Hello and welcome to the Dynegy third quarter 2009 financial results and 2010 guidance estimates teleconference. (Operator instructions) I’d now like to turn the conference over to Ms. Norelle Lundy, Vice President of Investor and Public Relations. Ma’am you may begin.

Good morning everyone, and welcome to Dynegy’s investor conference call and web cast covering the company's third-quarter financial results and our 2010 financial estimates and future outlook. As is our customary practice before we begin this morning, I would like to remind you that our call will include statements reflecting assumptions, expectations, projections, intentions or beliefs about future events with respect to our financial estimates. These and other statements not relating strictly to historical or current facts are intended as forward-looking statements. Actual results though may vary materially from those expressed or implied in any forward looking statements. For a description of the factors that may cause such a variance, I would direct you to the forward-looking statements legend contained in today’s news release and in our SEC filings, which are available free of charge through our website at dynegy.com. With that I will now turn it over to our Chairman, President and CEO, Bruce Williamson.

Good morning and thank you for joining us. With me on the call this morning to cover third-quarter results and 2010 estimates are several members of our management team, including Holli Nichols, our Chief Financial Officer. Let us now turn to slide three for those of you following along online via the web cast. Today we announced Dynegy is raising our 2009 guidance estimate and also tightening up the range due to our continued focus on commercializing and operating well. In terms of third-quarter results, the economy, power markets and capital markets continue to present challenges, but our focus on commercialization has mitigated some of these effects. We clearly have benefited from the diversity of our portfolio in terms of fuel and geography. While our base load coal fleet achieved a high level of end-market availability at 92%, our combined cycle units responded to shifting market dynamics with more frequent dispatch. As for our commercial strategy, we maintained our current plus one and plus two-year strategy. Given current market uncertainty, our expected generation is substantially contracted for 2010, and we are continuing to commercialize 2011 remaining open in the outer years to capitalize on improvements in economic and market conditions. We also maintained ample liquidity. Upon the closing of the planned transaction with LS Power, which we expect to occur during the fourth quarter, liquidity would improve by approximately $1 billion, further enhancing our financial flexibility. In addition to third-quarter 2009 results, we are reaffirming our 2010 adjusted EBITDA guidance estimates and providing regional performance drivers detailed on our 2010 financial estimates. Holli is going to cover third-quarter results, and then provide you with more detail on 2010. Then I would like to take a step back and give you our perspective on the industry and discuss our commercial strategy in some more detail. With that I will turn it over to Holli.

Thanks Bruce. Before starting I should point out that these materials do contain non-GAAP measures that are reconciled in the appendix of this presentation for your reference. Now let us turn to slide five for a look at our third-quarter financial results. Third-quarter adjusted EBITDA increased 44% compared to 2008 primarily due to the sale and assignment of a multi-year power sales contract, higher net capacity, and tolling revenues and higher realized energy prices in the Midwest. This is partially offset by lower volume in coal facilities due to weak demand and increased wind generation in MISO. The net loss attributable to Dynegy of $212 million for the third quarter of ‘09 reflects after-tax charges of $238 million primarily related to asset impairment and after-tax net mark-to-market losses of $78 million. This compares to net income attributable to Dynegy of $605 million for the third quarter of 2008, which includes $542 million of after-tax net mark-to-market gains. As of September 30, liquidity was $1.9 billion with $703 million of cash on hand. Please turn to slide six for a discussion of our performance drivers for the quarter by region. While adjusted EBITDA was up, overall volumes were down slightly period-over-period. Let me take you through the drivers for the quarter. In the Midwest, adjusted EBITDA was up 45% from the prior year despite lower volume. This was primarily due to the sale and assignment of a multi-year power sales contract that would have been in effect until 2011. Regarding this assignment, we chose to capitalize on an opportunity to crystallize and end the money contract that was subject to variability and difficulty to hedge. We effectively brought forward approximately $30 million into 2009 from future periods. Importantly, this does not result in a reduction to our 2010 guidance. In addition,…

Thank you, Holli. Please turn to slide 18, where I would like to touch on the near term and longer term fundamentals of the business. First and foremost, this is a cyclical industry and evidence suggests that the recent downward trend will reverse over time as supply and demand tighten. Right now we're continuing to see weak power prices and volatility in natural gas prices. However, given the slowdown of new power plant development and construction activities, we believe the new generation will come online at a much slower rate. This is because barriers to entry remain very high in this capital intensive industry and very few if any base load and intermediate development projects are actually being built. Another near-term factor is the uncertainty around carbon legislation. Our position is that since climate change is a global issue, any regulation of greenhouse gas sources in the US should be undertaken by the federal government in coordination with developed and developing countries around the world. Our preference would be for overarching federal legislation with federal pre-emption, not a password for state and regional regulations that addresses three critical interrelated critical elements central to the debate. First the environment, second the economy, which remains in a state of recovery, and third energy security and reliability. As for long-term industry fundamentals, we believe that power markets will tighten and natural gas prices will rise over time, thereby increasing power prices. In addition, we believe the cost and environmentally efficient units could push less efficient generation into retirement, which is why we are completing the environmental work at our coal fleet over the next few years, and believe in the diversity of our combined cycle gas fleets. Finally, industry consolidation remains an attractive proposition for investors based on the significant synergies in cost…

(Operator instructions) Our first quarter comes from Brian Chin with Citigroup.

Hi good morning.

Hi Brian.

Quick question on just clarity on the LS Power transaction that is pending. If I remember right on the second-quarter slides there was an assumption that the transaction could close in the third quarter, and I think you mentioned now its fourth-quarter. Can you just give us a little bit more update on what's going on there?

We expect -- I think we've always said we expected to close in the fourth quarter. There was a possibility of the third quarter, but it was dependent on getting all the regulatory approvals as well as all the required contract assignments and other conditions precedent. We got HSR approval, I believe, in the middle part or so of the third quarter. FERC approval came in the fourth quarter, and now we are in the process of completing the remaining conditions precedent, contract assignments and things like that.

Okay, that's helpful. Secondly, on one of your slides, I think it's slide five or six, you indicated a net benefit in selling options. Can you just give us a sense of how material that net benefit from selling options was in the West and the Northeast?

The way we manage it Brian is on a consolidated portfolio basis, and on a net basis the premiums for either selling or buying option was single digits far less than $5 million, and so that's how we've managed that.

Okay, and then one last question, and I'll jump back in the queue. The interpretation of the first -- I think it's in the first paragraph of the press release, it's depending on how you read it you could use the contract that you monetized is being related to assets in the Midwest or not. Was the contract that you monetized related to the LS Power assets that were sold or were they completely separate from those assets?

Completely separate from those assets.

Right. Thanks a lot.

Okay.

Neel Mitra with Simmons & Co. Your line is open.

Hi good morning.

Hi, how are you?

Can you comment more on the sale of the Midwest contract as far as what the contract you sold was, was it your First Energy utility contract or something else, and also if the contract was in the money, how did the sale of the contract now lower guidance for 2010 from the last quarter?

Sure Neil. First, we were really not in a position to be able to talk about the specific parties associated to the contract, but the reason and the logic behind the impact on '09 and '10 is as we mentioned there is $30 million that we previously expected to settle up in '10 and beyond. Not all of that was '10. There was some that was '11 as well. But as we were able to bring that forward and essentially crystallized that earnings we also took the opportunities than to invest in future periods by buying some other options, and so we spent money to do that, but we think that will add some value in '10. So that is partly why there are no adjustments to '10 and then I would say there are also just other benefits here and there that we've seen such that we are very comfortable. Obviously 2010 is a pretty wide range, and we are still very comfortable that we should be able to come in within that.

Was the contract primarily for 2010 or did it extend through 2012. I'm just trying to get a sense of what year it's really covered in terms of an EBITDA impact?

Sure. It was '09, '10, and '11 about $20 million was in '09 and I don't actually have that break out between '10 and '11 handy, but there was more for '10 than '11.

Yes. Of the $50 million, approximately $30 million is related to 2010 and 2011, and the majority of that I'd say you know, 20 plus or minus million dollars related to 2010.

But I think Neel it's important for people to understand that you know, when we monetize that and crystallize the value, because there was I guess you would just say there was a disparity between our view of the value, and what we were able to settle with out with the party for. We were then able to take back and then replace it with you know, hedge positions for '10 that we think then makes it where '10 did not need any lowering of guidance, and so that was really I think just opportunistic execution by the commercial group, which then brings that into '09. That's clearly additive to '09, but then they were able to quickly go out and underpin and support 2010 and beyond. So I don't really at this point consider it like a, you know, to use the term a one-timer that comes in and then it's not replaced in future years. It's not like we were bringing it in and lowering the outyears. We’re bringing it in, capturing a gain here, and maintaining the outyears.

Right. And then, one last question on possible plant retirements in California. First, can you ballpark South Bay EBITDA’s contribution and then also is there a near-term possibility the ISO or the State Water Resources Board in California would cause you to take action on Morro Bay or Moss Landing to address once-through cooling?

The EBITDA contribution in South Bay is I would say it's extremely minimal.

Okay.

It's not something that you would change your modeling for at all.

Given the structure of the RMR contracted, not much of a contributor.

And then with regard to your second part of your question about, you know, changes in I guess regulation or timetable for that. Lynn, I guess I let you comment on it but I mean, you know, politicians can change all sorts of things but at this point there is a stated timetable that you know, is around the assets. The most meaningful contributor of earnings in the West is clearly Moss, and the date for that is Lynn 2017 or quite a ways off.

Yes, the other thing to keep in mind is that the rule is not finalized, there is only a proposed rule and comments are coming in. We don't expect that there'll be a final rule until the beginning of next year, and until we know what that is, we don't really know the exact impact. We don't expect the timeline to change materially. So if there are impacts around Morro Bay, we would expect that around 2015 and if there are impacts around Moss Landing, we would expect that about 2017.

Okay, great. Thank you very much.

Thanks Neil.

Our next question comes from Lasan Johong with RBC Capital Markets.

Hi Lasan.

Hi Bruce. I'm kind of curious about something. You said wind that impacted your Midwest generation fleet. A, how big was the impact. B, were there potential makeup from bilateral contracts on ancillary products or increased volatility in power prices?

Holli, you covered some of that in your segment.

Yes, one of the things that we mentioned Lasan is that for the -- and this is just a period-over-period, it is a quarter-over-quarter, what we saw was about a 12% decrease in our coal volumes in the Midwest, but again that's where we saw the gas assets picking up as they were displacing some other less efficient coal plants.

That was all wind though. That's just period-over-period. So there's

Mild summer weather…

…very weather, very mild weather that goes into that as well. I mean, Chuck, the main impact of wind was in the off-peak hours and lowering of off-peak prices.

That's correct and I think you also said the impact of the economy and weather in those as well. So it's very difficult to pinpoint or specifically allocate an impact to one versus another but all three impacted.

What does your gut instinct tell you about whether wind is having a net, how much of a net negative it is to your EBITDA numbers, $10 million, $5 million, you know, $2 million?

I don't have a breakout on that Lasan. I think you know, the bigger thing this summer was probably you know, I guess my gut would say it was probably mild summer weather first, economy second, and wind in the off-peak hours is third or fourth, I don't know fourth. I don't know what third was.

Okay. Second question is on hedging strategy. You know, obviously if you think '11, '12, and beyond is going to be a recovery situation, then at some point I would think you would sit back and say, “Okay, we've hedged enough for now. Let's sit back and watch what happened before we make a move in one direction or the other.” Is there a threshold at which you would say or is there a kind of a time frame where you say this is the drop dead date. We either need to go up more in hedging or down more for 2011 because you're already 50% hedged. That's pretty aggressive for you guys you know, even before you get into 2010. So, is there…

I would say, compared to our history I wouldn't say it's aggressive, I would say it's defensive.

Okay, defensive.

You know, at this point I think we just have to -- we look out at 2011 and you know, I'm not uncomfortable with the situation where Chuck and Eric [ph] have got us to it around 50%, and they have been very opportunistic around getting us to that point. You know, if we see opportunities and we see some you know, run-up in pricing as we go into the winter here. If the winter of '09, '10 pulls up '11 pricing, then we might take advantage of that some. You know, if we saw a very mild winter and a big falloff from here, then I don't know at that point that we would be very aggressive in adding to that but, you know, we got ourselves to sort of I guess 50-50 is maybe a bit of a neutral position right now, where we're being, you know, defensive but we've got a good chunk there in '11 and then we've got '12 and beyond that is open, and we are comfortable with that.

Okay, last question on South Bay. If you mothball that plant down completely, are there plans for what you want to do with that real estate, pretty valuable real estate I remember.

Which one?

South Bay. I think you guys --

You know, Lasan we don't actually own the real estate. The real estate is owned by the Port and we lease the facility and we have a demolition obligation that will come into play once the plant is out of service. So we are looking at that out over the next few years. We've been recovering those demolition costs through the RMR rate. So --

And reserving cost in a segregated account.

Right. So --

No plans for repowering?

No.

We've been down that road and that didn't work.

Got you. Thank you.

Okay.

Our next question comes from Daniel Eggers with Credit Suisse. Your line is open.

Hi, good morning.

Hi Daniel.

Thanks for all the detail in the back of the presentation. That was helpful today. Bruce, just thinking about kind of the wide range and earnings at a 95% hedge rate, what is the assumption you know, kind of midpoint from a generation dispatch perspective next year. How much the coal plants have to run versus this year to be able to hit that number?

I think we probably have basically the same dispatch 90% in market availability and as per this year.

Okay, so just holding flat, you're not banking on a big economic recovery to get your numbers.

No, no. Basically same you know, same roughly same dispatches this year is what drives the guidance range for next year.

And then, you know, with the increase in 2011 hedging, can you just give maybe a little more color you know, where you guys have been able to offload that power as far as you know, physical power sales versus some of the, you know, options markets versus some of the auction activities you've seen?

Probably as far as what's been put in more recently Chuck, it's has probably been more financial than auctions at this point.

That's correct.

And how much are you -- how are you guys managing (inaudible) you know, there is probably some challenges to getting back to the plans in the financial market right now?

Generally, we are -- in Midwest we are hedging our facilities, our expected power output at (inaudible). So I think we talked in detail about the license risk that we have with respect to that. We're not using PJM to hedge, you know, Midwest output for instance. So the lessons we learned in 2008, we continue to remember. So, you know, I think with respect to basis not any different from the basis risk we've experienced in the past.

Okay. And I guess from a clarification perspective on the South Bay demolition cost, how much is that just out of curiosity?

Don't have a final estimate on it. You can in the Q, we cover you know, some more details on the accounts and things like that, but, you know, it should be covered largely through the segregated account and the RMR.

Is that segregated account on the balance sheet or is that off the balance sheet?

Secondly, the cash that we've received in the past sitting in our -- in the cash you see on our balance sheet. The cash that we've pulled from the RMR contract itself.

So as we look at the cash flow statement when, you know, when that demolition occurs there would be a net cash outflow relative to where the financial show today.

That's correct.

Okay, thank you.

Our next question comes from Brian Russo with Ladenburg Thalmann. Your line is open.

Hi, good morning.

Hi Brian.

Could you tell us about your post-2010 PRB hedges, how much were hedged and how was that relative to market or what you disclosed earlier for your 2010 pricing?

I believe we have about 35% Brian of the volumes committed for '11 and '12, but the pricing is still open.

Okay, so we should assume market prices for that when modeling.

I think so. When you think market, just think of in terms of term contract market versus the spot.

Market negotiated term.

Right.

Okay, and you currently have below market PRB contract. So we would expect your supply cost to increase post-2010.

Well, actually the way to think about is there are two components. There is supply of the coal itself, and then there is the transportation. And so what I just described is the supply of coal itself, and so to your point you can look to market for that. Now, the larger component though is transportation and that's fixed through essentially through 2013, and so you wouldn't expect to see significant move, absent a material move in the commodity market for the coal. As an example you know, these contracts open and roll every couple of years at different times, and I think the delivery cost to bottom line has been flat for the last two years.

Okay, and then just on the megawatt hour and volumes you expect for 2010. Just want to understand obviously gas prices are higher, are you assuming the same type of dispatch profile, meaning do you expect your efficient gas fired plants to be as competitive with coal in 2010 as they are in 2009?

I think generally the way we look at it is you can look at the forward market and look at the implied heat rates, and that's effectively how we think about the volumes as well in looking at what the pricing would indicate from you know, what's in the money, and then obviously we then consider that there are some volatility around that as well, but I don't think that we're seeing material differences and as we've included back in the detail, you can see the megawatts that we're expecting to produce in 2010 by region and so that should give you a feel as to how that compares out to 2009.

Put it this way. We're not -- in the guidance and in the forecast we're not putting in a big upturn or increase in runtime that isn't otherwise there supported by the forwards for 2010.

Okay, great. And then just lastly, could you just comment on, does your Illinois consent decree in the CapEx you're spending there, does that mitigate your exposure to the potential ETA rules being proposed for 2011 in terms of mercury, et cetera?

Lynn.

Not specifically for mercury. The consent decree didn't cover that although the -- when you think about the types of backend controls, the things that you do for particular for NOx for SOx for mercury all began to have some interrelation. So we are taking steps to address mercury as well, and remember in Illinois there is a specific mercury rule that we're subject to. So all of that work is going on at the same time, and it's part of the same general program. So we don't anticipate that there'll be anything new that we need to do to comply with mercury rules. We think we know what those are in terms of Illinois statute and we are taking the actions to be in compliance with that.

Okay.

Lastly, that was driven when we had an agreement with Illinois EPA under their mercury rule around the same time we did the consent decree didn’t affect it largely, but we think it would be the same as the federal rule.

As far as we know, we are comfortable with where we are in terms of mercury…

Okay, great. Thank you.

Okay.

Brandon Blossman with Tudor Pickering. Your line is open.

Good morning guys.

Hi Brandon.

Good morning.

How are you doing?

Good.

Most of my questions actually have been addressed. This is probably more of a detailed question, but you touched briefly on the use of options in '10, and perhaps in the outyears more than you have in the past. And I see there is some detail in the back around collars. Can I assume that most of those options are collars or are there some puts in there that would show kind of asymmetrical response to change in gas prices?

Chuck.

Yes, I think with respect to electricity, what you do not find is selling puts with respect to electricity on balance. So with respect to electricity he has collars, buying calls…

Buying puts and selling calls.

Sorry, buying puts, selling calls.

Okay, and then so how does that allow you to have exposure into the upside then?

Well, certainly the calls that we purchased, I'm sorry calls that we sold are higher than market prices today.

Okay, up to price of the caller.

Yes, and they don't always have to be a collar [ph]. We could invest a little money in there and, you know, in effect then put the put at one level and then have more upside participation beyond that.

Okay, and then just real quick to reiterate the close with LS Power, is there anything that could possibly derail that or is that essentially done?

Well, clearly, you know, there are parties, both parties need to complete, you know, as I said earlier you know, conditions precedent include a variety of contracts, contract assignments things like that, and we fully expect to have that completed in the fourth quarter.

That's all I have. Thanks guys.

Okay.

Our next question comes from Angie Storozynski with Macquarie Capital.

Thank you.

Hi, Angie.

Hi. I have a question about the rationale for monetizing this, the power contract that's lessened your EBITDA, lessened your EBIDTA by $50 million or $30 million something from '10 and '11. How should we think about it? Is there anything -- does it have anything to do with your debt covenants or your EBITDA to interest expense?

No, not at all.

No, and as you know let us work on a quarterly you know, trailing 12 months. So if we were to rob from '10 only to push back to '09 that would actually probably work against us in this particular situation. It was really more driven by the fact that there were some variability associated with that contract, particularly around the volumes that we couldn't really hedge and mitigate. So while we were able to manage the price side of it, we couldn't effectively manage the volume side, and so it was in the money now and so we choose to go ahead and crystallize that because that's something that could have actually moved away from us over time and that's what the team does you know, all the time. They look for opportunities to mitigate risk where we can. Where we can’t, we'll monetize when we see the value there and then again they took the opportunity to make further investments in '10 with some of the proceeds from that transaction.

I never liked this. It also contract with very good pricing, but it had variability in volume and that variability of volume meant that our commercial team needed to have, let's call it 100 units of volume available every day, every month, but it could flex downward suddenly, and maybe only take say 30 units of volume, and then we would have 70 units left over that we would then have to just sell at spot prices. That volume variability for us meant we had to basically keep more in reserve. When the opportunity came for the counterparty to then you know buy it out from us, back from us, and we then avoid that volumetric risk that we otherwise as Holli said, you know couldn’t hedge. We're then able to then take the proceeds for that and then you know, bring that forward and then go put on the know, a much more firm hedge for forward years and not lower forward guidance [ph] by them.

Okay. Thank you. And the second question is looking at your third-quarter earnings results and the uplift to earnings from the higher runtime on your combined cycle gas plants. What portion of this uplift is actually going away with the LS Power transaction?

If you think about where the uplift was, it was primarily the PJM combined cycle plants, things like Kendall and Ontelaunee. Actually our peaker volumes were down period-over-period, and in the Midwest it's the peaker plants that are going to LS. So we would actually be retaining the assets that drove this up-tick in volumes.

That's great. Thank you so much.

Okay. Operator, we'll take one more question.

Thank you. Our last question comes from Karen Miller [ph] with Libertus [ph]. Your line is open.

Hi Karen.

Good morning Bruce. How are you?

Good. How are you?

I got right in under the wire, but my question is actually for Holli, if I might.

That's fine.

On the slide 14, when you talked about the $800 million deployed for the retirement of near-term obligations. Is that an assumption that that would be the cash freed up by the role of $800 million of 11s and 12s, and therefore, you're being conservative or how should we think about that not being $1 billion now?

Yes. We're looking as if this is the cash usage that we would put to work, and we're not specifically at this point. I mean we did some modeling. We had to make some assumptions, but we're not specifically talking about the execution plan because we have several what I'll call near-term obligation that we will certainly look at the 11s and 12s. They are clearly on that list, and we are focused on that. So the key is we want to take any near-term cash payments that will be coming up for the company that have an interest component to own that will help us reduce our fixed cost. That's where we'll put the money to work and will use you know, right now on the plan we put $800 that can flex up and that can flex down depending on opportunities that when we get into actual execution, and we'll be obviously very clear when we've got that done to come out and announce that.

Okay.

Karen, it kind of comes down to this. When we get ready to put a plan together and come out with guidance, you know, on one extreme we could have had treasury assume zero in terms of liability management, and we'd have a huge amount of cash on the balance sheet. We'd have a little bit more interest income and a lot more interest expense. We could put you know, something like we are going to take out you know, all the 11s and 12s and we'd have you know, another assumption we could take out you know, other amortizing debts. We had to just kind of make an assumption that we thought was sort of down the middle and you know, is representative of you know, a middle position and then we can flex from there.

Okay and just a follow-up, therefore is December the modeling assumption or is December sort of your goal when you like to deal with this?

I think we can still deal with this in 2010, I'm sorry 2009.

Okay, thank you very much.

Okay. That concludes today's call. Thank you again for your time this morning and your interest in Dynegy.