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Executives

Dennis Barber -Investor Relations

Edward Muller - Chairman and Chief Executive Officer

J. William Holden III - EVP and Chief Financial Officer

Mark Jacobs - President and COO

Robert Gaudette - Senior Vice President and Chief Commercial Officer

Gary Garcia - Treasurer

Analysts

Ameet Thakkar - Bank of America Merrill Lynch

Gregg Orrill - Barclays Capital

Brandon Blossman - Tudor, Pickering, Holt & Co.

Brian Chin - Citigroup

Brian Russo - Ladenburg Thalmann & Company

Ted Durbin - Goldman Sachs

Mark Barnett - Morningstar

Ali Agha - Suntrust Robinson Humphrey

Robert Howard - Prospector Partners

Julien Dumoulin-Smith - UBS

GenOn Energy, Inc. (GEN) Q2 2011 Earnings Call August 8, 2011 9:00 AM ET

Operator

Welcome to the GenOn Energy Second Quarter 2011 Earnings Conference Call. My name is Sandra, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded.

I will now turn the call over to Mr. Dennis Barber. Mr. Barber, please go ahead.

Dennis Barber

Thank you, Sandra, 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 Mark Jacobs, our President and Chief Operating Officer, Rob Gaudette, our Chief Commercial Officer; and Gary Garcia, the Treasurer.

The earnings release as well as the slide presentation we're using today is available on our website at www.genon.com in the Investor Relations section. A replay of this call will also be available on the website approximately two hours after the call has completed.

Turning to slide two, I would remind you that all projections or forward-looking statements we make today are based on our current expectations and involve risks, assumptions and uncertainties. These statements 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. We’re also using non-GAAP measures to provide additional insight into the operating results and guidance. Reconciliations of the non-GAAP measures to GAAP figures are available on the website. I'll now turn the call over to Ed.

Edward Muller

Thanks, Dennis, and good morning everyone. I’ll start on slide five, make a few points before turning to some of the more detailed information. First, on slide four, if I said five I am at four, first I am very pleased I am very pleased to report that our integration since the merger on December 3, continues to proceed well. And we continue to expect or save $155 million per year in costs starting on January 1, 2012.

Second, this past May, we participated in the annual RPM auction in PJM, in which capacity is sold three years in advance. For the period of mid-2014 to mid-2015, we locked in over $0.5 billion of RPM revenue. Capacity has been and remains a very significant portion of our revenues. Third, I am pleased to report that the construction of Marsh Landing in northern California remains on schedule to be completed by mid-2013. And it remains on budget.

And fourth, last year, Montgomery County, Maryland imposed a carbon levy on a single entity in the county and that entity was our Dickerson Station. We challenged the levy in the courts. After a recent very favorable decision for us by the United States court of appeals, Montgomery County repealed the carbon levy and returned the approximately $8 million it had previously collected.

Turning to slide five, we are today updating our guidance for both 2011 and 2012 based on market curves on July 12. For both years we are increasing our guidance. For 2011, we are increasing our guidance by $63 million to $621 million. The increase results from higher energy margins and higher results from our energy marketing offset somewhat by lower value of hedges. Bill Holden will give more of the details, shortly.

For 2012, we are increasing our guidance by $75 million to $608 million. The increase as in 2011, results from higher energy margins. It results from lower operating and other expenses. Both are somewhat offset by lower realized value of hedges and lower results from energy marketing. Our guidance for 2012 does not take into account costs of allowances, the value of allowances or changes in dispatch resulting from the Cross-State Air Pollution Rule or CSAPR, which is being published in the federal register today. And again, Bill Holden, will provide more of the details shortly.

On slide six, we show our progress on the $155 million of cost savings. When we closed the merger this past December, we expected savings of $150 million a year. This past May we increased the savings to $155 million per year. As you can see, as of June 30, we had 73 % of it done. We remain on track to have it all in place by January 1.

On slide seven, we show our hedges, both for the fleet and for our baseload coal. Our strategy remains to hedge our output, to reduce volatility in our realized gross margin. Our figures for expected generation do not include the impacts of CSAPR.

Let's turn to slide eight and talk about CSAPR some. As I have said, both our guidance for 2012 and our expected generation do not include any impact from CSAPR, which the market is still trying to process. Assuming the actual price curves on July 12 and the EPA’s estimate of the cost of allowances, we think the impact on GenOn for 2012 would be modest. CSAPR is of course only one of a suite of regulatory actions coming out of the EPA. Other then CSAPR, we don’t know yet what the final rules will say nor what the applicable timelines for compliance will be.

On slide nine, we have laid out how we will address the rules. First, we will consider the impact of all the rules together, not just a subset of them. Second, we will not commit capital until we have clarity on the rules. And third, we will invest only when we are confident that the returns on our investment will exceed our cost of capital. Using those criteria and our own forecasts for increases in prices. We think it likely, we will invest between $565 million and $700 million for environment controls over the next eight years, which we expect to fund from existing sources of liquidity.

These investments would be for SCRs and other environmental controls to meet air and water quality requirements. If market prices increase even more then we currently expect, additional investments could meet our criteria. We expect that we will retire some of our units as a result of the suite of EPA regulations. We also expect that any reduction in GenOn’s earnings from retirements of its units resulting from the environmental regulations, if and when implemented, will be more than offset by higher earnings from increases in prices resulting from industry retirements.

With that I will turn things over to Bill Holden to walk you through the numbers. Bill?

J. William Holden III

Thanks, Ed, and good morning. I will start on slide 11, adjusted EBITDA for the quarter was $102 million, a decrease of $58 million from pro forma results for Q2 of 2010. For the year to date adjusted EBITDA was $305 million, a decrease of $44 million from pro forma results for the same period last year. Pro forma results for the 2010 period, adjusted reported Mirant results for the 2010 period, to show the combine result from Mirant and RI adjusted for margin related items.

Adjusted EBITDA for the quarter and year to date was lower principally because of lower contracted and capacity revenue, lower adjusted energy gross margin and lower realized value hedges partially offset by lower adjusted operating and other expenses. The $44 million reduction in contract and capacity revenue for the quarter, principally resulted from lower capacity revenues in Eastern PJM and California.

The $32 million reduction in energy gross margin for the quarter reflects lower energy gross margin from generation, principally from Eastern PJM. A $15 million decrease in realized value of hedges for the quarter was principally related to a lower contribution from hedge positions in Eastern PJM and the other operations segment. The $33 million reduction in adjusting operating and other expenses for the quarter reflects merger related cost savings and a reduction in planned outages.

Slide 12, summarizes debt and liquidity for GenOn at June 30. Total debt outstanding was approximately $4.1 billion. Total cash and cash equivalents was about $1.6 billion of which about $1.5 billion was held at GenOn or its subsidiaries other than GenOn Mid-Atlantic or REMA. Including availability under the revolving credit facility, total available liquidity was under $2.1 billion. Also note that funds on deposit at June 30, were just over $700 million. And I note that the cash collateral for energy trading and marketing activities will be returned to GenOn upon settlement of the underlying transactions.

The cash collateral to support the Marsh Landing project will be returned to GenOn when the project achieves commercial operations and if the GenOn Mid-Atlantic restricted cash has been removed from cash and cash equivalents and satisfied to fund payments for the scrubbers at our Maryland plants.

Slide 13, provides details around our updated guidance for 2011 and 2012. First, as noted on the slide, our guidance is based on forward commodity prices as of July 12, 2011. Also note that our guidance does not incorporate any cost of allowances, value of allocations of allowances or changes in generation dispatch resulting from the recently published Cross-State Air Pollution rule.

As Ed described we are raising our adjusted EBITDA guidance to $621 million for 2011, and $608 million for 2012. Our guidance is up principally because of higher forecast of energy gross margins. I will provide additional detail on adjusted gross margin for 2011 and 2012 and a comparison to prior guidance on the next few slides.

Starting with adjusted EBITDA, and deducting cash interest paid and income taxes paid and adjusting for working capital and other changes in cash, arrives at adjusted net cash provided by operating activities of $148 million expected for 2011 and $207 million projected for 2012. Deducting projected capital expenditures for each year, arrives at adjusted free cash flow deficits of $449 million projected for this year and $257 million projected for 2012.

Adjusting for the remaining Maryland Healthy Air Act expenditures, net of funds on deposit, Marsh Landing working capital and capital expenditures and payment of merger related costs results in an adjusted free cash flow deficit, excluding these items, of $106 million project for 2011. And adjusted free cash flow excluding these items of $10 million projected for next year.

Finally hedged gross margin which includes energy gross margin that is hedged plus contracted and capacity revenues for which prices have been set, is approximately $1.65 billion in 2011 or about 91 % of projected 2011 adjusted gross margin. And just over $1.2 billion in 2012 or about 71 % of projected 2012 adjusted gross margin. Deducting the full year forecast for adjusting operating and other expenses, arrives at hedged adjusted EBITDA of $453 million for 2011 and hedged adjusted EBITDA of $94 million for next year.

Turing to slide 14, this slide presents the components of adjusted gross margin that are contained in our guidance for 2011 and 2012. Contracted and capacity, the lower bar, represents gross margin received from capacity sold in ISO and RTO administered capacity markets through PPAs and tolling agreements and from ancillary services. Contracted and capacity comprises roughly half of our adjusted gross margin in 2011 and 2012. Prices have already been set for over 95% of these amounts in each of 2011 and ‘12. The decrease of $66 million from 2011 to 2012 principally results from lower RPM auction prices, partially offset by higher contracted prices in California.

Energy shown as the middle bar represents gross margin from the generation of electricity at market prices, fuel sales and purchases at market prices, fuel handling, steam sales our proprietary trading and fuel management activities and natural gas transport and storage activates. The increase of $120 million from 2011 to 2012 is principally driven by higher energy prices and generation.

And finally realized value of hedges, the top bar, reflects the actual margin upon settlement of our power and fuel hedging contracts and the difference between market prices and contract costs for fuel that we have purchased under long-term agreements. Power hedging contracts include sales of both power and natural gas used to hedge power prices as well as hedges to capture the incremental value related to the geographic location of our physical assets. The decrease of $117 million is driven principally by a lower hedged percentage of our expected generation in 2012 as compared to 2011.

Turning to slide 15. This slide reconciles our previous adjusted EBITDA guidance to our updated guidance. Our updated 2011 guidance is $63 million higher than our previous adjusted EBITDA guidance. This increase is comprised of the following items. First, a $79 million increase related to market price and generation changes principally resulting from higher power prices in PJM, and second, $16 million increase in energy marketing. These increases are partially offset by lower realized value of hedges and increase in operating and other expenses, and slightly lower projected contracting capacity revenue.

The increase in operating and other expenses reflects an increase in the accrual for payments under the company's incentive compensation plans to reflect the current outlook for 2011, partially offset by lower plant operating expenses, which includes the removal of the Montgomery County carbon levy. Our updated 2012 adjusted EBITDA guidance is $75 million higher than our previous guidance for 2012. This increase is comprised of the following.

First, a $79 million increase in energy gross margin resulting from higher power prices and generation. Second, an $11 million decrease in operating and other expenses, principally resulting from lower plant cost, primarily related to the removal of the Montgomery County levy. These items were partially offset by a $7 million reduction in the contribution from energy marketing, a $6 million decrease from realized value of hedges and a $2 million decrease from forecasted contracted and capacity revenue.

Turning to slide 16, this slide shows sensitivities for our 2011 and 2012 guidance. The guidance for both years is based on commodity prices at July 12, the NYMEX natural gas price and Market Implied Heat Rate for 2011, for the period from August through December 2011. A $1 per million Btu move in the price of natural gas for the balance of 2011 is estimated to result in a $37 million change in adjusted EBITDA for 2011. Although $1 per million Btu move in the price of natural gas next year is estimated to result in a $205 million change in adjusted EBITDA.

The natural gas sensitivities assume Market Implied Heat Rates and generation volumes are unchanged. A change of 500 Btu per kilowatt-hour in Market Implied Heat Rates for the balance of 2011 is estimated to result in a $16 million change in adjusted EBITDA, while a similar move in Market Implied Heat Rates for 2012 is estimated to result in a $91 million change in adjusted EBITDA for 2012. The heat rate sensitivities assume fuel prices and generation volumes remain constant. The sensitivities are greater in 2012 then 2011 because we are less hedged in 2012.

Turning to slide 17. This slide presents a breakdown of our projected capital expenditures for 2011 and 2012. Our maintenance capital expenditures are expected to be $112 million in 2011 and $91 million in 2012. We expect our normalized maintenance CapEx as approximately $115 million per year. The total projected cost for compliance with the Maryland Healthy Air Act remains at $1.674 billion with $155 million expected to be paid this year. As I noted earlier, $143 million of this amount is held as restricted cash at GenOn Mid-Atlantic and has been moved from cash and cash equivalents to funds on deposit on the balance sheet.

Other environmental expenditures are estimated at $30 million this year and $54 million next year. 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 for the ash beneficiation project at our Morgantown plant.

And with that, I'll turn the call back over to Ed, who'll wrap up and open the call for your questions. Ed?

Edward Muller

Thanks, Bill. I'll turn to slide 18 to sum up. First, we've increased guidance for both 2011 and 2012. Second, we've locked in over $0.5 billion of RPM capacity revenue for mid-2014 to mid-2015. Third, we expect the EPAs suite of regulations to result in higher market prices. With those higher prices, we think it likely we will invest between $565 million and $700 million in environmental controls over the next eight years which we expect to fund from existing sources of liquidity.

If market prices rise even more than we currently expect, more investments in environmental controls could meet our investment criteria. We expect that we will retire some of our units as a result of the suite of the EPA regulations. We also expect that any reduction in GenOn's earnings from retirement of its units resulting from environmental regulations, if and when implemented, will be more than offset by higher earnings from increases in prices resulting from industry retirements. And fourth, Marsh Landing remains on schedule and on budget.

Now, Sandra, we're ready for questions.

Question-and-Answer Session

Operator

(Operator Instructions) The first question is from Ameet Thakkar from Bank of America. Please go ahead.

Ameet Thakkar - Bank of America Merrill Lynch

Good morning, Ed, good morning, Bill.

Edward Muller

Good morning, Ameet.

Ameet Thakkar - Bank of America Merrill Lynch

Thanks for the additional commentary on the environmental and the additional disclosures. It's very helpful. Hey, Ed, you talked about retirements and potentially, I guess, some less dispatch of unscrubbed units as part of these proposed and I guess the final CSAPR rules, and then higher energy prices. I guess, is there another potential benefit to scrubbed units that they might actually run more frequently, so that’s kind of a, like a double leverage effect where you get the higher energy prices and more runtimes on your scrub units? Is that a fair way of thinking about it?

Edward Muller

As a general matter, sure. A lot of it's going to depend on what demand is. If demand, for example, in some regions is what it has been here in Texas for the last week or so, that's for sure going to happen. But as a general matter, if you think about it, the suite of regulations coming down is going to reduce supply. So, what remains is going to tend to have to run more and in terms of pricing and on the stack in coal stations with coal units, with all environmental controls are going to tend to run more.

Ameet Thakkar - Bank of America Merrill Lynch

Okay, that makes sense. And then on the $565 million to $700 million of environmental CapEx that you have laid out over the next years. So we should think of, I guess, the majority of that as really being likely allocated to installations of SCR's where maybe you have SNCR's or no, or I guess low burn, kind of NOx fired equipment? Is that a fair description of where the majority of that CapEx should lie?

Edward Muller

That is very fair. You can assume that the bulk of the $565 million to $700 million would be for SCRs and we would be putting SCRs either where we don't have any major NOx controls in place now or where we do and we'd be enhancing them.

Ameet Thakkar - Bank of America Merrill Lynch

Okay. And then, just finally, there was a technical conference a couple weeks ago at FERC on RPM I guess following the decision to support the minimum offer price rules. I was just wondering if you guys had any thoughts on what changes if at all, you expect to the capacity market as far as trying to accommodate either maybe a longer dated project for I guess newbuild generation.

Edward Muller

Mark, you want to take this?

Mark Jacobs

Sure. Ameet, as you mentioned FERC is looking at the technical conference, in addition to that, PJM undergoes a triennial process to evaluate RPM and how it's working. We expect over the next three, four months that they are going to be looking at the RPM model and evaluating whether any changes to that model are appropriate or not. And I think one of the ones that they'll take up is the tenure of how far out the RPM process goes.

And I think from our standpoint, I think one of the challenges the market certainly sees in the RPM model is the volatility that we've seen year-on-year with capacity prices and the inability, if you will, of market participants to predict or gauge where prices are going because of some of the complexities of how that's done. So I would expect that those are all things that PJM and FERC are going to be looking at. And again, we're going to be active in the dialog in terms of how that shakes out and we'll have to see how that plays out over the next several months.

Ameet Thakkar - Bank of America Merrill Lynch

Thank you very much, guys.

Operator

Thank you. The next question is from Gregg Orrill from Barclays Capital. Please go ahead.

Gregg Orrill - Barclays Capital

Thanks. When you talked about the environmental spending, you didn't mention scrubbers. Would it be a fair assumption that based on the way you’re seeing the curves that we can just look at the plants that don't have scrubbers and assume that they would be the shut down plant?

Edward Muller

Well, I think this, Gregg. How all of this is going to play out from the suite of rules is not crystal clear yet, and we are engaged in forecasting and modeling. And the $565 million to $700 million that we've set out today would, as we've just said before, primarily for SCRs and some other controls. But as we've just noted, and I want to emphasize, if market prices increase even more than we currently expect, then we could make additional investments that would meet our criteria. And it is possible depending on the level of such increases that we might consider putting in a scrubber. It's just at this stage I can't put it and we can't put it in the likely category, but we can not preclude it completely.

I'd note, major industry participants in various regions of the country have publically put out what they think the long-term increase in prices to their customers and users are likely to be as a result of the suite of EPA regulations. And the range that I have seen of those increases to end-use customers have been between 10% and 35%. Roughly speaking, as a rule of thumb, about half of the cost to an end-user is wholesale power. So that suggests just doing simple arithmetic, increases in power thought by – perceived by those major participants are between 20% and 70%. That is increases for wholesale power of 20% to 70%.

That is a big range. And it shows you, understandably, that as people try and figure out exactly how all this is going to work assuming it comes down in the ways that we think it's going to come down, that there can be a wide range of outcomes. I think it's without doubt an outcome that has prices rising, wholesale electricity prices. Now, the question is how much. So I don't want to say no, not ever on a scrubber. I do want to repeat that our $565 million to $700 million which we regard as likely, does not include any scrubbers.

Gregg Orrill - Barclays Capital

Okay. Thank you.

Operator

Thank you. The next question is from Brandon Blossman from Tudor, Pickering. Please go ahead.

Brandon Blossman - Tudor, Pickering, Holt & Co.

Good morning, gentlemen.

Edward Muller

Good morning, Brandon.

Brandon Blossman - Tudor, Pickering, Holt & Co.

Let's see, probably best if I continue on the environmental CapEx theme. I guess one question about timing. So I think you're making it pretty clear that timing only could stop once we have finalized rules. But can you put some bookends around that as far as when you'll actually start planning projects and tying down the final numbers there?

Edward Muller

On these kinds of projects there are often planning dollars early on for engineering and so on. But let me reiterate, and you alluded to this directly. We are not committing serious dollars until and unless we have clarity on these rules. Just take CSAPR, I think it is fair to say that for all or virtually all participants in the marketplace, CSAPR came out differently than anyone anticipated. I am sure there is somebody out there who is a genius and knew exactly what was coming out, but we were not among them. And so we have other rules coming and to start expanding capital on the anticipation of what those rules are, we are not going to do. I don't consider it to be prudent.

Brandon Blossman - Tudor, Pickering, Holt & Co.

And then kind of following up on that. You said majority of the spend that you're currently forecasting in SCRs, what about once through cooling 316(b) issues and any changes to what you think your coal burn portfolio will look like?

Edward Muller

Well, there are two aspects to that. Some of what we have in the $565 million to $700 million does include dealing with water. But as you can see from that range of numbers we are not talking about huge expenditures. We think we have a variety of ways that we can address the requirements that are reasonable and justify our expenditures of capital. Your second was I think, Brandon, you referred to coal burns. Tell me what your question was, I’ll make sure that we address it.

Brandon Blossman - Tudor, Pickering, Holt & Co.

Any changes to your sourcing, more Powder River Basin coal perhaps or Illinois Basin coal?

Edward Muller

Not in any meaningful way. I mean we do have some flexibility in that. First in how we can receive coal. For example, we can receive coal for Chalk Point and Morgantown from overseas and we have done a variety of test burns including some Powder River Basin coal at Avon Lake, Niles, and New Castle. But as a general matter, these units were all custom designed for kinds of coal, and while we can blend in something else without a major rebuild, which again would be very large amounts of capital, we can’t change that significantly.

Brandon Blossman - Tudor, Pickering, Holt & Co.

Thanks. That is useful. And then just moving to forward power markets. It looks like not really any material changes to your hedge book quarter-over-quarter except in 2015. Does that reflect a view on the current markets being a little soft compared to what your fundamental view is near term?

Edward Muller

No. Our approach to hedging remains the same. That is we hedge to reduce the volatility of our gross margin, one of our ways of managing our balance sheet so we don’t have to maintain excess amounts of liquidity. And while we have a general trend, we are always looking at what we think are the prices, the timing as well as future changes like the environmental regulations that make us have to assess whether the amount of potential generation is the same from time to time.

Brandon Blossman - Tudor, Pickering, Holt & Co.

Okay. Thank you very much.

Operator

Thank you. The next question is from Brian Chin from Citigroup. Please go ahead.

Brian Chin - Citigroup

Hi, good morning.

Edward Muller

Good morning, Brian.

Brian Chin - Citigroup

Question. And you're not alone in having to address this issue, but how do you intend to balance on your capacity obligations in '12 and '13 versus whatever environmental restrictions or penalties are in place due to CSAPR?

Edward Muller

Rob, do you want to handle this?

Robert Gaudette

Sure. Brian, just so I'm clear on what your question is. If the question is, is we’ve got it or you’re stating and you’re correct. We have obligations to offer in our units for energy in '12 and '13, and your question is, is how are these environmental rules affect that, is that correct?

Brian Chin - Citigroup

That’s right.

Robert Gaudette

All right. So like every other merchant player in PJM, we are going to – as the rules come out, CSAPR is coming out today officially, and the emissions markets develop prior to '12. What I will do or my team will do is incorporate the costs of CSAPR allowances into our bidding and then let the PJM market basically determine how the units run. And what we are doing is, we are meeting our obligation of offering the units in and then the question I guess – the follow on question is, what happens if the whole market runs and units run a lot during the year. You have to think about the caps inside of CSAPR and every player is going to have to consider state caps when they offer in their bids and that could lead to dramatic price increases at the back-end of the year when the CSAPR caps by state get tight. Does that answer your question?

Brian Chin - Citigroup

It does. If I can follow on that thought a little bit; when you are mechanically putting in the cost of the allowances into your energy market bids, is there an oversight or a review process on that, or is it possible for you to say we’re just going to bid in a really high price. So that way we actually get utilized less, but then we can still say, hey, look, we were available, it’s just that we were only available at an extremely expensive price. So, is there like sort of a market monitor that reviews the reasonableness of the bid that goes into the energy market?

Robert Gaudette

The way the bids work, Brian is, there we submit two sets. We submit a market bid, which any participant can pick what their price is. So, it’s kind of to the effect of what you’re talking about. I don’t want to run much, so I'm going to offer my plant high. However, there is a second cost based bid that we have to file with PJM everyday which incorporates your cost of fuels, your cost of emissions, etcetera. And those are reviewed by the market monitor.

And so, if you find yourself in a place where your unit, you’re a – they call it a three supplier test – but if you’re being mitigated, meaning you could create a giant price change because you’re the only guy in town, what PJM then does is goes back to your cost based bids and incorporates that in. In my cost based bids I would incorporate every dollar of expense that I would have around those emissions programs that are now going to kick off in '12. Does that help you?

Brian Chin - Citigroup

That’s very, very helpful. And then one last unrelated question and then I’ll jump back into the queue. Can you talk about, if you were to add on SCRs or SNCRs, what is the impact to your variable operating cost per megawatt hour?

Edward Muller

I think this, Brian, we are not ready to lay out the specific numbers, but there is no question it will increase the variable operating costs.

Brian Chin - Citigroup

Are there – okay, thank you. That’s helpful.

Operator

Thank you. The next question is from Brian Russo from Ladenburg Thalmann. Please go ahead.

Brian Russo - Ladenburg Thalmann & Company

Hi, good morning.

Edward Muller

Good morning, Brian.

Brian Russo - Ladenburg Thalmann & Company

Most of my questions have been asked or answered, but just curious on the cost cutting and synergy run rate. Is that a comfortable number or are you still looking to create more synergies or cut additional costs above that $155 million run rate?

Edward Muller

We are very comfortable with the $155 million, and our approach to this consistently has been to lay out what we actually expect, to neither be reaching for what we don’t yet see nor to be underestimating so we can look a bit like heroes. That said, so we think $155 million is the right number and we are comfortable with it. That said, we run this business and we think about costs all the time and we will never stop and that will continue past January 1, 2012 as well, but I think you should for now rely on the $155 million and assume that's the number.

Brian Russo - Ladenburg Thalmann & Company

Okay. And then just the total baseload volumes you're projecting in 2012, they are up quite significantly. And I know it’s hard to pinpoint one driver, but maybe you could discuss the various drivers that might be increasing your expectations for output there.

Robert Gaudette

Sure. I mean, for the increases generally in volumes, it's a function of widening dark spreads basically. You think about the GenOn fleet, we’re a large coal fleet and over the last several months, especially in the first quarter, we saw a compression of the dark spread. Natural gas prices increased in 2012 versus 2011 and coal prices, I haven’t looked at them in the last three days, but they have kind of stopped going up. So, we've seen an expansion in spreads. And that would lead to increased expected generation in the baseload market.

Brian Russo - Ladenburg Thalmann & Company

Understood. Thank you.

Operator

Thank you. The next question is from Ted Durbin from Goldman Sachs. Please go ahead.

Ted Durbin - Goldman Sachs

Thank you. Most of my questions have been asked. I just wanted to come back to the CSAPR, not to stay on this too much, but you said allowance prices are based on EPA estimates and you expect a modest impact. Do you think that those EPA estimates are actually reasonable or how are you thinking about allowance prices?

Robert Gaudette

That’s a great question. We looked at EPA’s estimates and then we’ve continued to try to understand the program and see how and where the program gets tight. I’m not in a good place to speculate as to how – what kind of quality is in those numbers. I think that’s something that over the next couple of months we’ll expect the market to begin to digest and that will add some clarity for me as to what those look like. But right now I’m just not prepared to talk about it.

Ted Durbin - Goldman Sachs

I mean even just directionally, higher, lower, any sense there or…?

Edward Muller

No, Ted, this is Ed. We’re not prepared and adding to the complexity on why we think that the market is still processing this. The market understands that there are parties who are going to seek to overturn CSAPR and stay CSAPR. So the market is understandably and intelligently in some disarray over this.

Ted Durbin - Goldman Sachs

Got it. That's helpful. And then I'd just love a little bit more of your general thoughts on the PJM capacity auction results, where they came out. How that may be factoring into some of your decision making in some of the numbers you put out today on your environmental spending going forward?

Edward Muller

It would not be fair to say that it's factored into our decision making. We’re looking – notice that the capital spending that we’ve laid out there is over an eight-year timeframe and we’re looking out a number of years. You don’t invest capital in this business for a year or two or three years out. These are long-term assessments and they have to make sense long-term. A factor is how we think about the capacity markets. We are always learning more, confirming our thinking and our methodologies and assessing them, but I wouldn’t draw any particular significance from how the last RPM auction came out.

Ted Durbin - Goldman Sachs

Okay, that's it for me. Thanks.

Operator

Thank you. The next question is from Mark Barnett from Morningstar. Please go ahead.

Mark Barnett - Morningstar

Hey, good morning, guys.

Edward Muller

Good morning.

Mark Barnett - Morningstar

Just a couple of quick questions. The first on your slide, when you were giving your guidance around your coal costs for 2014 and 2015 on slide 21. There is a pretty marked difference there, first between 2013 and 2014, and also between your first quarter and second quarter slide decks. And then you have just don't have any information on there for ‘15. I was just wondering, a, what is driving that and c, why 2015 is no longer included?

Edward Muller

Well, I'm going to let Rob amplify. But as a general matter so you understand how we buy coal. We go out at least twice a year seeking long term supplies. We sometimes buy and we sometimes don’t. And so, we are always running with overlapping contracts. And as contracts roll-off and new contracts come on, you should expect to see prices move to reflect the simple dynamic aspects of how we go about sourcing our coal. As to your particulars for 2015, Rob, is there anything that you can add there?

Robert Gaudette

You know in 2015, we’ve – other than Seward, we haven’t added any contracts. As far as value that rolls through hedges, remember that coal is a very lumpy product. So, over the last few months we have worked and gone through in RFP. We’ve added coal through '14, though it may be minor, in small amounts. And sometimes, depending on where the coal curve is, on the day we set guidance. We'll set where the hedge values are based on expected burns and as inventories cross over years. But there is not a whole lot to talk about as far as coal in ‘15.

Mark Barnett - Morningstar

Okay, thanks for that. Then, second, a couple other companies have mentioned pre-trading and pricing that they have seen in pre-CSAPR implementation trades. Have you seen any pricing yet or – I don't need an estimate for where you think they're going to be, but just have you seen any kind of pre-trading value yet?

Robert Gaudette

I have not seen any trades. We’ve seen very wide markets that aren’t even worth talking about. The one thing that you guys probably read over the weekend is that I believe contracts are going to be on ice at the end of the month. So, maybe we’ll see some market visibility then. But no, we have seen zero trades.

Mark Barnett - Morningstar

Okay. Thanks a lot, guys.

Operator

Thank you. The next question is from Ali Agha from Suntrust. Please go ahead.

Ali Agha - Suntrust Robinson Humphrey

Thank you, good morning.

Edward Muller

Good morning.

Ali Agha - Suntrust Robinson Humphrey

Ed, to be clear, when you talk about a modest impact from CSAPR as you're going through your analysis, you're talking about a modest negative impact. Is that the way to think about it?

Edward Muller

Yes.

Ali Agha - Suntrust Robinson Humphrey

Okay. And when you look at the decision making that you do need to make going forward with all the rules coming in etcetera, assuming the schedules remain on track, when would you be at the earliest in a position to think about capacity retirements? Is that a second half 2012 timeframe? Or what is your current thinking there?

Edward Muller

You know, Ali, our thinking is not clear on it. Because we have lived through this long enough and gone through this enough times that rules including their timing are not for us real until they are actually out there. And so we are watching this and, to be blunt, it is sort of like trying to make mush concrete. And it's just – to get out ahead of ourselves and say we’ve got drop dead dates and so on while we're waiting for the regulators to deal with what are very complex and difficult subjects, could drive us nuts. And we will wait.

Ali Agha - Suntrust Robinson Humphrey

Also, to be clear, the carbon levy that is no longer going to be implemented on you, the impact of that was, what, about $10 million a year? Can you just remind us what the impact would have been if that had stayed on?

Edward Muller

Sure. Bill, do you want to take that.

J. William Holden III

Yeah, the effect would have been $12 million this year and $13 million estimated for next year.

Ali Agha - Suntrust Robinson Humphrey

I see, okay. And final question, Ed, back to you. Obviously, with the market uncertainty impacts everyone's operations, you've got this big CapEx potential spending ahead of you as well. In the meantime the stock, like many others, is taking a pounding out there in the market. Given your liquidity position and your downward risk assessment, etcetera, is there any consideration or thought going in into balancing the environmental CapEx spending versus investing that capital in your own equity. Given where your stock is currently trading?

Edward Muller

Well, I’m going to let Bill walk you through again how we think about this, and this is our consistent approach which is how much liquidity we need in the business and whether we have excess liquidity, which we do not. We don’t think we do. And the fact that the market is in, the stock market is in some disarray with a variety of factors that go way beyond what is happening in the energy industry and what is happening in the electricity industry and so on, does not change the discipline that we bring everyday to how we assess the management of the business and the management of our balance sheet. So, with that, Bill.

J. William Holden III

Ali, I think we haven’t changed the framework that we use. So we look at liquidity requirements and the high price environment but also on a lower price environment. And as we’ve started to look at what likely capital expenditures could be based on pending environmental regs, we have started to incorporate that into our analysis as well. And as Ed said, given the outlook across those types of scenarios we don’t think we’re in a position we have excess cash today.

Ali Agha - Suntrust Robinson Humphrey

Right. I guess, Ed, what I was alluding to was, I mean, assuming in your mind you have a sense of what the intrinsic value is for GenOn and for the equity and presumably, you believe it is higher than where it is currently trading at. So I was just thinking, is there something more proactive you could do to bring that value out or do you think the market cycle has to play itself out for that to be recognized?

Edward Muller

Well, I think the reason I focused on liquidity and whether we have the appropriate liquidity for the company is, as the folks in Washington are slowly coming to learn you can’t spend what you don’t have.

Ali Agha - Suntrust Robinson Humphrey

Fair enough. Thank you.

Dennis Barber

Sandra, I think we can take about two more.

Operator

Thank you. The next question is from Robert Howard from Prospector Partners. Please go ahead.

Robert Howard - Prospector Partners

Good morning, guys.

Edward Muller

Good morning, Rob.

Robert Howard - Prospector Partners

A couple things. One, on your detailed guidance slide, you guys had – the working capital number, as comparing to the last call, you had a $241 million use of working capital. And that has dropped down to $68 million. I am just wondering what was driving that.

Edward Muller

Gary, you want to take that?

Gary Garcia

Absolutely. The main change there, Rob, is the Maryland Healthy Air Act, the cash that we’ve moved over to funds on deposit as we pay for the Maryland Healthy Air Act, instead of the cash to make those expenditures coming from cash, it will come from working capital and the funds on deposit. And so we’ve made that adjustment there by increasing the return of the working capital, but as you know, below in the Maryland Healthy Air Act we’ve also dropped that to $12 million to correspond to return of the funds on deposit.

Robert Howard - Prospector Partners

Okay. Great. And then on slide 16, the guidance sensitivity. Just kind of looking at the bottom there. And this may relate a little bit to one of the things Brian was asking earlier, but just looking at the market implied heat rates in 2012, and compared to the last quarter all those heat rates have increased a decent amount. And I just wondered if you had any comments about the market in general and what might be driving that improvement in the power market.

Edward Muller

Rob? I am sorry, Rob Gaudette.

Robert Gaudette

I think there is lots of factors that are working on the heat rates, but if you think about in 2012 in particular, which was your focus, we saw gas prices come off. However, we had a fairly volatile and interesting summer in power, gas prices regardless. And that has led the forward markets to take that into consideration and now people are thinking that we’re a little bit further up the stack when they are pricing these forward prices. And also is somewhat a market view or some form of market view of the future uncertainty that we’ve been talking about for 45 minutes now. Just how things are going to work and what that's going to do to the overall stack. Does that answer your question?

Robert Howard - Prospector Partners

Yeah, I mean is there a kind of outlook, if the economy is getting better and power demand is going to keep increasing and reserve margins going down or is it really just more of the other things besides demand?

Edward Muller

I don’t think we’d be relying on the economy getting better. Rob, got to add anything further? I think we’re talking much here little issues in the sector rather than big issues in the economy.

Robert Howard - Prospector Partners

Okay. And then, lastly, back on slide 21, just the hedges that you guys have. I was looking at the power hedges in ‘12, ‘13 and ’14. And it looks like you took them off a little bit compared to the third quarter. And it’s not huge but it is a little bit. I didn't know, does that mean or it kind of implies you want to be a little bit longer on those out years, or is something else going on that would have you take things off?

Edward Muller

No, generally speaking, Rob, we have not taken any off. And what you would see, however, is we are always updating for how much we have hedged against our expected generation. And expected generation which takes account of what we see in the marketplace, prices, fuel and the whole ball of wax, changes from time-to-time. So, we can with the exact same hedges see increases and decreases in our degree of being hedged based on what we expect in expected generation.

Robert Howard - Prospector Partners

Well, I – okay. So, like, when I look at 2014, last quarter you said you had 7.3 million equivalent megawatt hours sold and this quarter you said you have seven equivalent million of megawatt hours sold. So you’re saying that that equivalents sold can change based on…?

Robert Gaudette

No. This is Rob Gaudette. If you think about the way that we hedge in the back end of the curve, so, '13, '14, '15 or beyond, our primary tool is natural gas. So if heat rates expand or contract out in the back then that's what leads to different numbers on megawatt hour equivalents. What we've done is convert our gas hedges into megawatt hours for you to make it easier for you to compare to our expected generations. Like what this is – I know for fact we have not taken off ‘14 hedges. What it is, is the change in the conversion between natural gas and megawatt hours based on heat rates.

Robert Howard - Prospector Partners

Okay. All right. Yeah, because I guess usually I have thought about it. Most of the time when I have looked at it, your chart that you have early in the presentation, and just kind of the percentage changes have been based on your change in output. But I guess I hadn't realized kind of the way this part was looking here. Okay, that's it. Thanks.

Operator

Thank you. The last question will be from Julien Dumoulin-Smith from UBS. Please go ahead.

Julien Dumoulin-Smith - UBS

Hi, good morning, can you hear me?

Edward Muller

Absolutely. Good morning.

Julien Dumoulin-Smith - UBS

Excellent. With regards to the SCR and the NOx controls, I know the Maryland Healthy Air Act as a second step up here in ‘13. Just curious, it seems if I look at the CapEx profile or the new numbers you're talking about, that probably relates to Dickerson and Chalk Point as far as that moving from SNCR's to SCR's. Is that predicated on the Healthy Air Act compliance, and to what extent would you anticipate getting that for the second stage or the step up, if you will, in CSAPR in ‘14?

Edward Muller

We are looking here at a whole suite. And let me repeat, we don’t look nor do I think we ought to look, at just one regulation and so on. We are looking at the whole suite to see what is justified in how we go forward.

Julien Dumoulin-Smith - UBS

Okay, great. And then, secondly, if I take a look at the RPM numbers or the updated capacity numbers you provided and try to interpolate a sense on how much of your generation cleared in the latest ‘14/’15 auction. It would seem as if perhaps not all of the generation cleared. At least, preliminarily, can you provide an indication as to whether that was more eastern or western oriented? Was that more of the RTO capacity or the MAAC capacity? Or perhaps I have this off and did all of your capacity clear?

Edward Muller

We understand your question. It’s a good question and one we get frequently. And as you can imagine for competitive reasons we are not going to disclose what the cleared were. We will, I want to emphasize there are a bunch of rules that PJM has in how this process works and we comply with those rules religiously. Always have and will continue to do so but beyond that we’re not going to go.

Julien Dumoulin-Smith - UBS

Great. Going back to Brian's question quickly. If you were to install SCR's versus the current SNCR's, that would actually lead to lower cost or lower ongoing variable costs, correct?

Robert Gaudette

It will lead to lower variable emissions costs for sure. I'm the commercial guy, so I'm not ready to speak for the operations department. But if you just think about an SNCR versus an SCR, the SCR is more efficient at removing NOx, and so that will reduce the BOM or the cost of emissions inside a power based on the improvement of basically reducing your NOx costs.

Julien Dumoulin-Smith - UBS

Great. And then, quick, a last question on the capacity payments again. Looking at the west. I know and I approve – appreciate the improved disclosure here, trying to break out California separately. But, again, it is a bit tricky to exactly distill what the Marsh Landing component is relative to the other plants. Can you give us any kind of sense as to what is contracted for, what’s changing ‘12 versus ‘13 versus ‘14 a little bit. I mean I noticed the numbers are actually declining and I imagine that’s because some of the capacity isn't quite yet contracted, correct?

Edward Muller

Bill, you want to take this?

J. William Holden III

Yeah. As we move through time we do have different amounts of capacity under contract in California, and that generally declines as you move sort of into '13, '14 and '15. By the time we get to '15, we don't have anything under contract except for Marsh Landing.

Julien Dumoulin-Smith - UBS

Great, thank you.

Dennis Barber

Well, thank you very much for participating in our call today. A replay of the webcast will be available in approximately two hours. Thanks and have a great day.

Operator

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating, you may now disconnect.

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