Dyne Therapeutics, Inc. (DYN) Q4 2007 Earnings Report, Transcript and Summary

Hello and welcome to the Dynegy Incorporated Fourth Quarter and Year-End 2007 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 would now like to turn the conference over to Ms. Norelle Lundy, Vice President of Investor and Public Relations. Ma'am, you may begin.

Good morning everyone and welcome to Dynegy's investor conference call and webcast highlighting the company's 2007 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, particularly with respect to our growth strategy and 2008 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 statement. For a description of the factors that may cause such a variance, I would direct you to the forward-looking statements legend contained in today's news release and in our SEC filings which are available free of charge through our website at dynegy.com. With that, I will now turn it over to our Chairman, President and CEO, Bruce Williamson.

Good morning and thank you for joining us. Joining 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 3 for those of you who are following along online via the webcast. Today, I would like to provide an overview of how Dynegy set a foundation for growth in 2007. And in addition, I will highlight how the progress we made during the past year should translate into prospects for growth and value creation in 2008 and beyond. Holli will discuss our financial results and provide a business segment financial review and update our 2008 estimate. I will then discuss how our operational excellence and financial discipline strategically positioned us to capture value in a market characterized by rising power prices and declining reserve margins. And finally the management team and I will join me in answering your questions and we'll wrap up by sharing a calendar of upcoming investor events. Please turn to slide 4. During 2007, we built a solid foundation for growth by executing on our three part strategy: operate, build and transact. Today I will explain this strategy in some greater detail and then discuss how we implemented it during 2007 and how our actions should translate into future value creation. Let's begin with operate. One of our overarching goals as a company is to achieve operational excellence across our business. With nearly 20,000 megawatts of power generating capacity, Dynegy has established an enviable track record of operating our assets safely, efficiently and reliably as noted by a number of key metrics. We are also investing in our business. During the next five years, we will be introducing advanced systems for reducing emissions to ensure that our coal fleet continues to operate in an environmentally responsible and compliant manner while continuing to serve customers and our investors. Moving to build. Another opportunity for Dynegy to create value for investors relates to building and expanding our portfolio through development prospects. We currently have a number of high return greenfield and brownfield projects in various stages of development, which include natural gas, coal and renewable options. As we work with our joint venture partner to build new generation facilities, we are committed to implementing advanced technology to drive efficiencies and minimize emissions. The third aspect of our strategy that I will address today is transact, which focuses on buying or selling assets; in essence, strategically monetizing assets and then allocating capital to maximize returns to our investors. In 2007, Dynegy concluded a transformative transaction to acquire a significant fleet of power generating assets. In relatively short order, we fully integrated these assets and their systems into our company. Throughout this period, we maintained our strong capital structure and cleaned up the capital structure tied to the assets that we acquired, which continues to offer us the flexibility to maximize our commercial strategy and pursue additional strategic business combinations or asset acquisitions. We also selectively monetize assets when we believe that we could secure better returns by selling the plants rather than running them, or when we thought it was prudent to take some risks off the table from a development project. Please turn to slide 5. In terms of the operate portion of our strategy, 2007 was an outstanding year. Our financial results benefited from truly exceptional operational and safety performance. Our plant performance for 2007 was very strong with 93% in-market availability for the Midwest coal fleet. That fleet set an all-time production record, nearly 6% above its prior record. Despite relatively mild weather, we experienced increased production year-over-year, which indicates how well positioned our fleet is as the markets continue to tighten. In 2007, we continued our commitment to meeting the environmental standards. Compared to 1998 levels, our coal fleet has reduced emissions of sulfur dioxide and nitrogen oxide by approximately 90%. We have accomplished this by converting our Midwest coal plants to Powder River Basin coal, and we are building on this progress by installing baghouses, scrubbers and other emissions control equipment. Over the next five years, we will continue to invest several hundred million dollars in advanced systems for reducing emissions, consistent with our Midwest generation consent decree. In terms of safety, we achieved the second best safety performance in our company's history based on OSHA Total Recordable Incident Rate reporting. Our strong operating and safety performance helped produce solid financial results as we reported consolidated net income of $264 million or $0.35 per diluted share in 2007. Generation EBITDA significantly improved year-over-year to $1.3 billion, producing generation operating cash flow of $934 million. Please turn to slide 6. I would like to take a moment to provide an update on an important element of our operating strategy, and that's our commitment to enhancing our environmental performance through a significant multi-year investment in advanced control systems for reducing emissions. These projects relate to the Midwest coal fleet and the company's commitment to construct mercury-controlled projects, baghouses, scrubbers to further reduce emissions of sulfur dioxide, nitrogen oxides, particulates and mercury. We have already made significant progress with the completion of the Vermilion baghouse and mercury-controlled project. The baghouse at Hennepin is well under way and scheduled to be completed by the end of the year. We have also started the Havana baghouse and scrubber projects with completion scheduled for 2009. This work gives us a strong base of experience with engineering and construction that will be applied to the remainder of the projects. Based on this experience and in particular the significant increases we have seen in the market for labor, material and equipment rental and related activities, we are providing an updated estimate of our remaining spend of $850 million to $900 million or a total investment of $940 million to $990 million. A portion of this increase is reflected in our 2008 cash flow guidance, which Holli will cover in more detail. The chart on the lower right breaks down costs in the labor, material and rental equipment and other components. We estimate that approximately 25% of our remaining costs are firm. Further, we remain on target to meet our final completion date 2012. This is a major investment to contribute to the long-term viability of the Midwest coal fleet while cementing these plants standing as one of the cleanest operating groups of plants in the country. Please turn to slide 7. Now on to the build portion of our strategy. One important factor that differentiates us from other energy merchants is our advanced pipeline of projects in various stages of development. We are working with our partner, LS Power, in a joint venture to pursue these opportunities. We own partial interest in two generate greenfield projects that have received financing and are currently under construction. Both plants are scheduled to come on line at a time of high demand in their respective markets and both facilities will use advanced emissions control technology. Plum Point, a pulverized coal-fired plant with advanced emission controls in Arkansas remains on track to begin commercial operations in 2010. Also under construction is Sandy Creek, a pulverized coal-fired generation facility with advanced emission control in Texas that is on track to begin commercial operations in 2012. Sandy Creek is a so-called supercritical design, which means that it's highly efficient with a low heat rate and reduced CO2 production rate. I want to take a minute here to explain a little more about our 50:50 development joint venture. With our development approach, we will strive for a portion of our portfolio of projects to be self funding. This frees us cash from our current operations for other discretionary purposes. The key point for investors to understand is that the development joint venture has a very flexible approach, meaning that some projects will be pursued, some may drop off the list or be converted to a different fuel type and others will be added. The key to this is to build what customers want; not what a developer wants to build. Whether we monetize, build or operate new facilities is ultimately based on our assessment of allocating capital for the highest and best returns for our investors. Our development joint venture is currently pursuing a number of gas, coal and renewable options in various stages of the permitting process. This is in keeping with our balanced portfolio approach which we believe is the right direction for Dynegy and our country given the continuing need for affordable and reliable energy. Please turn to slide 8. The transact side of our strategy includes evaluating and pursuing potential transactions to grow the scale and scope of our diversified portfolio and create new options while opportunistically harvesting embedded value in the existing portfolio. I will begin by discussing assets that we monetized in 2007. First, we closed the sale of the CoGen Lyondell facility for $470 million or approximately $880 per KW. In addition, the development joint venture sold the a % interest in the Sandy Creek project for a value equivalent to approximately $2600 per KW. Joint venture also entered into a 30-year contract for 150 megawatts of the facility's output. We also sold a portion of our investment in the Plum Point project for $82 million net of non-recourse debt, which is the equivalent of approximately $2800 per KW. And last, we announced the sale of the Calcasieu peaking facility for $57 million or approximately $160 per KW. This transaction is the only one that has not yet closed, but is expected to close very soon. In each of these monetizations, we yield significantly greater returns than we believe could have been earned had we retained the assets. Going forward, we may make additional opportunistic sales to maximize stockholder returns. As most of you are aware, our biggest value creating accomplishment in 2007 was the successful integration of the portfolio of assets that we acquired into Dynegy's systems, strategy and culture. This transaction increased the capacity of our power genea4rtion portfolio by about 70% and provided us with an opportunity to reenter the strategically important mid... Western market with attractive assets. Also during the year, Dynegy successfully completed a number of key financings. The first relates to the placement of 1.65 billion of long-term unsecured notes, the proceeds of which were used to repay the various complex project debt structures and facilities assumed through the asset acquisition and eliminate the associated cash flow sweeps. This allows the free cash flow from these assets to simply go to the highest and best use and not tie up the assets in complex structures, covenants and other restrictions. We also repaid the $275 million of debt that we had drawn under our revolving credit facility at the time of the acquisition. As a result of this focus on solid financial management, we entered 2008 with a strong and importantly flexible capital structure with no significant debt maturities in 2011. I want to emphasize this point given the turmoil in the capital markets. We have no financing needs at all in 2008, 2009 or 2010 due to the hard work and clear strategy of our team in 2007. By maintaining appropriate debt levels, good overall liquidity and lengthening maturities, we are also well positioned to support our commercial strategy in the commodity cyclical market we operate in. Our strong, flexible capital structure provides us with the ability to pursue strategic business combinations or asset acquisitions should they become available and if they are attractive. Lastly, as Holli will cover in a little more detail, our 2008 guidance is based on $8.25 NYMEX gas prices. Today, the NYMEX is well above $9 for 2008 and 2009. In addition, Midwest power prices for 2009 are currently running around 20% above our 2008 guidance numbers, indicating the ever tightening U.S. power market. With that, I will turn the call over to Holli to discuss our financial results and provide the business segment financial review.

Thanks Bruce. Turning not to slide 10 and our financial performance for the quarter, I would like to cover our income statement, cash flow statement and balance sheet. Before I begin, I would like to point out that this presentation does contain non-GAAP measures that are reconciled later in the presentation. Turning to results. For full year 2007, we reported net income of $264 million or $0.35 per diluted share. This compares to a net loss of $342 million or $0.75 per diluted share during 2006. The improvement in 2007 results reflects higher volumes and prices associated with our baseload fleet and the contribution of nine months of earnings from the assets acquired from LS Power. I will cover these points in more detail with a walkthrough of the business segment. The other large contributors to earnings are the gains on the sales of our CoGen Lyondell facility and a partial interest in Plum Point. All these benefits were partially offset by a tax adjustment of approximately $50 million to reflect a higher anticipated state tax rate as well as a negative mark to market impact. The negative mark-to-market impact reflects the fact that on a net basis, forward price curves at December 31st of 2007 were higher than when we entered in to the forward sales. Moving on to cash flow. Cash flows from operations totaled $341 million with generation operating cash flow approaching 1 billion as Bruce previously mentioned. We had investing cash outflows of $817 million. More than $800 million of these investing cash outflows are funded by financing cash inflows. In addition to the $800 million that's offset in financing cash flow, there is over $300 million of cash deposited to support the Sandy Creek project equity commitment that can be replaced by a letter of credit at anytime we choose to free up cash. So, operating cash flows less required capital spend was over $120 million and we collected over $400 million in asset sale proceeds. I will emphasize here that with the exception of Calcasieu, the opportunistic monetization of assets was done at pricing that was equal to or above our replacement cost estimate. From a balance sheet perspective, we ended the year with total net debt and lease obligations of 5.2 billion. This is net of cash on hand of $328 million and restricted cash and investments of 1.2 billion. In addition, at the end of 2007, we had 1.3 billion of collateral posted and liquidity of 1.4 billion. Please turn to slide 11. In looking at our 2007 cash flow results, we have reconciled prior estimates provided on November 8th of 2007 to our actual 2007 results. Our operating cash flow was $341 million for the year and core free cash flow was $155 million, both of which are below our previous estimates. There are two primary reasons for this. First, we invested about $80 million more in working capital than previously anticipated. The most significant driver was the fact that power prices were higher year-end 2007 compared to year-end 2006. Additionally, we had increased run times in December of '07 at certain facilities due to colder weather. Let me give you an example of how this activity impacts our cash flow. Our independent facility ran more in December of '07 than in '06 and power prices were also higher at the end of '07 than in '06. Increases in volumes and prices created a large receivable balance to be collected in the subsequent month, which, in this case, is in 2008. On the other hand, the price of fuel was lower at the end of 2007 than in 06. So although we purchased more fuel to support increased volume, our payable balance remained relatively flat year-over-year. So higher working capital can be good in the sense that the ultimate impact is higher cash flows associated with higher volumes and wider margins. In addition to the working capital item, $25 million of legal and tax payment originally planned in 2007, were delayed to 2008. The timing of these payments was dependent on third parties and the actual payments occurred in early 2008 rather than late 2007 as previously expected. While this has a positive impact on our 2007 results, it will have a negative impact on our 08 estimate. All in all, there is no change in our anticipated cash balance for this item; it's really just the timing difference. Outside of these two items, our 2007 cash flows were in line with our expectations. Before moving on to earnings, I would like to point out that we'll be changing the definition of free cash flow to better reflect the cash generating ability of the business relative to the company's required capital expenditure program. New definition includes cash flow from operations less maintenance and environmental capital expenditures. Previously, we defined free cash flow as cash flow from operations less cash flow from investing activities. Then to help you understand the free cash flow from our core business, we adjusted for most of the other investing activity. While there may still be adjustments to get from the newly defined free cash flow to our core free cash flow, it should be more straightforward in the future. As you can see, core free cash flow is the same amount under both definitions for 2007. Please turn to slide 12, and I will cover earnings for the year. Once again, we've reconciled prior estimates provided on November 8th of 2007 to 2007 actual EBITDA and net income. I would summarize the adjustments into the following four categories. First on a net basis, the actual gains on asset sales were less than previously estimated. Next, operational results were slightly better than estimated. Third forward curves were higher at December 31st, than they were on October 9th, which is the pricing date of our previous 2007 estimates leading to mark-to-market losses of approximately $40 million. And lastly, we had previously reflected the adjustment to our state deferred tax liability in our estimates. I would like to focus my discussion on the third item of mark-to-market as it will also impact our 2008 estimates. Commodity prices have been and will continue to be volatile. As such we will continue to be impacted by mark-to-market earnings changes which can be particularly confusing as you crossover a year end. We have broken down the mark-to-market impact from our previous pricing date of October 9th to December 31st into three buckets. When we provided you with our 2008 estimates based on an October 30th pricing date, our estimates already considered the $81 million mark-to-market loss on 2008 and beyond positions that occur between October 9th and October 30th. This resulted from increasing forward price curves, which will benefit our generation volumes not already hedged. What we couldn't know when we provided our 2008 estimates was the impact of changing price curves subsequent to October 30th and the related impact on our 2008 an beyond forward sales values. That's a $38 million and the $2 million, the $38 million relating to 2008 positions is what's most important. The way to think about is that the $38 million of value we previously anticipated recognizing in 2008 was accelerated to 2007. Therefore, 2007 results are higher and 2008 results will be lower, then were to several of the adjustments I have discussed, it's just timing. While our 2008 earnings and cash flow will be lower due to the accounting for the forward sales, our 2008 cash balance will not be impacted by this timing difference. The earnings were recognized in 2007 and cash was accelerated to 2007. So, all in all, 2007 EBITDA is 1.2 billion, which is at the low end of our previous estimate. Absent the impact of mark-to-market on earnings on our 2008 and beyond positions subsequent to October 9th, we would have been towards a high end of our range. Additionally, I would point out that the annual impact of mark-to-market accounting on our 2007 earnings was a negative $32 million. Again, this was due to rising prices, which should benefit our un-hedged volumes. Turning to net income of $264 million, this was below our previous range of $295 million to $330 million. In addition to the adjustments noted in EBITDA, net income was also impacted by a change in tax estimates. As you may have noted, our 2007 effective tax rate was 57%. 2007 income tax expense includes the impact of a higher anticipated effective state tax rate on our state deferred taxes, as a result of changes in levels of our business activity in the states where we do business. This change in estimate was approximately $50 million. Absent the change in tax estimates in mark-to-market, net income came in about what we expected. Please turn to slide 13 for a quick run through of our business segments results. As Bruce mentioned earlier our Midwest coal fleet performance was exceptional in 2007 with 93% in market availability and record setting production. This contributed to an 80% increase in EBITDA of for this segment from $378 million in 2006 to $682 million in 2007. Now, keep in mind that 2006 EBITDA did include $110 million in asset impairments. In addition to higher volumes in 07 from the Midwest coal fleet, we also benefited from increased power prices, the addition of the Kendall and Ontelaunee plants acquired from LS Power and $39 million pre-tax gain on the sales of partial ownership interest in the Plum Point facility. 2007 was offset by $25 million charge related to Illinois Rate Relief Legislation and negative $36 million of mark-to-market, compared to positive mark-to-market of $15 million in 2006. The mark-to-market is comprised of several components and I would encourage you to review the details in the appendix. Capital spending in 2007 was greater than 2006, primarily due to planned Consent Decree spending and the construction of Plum Point. Please turn to slide 14 for the financial results of our West segment. Beginning in the second quarter 2007, the company's former South segment was renamed the West segment. This segment now also includes six assets acquired from LS Power, which helped drive significantly better results for the year. EBITDA for the West segment was $439 million in 2007, compared to a loss before interest, taxes, depreciation and amortization of $34 million in 2006. This improvement includes $230 million reported in discontinued operations, primarily related to the gain on the sale of the CoGen Lyondell facility. Volumes were $11 million megawatt hours during 2007, as compared to 0.9 million megawatt hours in 2006, due to the addition of the six former LS Power facilities. While we did not have a significant presence in the West in 06 a trend worth pointing out is the increase in natural gas spark spread to an average of $16.24 per megawatt hour during 2007, compared to $13.77 per megawatt hour in 2006. The West segment also benefited from positive mark-to-market of $44 million in 2007, compared to no mark-to-market in 06. Capital spending was actually lower than in 06 which included planned major maintenance at CoGen Lyondell. Please turn to slide 15 for a review of our Northeast segment. EBITDA for the Northeast segment was $209 million during 2007, compared to 88 million in 2006. Northeast generated 9.4 million megawatts hours, an increase of more than 100%. This is primarily due to the addition of the Bridgeport and Casco Bay facilities, as well as the increased run-time at all of the company's northeast facilities. 2007 results were negatively impacted by mark-to-market of $40 million, compared to $26 million in 2006. Lastly, 2007 capital spending was higher than 2006, primarily due to maintenance related to the Bridgeport and Casco Bay facility, added in April. Let's now turn to our CRM results on slide 16. As we continue to wind down our former legacy contracts EBITDA for the Customer Risk Management segment in 2007 was $29 million compared to $34 million in 2006. 2007 results included a $31 million pre-tax gain associated with the acquisition of the Kendall facility. Prior to the LS Power acquisition, the Kendall facility held the power tolling contract with the company's CRM segment. Upon completion of the merger, the contract became an inter company agreement and the gain was recognized. Results also included $15 million of income from favorable settlement of a legacy receivable, offset by $15 million in pre-tax legal and settlement charges. The 2007 cash outflows consisted primarily of natural gas purchases to satisfy legacy contracts and the 2006 cash outflow included a $370 million payment of exit the Sterlington toll and approximately $80 million for a legal settlements. Please turn to slide 17. Our other results consist primarily of general and administrated costs and legal and settlement charges offset by interest income. In other, the company recorded $139 million loss before interest, taxes, and depreciation and amortization during 2007, compared to a loss of $100 million for 2006. During 2007, general and administrated costs were higher as a result of the headcount and related expenses associated with LS Power asset acquisition. This increase was partially offset by greater interest income earned in 2007 due to higher restricted cash balances. Including legal and settlement charges, general and administrative costs in 2007 were $167 million, which was in line with our guidance estimate of $170 million. Cash flow used in operations was reflected of cash used to pay general, administrative cost and interest expense, which was higher in 07 with the addition of debt in connection with the LS Power asset acquisition, and was offset by interest income. Please turn to slide 18. Let's now take a look at our 2008 cash flow and earnings estimates. We provided cash flow and earnings estimates for 2008 back in December, based on quoted forward commodity prices as of October 30th of 2007. Today, we are updating our 2008 estimates to reflect quoted [file 15][01.27] forward commodity price curves as of January 29th of 2008. The new estimates also reflect assumptions regarding sale volumes, fuel cost and other operational activities among other things. Although we are making adjustments to our 2008 estimates, I want to be very clear that our views on our operations and the commercial opportunities for 2008 have not changed. As you know, we operate in commodity markets that are volatile. When we provided our 2008 estimates in December we used commodity prices as of October 30th, at that time the forward gas price for 2008 was around $8.25 per MMBtu. As of January 29th, the day we used our data 08 estimates, the 2008 average gas price was around $8.20 per MMBtu. The adjustments we are making to our 08 estimates are primarily timing related and our shift between 2007 and 2008. However you should note that forward gas prices have risen sharply since the end of February. As of earlier this week, the 2008 gas price traded around $9.40 per MMBtu. Our unsold generation capacity, especially from our Midwest fleet generally benefits as gas price have increased and were actively managing our commercial activities to capture the value of these improved prices. However, since the... these increased prices occurred after our January 29th of 2008 estimate revision date, this benefit is not yet reflected in our 08 estimates. We expect to provide additional updates to our 08 estimates in our next quarterly earnings call. Recently, we expect cash flow from operations to be between $510 million to $610 million, a $75 million decrease from the previous estimate. The reduction relates to the following changes, a $40 million reduction due to receipt of cash in 2007 associated with 2008 mark-to-market forward sales position. A $25 million reduction due to the deferral with legal and tax payments from 2007 to 2008 and $10 million reduction related to lower interest rates, which results in lower interest income, partially offset by lower interest expense. We already covered the first two items and the third is pretty self explanatory, given the recent rate cuts by the Fed we'll earn less on our cash balances over the course of the year. Also, as I discussed earlier, we have redefined free cash flow to better reflect the cash generating ability of the business relative to our required capital expenditure program. The new definition includes cash flow from operations, less maintenance and environmental capital expenditures. Previously, free cash flow was defined as cash flow from operation, less cash flow from investing activities. This change in definition resulted in $40 million reduction in estimated free cash flow due to the elimination of items such as net proceeds from asset sales, changes in restricted cash and development CapEx. Also, with regard to our environmental upgrades that Bruce covered earlier, we are increasing environmental CapEx by $35 million for 2008. After considering the change in definition, environmental upgrades and $75 million I covered earlier, our anticipated range of free cash flow is now $100 million to $200 million. Please turn to slide 19 for a look at 2008 earnings estimates. Our 2008 earnings estimates are broken by segment and based on January 29th, 2008 quoted forward curves for commodity prices. The equity... the EBITDA estimate for 2008 is in the range of approximately $1 billion to $1.1 billion. The $60 million reduction reflects the earnings impact of the cash flow I just covered. First, the $38 million adjustment reflecting the shift in value of the 2008 forward sales into 2007. And second, $20 million reduction due to lower interest rate, which results in lower interest income. However, this decrease of $20 million to EBITDA is partially offset by $10 million reduction in interest expense, for a net $10 million impact on pre-tax earnings. Again, the key takeaway here is that our overall view of 2008 and our ability to generate value and cash flow has not changed from previous estimates. We are optimistic about the current commodity price environment. That concludes my remarks, and I'll now turn the call back to Bruce.

Thanks Holli, please turn to slide 21. To give you a better understanding of how we are strategically positioning things to capture market opportunities, look at the trends that are reflected in today's market. Markets are entering a period of higher power prices and declining reserve margins. Increased demand for fuel stocks such as coal and natural gas is driving power price volatility. As you can see on the chart on the left, natural gas prices have been extremely volatile in recent years due to range of factors including weather, storage inventories and an overall increase in global demand. During the first two months of 2008, natural gas prices have increased by more than $1 per MMBtu and the forward curve remains above $9. We are actively participating in today's market to capture upside related to near term and longer term increases in power prices. Let's consider the PJM market as an example. In PJM, capacity prices have also increased significantly. This has resulted in benefits for some of our Midwest assets. Now turning to the chart on the right, another trend is the decline in reserve margins as demand continues to increase and supply, overall tightens. The recovery time-table for our Midwest assets which are split between MISO and PJM extends to approximately 2010. Our California and Northeast assets are currently operating in an environment already marked by relatively tight supply and demand. We believe that slim reserve margins will prompt stronger energy and capacity pricing, which should ultimately encourage the new development of power plants. Well this is something the country ultimately needs. The reality is that building new baseload plants in the U.S. is becoming more and more challenging. Absent, any significant development spending, certain regions could enter in to an under build [ph] scenario in a relatively near future. What does this mean for Dynegy? In the next few slides, I'll discuss how we operate and will commercialize to take advantage of these market trends. Please turn to slide 22. Defining reserve margins give Dynegy options to create and capture additional value to the strength of our operating performance. As reserve margins decline, capacity factors should be increased creating significant cash flow upside opportunities. Chart on the right of the slide shows the expected capacity for our fleet for 2008, compared to the capacity factors in a market recovery scenario. Currently, coal generally subs [ph] the margin in the Midwest, but in a recovery scenario natural gas should begin to set margin more frequently, driving power prices higher. In this environment, our baseload fleet which is primarily in the Midwest would benefit from higher prices, even if similar... at similar capacity levels. In addition, our combined cycle and peaking assets would benefit not only from rising prices, but also from increase runtime, as they would come online more frequently. Thinking of all this from a regional perspective, our West fleet is already operating in a recovery environment and the natural gas sets the prices in these regions. In this market we see upside potential from greater merchant exposure in a fundamentally balanced market. And in the Northeast, where natural gas sets the margins, that region is close to a tight supply and demand environment as well. Here we would expect stronger runtimes from our combined cycle and peaking fleet to capture improved market prices. But to sum up, the diversity of our fleet should provide us with the ability to produce increasing free cash flow as the market continues to recover. Please turn to slide 23. Here we shift from our operational approach to our focus on commercializing our assets to take advantage of the recent market opportunities. Development of regional capacity markets represents a favorable trend and our commercial team is working to proactively secure future revenue streams to capture this attractive pricing. Recent data from capacity market auctions points to the trend towards tightening supply and demand, as well as our ability to capitalize on these improving market dynamics. In the Midwest PJM capacity auctions, you can see that the auction price has increased from an average of $41 per megawatt day for the auction years 2007, 2008 to $174 per megawatt day for 2010, 2011. In addition, we are seeing more uniformity in prices across... among PJM regions. Just last year there was more price disparity region-to-region. You can see that these... as these auctions advance we have been able to capture stronger prices and clear more megawatts. In the West, due to improving market conditions we have entered into tolling contracts relating to our Arlington Valley and Griffith assets in Arizona. These agreements enable us to lock in significant value and improved economics over ten year terms of these contracts. And in New England, where we operate approximately 1000 megawatts of generating capacity, we recently participated in the first forward capacity market for auction years 2010 and 2011. In that auction, the minimum clearing price was approximately $148 per megawatt day. These commercial trends should all contribute to our average annual EBITDA growth estimate of 15%. Further we expect capacity and capacity type arrangements in other regions, the increase in value overtime representing future upside potential for our investors. Please turn to slide 24. Earlier, both Holli and I did cover briefly how commodity prices are arising, given the recent run up in coal prices, many of you have inquired about the impact on our fleet. I would like to demonstrate here how our Midwest fleet is well positioned to manage the rising price of coal. The chart on the left demonstrates the recent pricing trends for Eastern and Power River Basin coal. Although prices have escalated, we have strategic contracts that minimize our exposure to the volatility of the spot market and help ensure an adequate and affordable supply of fuel to run our plants. Our Midwest fleet utilizes PRB, which benefits... with benefits including lower emissions and less price volatility. And essentially, 100% of our Midwest coal requirements are contracted through 2010. These contracts are subject to price re-openers that go into effect in 2009. However, a significant portion of these re-openers are capped. In addition to our coal contracts, 100% of our rail transportation cost is contracted at a fixed price through 2013. So as a benchmark, our 2008 delivered coal cost is $1.39 per MMbtu at Baldwin, our largest coal facility. Due to our long-term fixed rail contract and relatively stable coal cost, we believe we have significant advantages over current market-based purchases of comparative coal, which would run up to $2 per MMbtu or more. So the key takeaway here is that our coal and rail contracts offer a significant competitive advantage in a rising cost environment. Please turn to slide 25. Dynegy is positioned to benefit from improving market conditions and we are taking steps on the operational and commercial fronts to deliver current and future value to our investors. It's important to acknowledge that given our cyclical business, some market factors are outside of our control. However, others are not. We will maintain a flexible strategy that allows us to keep our options open as we continuously evolving market and regulatory conditions to pursue value creating initiatives and rapidly respond to change. At the same time, we will never lose sight of our core business, which is to generate and sell electricity in a safe, reliable and economic manner. We always take into account the business cycle and adjust our strategy in keeping with such variables as seasonality, regional market issues and global commodity prices. Underscoring all of this is our solid foundation, our well positioned, well operated assets, strong balance sheet and flexible financial structure and an experienced and dedicated management team with a proven ability to execute. So to sum up, Dynegy's operate, build and transact strategy provides us with the ability to create and return significant value to our investors. As we leverage our strong operating... operational capabilities in power generation, we will also seek to continue to invest in high return market opportunities that generate significant cash flows and attractive returns for our stockholders. With that, let's move to the Q&A portion of our presentation. Operator, we'll take the first call now. Operator? Question And Answer

[Operator Instructions]. Our first question comes from Mr. John Kiani from Deutsche Bank.

Good morning Bruce, Holli.

How are you?

Fine. Thank you. If I look at Calpine, it's trading at a pretty substantial premium to Dynegy with an embedded spark spread option that's, I think, pretty similar to your 15,000 megawatt gas and oil-fired portfolio. Would you ever consider a carve out of your gas-fired portfolio to highlight and extract this value discrepancy?

Well, I think, John, what you highlight is I think investors should look at the companies in the power sector and understand that not all the companies are the same. The company you just mentioned is clearly trading on its, call it, on a forward EBITDA outlook given investors in that case looking forward and seeing continued market recovery, lack of new supply coming into the market and continuing U.S. increasing power demand. So that entity is in effect being priced on forward EBITDA multiples, if you will. You can compare that at the other end of the spectrum to some of the others in the IPP sector who have a lot of coal-fired generation who don't have that gas-fired upside, and they are trading more on just current EBITDA multiples. We have a bit of both of those in our portfolio as you are saying. But importantly, I think for investors, we have the diversity element of not being all one way, just a pure bet on the forward outlook nor are we just a bet on current results with no upside potential. So I think when you balance them together, I think that's what investors should look at is both the forward upside opportunity as well [ph] with sort of a core or baseload position or earning power off of the coal fleet.

Okay. And then another question. Can you talk about why you include mark-to-market gains and losses from hedges for FAS 133 accounting and EBITDA guidance? It doesn't seem to be standard industry practice.

I guess the way to think about it, John, is we actually don't include any anticipated effects of mark to market in our estimates as we go forward. All we reflect is what has actually happened to date, and that's what's going to start to create a disconnect, right, especially when you cross over a period, because as an example what happened here is we put positions on in 2007. We liked the price and so we locked that in on our '08 generation. But now what you will see is the earnings associated with that financial contract have been disaggregated from the actual production, which will happen in 08.

Because commodities are higher?

[Multiple Speakers] going to settle exactly where we expected it to and where we were happy to enter into a contract. It's just the earnings have... some are showing up in '07 and some will show up in '08.

I mean is there any way to when you just report EBITDA, come up with some type of a recurring or operational EBITDA that excludes that, so that when the Street tries to benchmark your reported quarterly numbers to what your guidance was, we strip out that volatility?

I think what we have tried to do, John, is to highlight what the mark-to-market impact is. For example, the annual mark to market for 2007 was $32 million in a pre-tax basis. So if you want to think about it, our earnings absent that, you would want to add that back to 2007 EBITDA.

All right. Thank you, Holli and Bruce.

John, I guess [ph] I would say is we are trying to give you analysts on the sell side something to do. And I know we've got some SEC counsels here in the company that want us to, as much as possible, not to mention our auditors and our controllers organization, try to do as much as we can to stick with Generally Accepted Accounting Principles, whether that reflects the economic reality of, I guess, I think about it or not. So what we try to do is obviously just provide enough reconciliation for people to get to the answer, and John, you guys can lead the way in helping break that down for people.

Thanks. Well, you gave me something to do at 5:30 this morning.

There you go.

Our next question comes from Ms. Elizabeth Parrella of Merrill Lynch.

Thank you. A couple of questions. Holli, you mentioned that gas prices now, the most recent quote for 2008 average was about 9.40, which is up $1.20 from what this revised guidance is based on, if I understand it correctly. If we go back to your kind of sensitivity that you gave us in December, would it be fair to apply that here just theoretically if the 9.40 were sustained? That's about a $60 million uptick to EBITDA, which basically offset the reductions that you've get in this revised guidance.

I think the sensitivities still apply, Elizabeth. So that's probably a fair way of looking at it. And certainly when we come out with our first quarter results, we will update guidance for more current gas price. And the other key to your point was we would need to go and capture that pricing environment that's out there today. So we still have some execution around that. But I think that's a fair way of looking at it.

And Elizabeth, I guess I would also add, people also, I think, maybe just picking up on John's comment and looking at the forward EBITDA outlook, I think people need to focus not just on '08; they need to be looking at where prices looking like they are at for 09, maybe 2010. And it's not just taken on the gas price, which I think as of yesterday the 09 strip on coal was running around 9.25. But Midwest synergy power price is running in the low to mid 70s, around 73. So we see a very high energy price and power price environment in a tightening market, and I think longer term, that's what I would want investors to be taking a good look at.

Okay. A couple of other questions. The slide on coal hedging, slide 24, could you give us some sense of... you talk about a significant portion of the price re-opener for next year are capped. If you were to look at the 2009 coal costs, how much of it is sort of really already locked or locked down? I realize your supply is 100% locked down. But if we thought about how much of the price was really open to some type of escalator and then adjusting for how much of an escalation you could see. I don't know what that's tied to.

Yes.

That market price --

Elizabeth, on that, we've got with the suppliers, we have confidentiality agreements on those. And I think the best way we have been explaining to people to take a look at that is you can go back to our past years, you could go back. We have been doing dollars per MMbtu delivered at Baldwin now for probably at least three years, Lynn. And I think if you go back three years ago, we were probably around $1.15 or $1.10. Then it was around $1.20, $1.25. We are at about $1.30. And so even with increases that have happened over the last few years, you have a very gentle movement up and not the least of which is depending on exactly which plant this stuff ends up at. It probably is somewhere around 50% to 60% of the delivered cost is rail, which is hard fixed. So the exposure there is muted not only by sort of the rolling and capped nature of the price escalators on the coal, but moreover, by the hard fixed nature of the rail contract.

Right. But the --

We really just wanted to get across to people that when you see these spot Eastern prices running up, it's not a big, at this point, I would say a big factor for us given those two muting factors of the fixed rail and then the capped escalators in the various coal contracts.

Right. The market price increase we have seen, even for PRB, I think has been sharper than in past years. I am not sure, well, it will give us some general sense to go back and look at the historicals. I am not sure that this time around, it might not be more pronounced. So I am wondering if it would be possible for you to indicate at least on the general sense kind of maybe either how much of an increase or what might be sort of the worst possible percentage increase in 2009 based on where we are today for PRB prices and the way your contracts work?

We can take a look at it. I mean, Lynn, anything you want to add?

Yes, well, Elizabeth, I was going to say I mean we are in the middle of discussions with coal suppliers right now. So that's part of the reason that we are a bit reticent to say too much at this point. In the next few months, we will have a much better idea of what the prices are going to like for 2009 and beyond. But our expectations now I think are in line with what Bruce said a minute ago. If you look at the kind of historical price increases that we have seen over the last few years, we expect that we will see similar type things this year. So that's probably as much as we can really say right now given that we are in the middle of those discussions.

Okay. Perhaps --

We have kept [ph] it for later in the year.

Yes, maybe we can revisit that on the next call.

Okay.

And just one other topic Bruce. In both your remarks and the slides and the press release, you talked about opportunities for creating value through investments in new projects, those brownfield and greenfield transactions, acquisitions. Where does stock buy back fit in all of this?

Well I think it all has to be factored in terms of capital allocation decisions. And the short answer is we have been talking for now, I guess going back to the December presentations or a little before about where the stock has been relative to replacement cost economics. And if faced with a choice of buying an asset at 80 or 90 or 100% of replacement cost or looking at where our own stock is, the stock would have a better outlook on things. And we've said that we will have to evaluate that and work on, let's say, capital allocation as we go through 2008. We continue to see strong recovery in the market and that should be good increased earnings power and so that becomes a very high quality problem for us to get to deal with in 2008 and beyond. What we are just highlighting with the capital structure and the comment is that we do have a very flexible capable structure, and that can serve us both to return money to shareholders, or to look at acquisitions, or to look at discretionary capital spending without needing to go out to the capital markets and get a lot of consents [ph] or refinancings and things like that like some of our competitors need to do. We in effect got our financings done last year.

Okay, thank you.

Our next question comes from Mr. David Silverstein of Merrill Lynch.

Hi there. Just to follow up a little bit on what Elizabeth was talking about. If you could maybe give us an update in terms of what your committed sales are for 2009. I mean 2008 looks like it's relatively locked up given the commitments you have in place. But in terms of 2009 forward sales agreement relative to your coal costs. And I mean does it provide, given the limited upside that you see in terms of the price re-openers based upon historical... based on what this percentage increase could be, do you see an additional upside then for 2009 or do you see some contractual risks potentially in terms of escalating coal prices?

I think on the coal price side, we covered that, but we don't see a tremendous amount of risk to the upside in terms of an increasing coal cost. And as Lynn said, you can look at our past history kind of going over about a three-year period, and we have been moving things... things have moved up maybe a dime or $0.15 per MMbtu. I don't think we expect things to be dramatically different than that. So that's I guess on the cost side of things. If the other side of our question is then well, how are we positioned in 2009 as power prices and gas prices, setting marginal price and things like that have moved up? I would tell you that we will update 2009 forward sale outlook around the end of this year like we did last year for 2008 and the year before for 2007. But our commercial strategy remains very much the same where we want to look at the current year plus one around the baseload coal fleet and not really go out very much beyond that because we want to have that participation in the upside as the markets continue to tighten and power prices and energy prices generally look like they are tightening and moving in that direction. So we want to sort of move it into forward sales of the output in a reason [ph] and gradual manner so that we participate in that market recovery in the commodity cycle.

I mean just to be specific, I mean you are looking at a 50% increase in PRB over the last month or two. And so if you are saying that you have a strategic advantage because of the re-price... the price re-openers. And you think that the market is going to be somewhat correlated to, at least for the off peak periods, to a large degree with PRB pricing in that area or Central App for even a better situation right now. I mean that looks like substantial upside for 09, but you are not prepared to make that --

Yes, I think it's important that that's spot prices versus term prices and then Lynn --

David, I think that's right. You need to remember that we are buying under term arrangements, and so the applicable [ph] comparable or term prices and not spot prices. And to this potential concern about off peak prices, you are right, off peak prices are generally set by coal units. But everybody has a similar situation. So we don't think we are disadvantaged in that respect. And for 08, as you said, things are more nailed down. As we look forward, we are watching the prices and we are managing that in concert with what's happening on the fuel side. So we don't think that there is going to be any big surprise that occurs out of that.

Okay. Because term right now for '09 is 17.5 a ton for PRB. So you are either really well positioned or you are just not willing to make that statement at this point?

We are comfortable at the position that we've got..

Okay, got you. Thank you.

Our next question comes from Mr. Gregg Orrill [ph] of Lehman Brothers.

Thanks a lot. Wanted to go back to your slide 21 on the reserve margin guidance by market and the two questions there. Certainly... I certainly agree with the trends, but I was curious, particularly for the California and Northeast curves since they are the lowest, how you are weighting the different parts of those markets. And then second question is what's your... what are some of your thoughts on how renewables and demand response are going to affect the outlook.

Well I'll comment on the renewables and the demand and then maybe ask Lynn to comment... or Jason on the different segments or comment within that. I think on renewables and on demand response, I mean those are going to kick in, but they are going to be at some pretty high pricing levels. Consumers are going to respond with changes in behavior an demand I think when prices dictate that that's what they should do economically. At the end of the day, we are still seeing an overall increase in prices and not that much of an impact in terms of a curtailment of demand at this point of time. I think longer term, that's going to be part of the energy solution in the country dealing with traditional fuels, renewables, demand response as hopefully government tries to strike a balance between environmental concerns, the cost of power to consumers and energy dependence on foreign oil and foreign... and increasingly foreign natural gas. So it's not like there is just a one trick of advance this to six, one side of things with out impacting the other. In other words we can't have a whole lot of additional renewables and --without jeopardizing reliability or increasing cost, nor can we have just put all our eggs in the basket of demand response and not have new supply come into being. So, it's a complex energy problem that is going to have multitude of solutions. And then comment I guess on different regions of... Greg your other part was comment on different parts, I guess breaking down.

Yes, I guess the idea of being that.

Like we have it on graph, I guess Northern versus Southern and probably New England versus New York.

Just in those... right in those curves how do you see the various up segments, higher or lower than the curve?

Well I guess we started in the Northeast. We are pretty comfortable with what we have in the Northeast because the diversity we have in the portfolio with coal and oil and gas and that gives us the opportunity to participate in several different segments. You got capacity markets that are developing in the Northeast, they have already been there in the New York region, they were now in the New England region. So we participate there. We have got well placed assets that participate well in the market so... on the energy side. So there, we've got a good portfolio and we've tried to spread around the positions that we take and the product that we sell out of those to best match where we see the opportunities. And we think that market is tight and it's likely to remain tight going forward, we would expect to see some improvements in capacity prices overtime and energy prices-- as I said, we've got new facilities, that are well position low cost. So they'll do well. And particularly, if you see any kind of weather event which can really have pronounced effects on prices when your supply demand balance is right at the margin. If you go out West to look at the California markets, there you don't have a very well developed capacity market. So, we participate more in the energy markets there in the mass landing facility, we think we've got a new, one of the lowest cost production facilities in the West. So that facility does very well. If you go back to the Arizona plant... as Bruce mentioned we had put some contracts in place which help capture some of the increasing value that we see across time. But we also have upside potential associated with those facilities that we can continue to capture as those markets develop. So I am not sure if you had something more specific in mind, but that's our general view about the two areas.

That's great, thanks.

I would just, Greg I want to add one thing. Everybody want to... we usually want to talk about what's happening in the market with supply-demand or with pricing. In addition, it's important that we have assets that are going to actually operate in those markets. When the consumers need the power and that's where the traditional sources rather than renewables have been kicking at an awful lot. But what I really want to highlight is the operating performance. We rarely get a question on these calls, and I think to some extend, people sometimes take it for granted that while you're going to operate the plants when they are in the market and... Rich and his team on the operating side, I mean they had just had a stellar year last year in terms of operating the plants well. And that's a very important value driver, because it's not just about when is the pricing right. But do you have the asset up and running and in the market. And I think, I would just on this call like to highlight Rich and Keith and Dan and Sam and their team for their operating performance during the year.

Thanks.

Our next question comes from Ms. Shalini Mahajan.

Thanks and good morning. I just wanted to actually touch a little bit upon the market recovery, EBITDA that you gave in your December Analyst Meeting which was 1.8 billion. I am kind of thinking about the current environment impacting that number given, one, the commodities are up a lot today. But two, we are looking at a recession which might be an extended one. But how can you see these two factors impacting the extent and timing of recovery?

Well, I think... I am not going to try to give a recession prediction or a lack thereof. What we look for is... we look for kind of the signals that we see in the marketplace in terms of consumer demand for energy which continues to be high and continues to be strong. Probably the other area interestingly that we see evidence of how the economy is doing is when we look at the cost of labor and talent as we do things like the Consent Decree spending program and that sort of thing. And we see a very strong tight labor market there. So, we have got some very conflicting signals that we are seeing relative to all of the commentary around housing prices and sub-prime mortgages and things like that. I think there is a little bit of maybe a difference between sort of call it the broad U.S. economy and the energy economy. Because there can be some slowdown in the economy, but you continue to have strong to stable energy demand. And that's where we just need to be in market and having Rich and this team run those assts. So we are in market and available and operating. So we've got some conflicting signals I think in terms of what we are seeing. Now with crude oil coming up at $102 a barrel and NYMEX running 950 for 08 for gas and things like that. I think there are some high energy prices that are going to start to impact the U.S. economy generally. And may be that's... may be that pushes out some recovery a little bit. But I don't think from the signals that we are seeing its not that we see energy demand contracting or reducing or something like that. Maybe there is a slowing of demand, but not a decrease.

Okay. And then kind of just following-up on that question and looking at slide 22 where you pointed out both the upside on margins as well as high capacity factors for your intermediate and peaking fleet. If we have to kind of think of bear case, would that to be more on the capacities factor? Or on the margin front?

I think it's probably... the answer is probably if you do a bear case, I guess it's probably both. But it's probably... I guess I would go back to my earlier comment, it's probably a shift in time over plan those market recovery cases were to come about more than... in my opinion on... if they come about, because we didn't have it in this presentation. But I know we have used it in December and in presentations before. And if you think about how many years toll markets are in a very tight situation, it's probably anywhere from a couple of years to maybe three or four years at most out. And if somebody isn't already building the plant in these regions, not thinking about and asking for permits and licenses and getting communities support and things like that. But if they are not building it right now, it's not going to be on the ground in two to four years. And I think that's probably one of the major factors.

Yes and if I could just said one other thing real quickly as the way to think about it. The baseload facilities are baseload facilities and their production volumes are not going to go up, when things get tighter. And their production volume is not going to get down if there is recession. Yes it's the gas facilities that will begin to move, you'll begin to see the volumes go up in the combined cycle fleet as the economy tightens or as the supply demand balance tightens. And they will begin to move in response to what happens to spark spread. And then the peaking fleet will respond to what's going on in the supply-demand balance in the market. So, that's probably the way to think about it. One of the good things about Dynegy is we do have this portfolio so we have different parts of the portfolio that respond to different things. And overall, that gives us good exposure to the upside, but portfolio effect it gives us some stability across the whole system.

Yes, I might draw that back to the first question we had mentioning one of these other companies that has... have basically and all the bet is in natural gas and forward EBITDA growth. I think... again we would want to highlight for investors that we think the diversity of this portfolio gives you not only strong upside potential, but gives you sort of... a bit of... definitely what we call it baseload buffering in terms of some downside protection as well.

Great, that's very helpful. Thank you.

Okay.

Our final question comes from Mr. Lasan Johong of RBC Capital Markets.

Thank you, good morning. Bruce, quickly on that same page 22, you have the much of recovery on the intermediate and peaking plan. What does that represent in terms of EBITDA?

I believe those are the ones that... as we used December that... those sort of workout to the 1.8 billion case. And so we leave it up to you to determine at what years that will actually come in to being.

Excellent. And can I assume that you're really not going to look at building and you are saying with LS Power until you have a cost advantage that either lower the cost per KW or boost the returns. Is that a fair assumption?

Well we will look at moving forward with the project as long as it clears our cost of capital. And that we think that it's the right risk for reward decision for us. I mean, like we did with moving forward with Sandy Creek last year. But at the same time as I mentioned in my remarks, it is very tough to develop new projects in the country from both, a permitting and citing standpoint. And if something can move forward and that can be economic then that's a very good thing because it indicates that there are customers out there willing to sign the long term contracts that it will be needed to underpin the project. It also probably indicates... it does indicate that at least in that instance wherever that is in the country that we are at a point where prices on a current basis are justifying replacement cost. Because that's implicitly what it will be. In the meantime, things continue to be difficult. I think that's... for investors that's in fact good news for the operating portion of our fleet, because there is continued upside out there. And we would want them to focus on that element.

Okay then let me twist it in a slightly different way. What is now your cost-to-build Sandy Creek on a per KW basis?

No, I don't know if we... let me see. Somebody is going to grab a calculator here and... otherwise I can throw it to Lynn and duck your question Lasan.

Yes, I mean I don't know that we've ever said specifically what that cost is.And we have got things largely locked down, but we are going through the construction phase now. And we are also talking to people about additional sales out of that facility. So we are not particularly interested in tipping our hand. But you can tell from what we have said about Sandy Creek and what we have said about Plum Point. And the interest that we have sold there, that... that market value is in the 2,500, 2,600, 2,700, and 2,800 per KW range. And so, if you wanted a range, that's the kind of range that we see on those facilities.

As we think you know that one moving forward with... and again I am highlighting the difficulty that there is in getting all the necessary permits and overall support. And you are never going to please everybody with the new development and Sandy Creek is no example, but it did work its work its way through the normal approval process. And it got a full wetting in terms of regulatory approvals and citing commissions and air quality boards and all of that and even appeals and that sort of thing. And that one is moving forward. And I think there's probably a little bit of a scarcity value that ultimately can develop on the project.

Yes, I mean time to market can be a competitive advantage as well.

Let me ask you this way on Sandy Creek... I am sorry on Plum Point you were able to take advantage of somebody else's cheaper cost of capital to gain a cost advantage in building the facility.

You mean when we sold the piece last year?

Yes.

We didn't actually gain in advantage in the cost of the facility, it was.

So what it [ph] was already underway, we just saw a great price and the performance team jumped on that.

Absolutely and your cost on a per KW basis kind of decreased if you would?

Yes.

Can we expect something similar

[Indiscernible] investment.

I am sorry. Can we expect something similar on Sandy Creek?

If we--

Is that the kind of opportunity you are looking for?

If we had a similar investor who wants to buy a piece at a price greater than what we think its worth to hold to for our investors, we would similarly jump on that. I mean like you and I have talked in the past. I mean I equate of this a lot to like oil and gas. And you know you develop a project and you even sell down pieces and farm someone in. I think as you highlighted in one of your reports that was directly analitative [ph]. I have though about it and we would be willing to entertain those as well for Sandy Creek. That's just being opportunistic and transacting. And I think we have demonstrated a very good track record of doing that.

Lasan I... this is Jason, I think a good way to think of it in what you are trying to get at is that, back when LS signed up construction contract for Plum Point, we've previously mentioned that kind of a all-in cost a build at Plum Point is about $2000 a KW or so. Now with the passage of time, as labor and materials and all these things are more and more in demand and the cost to build goes higher and higher, the fact we signed up a fixed price construction contract and began breaking ground at that time and have advanced significantly during construction, gives us a cost advantage. And with some of the trends you are seeing in all the Consent Decree and the like that overtime the cost of Sandy Creek, we expect to be more and more attractive.

Very good thank you very much.

Okay, thank you. Before concluding today's call, I would like to remind you all to enroll in our program that enables you to receive future stock holding material electronically. This will help save all of our investors' money by reducing our printing and mailing cost and increasing efficiency. You can enroll on our web site, www.dynegy.com. Now, let me mention some upcoming investor out reach activities that various members of the management team will be participating in. First, we will be at the UBS Natural Gas and Electric Utility Conference in Austin, Texas on March 7th. Next we will be traveling to the Northeast for series on investor meetings spanning most of the week of March 10th. We also plan on attending the Deutsche Bank 2008 Energy and Utilities Conference on May 28th and 29th. And later this, year we'll be scheduling a trip to meet with investors in the Midwest section of the country. Thank you again for your time this morning and your interest in Dynegy. I look forward to seeing some of you again at these upcoming Investor events.

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