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Executives

Norelle Lundy – Vice President of Investor and Public Relations

Bruce Williamson – Chairman, President and CEO

Holli Nichols – EVP and CFO

Lynn Lednicky – EVP, Operations

Charles Cook – EVP, Commercial and Market Analytics

Analysts

Brian Chin – Citigroup

Neel Mitra – Simmons & Co.

Lasan Johong – RBC Capital Markets

Daniel Eggers – Credit Suisse

Brian Russo – Ladenburg Thalmann

Brandon Blossman – Tudor Pickering

Angie Storozynski – Macquarie Capital

Karen Miller [ph] – Libertus [ph]

Dynegy Inc. (DYN) Q3 2009 Earnings Call Transcript November 5, 2009 9:00 AM ET

Operator

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.

Norelle Lundy

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.

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.

Holli Nichols

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, Midwest adjusted EBITDA rose period-over-period due to higher realized energy prices that were contracted prior to the market downturn. These benefits were partially offset by the net expense of purchasing options for the benefit of future periods.

Our base load coal fleet achieved 92% in market availability, which means that we generally were in the market running when the market called on us to do so. However, production volumes in the region were down 7% primarily due to reduced runtimes at our cold facilities. This was largely related to decreased demand for our coal plants due to the economy, mild summer weather, and increased off-peak wind generation.

This decline was partially offset by increased volumes related to our natural gas combined cycle facilities, which experienced increase runtimes due to coal to gas switching in PJM. More specifically, looking at our Midwest segment we saw a 12% decrease in our coal volumes, which was partially offset by a 15% increase in gas volume, and actual combined cycle volumes were up 35%, which was offset by reduced runtimes for the peakers.

Moving on to the west, adjusted EBITDA increased by 35% primarily due to increased capacity and tolling revenues and the net benefit of selling options for future periods. This was partially offset by a 5% decline in volumes in the West due to the weak spark spread caused by lower demand and mild weather.

Finally in the Northeast, adjusted EBITDA increased by 30% primarily due to higher runtimes at our combined cycle facilities and the net benefit of selling options for future periods. Production volumes in the Northeast increased overall by 20%. Our combined cycle facilities benefited from coal to gas switching in the region. In addition, our Independence and Casco Bay facilities benefited from reduced transmission congestion. This was partially offset by reduced runtimes for our coal and oil fired units due to compressed spark spreads.

And finally, our Danskammer coal facility achieved 95% in-market-availability, which means that when it was economic for Danskammer to run it did so 95% of the time. For more detailed information on our segment performance during the third quarter, you can refer to the appendix of this presentation.

Please turn to slide seven. Now let us turn to 2009 guidance estimates. I'm going to focus on adjusted measures; the GAAP measures are included at the bottom of this slide and in more detail in the appendix of the presentation. The estimates we are providing today are based on $3.97 per MMBtu 2009 for gas curve as of October 6, 2009.

Dynegy’ is raising and tightening its 2009 adjusted EBITDA range to $730 million to $760 million. This range has improved largely due to the sale and assignment of the multi-year power sales contract I mentioned previously, which resulted in the accelerated recognition of $30 million. In addition, there were various other individually small items that in aggregate were a benefit. These benefits were partially offset by net purchases of options, which we use as part of our commercial strategy in our attempts to collar [ph] our exposure to changes in commodity prices.

Our improved adjusted EBITDA also benefits adjusted cash flow estimates. However, this benefit is offset by an economic decision to increase cash collateral postings related to contracting for years 2010 and 2011. As a reminder, with regard to many of our power and gas divisions we utilize a clearing agent in order to net position. While using an agent creates efficiency in terms of collateral requirements, we still expect to have posted an additional $185 million in cash in 2009 in support of these positions.

Utilizing cash is currently the most efficient and less costly means of collateralizing the companies hedging programs, we would earn less on cash investments than we would pay to post letters of credit. It is worth noting though that we could decide to exchange letters of credit for cash resulting in a significant cash inflow. And this will depend upon the economics of our cash needs.

With that as background, our projected range of adjusted cash flow from operations is now $75 million to $105 million and our estimated adjusted cash flow range is projected to be an outflow of $425 million to $395 million.

With that I will move on to a discussion of 2010 estimates and regional performance drivers. Please turn to slide nine. Our annual results are driven primarily by power prices, spark spreads and our participation in capacity markets. And that is what I will focus on as we cover the Midwest, West and Northeast regions.

This overview reflects our generation profile, pro forma for the expected close of the LS Power transaction, and going forward we will have a 13,000 MW portfolio focused on three regions of the country. When we look at adjusted EBITDA by region, the Midwest remains our largest contributor at approximately 65%, and while our coal fleet is responsible for half of our adjusted EBITDA, our combined cycle fleet is becoming a larger contributor, particularly in a low natural gas price environment accounting for approximately 45% of adjusted EBITDA.

For each region, I will cover the performance drivers including the price at which we sell energy and capacity type products, our cost structure and our hedging profile. I will also spend some time focusing on what to look for in each region. For those of you who are modeling us, this will help you understand the variables that can influence regional performance, and we’ve included even more regional detail in the appendix.

Finally, I will cover capital expenditures over the next five years, our current thinking on liability management, and 2010 guidance estimates. Please turn to slide 10, and we will start with our Midwest segment. The Midwest segment includes base load coal, combined cycle and peaking generation in MISO and PJM. The estimates we are projecting include volumes of approximately 25 million MW hours and adjusted EBITDA range of $370 million to $465 million.

Let us begin by considering some of the regional performance drivers that will shape our 2010 results. Given that we are contracted, power price volatility at CIN Hub should not impact our base load plans. Also the outright spark spread can dictate the runtimes and margin related to our Kendall and Ontelaunee combined cycle plans. Looking at cost, our Midwest base load coal fleet uses low-cost Powder River Basin coal, and we have strategic contracts that lessen our exposure to the volatility of the spot coal market.

Taking a closer look, our PRB and rail transportation cost is fully contracted through 2010 at fixed pricing. The 2010 average delivered cost at PRB at our Baldwin facility is a $1.49 per MMBtu, and this cost is unchanged from 2009. Another Midwest cost relates to our multi-year environmental investment that has already resulted in a significant reduction of coal plant emissions.

Here are some of the things to look for in the Midwest region next year. In MISO, coal generally sets the marginal price of power, while in PJM natural gas sets the marginal price of power. Those of you, who are modeling us, will want to track the CIN Hub to Illinois Hub basis differential as this too can impact our margins.

And you will also want to watch capacity markets in MISO and PJM. Looking at the graph on the right-hand side of the slide, you can see our relatively attractive positioning on the MISO [ph] and that most of our coal facilities are in the money and minimum load situations.

Turning to our hedging profile in the Midwest, currently more than 95% of our expected generation for 2010 is contracted, while approximately 50% is contracted for ’11 and we remain open in 2012.

Please turn to slide 11. Now we will shift our attention to the West region, which includes combined cycle and peaking natural gas-fired units. The dynamics of our West segment are quite a bit different from our Midwest region, and you will see a whole new set of performance drivers.

We are estimating volumes at approximately 7 million MW hours for the West with an adjusted EBITDA range of 130 million to 140 million. I would like to point out that approximately 70% of our estimated adjusted gross margin is attributed to tolling agreements in the near-term. Regional drivers include the spark spread for gas-fired combined cycle and peaking units. On the cost side, tolling counterparties take the financial and delivery risk of natural gas. For units that are not operating with tolling arrangements, we purchased fuel and oil as needed at index prices.

In terms of what to look for next year, operational performance will be important if the majority of our plans operate under term contracts. This means that if they are not running, we may have to buy replacement power from other sources, which can impact our margins.

In a market where natural gas sets the marginal price of power, a look for spread variability could be mitigated by toll contracts. Additionally, weather can impact uncontracted volumes generated by our combined cycle units. Moving on to the impact of regulations, we frequently get questions about the impact of proposed state level once-through cooling regulations on our California assets. Under the draft regulations, and specifically relating to our (inaudible) combined cycle unit, we would be looking at various options for reducing environmental impact, and would have until 2017 to develop solutions. We would have until 2012 to develop solutions for South Bay, and 2015 for Morro Bay.

As an active stakeholder in the process, we are continuing to monitor the development of the regulation, which are expected to be finalized in early 2010. Our three plants are among 19 others in California that use once-through cooling, including two nuclear plants and together these plants provide approximately 20% of the state's generation. On of our older California plans South Bay, near San Diego, has received RMR designation for 2010 from ISO for two of its units. Its two remaining units did not receive RMR for 2010, and we’ve therefore initiated the process of decommissioning those two units with plans to retire the others when their reliability services are no longer required.

In terms of our hedging profile in the West, we tend to be more contracted than in our other regions due to the uncertainty of hydro capacity available. In the West, more than 95% of our expected generation for 2010 is contracted. Approximately 50% is contracted for 2011 and 15% is contracted for 2012. As will be typical for an intermediate and peaking fleet, our West assets operate in times of greater than average load conditions.

Please turn to slide 12. Now I will cover our Northeast segment. Investors can think of Northeast as a hybrid region for Dynegy. Our fleet includes low (inaudible) combined cycle units in Upstate New York and Maine as well as coal-fired base load facility, and a large fuel load asset [ph] in New York.

In the Northeast, we are projecting generation volume of 6 million MW hours with a range of adjusted EBITDA of 60 million to 80 million. Our Danskammer facility is affected by power prices in New York Zone Guidance, while Roseton is affected by the spark spread in Zone G. Our Independence plant in New York is affected by spark spread for New York Zone C, while our Casco Bay facility in Maine is affected by spark spreads in Mass Hub.

With regard to cost, our Danskammer facility uses South American coal, and the majority of our coal supply is contracted in 2010 at a delivered price of $3.55 per MMBtu. For our combined cycle plant, natural gas is purchased as needed at index related prices. The final cost performance driver is the implementation of RGGI, and its impact on our overall cost of operations.

Dynegy will continue to secure sufficient allowances to meet our operational requirements. We estimate allowance cost of 10 million to 15 million in 2010. Now let us consider what to look for in the Northeast region, where natural gas sets the marginal price of power.

Look for the impact of weather on the run times of our combined cycle fleet as well as our Roseton facility. As for our hedging profile in the Northeast, more than 95% of our expected generation for 2010 is contracted. Approximately 60% is contracted for 2011 and 10% is contracted for 2012.

In terms of dispatch, we have three plans that are well-positioned in the minimum to average load range as well as two others that only operate during peak load conditions.

Please turn to slide 13. This slide is our current view of anticipated capital expenditures in the 2009 to 2013 timeframe. As you can see, our anticipated total CapEx dropped significantly from 530 million in 2009 to $345 million in 2010. Environmental CapEx decreases from $280 million to $200 million in the same timeframe period.

This largely relates to the winding down of our (inaudible) reinvestment, which include baghouses, dry scrubbers, and mercury control projects at 8 core units in Illinois. Combined with our earlier state line conversion to low-sulphur PRB coal, we expect to see reductions in sulphur dioxide and mercury of approximately 90% as well as significant drops in particulate and other emissions.

Additional factors in the reduction of CapEx relate to the anticipated sale of certain assets to LS Power as well as our previously announced cost savings initiatives, which is expected to produce total CapEx, operating and G&A expense savings against our original plan of $400 million to $450 million over the next four years.

Please turn to slide 14. In this slide, I would like to provide some color on the liability management plan that we are considering following the completion of the LS Power transaction. Dynegy is currently exploring alternatives for use of its excess liquidity following the anticipated closing of the transaction, and we prefer a program focused on addressing the near-term obligations.

The current 2010 financial estimates that I will review with you next assume will deploy approximately $800 million of cash to retire or decrease near-term obligations in December of 2009. The deployed amount can vary upon actual execution of the final program, but these assumptions are a reasonable stakeholder for modeling purposes until actual amounts and uses are announced.

The bottom line is the liability management program will be designed to address near-term maturities, reduce fixed cost and maintain ample liquidity, all the while preserving a simple flexible capital structure that is well integrated with our commercial strategy.

Please turn to slide 15. Now I will cover our consolidated 2010 earnings estimates. I'm going to focus on adjusted measures; the GAAP measures are included at the bottom of this slide, and in more detail in the appendix of this presentation. The estimates we are providing are based on a $6.15 per MMBtu 2010 forward gas curve. As of November 3, the 2010 curve was $5.61. Today we are reaffirming adjusted EBITDA of $425 million to $550 million for 2010. This includes a contribution of $560 million to $685 million from our generation business segment and use of $135 million from other, which primarily include G&A offset by interest income.

We are projecting a range of adjusted cash flow from operations of negative 15 million to positive 110 million, which includes interest payments and working capital. Taking into consideration maintenance CapEx of 120 million, environmental CapEx of 200 million, and capitalized interest of $25 million, we are projecting an adjusted free cash flow range of negative 360 million to negative 235 million.

Please turn to slide 16. Our expected range of adjusted EBITDA continues to be sensitive to several factors, some of which are beyond our control, and the outcome and timing are difficult to predict. This graph demonstrates the sensitivity of our generation business and our adjusted EBITDA estimate to natural gas commodity pricing, based on our hedged profile for 2010, which is more than 95% of expected generation contracted on a consolidated basis.

The horizontal X axis represents possible changes in natural gas and power prices. With 95% of our expected generation contracted, the impact of natural gas price volatility is reduced. The vertical Y axis reflects the potential variability and other assumptions, most notably the volatility of commodities, basis differentials, capacity prices and unplanned outages.

We tried to help quantify sensitivities in the appendix to further assist you in the modeling efforts, and demonstrate how to think about future periods based on your views of the market. We worked to provide transparency around our 2010 guidance estimates, and while these estimates are lower than 2009 due to weak commodity pricing; we believe we are managing through these difficult times with a focus on maintaining adequate liquidity, and providing earnings predictability.

With that I want to thank you for your time and turn it back over to Bruce.

Bruce Williamson

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 savings that could be achieved through combinations. In the meantime, Dynegy will continue to focus on operating and commercializing well and maintaining ample liquidity.

Please turn to slide 19. The next two slides provide more information on our current plus one and two-year commercial strategy and how it reflects industry fundamental. In the near to intermediate term, we are essentially fully contracted to increase predictability of earnings and cash flow, while protecting against downside risk. Our commercial arrangements include tolling agreements, financial swaps, collars, and a variety of options.

The percentage of expected generation volumes we contracted on a consolidated basis, currently stands at essentially 100% for 2009 and about 95% for 2010. At the beginning of October, we were about 50% contracted for 2011. As we have in the past, we will continue to contract 2011 as we see market opportunities. Our long-term strategy is to stay relatively uncontracted in the outer years. This would provide opportunities to capture where value as the economy strengthens and supply and demand tighten.

Please turn to slide 20. This slide touches on an important point surrounding our commercial strategy that is we are constantly working to capture value around our assets. While 2010 expected volumes are substantially contracted, our use of options allows for the capture of some additional upside, while mitigating some downside exposure to lower commodity prices.

The sliding scale in the centre of the slide shows the impact of the dollar moment in natural gas on an adjusted EBITDA basis. The almost fully hedged portfolio, the impact would be a positive or negative $15 million. Conversely in the outer years, which are less hedged adjusted EBITDA would be more sensitive to commodity price movements, as you can see dollar movement results in a potential change to adjusted EBITDA of positive or negative 165 million.

To the extent that a year is partially contracted, sensitivities need to be adjusted between these two numbers. The bottom line is that the contracted percentages for expected generation volumes of base load and intermediate assets are dynamic, and may be adjusted to capture upside or mitigate downside risk. We believe our base load and intermediate assets will be among the best positioned assets to capture value.

The expected impact of recovery on our base load coal assets would include widening dark spreads as natural gas prices rise and heat rates expand. In addition intermediate dispatch combined cycle plants will benefit from increased runtime as heat rates expand.

Before opening up to your questions, I would like to wrap up this morning's prepared remarks by talking about the steps we have taken to date in 2009 to capture value. Please turn to slide 21. Let us look at what we have said and what we have done. We said we would continue to focus on operating our assets well, and we have delivered on that by maintaining our focus on reliable low-cost production with 90% in-market availability for our base load coal fleet.

We said, we would maintain ample liquidity, and have done so. In addition, upon the anticipated closing of the transaction we announced on August 10, our liquidity will improve significantly positioning the company for a substantial debt production, which will also redeem about 30% of our outstanding common stock.

We said we would improve our commercial execution to protect near-term cash flows, and again we have delivered on that as evidenced by our tightening and raising of the 2009 guidance range. In terms of our commercial approach, we are following our current plus one and two-year strategy, remaining open in the outer years to capitalize on improvements in economic and market conditions.

And finally, we said we would continue to focus on managing cost. In response, we have launched an aggressive cost savings initiative with anticipated total savings estimated at $400 million to $450 million over the next four years. During 2009, we delivered on what we said we were going to do. We can’t control the tough market conditions, but we can and did work hard to respond to the challenges that we have faced.

Today we’ve positioned ourselves to deliver long-term value to our investors as market conditions improve.

Operator, we will take the first question now.

Question-and-Answer Session

Operator

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

Brian Chin - Citigroup

Hi good morning.

Bruce Williamson

Hi Brian.

Brian Chin - Citigroup

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?

Bruce Williamson

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.

Brian Chin - Citigroup

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?

Holli Nichols

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.

Brian Chin - Citigroup

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?

Bruce Williamson

Completely separate from those assets.

Brian Chin - Citigroup

Right. Thanks a lot.

Bruce Williamson

Okay.

Operator

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

Neel Mitra - Simmons & Co.

Hi good morning.

Bruce Williamson

Hi, how are you?

Neel Mitra - Simmons & Co.

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?

Holli Nichols

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.

Neel Mitra - Simmons & Co.

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?

Holli Nichols

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.

Charles Cook

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.

Bruce Williamson

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.

Neel Mitra - Simmons & Co.

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?

Bruce Williamson

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

Neel Mitra - Simmons & Co.

Okay.

Bruce Williamson

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

Holli Nichols

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

Bruce Williamson

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.

Lynn Lednicky

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.

Neel Mitra - Simmons & Co.

Okay, great. Thank you very much.

Bruce Williamson

Thanks Neil.

Operator

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

Bruce Williamson

Hi Lasan.

Lasan Johong – RBC Capital Markets

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?

Bruce Williamson

Holli, you covered some of that in your segment.

Holli Nichols

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.

Bruce Williamson

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

Holli Nichols

Mild summer weather…

Bruce Williamson

…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.

Charles Cook

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.

Lasan Johong – RBC Capital Markets

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?

Bruce Williamson

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.

Lasan Johong – RBC Capital Markets

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…

Bruce Williamson

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

Lasan Johong – RBC Capital Markets

Okay, defensive.

Bruce Williamson

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.

Lasan Johong – RBC Capital Markets

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.

Bruce Williamson

Which one?

Lasan Johong – RBC Capital Markets

South Bay. I think you guys --

Charles Cook

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 --

Bruce Williamson

And reserving cost in a segregated account.

Charles Cook

Right. So --

Lasan Johong – RBC Capital Markets

No plans for repowering?

Bruce Williamson

No.

Charles Cook

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

Lasan Johong – RBC Capital Markets

Got you. Thank you.

Bruce Williamson

Okay.

Operator

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

Daniel Eggers – Credit Suisse

Hi, good morning.

Bruce Williamson

Hi Daniel.

Daniel Eggers – Credit Suisse

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?

Bruce Williamson

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

Daniel Eggers – Credit Suisse

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

Bruce Williamson

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

Daniel Eggers – Credit Suisse

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?

Bruce Williamson

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

Charles Cook

That's correct.

Daniel Eggers – Credit Suisse

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?

Bruce Williamson

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.

Daniel Eggers – Credit Suisse

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

Bruce Williamson

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.

Daniel Eggers – Credit Suisse

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

Holli Nichols

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.

Daniel Eggers – Credit Suisse

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.

Holli Nichols

That's correct.

Daniel Eggers – Credit Suisse

Okay, thank you.

Operator

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

Brian Russo - Ladenburg Thalmann

Hi, good morning.

Bruce Williamson

Hi Brian.

Brian Russo - Ladenburg Thalmann

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?

Holli Nichols

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

Brian Russo - Ladenburg Thalmann

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

Holli Nichols

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

Bruce Williamson

Market negotiated term.

Holli Nichols

Right.

Brian Russo - Ladenburg Thalmann

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

Holli Nichols

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.

Brian Russo - Ladenburg Thalmann

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?

Holli Nichols

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.

Bruce Williamson

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.

Brian Russo - Ladenburg Thalmann

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?

Bruce Williamson

Lynn.

Lynn Lednicky

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.

Brian Russo - Ladenburg Thalmann

Okay.

Bruce Williamson

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.

Lynn Lednicky

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

Brian Russo - Ladenburg Thalmann

Okay, great. Thank you.

Bruce Williamson

Okay.

Operator

Brandon Blossman with Tudor Pickering. Your line is open.

Brandon Blossman - Tudor Pickering

Good morning guys.

Bruce Williamson

Hi Brandon.

Holli Nichols

Good morning.

Brandon Blossman - Tudor Pickering

How are you doing?

Bruce Williamson

Good.

Brandon Blossman - Tudor Pickering

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?

Bruce Williamson

Chuck.

Charles Cook

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…

Bruce Williamson

Buying puts and selling calls.

Charles Cook

Sorry, buying puts, selling calls.

Brandon Blossman - Tudor Pickering

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

Bruce Williamson

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

Brandon Blossman - Tudor Pickering

Okay, up to price of the caller.

Bruce Williamson

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.

Brandon Blossman - Tudor Pickering

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?

Bruce Williamson

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.

Brandon Blossman - Tudor Pickering

That's all I have. Thanks guys.

Bruce Williamson

Okay.

Operator

Our next question comes from Angie Storozynski with Macquarie Capital.

Angie Storozynski - Macquarie Capital

Thank you.

Bruce Williamson

Hi, Angie.

Angie Storozynski - Macquarie Capital

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?

Bruce Williamson

No, not at all.

Holli Nichols

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.

Bruce Williamson

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.

Angie Storozynski - Macquarie Capital

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?

Holli Nichols

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.

Angie Storozynski - Macquarie Capital

That's great. Thank you so much.

Bruce Williamson

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

Operator

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

Bruce Williamson

Hi Karen.

Karen Miller - Libertus

Good morning Bruce. How are you?

Bruce Williamson

Good. How are you?

Karen Miller - Libertus

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

Bruce Williamson

That's fine.

Karen Miller - Libertus

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?

Holli Nichols

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.

Karen Miller - Libertus

Okay.

Bruce Williamson

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.

Karen Miller - Libertus

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?

Holli Nichols

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

Karen Miller - Libertus

Okay, thank you very much.

Bruce Williamson

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

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Source: Dynegy Inc. Q3 2009 Earnings Call Transcript
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