Dyne Therapeutics, Inc.
Q1 2009 Earnings Call Transcript

Published: 7 May 2009

[Operator:]

Hello and welcome to the Dynegy Incorporated first quarter 2009 financial results teleconference. At the request of Dynegy, this conference is being recorded for instant replay purposes. Please note that all lines will be in a listen-only mode until the question-and-answer portion of today’s call. (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 webcast, highlighting the company’s first quarter 2009 results. 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 business strategy and 2009 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 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 this morning are several members of our management team, including Holli Nichols, our Chief Financial Officer. Let’s now turn to the agenda for our call, which is highlighted on slide three for those of you following along. I’ll begin today by discussing first quarter highlights and some key market observations. Holli will then provide first quarter financial results, discuss regional performance drivers for the quarter, and provide an update on our commercial strategy and 2009 estimates. I’ll then wrap up by discussing why we believe Dynegy is well positioned to weather the current economic environment and then we will go to Q&A. Please turn to slide four. 2009 continues to be a difficult year due to the downturn of the global economy and the corresponding impact on commodity prices. In turn, lower commodity prices impact our results. However, to some extent, Dynegy’s diversified portfolio and commercial strategy are helping to mitigate the affect of lower market prices. As the table demonstrates, power prices in all of our key regions declined period-over-period. However, first quarter production volumes in total increased approximately 10%, with stronger production particularly from our natural gas-fired facilities. On peak market heat rates increased in our key regions as well, leading to higher utilization of our gas plants. Additionally, we have significantly increased our contracted percentage of expected generation in 2009 to protect cash flows and increase 2009 earnings predictability. We have also maintained a capital structure that as of May 1 included available liquidity of approximately $2.1 billion, including $829 million in cash. Finally, after the end of the quarter, we closed on the sale of the Heard County peaking facility in Georgia, which brought in $105 million in cash. This sale is consistent with previous divestitures of assets located outside our three key regions, the Midwest, Northeast and West. It’s also consistent with our strategy in selling non-core assets for a value that we believe is greater than what we can earn by holding and operating the assets ourselves. Please turn to slide five. On a national level, US power generation declined by about 3% period-over-period in the first quarter according to EDI. However, US generation still remains slightly above the five-year average. As I mentioned, our generation production actually increased by about 10% period-over-period. Production volumes were up in two of our three regions for the first quarter. Despite lower power prices, Dynegy’s geographic and fuel diversity provides an opportunity to partially mitigate declining dark spreads associated with our baseload coal generation. In the Midwest, our overall production volumes increased by about 10% due to warmer winter temperatures. This was primarily driven by increased production from our natural gas-fired units. In the Northeast, cooler than normal weather and lower fuel prices drove a 60% increase in our production volumes. Roseton, a dual-fired facility, but this let past quarter predominantly fuel oil-fired, and Independence, combined cycle natural gas-fired facility, showed significant increases in production volumes period-over-period. In the West, warmer temperatures led to a 40% decline in our production volumes period-over-period. Please turn to slide six. Now I’d like to address some concerns about coal to gas switching, the situation that occurs when more economically efficient combined cycle natural gas plants displace less efficient coal-fired plants in the generation stack. A recent EIA report on power production indicates that coal volumes declined in parts of the US, primarily in Texas and the southeast regions. This has led to speculation about coal to gas switching more broadly. First, Dynegy does not have production in these regions of the country. In fact, 90% of our coal fleet is based in the Midwest, and while we have experienced a tightening of dark spreads in the Midwest due to lower power prices, we have not seen the effects of significant coal to gas switching in the region. Drilling down a little more here, before this issue could materially impact the run times of our economically efficient coal facilities, which are depicted by arrows on the left side of the graph, 30,000 to 35,000 megawatts of coal generation would have to be displaced in the market. What’s more? Dynegy’s entire Midwest fleet burns Powder River Basin or PRB coal. Our favorable fixed price PRB coal and rail contracts give the Midwest coal fleet a relatively low dispatch cost. Therefore, our more economically efficient coal units can avoid the coal to gas switching that may be impacting other coal-fired generators, particularly those that use higher price Appalachian and Illinois coals and selling to regions where natural gas is largely on the margin, like ERCOT and other regions of the country. To the extent that natural gas assets displace less efficient coal units in the Midwest, our combined cycle gas facilities in the region are benefiting from additional run times. Before moving on, I’d like to say that we view coal to gas switching is a short-term impact that is ultimately self-correcting in nature. You should assume that if more natural gas is used for generation, the increased demand will raise the price of natural gas, which will in turn improve the economics of low-cost baseload coal-fired generation. The key takeaway is that coal plays a critical role in the Midwest power generation market, and we do not expect coal to gas switching to be a major factor in the region where most of our coal assets are located. In fact, the Midwest simply does not have enough natural gas capacity to meet even average, much less peak load requirement. Please turn to slide seven. In preparing the low dispatch cost of Dynegy’s Midwest fleet to our competitors, we believe we have some key cost advantages. Due to our favorable PRB coal and rail contracts, our Midwest coal fleet has a cost of dispatch of approximately $20 per megawatt-hour compared to about $24.50 per megawatt-hour dispatch cost related to spot PRB and rail prices. This is also a significant advantage over coal-fired units using Central Appalachian and Illinois coal. Our Midwest combined cycle facilities are also advantaged in the low natural gas price environment and we are seeing increased utilization from these assets. With a typical dispatch cost of about $27 per megawatt-hour, they can be more economical than some competitors’ non-PRB coal-fired units. The bottom line here is despite tightening dark spreads, we believe we have a competitive cost advantage in a low natural gas price environment. Please turn to slide eight. Switching gears here, we have received many questions regarding basis and how we can mitigate this risk. Basis is essentially the price difference between the location of a plant where the power is produced and the location where the power is sold. For us, basis is more of an issue for our Southern Illinois fleet because of the distance between our plants and the CIN Hub location where we sell forward. Basis can be volatile due to physical limitations of transmission, factors that include congestion, line loss, and line and plant outages, all of which can further be impacted by the weather. We also tend to experience higher basis during the spring and fall outage seasons. There are a number of options available to partially mitigate basis risk. However, keep in mind that each tool has limitations. Over the short-term, we can purchase Financial Transmission Rights, enter into basis swaps, or simply sell locally. We can also consider investing or partnering in transmission upgrades that go directly to the source for a longer term solution. With our risk management efforts, the impact of basis during the first quarter was in line with our previous estimates. However, basis is trending higher for the balance of the year, which could impact earnings. We will continue to actively monitor market conditions and exercise options to help mitigate basis risk where and when appropriate, subject to the limitations we mentioned earlier. With that, I’d like to turn it over to Holli to cover first quarter results.

[Holli Nichols:]

Thanks, Bruce. Before starting, I’d like to point out that these materials do contain non-GAAP measures that are reconciled in the appendix of this presentation for your reference. Now let’s turn to slide ten for a look at our first quarter highlights. Adjusted EBITDA decreased by 16% from $237 million in the first quarter of 2008 to $198 million in the first quarter of 2009. This is primarily due to lower realized power prices period-over-period, partially offset by higher volumes. On a GAAP basis, we reported a net loss of $335 million for the first quarter of 2009, which reflects goodwill impairment charges of $433 million. The goodwill impairment charges resulted from the impairment test that compared book values to market values, in light of the significant drop in forward power prices, further deterioration in the economic condition and a sustained decline in the company’s market capitalization. Impairments were recognized reducing the book value of our operating assets. We have more information in our first quarter 2009 Form 10-Q, which will be filed later today. The goodwill impairment charges were partially offset by $105 million in after-tax mark-to-market gains, which reflect the decrease in prices over the quarter. The net loss in ’09 compares to a net loss of $152 million in first quarter 2008, which included $173 million in after-tax mark-to-market losses. Moving on to capital and liquidity, as of March 31, 2009, Dynegy had net debt and other obligations of approximately $5 billion and collateral postings of $1.4 billion. Liquidity was approximately $1.9 billion, with $722 million of cash on hand. Before moving on to regional drivers, I wanted to address a question many of you have asked regarding the calculation of our financial covenants. We have worked with many of you individually to understand the mechanics behind the ratios, which are contained in our publicly available credit documents. However, we have included the calculations in the appendix of this presentation for your convenience. In looking at the maintenance covenants, we do expect a temporary loss of revolver capacity later this year, but we would expect to remain in compliance with the interest coverage ratio. Please turn to slide 11 for a discussion of our performance drivers for the quarter by region. Lower pricing is the key takeaway for the first quarter of ’09 results, leading to the 16% reduction in adjusted EBITDA period-over-period. On a more positive note, our operational highlights included achieving 88% in market availability for our baseload coal fleet, and volumes were up in Midwest and the Northeast driven by higher run times for our combined cycle and peaking assets. Starting with the Midwest, earnings were down quarter-over-quarter as lower realized power prices were only partially offset by the benefit of higher volumes. We saw higher volumes, a combined cycle, and peaker facilities, which doubled due to lower natural gas cost and higher heat rates. In the West, adjusted EBITDA was up slightly, even though milder weather and decreased spark spreads led to a 40% decrease in production from combined cycle facilities. Since the West is significantly contracted by agreements that are not based on run times, such as tolling and RMR contracts, the 40% decline in volume did not have a corresponding impact on adjusted EBITDA. In fact, tolling revenue increased approximately $4 million. In the Northeast, results were essentially flat quarter-over-quarter, as lower realized power prices were almost completely offset by a 60% increase in volumes. At our Roseton facility, the volumes increased due to colder winter weather and low fuel prices. Our combined cycle facilities saw higher volumes as well. As Bruce noted, the Independence plant volumes increased period-over-period as a result of improved spark spreads. For more detailed information on our segment performance during the first quarter, you can refer to the appendix of this presentation. Please turn to slide 12. We had one notable change in the timing of our CapEx projections. Maintenance CapEx will increase in 2009 by $40 million, as we shift some expenses related to our Moss Landing facility into the current year. That facility will reach 24,000 run hours earlier than originally planned, and that milestone will trigger a major inspection in 2009 rather than 2010. This advanced scheduled outage will negatively impact 2009 CapEx, gross margin, operating expense, and adjusted EBITDA. Otherwise, our CapEx projections remain unchanged. We continue to make progress on our Midwest environmental investments to further reduce emissions. The Midwest environmental projects, which will run to 2012 and remain on the required schedule, include baghouse and scrubber projects at eight of our Illinois units. Our Midwest coal fleet already has reduced emissions as sulfur dioxide and nitrogen oxide by approximately 90% in the last ten years largely to our conversion to the PRB coal. The baghouses and scrubbers are designed to further reduce mercury particulates and sulfur dioxide emissions. Please turn to slide 13. On recent conference calls, we told you about our decision to increase near-term contractive positions to add predictability to adjusted EBITDA. At that time, we stated that we had contracted approximately 90% of our expected generation for 2009. As of April 7th of ’09, the percentage of expected generation volumes we have contracted on a consolidated basis has increased to more than 95%. This means that plus-95% of the energy we expect to produce in 2009 has been contracted with either a physical or a financial sale. Although 2009 volumes are nearly fully contracted, our guidance range, which I’ll cover in a minute, is subject to variability due to possible impacts from a number of factors, including unplanned outages, weather, basis, market implied heat rate, capacity, and commodity price volatility. Lastly, I would add that we are actively contracting 2010 and we’ll provide more details later in the year. Please turn to slide 14. When we provided 2009 guidance estimates in February, we demonstrated the sensitivity of our generation business and our adjusted EBITDA estimates to natural gas commodity pricing based on the then current level of hedging by using this graph. As a reminder, the X-axis represents average prices for natural gas and the Y-axis reflects the potential variability and other assumptions, most notably, unplanned outages, weather, basis, market implied heat rates, commodity price volatility, and the ability to sell uncommitted capacity. Today, our expected range of adjusted EBITDA continues to be in the forecasted band that we provided in February when you consider the commodity price sensitivities we provided and what has happened to commodity prices since then. Since February, annual average natural gas price has declined from approximately $5 to approximately $4.20 per Mmbtu. Based on the sensitivities given in February, the dollar price change in natural gas resulted in a $20 million change to adjusted EBITDA. Therefore, the bottom end of our prior range of $700 million has shifted downward to $680 million. Because we are over 95% contracted today, our adjusted EBITDA will be even less sensitive to natural gas prices for the balance of the year. Now, in looking at our Y-axis, the top end of the range has decreased to $740 million due to a number of factors, including the decline in power and capacity prices, the acceleration of the Moss Landing outage, and basis differentials. Our updated range for 2009 adjusted EBITDA is now $680 million to $740 million. Please turn to slide 16. Now turning to more details regarding our 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 this presentation. I’ve just walked you through adjusted EBITDA, so let’s focus on cash. Our projected range of adjusted cash flow from operations is from $140 million to $200 million. As I mentioned earlier, maintenance CapEx is increasing by $40 million because Moss Landing outage has been moved to the fall of 2009 from the spring of 2010. That leaves us to a change in our estimated adjusted free cash flow range, which is now projected to be an outflow of $300 million to $360 million. With that, I want to thank you for your time and turn it back over to Bruce.

[Bruce Williamson:]

Thanks, Holli. Please turn to slide 17. In closing, I want to leave you with some key takeaways. First, Dynegy’s diverse portfolio and current liquidity are important tools in helping to mitigate uncertainties in the low commodity price environment, which we expect to continue in the near-term. While the US power demand has slowed, two of our three regions actually experienced increased production volumes in the first quarter of 2009, which demonstrates the advantage of having a diverse fleet in terms of geography and fuel price. Even in a low commodity price environment, our Midwest coal fleet is not experiencing coal to gas switching. Also, our favorable delivered PRB coal and rail contracts provide a cost advantage for a Midwest coal fleet, helping to mitigate tightening dark spreads. In addition, some additional value can be captured by our well-positioned combined cycle natural gas fleet if or when coal to gas switching does occur. Also we believe our liquidity position now at approximately $2.1 billion is our most significant tool to weather out the current economic downturn. In addition, we don’t have significant debt maturities until 2011. And finally, in our cyclical energy business, we fully expect to see a rebound after this trough. As the energy markets recover, Dynegy’s fleets have the benefit from an increase in both power prices and demand. We believe our significant gas-fired fleet will see increased utilization and our entire fleet will participate in a heat rate expansion. And because our stock has leveraged both power prices and demand, we would expect benefits for investors as financial and energy markets recover. With that, let’s move on to the question-and-answer portion of our presentation. Operator, we will take the first call now.

[Operator:]

Thank you. The first call will come from Ameet Thakkar of Deutsche Bank. Your line is open.

[Ameet Thakkar:]

Good morning, guys.

[Bruce Williamson:]

Hi.

[Ameet Thakkar:]

Just wanted to ask you guys if you could kind of leave or remind us what are the auction rights provisions in your merger agreements with LS Power. Can they effectively put you guys up for sale?

[Bruce Williamson:]

Well, I mean, what LS can do after April, though now we are past that date, is really they are lockup ended. So prior to April, they had limitations on their ability to sell shares other than some very small amount, about 40 million shares or so. Now, post April, they can sell shares if they would like to, but it has to be in a widely dispersed offering where no party buying controls more than 15%. If they want to buy more shares than what they currently own, they have to make an offer for all and not less than all of the outstanding common shares. That offer would have to be received and be evaluated by the independent directors of the Board, much like any company would by a Board, and has to be viewed and judged as a full and fair value for all investors. And then after that, if that offer is rejected, then LS has an additional right, which is they can request the company to hold an auction. And again, any bids that would be received from that party or anyone else has to be judged by the independent directors to be at a full and fair value for all investors.

[Ameet Thakkar:]

Okay. And then just turning to MISO capacity pricing, we saw the results of Ameren’s capacity auction. There is not a centralized capacity market in MISO. I know it’s been largely a bilateral market. I mean, what takeaways should we take away from the results of that process?

[Bruce Williamson:]

Let me ask Chuck or Eric [ph] to weigh in on it.

[Chuck Cook:]

Well, I think in general what we’ve seen is the capacity prices are down a bit. We – you are correct. It is a bilateral market. There are a couple of auction process – prospects underway now. I guess – that’s all I got [ph].

[Ameet Thakkar:]

All right. Thanks.

[Bruce Williamson:]

Okay.

[Operator:]

Our next question comes from Dan Eggers from Credit Suisse. Sir, your line is open.

[Dan Eggers:]

Hey, good morning.

[Bruce Williamson:]

Hi, Dan.

[Dan Eggers:]

Can you just help a little bit – the EBITDA reductions, anyway help quantify how much was Moss Landing timing do you see now this year versus next year? Is that material to gross margin or more just (inaudible) free cash flow side

[Holli Nichols:]

Dan, it’s about $15 million or $20 million on an adjusted EBITDA basis. When you think about the downtime, obviously it’s not bringing in the energy revenues. And then you add to that the additional – there is always some OpEx in addition to the CapEx when you go around these projects. So the combination of those two is expected to be between $15 million and $20 million.

[Dan Eggers:]

Okay. I guess just kind of going back to the hedging strategy for 2010, with ’09 basically all full at this point in time, I know you guys are looking at transactions. But is there more in thought that you want to be more hedged even into ’10, or kind of where you think your target should be going into 2010 from a hedge position perspective?

[Bruce Williamson:]

Yes, Dan. I think more than in years past. I mean, given how the economy and the market environment is, I think right now people are putting a premium on predictability over upside. And so much like you saw us increase the amount when we came into 2009 over prior years and then quickly ramp it up into the year, I think we will end this year significantly higher going into ’10 than we would have in prior years.

[Dan Eggers:]

All right. Holli, Heard County is included in the free cash flow guidance for the year?

[Holli Nichols:]

It’s not included in free cash flow guidance. We take out things like asset sales.

[Dan Eggers:]

And that’s the only substantial adjustment we would make to the free cash flow numbers you guys gave?

[Holli Nichols:]

I think that’s right.

[Dan Eggers:]

And then I guess last question, you said that basis was trending wider than expected – wider than – it is showing wider than planned recently. Is that in guidance? And how do you see mitigating that if it’s continuing to slip away from you?

[Bruce Williamson:]

The short answer on it is yes, it’s in guidance. And what we wanted to point out is, you always have to look at where the forward is for it as well as where things have settled out at. The first quarter basically settled out about where we would have thought on average, and we were just highlighting for people that the forward is trended up, so that is incorporated.

[Dan Eggers:]

Okay. So the forward is incorporated at these levels. And I guess just one more on Ameet’s question around LS Power. If LS were to submit a bid, would that be public or would that – how would that come out if they were to look to be transactional?

[Bruce Williamson:]

Really no different than any other company. I mean, a company can receive an offer and then things become public when an agreement is entered into. And that’s when things would become public.

[Dan Eggers:]

So the (inaudible) conversation could be occurring now, but it wouldn't be public until later. Okay, thank you guys.

[Operator:]

Neel Mitra of Simmons International, you may ask your question.

[Neel Mitra:]

Hi. Do you attribute any of the increase in capacity factors to combined cycle plans from coal to gas switching in the first quarter? The capacity factors were like two to three times higher than last year in the Northeast and Midwest. Do you attribute all of that increase in capacity factor to colder weather in the mid-Atlantic?

[Bruce Williamson:]

I don’t know that we can drill it down and say how much was weather and how much was coal to gas switching. I mean, I think if there was any, I mean, it would have been pretty targeted probably around like Antalani [ph] in PJM or potentially I guess in the New York market. But I don’t know that we really – that we have a quantification for you of this much is weather and this much is coal-to-gas switching. Chuck, anything you want to add?

[Chuck Cook:]

No. I’d just say that the gas prices being down, (inaudible) being up, that tends to lead to more combined cycle generation, and that’s what we have.

[Neel Mitra:]

And then it looks like your Northeast and Midwest EBITDA estimates are staying roughly the same for 2009. Are you factoring in any increased combined cycle utilization like what we saw this quarter into those estimates?

[Holli Nichols:]

I think the way, Neel, to help from a perspective how we prepare our forecast is, we go in and I think – and for this particular update, we used April 7th pricing. And if the curves are implying that there is more run time around that portion of our fleet, that’s going to be built into guidance. If not, then it wouldn’t be in there. So we haven’t made a special adjustment to try to capture additional value in there. If the markets imply, then it’s there.

[Neel Mitra:]

Okay. And then lastly, how should we think about oil-fired utilization for the rest of the year now that fuel oil is trading at significant premium to natural gas? It’s your estimate of $25 million in adjusted gross margin still good for 2009 from Roseton?

[Bruce Williamson:]

Yes is the short answer. I mean, right now – I mean, Roseton tends to run obviously in either very cold weather in the wintertime or hot weather in the summertime. And again, much like Holli’s explanation of gas, we would be taking a look at the forwards and saying, okay, when does Roseton forecast to be in the money. It had a very good first quarter with low oil prices and cold weather in the Northeast. We would think that – obviously all the first quarter has been incorporated in and then we look forward for the summer, and it’s possible Roseton gets some more run time then in the summertime.

[Neel Mitra:]

Okay, thanks.

[Operator:]

Brian Chin from Citi, you may ask your question.

[Brian Chin:]

Hi, good morning.

[Holli Nichols:]

Good morning.

[Brian Chin:]

Quick follow-up question on Moss Landing. Since the maintenance event was pulled into ’09, is that a fourth quarter ’09 event?

[Holli Nichols:]

Yes, we expect – we had planned on it being in the spring of ’10 and it has been pulled forward to, yes, the fall. So it would be somewhere in the –

[Chuck Cook:]

October time frame.

[Holli Nichols:]

Yes.

[Bruce Williamson:]

It was October, Brian.

[Chuck Cook:]

October, November time frame.

[Brian Chin:]

October, November. Great. That’s it.

[Bruce Williamson:]

Okay.

[Operator:]

Lasan Johong, RBC Capital Markets, you may ask your question.

[Lasan Johong:]

Thank you. Good morning. Bruce, although you are not seeing any coal to gas switching in your fleet, I’m assuming your CCGTs are replacing somebody else’s coal output. Is that right?

[Bruce Williamson:]

All we can say is that we obviously experienced increased run time. I mean, as far as who experienced the decreased run time, I mean, that’s in effect a question for somebody else. I don’t know.

[Lasan Johong:]

Okay. And then –

[Bruce Williamson:]

I think it’s fair to say if you look at our slide seven, what we tried to do is lay out there some map to say, okay, well, if you are someone burning Illinois coal, a gas plant in the area probably has about $5 a megawatt-hour advantage on you. So the gas plant should increase its run time and the Illinois coal would decrease. If you are a Central App scrubbed plant in the area of a similarly situated gas plant, I don’t know that we’re a $1 – what's that, a $1.40 difference, I don’t know that we’re $1.40 smart there on everything. But it’s basically sort of saying that the gas plant and the Central App are kind of at a push with each other and so they are probably going playing tug-of-war back and forth. But it probably comes down at that point to what the Central App burners’ bidding strategy is. If they just want to go ahead and monetize coal on the stack and things like that, they may be running in order to just keep running. So it’s a little bit more of a push there.

[Lasan Johong:]

So let me tackle it from a slightly different aspect. It looks like at some point in time, your profitability actually increases as gas prices stride. At what point do you see a J curve kicking in on your fleet where gas prices going down actually helps your profitability?

[Bruce Williamson:]

Well, we are still – just when we look at the overall portfolio, we’re going to do better in a higher gas price environment because that’s going to derivatively then increase the price of power. And we are going to make more off of the dark spread, off the PRB burning plants more than we will be making off the gas plants. But I don’t know that we have a scenario that we do better in a low gas price environment. I think the best we can tell people is that the diversity helps to sort of mute the downside if we are just in the low commodity environment, if not just all downside for us, there is an offsetting positive that takes place, but it’s enough that it turns things around and we are sitting here timing for a low gas price environment.

[Lasan Johong:]

Okay. Now I’d agree you want to have a low gas price environment. Last question, Holli, you said – you mentioned that there was a potential restriction on your revolver availability. How long will that last in your mind? And I’m assuming you have no impact as you have enough cash. But how long would you think that restriction will last and when do you think it will start?

[Holli Nichols:]

Sure. I think – to just restate what you said, that I agree with you, that it’s not something that given our current liquidity and collateral postings that we were concerned about. But if you look forward, it is a rolling quarterly test. And so I would suspect the first time we expect to see a reduction would be in the summertime. And that’s something that is we estimate it’s plus or minus $250 million. And then it will just depend on how we – I don’t expect it to be – I would expect that to be for the year. I wouldn’t expect it to be any worse than that. And then the balance will be dependent upon when you start to roll into 2010.

[Lasan Johong:]

So basically roughly at most about six months?

[Holli Nichols:]

Well –

[Bruce Williamson:]

No, you tell me when the economy is turning and everything is trending sharply higher. I think that is the word of art and I keep hearing on CNBC is we are seeing sprigs of green. So –

[Lasan Johong:]

Okay. Appreciate the chat. Thank you very much.

[Bruce Williamson:]

Okay.

[Operator:]

Angie Storozynski, Macquarie Capital, you may ask your question.

[Angie Storozynski:]

Thank you. Let me just start with a question why we are not seeing any disclosure about your current level of hedges. I mean, we had in the past and I understand that you are working on your additional hedges for 2010. But should we assume then that nothing has changed since the last update, so you are still about 50% hedged for 2010?

[Holli Nichols:]

Angie, your focus is on ’10 versus ’09?

[Angie Storozynski:]

Yes.

[Holli Nichols:]

Okay. One of the things that we want to be careful about is that we have been active in 2010 and we have put on more positions since the last time we were on certainly. And that’s – it's a percentage that’s significantly high. I would say it’s 80% on a consolidated basis for the fleet. But what I would also say is that we want to be careful about what people read into that, because that is just for the energy volumes that we have sold forward. And as you know, our earnings are dependent upon several factors, that being one of them. But capacity markets, basis estimates, all those sorts of things will play into that as well. And that’s why we would look to give more information on our typical basis towards the end of the year and a give a full view of 2010 at that time.

[Angie Storozynski:]

But your assumption is that going into the summer months and closer to December when you issue guidance, you’re going to continue adding hedges for 2010?

[Holli Nichols:]

Well, as we’ve said, we would – if we are at 80% now, we said we would go into 2010, as Bruce mentioned, higher certainly than we have in the past. And we will be opportunistic in looking at opportunities. And if it makes sense, yes, we could put some more on or we could stay where we are at. So we’re not necessarily going to project the future changes in that figure as we sit here today. But again, that’s where we are.

[Bruce Williamson:]

To put it in perspective, I think in past years we’ve – the high going into a year was probably around 65% or so. And we’re telling you we’re basically already at around 80%. So we’re already well up above where we would have been in the past. And so I think you should expect that by the time we get to the end of the year, we’ll be at a pretty well – very high number.

[Angie Storozynski:]

Okay. And also the lowered guidance, the low end of the guidance, did you account for potential basis differential impacts? So the 670 or 680 number that we have now, does it incorporate any wiggle room for basis differential or is it just basically –? I mean, that’s my question.

[Bruce Williamson:]

Basically the forward curve – Chuck, you want to add anything?

[Chuck Cook:]

Yes. There is not a – we don’t have a forward curve for basis per se, but it reflects our current estimate for basis, which is higher than the number that we use for planning purposes when we put together our original plan and then our guidance estimates that we used in February.

[Angie Storozynski:]

Okay. Thank you.

[Operator:]

Gregg Orrill, Barclays Capital, you may ask your question.

[Gregg Orrill:]

Thanks. Two questions. Just a simple one first on ’09, what’s your EBITDA sensitivity now to a dollar change in gas? And then the second topic is just, if you could talk about prospects and timeline for the implementation of climate change legislation. It seems like the calendar has got pushed back. Maybe you can also talk about sort of the type of compromise that would be necessary to get something through the House this year. Thank you.

[Holli Nichols:]

Maybe I can take the first one. It’s fairly easy. Given that we, again, have plus-95% of our energy volume hedged, the sensitivity of gas, we didn’t run a new one and place it in here. But given that we were a dollar, was $20 million. When we were around 90% hedged, I would say at $15 million or less to a dollar change in gas going forward for the balance of ’09.

[Bruce Williamson:]

And Gregg, on your second question, I mean, I guess I could say, well, thankfully none of us in this room are in the House with the Senate. And so I don’t know that I have a projection or an estimate on what sort of compromise is going to be needed. There were a lot of hearings held in the last couple of weeks. A variety of people commented and provided I think constructive input in some cases. And I think it’s up in many ways to Congress to take a look at the issue, make a decision on whether this is the time to put something in place. I think what we would like to see as a company still would be a Federal program. We have one program to deal with administratively rather than a patchwork quilt of things from a variety of locations around the country. But I think importantly, people need to realize that whatever is put in place, it’s going to be an increase in cost. It’s going to be an increase in cost at the electric switch, the gas pump, jet fuel, plane tickets, FedEx packages, shipping, virtually anything in the US economy. And I think that needs to be thought through by Congress and come up with a plan so that there is a way to migrate the US consumer and the US economy to this rather than to shock the system. I think we’ve got enough shock in the system right now. What we need is to see something put in place that is economically sound at the same time and allows the country to ease into it.

[Gregg Orrill:]

Thanks.

[Bruce Williamson:]

Okay.

[Operator:]

Ivanet Ergovich [ph] of Jefferies, you may ask your question.

[Ivanet Ergovich:]

Hi, good morning. I have two questions. First one, what do you think was the reason for the heat rate improvement, in particular in Midwest?

[Bruce Williamson:]

Well, I mean, I think namely it comes out probably from low gas prices more than anything else. And that in turn – just simply put, gas prices fell faster than power prices and so you ended up with the Midwest combined cycle facilities getting in the money more than they had in years past by a pretty significant amount and their run times increasing.

[Ivanet Ergovich:]

Do you think this will continue throughout the year or the gas prices are still low (inaudible)?

[Bruce Williamson:]

What we’ve put in our plan is just wherever the forwards are and that’s how we’ve put it in. I think if anything, what it shows is that even with an economic slowdown, the American consumer continues to use electricity. I think there has been a lot of view that as the economy goes down, people don’t consume electricity. And while that may be the case on at the margin, industrial and commercial applications where people can go ahead and shut a factory down for a period of time or things like that, our coal fleet is more down in South Central Illinois where it’s more agricultural. And so we probably didn’t see as much of a decline there, plus as they are positioned from a cost standpoint, like we highlighted on a couple of the slides, in terms of our cost advantage. So we didn’t see the decline there. And then we did see the improvement of the gas plants as gas prices – I don’t know what words you want to use – plummeted this past quarter and power prices fell but didn’t fall nearly as much.

[Ivanet Ergovich:]

Okay. And another thing, last year, I think second quarter, basis differential was significantly higher than it was a year before. I mean, I know you are saying you expect higher basis differential this year, but would you expect something similar to the second quarter last year or there is something more returning to a normal number? I mean, what would be, like, the best way to look at it?

[Bruce Williamson:]

Well, I think if you look at last year, what really drove things last year was because we had natural gas. I don’t know, it hit $13 or so. And so that spikes the price of power in PJM east and west and had a drag-along effect that impacted us in the PJM and in the CIN Hub. So I think this year I think we would say we would expect more of a return to normal because we certainly don’t expect gas prices to turn 180 degrees and spike up like they were at this time last year.

[Ivanet Ergovich:]

Okay. Because I think last year when I was looking at numbers like around $8 and a year before in the first quarter was – in the second quarter was like $2. So, what is like normal? Is it like $2?

[Bruce Williamson:]

Our guidance was around $4 or $5. And I think that would be about the place to be.

[Ivanet Ergovich:]

Okay, thank you.

[Bruce Williamson:]

Okay. Operator, we will do one more question.

[Operator:]

Thank you. The last question comes from Terran Miller of Knight Libertas. Your line is open.

[Bruce Williamson:]

Hi, Terran.

[Terran Miller:]

Good morning, Bruce. How are you?

[Bruce Williamson:]

Good. How are you? Long time.

[Terran Miller:]

Thank you. As we look at your financial flexibility going forward, I know you have a fair amount of cash on hand, but you’re going to have reduced availability for some period under the bank facility. I look at the prospects of continuing to lighten up on your peaking assets. Could you give us some view of what you think – what percentage of those peaking assets were considered core and what percentage were not considered core as we try to view what your financial flexibility is going forward?

[Bruce Williamson:]

Geographically, if we cut the portfolio one way, which we’ve talked a lot about in the past with people, we really view geographically the Northeast, the Midwest, and West as the core regions. So that left assets that were in the Southeast regions. So that led to the sale of Calcasieu, which we did a while ago, Heard that we closed this past quarter. We do have one other peaker that’s in that region, Bluegrass. And then I think people should also remember we’ve told the market that we are out in the market via a Barclays investment bank working with us to explore the potential to sell our interest in Plum Point and Sandy Creek. Plum is in the Southeast region and Sandy is the only asset in ERCOT, both of these being minority stakes. And so if you like at it kind of cutting the portfolio geographically, I think that would be a way to take a look at it and leaving everything else in those three regions. We did sell a peaker I guess a year and a half or so ago, maybe almost two years ago now I guess, that was in the upper Midwest. And we did that strictly because of opportunism at the price level that was achieved. But I guess at this point, I would say cutting the portfolio geographically is probably the easiest way to do.

[Terran Miller:]

Is there any update in terms of the process for Plum Point and Sandy Creek or expectation when that process will come to a conclusion?

[Bruce Williamson:]

I would just say that it’s well under way. And we would hopefully be looking to be able to conclude the process and get something out I would hope in the second quarter.

[Holli Nichols:]

Second to third quarter we would be in a position to disclose more.

[Terran Miller:]

Thank you very much.

[Bruce Williamson:]

Okay. That concludes today’s call. I’d like to thank you all of you again for your time this morning and your interest in Dynegy.