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Executives

Dennis Barber - IR

Ed Muller - Chairman and CEO

Bill Holden III - EVP and CFO

Rob Gaudette - SVP and CCO

Gary Garcia - Treasurer

Analysts

Ameet Thakkar - Bank of America/Merrill Lynch

Brandon Blossman - Tudor Pickering Holt

Jon Cohen - ISI Group

Keith Stanley - Deutsche Bank

Jeff Kramer - UBS

Brian Russo - Ladenburg Thalmann

Ali Agha - Suntrust Robinson Humphrey

Mark Barnett - Morningstar

Steven Burd - Morgan Stanley

Ted Durbin - Goldman Sachs

David Frank - Catapult Partners

Tom Rebinoff - Tom Rebinoff Research

GenOn Energy, Inc. (GEN) Q4 2011 Earnings Conference Call February 29, 2012 9:00 AM ET

Operator

Greetings and welcome to the GenOn Energy Fourth Quarter 2011 Earnings Call. At this time all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions) As a reminder this conference is being recorded.

It is now my pleasure to introduce your host Dennis Barber of GenOn Energy. Thank you Mr. Barber you may begin.

Dennis Barber

Thank you, Rob 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, our 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. And a replay of this call will be available on the website approximately two hours after the 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 the 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 are also using non-GAAP measures to provide additional insight into the operating results and guidance and reconciliations of the non-GAAP measures to GAAP figures are available on the website.

I'll now turn the call over to Ed.

Ed Muller

Thanks Dennis, and good morning everyone. I’ll start on Slide 4 with some updates. First, when we announced the merger of RRI and Mirant in April 2010, we committed to annual savings from the merger of $160 million by January 2012. We have met and we have exceeded our commitment. Starting last month, we are saving $160 million per year in costs. Second, I’m pleased to report that the construction of Marsh Landing in Northern California remains on schedule to be completed by mid 2013 and the project remains on budget. Third, we and others were successful in obtaining a stay on the last business day of 2011 of the Cross-State Air Pollution Rule or CSAPR. We see CSAPR as a significant negative for our business until compliance with what is now called Mercury and Air Toxics Standards or MATS begins in 2015. We see MATS as very positive for GenOn.

As a result of MATS and other environmental regulations we expect to deactivate 3,140 megawatts of generating capacity, because our forecasted returns on investments necessary to comply with the environmental regulations are insufficient. For units that we will not be deactivating, we expect to invest between approximately $586 million and $726 million over the next 10 years for major environmental controls. Overall, we expect higher earnings from price increases resulting from industry retirements will more than offset reduced turnings from GenOn unit deactivations.

Turning to slide 5, we laid out our updated guidance for adjusted EBITDA for 2012 and 2013. We have reduced our guidance for both years because of lower energy margins offset somewhat by higher realized value of hedges and reduced operating expenses. Bill Holden will provide more of the details on our guidance shortly.

Turning to Slide 6, we show our hedges as of January 24, both for the fleet and for our base load coal. For our base load coal, we are fully hedged for this year, heavily hedged for next year and less hedged but nevertheless, somewhat hedged from 2014 through 2016. You should expect us to maintain that general profile as we go forward.

On Slide 7, we lay our approach to capital expenditures for environmental controls required to comply with the environmental rules. We will invest only if we are confident that the expected return will exceed our cost of capital. We expect that industry retirements including those already announced will result in market prices rising sufficiently to justify investments of between approximately 586 and $726 million over the next 10 years. If prices improve even more than we expect, more investments could become economic.

On Slide 8, we lay out our expected deactivations. In the top box you can see the units totaling the 3,140 megawatts I mentioned earlier. We expect to deactivate the units over a periods starting later this year and ending in the middle of 2015. In the bottom box we have laid out other reductions in our fleet.

Let me speak for a moment about Avon Lake which is near Cleveland, Ohio. It's big unit, its 640 megawatts. Our analysis to-date indicates that the return on investment on required environmental control for that unit is insufficient. That’s why we expect to retire the unit in 2015. We are however, continuing our analysis of the sufficiency of the return on the required investments, which would total about $500 million between 2013 and 2020 for a scrubber, an SCR, and water intake screens.

On Slide 9, we lay out the particulars of our expected investments between approximately 586 and $726 million over the next 10 years for major environmental controls. This range is slightly higher than our forecasted range last quarter, because we expect additional investments to meet our investment criteria.

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

Bill Holden III

Thanks Ed and good morning everyone. I will begin on Slide 11. Adjusted EBITDA for the quarter was $57 million a decrease of 93 million from pro forma results for Q4 2010. For the year adjusted EBITDA was $622 million a decrease of 297 million from pro forma results for 2010. The pro forma results for 2010 adjust the reported Mirant results that show the combined results for Mirant and RRI adjusted for merger related items.

Adjusted EBITDA for the quarter and year was lower principally because of lower adjusted energy gross margin and lower contracted and capacity revenue partially offset by lower adjusted operating and other expenses. The $80 million reduction in energy gross margin for the quarter reflects lower energy gross margin from generation principally from Eastern PJM. The $74 million reduction in contracted and capacity revenue for the quarter principally resulted from lower capacity revenues and PJM. And the $37 million lower adjusted operating and other expenses for the quarter primarily reflect lower plant costs and merger related costs savings. The $284 million reduction in energy gross margin for the year reflects lower energy gross margin from generation again principally from Eastern PJM. The $196 million reduction in contracted and capacity revenue for the quarter principally resulted from lower capacity revenues and PJM. The $157 million lower adjusted operating and other expenses for the year primarily reflects merger related cost savings and lower plant cost.

Slide 12 summarizes debt and liquidity for GenOn at December 31, 2011. Total debt outstanding was approximately $4.2 billion, the increase of 55 million since September 30 was attributable to borrowings on the Marsh Landing credit facility at $57 million slightly offset by term loan amortization of 2 million.

Total cash and cash equivalents was just under 1.7 billion on which just under $1.6 billion was held at GenOn or its subsidiaries other than GenOn Mid-Atlantic or REMA. At December 31, 29 million of cash in REMA was not available for distribution because REMA did not satisfy the ratio required and its operating leases to permit distributions.

In addition, based on the results for the quarter, GenOn did not satisfy the ratio required by the GenOn senior notes to allow distributions of cash above the $250 million basket. And do not expect either of these restrictions to effect operations. Including availability under the revolving credit facility. Total available liquidity was just under $2.2 billion. And finally, funds on deposit at year-end were just over $600 million.

Slide 13 provides details around our adjusted EBITDA guidance for 2012 and 2013. First, as noted on the slide our guidance is based on forward commodity prices as of January 24, 2012. In addition, our guidance for 2012 and 2013 no longer incorporates the effects of the Cross-State Air Pollution Rule which has been stayed.

As Ed described we are reducing our adjusted EBITDA guidance to $440 million for 2012 and $665 million for 2013. I will provide additional detail on adjusted gross margin and a comparison to prior guidance for 2012 and 2013 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, we arrive at adjusted net cash used in operating activities of 101 million expected for 2012. And adjusted net cash provided by operating activities of $279 million projected for 2013.

Deducting projected capital expenditures to be paid from cash for each year arrives at an adjusted free cash flow deficit of 313 million projected for 2012. And adjusted free cash flow of 3 million for 2013.

As noted on the slide, capital expenditures to be paid from cash, exclude the amount for Marsh Landing they will be funded by project finance debt as well as the remaining Maryland Healthy Air Act capital expenditures that will be paid from funds on deposit.

Adjusting for the Marsh Landing working capital and equity contributions, and payment of merger related costs, results and adjusted free cash flow deficits excluding these items of 334 million projected for 2012, and $65 million projected for 2013.

Finally, hedged gross margin which includes energy gross margin that is hedged plus contracted and capacity revenues for which prices have been set has approximately 1.32 billion in 2012 or about 84% of projected 2012 adjusted gross margin. And approximately 1.41 billion in 2013 are about 80% of projected 2013 adjusted gross margin. Deducting the full-year forecast for adjusted operating and other expenses arrived at hedged adjusted EBITDA of $190 million for 2012 and $310 million for 2013.

Turning to Slide 14, this slide presents the components of adjusted gross margin that are contained in our guidance for 2012 and 2013. 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 a little over half of our projected adjusted gross margin for 2012 and 2013. Prices have already been set for over 95% of these amounts end of years. The increase of 149 million from 2012 to 2013 is driven primarily by higher RPM auction prices in 2013.

Energy shown as the middle bar represents gross margin from the generation of electricity and market prices, fuel sales and purchases at market prices, fuel handling, steam sales our proprietary trading and fuel management activities and natural gas transportation and storage activities. The increase of 109 million from 2012 t 2013 results from higher market prices and higher generation.

And finally realized value of hedges, the top bar, reflect the actual margin and settlement of our power and fuel hedging contracts and the difference between market prices and contract cost for fuel that we have purchased under fixed price 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 locations of our physical assets.

The decrease of 57 million from 2012 to 2013 is driven principally by a lower hedged percentage of our expected generation in 2013 as compared to 2012, partially offset by higher hedged to margins.

Turning to Slide 15, this slide reconciles our previous adjusted EBITDA guidance to our updated guidance. Our updated 2012 guidance is $56 million lower than our previous adjusted EBITDA guidance for 2012. This decrease is comprised of $271 million decrease related to market price and generation changes reflecting lower power and natural gas prices, which was offset to a large degree by an increase in realized value of hedges.

Our updated 2012 guidance also reflects a lower expected contribution from energy marketing, slightly lower contracted and capacity revenues and a $21 million decrease in operating and other expenses. Our updated 2013 guidance is $96 million lower than our previous adjusted EBITDA guidance.

This decrease is comprised of a $277 million decrease related to market price and generation changes again reflecting lower power and natural gas prices, which was partially offset by an increase in realized value of hedges.

Our updated 2013 guidance also reflects a $44 million decrease in operating and other expenses primarily related to lower plant cost resulting from plant generating station deactivations as well as a $3 million lower expected contribution from energy marketing.

Turning to Slide 16, this shot at slide shows sensitivities around our guidance. The guidance for both years is based on commodity price as of January 24, 2012. An NYMEX natural gas price and Market Implied Heat Rate for 2012 for the period from February through December.

A $1/mmBtu in the price of natural gas for the balance of 2012 is estimated to result in a $63 million change in adjusted EBITDA for 2012. Our 500 Btu per kilowatt hour change in Market Implied Heat Rate for the balance of 2012 is estimated to result in a $20 million change in adjusted EBITDA for 2012.

For 2013, $1/mmBtu move in the price of natural gas is estimated to result in $137 million change in adjusted EBITDA, our change of 500 Btu per kilowatt hour and Market Implied Heat Rates for 2013 is estimated to result in a $50 million change in adjusted EBITDA for 2013. Note that the natural gas sensitivities assume Market Implied Heat Rates and generation volumes are held constant. On the Market Implied Heat Rate sensitivities assume fuel price and generation volume are held constant.

The sensitivities are greater in 2013 because we are less hedged in 2013 than in 2012.

Turning to Slide 17, this slide presents a breakdown of our projected capital expenditures for 2012 and 2013. We expect our 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. The total projected cost for compliance with the Maryland Healthy Air Act remains at 1.67 billion, the remaining 83 million is expected to be paid this year.

As I noted earlier, the funds to satisfy the remaining payments are held as restricted cash at GenOn Mid-Atlantic and have been moved from cash and cash equivalents to funds on deposit on the balance sheet. Other environmental expenditures are estimated at $64 million this year and $120 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 completion of the Ash Beneficiation project at our Morgantown plant.

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

Ed Muller

Thanks, Bill. I’ll turn to Slide 18 to sum up. First, as I said earlier, we met and exceeded our commitment for annual savings as a result of the merger to create jobs. Our savings starting last month are $160 million per year. Second, Marsh Landing remains on schedule and on budget. Third, we will invest in environmental controls if we are confident the expected return will exceed our cost of capital.

As a result of MATS and other environmental regulations we expect to deactivate 3,140 megawatts of generated capacity because our forecasted returns on investments necessary to comply with the regulations are insufficient. For units that we will not be deactivating, we expect in accordance with the same investment criteria to invest between approximately 586 and $726 million over the next 10 years for major environmental controls. Overall, we expect higher earnings from price increases resulting from industry retirements were more than offset reduced earnings from GenOn unit deactivations.

And with that, Rob, we’re ready to take questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Thank you. Our first question is from Ameet Thakkar of Bank of America/Merrill Lynch. Please proceed with your question.

Ameet Thakkar - Bank of America/Merrill Lynch

Well, thanks for the additional disclosures, it’s helpful. Ed, you mentioned that your guys are still in the evaluation process with respect to Avon Lake, but right now as you see it, you kind of put in the bucket where you expect to shut that down. When the PJM parameters were leased and it did highlight that Avon Lake unit nine does provide a lot of voltage support in the amps region. Is there a scenario where you could see that unit being placed in the RMR status and how would that work?

Ed Muller

Well, it’s all possible that of course is PJM’s purgative and decision in PJM the ISO does not have the authority to require us to enter into such a contract. But, as a practical matter, we would of course do everything we could to help PJM to meet its obligations. Whether PJM will do that, I can’t tell you, that’s for PJM to address. I would know note that to enter into some sort of contract for Avon Lake unit 9 would presumably have to include the environmental costs for CapEx that I mentioned earlier of about $0.5 billion for a scrubber and SCR and water intakes screens.

Ameet Thakkar - Bank of America/Merrill Lynch

Okay. And then, just looking your updated hedged profile, it looks like you’re, I guess, a little bit more hedged in power versus coal in 2013? Now, I mean, is that, I guess the kind of normal course or is that kind of based on maybe a view point that you have on kind of value of gas versus coal as we stand here today?

Ed Muller

Rob, do you want to take that?

Rob Gaudette

Sure. Just recall, we’ve talked about this a little bit before, but when we think about our coal hedging versus power hedging, I do try to maintain somewhat of a balance, but recall the markets aren’t quite as liquid as power, we could trade every day. Coal we go out for RFP twice a year. We’re looking our forward projections and we have the benefit of carryovers as far as inventory goes. So, where are you looking at our positions and where our hedges are? This doesn’t concern us. I think that we’re in a good place. We’re always looking to optimize the value around our coal. So, as you’re kind of suspecting, prices have dropped recently, that’s good, but that was not a play on our part. We try to look at our needs going forward and in the spring and the fall, we go out for RFP and address our needs up to three or four years out. That answered your question?

Operator

Thank you. Our next question is from line of Brandon Blossman of Tudor Pickering Holt. Please proceed with your question.

Brandon Blossman - Tudor Pickering Holt

Ed, retirement/deactivation, can you give a little bit more color around how permanent those deactivations are going to be, I assume they vary by plant?

Ed Muller

That’s correct. When we indicate that we’re going to retire them, we expect that to be permanent, there are things that could happen, but, our expectation is they are permanent. For the units that where mass falling which are at REMA, we expect that within two years following the mass falling of the unit, the station will be retired and for the units at Shawville, which we are putting into long-term protective layup, that is in compliance with the lease for the units, which runs through 2016. We don’t expect to be operating the units, but we intend to maintain them in accordance with the lease including making rent payments all the way through 2016.

Bill Holden III

One thing that lease front is 5026.

Ed Muller

I’m sorry, thank you.

Brandon Blossman - Tudor Pickering Holt

Too bad. And then so should we expect kind of incremental say severance and shutdown cost between ‘12 and ‘15?

Ed Muller

Yes, we will have some costs to shut down there not as to the physical plants, all that significant because in no case do we see a requirement or nor do we have a plan to actually bring down the physical facility. We would of course maintain it in a safe condition including security services and so on and we would have severance for employees who would be leading the stations and that would be one-time significant costs.

Brandon Blossman - Tudor Pickering Holt

And then kind of switching gears here ‘12 and ‘13 coal burns. It looks like your base load generation expectations are down particularly for ‘12. Any risk of obligations on the coal delivery side, running up inventories to levels that are not kind of palatable sort to speak?

Ed Muller

Rob, do you want to take that?

Rob Gaudette

Sure. So, in most of our contracts most probably we get a definition. We have a couple of provisions, one is we have carryover tons because the industry obviously it’s hard to pin down exactly where we’re going to be as far as burns go. But as we look at our procurement plants over time, we typically don’t hedge up or lock up a 100% of the coal going into a delivery here for reasons exactly like you talked about. We do have inventory space at our plants. We have a lot of ability to move contracts or coal from one station there was destiny for one station to go to another, so we can balance out inventory levels. And we’re already talking to coal companies, not just about ‘12, but into ‘13 and ‘14 about how we look at, what our procurement plants look at over time. So, as I procured going into a year, I’m always taking that into account. And then, secondly, we balance across our plants to maintain safe levels of inventory. Does that answer?

Brandon Blossman - Tudor Pickering Holt

It does, and I guess from say year-over-year last three or four months, I imagine that your expectations for ‘12 coal burn have dropped dramatically. So, it seems like more of a state change than anything that’s happened previously?

Rob Gaudette

We’re definitely seeing lower coal burns, both realized over the lot in Q4 and then on a projected basis, our expectations of burns have been down over the last couple of years, but when I go to procure coal, I’m looking three or four years out, but I’m layering in, that’s like we layer in power hedges, I just do it twice a year. So, right now, we’re in a pretty decent month.

Operator

Thank you. Our next question is from the line of Jon Cohen of ISI Group. Please proceed with your question.

Jon Cohen - ISI Group

Ed, can you give us some sense of how are you’re tackling the decision to retrofit Avon Lake and other units, I mean are you willing to undertake retrofits just based on PJM’s capacity market dynamics or would you want to get some longer term contracted revenue stream in order to do that?

Ed Muller

Well, longer term contracted revenues in PJM are not available. So, we are doing a full analysis taking into account on a continuing basis, all of the data that we can obtain in the marketplace. And that includes of course the capacity of markets, but also the energy market, and we we’re using looking not at any one data point, but over time, what our assessment is and we’re doing just we’d think it hopefully would do, which is we’re doing a return on investment analysis using our best judgment, looking at a variety of cases and seeing whether the investments meet our cost or exceed our cost to capital. And that’s what true for Avon Lake and every other unit that we have assessed and our approach to it is consistent and it is unit-by-unit.

Jon Cohen - ISI Group

Okay. And when you think about the long-term sort of correct mid cycle capacity number, what is that?

Ed Muller

Well. First, we don’t think about a long-term mid cycle capacity number and if we did we wouldn’t disclose it, but we are looking in a very careful and analytical way, not at rules of thumb but at what we see in the market and assessing what we see occurring the market, whether it’d be retirements, whether it’d be new goals, the demand forecast and we’re doing this all the time and constantly updating it and taking it out for many years.

Jon Cohen - ISI Group

Okay. And just one other question, your OpEx projections, so those take into account what would seemed to be much higher cycling requirements for the coal units and the wear and tear that’s likely to have on the machines?

Ed Muller

We absolutely take into account, how we’re going to operate these units.

Operator

Thank you. Our next question is from the line of Keith Stanley of Deutsche Bank. Please proceed with your question.

Keith Stanley - Deutsche Bank

Ed, you show expected O&M reductions of 80 million a year from 2013 levels due to the retirements you intend to make in 2015, can you provide any rough sense of how much those plants will contribute in terms of gross margin in 2013 so we can assess the impact of retirements on EBITDA. Or in other words should we think of these plants as contributing materially to 2013 EBITDA guidance?

Ed Muller

Bill, why don’t you take that?

Bill Holden III

Yes. I think first it’s important to note that the deactivations that we have for 2012 are reflected in the 2012 and 2013 guidance. The other deactivations are not until 2015, we haven’t provided guidance for 2015, but we have said that we expect higher earnings from price increases that result from the industry retirements to more than offset the reduced earnings from GenOn unit deactivation. So, that’s the way I’d encourage you to think about it.

Operator

Thank you. Our next question is from the line of Jeff Kramer of UBS. Please state your question.

Jeff Kramer - UBS

Just on your 2013 guidance, CSAPR was excluded from that, in the last quarter you mentioned it was going to be about an $85 million impact on 2012 results. If CSAPR gets reinstated, GenOn at ‘13, is that how we should be thinking about the impact next year still or.

Rob Gaudette

Hi, this is, Rob. I don’t think I would think about it that way, the market has moved quite a bit in terms of the price of power and natural gas. So, that would have an effect on the cost of CSAPR. I can’t quantify for you what it would be in the current market because our guidance is based on January 24th prices and since the rule has been stayed, we don’t have a good market data point for what the cost of the allowances would be in this market environment. We still think its negative, but I don’t think what we thought in the prior commodity price environment of our last guidance, would still be applicable in this situation.

Jeff Kramer - UBS

Okay. And, just on the PJM capacity auction coming up in May, any thoughts on that kind of versus last year, where that’s headed.

Ed Muller

As both on practice and what we think is appropriate that we’d not be accused ever of trying to signal to other bidders, bidding behavior, which we do not do. We have no comments.

Jeff Kramer - UBS

Fair enough and just a couple of follow-ups. On Shawville, I’m assuming that you’re going to make the lease payments on the agreement leases, I mean effectively those all the plants in REMA or Elrama hope be the guarantees, I’m assuming that supporting that decision?

Rob Gaudette

Yes, that’s correct. The obligations for the REMA leases, our obligations of REMA.

Jeff Kramer - UBS

And it’s done on liquidity, I’m assuming no change in allocation of your cash position that remains kind of hope your down liquidity and then your uses for environmental CapEx is needed over the next several years. Is that correct?

Rob Gaudette

That’s correct. I think, we’re using the same framework that we’ve used in the past and based on our assessment, we don’t think we have excess cash at this time.

Operator

Thank you. Our next question is from the line Brian Russo of Ladenburg Thalmann. Please proceed with your question.

Brian Russo - Ladenburg Thalmann

Just on the guidance assumptions on slide 20. You’re showing quite a bit of a step up in the Western PJM/MISO volumes, in ‘13 over ‘12, I was just wondering if you could kind of elaborate on what the drivers are there?

Ed Muller

Rob, you can correct me. I think, it’s driven by higher energy prices in ‘13 and ‘12.

Brian Russo - Ladenburg Thalmann

Okay. And with that said, how come we’re not seeing kind of a similar increase in Eastern PJM volumes then?

Rob Gaudette

This is, Rob Gaudette. The way to think about when we’re talking about volumes in MISO versus East, think about the relative pricing of each of the coal units that sits in the portfolio, so if you think about MISO coal units versus our Mid-Atlantic coal units. We have some very efficient close to the money in ‘12 or in the money coal units in the East where some of our MISO units have higher costs than West controls or higher cost fuel or less efficient heat rates and so they are further out of the money. When you get small step changes in the energy that dramatically increases the megawatt hours produced, half of the unit that would might have been out of the money, does that make sense to you?

Operator

Thank you. Our next question is from the line of Ali Agha with SunTrust. Please state your question.

Ali Agha - Suntrust Robinson Humphrey

Ed, question for you, in your opening remarks, you laid out some fairly significant positive developments that have happened since the last call, CSAPR got delayed, MATS rules were firmed up. And yet your stock has continued to slide over that period as well. So I just wanted to get your perspective, I mean, is the pure play merchant model just not being valued in the public equity markets. I mean what’s your thinking, and if so, how do you think about maximizing shareholder value in a market that doesn’t seem to giving any value for your assets and these positive developments?

Ed Muller

Well my expertise is in running the business, not in figuring out how the stock is traded by various people, we obviously would like to stock and we always like this to be trading higher. I think in general there is a concern that the natural gas prices which are at low that we haven’t seen for a longtime that there is a lot gas in the market and we’ve had a very warm winter is affecting how people think about power prices.

Ali Agha - Suntrust Robinson Humphrey

But as the CEO and looking at maximizing shareholder value, do you believe the retirements and the hunger down approach is the way to go or is that something else that needs to be done here to make the market realize, that is more value to these assets than weighed out there?

Ed Muller

Well I think running our business well, investing our capital so that we exceed our cost of capital on each investment. Well, although ultimately and should deliver the value. I’ve heard now several times both from you and others on this call the term hunker down, I don’t think that’s the right term. We are well placed with the refinancing of the company that we did when we did the merger in the late ‘10 to comfortably move through the current cycle. And we’re not in hunker down mode, we are running our business thoughtfully, none of the decisions that we made on deactivations were for lack of capital, they were all made based on an assessment of whether it was appropriate to invest more capital.

Ali Agha - Suntrust Robinson Humphrey

Okay and I guess I mean just looking at the portfolio and as you’ve mentioned to us in many of your calls I mean based on your analysis, you don’t have any excess liquidity currently in the business, but is there a size issue or some other issue that would cause a more efficient use of the balance sheet, sitting on 1.6 billion of cash is obviously not the most efficient use of that cash. I understand your point about the stress case and what have you, but is there another way to free up that cash I mean maybe bigger is better I mean what’s your thoughts about that?

Ed Muller

Well, if by bigger is better, Ali you mean are there more opportunities to do what we did when we created GenOn and have the savings, which are significant if you put whatever multiple you want on $160 million you’d say a lot of value. Are there more such opportunities, perhaps I think it is just difficult when you look at the number of players in this industry. It’s not as this there are 20 companies just like GenOn out there. So, it’s possible. But I think given the number of players it is more difficult.

Ali Agha - Suntrust Robinson Humphrey

I guess one last question. As far as your hedging is concern, has there been a material change since the month or so since January 24th?

Ed Muller

We’re only giving data as of January 24th, but as I said, the pattern that we described and if you look at that chart, particularly for our base load coal has been and will remain consistent.

Operator

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

Mark Barnett - Morningstar

Just real quickly, you’ve mentioned obviously the CSAPR is not incorporated and your EBITDA forecast. So, correct me if I’m wrong here, but I’m assuming it’s not at all contemplated when you’re looking at your shutdowns and closure projections as well?

Ed Muller

When we thought of win CSAPR was enforced or is expected to be enforced. We of course took it into account, but our thinking in general was that the impact of CSAPR on our fleet was pretty well dissipated once MATS came into force in 2015. And for the investments that we have contemplated, both making and the ones we’ve decided to make and the one’s we’ve decided not to make, we are looking long-term. So, the CSAPR piece while it’s there is near-term. And so, it’s not all that significant in terms of the investments.

Mark Barnett - Morningstar

Okay. And you had given maybe a number around the Shawville unit, but for the plants, do you expect you to retire in ‘15, do you have at this point kind of a rough estimate of your one-time costs and what’s your projection for 2012, which I think was somewhere around 25 to 26 million?

Ed Muller

Bill, have we disclosed this.

Bill Holden III

Yes. We haven’t given any guidance for ‘15. So, we are not ready to provide that yet.

Mark Barnett - Morningstar

Okay, understandable. I guess, it’s all right, just one last quick big picture question. Given the shift in dispatch dynamics and kind of resulting decline so far and demand for coal, do you expect to see any improvement in your transportation costs at all or is that something that is not that sensitive?

Ed Muller

Rob?

Rob Gaudette

Sure. In the past, coal transporter so the railroads, all right, they tend to take account for market conditions. And they’re going to want to fill the rails with our coal or they want to run their trains so that they can make money. So, as we go through the re-contracting or renegotiations with our primary movers, we would expect to see some of that. I would caution you to note though, it’s a big part of what everybody pays as far as transport for coal includes fuel adjustments. And our fuel adjustments are driven in most cases by crude oil. And so, while we may get some consideration out of the railroads based on lack of exports on coal now, lower economic demand for rail transport, price of oil are still over $100, so we’ll hear about that. But it’s a negotiation, it typically they take everything into account and I would expect that we should see some view out of these guys that they want our business. That helps?

Operator

Thank you. Our next question is from the line of Steven Burd of Morgan Stanley. Please proceed with your question.

Steven Burd - Morgan Stanley

In this update mentioned that the environmental CapEx that you’re forecasting is somewhat higher than on the last earnings call. Could you just talk a little bit about what’s changing your mind to make more that CapEx more economic related to the last call we had.

Ed Muller

Sure. I described earlier the analysis we do and we continue to do. And, in the course of doing that analysis, we found that some more of our units gas fired units in New Jersey would justify putting on SCRs. And so the difference was simply our analysis, earlier we have not thought, they would make the cut and they did make the cut.

Steven Burd - Morgan Stanley

Understood. And, just given since the last early update on energy and margins are generally on the energy side did not, there has not been an uptick. I presume that would be more focused on capacity views just as I look at it since the last quarter, we haven’t had much from positive developments on the energy side.

Ed Muller

I understand that we’re looking at all the factors and we are constantly taking all of the data in the markets, so I would caution against grabbing it, looking for one data plant that moves things. We have a capacity auction coming up in May and is enough on some of these sales what will ‘15, ‘16 clear, that’s unlikely to be at. We see these investments are going to have long life and we have to use our best judgment in modeling those to say is the investment over its life go on a more than our earned cost of capital.

Dennis Barber

Rob this is Dennis. I think we have time for probably couple of more questions.

Operator

Okay sir. The next question will be coming from the line of Ted Durbin of Goldman Sachs. Please state your question.

Ted Durbin - Goldman Sachs

Thanks. Most of my questions have been answered. I just wanted to ask a little bit about how much you are cycling your plants right now, kind of on and off peak, how are you thinking about that in terms of the volume impact given where the forwards and the spot market is and then how should we think about the cost impacts of essentially cycling?

Ed Muller

Rob do you want to take?

Rob Gaudette

Sure. So let me make sure that I’ve got your questions. The first is it how we’re running the units and then the second piece is how we account for those costs, correct?

Ted Durbin - Goldman Sachs

That’s right.

Rob Gaudette

Okay, so let’s start with how we run the units. Recall I’ve got a portfolio of coal and I’ve got a big CCGT in PJM, I’m going to focus on PJM if you want to talk about another market please ask me, but let’s focus on PJM for now. We got a list of units, and we go from deep in the money to out of the money coal units, what we’ve seen over the last several months is that our deep in the money units have become less in the money as you’ve seen natural gas drop. And then our units that were on the margin are now out.

The way PJM has been we bid in our units, we bid demand for their costs, we also bid in a market-based approach to each of the units so we submit two bids per unit. And if it’s needed for reliability then PJM falls back on their cost based bid. Inside that cost based bid is fuels, DOM any start up cost if possible and then there is some additional stuff for the wear and tear on the units. What we have seen on a coal unit is that they are not getting cycled around in the worst case scenario where you think that it’s moving around 100 megawatts every hour. We see that they are on for full load on the ramps and then we typically have seen them down in near men’s in the shorter period, the least exciting part of the curve. Most coal units have a 24-hour men so they are on for that whole time. So, we try to minimize shutdowns. The normal damage of shutting the unit down is the most important piece that we have to take into account.

On our gas side we’ve seen incredible amounts of run times out of unites like our Hunterstown CCGT. The unit sale of capacity factory in the 40s, up near 75% over the last quarter. So, the unit is running hard their designed cycle. So, but it’s been running – given its economics, it’s been running a lot harder than our coal units. Does that answer the first part.

Ted Durbin - Goldman Sachs

Yes, that’s actually really helpful.

Rob Gaudette

So, on the second part, all of our guidance and all of our the way we look at, what are costs are going to be around our units? Both long-term so in the projections you see in front of you as well as short-term so in my bidding decisions, take into account the wear and tear on the unit. So, the projections you see we’ve looked forward in the market. We see what the prices look like, we see what our expected runs on these units. They are going to look like to include starts and stops. And then I work with our operations group to establish what the operating costs that are going to go with that to ensure that we have reliability of what we projected. So, we account for that in the long-term in these numbers. In the short-term I account for cost for wear and tear on units. In my shutdown and start up decisions around the unit, does that help you?

Ted Durbin - Goldman Sachs

It’s very helpful. I guess would you say on a variable cost. I mean, can you put a number on it, is a dollar per megawatt hour higher kind of the way they are running now, can put any numbers around it?

Rob Gaudette

I opt to not.

Ted Durbin - Goldman Sachs

Okay. That actually is very helpful. Thank you. And then my other question I think I’m not sure it is answered, but on the $80 million of O&M, how much of that reduction is fixed costs versus variable cost on the shutdowns?

Ed Muller

I don’t think we have that breakdown.

Rob Gaudette

No, but it’s going to be largely fixed cost.

Operator

Thank you. Our next question is from the line of David Frank with Catapult Partners. Please proceed with your question.

David Frank - Catapult Partners

Real quick question, prior to your announcement today to shutdown capacity and there is speculation in the market that adds the capacity prices could clear at the cap. Can you share with us the odds that you believe that (inaudible) clear the cap those with your capacity in clearing and what’s this new announcement of that capacity would be retired?

Ed Muller

Yes, I think given that we are in fact a participant in this market and think it very important is that the biding process be as pure as the driven snow. I don’t want to share any of our thinking on how we think things will clear.

Operator

Thank you. (Operator Instructions) And next from the line of Tom Rebinoff with Tom Rebinoff Research. Please state your question. Mr. Rebinoff your line is open for question.

Tom Rebinoff - Tom Rebinoff Research

I wanted to go back to the kind of gas to coal switching question a little bit and I think, you largely addressed that, but I wanted to get a little bit more color in terms of I don’t know if you can provide this, but on average, what were the capacity factors, let’s say for your coal plants in PJM, this past quarter may be versus Q3. And then as you think about your projections going forward, what were some of the assumptions that you made around volumes and capacity factors. Because I think from my perspective, I mean, it’s a little bit easier to kind of figure out what the forward curves are and then obviously sensitize those, but as far as volumes are concerned, it’s just a little bit more difficult and obviously Calpine and some other competitors over there, have put out numbers pretty interesting in terms of obviously the capacity factors from there CCGT is being very, very high. So, again I’m kind of curious is to what the impact is on the coal facilities in those markets?

Ed Muller

Bill, can you?

Bill Holden III

Yes. I don’t think we have capacity factors by units broken out. The best thing we have is the generation and the appendix from the different types of units.

Tom Rebinoff - Tom Rebinoff Research

But so then maybe just kind of general color on what you’re seeing and what the expectations are going forward would be helpful as well?

Ed Muller

Rob?

Rob Gaudette

So to follow-up on our discussion a couple of questions ago. What we’re seeing is given the price of natural gas, you’re seeing CCGTs six months ago, a year ago, two years ago were 5 to $10 of the money, now at the money or setting price, right. So, those guys are running considerably more than they have in the past. The capacity factors are probably going up 20, 25% that’s rough that is not well I’m just saying that’s what I would guess across the industry. On the coal side, are you deep in the many coal units? You are seeing a less run time out of them, we’re seeing less runtime out of them. However, a lot of the units that were three months, six months ago out of the money just became further out of the money, so they’re just not running. I don’t know how much more color I could give you there comfortably without having numbers in front of me.

Tom Rebinoff - Tom Rebinoff Research

Got it. And so maybe question is kind of going forward is you think about your projections and your guidance just very broadly speaking, was the assumption that this trend is here to stay or you guys did you change that like how should we think about that?

Bill Holden III

This is Bill. I will take this out and then Rob you can fill in. When we look at the guidance, we’re using forward commodity prices at January 24th for ‘12 and ‘13. So, that is the basis for the dispatch assumptions and then the operating profile and the guidance that we’ve given. So, to the extent you see prices moving, it will affect the dispatch of the plants.

Tom Rebinoff - Tom Rebinoff Research

Got it, okay. And may be the other question real quick is, on page 13, on the working capital and other changes just comparing that number in 2012 versus what you showed us back in Q3, it seems like that number went up. Could you provide a little bit more color on what’s driving that?

Bill Holden III

Yes. The change I think from Q3 was $79 million for 2012, the biggest pieces there is the 32 million that comes back from on Potomac River closes. We’ve moved that out of working capital into investing activity and that’s consistent with the way it will be accounted. And then the other one is we have deactivation costs for Niles and Elrama that are excluded from adjusted EBITDA of 21 million, that’s also in that caption. And then there is a bunch of other miscellaneous items.

Operator

Thank you. Ladies and gentlemen, we’ve reached the end of our allotted time for question-and-answers today. I would like to turn the floor back to Mr. Barber for closing comments.

Dennis Barber

Thanks, Rob and thank all of you for participating in our call this morning. A replay of this webcast will be available in approximately two hours. Have a great day.

Operator

This concludes today’s teleconference. You may disconnect your lines at this time and thank you for your participation.

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