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Executives

Dennis Barber – VP, IR

Mark Jacobs – President and CEO

Rick Dobson – EVP and CFO

Analysts

Dan Eggers – Credit Suisse

Brian Chin – Citigroup

Michael Lapides – Goldman Sachs

Brandon Blossman – Tudor, Pickering, Holt & Co.

Mark Bishop – Boston Company

Julien Dumoulin-Smith – UBS

Lasan Johong – RBC Capital Markets

Neel Mitra – Simmons & Company

Ameet Thakkar – Bank of America

Nitin Dahiya – Nomura Securities

RRI Energy, Inc. (RRI) Q4 2009 Earnings Call Transcript February 25, 2010 11:00 AM ET

Operator

Welcome to the RRI Energy fourth quarter 2009 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, you may begin.

Dennis Barber

Good morning and welcome to RRI Energy's fourth quarter conference call. Leading the call this morning are Mark Jacobs, President and CEO; and Rick Dobson, our Chief Financial Officer. Following our prepared remarks, we'll have a question-and-answer session.

The earnings release as well as a slide presentation we're using today is available on our Website at www.rrienergy.com in the Investor Relations section. A replay of this call will also be available on our Website approximately two hours after the call. Consistent with our past practice, we're using several non-GAAP measures to provide additional insight into the operating results. Reconciliations of the non-GAAP measures to GAAP figures are available on the Website.

As many of you know, we update our outlook each quarter using forward commodity prices. The current outlook uses forward commodity prices as of February, 5th. I would also remind you that we do provide directional commodity sensitivities in the appendix of the presentation that can be helpful in adjusting the outlook based on your view of future commodity prices.

And finally I would remind you that any projections or forward-looking statements made on this call are subject to the cautionary statements on forward-looking information contained in our SEC filings.

I'll now turn it over to Mark.

Mark Jacobs

Thank you Dennis, and good morning everyone. Welcome to our fourth quarter earnings call. This morning, we released our full-year 2009 results, which are summarized on slide four. We reported open EBITDA of $185 million and adjusted EBITDA of $55 million for the year. Including discontinued operations, we were just above breakeven free cash flow.

2009 results reflect the challenging commodity price and economic environment we are operating within and the impact of our above market coal hedges. We also updated our 2010 outlook and initiated a 2011 outlook. For 2010, the outlook for open EBITDA is $367 million, adjusted EBITDA of $360 million, and free cash flow of $92 million. The 2010 outlook reflects some improvement over 2009 figures, but it still represents depressed gas coal spreads and challenging supply demand fundamentals.

The 2011 outlook for open EBITDA is $366 million, adjusted EBITDA of $309 million, and free cash flow of $110 million. Relative to 2010, the 2011 outlook reflects some modest improvement in forward gas coal spreads and lower expenses, offset by lower PJM capacity payments. At our investor conference last July, we outlined our strategic priorities.

On slide five, I wanted to update you on our progress. In light of the uncertainty in the current market environment, our primary focus is on managing risks. It is without question our highest priority. The bottom line is that we are in a position ending the year with approximately $1.6 billion of available liquidity, including nearly $1 billion of cash. During the second quarter, we completed the sale of the retail business. That transaction significantly reduced risks, most notably, the risk of nearly $3 billion of capital and contingent capital. In 2009, we implemented a modest forward hedging program for 2010 and 2011.

The hedging program is designed to provide a high degree of certainty of free cash flow breakeven or better even if market conditions substantially worsen. The balance of our output is unhedged, so that we will benefit when market conditions improve. We have also completed a number of actions to improve our core operations. During 2009, we added over $415 million in future forward capacity revenue, including about $220 million from PJM and $180 million from our California fleet.

As you know, capacity revenue represents a stable, invisible source of earnings and 2009 results represented outstanding progress. We realigned corporate support costs, a program that provides $40 million of annual benefits. We have completed our review of the stations in our fleet that have struggled to operate profitably in the current environment. Accordingly, we made significant changes in our approach at five stations; Elrama, New Castle, Niles, Avon Lake, and Indian River. The principal benefit of this approach is it both improves near-term economics and preserves the upside option if market conditions improve. We have reduced annual O&M spending for these five plants by $50 million from 2008 levels. These spending reductions are substantially higher than the roughly $10 million reduction in 2010 gross margin associated with the operating model changes based on current forward prices.

We continue to review this group for long-term viability. In that regard, I wanted to mention that in January, we mothballed the Indian River plant in Florida. You will recall that the plant had a PPA that expired at the end of 2009. In 2010, I expect that we will make a decision to either retire the plant or bring it back to service. Of particular note was the recent FPL and Progress rate cases at the Florida PUC. The practical outcome of these cases as it is likely that less new generation will be built in Florida. Consequently, Indian River may have a better opportunity to play overall in helping Floridians meet their long-term energy needs.

I also wanted to update you on our scrubber installation program. We completed the tie-in of the Keystone scrubber in November and it’s fully operational. In this spring, we will complete the tie-in at the scrubber at Cheswick. These two projects will provide for a significant reduction in SO2 emissions. Post-completion, about half of our coal-generated megawatt hours will come from scrub plants.

Stepping back from the details, we accomplished a lot since July and I wanted to acknowledge the efforts of the RRI team in that regard. Moving to slide six, as you know the industry is capital-intensive and cyclical. There is one certainty and that is that there will be uncertainty. That belief underlies our approach to managing the business.

Before I discuss the 2010 priorities and initiatives, I want to provide some perspective on a couple of factors that are shaking the environment in which we operate. Then, I will discuss the actions we are taking to manage in that environment. As you know, the two principal value drivers of our earnings are supply demand fundamentals and the gas coal spread. And environmental issues have a significant impact on each of these. With respect to supply demand fundamentals, we have started to see early signs of a demand recovery.

If you examine year-over-year electricity demand on a weather-adjusted basis, 2009 showed decreases in our principal markets by as much as 8% at points in time, and averaged out to a 3% to 5% decline for the year. More recently, the year-over-year data is showing very small increases albeit against easier comparisons. In the near and intermediate term, the pace of economic recovery will drive supply demand fundamentals. In the intermediate and longer term, demand response, renewal portfolio standards, and supply retirements will also shake supply demand fundamentals.

With respect to supply retirements, it’s the one factor I see that could bring supply demand balance back in line more quickly. There have been some early signs of supply rationalization as evidenced by recent plant retirement announcements. In the US, approximately 5,000 megawatts of coal generation is scheduled to retire over the next couple of years. Within PJM, a total of 2,600 megawatts of generation, 1,400 of which is coal are scheduled to be retired before the summer of 2012.

Looking beyond announced retirements, the current reserve margin in PJM is approximately 21%. When you dig beneath that figure, you will find that there are over 10,000 megawatts of uncontrolled coal units that are less than 200 megawatts in PJM. To put that into perspective, 7.5% of PJM’s total generation or over one-third of that reserve margin is represented by small, unscrubbed coal units.

In addition, PJM has another 7,800 megawatts of partially-controlled coal units that are less than 200 megawatts. Taken together, the group of coal units that are under 200 megawatts and are either uncontrolled or partially controlled represent 13% of total generation in PJM or over 60% of the reserve margin. I expected a significant portion of this group would be retired overtime.

Moving on to the gas coal spread, spot natural gas prices have rebounded from last fall. Importantly, at this level, we don’t expect widespread coal to gas switching that we saw in 2009 to repeat itself in 2010. Throughout much of 2009, supply outpaced demand with the result being a record storage fill and gas displacement of coal generation. However, since midyear 2009, production began to ease and demand started to recover.

In combination with the cold winter, storage excess has narrowed from above 400 Bcf to a level within sight of the five-year average. To be sure, this doesn’t necessarily point to a strong recovery in the natural gas market, the important point though is that the storage overhang is largely been removed and the supply demand picture is back in balance.

Looking ahead, shale gas will play an important role in natural gas prices. The speed with which new shale production can be brought online combined with shale decline rates means that gas production is likely to respond much more quickly to price signals than it historically has. To me, it argues that natural gas prices volatility will continue, but perhaps in a narrower range than of the last five years.

Regarding coal, in 2009, coal prices fell significantly from 2008 levels, as demand decreased due both to weak economy and the displacement of coal generation by gas generation. This led to record inventory of 200 million tons in December compared with a five-year average of 140 million tons. More recently, we have seen some strengthening in the coal markets. A pickup in med coal exports and some reduction in inventory levels is likely contributing to firming prices. But January inventories remained well above five-year averages. Like any other commodity, future coal prices will be driven by supply demand fundamentals. Forces that will impact coal demand include the export market, the pace and size of potential coal-fired power plant retirements, coal-to-gas generation switching, and the rate at which additional renewable are completed. The coal supply equation will be impacted by future environmental regulations, including changes in mountain top mining prices and increasing cost of production.

Now, let me bring this back together in terms of the gas coal spread. I see less of a correlation between gas and coal prices going forward. And this argues that we will see volatility in the gas coal spread going forward. Environmental laws and regulations will also shape our industry. A year ago, most would have predicted that Congress and the EPA would act quickly. Climate change legislation seemed a near certainty if not in 2009, then in 2010. But the political agenda may not have shifted as much as some thought it would.

Today, it seems far from certain that CO2 will be priced in the near or intermediate term, and the EPA is met-resistant in pursuing its agenda from multiple constituencies. As I reflect on these developments, I still expect tightening environmental rules and regulations overtime, but I think they will likely play out more slowly. Without question, our industry faces significant uncertainty in the near term, but longer term, the market will recover. Electricity is a basic commodity, it’s essential to daily life. As I look forward, I see significant challenges to adding new generation, and I believe that the majority of our fleet is well positioned to deliver long-term value.

With that as a backdrop, I want to discuss how we are managing the business in positioning RRI Energy on slide seven. Our focus is squarely on what we can control, how we operate the business, how we finance it, how we manage risk and how we position it to create long-term value. For 2010, we have developed a set of initiatives that are derived from the same strategic priorities we reviewed with you last summer. Our goal is to become the best operator of power plants in the industry, making sure that we capture every nickel of value out of our assets.

That’s what’s behind enterprise-wide execution excellence. We believe efficiency and effectiveness are the appropriate measuring sticks. We think the best measure for efficiency is the total cost per megawatt hour and the total cost per megawatt. In other words, how much did it cost us to produce the power we generated and deliver on our capacity commitments. In terms of effectiveness its total margin capture factor, or TMCF for short. TMCF is a measure of what percentage of the available margin we captured as measured against 100% plant availability. Our objective is to optimize the trade-off between spending levels and equipment performance. Importantly, every RRI Energy employee’s compensation is tied to these metrics.

Going forward, we will be reporting to you on our performance on these measures. Another component of enterprise-wide execution excellence is our focus on plant level business models, that reflect the uncertainty of the environment in which we operate. Earlier, I discussed the work we have done to develop flexible operating models at some of our stations. That work is particularly important when you consider the likely volatility and gas coal spreads. They are significant value to lowering our operating costs in periods of compressed spreads and at the same time having the ability to respond quickly to capture full value when spreads improve.

Effective risk management is another key element of execution excellence. In 2010, we will complete the implementation of improvements to our enterprise risk management system. You will recall that last fall, we conducted a comprehensive top to bottom assessment of our risk management with the assistance of a well-regarded third party. One tangible outgrowth of the risk management work is the free cash flow hedging program that we implemented last year. It’s one of the key elements of our strategy to maintain financial flexibility in light of the challenging and uncertain market environment.

We dynamically managed the hedging program. Our objective is to ensure that we deliver free cash flow positive results regardless of market conditions. Through the commodity price volatility to date, the hedging program has performed as we expected it would. In 2010, we will evaluate the hedges for 2012. As with the 2010 and 2011 program, the goal is to assure that we are free cash flow breakeven or better even if market conditions further deteriorate. At the same time, we want to keep the majority of our output unhedged, so that we will benefit when market conditions improve.

Turning to potential environmental investments, it’s an area that is highly uncertain. There are a number of factors that we will consider in ultimately determining which projects make sense to pursue. That list includes what future regulations are promulgated, what new laws are passed, the outlook for wholesale power markets, and the status of climate change legislation to name a few. At July’s Investor Conference, we provided a review of potential environmental upgrades that we are likely to consider overtime. As part of our ongoing commitment to provide transparency, our 10-K includes more information.

We are actively engaged with policymakers in helping to shape new environmental laws and regulations. However, as I mentioned earlier, those will likely play out over the next several years. The key point is that we will be looking for clarity on the rules before committing substantial capital to environmental projects. We remain a fragmented industry and I have discussed my expectations of industry consolidation overtime. RRI has a solid financial and asset foundation, but I believe size, scale and diversity matter in delivering shareholder value through the cycles. It’s our job to identify all of the avenues to achieve that objective in a manner that creates value.

I will now turn the call over to Rick Dobson, our Chief Financial Officer.

Rick Dobson

Thank you Mark. Let’s turn to slide nine. As Mark said, 2009 was a challenging year. We saw unit margins decline $16 per megawatt hour, driven by weak commodity prices and mild summer and early winter weather (inaudible) decline a 430 million in open energy margin year-over-year. PJM auction results for the period effecting calendar 2009 drove the increase in other margin of 58 million.

As we discussed at our last earnings call, our focus had been on achieving top-quartile equipment performance levels, which we did in 2008. With more gas coal spreads in 2009, we moved from a fleet-wide focus to a segmented approach, with operations and investments tailored to plant profitability and value. This change principally impacted two areas of performance in 2009.

We reduced operating and maintenance cost of $51 million, principally in the lower margin segments of our fleet. At this investment level, we also generated a lower commercial capacity factor performance, up 83.6% impacting 2009 margin by a modest negative $11 million. Our commercial capacity factor performance did come in lower than our projections. This performance shortfall occurred in both lower margin plants and fleet, while we significant reduced costs and at higher margin plants, we are not satisfied with the results in the higher margin plants and have either corrected deficiencies or plans to correct efficiencies in the future.

This will position us to be successful as coal gas spreads improve. In addition, our general and administrative and other expenses declined 19 million, as we aligned our business to a pure merchant generator platform. Cost efficiency in this area will also continue to be a major focal point. The combination of these factors resulted in $185 million of open EBITDA in 2009. 2009 coal purchase, prices above the market were partially offset by our above-market natural gas hedges, yielding adjusted EBITDA of $55 million. These same factors resulted in a use of free cash from operations of $327 million in 2009.

As Mark touched upon, factoring into cash flow from discontinued operations, we were about breakeven for 2009. Before I move on, I want to touch on something you will see when you review our GAAP financial statements. As many of you know, FASB Statement 144 requires cash for long-lived asset impairments. In the fourth quarter of this year, we had two such plants that failed this test and wanted a fair value review. This review resulted in impairments at our Indian River and New Castle plant of $211 million. In addition, you will recall from the July Investor Conference that these two plants were in the restore profit or marginal category.

Turning to slide 10, let me elaborate on some of our key operational measures that Mark just mentioned. Our cost efficiency measures are calculated by aggregating operations and maintenance costs, maintenance capital expenditures, and general and administrative expenses, excluding the REMA lease expense and dividing this total by the amount of megawatt hours generated or by the megawatts of total capacity. We have metrics on both a per-megawatt hour and on a per-megawatt of capacity basis, because we have plants that primarily earn capacity revenues and others that also produce material amounts of energy revenue.

Our 2009 total cost per megawatt hour measure was $28, with an expected decline to $20 in 2011. On a per megawatt basis, our targets for 2010 and 2011 are approximately 45,000 and 41,000 respectively. As Mark previously mentioned, TMCF is a measure of effectiveness. Our TMCF targets are 90.1% for 2010 and 92.2% for 2011. We focus on all of these measures at the plant level as we believe this is the optimal combination of performance metrics to tell us how close we are to maximizing the portfolio’s value irrespective of commodity prices.

Moving to slide 11, we retired nearly $540 million of long-term debt. This was primarily accomplished with $261 million of the proceeds from the sale of or retail operations, cash deployment of $127 million for open market purchases, and the execution of $129 million tender offer. With the retirement of the Orion notes in May 2010, our gross capital would be approximately $2.4 billion, about $700 million from the top of our targeted range.

In the near to medium term, we will put in a collateral-friendly hedge vehicle, extend our revolver and continuing to focus on reducing our working capital. These initiatives combined with some of the cash on our balance sheet and a modest amount of free cash flow will allow us to move our debt into the $1.25 billion to $1.75 billion range. We believe the combination of a strong balance sheet and liquidity position, a solid capacity and PPA revenue profile, and our modest forward hedging program yields a sustainable platform to build long-term value for shareholders.

The commodity positions related to our hedge programs that Mark talked about are not materially different than what was discussed last quarter and are included in our appendix. Now, let’s move to our outlook on slide 12. Our curve date for this outlook is February 5th, 2010 versus our last outlook date of October 23rd, 2009. Since the last outlook, we have seen dark spread compression in the forward curve. This is primarily driven by $0.40 per MMBtu lower TETCO M3 gas prices and $2 per ton higher coal prices. Dark spread compression and off-peak coal heat rate declines are the primary drivers behind the $88 million decline in 2010 open EBITDA relative to our last outlook. These same energy commodity explanations combined with lower year-over-year RPM capacity margins are the main catalysts driving our 2011 open EBITDA results of $366 million.

Factoring in hedges and the expected 2010 Kern River settlement, our adjusted EBITDA for the 2010 and 2011 outlook is $360 million and $309 million. These adjusted EBITDA amounts drive free cash flows of $92 million and $110 million for the 2010 and 2011 time periods.

With that, let me turn it back to Mark to wrap up.

Mark Jacobs

Thanks Rick. Let me wrap up on slide 13. RRI Energy is a well-positioned wholesale power company. While current conditions are depressed, the market will eventually recover, but the timing of the recovery is uncertain and market conditions may remain challenging for some time. Our approach is simple. We are prepared for the first, and we are positioned to benefit when the market recovers. We have taken a number of steps to lower our risk profile, and we have taken actions to improve the performance and value of the business in these depressed market conditions.

At the same time, we have recognized that our business is highly leveraged to a commodity price and economic recovery. It’s the fundamental value proposition in any merchant power stock, and it’s our job to make sure that the company is positioned, so that our shareholders benefit from a recovery when it happens.

With that, operator, let’s open the line for questions.

Question-and-Answer Session

Operator

Thank you. (Operator instructions) The first question is from Dan Eggers from Credit Suisse. Please go ahead.

Dan Eggers – Credit Suisse

Mark, I was wondering if you could just share a little more thought on the idea of gas prices and coal prices not moving together as tightly at various points in time. How are you going to – does that affect how you guys are thinking about hedging, both forward power sales and the fuel that goes alongside of it?

Mark Jacobs

Dan, it’s a good question, and you know, as we have observed the – you know, historically you had a coal market where coal prices were generally pretty flat and the gas coal spread was driven largely by increasing or decreasing natural gas prices and there was a, to a lesser degree, coal followed that. You know, as we have observed the market and studied the fundamentals in coal, there is still some correlation in there, but my sense is that going forward, we may see periods prospectively where there is not a strong correlation as we have historically seen. So, you know, let me bring that back to what does that mean for us, you know, as we think about that, I think we are likely to see more volatility in that gas coal spread here. I think some of the changes that we have implemented here is really making sure that our marginal coal fleets that are really impacted by that gas coal spread are prepared to respond quickly to changes in the market and it also does play into the, you know, I think the hedging types of scenarios that we look at. I would say philosophically, our approach on the hedging as we have described is to make sure that we do enough of that, so that even in a very depressed downside scenario that we are generating free cash flow breakeven. So, you know, looking at different coal gas spreads here certainly gets into that analysis and the different types of scenarios that we run.

Dan Eggers – Credit Suisse

I guess you've had, along those lines, you talked about the total margin capture factor of moving that higher as a way to capture more economics. You know, what is your view on the operating cost and capital costs associated to hit those targets? And is there any kind of framework we could think about as far as – or any sensitivity to every 100 basis points improvement in that measure?

Mark Jacobs

Yes, that’s a good question. And that’s going to be market dependent, and I would say if you think about the total margin capture factor, I would say that’s really taking the commercial capacity factor concept we introduced several years ago to the next level. One of the shortcomings in the commercial capacity factor is that it treats every megawatt hour the same and just calculates where we are available, where we are not available to run in the hours where the plants were in the money. So, it would treat a shoulder period from New Castle the same as a peak hour from Seward in the middle of the summer. And one of the things that total margin capture factor does is it really value normalizes all of that. So, it looks at the pool of available margin that we could capture. And so, you know, one of the things while the CCF performance in 2009 was less than 2008, when you look at the slide that Rick went through on slide 10 and looked at the total margin capture factor, we were essentially flat year-on-year. And I think what that shows as I said is that, the team did it. Good job instead of capturing more of that value from the higher margin plants. And that’s really how we think about the trade-off of, you know, there’s an available pool of margin that we are able to capture.

If you look at today’s figures again, depressed commodity prices, when we are looking at a gross margin in the billion dollar range, every percentage point in that TMCF is going to be worth about $10 million to us is a way to think about that. And then the cost piece that you raise again, that’s really as I said, we think the other end of the equation is because of the way we get higher total margin capture factor as we just spend indiscriminately, you know, we are really not making that good trade-offs. So, that’s really at the intersection of how we think about trying to manage each of our plants as that trade-off between spending levels and what we are able to deliver from a total margin capture factor. And you know, you see some – in the forecast numbers, you are going to see some expected improvements in the total cost per megawatt hour. I will tell you that 2010 is driven principally by, you know, the forward curves would indicate higher levels of generation megawatt hours and then in 2011, you are going to see that being driven more by a step down in expenses.

Dan Eggers – Credit Suisse

So, the assumption should be that you – with the forwards, as you see them today, you guys are going to see the coal plants run more this year than last year?

Mark Jacobs

That’s what’s implied by the forward curves, and you know, I think gas prices today are at a level where we would not expect to see nearly the coal-to-gas switching that we saw in 2009, and again, that based on the forward curves today. So, when we run that, that will imply a level of generation that you will see as you go back through the details of the outlook, a level of generation that is significantly higher than what we saw in 2009.

Operator

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

Brian Chin – Citigroup

Hi. Good morning.

Mark Jacobs

Hi.

Brian Chin – Citigroup

For your 2011 outlook, did you include any capacity revenues from the three plants that are in FirstEnergy's territory that are going to be going into the transitional auctions in about a month?

Mark Jacobs

Brian, we did not. What we have got in there is about $10 million of capacity revenue from MISO, and just to bring others up to speed that may not be as close to the details of this as you are, there will be the week of March 15th a catch-up auction for planning your 2011 and 2012. Now, that only impacts the three plants that we have that are moving to PJM as part of the FirstEnergy transition. So, we will – ultimately what’s going to happen is we are going to give up that $10 million of capacity revenue in MISO and we will get whatever that the planning auction clears at, just to put some, you know, numbers around that. If you take the prices from the last auction of $16 a megawatt a day in RTO, the plants would earn about 7 million a capacity. So, it would be a $3 million deduct. At $55 a megawatt a day, it would be 24 million, so it would be 14 positive, but as I said we will have the results of that here in another couple of weeks.

Brian Chin – Citigroup

Great, thanks a lot.

Operator

The next question is from Michael Lapides from Goldman Sachs. Please go ahead.

Michael Lapides – Goldman Sachs

Hi guys. When you look at your gas plant portfolio outside of PJM, what's kind of your latest thinking in terms of monetizing that somehow, whether it be divestitures, whether it be PPAs to utilities if they need any of the capacity, and whether you strategically think you are kind of the right strategic owner of those assets?

Mark Jacobs

Michael, let me break that down into two pieces. You know, as we have described before, our principal focus as the company is on competitive markets, we think that’s our real power alley in terms of operating assets in competitive markets. And so, you know, if you set aside PJM for a second, we have got some gas plants out in California that we think that we are very comfortable in that. I think California has taken some positive steps towards capacity markets ultimately here, you know, we are still ways away from that. So, we are very comfortable operating that. I would say when you get down to the other regions of Florida and Mississippi, those are markets that aren’t nearly as far along to a competitive model and it’s not clear that they are going to move further along to that. And you know, as you saw with the Big Horn plant that we sold in 2008, I think if there was an opportunity to monetize those plants, we would so. But I recognize, you know, in today’s market conditions, things are pretty challenging. So, I wouldn’t as I said, that’s not something I necessarily see as a near-term opportunity for us, but I think longer term, we would like to have the focus of the company where we have got good competitive markets.

Michael Lapides – Goldman Sachs

Okay. And a follow-up – thinking about the Orion a little bit, I mean a lot of the Orion plants are unscrubbed when you kind of go through your list of units that have scrubbers and those that don't. Is there any thought about some kind of – in terms of rethinking whether you just write a check for the debt maturity at Orion or whether there is any other alternative there?

Mark Jacobs

I think what you are speaking to is that those plants are down in that corporate entity. You know as we look at that on a long-term, we have looked at that on a long-term value basis, we are strongly of the view that the value of those plants significantly exceeds the debt levels we have on there.

Rick Dobson

Cheswick and Elrama basically are primarily controlled at this point. But you make a good point. Avon Lake, New Castle, Niles, and Bruno – Bruno is a gas plant obviously, they sit under that thing too, but Mark’s exactly right. Lot of value in the scrub part of that portfolio alone. So, I see us marching towards a retirement of those notes, but still what we follow the prospects of the market day by day, but right now, our base plan is still to retire the notes and moves towards our target cap structure.

Operator

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

Brandon Blossman – Tudor, Pickering, Holt & Co.

Good morning guys.

Mark Jacobs

Good morning Brandon.

Brandon Blossman – Tudor, Pickering, Holt & Co.

Let's see. Just general thoughts on the next PJM auction, a little bit of changes around the edges to that structure. Do you guys have any thoughts or hopes as we go towards May?

Mark Jacobs

Well, Brandon, as I mentioned, there is a couple of changes in that auction that have or that are scheduled. One is the removal of the offered cap on existing demand resource. As you may recall that in the last auction, existing demand response was a price taker in that auction. So, effectively they did in at zero. The inclusion of the FirstEnergy load in the auction, when you consider both the generation and the load coming over, that’s going to, there’s a little bit more load than generation. So, that should tighten things up a little bit. And then you have some other things like the adjustment or the increase in the cone rates for that. So, we are all that shakes out, we are going to have to wait and see. I don’t want to get into the prediction of business there, but you know, certainly, when you look at the history of the cleared prices, the result we got from the last auction particularly in RTO was a – sticks out certainly as an outlier on the load side.

Brandon Blossman – Tudor, Pickering, Holt & Co.

Fair enough. The collateral structure – can you tie that to I guess one, timing, and then, two, tie it to your cash flow breakeven hedge strategy and why you would need $1 billion of collateral capacity?

Rick Dobson

Brandon, it’s Rick. The collateral structure, when you think about free cash flow breakeven, it would be something that would be necessary post the middle of 2012 as the revolver matures at that point in time. $1 billion is I guess I would call aspiration. I think something over $500 million would be a minimum for free cash flow hedging, but if we think about doing, as I said and as Mark said, we think about in the near to medium term, we will gain clarity on the revolver and its extension as well as then marrying that with a collateral-friendly vehicle so that as we move beyond June of ’12, we have facilities that are there for hedging the part of our portfolio to keep us in the free cash flow breakeven or better category. I don’t have an exact timetable for that right now, but it’s something that we are targeting for 2010.

Brandon Blossman – Tudor, Pickering, Holt & Co.

So both rolling the revolver and a $1 billion collateral structure for '10 for timing?

Rick Dobson

That’s our goal right now, yes, market permitting.

Brandon Blossman – Tudor, Pickering, Holt & Co.

Okay. And assuming that, that collateral structure was in place, we would see open market debt buyback or is it something other than that with available cash?

Mark Jacobs

Well, Brandon, yes, one of the things that we talked about it on Investor Conference the last summer is that you know, we have substantial cash balances on the balance sheet. That gives us a lot of comfort from a liquidity standpoint in managing risk in this capital market environment. You know, as I look longer term, it’s not a terribly efficient use of capital to have that much tied up in cash, and we did do some debt reduction in 2009, but I think as Rick described, when we completed the last tender offer, we are really not looking other than the Orion notes to deploy more cash until we get resolution on the revolver and the collateral facility, because that cash right now is kind of set aside if you will as the contingency just in case as I said, we don’t make the progress that we hope and expect to make on those two fronts.

Operator

The next question is from Mark Bishop from the Boston Company. Please go ahead.

Mark Bishop – Boston Company

Hi, I just have a question about assuming it's on page 11, I guess you were just struggling with that page. If I am reading this right, it looks like your target in the long-term is like $1.250 billion to $1.750 billion of gross debt, so let's call it $1.5 billion. On the other side, you have liquidity, but I am just trying to get to your cash flow so I can get to your net debt. It looks like your cash would be like $250 million, so your net debt you are contemplating – if you weren't using these other things, a low as liquidity, your net debt would be like $1.25 billion, plus any other stuff that you might use, like if you use some of this revolver stuff and all of that. I was wondering, do you show net debt forecast somewhere? Because I thought the debt was more like $675 million in the out years. And that's like $3 a share difference from what I was expecting on an enterprise value basis. So, I was just wondering if I got that outlook wrong somehow.

Mark Jacobs

Yes. Mark, if you look at, we ended 2009 with about $2.8 billion of gross debt and that includes the off-balance sheet REMA lease facility. We also ended with cash just under $1 billion. So, if you did a net debt calculation, we would be at about $1.7 billion to $1.8 billion of net debt. So, really right at the top of the debt range that Rick talked about. Again, we described that target range as one of gross debt target range, and clearly part of how we expect to get there is the redeployment of some of that cash on the balance sheet to reduce debt levels.

Mark Bishop – Boston Company

Right. So your target is for net debt is more like $1.25 billion or something, eventually, or is it higher than that because you're going to use some of this collateral stuff (inaudible)?

Rick Dobson

That’s right. Longer term, we would expect to have cash on the balance sheet of around $250 million. So, if you use your midpoint, you can just use that $1.5 billion for gross debt, you would have long-term net debt of about $1.25 billion using the midpoint on the target range of gross debt.

Operator

The next question is from Julien Dumoulin-Smith from UBS. Please go ahead.

Julien Dumoulin-Smith – UBS

Hi, good morning. Most of my questions have been already answered, but looking specifically at the upcoming – at the auctions, what are you guys anticipating there? Because, again, going back to a prior comment you guys made, you suggested that the FirstEnergy load is greater than at least the amount of generation within that zone being added to the upcoming May auction. Any incremental flavor as far as the transition auctions go as to where they come out?

Mark Jacobs

Well, I think the transition auction, you know, there is going to be a small amount of load and a small amount of generation that bids into that. So, I am not sure that I would interpolate a whole lot from those catch-up auctions to what that implies for the planning year 2013 auction that will take place in May. And again, I went through some of the factors. There’s a few rule changes that go into that, or will go into the 2013 planning year auction that are going to have some impact on prices, but you know, I really would like to stay away from trying to predict where prices are going to come out in that auction.

Julien Dumoulin-Smith – UBS

All right. Fair enough. I mean, if you could give at least sort of a sense, do think it would be sizably different from where those respective years placed for the RTO in those transition periods?

Mark Jacobs

Yes, and again, you know, one of the comments I made when you look at the RTO results by year, you will see a whole lot of variation. There have been years where PJM cleared all of their notes, constrained zones, they cleared in everything, cleared at the same price across zones. You know, when I look back at the results, the auction that happened last May – I am sorry, the RTO cleared at a level that really sticks out as kind of a low point on the scale. Some of that I think had to do with some of the ways that the rules were implemented. But you know, to be fair also, some of that resulted I think from additional demand responses come into the auction.

Julien Dumoulin-Smith – UBS

All right, great. Really appreciate the time. Talk to you guys soon.

Operator

The next question is from Lasan Johong from RBC Capital Markets. Please go ahead.

Lasan Johong – RBC Capital Markets

Thank you. Good morning, everybody. I have a couple of quick questions. First of all, Mark, one of the whole premise of Reliant is to try and capitalize on weak markets and make some asset purchases and/or corporate purchases. There's one company out there in particular that has got $2 billion of cash on their balance sheet, which is greater than their market cap. Any thoughts on why you would not deploy your significant cash and liquidity position to do something like that?

Mark Jacobs

Well, Lasan, as I have mentioned, I think we have got a solid foundation of assets, but I do believe that size, scale and diversity are going to be important long-term value drivers. You know, I think we are going to see the industry consolidate overtime, I think it’s a question as to when. And when I look back, I think there have been a number of impediments to M&A activity over the last 18 months, you know, notably the rating agencies I think view on the merchant power sector. I think the change of control debt provisions that most of the merchants have and I think refinancing markets to name a fewer, some of the things that have been impediments at M&A activity. Arguably I think you are seeing some of those abate. We certainly took notice of the FirstEnergy Allegheny announcement, but I think it remains to be seen if that’s an isolated instance or whether that really represents a new paradigm in seeing more M&A activity. I will tell you that we are very focused as a company on looking at all of the possible ways in terms of how we could participate in the industry consolidation and again our real focus is how can we create value for shareholders through consolidation.

Lasan Johong – RBC Capital Markets

Okay, good enough. A technical question for Rick. I was confused as to whether the efficiency measure total costs, dollars per megawatt hour and dollars – and thousands dollars per megawatt were two separate measures or they were the same thing looked at different ways? Is one variable and one fixed costs, or is it just this total cost, one divided by megawatt hours, one divided by megawatts?

Rick Dobson

The numerators are same in both, and then so, there are different ways at looking at the total cost of the business.

Lasan Johong – RBC Capital Markets

Got you. Any chance you could give me a breakout between fixed and variable costs, percentage-wise?

Rick Dobson

You know what we can do is give Dennis and Monica a call and they will get you that detail.

Lasan Johong – RBC Capital Markets

Great, thank you.

Operator

The next question is from Neel Mitra from Simmons & Company. Please go ahead.

Neel Mitra – Simmons & Company

Hi, good morning.

Rick Dobson

Good morning Neel.

Neel Mitra – Simmons & Company

How do you expect the trail transmission line to impact the plant to PJM West hub bases in 2011? And is any of that uplift embedded in your guidance on Page 17?

Mark Jacobs

Yes, Neel, the short answer on the guidance is we take the forward curves and we use that as the basis for developing the outlook, and you know, to the extent that, that’s baked into the forward curve. It would incorporate it. To the extent it's not, it wouldn't. And so, I can’t tell you exactly what the market has baked in there. I will tell you just directionally that as you know there is, our transmission constraints in moving generation from west to east across PJM in general, power prices are higher in the eastern part of PJM. So, transmission that helps release some of that congestion is going to have the effect of increasing prices in the western part of PJM and lowering prices in the eastern part of PJM. You know, when you look at our fleet, we have got probably weighted 5 or 6 to 1 west versus east. So, we would see more benefit from a bigger part of our portfolio with additional transmission upgrades and we would see a decrement from the plants that are on the eastern side of the constraint.

Neel Mitra – Simmons & Company

Just from your internal transmission models, can you in any way quantify what you think the dollar per megawatt hour uplift is around-the-clock, not necessarily from the forwards, but just in your view?

Mark Jacobs

Yes, I am not – as I said, I don’t have that information at my fingertips, and again, there’s a lot of what ifs that would go into that analysis again. I think I would rather keep the comment just at a higher general level it’s going to be a positive.

Operator

The next question is from Ameet Thakkar from Bank of America. Please go ahead.

Ameet Thakkar – Bank of America

Hi guys.

Mark Jacobs

Good morning Ameet.

Ameet Thakkar – Bank of America

Good morning. How are you? Just a quick question on I guess the generation volumes that you guys are showing on Slide 18 from today's presentation versus what you guys shared with us on the third quarter presentation. It looks to me that you are kind of assuming an additional terawatt hour of dispatch from the coal units versus what you showed back in October or November, and yet, it kind of looks like dark spreads have actually gone down. What's driving that?

Mark Jacobs

Yes, again, I think if you come back to, we take the forward curves and run that through a dispatch model and you know, coming out of that, the terawatt hour volumes comes out, I think the principal thing I would point to is the coal to gas displacement that we saw in 2009 had a meaningful impact on our generation volumes, particularly the marginal coal plants. We also saw that in a pickup in the generation volume from Hunterstown, which is our combined cycle plant in Pennsylvania. So, you know, as I mentioned if these four levels, even though they are compressed from what the forward curves were prospectively, they are still a gas coal spread is north of lot of what we saw during 2009. So, that would be the principal drivers, just less coal-to-gas switching.

Ameet Thakkar – Bank of America

Okay. And then real quick and just kind of a follow up on Dan's question earlier in the Q&A, you mentioned, Mark, you see less correlation between coal and gas prices when you look at fundamentals. What sort of variables are you kind of looking at to kind of make that determination?

Mark Jacobs

Yes, again, you know, let me go back to the factors that are driving coal demand. Well, gas prices are part of it, you have got a growing international export market for coal, you know, on the supply side. The coal industry has been subject to increasing environmental regulation. There is a lot of pressure of mountain top mining practices and whether that continues or not, I think remains an open question here. I think you also have factors how much and how fast we see some of the more marginal coal plants industry-wide retire. It is going to have a big impact on the coal markets. So, there is a lot of dynamics that are driving coal prices that aren’t pure natural gas price driven, and so that’s where I really see that as I said the prospect for reduced correlation going forward. You have a lot more independent factors I see that are going to drive some of the coal supply demand fundamentals.

Dennis Barber

Sandra, I think we have time for one more question.

Operator

Thank you. Our last question is from Nitin Dahiya from Nomura Securities. Please go ahead.

Nitin Dahiya – Nomura Securities

Good morning.

Mark Jacobs

Good morning.

Nitin Dahiya – Nomura Securities

In terms of the comments around addressing the revolver maturity and everything, is that something that you are actively engaged in now or is that something you want to kind of look at next year?

Rick Dobson

Hi, Nitin, it’s Rick.

Nitin Dahiya – Nomura Securities

Hi Rick.

Rick Dobson

We maintain precluded contact with our large relationship banks. So, it’s hard for me to say that we are in active negotiations to move forward than that. But what I am telling you from a broad brush perspective, it’s a focus to get that done in 2010. That’s the collateral vehicle and the revolver, marketing permitting.

Nitin Dahiya – Nomura Securities

Okay, fair enough. And the second part of that, Rick, is, now, you were obviously buying the secured earlier for covenant purposes, if you like, but now, once you get the revolver done, then is there anything in the secured that would prevent you from buying the 7 5/8 instead?

Rick Dobson

There is not.

Nitin Dahiya – Nomura Securities

There isn’t. Okay, so future reduction could come from that.

Rick Dobson

Yes.

Nitin Dahiya – Nomura Securities

Great. And lastly, on M&A, obviously, I think Mark had some comments in terms of why it's kind of being deferred out and that how you would be looking at all options. Would you say that you would see yourself as a seller or a buyer of assets if something became available and financing was available?

Mark Jacobs

Yes, you know, basically the comment I made is that we would look at all avenues. We don’t have any preconceived notions of how that, we are looking at kind of all ways to create value. Again, I believe that we are going to see consolidation overtime, and so we look at that as an industry dynamic and say, okay, given that, then how can RRI position itself to create value from that dynamic, and I would say that could be on either side of the equation.

Nitin Dahiya – Nomura Securities

Great. Thank you very much.

Dennis Barber

Thank you all for your participation this morning. Please feel free to contact Monica or myself if you have any further questions. 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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Source: RRI Energy, Inc. Q4 2009 Earnings Call Transcript
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