at all? Given the context of EPA regulations, anything like that?

Ed Muller

In our contracting process and as we look at what our obligations are around coal. We saw this coming and the way we look at our assets shows projected generation and so we procure along those lines. When we expect that the units are being deactivated, typically they couldn’t support backing controls, so thus they are being deactivated. We weren't expecting to see a lot of run out of them to begin with. So my obligations aren't that great. But we'll honor our obligations and we'll move the coal around as we see the flexibility to do that. And we've got an active good, coal trading route that can help us move any excess tonnes we may have. But I don't have a giant contract that I've got to deal with, that I'm really concerned about. Does that help?

Julien Dumoulin-Smith - UBS

And that CSX rail contract you just alluded to, when was that up for to just fire?

Ed Muller

In to the year.

Julien Dumoulin-Smith - UBS

And just a final question on the hedge unit in New Jersey. Could you just clarify if you can which units you intend to retire there? I don't know it can be exact.

Dennis Barber

It could be which of the plants in New Jersey we have expected to retire.

Julien Dumoulin-Smith - UBS

Dennis Barber

It's Glen Gardner, its 160 megawatts.

Operator

Your next question is coming from the line of Brian Chin with Citigroup. Please state your question.

Brian Chin - Citigroup

I wanted to ask two questions related to HR 427 free the representative (inaudible). I just wanted to ask what's the latest update on that, seeing like that was submitted other ways couple of months ago and then we haven't really heard a lot about that so hoping for an update from you.

Ed Muller

Sure. Let me make sure we get everybody who's listening on the same page. This rises from a lack of clarity between as to which law applies environmental law or the power of the department of energy in emergency situations to order plants to run. And plants within GenOn have twice faced this. Once, the now retired plant called Potrero in San Francisco during the California energy crises was ordered to run. And another time was when the Potomac River station was ordered to run because of concerns with transmission in to the District of Columbia. And in both instances the department of energy within its authority ordered us to run and in both instances complying with the order of the department of energy had us trip over various environmental restrictions on the plant leading to fines and so on. And that has struck us and others in the industry as a conflict that shouldn’t be on the back of the generation owner but rather ought to be resolved by the government if the department of energy says, thou shalt run, because of an emergency to keep the lights on, it shouldn’t fall to us to have to deal with violations of our environmental permits because we are not doing this voluntarily. The government has, over the years, not resolved this and the bill put in by Congressman Olsen to which you referred would address this. And the bill passed the house recently unanimously. And it is now somewhere in the process at the senate.

Brian Chin - Citigroup

Excellent and then have you had any conversations with David over at NRG about whether you both share the same point of view on that legislation?

Ed Muller

I don't think so. I don't recall that.

Operator

Our next question is coming from the line of Greg Orrill with Barclays. Please state your question.

Greg Orrill - Barclays

I think in the quarterly analysis energy marketing versus last year was mentioned as a headwind. Could you provide a little bit more detail on that?

Ed Muller

Sure, if you look at the contribution of energy marketing for the quarter, across both operators, proprietary trading, fuel management and gas transportation storage, the contribution was $1 million which was down from the prior quarter by 21 million.

Greg Orrill - Barclays

And then I don't know if it's possible to provide any more context around the conditions that led to the running of (inaudible) Niles and the Potomac River units, was it new peaks or what were the conditions around those plants running?

Rob Gaudette

At the end of the day it was just a very strong heat wave. We've had a couple of them in the east, that I am sure you've seen, it probably lives through. At the end of the day, this grid was built with units in key places, Potomac River is essential to keeping up the DC grid. We saw runs that you wouldn’t expect out of units that are going to be deactivated in three or four months but the way the grid works is it accounts on transmission and key component units. What we saw this summer and I would expect with another heat wave we'll see again, is PJM needed these units as well as peaking capacity like Ed said, to meet the demand in the area will call us breaking any particular peak loads but where the market is and where things are, you need generation to support lines, you need generation on to meet ramp rates. So even if you weren't at a peak load, some units and some particular areas of the grid are absolutely necessary. As Ed's talked about, as deactivations across the PJM footprint continue, you'll expect that the grid itself will be leaning more on peaking capacity and that typically is higher heat rate, higher fuel costs, higher overall costs type generation. So you can draw your own conclusions from that. But that's kind of where we're at.

Operator

Our next question is coming from the line of Jon Cohen with ISI Group. Please state your question.

Jon Cohen - ISI Group

Actually just want to follow-up on that point. So, if we saw the same kind of load pattering next summer, as we see this summer, do you think that the current forward heat rates adequately reflect the risk that these units are not going to be around and are dispatching the next guys up the stack?

Rob Gaudette

Yes, I've never been a proponent of saying that the market's wrong. I try very hard to not do that. The way I would think about it is, before markets have to price in the exposures and the risks inherent in what's going on. I think that our forward markets typically price in what people are experiencing today. They very rarely make this step change necessary when things go along. And if we had the exact same weather, with the exact same fuel prices, everything is the same except for you take some of these units that are deactivated out. Then I would expect that in order to fill the gap, PJM is going to have to turn on a higher heat rate, a more expensive unit than these three coal plants that we're talking about. A coal plant's cost are in the $40 range. There are gas turbines out there that are considerably higher than that. I think if you look at the forward heat rates and the forward fuel curves, you'll see that we may not have gotten there yet as far pricing goes.

Jon Cohen - ISI Group

And then how are you dealing with this dynamic of reasonable peak pricing when you have some weather and load but still very low off-peak pricing because of the low gas price. Does the margin that you're in the peak, is that sufficient to sort of offset the losses that you're probably taking by running those units in the off-peak. You've been given the fact that they can cycle down to 50% or in some cases lower.

Rob Gaudette

Yes, so when we think about the economics around, the point to your question around coal units. Right, our gas units we can flip on and off and we don't have to suffer through in a lot of cases, lower gas prices. There's two ways to think about coal units when they are running. If they are running for reliability reasons like we saw back in Q1 a lot, the market itself, the way the mechanism works we get picked up and we don't lose money. When I'm looking at economics, when we're on a fully competitive basis, running, I'm looking at the economics of a coal unit over a seven day period typically. And so I'm incorporating things like the off-peak costs, startup costs and then the on-peak values. So I don't chose to run coal units at a loss net when you take on and off peak into account. So we're only running units when everything is positive. I only do it for economic reasons. I'm getting picked up in a place where that's not economic to me. PJM is going to be telling us to do that for reliability and we get in net whole. So it makes sense?

Jon Cohen - ISI Group

It makes sense, but could be still economic, the margin could be marginal, for lack of a better word. So as gas prices firm up on the front, would you expect to lose less in the off peaks, thereby improving sort of overall margins in the summer of 2013-2014.

Rob Gaudette

Yes, I think your point is that we got CCGTVs on the margin in the off peaks and so obviously if you drive up the fuel costs, the off peak prices will rise and that will reduce any marginal loss when they have on a coal unit in the off peaks.

Jon Cohen - ISI Group

That's correct.

Rob Gaudette

So I would confirm what you're saying.

Operator

There are no further questions at this time. I would like to turn the call back over to Dennis Barber for closing remarks.

Dennis Barber

Thank you Claudia and thank you to everyone for participating in our call this morning. A replay of this webcast will be available in about two hours. Have a great day.

Operator

This does conclude today's teleconference. You may disconnect your lines at this time and we thank you for your participation.

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