Dyne Therapeutics, Inc.
Q4 2008 Earnings Call Transcript

Published: 26 Feb 2009

[Operator:]

Hello and welcome to the Dynegy Incorporated 2008 annual and fourth quarter 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 now like to turn the call 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 2008 annual and fourth quarter results and our business strategy going forward. 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 estimate. 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 www.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 Dynegy’s 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 who are following along via the webcast. I’ll begin today with the review of 2008 focusing on our challenges and successes and I’ll also cover a recent event involving the sale of one of our non-core assets. Then Holli will provide our full year 2008 financial results and discuss annual performance drivers for each of our key regions. I’ll then discuss our outlook for 2009, including market trends and how we intend to provide greater predictability in our near term adjusted EBITDA. I’ll also provide an update on 2009 sensitivities and financial estimates. Finally, my management team will join me in answering your questions. Please turn to slide four. While 2008 was a difficult year for most U.S. businesses, the power generation sector faced its own unique set of challenges. We saw extreme volatility in natural gas prices with a steep rise for about the first half of the year followed by an abrupt drop in the second half. A number of weather related events also affected sales volumes for some power generators. With that as a backdrop I now want to touch on some of the challenges we faced as a company in 2008. Besides volatile energy prices, we also have reduced sales volumes caused by mild summer weather and forced outages at some of our plants in early 2008. Relating to the weather in both the Midwest and the Northeast, we experienced fewer cooling degree days in the third quarter of 2008 compared to the third quarter of 2007. In the Midwest, a widening of basis between the liquid market and power delivery prices had a greater impact than we expected. In response, we are now working to actively manage basis risk by limiting forward sales at our Midwest assets in to PJM via purchasing firm transmission rights or bilateral basis swaps. In the Northeast, our Danskammer facility experienced increased fuel costs from South American coal. We now have entered into new contracts for 100% of our 2009 fuel obligations for Danskammer. The price of coal for Danskammer will now average approximately $4.20 per MMBtu, which compares quite favorably to the $5.83 per MMBtu that we projected in December. On the success side, operational performance was solid with 90% in market availability for the base load coal fleet. At a time when the credit markets almost completely shut down, we maintained our strong liquidity and flexible capital structure. We believe this serves as the ultimate hedge against commodity price volatility and financial uncertainty. We also locked in a minimal increase in the cost of PRB coal through 2010. This equates to an average delivered coal cost of our Baldwin facility of approximately $1.49 per MMBtu in 2009 and a modest increase to $1.52 in 2010. Approximately 35% of our PRB supply is locked in for 2011 and 2012 as well. In addition we harvested value through a number of opportunistic asset sales in 2008, highlighted by the sale of Rolling Hills peaker for $368 million in cash. In January 2009 we agreed to dissolve our development joint venture. In addition as we’ve indicated previously we are revaluating our participation in the Plum Point of the Sandy Creek construction projects. Our plan is to monetize our interest in these two projects which would release about $275 million of future equity commitment. Barclays Capital is running the sales process along with our corporate development team. As a result of the JV dissolution, Dynegy will focus its development activities and investments around its existing operating portfolio. Because new development is becoming increasingly difficult due to steep barriers to entry, we believe that focusing on our own portfolio where we can better control cost in to that option to build is a more sound strategy for us. Because of the economic market impacts on new development, we don’t expect any material development work for the foreseeable future, but since we now own 100% of the opportunities around our own sites, we can control costs and wait for improved conditions. Another item in the success column I’d like to touch on is our decision to increase near term contracted positions and add predictability to our EBITDA. This leaves us open to longer term benefits associated with power market recovery. When we provided our 2009 estimates in December, our contracted percentage of expected generation was about 55%. These contracts include power purchase agreements, options or forward sales agreements that exclude capacity arrangement. Today our contracted percentage of expected generation stands at approximately 90%. This volume metric measure is a new way of presenting the contracted profile going forward and I’ll provide more information on this later in the call. Please turn to slide five. Before moving on, I’d like to touch on a recent event involving a non-core asset sale. We have agreed to sell the Heard County peaker in Georgia to Oglethorpe Power for a $105 million in cash. This equates to approximately $200 per KW on the plants 539 megawatt winter capacity rating. The transaction is consistent with previous sales of non-core assets. In this case Heard is located in the Southeast U.S. which is not one of our core operating regions. The transaction is expected to close in the second quarter subject to various approvals and closing conditions. With that I’ll turn the call over to Holli to discuss our 2008 financial results.

[Holli Nichols:]

Thanks Bruce. Please turn to slide seven. Before I begin I’d like to point out that this presentation does contain non-GAAP measures that are reconciled later in the presentation. Also fourth quarter results are current in the appendix of this presentation. Now, turning to full year financial results; annual adjusted EBITDA decreased from $998 million in 2007 to $814 million in 2008. This is primarily due to lower realized power prices, compressed realized spark spreads, mild summer weather, transmission congestion and forced outages that included two key baseload units. All of these factors contributed to lower sales volume and lower adjusted EBITDA year-over-year. Adjusted cash flow from operations also decreased from $370 million in 2007 to $349 million in 2008, primarily due to the decline in adjusted EBITDA, which was partially offset by favorable changes in working capital due to lower prices year-over-year. Adjusted free cash flow changed from an inflow of $155 million in 2007 to an outflow of $25 million in 2008. In addition to the EBITDA and working capital changes, our investment in environmental upgrades was $146 million higher in 2008. It’s worth noting that we made significant progress in 2008 on our Midwest environmental investments to further reduce emissions. The entire project which will run through 2012 includes baghouse and scrubber projects at eight of our Midwest units. Our Midwest coal fleet already has reduced emissions of sulfur dioxide and nitrogen oxide by approximately 90% in the last ten years, largely through our conversion to PRB coal. The baghouses and scrubbers are designed to further reduce mercury, particular in sulfur dioxide emission. Now, turning to net income, Dynegy reported $174 million for 2008, compared to $264 million for 2007. In both years there were a number of items to be noted, which are listed on this slide. Most notable in 2008 were substantial mark-to-market gains as commodity prices fell dramatically in the last half of the year. In 2007 we had a large amount of income from discontinued operations, which was driven by the gain on the sale of CoGen Lyondell. As for capital and liquidity, we had net debt and other obligations of $5 billion as of December 31 of ‘08. This included cash on hands and investments of $693 million and restricted cash and investments of $1.2 billion. At the end of the year, Dynegy had collateral of $1.3 billion posted and liquidity of approximately $1.8 billion. This is since increased to $2 billion as of February 20. Please turn to slide eight for a discussion of our 2008 regional performance drivers. As I mentioned, adjusted EBITDA decreased 18% year-over-year. Let me take you through a brief overview of the drivers in each of our three key regions. In the Midwest, volumes decreased 2% year-over-year. First, we were impacted by milder summer weather, year-over-year cooling degree days during the third quarter were down 30% in St. Louis and down 20% in Chicago. We were also impacted by transmission congestion issues. 2008 was also impacted by some lost opportunity costs and lower realized pricing. We had a pair of forced outages at our Havana and Baldwin baseload coal facilities during the first quarter. While year-over-year volumes weren’t significantly impacted, the fact that these were baseload facilities down at a time of high demand created a meaningful opportunity costs. As Bruce mentioned earlier, a widening of basis between the liquid market and the power delivery point prices also impacted results. In 2008 the annual market impacted basis between the Cin and IP Hub, averaged approximately $2 more per megawatt hour than the previous year. We were also impacted by wider than expected basis between the PJM and Cin Hub and finally we experienced lower realized energy prices for the years. These factors were partially offset by $50 million increase, capacity revenues over 2007. Going from 2008 to 2009, we should expect to see a similar benefit from higher prices from the ‘08, ‘09 PJM auction and higher capacity prices from our Ontelaunee facility. These benefits will be slightly offset by lower prices from the PJM 2009, 2010 auction. In the West, volumes and results increased as a result of a full year of operations related to the new assets in Arizona and California. However, compressed spark spreads reduced run-times at our combined cycle facilities in total during 2008. Finally results for the West improved $11 million year-over-year due to the new tolling agreement at our Griffith facility. In the northeast, volumes decreased to 16% year-over-year due to milder summer weather, compressed realized spark spreads and an extended planned outage. Year-over-year cooling degree days during the third quarter were down 10% in New York and Boston regions. Regional transmission congestion also led to lower earnings in 2008. In addition, 2007 included the positive impact of a $30 million settlement of a financial contract related to our Casco Bay facility. Also while Danskammer did achieve 91% in-market availability in 2008, fuel costs increased by approximately $1 per MMBtu year-over-year, which resulted in a $20 million reduction in earnings. The bottom line is that 2008 was a challenging year based on factors both within and outside of our control. To help mitigate some of these challenging factors, we’re actively managing our risk with one key example being an increase in our near term contracted expected generation. We believe this approach will result in greater predictability of adjusted EBITDA, while protecting cash flows in the near term. We also believe this will leave it open in the longer term to capture the benefit that market recovery for our investors. That concludes my remarks and I’ll now turn it back over to Bruce.

[Bruce Williamson:]

Thanks Holli. Please turn to slide 10. We are in a period of extreme market volatility and low commodity prices as demonstrated by the top chart on the right hand side of the slide that shows substantial declines of Henry Hub natural gas and Cin Hub on-peak pricing. We believe near term demand is influenced by both weather and the current economic downturn. Weather tends to influence residential and commercial demand, whereas recessionary periods may have a greater impact on industrial demand. During previous recessionary periods the U.S. has seen a short term drop in demand increases and that may again be the case in the current recession. However, we believe that demand growth will continue over the longer term and that’s because the long term power generation market fundamentals remain essentially unchanged. Electricity remains as an essential commodity that cannot be stored. Demand may erode temporarily, but as we’ve seen in previous recessions, recovery historically appears as a series of weather and commodity price driven peaks and valleys trending upward. In addition barriers to entry remain high in a capital intensive industry. With the credit markets essentially closed, very few if any developments projects are actually being built. This reduction will further constraint supply when markets do recover providing support for higher electricity prices. The chart on the bottom right demonstrates that electricity generation in 2008 generally trended with around a five year average, which points out that usage patterns remain consistent despite the economic conditions. You will see that 2008 generation did pull below to five year average towards the end of the third quarter, which was a quarter marked by very mild summer weather. Also consider the red 2009 year-to-date line on the far left of this chart. Until recently 2009 generation was near the top of the five year range and this was most likely related to the colder than normal temperatures in most parts of the U.S. in January. Last week we saw a drop below the five year average as February has been much warmer than normal. Although, both weather and the economy impact demand, it appears to us that weather is having a more noticeable impact on demand. Please turn to slide 11. At our December meeting we outlined our 2009 focus by spelling out a number of objectives. First, operate our assets well; second, protect liquidity and near term cash flow; third, manage spending; and fourth, improve our adjusted EBITDA predictability. We view all of these as critical for operating and sustaining the business in a weak economy. Let me now move forward and comment on how we’re doing in these areas. We are maintaining our focus on operating well and holding down costs with one important metric being the 90% in-market availability for the baseload fleet that we demonstrated in 2008. We ended the development joint venture to turn our complete focus on operate on our assets and set aside development for awhile. We’re continuing to preserve liquidity with this important measure at approximately $2 billion as of February 20, with more than $850 million of this made up of cash. In addition the sale of Heard and other non-core assets will then add to this cash and liquidity. Cost control is also a key focus. We’re striving to maintain a low cost structure as demonstrated by our 2009 G&A estimate, which is now cut to approximately $175 million. We have made progress in terms of improving predictability of the near term adjusted EBITDA, protecting cash flow and reducing downside risk. In 2008 we were not able to deliver on this to our desired extent. However, since the first of the year we have worked to enhance predictability of near term adjusted EBITDA going forward, a direct response to concerns express by some of the investor community. We have developed what we believe is an appropriate commercial approach for the current economic times; an approach that seeks to balance commercial risk and reward by reducing merchant exposure with an increase in contracted positions in the near term. Today the contracted percentage of expected generation is approximately 90% as compared to about 55% in early December. This percentage relates to volumes we expect to generate, versus growth margin hedged and differs from what we have previously disclosed. We believe that by providing the percentage of expected generation volumes contracted, we create greater transparency on our commercial strategy. Now you will be better able to match volumes sold with fuel contracts. One item that this percentage excludes is capacity that has been sold. The key takeaway here is that as the percentage of contracted expected generation increases, we’re able to better protect near term cash flows and improve adjusted EBITDA predictability. Please turn to slide 12 for a more in-depth look at our commercial strategy. We continue to believe that our strategy of commercializing our assets for the current year plus one of two years is the right approach. The strategy is designed to better protect near term cash flows from entry year volatility and leaves us open in the longer term to the capture benefits associated with tightening supply and demand, including anticipated increases in prices and volumes. For parts of the portfolio, including combined cycle plans and peakers in our three regions, the lengths of contracts may be longer based on local market factors. With this portfolio approach, we expect to see the benefits of our fleet’s diversification. However, even with the portfolio there are numerous moving pieces that can influence results. Going forward, we are continuing to sell energy and capacity through a combination of spot market sales and near term contracts over a rolling 12 to 36 month timeframe in periods that we describe as current, current + 1 and current + 2. At any given point in time, we will seek to balance predictability of near term adjusted EBITDA and cash flow with achieving the highest levels of earnings in cash flow possible over these periods. We will also continue to seek to reduce the negative impact of short term volatility, while keeping some energy and capacity open to capture upside opportunities presented by weather extremes and unplanned outages of other generators. Over the longer term, we are staying relatively open in the plus two years and beyond period. This provides us with an opportunity to capture value in a fundamentally rising price environment, as supply and demand tighten and no significant new generation is on the horizon. Going forward, we intend to provide you with the information on what has been contracted on a volume metric basis. Turning to the bottom of the slide you will see that from December 2008 to mid-February 2009, we’ve significantly increased the contracted percentage of expected generation in each of our regions. In the Midwest we’ve gone from 55% to approximately 95%. This stems from an increase in the number of financial swaps, as well as new bilateral energy sale to the Midwest utility for the first three months of 2009. In the West where we traditionally have contracted a larger percentage of our output, the contracted percentage increased from 65% to 75%, simply due to additional forward sales and in the Northeast, we have increased from 40% contracted to 95%. This is primarily due to an increase in financial swaps to hedge our expected sales volumes. As a reminder our contracted percentage of expected generation therefore stands at approximately 90% on a consolidated basis. Now please turn to slide 13. Now, I’d like to highlight some changes that impacted adjusted EBITDA since we provided financial estimates in December. This is not a comprehensive list, but it includes some of the most significant factors. The biggest impact of course is the overall decline in commodity prices. Note that the approximate $3 move in natural gas from our original plant sensitivities has an approximately $210 million adverse impact. Today’s market conditions remain extremely volatile and we expect this volatility to continue through 2009. At the same time there are a number of offsetting factors in our favor. Since, our December call we have locked in 100% of our 2009 coal supply for Danskammer to ensure reliable relatively low cost fuel to serve Northeast customers. We’ve also seen a marginal improvement in market implied heat rate since December. In addition run-times at our Roseton facility have improved due to the decreases in fuel oil prices and cold weather in the Northeast. With our commercial strategy now focused on increasing near term predictability, our contracted percentage of expected generation therefore went from 55% in December to about 90% today. In the longer term periods, we remain more open as you can see by the chart at the bottom of the slide. This shows that we are approximately already 50% contracted for 2010, which is not typical for us this early in the year. Here you can also see we’re 10% contracted in 2011. The concept I would like to leave you with here is that because we manage our assets as a portfolio and because we have contracted more for the near term and reduced our exposure to falling commodity prices; since December, our current expected results are better than if you apply the sensitivities that we have provided in December. Because of our new positions, we’ve updated sensitivities which I’ll cover in the next few slides. Please turn to slide 14. We customarily demonstrate the sensitivities of our generation business and our adjusted EBITDA estimates to natural gas commodity pricing. This trapezoid of adjusted EBITDA range of $700 million to $825 million can be adjusted to reflect different average prices for natural gas which is reflected across the x-axis. These changes have less potential impact both to the up side and downside, when more volumes are more contracted. The vertical range of y-axis reflects the potential variability and other assumptions such as unplanned outages, weather, baseload, market implied heat rates, commodity price volatility and the ability to sell uncommitted capacity. Combined, these factors lead to our $125 million guidance range. The ownership of power plants and the spread volatility between the fuel and power provides us with an opportunity to capture additional value. When the spread volatility is low there is less opportunity to capture this value. Turning to the x-axis with our contracted percentage of expected generation at 90%, we would expect a $1 plus or minus change in the price of natural gas, to impact adjusted EBITDA by approximately $20 million. In December when volumes were at 55% a $1 change in natural gas would have resulted in the $70 million change in adjusted EBITDA. The key take away here is that we are substantially more hedged today than when we last talked to you in December and we have made changes in our commercial strategy and structure. Please turn to slide 15. Here we’ve included a few of the sensitivities that as we mentioned can impact our adjusted EBITDA. What you’ll notice here is that we’ve ramped up contracted volumes and therefore become less sensitive to price changes. Our natural gas sensitivity is based on full year estimates with our current profile at approximately 90% of expected generation volumes contracted and therefore assumes natural gas price changes occur for the remainder of the year across the entire portfolio. Looking at the different cost scenarios at the top of the slide, you can see a $1 change in natural gas would result in a $20 million increase in adjusted EBITDA and conversely $1 decrease would result in a $20 million decrease in adjusted EBITDA. As noted, changes in natural gas prices without a change in sparks spread primarily impact our coal baseload units. Previously in December $1 change would have resulted in a $70 million change in adjusted EBITDA. A key point here is that as we’ve become more contracted, our EBITDA is not as sensitive to changes in natural gas prices. Now let’s look at sensitivities related to market implied heat rates. These sensitivities are based on on-peak power prices for the remainder of the year. Sensitivities assume a constant natural gas price of $5 per MMBtu. Further increased run-times could result in accelerated maintenance costs, which are not included in this sensitivity. Here you can see that a change in the market implied heat rate of 500 Btus per kilowatt hour would result in a $15 million increase in adjusted EBITDA and a decrease of 500 would correspond to a $15 million decrease in adjusted EBITDA. The key takeaway here is that changes in market implied heat rates impact the entire fleet and finally we’ve added sensitivities to CIN Hub On-Peak power prices, which impact to Midwest baseload coal fleet. Assuming no change in basis from CIN Hub and IP, a $5 change in price would result in a $15 million impact to adjusted EBITDA. Please turn to slide 16 where I’ll update our consolidated 2009 earnings estimates. I’m going to focus on adjusted measures; the GAAP measures are included at the bottom of the slide and in more detail in the appendix of the presentation. The range we are providing is based on $5 per MMBtu, 2009 forward gas curve. The guidance range has been reduced from the previous guidance presented on December 10, 2008 largely due to lower natural gas prices, which are expected therefore affect the power prices in all of our regions. Looking at our regions individually, adjusted gross margin was largely reduced in the Midwest due to the impact of natural gas prices on out right power prices. This is partially offset by the previously mentioned favorable energy contract and the widening of spark spreads in the region. In the West expected adjusted gross margin has been reduced due to compressed spark spread and as I mentioned earlier, we expect a negligible impact to adjusted gross margin in the Northeast. In addition to the changes in adjusted gross margin we’re reflecting a $20 million reduction resulting from a decline in interest income given that LIBOR rates continue to fall, which is partially offset by an anticipated reduction in our G&A expense. We’re projecting a range of adjusted EBITDA of $700 million to $825 million in the $5 natural gas price environment. In addition to the changes to adjusted EBITDA, projected free cash flow will be impacted by an $85 million collateral outflow related to our decision to increase our contracted megawatt hours as we enter 2010. We’re projecting a range of adjusted cash flow from operation of a $160 million to $285 million. Taking into consideration, maintenance CapEx of a $155 million, environmental CapEx of $280 million and capitalized interest of $25 million, we’re then projecting adjusted free cash flow in the range of negative $300 million and negative $175 million. Please turn to slide 17. I’ll end my prepared remarks by discussing why you should consider Dynegy as an investment today. The challenges of 2008 are continuing into 2009 as industries across the country are grappling with the economic downturn in the credit markets. As I’ve said at the outset of this call, the power generation sector continues to be faced with its own set of challenges. Commodity price have been falling an as a result our sector is trading at all time lows. However, Dynegy has the financial stability and liquidity to weather the current economic downturn. Our circumstances today are dramatically different from the last time our equity traded at these levels, given our balance sheet flexibility and liquidity. Considering our low cost structure the majority of Dynegy’s current earnings come from our baseload coal fleet and we’re committed to operating these assets well based on our strong track record of achieving high-end market availability level. In addition Dynegy has proactively managed its capital structure to weather cyclical downturns. We consider our balance sheet to be our ultimate hedge. We’ve mentioned this before, but it bears repeating; we have a strong liquidity of $2 billion made up of more than $850 million in cash and $1.2 billion of availability under our credit facility. I would note our current level of cash alone is almost $1 per share. We have a very flexible capital structure and we have no significant debt maturities until 2011. Also we’ve focused our efforts on increasing the level of commercial contracts to protect the near term cash flow and provide more predictable adjusted EBITDA. Now let’s look at how Dynegy differentiates itself in an economic recovery. As supply and demand tightens, our significant gas-fired fleet is available for increased utilization. At the same time our coal fleet will participate in the expected heat rate expansion. We’re increasing our contracted profile for the near term to enhance the predictability of adjusted EBITDA and protect cash flows, leaving us relatively open over the longer term to capture this value in a fundamentally rising price environment. What’s more, Dynegy is well positioned to participate in industry consolidation, with no significant restrictive covenants, including change of control provisions in our bond indentures. We believe we’re able to sustain the current market turbulence and capture value as supply and demand tighten and our stock is leveraged to both prices and demand which we believe creates benefits for investors as the financial and energy markets recover. With that we’ll move on to the question-and-answer portion of our presentation. Operator we’ll take the first call now.

[Operator:]

Thank you. (Operator Instructions) Lasan Johong of RBC Capital Markets, you may ask your question.

[Lasan Johong:]

Thank you. Good morning. Bruce it sounds like there’s a little bit of a change in how you view the world. It used to be that Dynegy hedged on a current + 1 basis, and now it sounds like it’s more like current + 2. I’m not criticizing that strategy; I think that’s probably a good one and it sounds like you’re trying to bridge to “the better times” so to speak. Is that a correct perception or am I kind of missing something here.

[Bruce Williamson:]

No, I think that’s actually a pretty good way of putting it. Right now in this environment I think investors are more concerned about protecting against the downside and what we’re trying to do is sort of strike the balance here between, adding greater near term predictability, protecting against any further fall in commodity prices. When we look longer term we see fundamentals are still there, largely no ones really building new power generation in the country. The economy will come back, consumers will consume energy, they do consume electricity and we’ll see supply and demand tighten and probably tighten pretty rapidly. So, I think that’s a pretty good way of putting it. Chuck you’re on the commercial group now, anything you want to add to that?

[Chuck Cook:]

No, I think that’s a fair assessment of the goal and strategy.

[Lasan Johong:]

Excellent. There’s been a lot of chit-chat about what the current congress and President Obama wants to do on the energy front, particularly there’s been some noise on CO2. Do you have any kind of opinion what you think might happen?

[Bruce Williamson:]

No. I think the main thing for investors that look at that issue is, when something is implemented whether it’s a cap and trade or carbon tax, if you have to buy your credits it’s effectively the same thing. I just want to point out again that our coal fleet is in a market where coal is at the margin of most of the time and so we would expect to get full cost recovery of any cost of carbon credits or carbon charges that we would incur most of the year, and then as we move to that world, in the periods of time when gas is setting the marginal price you’d expect greater gas usage in the country, so you should see a rise in natural gas. We went through that with the financial community last year and tried to layout a rather complicated graph, but it basically shows the amount of any impact on our earnings and cash flow of carbon legislation should be modest. Mainly Americans need to understand that any carbon regime is going to be an increase in the cost of power, gasoline, jet fuel, plane tickets, virtually everything in the economy.

[Lasan Johong:]

Right. On the Sandy Creek and Plum Point situation, I think I’m misunderstanding what you’re saying. I’m assuming that in addition to the $275 million of equity commitment that gets freed up, you would also receive some proceeds in addition, would you not?

[Bruce Williamson:]

We’ll get you on the bid list. Yes, we would anticipate we would get proceeds. The part that we mentioned there on the 275, that’s our equity commitment that has been posted through a letter of credit and obviously that would be released and then yes, we would anticipate proceeds on top of that. We’re not projecting a sales price though.

[Lasan Johong:]

Okay. One last question on the hedging that you’ve additionally placed in ‘09 and 2010, are these mostly bilateral contracts or is it to a financial hub. It sounds like it’s mostly to Cin Hub and if so are you exposed to basis differentials.

[Chuch Cook:]

Yes, those are mostly placed through financial swaps and we are as we mentioned before not focusing on PJM as a hub for that activity. So we are not trying to take CIN hub to PJM with respect to that.

[Lasan Johong:]

That’s it, great. Thank you very much.

[Bruce Williamson:]

Thanks Lasan.

[Operator:]

Brian Chin with Citi, you may ask your question.

[Brian Chin:]

Hi, on the additional hedges you are throwing on, are you taking the volumetric risk on those hedges and you’re just hedging up the pricing risk; I’m just trying to clarify that.

[Chuck Cook:]

I’m not sure I understand the question.

[Brian Chin:]

Let’s say for example you hedged out a 100 megawatt hour or $100 per megawatt hour on one of your coal plants and then let’s say economic demand drops off, whether demand ends up not being favorable; you would simply have a locked in price, but the volumetric risk would be yours and that will be something we have to be cautious about right, there’s no locked in actual dollar amount that you’ve sold.

[Chuck Cook:]

Yes, I think really the risk that we take is with respect to our plants operation. So, when we try to determine our expected generation, we assume some factors for end market availability and to the extent that we are better or worse than that, that’s a volume number that can impact us, but otherwise no.

[Brian Chin:]

Okay, great, thanks a lot.

[Operator:]

Neel Mitra of Simmons & Company; you may ask you question.

[Bruce Williamson:]

Hi, Neal.

[Neel Mitra:]

Hi, I had a couple more questions on hedging. When you locked in the majority of your open position post December 10, was the hedge exposure spread out over the last two and a half months or were they concentrated during a certain timeframe, since gas prices are trending down during the entire period; and since you’re evocating more of a current plus two position at this point, can you describe your progress or strategy towards commercializing 2010 at this point?

[Bruce Williamson:]

Neel, they would have been done. I can’t pinpoint days or specific times. I would say it’s probably throughout the time period from December through February, a lot of it in January. That’s probably the closest I can narrow it down to and then with regard to 2010, Chuck?

[Chuck Cook:]

Yes, I think the graph speaks for itself. We’re beginning to initializes a position and we will look to add additional contracted volumes as we’d inappropriate, but I think the trend is pretty self evident.

[Holli Nichols:]

Right now that’s about 50% of the volume.

[Neel Mitra:]

Okay, that’s helpful and then can you provide a little bit more information regarding how the transmission congestion affected your 2008 operations at Bridgeport and Casco Bay and how you view that going into 2009?

[Lynn Lednicky:]

Yes, for the transmission in the Northeast, there wasn’t a tremendous impact to Bridgeport. Bridgeport has been a load pocket and so it normally responds to the demand in that particular area. Casco is of course a little more remote and the liquid sales point is at Mass Hub and we do see transmission constraints along that line. So, it’s a little difficult for us to project exactly what those were going to be on a go forward basis and so for 2008 it turned out that our realized congestion costs were a little bit higher than what we had projected in the plan.

[Neel Mitra:]

Okay great, thank you.

[Operator:]

Andy Smith of J.P. Morgan, you may ask your question.

[Andy Smith:]

Hi, good morning guys.

[Bruce Williamson:]

Hi, Andy.

[Andy Smith:]

A quick question for you guys, and looking at the hedge book, it had some stats I think out of the bank facilities and obviously there’s some tests, but it looks like the last disclosure I think, had you guys have been needing to maintain a $700 million EBITDA level. I believe that was in the unsecured facility. It’s kind of a two part question; one, is that right; is that number still good? Then the second part is based on the sensitivities you guys laid out, would your significantly increased hedge book. It still looks like you got about $30 million, $40 million bucks of sensitivity, that kind of maybe it’s a disaster scenario, that $3 gas, but you could blow through that $700 million level. So, is that level still a good level and if so, how do you guys think about worrying about that little bit of gap that appears to still be exposed?

[Holli Nichols:]

Andy let me maybe make sure I can clarify your point on the 700. When I think about it and I think about our credit agreement, primarily there are two tests or two covenants that we look to, one being our interest coverage ratio and the other being our secured debt-to-EBITDA ratio. The secured debt-to-EBITDA ratio is one where it just will sort of put a governor on the amount of capacity you have related to your revolver and that number and then what will happen is if you aren’t meeting that ratio, then the LC and capacity and drawing capacity you have under that facility will go down. For every dollar you’re below the ratio you will lose $2.5 of capacity. So that’s something that we would expect to have some impact on that this summer, but it’s the type of thing that as soon as your EBITDA then improves or turns back around, then you regain that capacity. So it’s not a trigger you have lost it indefinitely and it will fluctuate, but given the level of liquidity we have that’s not something we’re worried about. Now the other is interest coverage ratio and that maybe what you were thinking about. The way that ratio works is it began the year about 1.5 times and it gross over the course of the year to 1.75 and at the same time though our interest is actually fallings over the course of the year, primarily through the SIF amortization of that debt and so I think the number that I would use is more around a 650 number and so, at this point as you said we do have some sensitivity around gas prices, power prices, basis, those sorts of things. One thing I wouldn’t double up obviously the gas and power sensitive that we gave you, but a dollar in gas is about 20 million and two points, so could that be 40 million in a $3 case from the time we ran these sensitive. I guess that’s possible but I would also say the team is continuing to work towards commercializing that last 10% of the portfolio and would certainly hope to have that done before you would see a $3 gas price.

[Andy Smith:]

Okay, got you. In the interest coverage ratio, it sounds like you said the SIF amortization would cause that ratio to actually kick the EBITDA closer to 650, is that the way to think about that.

[Holli Nichols:]

Yes, that’s right the interest is coming down over the course of the year.

[Andy Smith:]

Okay, that’s very helpful color there. I mean just to switch over a little bit to the hedge book, and Holli maybe you can speak to this too, it sounds like I think Chuck mentioned primarily financial swaps in terms of setting up ledge. How do you guys think about it? Are the counterparties primarily trading houses; is some of that done through exchanges how do we think about the potential risk of an industrial going away from a credit quality perspective, how have you guys managed that?

[Chuck Cook:]

Those are all generally cleared transactions, so we use brokers for that activity and requirements as far as the clearing process are that we aren’t exposed to credit risk with respect to that.

[Andy Smith:]

Okay, perfect. I appreciate the time guys, thank you.

[Operator:]

Brian Russo of Ladenburg Thalmann, you may ask your question.

[Brian Russo:]

Good morning

[Bruce Williamson:]

Hi, Brian.

[Brian Russo:]

Could you give us an idea of what the heard plant 2008 EBITDA contribution was?

[Bruce Williamson:]

$3 million give or take.

[Brian Russo:]

Okay, great and then how much is the SIF amortization per year.

[Holli Nichols:]

When you say the amortization are you talking about the difference between the cash and actual earnings that show up in our financial statements?

[Brian Russo:]

Right, and then what would drive the interest expense lower.

[Holli Nichols:]

Sure, the SIF amortization is around $50 million, between what’s in the P&L and the cash that we receive, that’s amortizing debt facility that we have there. So as we pay down the debt, its $50 million, $60 million a year, that’s what’s bringing the interest down.

[Brian Russo:]

Okay and then just to be clear on the financial covenants on the credit facilities, are there any crossover defaults to any other part of your capital structure.

[Holli Nichols:]

Really if you think about it, the credit agreement is the primary and the interest coverage ratio will be the one that we’d be most concerned around there, but no there aren’t other cross defaults.

[Brian Russo:]

Okay and also to be clear what if you were to fall below $650 million EBITDA, what happens to those facilities.

[Holli Nichols:]

Well, we would be in default of our credit agreement facility for the interest coverage ratio itself. So I think we would be in a position we’d be working with our banks at that point, but again as I said that’s not something that we’re terribly concerned about based on the numbers we have giving you and I think we’ve been fairly broad in our range of estimates, in considering the types of things that can impact earnings during the year. But there’s not necessarily a built in cure for that covenant.

[Brian Russo:]

Okay and then how much is drawn on the revolver in the term loan?

[Holli Nichols:]

We don’t have any drawn. We will post some level of LCs against that. Obviously the $850 million term LC facility, we try to maximize our usage of that since we cash collateralize it, but right now we have a fairly small amount I believe if any, of LC posted against the revolver itself, but certainly nothing drawn.

[Brian Russo:]

Thank you very much.

[Operator:]

Daniel Eggers of Credit Suisse, you may ask your question.

[Daniel Eggers:]

Good morning. I guess just on the fact that you guys were able to sell into that short-dated auction event in the first quarter to help the ‘09 hedges, how do you guys think about 2010, 2011 willingness to hedge more than you have now as a regional auction occurs later this year?

[Bruce Williamson:]

I think we will pursue regional auctions as they occur. I mean the success of the one in the first quarter I think we liked quite a lot. To the extent we can do that some more and replicate that on a bilateral basis, I think we’re fine with it.

[Daniel Eggers:]

So you would be willing to let that 50% move to 70% or presumably higher if the auction was an attractive price?

[Bruce Williamson:]

Yes.

[Daniel Eggers:]

Okay. From a collateral perspective you had to put up $85 million of collateral for the 2010 hedges, anything we should be thinking about as far as sensitivity to future postings on what you guys have now?

[Bruce Williamson:]

Dan, on that I’ll let Holli address that.

[Holli Nichols:]

Dan, that was actually initial margining and so that would have related to ‘09 and ‘10 positions that we’re entering into. I think the way to think about that is it’s like a working capital investment. As we’ve increased the level of commercial activity it’s just required that additional investment. So if we continue to increase the amounts outstanding at a rate greater than things rolling off, we could have some more initial margining, but I think we’ve made the largest move at this point and so I look at that as being like a working capital investment and it’s not really a mark-to-market concept that you would think about.

[Daniel Eggers:]

So these new hedges do not have a mark-to-market component from a collateral posting perspective?

[Bruce Williamson:]

Some will.

[Holli Nichols:]

As Chuck mentioned too though, we settle on those essentially through a clearing house and so I would say to your question, yes, we still have exposure as we said all along. There is a cost to increasing the level of commercial activity and so we’ve entered into this with a view on being very aware of the sensitivities around that and we’re very comfortable with our abilities to meet any of the collateral needs that we would have going forward, based on the future changes in prices. If prices scream up, which we’d certainly be happy enough with at this point, we’re still comfortable that we have the liquidity to cover that.

[Daniel Eggers:]

Okay and then with the Heard sale, is that $105 million or thereabouts going to be in your free cash flow forecast for 2009? I might not have understood. Then also along those lines, are there any NOLs or losses that you’re going to get from a tax benefit perspective with the sale?

[Holli Nichols:]

For Heard, we don’t typically include asset sale proceeds in our adjusted free cash flow numbers, so that would not be included in there. It would obviously be in our cash flows, but not in what we would project, because we try to limit that to things that we view as more recurring operational-type items. On the tax side we will have a small tax gain associated with that sale, because the basis was lower than $105 million, but as you’ve probably tracked, our NOLs are down to fairly small numbers, $25 million or so and what we’re left with now is more AMT credits that we would look to utilize over the course of the next few years.

[Daniel Eggers:]

Okay. Do you have the end quarter NOLs and AMTs by chance?

[Holli Nichols:]

I want to say its $28 million for the NOL and the AMT credits are about $270 million. Now I’m getting a nod from Norelle so that must be right.

[Daniel Eggers:]

Perfect, thank you.

[Bruce Williamson:]

The K will be filed later today Dan.

[Daniel Eggers:]

Thanks.

[Operator:]

(Inaudible) of Goldman Sachs, you may ask your question.

[Unidentified Participant:]

Hey guys, a couple of things. Back to the bank line, I think you recently just renegotiated some sort of waiver on the covenant, can you talk a little bit about that and were there discussions to try to get additional covenant relief with respect to the financial metrics and also what did you have to give up or consent fee or any other additional assets as collateral?

[Bruce Williamson:]

What we did there, we had a waiver that we needed to do because there was a test called an incurrence test, and really what it dealt with ultimately was our ability to sell Plum Point, because that was not a carved out asset and so we wanted to basically correct that, so that we were able to free that up in order to do that. So it was really just pushing out the incurrence test one year from when it was originally set on a ratchet up. I’m not going to get into the amount of consent fee other than to say it was immaterial.

[Unidentified Participant:]

Okay, did you have to post additional assets or you took something that wasn’t restricted?

[Holli Nichols:]

Something we chose to do as part of the process and we’ve been trying to move a little bit more to simplification anyway, was the SIF assets and that in fee had been an unrestricted sub in the past, that’s not a restricted sub, but we did that along with this more again to clean up and simplify the capital structure.

[Unidentified Participant:]

Okay and just a second question with respect to liability management, I know you talked about it last call or you made a mention of it, of debt repurchase. Have you guys thought about anything yet on that front given that you’ve executed on the Heard sale here and you may look at other asset sales. Does it sort of make sense at some point to look at repurchasing any debt?

[Bruce Williamson:]

Yes, we’ve talked about it, looked at it a lot and I guess I would say for the last year, year-and-a-half, maintaining the cash and liquidity that we’ve had turned out to be a pretty good game plan for right now, just given how the economy has turned out. It’s nice to have your bank facility be basically undrawn, have the amount of cash that we have on hand, but all options are on the table ultimately to make decisions like that and we’ve got a tremendous amount of flexibility to do that.

[Unidentified Participant:]

Okay, just one last thing back to the bank lines. Would you start talking to the bank lenders now given there might be some tail risks with respect to even though you’ve laid on hedges to essentially piercing covenants to just get some freedom now? Would that make sense or are you just going to wait and see?

[Holli Nichols:]

I think if we become concerned that there’s going to be an issue, we would reach out to our banks, but we’re not at that point yet.

[Unidentified Participant:]

Okay, fair enough. Thank you.

[Operator:]

Charles Sharett of Credit Suisse, you may ask your question.

[Charles Sharett:]

Hi, good morning. Just on a broader picture here, a lot of people are talking about natural gas going lower in the short term. I mean what does this business look like in 2010, 2011 if you assume natural gas stays at around $4 and what’s your view on managing the business?

[Bruce Williamson:]

Well, I think that’s where as Lasan put it on the first question, it’s kind of bridging out with the current + 1, current + 2, I think those are the things that we’re doing to protect that sort of downside. We’ve got costs that we can manage and in addition, if you go out a couple years like that, this is really our peak year in terms of the consent decree environmental spending, so you’d see that coming down. There’s a potential that we’ve got some gas combined cycle maintenance, but that’s all tied to run time, so I guess in the world you’re projecting that run time is down. I think at that point the best management that you’ve got is probably the balance sheet and the liquidity that we have and the flexibility around our covenants, which I know we’ve talked quite a bit around covenants and the bank agreement, but as Holli said those are down at a level that we’re not concerned about at this point in time and there really are none in our term debt or in our permanent debt. So if that’s your concern I don’t know that I’m going to come up with a scenario that’s going to have a rosy upside picture for you if you’re projecting a depression/recession of the lasts three years.

[Charles Sharett:]

Okay, thank you very much.

[Bruce Williamson:]

Operator we’ll take one more question.

[Operator:]

Thank you. Ivan Urkevich [Ph] of Jefferies, you may ask your question.

[Ivan Urkavich:]

Hi, good morning.

[Bruce Williamson:]

Hey Ivan.

[Ivan Urkavich:]

Hi. I noticed that the market heat rates in your parts of Illinois basically decreased in February versus January. I’m just wondering; would that be due to demand destruction or is it due to weather and would you expect this phenomenon to continue?

[Bruce Williamson:]

I’m sorry, it was very quiet there. Your question dealt with Illinois what?

[Ivan Urkavich:]

It’s the Illinois market heat rates, it basically decreased significantly in February versus January and I was just wondering is that due to demand destruction and would you expect this to continue?

[Bruce Williamson:]

Ivan, I would think that it’s mainly weather. We had a pretty cold January and we’ve had a mild, relatively speaking other than thunderstorms, pretty mild from a temperature standpoint February. So, as much as I think right now a lot of people are wanting to look to changes in volumes and try to immediately pin it on demand destruction or something like that, I think predominantly it’s going to be weather and that may sound simplistic, but that’s what we continue to see as the major driver in our regions.

[Ivan Urkavich:]

Okay, thank you.

[Bruce Williamson:]

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