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Executives

Dennis Barber - Vice President, Investor Relations

Mark Jacobs - President, Chief Executive Officer

Rick Dobson - Chief Financial Officer

Analysts

Neel Mitra - Simmons & Company International

Daniel Eggers - Credit Suisse

Michael Lapides - Goldman Sachs

Lason Johong - RBC Capital

Brandon Blossman - Tudor Pickering & Co.

Greg Orril - Barclays Capital

Brian Tedale - Broadpoint Capital

Nitin Dahiya - Nomura Securities

Reliant Energy, Inc. (RRI) Q3 2009 Earnings Call November 5, 2009 10:00 AM ET

Operator

Good morning ladies and gentlemen and welcome to the RRI Energy third quarter 2009 earnings conference call. (Operator Instructions). 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 third quarter conference call. Leading the call this morning are Mark Jacobs, President and CEO and Rick Dobson, 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 the website approximately two hours after the call.

Consistent with our past practice, we're using several non-GAAP measures to provide additional insight into 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 October the 23rd.

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 third quarter earnings call. This morning we released our 3Q results, which are summarized on slide 4.

We reported open EBITDA of $133 million and an adjusted EBITDA of $100 million for the quarter. This quarter's results reflected the challenging commodity price and economic environment we are operating within. I will share some statistics with you to give you a flavor for the environment and then I want to discuss our operating performance.

First on the market environment. On a weather-adjusted basis, electricity demand in PJM and MISO improved from Q2 but still was off 3% and 5% respectively from 3Q last year.

As you know, the price of natural gas plays a big role in setting power prices. The average spot price for natural gas at the TETCO M3 hub was $3.41 per mmbtu in 3Q, and traded as low as $2 and change during the quarter. Add to those factors, average cooling-degree days in Western Pennsylvania were down 22% versus normal for 3Q.

Given the weakness in natural gas prices, we also experienced some coal to gas switching. Let me share with you a couple of anecdotal figures from the quarter to give you a better insight into that phenomenon.

Hunterstown, which is a combined cycle gas plant, had an additional 300000 megawatt hours of economic generation in 3Q 2009 versus last year. At the same time, our mid merit coal plants including Elrama, Titus, New Castle and Niles had about 400,000 megawatt hours less economic generation.

Now the silver lining in the data is that we've started to see some improvement in both demand and natural gas prices.

October demand data in MISO and PJM shows a smaller reduction in demand versus last year continuing a trend that started in 3Q, and spot natural gas prices have rebounded to the $4 per mmbtu range.

Now let me turn to operating performance with this discussion of market environment as a backdrop. Most of you know that we had a focused effort over the last several years to improve the performance of our overall fleet.

More specifically, our goal was to reach top quartile equipment performance levels, which we achieved in 2008. As we discussed in our investor conference, the next phase of our strategy is to have a more differentiated investment approach.

We invest for higher performance levels at our higher margin plants. In many cases, there is not a financial return in investing in top quartile performance at lower margin plants.

And in light of current market conditions, an incremental unit of availability is worth much less today than it was in 2008. Against this environment, we are reducing our investment spending on projects and outages by over $20 million in 2009 and we did this with an objective of maintaining 2008 equipment performance levels.

You will see the impact of lower cost in the 3Q. However, commercial capacity factor performance was a shade behind 2008 levels and we expect to end the year slightly behind as well.

The financial impact of the lower commercial capacity factor is negligible and greatly outweighed by the reduction in spending. Nonetheless, we can do better and we have redirected some of our O&M spending and continue to work inside our plant operations excellence program to improve performance at specific higher value plants.

This morning, we’ve also provided an updated financial outlook for 2009 and 2010. 2009 reflects the difficult market environment as well as coal purchases that are substantially above current market prices. The outlook for 2010 open EBITDA is $455 million and for 2010 free cash flow is $167 million.

Virtually all of the 2010 improvement over 2009 is due to the higher gas coal spreads in the forward curve and the role off of our out of the money coal purchases. Market implied heat rates and affords do not show any improvement.

In connection with the sale of the retail business earlier this year, we reevaluated our segment reporting. The bottom line is that we still provide the same level of granularity in the data, but we're rolling it up a little bit differently than we have in the past.

The four new segments are East coal, East gas, West and other. The East coal segment includes the coal plants in both MISO and PJM.

On slide 5 I wanted to update you on the progress against the strategic priorities we outlined in our investor conference in July. As a remainder our primary focus is on managing risk.

In light of the uncertainty in the current market environment, it is without question our highest priority. We are in a strong position ending October with approximately $1.7 billion of available liquidity including $1.1 billion of cash.

In addition as we've discussed, we implemented a modest forward hedging program for 2010 and 2011. As a remainder we have strategically left open the majority of our output so that we will benefit when market conditions improve.

The hedging program is designed to provide a high degree of certainty of free cash flow break even or better if market conditions substantially worsen. To that end we have recently layered in some additional positions to give us added downside protection while preserving the upside.

Since our last call, we also sold some additional capacity off of our California fleet. This was an important step because it builds on our sizable base of capacity revenues. You will remember that capacity provides a large and stable source of revenue for the next several years.

This quarter, we added a new schedule in the appendix that details forward capacity sales for the entire fleet. When you review the data you'll see a significant increase in 2012 capacity revenue from California that partially offsets a reduction in PJM in the same timeframe.

In October we completed a tender offer for two tranches of our secured bonds. Added to open market purchases we've reduced over $220 million of secured debt this year.

As Rick will cover in more detail, this has been a component of our strategy to manage the financial covenant in our corporate revolver in addition to being consistent with our strategy to redeploy cash to reach target debt levels.

Bottom line, I believe we are well positioned to manage through the current market even if conditions further deteriorate. At the same time we are well positioned to create long term value for shareholders when the markets recover.

Not withstanding the difficult market environment, we are keenly focused on getting the maximum value from the assets and improving those items we can control, our efficiency and our effectiveness.

At the Investor Conference we discussed the fact that we have developed a plant specific operating approach. Most recently we've revised our operating models at Elrama and our MISO coal fleet, which includes Avon Lake and New Castle where we’re going to seasonal operations.

In addition, we’ll significantly reduce costs and staffing in Indian River, where we have a PPA that expires at the end of 2009. We may also mothball Indian River unless we identify a viable near term PPA opportunity. Collectively these changes will reduce 2010 costs by nearly $60 million and will only result in $17 million less in margin.

At the same time, we've built in the flexibility to further reduce costs should the commercial environment deteriorate or to return the plants to full operation if gas/coal spreads improve. Next up will be reviews at several of our PJM coal plants Titus, Shawville and Portland. I expect that we will be reporting on the outcome of those reviews on the year-end earnings call.

I want to pause here and acknowledge the work done by our cross-functional teams. Early on in our analysis, we identified flexibility or perhaps better defined as flexibility to respond to changing market conditions as a very important value lever. However, that’s much easier said that done. There are a number of obstacles in traditional approaches to operating power plants.

To the credit of our team, they have developed some very creative solutions to these challenges. I believe that we’re well on our way to developing a differentiated capability in this area.

An important component of our work on efficiency and effectiveness is our focus on capital deployed in the business. We've identified opportunities to reduce working capital by approximately $50 million and are in process of executing against that plan.

At our investor conference, I discussed our focus on improving our risk management capabilities. During the third quarter, we completed a top to bottom review of our enterprise risk management with the assistance of a well-regarded third party. We have identified some areas for improvement and are well underway on an implementation plan.

Before turning the call over to Rick to take you through the numbers, I wanted to update you on the scrubber installations. At Keystone, Unit 1 was completed in late September and Unit 2 is being tied in now and will be completed later this month.

As I mentioned on the last quarter call, we decided to defer the tie in of the Cheswick scrubber until next year. With the completion of these projects 53% of our coal fire generation volume will come from scrub plants.

I’ll now turn the call over to Rick Dobson our Chief Financial Officer

Rick Dobson

Thank you Mark. Let's turn to Slide 7. In the third quarter of 2009, we experienced very weak commodity prices, reduced load driven by poor economic conditions and mild weather.

These factors were the primary drivers of our lower generation output and much lower open energy margins. The continued focus on effectiveness and efficiency was a significant factor in our lower year-over-year O&M costs.

Our commercial capacity factor was 90.9% for the third quarter, slightly below 2008 levels and below our expectations. Although the financial impact was not material on today’s commodity price environment, this remains a high priority.

On a plant basis, we saw improvements at the Seward, Shawville and Hunterstown facilities, and there is room for improvement at our Portland and Avon Lake plants.

The combination of these factors resulted in opening EBITDA of $133 million in the third quarter. Lower unit margins and reduced demand that Mark described, combined with coal purchases at prices above the current market, resulted in a third quarter adjusted EBITDA of $100 million.

These same drivers are the contributing factors to our operating free cash flow use of a $179 million year-to-date, but after considering the retail performance through April of this year, we produced a $134 million of free cash flow through September of 2009.

Let's move to outlook on slide 8. We've used a more recent forward curve date due to the implementation of certain process improvements. These improvements enable us to use a forward curve date that is about two weeks prior to our call date, an acceleration of three to four weeks.

Let's now review our 2009 and 2010 outlook. Many of the same drivers of our third quarter performance drive our full year 2009 outlook. Depressed commodity prices, mild weather and lower generation due to the state of the economy result in open EBITDA of $198 million for 2009.

Factoring in our coal purchases partially offset by our natural gas hedges, our 2009 outlook reflects $56 million of adjusted EBITDA. While the 2009 adjusted EBITDA drives operating free cash flow losses from continued operations of $314 million, again when we factoring the retail performance we would be effectively free cash flow break even for 2009.

Turning to 2010, we see stronger commodity prices. The full year impact of our corporate cost realignment and the role off of the out of the money coal purchases pushing open EBITDA to $455 million and adjusted EBITDA to $428 million.

With the completion of the Keystone scrubber and the bulk of the Cheswick scrubber spend occurring in 2009 our free cash flow outlook is $157 million in 2010.

Let's turn to slide 9 and talk about hedging. As Mark briefly discussed we implemented a modest forward hedging program for 2010 and 2011, designed to provide for a high degree of certainty of free cash flow break-even or better even if market conditions significantly worsen. Our design primarily centers around $1 per MMBtu gas/coal spread in weak economy.

To that end we adjusted our 2010 and 2011 hedge position by adding 10 Bcf of gas puts to 2010 and 2.2 terawatt hours of power sales to our 2011 position. This profile leaves substantial commodity price spread upside with our 2010 and 2011 expected PJM coal hedge volume percentages now resting at 30% and 29% respectively.

Natural gas put volumes account for an additional 5% and 12% of the 2010 and 2011 amount respectively. From 2010 to 2011 the overall percentage hedge increase is primarily due to a decline in capacity payments between those years. We use a wide variety of hedging instruments and an effort to maximize effectiveness across the wide array of economic scenarios.

I see in the slide, this typically takes the form of power sales at the PJM west hub and AEP Dayton hub as well as fixed price gas input options. We are currently evaluating plans for the same type of modest hedging program to protect against down side for 2012.

Moving to slide 10, we completed our tender offer in October this year reducing $130 million of secured debt. This reduction and secured debt combined with our open market purchases and an increase in cash collateral provide us more flexibility with respect to our financial covenant.

The open market purchases and tender are consistent with our strategy to convert our strong liquidity position into a strong balance sheet. With the retirement of the Orion notes in May of 2010, our gross debt will be approximately $2.4 billion about $700 million above the of our long-term gross debt target.

Ultimately, the combination of a strong balance sheet and liquidity position, a solid capacity and PPA revenue profile and our modest forward hedging program, will yield a very sustainable platform to build long term value for shareholders.

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

Mark Jacobs

Thanks, Rick. Let me wrap up on slide ‘11. RRI Energy is a well-positioned wholesale power company. While current market conditions are depressed, the market will recover. But the timing of a recovery is uncertain and its possible that things will get worse before they get better.

Recently, I had one investor remark that I was not as optimistic as other CEOs on an economic recovery. The truth is that I don’t have a crystal ball. While we all may hope for a quick recovery, we are not counting on it.

Simply put, we are prepared for the worst, but we are positioned to benefit when the recovery occurs. We've taken a number of steps to lower our risk profile and we've taken actions to improve the performance and value of the business in these depressed market conditions.

At the same time, we recognize 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

(Operator Instructions) Your first question comes from Neel Mitra - Simmons & Company International.

Neel Mitra - Simmons & Company International

I'm looking at the economic factor in your presentation, which increased for both 2009 and 2010 in MISO and decreased in PJM from your last call. What dynamic is causing this? Does it have anything to do with the seasonal plant model in MISO or is MISO more attractive than PJM relative to the last quarter?

Mark Jacobs

As you know we use forward based commodity prices to report that outlook and so really what your seeing is just a change in the forward curves that may imply a little bit more or a little bit less generation and you are going to see that bounce around a little bit from quarter-to-quarter.

Neel Mitra - Simmons & Company International

Mark, on a longer-term basis, what do you think needs to occur in the MISO market for your three coal plants to run as typical base-load units rather than load-following units?

Mark Jacobs

Well I would separate those Neel. I think Avon Lake has the capability to run as a more significant base-load plant. That really at the end of the day is a plant that is driven by the gas-coal spread and so when we saw our market conditions like we did in 3Q of this year with a very depressed gas-coal spread, we got the results that we are going to see.

But if you look at the forward curve or the recovery net spread, we would expect to get more generation volume from Avon Lake perspectively. The other two units are more mid-mar and I would say that’s more governed by the boiler characteristics that we have in those plants.

Another factor I would point at in terms of the economics of the MISO assets, as you know MISO does not have an established capacity market like PJM does.

One of the things we are watching very closely is whether First Energy does indeed complete its move into PJM. I think that's likely to happen in the first part of next year, reach a conclusion on that.

If that happened, those three coal plants would move from MISO into PJM and that would provide them the opportunity to have a little bit better capacity value play as well.

Neel Mitra - Simmons & Company International

It looks like your coal hedge volume has almost doubled for 2010 after your last call with previously hedged prices. Was that because you differed some of your coal deliveries in 2009 or was it something else?

Mark Jacobs

We really just started to leg into the 2010 purchases at this point, and one of the things is we have implemented the modest hedging program also as we said we started to make sure that the coal volumes are matched up with those forward power sales.

Operator

Your next question comes from Daniel Eggers - Credit Suisse.

Daniel Eggers - Credit Suisse

Mark, can you start off and just give us a little more color on the California capacity markets? What you guys saw to be able to up the revenues so much in 2012 there and is that changing the energy contribution or energy margin contributions from those assets?

Mark Jacobs

Dan, it’s really as you know the assets we have in California, the principal value proposition in those is the capacity play and while sporadically we see energy margin opportunities on that I think the vast majority the value really isn't that capacity play.

As you look forward, the kick up you are seeing in 2012 is a result of both more capacity that we've sold forward and that capacity being sold at a higher price.

And I think one of things, the next question is why do you see prices going up and as you know, California is a bilateral market here. But I think it’s a reflection of the tightening supply demand fundamentals. As you look out over the next couple of years in California that we are seeing the benefit of that show up in better capacity revenues.

And I might also, while we were talking about California, just point out that earlier this week the California Public Utilities Commission issued a proposal in the capacity market rule making case that I wanted to make sure you are aware of.

And bottom line is what that proposal would require is that the load serving entities procure 80% of their forecasted load five years out and within three years out, that they will be at a 100% contracted on a capacity basis. And while that proposal stops short of a centrally cleared market like PJM that we've been advocating for I think it's certainly a big step in the right direction for California.

Daniel Eggers - Credit Suisse

Mark, along the lines of the California capacity, you still have open positions in ’10 and ‘11. Why are those not getting sold out at this point in time if the market is there and the ’12 need is there?

Mark Jacobs

Dan, I would say if I go back to how the counter parties to those agreements typically have legged into their capacity needs over time. So again that’s some portion of the fleet that we have not yet sold.

I would expect we will have opportunities to monetize that capacity value. I'm not sure it's going to be at values that are consistent with what we've sold earlier volumes on that to date. But again I think there is going to be opportunities, we will have to monetize that capacity and add to the capacity revenues we have locked in.

Daniel Eggers - Credit Suisse

Have you ever seen capacity revenues this high in California as you saw for the 2012 year?

Mark Jacobs

I think not to my recollections here, certainly not in the last six, seven years.

Daniel Eggers - Credit Suisse

And I guess just on capacity housekeeping with First Energy that three coal plants could move into the PJM market. Is there any other capacity that would go with that in the gas plant you picked up in that?

Mark Jacobs

There is not. It's the three coal plants that would move. So that would leave us as Rick is pointing out, Shelby would be then our only, that's a gas plant. That would be the only plant we would have in MISO if FE completes that move.

Daniel Eggers - Credit Suisse

One last question, as you saw more hedging activity, you are selling PJM West and AD hub. Are you seeing much liquidity in the AD hub or it's just predominantly PJM West hedging activity in a little bit further West?

Mark Jacobs

As you know Dan, ADP Dayton hub is not as liquid as the West hub, but if you are patient you can get out there and execute fair amount of volumes and that's what we've done.

Daniel Eggers - Credit Suisse

Mix wise does that mean more even or is that mean that -.

Mark Jacobs

Yeah, bit mix wise what we have done for ‘10 is on peak we've sold 500 megawatts at the West and 350 megawatts off and then in Dayton we did 300 on and 100 off for ‘10 and then for ‘11 at the West hub it's a 550 on 350 megawatts off and at Dayton it's 300 on 200 off. So it's a little heavier weighted towards with the West hub.

Operator

Your next question comes from Michael Lapides - Goldman Sachs.

Michael Lapides - Goldman Sachs

I have two questions. One PJM can you talk a little bit about how some of the changes that are coming down the pipe in PJM from the last auction results would likely impact bidding when we start thinking about next spring’s PJM auction?

Mark Jacobs

Michael I think there is two potential subset changes that we have coming up for the May 2010 auction. One that is approved and one still a work in process and the one that’s been approved is the removal of the offer cap on existing demand response resources.

That’s something the FERC approved in late October. And you may remember in the last auction the demand response or demand response that had perviously bid in was basically a price taker in the last auction.

So what the rule change will be will permit existing demand response to bid in economically and efficiently and that change was supported by a broad array of PJM stakeholders.

The other change was the one I was referring to here most recently, which is the potential inclusion of First Energy in that auction and certainly that would - our expectation will go in as RTO if that change takes place. And again as I mentioned, we've got three plants Avon, New Castle and Niles that would move into PJM if FE completes that move.

That’s dependent on FERC approval and a final decision by the FE Board of Directors. Again we expect that to get resolved one way or another in advance of the May 2010 auction.

I think the other impact that, that would have is, if FE completes that move there will be more load moving than generation volume. So that, you know on the margin should have somewhat of a positive impact on the supply/demand balance.

Michael Lapides - Goldman Sachs

And when we think about the cost changes that you - really going to a plant specific or a plant centric model and the impacted has on O&M expense.

I just want to follow up with you on that because we didn't see much of a change to your O&M guidance for 2010. So I’m struggling to understand where the benefit of that is actually going to show up when we think about the income statement?

Mark Jacobs

Well, the numbers as I recall, our reduction is about $50 million from 2009 to 2010 in O&M so in my book that's a pretty significant change that we've had here. Much of that has to do with really taking a very close look at the economic spending levels we have. So a big part of that Michael would be coming from looking at these plants on a specific individual basis.

Michael Lapides - Goldman Sachs

I'm just looking at the slide 8, O&M is $540 million for '09 and then for 2010 it's $557 million. I understand there's a big drop from '08 levels and that maybe what you're referring to or am I totally off?

Mark Jacobs

No. That is what I'm referring to is the 2008 to 2010. Sorry for the confusion.

Operator

Your next question comes from Lason Johong - RBC Capital.

Lason Johong - RBC Capital

Mark or Rick, why so little on the PUT options when natural gas in 2010 relative to '11 if you think '11 has a better chance or an upside on natural gas pricing?

Mark Jacobs

Well, Lason I'd say just as we look at forward sales versus the auctions it's a trade off of, obviously for auctions are coming out of pocket dollars.

The way we’ve tried to approach this again strategically is to number one, make sure that even if market conditions are very, very bad, that we are free cash flow break even or better.

At the same time, we do want to keep as much of our output open to benefit from improving market conditions as we can and so we have layered in some options for that. I think the biggest redoubt is you are looking at between ‘10 and ‘11, and Rick had mentioned this in his prepared comments, is that we do have a little bit of a falloff in capacity revenues going from ‘10 to ‘11.

So that necessitate if you will a little bit higher level of hedging in order to make sure that we weren’t getting up all of our upside. We did use a little bit of higher level of options in ‘11.

Rick Dobson

Lason, this is Rick. You said we use 24 Bcf of puts in ‘11 which leaves more upside there and we use 10 in ‘10, not to be confusing and we do have 7 Bcf of our gas hedge at about $8.30 to $8.40 also a fixed price gas hedge in there.

So we're leveraged to better improvement in prices in ’11, which was our thought process on putting more puts on in ‘11. Is that what you said or you said there was more upside in 10?

Lason Johong - RBC Capital

There is more upside in ‘11.

Rick Dobson

So, that’s why we were actually leaned heavier on puts in ‘11 because we have the same view.

Lason Johong - RBC Capital

So basically your selling puts -

Rick Dobson

We have basically -

Lason Johong - RBC Capital

In ‘11?

Mark Jacobs

We bought puts.

Lason Johong - RBC Capital

You bought sputs in 11?

Rick Dobson

Yeah 12 Bcf of puts were bought at $7 and 12 were bought at $6.50 in 11, 10 Bcf were bought at $5 in 2010 and we had also a 7 Bcf sale at about $8.40ish at the hump in ‘10 also.

Lason Johong - RBC Capital

So you had more volume put in '10 than '11.

Rick Dobson

We do.

Lason Johong - RBC Capital

Okay, because the graph here says its 5% in 2010 and 12% in 2011 on page 9.

Rick Dobson

Yes.

Lason Johong - RBC Capital

I thought one of that was your gas swaps.

Rick Dobson

No, that—

Lason Johong - RBC Capital

All right, that’s where my confusion was. I get it now. Second, I'm assuming your natural gas sensitivity in the back, in the appendix, does that include potential gains from peaking plants and CCGT's if gas prices really drop off? It doesn't look like it does.

Rick Dobson

No.

Lason Johong - RBC Capital

Okay, so that's a potential additional change or delta?

Rick Dobson

Yeah it's purely driven on the coal.

Lason Johong - RBC Capital

Okay, last question for me on the PJM capacity as First Energy class is over, is that additional capacity payment reflected in your 2010 outlook?

Mark Jacobs

That is not.

Lason Johong - RBC Capital

So that's another potential upside opportunity.

Mark Jacobs

I think you mentioned 2010. I think the, what will be key here is what the effective date of that move is. So that will be part of the proceeding that they are going with through with FERC but I wouldn't expect them to move effective in 2010. So I think it's really going to be a change here, that’s going to hit us after 2010.

Lason Johong - RBC Capital

So the effective - even though the permission is granted in ‘10, the effective move on, happening probably until '11?

Rick Dobson - Chief Financial Officer

Again I am not the expert on the exact timing of that move, but it would be sometime after there.

Operator

Your next question comes from Brandon Blossman - Tudor Pickering & Co.

Brandon Blossman - Tudor Pickering & Co.

How about the walk down of '09 guidance from last quarter to this quarter, they may be a detail that will me understand this but could you address or give a little bit of color to the other segment the, $36 million, and then also why the hedges were less in the money from second quarter to the third quarter?

Rick Dobson

What page are you on to make sure I’m synced up here?

Brandon Blossman - Tudor Pickering & Co.

I'm looking at page 20. And that’s open EBITDA walk-down from '09. Before '09 it has the full year EBITDA second quarter or the third quarter?

Rick Dobson

Right. Since we give the directional indicators out there, Dennis obviously stays what's that and from a directional perspective walks the numbers down using that. The big driver in the other 36 and 9 is a combination of a lot of factors that will probably best served if we got with Dennis and Monica and talked about all the differences.

There is a wealth of data in this package around how basis would have moved, how off peak would moved, how generation volumes would have moved and when you put all that together, it does start from 9 to kind of build up into a number like that and I think we’ll take that offline. It takes a little bit time to get through that 36, that would be helpful.

Mark Jacobs

I think that at a high level Brendon, which you are seeing there is a fall off in demand and you are seeing a low weather or mild weather.

Brandon Blossman - Tudor Pickering & Co.

And just again keeping it at a high level, my sense is that the third quarter came in pretty close to expectations of not a little bit better. So should I assume that fourth quarter is going to be pretty poor?

Mark Jacobs

The third quarter would have been, against a forward price curve that we would have talked about in our last call third, Q3 was substantially below.

Rick Dobson

Above fortyish, it was off about 40 Brandon. And Mark made a good comment. So we were short on the terawatt hours in third quarter too, about 1.1. And that's driving $9 million or $10 million to $36 million.

But it's just a lot of additional detail we can provide you offline, but about fortyish is the different between what we had from the June 26th price tag and what we actually achieved and then we're looking on an open basis probably another 25 reduction due to the $0.40 per mmbtu difference in [tech OM3] price tags between the June’s second quarter release and this October 23rd release.

Brandon Blossman - Tudor Pickering & Co.

That's helpful and I will follow up offline. Conceptual question, risk control you said that you had ID’d some areas for improvement. Can you give a little color around that?

Mark Jacobs

Yeah, I think the overall comment I'd make is I think we were doing a number of the things that we should be doing. I think what the review that we've undertaken has shown that there is going to be some value from adding more formality and structure to that process going forward and that's what we were working on now that I referenced in the prepared comments from an implementation plan standpoint.

Brandon Blossman - Tudor Pickering & Co.

So everything has been ID’d and you are just implementing at this point?

Mark Jacobs

Yes.

Rick Dobson

Also Brandon there’s been a lot of validation around this concept that we began this year around finding a sweet spot hedge level to give us a high probability of free cash flow break even that we really working on hard early in the year and I think with this work that’s being validated as we speak, that that makes sense and it’s the right way to go and the mix is the best mix that you can have for a fleet like ours around the mix of hedges.

Brandon Blossman - Tudor Pickering & Co.

And then finally on Indian River. So no incremental PPAs forthcoming. Mention of mothball. Are there any plans in the work for - I assume that retirement and decommission is probably not in the cards for that site. So any possibilities or thoughts about re-powering or selling the site itself as brownfield site?

Mark Jacobs

Brandon we’re looking as you would expect at all of the possibilities with Indian River. Everything from a sale to mothball, to decommissioning, to a PPA and what we've got in the forecast here really is no kind of revenue to speak of coming off of the PPA that expires at the end of the 2009.

So that is certainly, as we look at that, a situation that we’re going to hope to improve in 2010. But we’re looking at all the different options you would expect.

Operator

Your next question comes from Greg Orril - Barclays Capital.

Greg Orril - Barclays Capital

Just wanted to address the East coal volume forecast for ’10 versus ’09 and the assumptions there. It looks like it goes up to 24 terawatt hours from about 20.5 terawatt hour. Just wondering if you could provide a little detail there?

Rick Dobson

Greg, we use the forward curves here and look at what that implies in terms of generation volume that’s in the money. We run those forward curves against a fairly detailed dispatch model. So you're going to see that forward-generation number bounce around as we see prices happening in the prospective market.

Greg Orril - Barclays Capital

And then on the California, on the west capacity revenue in 2012, if we would look forward there is that sort of comprised of longer term agreements or does that - when would that stepdown or does that continue for a while?

Mark Jacobs

From a volume metric standpoint, it would stepdown pretty significantly after 2012. We do have some of that capacity that is sold in 2013 and 2014. But you would see that stepdown again pretty significantly after 2012.

As we go forward in time here, we would expect to be filling that out here and I think you combine that with the decision coming out of the California Public Utility Commission earlier this week, my guess is that will provide us more of an opportunity to build a further forward book on capacity sales in California.

Greg Orril - Barclays Capital

No, I think that the '12 uptick is positive. You had mentioned that on the fourth quarter call you'd talk about that the outcome of the reviews for Titus, Shawville and Portland. What kind of the nature of the review there? Maybe you could remind us a bit there or give us a bit of a preview?

Mark Jacobs

Sure. Well, the context is that we are not operating our business with one-size fits all operating strategy for our plants. So each of these what they entail is a deep dive analysis understanding of the value drivers in that plant and then how we can best have an operating strategy to take advantage of those value drivers.

So, we have some plants like Seward plant deeply in the money, really irrespective of market conditions that would call for an operating strategy that’s more consistent through different market conditions and we have other plants and I think New Castle is a very good example for us.

Principally a gas-coal spread play and in more depressed market conditions that plant really struggles to be profitable. And so that’s a plant we spent a lot of time building a model that was flexible from an operating standpoint.

We are going to go to a seasonal operation there that will turn the plant from being not profitable into being profitable but at the same time, we left in a flexibility that if market conditions improve, we can ramp back very quickly to full-scale operations and capture that gas spread coal play.

So the plants that we are going to be looking at here or are looking at now that I mentioned on the call, a little bit different situation around those, but its really trying to develop an operating strategy that recognizes the value drivers and how we can best respond to market conditions to make sure that we're able to capture the maximum value out of that plant.

Operator

Your next question comes from Brian Tedale - Broadpoint Capital.

Brian Tedale - Broadpoint Capital

I just had a quick one on the capital structure. At the conference, you had talked about pursuing or looking at a collateral facility to free up some additional cash, the potentially used to pay down some more debt. Just give me an update as to where that stands now, if it's moved at all?

Rick Dobson

We have been honestly pretty keen on watching the capital markets and the bond market has been pretty robust as of late. We haven't made any significant progress on the lean structure at this point in time.

I think it's something that I would point to 2010 and it's something that we would realistically marry up with our dealing with our revolver and extending it because of the inner credit relationships you typically get with a lean type structure like that.

So to match both those facilities will be an event I would look more to 2010 for.

Brian Tedale - Broadpoint Capital

Is that a different perspective than you thought you would have before? I mean is it-

Rick Dobson

No, it's not a different perspective than I thought before. I mean we have time. The sweet spot is probably into 2010 to deal with the revolver and extending it and that point in time it makes, it would make a lot more sense inner creditor wise to then, put some type of collateral friendly facility in place.

Brian Tedale - Broadpoint Capital

I saw [your 16] to buy back the secured notes. Do you anticipate that you are still going to getting to go after those or any - would you like to go after some of the unsecured notes now? Where is your head on that now?

Rick Dobson

Our point of view on the relative value proposition of buying back different notes really hasn’t changed. For 2009 though we did have that covenant stuff, but the financial covenant that's much more relevant and that did change, that caused a temporary focus on the secured debt that we had to provide more covenant cushion as we move to this year, but overall the philosophy that we espoused in the late July hasn't changed.

Operator

Your next question comes from Nitin Dahiya - Nomura Securities

Nitin Dahiya - Nomura Securities

My question was on the buyback as well. And Rick, maybe you could explain it again, in terms of the buyback just to reaffirm, what you are saying is that we shouldn't probably look at more open market buybacks over the next six to nine months and we would rather see the Orion maturity and that would be a focus on the deduction. Am I hearing you correct there?

Rick Dobson

No, I would say this way, Nitin. Definitely we have $400 million of cash earmarked for Orion maturity at this point in time. No question about that. So that’s a big joke. We did talk about in the third quarter call that there was outside of maturity, there was another $250 million we feel comfortable expending.

We now expended about a $160 million of that cash to delever the company. But you could see some more delevering, but it wouldn’t be a huge number, it wouldn’t really be that material.

So I don’t want to say no, but I think that you captioned it correctly. The big next delevering will be the Orion maturity and then possibly some other stuff in the open market around the rest of the debt in the Cap structure.

Nitin Dahiya - Nomura Securities

But within the context of the $250 million that you talked about?

Rick Dobson

At this point in time, that’s still our point of view.

Mark Jacobs

We appreciate your participation on our call. Both Monica and I will be in the office today. So if you have any followup questions, please feel free to give us a call. Thanks for your participation.

Operator

And thank you ladies and gentlemen. This concludes today's conference. Thank you for participating. You may all disconnect. Thank you.

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