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Dynegy Inc. (NYSE:DYN)

Financial Guidance Call

December 10, 2008 8:00 am ET

Executives

Norelle V. Lundy - Vice President, Investor and Public Relations

Bruce A. Williamson - Chairman, President and Chief Executive Officer

Holli C. Nichols - Executive Vice President and Chief Financial Officer

Lynn A. Lednicky - Executive Vice President, Asset Management, Development and Regulatory Affairs

Analysts

Daniel Eggers - Credit Suisse

Lasan Johong - RBC Capital Markets

Elizabeth Parrella - Merrill Lynch

Brian Russo - Ladenburg Thalmann & Co.

Andrew Smith - J.P. Morgan

John Kiani - Deutsche Bank Securities

[Neal Metra] - Simmons & Company

Brian Chin - Citigroup

Operator

Hello and welcome to the Dynegy Inc. 2009 guidance estimates conference call. (Operator Instructions)

I now like to turn the conference over to Norelle Lundy, Vice President of Investor and Public Relations. Ma'am, you may begin.

Norelle V. Lundy

Good morning, everyone, and welcome to Dynegy's investor conference call and webcast covering the company's 2009 financial estimates and outlook.

As is our customary practice before we begin this morning, I would like to remind you that our call includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events with respect to our financial estimates. These and other statements not relating strictly to historical or current facts are intended as forward-looking statements. Actual results, though, may vary materially from those expressed or implied in any forward-looking 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.

Bruce A. Williamson

Thanks, Norelle. Good morning and thank you for joining our call regarding our 2009 estimates.

As we've traditionally done in early December, we're in New York this week for meetings with our investors, analysts and rating agencies, and joining me this morning on the call is Holli Nichols, our Chief Financial Officer, along with other members of our management team.

Let's now turn to the agenda for our call, which is highlighted on Slide 3 for those of you following along via the webcast.

This morning we will cover the company's anticipated financial results for 2009 and discuss how we position the company to withstand these turbulent markets. I'll begin by giving an overview of the company for investors, including a look at the long-term fundamentals of the power generation industry. Before turning it over to Holli, we'll spend some time discussing in detail our overall commercial strategy in response to your questions.

Holli will then provide a regional overview, with an in-depth look at value drivers and major assumptions by region to help you with your modeling efforts. She will also provide our 2009 estimates and cover sensitivities that can influence our earnings.

Finally, I'll conclude with a review of 2008, including lessons learned and how we'll apply them going forward into 2009.

Following our prepared remarks, we'll be glad to take your questions.

Please turn to Slide 4. Despite the extreme economic turmoil we've experienced this year, we believe the long-term supply-demand fundamentals for the power generation industry remain essentially unchanged. In the near term I think it is likely we'll see somewhat slower demand growth due to the economic slowdown. However, the financial crisis makes financing new power plants very difficult if not impossible, thereby creating the effect of an additional barrier to new entrants in the supply side.

Dynegy is very well positioned to weather the current market volatility and protect value today. Our balance sheet financial strategy is, in effect, our ultimate hedge against an economic downturn, volatility in commodity prices and financial uncertainty. We have ample liquidity of approximately $1.9 billion, with no significant debt maturities until 2011. In addition, our bank facility is locked in at LIBOR plus 150 until 2012, and our LT facility goes to 2013. So, in short, we have no need to access the capital or credit markets, so we're insulated from the current market turmoil.

In 2009 we expect adjusted EBITDA to increase approximately 10% over 2008 based on a midpoint of our estimated range. We expect adjusted free cash flow to be essentially neutral after internally funding all of our planned investments in emission control equipment for our Midwest baseload coal fleet.

Behind these estimates is a focus on protecting near term cash flows. We've created and we're working to maintain a flexible capital structure where we're not entangled with complex structures or significant restrictions. This has resulted in a reevaluation of our participation in future greenfield development activities. This includes the siting, permitting, financing and construction of greenfield projects, including projects currently under construction. This is in light of the rising barriers to new entry, including the tightening credit market.

We're also outlining our plans for enhancing value tomorrow. We intend to maintain our options and control around our existing assets and we remain focused on our core strategy of operating and commercializing well.

Given our belief that we're in a cyclical business that has not yet reached recovery, we also intend to maintain a commercial strategy that captures market opportunities related to stronger pricing in the future, but we need to do a better job of protecting the current cash flows than we did in 2008.

Lastly, we intend to position the company to evaluate other opportunities, which may include participating in industry consolidation or returning capital to our investors. Again, simplicity and flexibility in our capital structure like we have created are the cornerstones of our financial strategy and the drivers of any decision will ultimately come from what is the highest and best return we can achieve for our investors.

Please turn to Slide 5. I want to take a moment to provide some perspective on the broader topic of energy economics considering the volatile energy prices and economic events of 2008. Despite the recent economic downturn, global energy demand is expected to increase substantially over the next decade. Further, we believe the demand will be met by a mix of fuel types, with fossil fuels continuing to be the predominant choice. That's because of several factors:

First, our country has ample long-term reserves of coal and natural gas that we simply can't afford to ignore as we work to lessen our dependence on fuels from the Middle East and other regions that are marked by political uncertainty.

Second, the current low commodity price environment does not provide much incentive for renewables or research into new fuel technologies.

And third, we're at a point where the U.S. consumer simply doesn't want to be burdened with additional economic hardships.

So all this together means we still need to focus on basics like caulk management, contracting fuel early and opportunistically for our baseload plants to best position the company to benefit from the expected return to high commodity prices.

That said, we recognize the importance of environmentally responsible operations. We fully anticipate the introduction of new federal legislation that will effectively deal with CO2 and ideally SO2 and NOX and mercury, in light of the framework established for those emissions being stranded by a federal appellate court decision earlier this year.

The key takeaway here is that the fuels we use to generate electricity today will be here tomorrow. In fact, we believe our diversified portfolio, which is approximately 70% natural gas fired in terms of capacity, will see substantial increases in value and earnings power over the next decade.

Please turn to Slide 6, where we take a closer look at the fuel mix for U.S. power generation over the next decade according to estimates from the Department of Energy.

Without significant investments in new infrastructure and technologies, the fuel mix for the U.S. power industry will remain essentially unchanged. In today's financial and regulatory environments, intensive capital requirements and lengthy permitting cycles make construction of new power general facilities extremely difficult. And while there are a number of development initiatives currently on the drawing board, the current economic conditions may result in cancellation of many of these projects.

Given the fact that a significant construction cycle is not currently under way, it will take perhaps 10plus years before a meaningful level of new baseload generation will be operational. Therefore, a key operational value driver will be to ensure reliable operation of our plants, simply put, to be up and running when consumers need the power.

Please turn to Slide 7. Long-term power generation fundamentals remain, with demand expected to grow and supply expected to tighten over time. As demonstrated on the chart on the left, U.S. electricity consumption has historically trended upward. During recessionary periods, the U.S. has seen short-term dips and the country may see one in 2009, but there's no reason to believe that demand will not continue along the established trend line on a long-term basis. We also believe that future improvements in energy efficiency will be offset by growth in electricity demand, especially as regional generation supplies continue to tighten.

In this environment, new investment is needed. Cambridge Energy Research Associates projects that the industry needs about $1.2 trillion of capital investments over the next 15 years, including $600 billion of new generation. However, barriers to entry remain high. As you can see on the chart at the right, construction costs for coal and combined cycle projects have doubled from 2006 to 2008. Additional challenges to development include regulatory uncertainty and tight credit markets, with the high cost and limited availability of capital likely causing even more delays and cancellations.

All of this contributes to our belief that supply and demand will continue to tighten in the future, while over the near term incumbent asset values should rise.

Please turn to Slide 8. Now let's take a look at long-term commodity prices. One of the most obvious things with these three charts is their volatility, with major peaks and troughs. And while we're now experiencing one of those troughs, which may last longer than usual due to recessionary economic conditions, we don't expect prices to stay at current levels.

The second obvious thing you'll notice is that when we step back and look over several years, the overall trend line for each is headed upward despite the short-term volatility. Over the long term we believe that global demand for coal and natural gas will continue to put significant upward pressure, therefore, on power prices. And while near-term pricing has been impacted by natural gas volatility and a lack of liquidity due to the attrition of financial players, in general terms power prices have still risen year-over-year and we expect that trend to continue.

Please turn to Slide 9, where we'll discuss our commercial strategy. This strategy is underpinned by our strong balance sheet. The balance sheet or our financial strategy is, in effect, our ultimate hedge, and the practice of using your balance sheet has stood the test of time in the energy business. In this respect, strong liquidity and minimal near-term debt maturities provide security for our investors. They also allow us to contract our commercial positions in a volatile or rising price environment in a very efficient manner, without adding significant restrictions, covenants or complexities.

Now let's discuss our commercial strategy apart from the balance sheet. Dynegy employs a Current + 1 commercial strategy that seeks to provide stability to protect near-term cash flows from intrayear volatility resulting from weather events and other short-term commodity price spikes, as demonstrated by this view of CIN Hub on peak prices. Current + 1 is, therefore, intended to bring near-term stability against events we can't predict and protect near-term cash flows. For us, typical commercial contracts include heat rate call options, bilateral contracts, tolling agreements and financial swaps.

Longer term or for periods that are beyond the current year or the plus one year, we continue to believe that the power market fundamentals remain intact and that demand will in the future outstrip supply additions. This is data we can see and evaluate and watch, and given the dearth of new power plant developments, the market should continue to trend upward as this view of CIN Hub pricing suggests. As such, staying relatively open in the +2 and beyond years provides us with an opportunity to capture value in the fundamentally rising price environment.

Please turn to Slide 10. Our commercial strategy provides opportunities to capture rising price trends, but also brings exposure to downside risks. It's important to point out that our strategy is tailored by region to match market opportunities. For example, in the Midwest our assets are primarily baseload coal-fired facilities with very high utilization levels. These plants are generally in the money and run all the time they're operationally available, therefore our forward sale contracts in the Midwest region tend to be shorter term.

In the West, we primarily have natural gas-fired assets in a region with potential for large swings in demand from weather and from supply due to the huge impact of the hydro capacity in the region, so our West contracts tend to be medium-term in length.

In the Northeast we have a diverse asset mix, with coal, fuel oil and natural gas-fired assets. These assets are commercialized based on market dynamics and dispatch economics for both the fuel costs and the power sales.

We expect to enter 2009 with approximately 60% of the adjusted gross margin contracted through bilateral contracts, tolling agreements, capacity payments, financial forward sales, and options. This percentage declines in the outer years of 2010 and 2011 given our belief in the fundamentals and a rising price environment.

Please turn to Slide 11. Here we see the contracted positions for our consolidated portfolio. Again, going into 2009, approximately 60% of our adjusted gross margin will be covered by some contract arrangement. During 2009 we intend to monitor commodity prices and seek to capture additional short-term market opportunities for the remainder of 2009 and for 2010 as they arrive. Beyond 2010, our portfolio is more open, except for structured transactions that might include long-term tolls or capacity agreements. We believe that changes in market conditions or contracted positions can impact results either positively or negatively.

Before moving on, I want to make one last point about or commercial strategy. As a reminder, contracting does not negate all of our risks. It really diversifies the risk into other forms that we then carry. While contracting mitigates price risk and brings some cash flow certainty, there remain performance and finance risks, including collateral, which we proactively work to mitigate. This underscores one of our fundamentals, which is to operate well and to achieve high levels of end market availability.

Please turn to Slide 12 for a recap before I turn it over to Holli. Maintaining strong liquidity was a primary objective of 2008 and it will continue to be our foundation for 2009. We believe that strong liquidity and what we believe is the most flexible capital structure in our sector are the keys to our strategic plan for the company. As such, as of December 1 we had approximately $1.9 billion in liquidity. Additionally, we entered into a contingent letter of credit facility earlier this year that provides up to $300 million of additional liquidity that can be tapped in a high commodity price environment.

Second, as I said earlier, in terms of our debt profile, we have not significant maturities until 2011 and an undrawn credit facility that is not due until 2012 and a letter of credit facility not due until 2013. Additionally, our cost of capital and debt covenants are equivalent of what a strong investment-grade company could hope to achieve in today's market environment. All of this contributes to a relatively clear runway in terms of our not having to access capital markets to deal with debt maturities in these extremely difficult times.

Turning to 2009, we expect adjusted EBITDA to be in a range of between $825 million and $1 billion. Assumptions for our estimates are based on $8 natural gas and $61.50 for CIN Hub onpeak power, both of which we believe are conservative prices. Our adjusted operating cash flow is expected to cover environmental expenditures, maintenance needs, and protect our strong liquidity position.

With that, I'll turn it over to Holli to provide more details about our 2009 estimates and regional performance drivers.

Holli C. Nichols

Thank you, Bruce. Before starting, I would like to point out that these materials do contain non-GAAP measures that are reconciled in the appendix to this presentation.

Please turn to Slide 14. In my remarks I'll be covering Dynegy's regional drivers. Shorter term, our results are driven primarily by power prices, spark spreads, and our participation in capacity markets, and that's what I'll focus on as we cover the Midwest, West, and Northeast regions.

On a regional basis, I'll cover the performance drivers, including the price at which we sell energy and capacity type products, as well as the cost structure. In each region, I'll also spend some time focusing on what to look for. This will help those of you who are modeling us understand the variables that can influence regional performance. I'll also cover our key contracts by region, and then move to our capital expenditures over the next five years and our '09 guidance estimates.

Please turn to Slide 15 for a look at our Midwest segment. This includes more than 3,100 megawatts of baseload coal generation in Illinois, plus more than 5,000 megawatts of combined cycle and peaking generation in Illinois and surrounding states. The estimates we're projecting include volumes of approximately 25 million megawatt hours and an adjusted EBITDA range of $685 to $790 million.

Let's begin by considering some of the regional drivers that can impact results. In MISO, there's the outright power price for uncontracted baseload volume as well as spark spread for uncontracted natural gas-fired peaking units. At PJM, there's a spark spread for uncontracted combined cycle and peaking units. And in terms of capacity markets, consider that MISO is sold under bilateral agreement while PJM capacity is sold in forward auctions over three years. The auction process and the three-year forward market make the capacity market in PJM more transparent. In terms of pricing, we're seeing MISO prices trending with PJM prices, both slightly lower.

Now consider some of the performance drivers that will shape our results in 2009. In the Midwest, price volatility can create upside opportunities and expose us to downside risk. Recalling the CIN Hub chart that Bruce just shared a few minutes ago, hub price volatility can impact our baseload plants. Also, the outright spark spread can dictate the run times and margins related to our Kendall and Antwane combined cycle plants.

On cost, our Midwest baseload fleet uses 100% Powder River Basin coal, which has not seen the dramatic price increases that Eastern coal has experienced as a result of global demand. In addition, we have strategic contracts that lessen our exposure to the volatility of the spot coal market.

Taking a closer look, our rail transportation cost is substantial contracted through 2013, with no fuel escalators. In addition, our coal supply is now contracted through 2010 at largely fixed pricing and a meaningful portion is contracted to 2012. Also, our contract positions roll every two years and some include price caps. As such, we expect changes in our future coal costs to be consistent with our historical annual price increases of perhaps $0.10 or so per MMBTU over the next few years. This results in a low delivered cost of coal, which offers significant competitive advantages in terms of dispatch cost. In fact, our dispatch cost equates to approximately $20 per megawatt hour on average for our Midwest coal fleet.

Another Midwest cost relates to our multiyear environmental investment and has already resulted in a significant reduction of coal plant emissions. In addition to the cost related to the investment in emissions control equipment, there's a higher operational cost associated with running the new equipment. This includes activated carbon to operate mercury controls as well as additional labor. This is expected to result in an increase of approximately $15 million in 2009.

In this region some of the things to look for this next year include the following: First, improvements in capacity markets in MISO. Unlike PJM, the MISO capacity market is not liquid in the outer years. However, average MISO capacity payments tend to follow PJM capacity payment trends over the longer term. Second, weather can impact volumes and prices for our combined cycle fleet and the absolute price received for our coal fleet. And third, track the CIN Hub to Illinois Hub basis differential as this, too, can impact the margin we realize.

We're frequently asked about our commercial profile in each region. In the Midwest, where operating expenses are relatively fixed, approximately 60% of our expected adjusted gross margin is contracted. As we move through 2009, the percentage of adjusted gross margin contracted will increase. Beyond 2009, the portfolio is essentially open to take advantage of the longer-term market trend of increasing prices.

Please turn to Slide 16, where I'll discuss our key contracts in the Midwest. Also more detail to help you with your modeling efforts can be found in the appendix of the presentation.

In the Midwest our commercial activity largely centers on the baseload coal fleet. Approximately 1200 megawatts of our '09 peak production and 1600 megawatts of off-peak are contracted financially using power [slots]. Additionally, we have 200 megawatts of around-the-clock power that was contracted at $65 per megawatt hour in the Illinois option back in 2007. This extends through May 2009 and traditionally has a 50% load factor.

In terms of our combined cycle assets, a tolling agreement for Units 1 and 2 of our Kendall plant rolled off last month. So outside of the 280 megawatt tolling agreement that extends to 2017 for Kendall Unit Number 3, the rest of our Midwest combined cycle fleet will be commercialized on a merchant basis in 2009.

Term capacity sales include our participation in PJM capacity auctions and the box on the right slide of the slide demonstrates the megawatts we've cleared in these auctions as well as the auction prices.

In MISO, approximately 1100 megawatts of bilateral capacity sales are in place in 2009.

On the fuel side, I previously touched on our PRB supply and transportation agreement. Again, a significant portion of our supply is contracted to 2012, and our rail cost is contracted to 2013, with no fuel escalators. This results in an average delivered coal cost at Baldwin of approximately $1.49 per million BTUs for 2009.

Please turn to Slide 17, where we'll shift our attention to the West region, which includes approximately 6000 megawatts of natural gas-fired generation. The dynamics of our West segment are quite different from our Midwest region. You'll see a set of performance drivers and regional drivers. We're estimating volumes of 11.4 million megawatt hours for the West and an adjusted EBITDA range of $185 to $205 million.

Regional drivers include the spark spread for uncontracted gas-fired, combined cycle and peaking units, as well as ancillary services. I'd also like to point that twothirds of our estimated adjusted gross margin in the West is attributed to tolling agreements.

On the cost side, we don't procure natural gas in advance for our uncontracted megawatts. Rather, natural gas is purchased as needed at index-related prices. For our contracted facilities, tolling counterparties take the financial and delivery risk of natural gas.

In terms of where our natural gas sets in a market where natural gas sets the marginal price of power, the things to look for include spread variability not already mitigated by contracted positions. Additionally, summer weather can impact volumes generated by our combined cycle units, as well as margin for our uncontracted assets. For that reason - and again, for your modeling purposes - look for the largest percentage of our earnings in the Midwest in the third quarter.

Also, because California doesn't have a formal capacity market, the utility should have greater resource adequacy requirements in 2009. In addition, operational performance will be important, as the majority of our plants operate under term contracts. This means that if they're not running, we have to buy power from other sources, which can impact our margin.

Lastly, in the West you'll see that we have approximately 85% of expected adjusted gross margin contracted and relatively fixed operating costs going into 2009. We believe this is the best approach for mitigating volatility since weather impacts, including hydro availability, can result in significant swings within a given year.

Please turn to Slide 18 for a look at our key contracts in the West. Here you can see our revenue contracts, most of which are tolling agreements, but also include RMR and capacity arrangements. The more significant contracts include a substantial heat rate call option on Moss Landing 1 and 2 that runs through September of 2010, a toll on Morro Bay that begins in January of '09 and runs through 2013, and tolls on the Griffith and Arlington combined cycle plants in Arizona. The Griffith toll extends through 2017, and elements of the Arlington toll run through 2019.

On the fuel contract side, as I covered on the previous slide, tolling counterparties assume the risk for fuel supply and delivery. And on our merchant volumes, we will buy the fuel when it is needed at index prices.

Before moving on, I'll remind you that during the next two years we're approximately 85% contracted, so you shouldn't expect much variability in the West segment.

Please turn to Slide 19, where I'll cover our Northeast segment. Investors can think of the Northeast as a hybrid region for Dynegy. We operate approximately 3800 megawatts in the Northeast, and our plants include low key rate combined cycle units in Upstate New York, Connecticut and Maine, as well as the coal-fired baseload facility and a large fuel oil asset, both of which are in New York Zone G.

For the Northeast we're projecting generation volumes of 7.8 million megawatt hours, with a range of adjusted EBITDA of $85 to $125 million.

Before moving into our Northeast discussion, I'd like to note that our adjusted EBITDA range includes the amortization of the ConEd capacity contract and the Central Hudson lease obligation. In 2009, we expect to receive net payments of approximately $100 million under the ConEd capacity contract. Of this amount, only $50 million is recognized in earnings due to the purchase accounting treatment that resulted at the time we acquired the independent facility in 2005. Also, we include a $50 million expense related to the Central Hudson lease, however the cash payment for '09 is approximately $140 million.

Now, moving on to our Northeast regional drivers, these include spark spreads for uncontracted combined cycle gas units and outright power prices for uncontracted baseload coal volume. In addition, runtime for our Roseton facility can be driven by weather events, combined with a favorable fuel oil spread.

With regard to costs, we've experienced increased cost for our South American coal for our Danskammer unit given the run up of the international coal market. A substantial portion of our Danskammer coal supply and transportation has been contracted for 2009, and I'll provide a little more detail on that in the next slide.

A final cost performance driver is the implementation of RGGI and how it will impact our overall cost of operation. Our plan assumes we will purchase the required credits over time through periodic auctions as well as the secondary market. RGGI credits as of the last auction cleared just over $3 per ton.

Things to look for in the Northeast market, where natural gas sets the marginal price of power, include the following: First, look for a margin impact related to South American coal costs, as not all costs have been fixed for 2009. Second, look at the run time of our Roseton plant which, again, is dependent on weather and a favorable fuel oil spread. We've included approximately $10 million of margin for Roseton in '09 based on minimal run times. And finally, weather and spark spreads can impact volumes and margins of our combined cycle fleet in the Northeast.

Looking at our commercial strategy for the Northeast, approximately 50% of our expected adjusted gross margin is contracted going into 2009, again, with relatively fixed costs. Beyond '09, our portfolio is very open.

Please turn to Slide 20 for a look at our key contracts in the Northeast. Relating to revenue contracts, you'll notice we see capacity contracts on our combined cycle units. I mentioned the Independence and ConEd contracts on the previous slide. We also have price certainty on capacity for our Casco Bay and Bridgeport plants in New England through their participation in previous auctions. In addition, we have a 200 megawatt power swap on our Danskammer facility, as well as the heat rate coal option on Independence and Casco Bay.

With regard to fuel, we procure coal, natural gas and fuel oil. We've entered into one twoyear contract for our Danskammer coal supply, which is primarily sourced from South America, and about 70% of this is priced for 2009 at fixed cost, including delivery. Natural gas to run our combined cycle plants is purchased on an as-needed basis, and at the Roseton facility, where we have 1 million barrels of on-site storage capacity, we'll purchase fuel oil opportunistically.

Please turn to Slide 21, where I'll cover our anticipated CapEx through 2013. We're projecting CapEx of $490 million in 2009. This is largely comprised of environmental and routine maintenance projects. The overall number will decrease in subsequent years as we make additional progress on our previously announced Midwest environmental investment to further reduce emissions.

With regard to this upgrade that we're making to the coal fleet, we're on track for completion in 2012, and about a quarter of our remaining costs are fixed. As you may be aware, this work includes baghouse and scrubber projects in aid of our Midwest units. This fleet already has reduced emissions of sulphur dioxide and nitrogen oxide by approximately 90% in the last 10 years, largely through our conversion to PRB coal. The baghouses and scrubbers are designed to further reduce mercury particulate and sulphur dioxide emissions.

Shifting gears to routine maintenance, the timing is generally more predictable for our coal assets, with maintenance costs and schedules for gas plants more sporadic. More specifically, maintenance CapEx on coal facilities includes boiler overhauls every two to three years and major turbine overhauls generally every six years. The size of the unit will drive the cost. In all the forecasted years, there are approximately 20 to 30 weeks of planned outages for our coal fleet. In 2011 and 2013, there are fewer outage weeks and outages are on smaller units, thus resulting in lower CapEx in those years.

Maintenance CapEx on gas facilities is not as predictable due to hot gas path and major inspections that are driven by a calculation of equivalent operating hours that includes run times and startups. Hot gas path and major inspections typically occur every four and eight years, respectively, at an average cost of approximately $10 million.

I'd also add that in the line Maintenance - Other Facilities, we've included $15 million for corporate CapEx as well as maintenance for Roseton.

And before moving on, we're anticipating approximately $30 million in discretionary spending in 2009, and we'll continue to assess projects on an annual basis as we go forward.

Please turn to Slide 22, where I'll cover our consolidated 2009 earnings estimate. I'm going to focus on adjusted measures, but GAAP measures are included at the bottom of this slide and in more detail in the appendix to this presentation. But before moving to our adjusted EBITDA measures, we've added contracted and uncontracted adjusted gross margin as well as operating expense. We plan to update this breakout on a quarterly basis and, as we move through the year, the percentage of adjusted gross margin contracted will increase.

Operating expenses are relatively fixed, coming down to adjusted EBITDA. From there, you can decide how to adjust the uncontracted margin based on your own pricing assumption. The estimates we're providing are based on $8 per MMBTU 2009 forward gas curve.

We estimate total adjusted EBITDA of $825 million to $1 billion for 2009. This includes a contribution of $955 million to $1.12 billion from our generation business segment and a use of $120 to $130 million from other, which primarily includes D&A and interest payments offset by interest income.

We're projecting a range of adjusted cash flow from operations of $360 to $535 million, which includes interest payments, cash taxes and working capital.

Taking into consideration maintenance CapEx of $155 million, environmental CapEx of $280 million, and capitalized interest of $25 million, we're projecting an adjusted free cash flow range of negative $100 million to positive $75 million.

Please turn to Slide 23. Here, let me walk forward our '08 estimated results for adjusted EBITDA to our '09 projection. I'll take you through a series of adjustments, all of which are approximate amounts based on range midpoints. Let's start with our '08 adjusted EBITDA of $840 million as estimated on November 6, then incorporate the following adjustments - an increase related to higher prices and volume; an increase related to additional capacity sales; and an increase related to the new Morro Bay toll that begins in January of '09, as well as some other miscellaneous items.

In addition, you should consider a decrease related to higher operating expenses, part of which includes the impact of higher costs related to the new emission control equipment in the Midwest, a decrease related to higher Danskammer coal costs, a decrease related to the Kendall toll that rolls off in 2008, and a decrease related to higher Midwest coal costs. And comparing to midpoint of 2009 adjusted EBITDA projection to 2008 estimated results, we're anticipating an approximate 10% increase in adjusted EBITDA.

Please turn to Slide 24. In this chart, I'll compare '08 estimated results for adjusted free cash flow with our '09 projection. Again, these are approximate amounts based on range midpoint.

Let's start with our '08 adjusted free cash flow estimate of $25 million. For '09 there is an increase in adjusted EBITDA year-over-year largely related to increased price, volumes and capacity sales; a decrease in interest payments due to lower LIBOR rates; an increase in environmental CapEx compared to '08 estimates, largely resulting from our investment in emission control equipment in the Midwest; an increase in working capital, primarily related to the timing of contract settlements; and finally, an increase in maintenance CapEx in 2009. This is primarily due to maintenance on Midwest units that are already down for environmental work, in effect, taking advantage of the down time. This is partially offset by decreased maintenance expenses in the West and Northeast.

Overall, the midpoint of our 2009 adjusted free cash flow estimate is essentially neutral. Compared to our '08 estimate, 2009 reflects increased prices and volumes, offset by greater environmental CapEx that trails off after 2009.

Please turn to Slide 25. Here I'd like to discuss some things that you should consider when looking at the future. Various factors will impact our business, both positively and negatively. Some of these situations are beyond our control, and the outcome and timing is difficult to predict, making the preparation of guidance estimates challenging. Often, events and variables are interrelated, and business impacts are not always additive, further complicating forecasting.

As we've listed here, there are numerous factors that can impact results. We're providing sensitivities for natural gas and market implied heat rates that I'll take you through; however, don't lose sight of the fact that these are not the only factors that can lead to higher or lower results. While many of these other factors are difficult to model, they should continue to be monitored over the course of the year.

Please turn to Slide 26. Here I'll demonstrate the sensitivity of our generation business and our adjusted gross margin estimate to natural gas commodity pricing. The first sensitivity is based on full year estimates with our current contract profile and assumes the natural gas price change occurs for the full year across the entire portfolio.

Looking at the different cost scenarios at the top of the slide, you can see that a $1 increase in natural gas would result in a $70 million increase in generation adjusted gross margin in a portfolio that is approximately 60% contracted. Conversely, a $1 decrease would result in a $70 million decrease in generation adjusted gross margin in a portfolio with a similar commercial profile.

On a longer-term basis, if you assumed an uncontracted position, you could expect a $1 increase in nat gas to result in a $165 million annual increase in generation adjusted gross margin and a $1 decrease would result in a $145 million decrease in generation adjusted gross margin - again, in an uncontracted portfolio scenario.

A key takeaway here is that change in natural gas price without a change in the spark spread primarily impacts our full baseload unit.

Let's now turn to Slide 27, where I'll provide sensitivities relative to market implied heat rates. These sensitivities are based on on-peak power price changes and full year estimates. Sensitivities assume a constant natural gas price of $8 per MMBTU and heat rate changes are for a full year. Further, increased run times will result in increased maintenance costs, which are not included in this sensitivity.

Please take a look at the box on the left, which considers our 2009 contracted portfolio. Here you can see that a change in market implied heat rate of 500 BTUs per kilowatt hour would result in an $85 million increase in generation adjusted gross margin. To show the impact of falling heat rates on our contracted portfolio, we demonstrate here that a decrease of 500 would correspond with a $70 million decrease in generation adjusted gross margin.

Looking at the long term and assuming an uncontracted portfolio, an increase of 500 BTUs per kilowatt hour would increase annual generation adjusted gross margin by $175 million. Conversely, a decrease of 500 would lower annual generation adjusted gross margin by $135 million.

The key takeaway here is that changes in market implied heat rates primarily impact our natural gas-fired fleet. As a reminder, this includes approximately 13,000 megawatts of combined cycle and peak generation assets. In addition, you should assume that higher power prices could also benefit our pull through.

Please turn to Slide 28, where I will wrap up with a quick discussion of the variability of our adjusted EBITDA range. On a consolidated basis, Dynegy expects to enter 2009 with 60% of its adjusted gross margin contracted. I would note that this is a snapshot in time and, if market conditions dictate, we could continue to commercialize our portfolio through the end of 2008.

While our commercial strategy provides some margin stability, upside and downside continues to exist, most of which we've covered. Additionally, as we develop our plan for the year, we do consider the impact of forward curves and volatility on our uncontracted generation. Earnings will ultimately be impacted by realized prices and the volatility of those prices through time. We manage our portfolio by being aware of current conditions, continuously evaluating and cultivating our options, and maintaining a diverse portfolio and, most importantly, by operating our assets well to be in a position to take advantage of commercial opportunities.

That concludes my part of today's presentation. I'll turn it back over to Bruce.

Bruce A. Williamson

Thank you, Holli.

Please turn now to Slide 30. I'd like to conclude today with a recap of 2008 and an outlook for 2009. In the what went well this year column I would first list the 93% in-market availability of our baseload coal fleet in the third quarter, which was last updated at the end of October. This is a telling indicator; where the market called on us for energy, we were well positioned to deliver it. It also reflects a very strong effort after two forced outages early in 2008 that impacted our performance in this area.

As I mentioned, we created capital and credit structures that mitigate our exposure to the market turmoil while maintaining strong liquidity.

We've repriced our PRB coal contracts, achieving a minimal price increase in cost through 2010, and we also locked in approximately 35% of our 2011 and 2012 supply at attractive price levels. In addition, we've entered into long-term tolling agreements in the West that provide some predictable stream of cash flows, and we commercialized portions of the Midwest fleet at attractive on-peak prices.

This past year we sold Rolling Hills for approximately $370 million in cash, monetizing an asset that was not earning very much.

Now to things that didn't go so well in 2008. We had two significant forced outages, one at Baldwin and one at Havana that reduced sales volumes early in 2008, when margins were quite good. We realized lower net margins later in the year due to widening basis in the Midwest caused by a combination of flooding, transmission constraints and some lessthanoptimal commercial execution.

In the Northeast, we were forced to recontract the pricing of some South American coal, which impacted our results adversely. And in the third quarter we experienced very mild weather, much milder than anyone expected, resulting in decreased volumes and margins in both the Midwest and the Northeast.

Now let's look at how we will apply those lessons learned in 2008. going forward, we will continue to focus on strong operating reliability. We'll continue to maintain strong liquidity and our simple, flexible capital structure as our ultimate hedge. And we will need to improve our execution in the commercial function to better protect near-term cash flows through the current Current + 1 part of our commercial strategy. We need to work with our coal suppliers to further contract fuel supplies, and we need to continue to focus on managing spending when we see a return to the rising cost environment. Again, we will be actively monitoring all of these to protect value.

We've discussed the company's strong financial profile. This is one differentiating competitive advantage for us that enables us to focus on operating and commercializing well. We don't have to fundamentally change the way we run the company in light of today's economic conditions or the depressed financial markets.

And with that, let's move on to the question-and-answer portion of our presentation. Operator, we'll take the first call now.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Your first question comes from Daniel Eggers - Credit Suisse.

Daniel Eggers - Credit Suisse

Just for some clarification on some of the sensitivities to the guidance range this year, would $8 gas equate to effectively a midpoint EBITDA guidance of the $915 million, and then if we thought the $825 to $1 billion, would that be $1 plus or minus on gas? Is that the right way to think about the number you gave?

Holli C. Nichols

I think that's right, Dan. The $8 gas, if you then just take that to a midpoint, that is the $915 of EBITDA. And then you would want to stress natural gas and a heat rate off of that midpoint as you think about the range.

Bruce A. Williamson

I think, Dan, you also have to, though, take into account with, you know, gas prices having come off, we've also seen coal prices come off, so the open amount of coal, for example, for next year on the Northeast fleet, we would anticipate getting some pickup there.

And I guess, Lynn, you're here, you might comment. I mean, if we re-ran things today, we would still come back at about the same midpoint, correct?

Lynn A. Lednicky

Yes. We've got a number of things that offset within the portfolio, so even though commodity prices are down if you look at gas, heat rates have moved around. We see some impact on coal. So we would still be in the middle of the range if we re-ran things today.

Daniel Eggers - Credit Suisse

So in today's world, even in a $6-ish forward curve, the plusses would offset the minus on the gas side as you're looking at it?

Lynn A. Lednicky

Well, you would be always at the midpoint, but it wouldn't be accurate to, for example, say gas is down roughly $2, therefore we should take the midpoint down by, you know, $120 or $140 million.

Holli C. Nichols

I think it's fair to say, Dan, we're still very comfortably within the range that we've put out today for our EBITDA estimate.

Daniel Eggers - Credit Suisse

So you would say that if things held as they were today, you would be within the $825 to $1 billion, but probably closer to $825 than anything else?

Lynn A. Lednicky

We're probably still closer to the midpoint, but certainly well comfortable within the range.

Daniel Eggers - Credit Suisse

Just another question for you. On the Danskammer contract for coal, what price index should we follow to think about that open 30% position for this year?

Lynn A. Lednicky

Well, that's a good question, Dan. The Puerto Bolivar index is probably the closest, although that index is not very liquid. In general, what we see is that those prices generally track the international markets, so we actually have difficulty in using an index number to predict where that's going to be and actually form our views based on conversations with our suppliers.

Bruce A. Williamson

The [inaudible] closest to the -

Lynn A. Lednicky

The Puerto Bolivar index for supply is out of Venezuela.

Operator

Your next question comes from Lasan Johong - RBC Capital Markets.

Lasan Johong - RBC Capital Markets

Bruce, you'd talked about M&A opportunities or consolidation and share repurchases. Are you seeing any opportunities today and what kind of share repurchase options are you looking at?

Bruce A. Williamson

Well, I usually let Holli handle that, Lasan, because it deals with liquidity and capital allocation. So from a standpoint, I guess I would say, you know, those are options for us. As you know, we've got a very flexible capital structure that enables us to do that.

At this point, you know, going back a year ago, that's when share buybacks really reared their head pretty significantly for us, and we went from the meeting that we're having in effect today a year ago - we told all of you that we wanted to build our liquidity, maintain liquidity, deliver free cash flow through the year, and then see how sort of the energy economy and supply/demand were looking out into 2009 and 2010, so we did that.

I will tell you, it feels pretty good right now to have $1.9 billion of liquidity and call it around at this point, after some debt repayment, it's almost $1 a share in cash on hand. It feels very good to not have any issues of liquidity, any issues of financial concern given how turbulent the market is.

Holli, would you like to add to that?

Holli C. Nichols

I think you captured it. I think it goes back to the conversations we've had, Lasan, that there are two phases to the capital allocation program. The first phase is deciding that you want to utilize your liquidity for anything other than just maintaining the strong balance sheet that we have right now. And once we've made that decision, as I've said in the past and Bruce has said, everything will compete for that capital, and we'll look at things on a return basis and that would include, certainly, share repurchase, debt repurchase. Asset purchases it's tough to throw in there right now based on where everything would be priced, but theoretically that would go into the analysis as well.

Bruce A. Williamson

And I would say today leading the charge would be looking at returning money to investors, so that's either share repurchase or debt repurchase relative to asset acquisition.

Lasan Johong - RBC Capital Markets

Well, you said it best, Bruce. You've got almost $1 in cash in your share price. I think it's a matter of how much, not when you do this, but that's just my opinion.

Second, you had said your presentation that you think forward looking there's a substantial trend line towards increasing commodity prices of everything. It seems like that seems contrary to your position on hedging. I mean, '09 you're substantially - well over substantially - hedged in '09, and in 2010 you're pretty close to being substantially hedged. Help me reconcile the two, because if you believe that there's more upside coming, why are you so highly hedged?

Bruce A. Williamson

Well, I think, you know, it comes down to sort of splitting the two - I guess splitting time into two buckets, I guess, is how I would put it. The current year, which is 2009, effectively, for this presentation, and the plus one year, let's call that one bucket, and then plus two and beyond, and let's call that the second bucket of time.

Within that shorter-term bucket, you know, I think we need to go ahead and take opportunities when we see attractive pricing. And we can all argue over what's attractive, but it falls in the  good enough pricing to go ahead and take it, commercialize it in that short-term period, because what's really going to drive pricing in the next year is probably weather more than anything else. We get cold weather this winter, we get a hot summer, we'll have high gas prices, then in turn driving high power prices and so on.

On the longer-term basis - well, before I leave that, in the short-term we don't obviously have any control over that, and so I think protecting ourselves from the inverse of that - a mild winter and a mild summer - is just probably being prudent in making sure we've got cash flow certainty.

When we get to the longer term, going out to a plus two and beyond, you know, that's where we've tended to take a much more open position than some of our competitors because that's going to be driven more by supply/demand fundamentals, and are people putting new plants on the ground as their new supply coming into the market and things like that, where we can actually look at the data and evaluate it and see how the market is shaping up.

So that's where we see the trend and the upside potential for our investors, and I think we're just trying to strike a balance in the short end. You know, as I think about last year - or this year, I guess; we're referring 2008 in the past tense here - we basically had commodity prices starting in roughly January just move straight up, with gas hitting $13 and CIN Hub for '09 hitting around $80  $85.

As we hedged into that, we had some analysts - I think yourself included  disappointed that we had hedged at all, taken to the extreme. And then we had prices equally trend almost the same way directly back down in the back half of the year, and we've had a number of your friendly competitors upset that we didn't lock everything in.

So we're trying to strike a balance between the short term and the medium term, and balance off, you know, weather-based volatility in the short term, where we don't have any advantage or any position to take a position on that, against the longer term, where it's more supply/demand driven.

Lynn A. Lednicky

And Lasan, this might help you just a little bit. If you look at Page 10 in the presentation, you see we break out what those forward contractual arrangements look like by region. You see they're very different in each region because of the term structure that we have. And you'll also note that in the Midwest and in the Northeast there are some positions in the future, but in many respects those are largely capacity payments.

So that's the structure of that market and that's what we know and that's what we've done. And that's already done; that's not really a bias on our part about what future energy prices may be. So we're still exposed for the upside potential associated with those energy prices, but where we have term structures that go out longer. That's why you see [inaudible], for example, that 40% of our expected gross margin is contracted to 2010.

Lasan Johong - RBC Capital Markets

Let me just get a quick sense of your hedging profile in '09, if you don't mind. I'm assuming you're not flat 60% hedged straight across 12 months, so quarter by quarter, am I to assume that you've got more hedges in the first quarter and maybe the third quarter and less hedges in the second and fourth quarter, or is it the other way around?

Lynn A. Lednicky

Well, I guess, first of all, going through 2008, we put 2009 positions in place. And when we were early in 2008 - we tend to put on calendar year positions and as we get to, you know, this time of the year, we might not put on calendar year positions; we might put on seasonal positions such as a Q1 or a Q3.

So at this point it is relatively flat still, although there's probably more forward position in the third quarter. As we go through the year, we'll discriminate a little bit more based on what kind of opportunities we see.

Lasan Johong - RBC Capital Markets

So still relatively flat, but maybe a little bit more prejudiced towards third quarter?

Lynn A. Lednicky

Yes. And in particular that would be true in the West, where some of the tolling arrangements we have are really only in place for the summer months. But I don't think that that should materially change how you think about modeling the company.

Lasan Johong - RBC Capital Markets

I have one last question. I'm trying to reconcile your answers to Dan Eggers. It's a little confusing for me. If you are - according to what you said, at the current forward prices, the EBITDA number would be roughly, say, in the range of $875 to $900 million or something close to $915, but the midpoint of the guidance is $8 and the forward curve is $6. So that means that if the current conditions prevail, all else being equal, if the gas prices jump by $2, are we not at $1.040 billion around?

Bruce A. Williamson

Well, what we need to have - what you need to remember there, Lasan, is, let me put it in the path  let me describe an analogy to this last year. When gas hit $13 in June, we didn't necessarily have a corresponding increase on just an absolute dollar-for-dollar basis with power prices. Similarly, when gas now has come down from $8 to call it $6, we haven't seen that dramatic of a falloff in power prices, again, on a dollar-for-dollar basis.

You then do have some things that have gone the other way, whereas coal prices have come down. That lets us have some pickup on South American coal and some various things like that. And so, you know, all these commodities don't just move on a one-to-one basis with each other, as you know.

That's where, when we, if we were to re-run this plan, we would still be pretty comfortable that we're right around the midpoint.

Holli C. Nichols

As a specific example, Lasan, if you were to look at the quoted power price for CIN Hub and you think about what's happened with gas, based on the market implied heat rate we used for our plan, it's up actually 500 when you look at a $6 something gas price. So there's definitely offsetting factors that you need to consider because you're right, if you'd looked at just one in isolation, it would give you a different answer. But when you add everything up, that's why we're down only slightly from our estimate.

Lasan Johong - RBC Capital Markets

It sounds like your sensitivities are too broad. That's what it sounds like to me. Instead of having a $70 million change in EBITDA for $1 change in gas, it ought to be closer to $30 million.

Holli C. Nichols

They're blunt instruments, you're right.

Bruce A. Williamson

Well, they're all done on a - you know, the modeling team there just takes it and they run it on let's assume gas price change and everything else holds constant, let's assume heat rates change, everything else holds constant. And in the real world, obviously, none of these things move independent of each other.

Operator

Your next question comes from Elizabeth Parrella - Merrill Lynch.

Elizabeth Parrella - Merrill Lynch

What date are these commodity forecasts - price forecasts - as of and are they just essentially a [inaudible] date or is it intended to be some reflective of some fundamental view that you're going to see higher prices than what's embedded in the forward curve?

Bruce A. Williamson

Well, we start out with - it was probably set back around mid-October or somewhere around in there, and then we look at it from a standpoint of rather than just taking the forward curve and just running those through, we apply I guess you would say our judgment of what we think is a reasonable planning case for gas, for on-peak power or off-peak power, and all of those things.

So I wouldn't say it's tied to a date. The forward curves have proven themselves time and again to be completely erroneous for anybody to utilize, so they're just, in effect, our assumptions.

Elizabeth Parrella - Merrill Lynch

And then going back to something you said earlier, Bruce, that you're reevaluating your role in development, and I wanted to ask you specifically on Plum Point and Sandy Creek, what this implies, what things you're considering? And Plum Point's already financed, you don't have an equity commitment there, but Sandy Creek you do, I believe, in 2012. Maybe you can refresh for us what that number looks like today and, again, what sort of things are you looking at with respect to those two plants?

Bruce A. Williamson

Well, those two plants are basically, I mean, I've said in various investor sessions over the years, they're basically financial options for us. They're not in our core regions of the Northeast, the Midwest or the West, and so they represent value opportunities for us to harvest for our investors. And so that's why we would view those, you know, they're really not part of those three core portfolio positions, and I wouldn't look for us to be out adding additional financial options, in effect, through other greenfield opportunities outside of our core regions.

And so, you know, when you put that together with how the market is in terms of your ability to finance anything new right now, to get permits for anything new, we just think that a better use of our time and capital is to look at opportunities internally around our operating portfolio. So if there are operating assets that have re-powering opportunities or redevelopment opportunities, that's where we would to put our time and our effort because they'll fit in with our portfolio over the longer term.

Similarly, you know, going back to Lasan's question, when you think about use of excess cash, if you have a choice between share buybacks, bond repurchases, which are trading in these financially turbulent times at a discount, or development, which by default is at 100% of replacement cost, it falls out clearly on that pecking order; it's third on the list.

So development, I think, is just something that we're not seeing very much going on in the country. If anything, that realization is supportive of the fact that the value of incumbent assets should be rising substantially.

Elizabeth Parrella - Merrill Lynch

And what is the equity commitment right now to Sandy Creek in 2012, your piece?

Holli C. Nichols

It's $275 million in total, Elizabeth. And if you think about it, those would be the late dollars spent, so that would show up some time likely in late 2010 - 2011 timeframe. And keep in mind that we have posted an LC that's actually the cash for that commitment, so that's already taken out of our liquidity.

Bruce A. Williamson

That's funded.

Elizabeth Parrella - Merrill Lynch

I'm sorry, it's taken out of liquidity?

Bruce A. Williamson

Yes.

Holli C. Nichols

Yes.

Elizabeth Parrella - Merrill Lynch

One other question for you. Coming back to an earlier question around the Danskammer coal, the open position, the 30%, if you were re-contracting or contracting that remaining 30% today, where do you think it would come in at versus I think you told us something like 583 delivered on the 70%?

Lynn A. Lednicky

In terms of a price it would be someplace probably in the mid 4s. But that's still an open issue for us and, you know, commodity prices are moving around quite a bit. So we'll see where we end up with that.

Elizabeth Parrella - Merrill Lynch

Just a point of clarification on that Slide 33, where you're talking about the 583 delivered. Is that intended to be an average cost across the entire coal supply, meaning including the unhedged piece?

Lynn A. Lednicky

Yes.

Elizabeth Parrella - Merrill Lynch

So the hedged piece is presumably higher than 583?

Lynn A. Lednicky

Yes.

Operator

Your next question comes from Brian Russo - Ladenburg Thalmann & Co.

Brian Russo - Ladenburg Thalmann & Co.

Could you maybe give us a sense of what type of pricing you've locked in for the incremental hedges on TRB in 2011 - 2012?

Bruce A. Williamson

We hadn't intended on going out with that. I guess I would say it's in the same area as around what we've put in here for the guidance, which works out to $1.49 an MMBTU.

Lynn A. Lednicky

Look, we don't have those numbers right here, but what we've said before is that the pattern has been about $0.10 an MMBTU delivered year-on-year, and unless we see some type of major changes in the commodity markets [inaudible] markets going forward, we would expect that that's about the trend that we see going forward.

I mean, I think if you use something like that for modeling purposes, you should be fairly close.

Brian Russo - Ladenburg Thalmann & Co.

And it looks like you're forecasting cash on hand of $684 million in '09 and that compares to north of $800 million as of November of '08. I'm just wondering what's contributing to the decrease in cash.

Bruce A. Williamson

Okay, the $684, I think, was probably the cash as of December 1. You know, we have normal intramonth swings. Since then it was up a couple of days ago to around $725. Since then, now I guess from the third quarter to today, Holli?

Holli C. Nichols

Yes, essentially what we have, your debt coverage payments, all of our interest payments as well as the Central Hudson lease payment, fall in the second and the fourth quarter, so those are the primary drivers of the change in cash.

Brian Russo - Ladenburg Thalmann & Co.

Okay, so is $684 more of a good kind of cash run rate in '09 if you're free cash flow neutral?

Holli C. Nichols

I think, as we disclosed this morning, $725 is the current cash balance. That's probably a more 

Brian Russo - Ladenburg Thalmann & Co.

And then just on the CIN Hub and Illinois basis differential, I mean, should we just look at your commodity price assumptions and the on-peak power prices there and look at the difference as kind of an assumed normalized differential for 2009 midpoint?

Lynn A. Lednicky

Yes, that's roughly right. If you look at Page 35 in the presentation, you can actually see the basis assumptions that we've made. But what we tried to do was look at the actual basis differentials that we saw for 2008. We made an adjustment for June, which was an unusual month because of weather and transmission and some other things, but otherwise tried to use the experience that we saw in 2008.

So, for example, if you were to try to compare the basis assumptions we had in 2008 versus 2007, the basis assumptions - I'm sorry, for 2009 versus 2008 - the basis assumption we had for 2009 is larger.

Brian Russo - Ladenburg Thalmann & Co.

And then lastly, do you have opportunities for additional capacity payments out of MISO and is that included in your guidance?

Lynn A. Lednicky

We do. Not all of our capacity is sold at this point, so we make an assumption about the total volumes we'll sell and the total price and that goes into our total estimate for the Midwest.

Where we have sold capacity - if you go back, for example, to Page 10 - the sold capacity would be in the dark blue bar of contracted and the unsold capacity would be in the light blue bar of uncontracted.

Operator

Your next question comes from Andrew Smith - J.P. Morgan.

Andrew Smith - J.P. Morgan

A couple of questions just to follow on some of the guidance. Could you guys tell us, you mentioned 62% margin locked in for '09. What would have been the comparable level this time last year?

Bruce A. Williamson

It was [break in audio] 50% and 65%.

Andrew Smith - J.P. Morgan

So you're not that different going into '09? You're a little more heavily hedged going into '09 than you were going into '08 on an apples-to-apples basis, it sounds like?

Bruce A. Williamson

Pretty similar.

Andrew Smith - J.P. Morgan

If I go look at the sensitivities page, where you guys look at the gas sensitivity, the sensitivities were asymmetrical last year and they look like they're symmetrical this year. Is that a change in gas on the margin, is that a change just in the nature of the contract book you have? What's going on there?

Holli C. Nichols

Andy, it is more the latter, the nature of the contract book. And as you said, the impact on the coal fleet and the natural gas fleet, first of all, those are the same as well, which is more of an anomaly because when you look at it on Page 27 on an uncontracted basis, you'll see that that relationship goes away. So it happens to be the particular contracts that we have in place.

Andrew Smith - J.P. Morgan

And that also, I'm assuming, then, would account for the increased sensitivity, the natural gas, as well? Because last year you said a $2 move was $100 million.

Holli C. Nichols

Right.

Andrew Smith - J.P. Morgan

Okay, so that's all just the contracts book. Okay, perfect. And then one other question I had just in trying to reconcile because the $8 gas embedded in the guidance sort of jumped out at me versus obviously where the strip is today, but I was looking at where you guys are using peak pricing, for example, in the Midwest and looking at, you know, you were using $8.25 gas last year and $8 this year and then trying say, okay, well that assumes some on-peak market clearing heat rate, and go through the math.

You're modeling a larger drop in on-peak power price than I would have thought I would have expected based on the other inputs into that analysis. Do you get what I'm kind of driving at? I guess my question is how do I reconcile those two moves? Is that a change of heat rate on the margin or what's going on there?

Lynn A. Lednicky

Well, Andy, I think the way to think about that, as Bruce mentioned earlier, when we put this price set together, we made a conscious decision that we didn't want to just use a forward curve at a point in time. We looked at the margin and we made our estimates of what we thought would be reasonable prices and consistent across the various commodities.

Now, that's been particularly difficult to do this year because all of the quote-unquote historical correlations really become [undiluted] when you get large swings in power prices. So if you were looking at the earlier part of this year and you saw this big ramp up in commodity prices, you know, all the cross commodity correlations were messed up relative to history. And then when you got the collapse of prices, you saw the same thing.

So we really just tried to look at it and say this seems reasonable based on what we're seeing in the market and what we expect. And then we tried to [bound] that by what we thought about as historical heat rates and commodity correlations, but we didn't try to land on a specific number and say well, we know that the correct answer is a 7.8 implied heat rate or so forth.

So that's what causes that disconnect if you try to compare this year, which was more of a [inaudible] consensus [inaudible] versus last year, which was literally a commodity curve at a point in time.

Andrew Smith - J.P. Morgan

And maybe we can follow up in the meetings. I'd like to dig in some more into that because what I'd still take away from your guidance on the price, though, is that you have to sort of assume a lower marketing clearing heat rate on peak given the gas price inputs you take. But we can follow up. We'll kind of dig into that, if we can.

Operator

Your next question comes from John Kiani - Deutsche Bank Securities.

John Kiani - Deutsche Bank Securities

I'm trying to better understand some of your comments earlier on in the call when you said that you were still very close to or pretty close to the midpoint of your guidance range, even though natural gas forwards for [Cal] '09 are at about 609 versus the $8 number that you all had shown. And I think, Lynn, perhaps you mentioned that it was heat rates, and I know you said that Danskammer coal had helped a little bit.

What I'm a little bit confused about is that the CIN Hub on peak power price that you all show on Slide 12 as one of your assumptions - and obviously that's for a big part of your portfolio - is $61.50 and I'm seeing CIN Hub Cal '09 on peak forwards as of last night's broker quotes at basically a mid of $50, so about $11.50 per meg whatever lower. And then, you know, trying to understand a little bit better as to where you make up the difference, then, to get back to the midpoint.

Bruce A. Williamson

Well, the short answer on some of this is it wouldn't be a good time to go ahead and lock that in at $50.

John Kiani - Deutsche Bank Securities

No, I understand that, Bruce. I guess my question was more earlier in the call it sounded like Lynn and you all had said that you felt like even though natural gas prices had dropped that, based on the current forwards, if you went and kind of re-marked everything today, you'd still be close to the midpoint of your guidance range. And I was trying to understand what helped kind of get you there and offset the fact that gas prices had dropped.

I know heat rates have recovered some, so power prices haven't fallen nearly as much as gas. But when I look at the CIN Hub Cal '09 forwards, it's $11 and change lower than the assumption that you all show. So I was just trying to get a little bit of a better understanding on what gets you all back closer to the midpoint of the range.

Lynn A. Lednicky

Look, to start as simple as we could, what we see if we tried to look at things today, for example, is that the Midwest would be somewhat below what our Midwest number was for the plan and the Northeast would be somewhat above, and the West is roughly in the same place. And so it just happens with all of the moving pieces that, you know, it's not just outright gas price, but it is spark spreads and heat rates in all of the regions and coal prices that, when you add all of that up, that we don't get back to the midpoint of the range, but we're not at the very bottom of the range either.

And, you know, without - to take it to the next level of detail, then you really have to dissect all the pieces and figure out all the plusses and minuses and that's not something we can do today, but we do provide a fair amount of detail in the package as far as the positions that we have in place so that you can better figure out where we do have exposure to market moves.

John Kiani - Deutsche Bank Securities

Sure, yes. I saw that that was helpful. So if I'm understanding you correctly, Lynn, it sounds like you're saying the offset is really in the Northeast, and I think you mentioned spark spreads and coal. I guess Danskammer to me is a little bit smaller; it only generates about 2 terawatt hours of power based on my estimates. And I guess the EBITDA estimate that you all give for that asset is zero to $5 million based on the slide that you just referenced in your deck.

So can I assume that perhaps, if that's smaller, you get a little bit of a benefit there, and that the majority of the offset is more in spark spreads in the Northeast?

Lynn A. Lednicky

I'd really have to go back and try to, you know, dissect things a little more closely. I mean, look, at this point we're not even into 2009 yet. We're at the down part of the commodity cycle. So [break in audio] thinking about what the moving parts are, but I'm not sure that we're ready to try to break it down into all the components to add up and do all the offsets.

Operator

Your next question comes from [Neal Metra] - Simmons & Company.

Neal Metra - Simmons & Company

Can you give us any indication as to your hedging strategy for the remainder of 2009? I know the current commodity environment doesn't provide a great incentive to hedge, with gas under $7. Are there any drivers you can guide us to, for example, if gas hits a certain price, you'll layer hedges higher, you know, on at a higher rate? If those drivers aren't hit, you'd be comfortable transacting more in the short term or day ahead markets. Would you be willing to take more short-term weather-related risk than previous years if gas prices stay where they're at right now?

Bruce A. Williamson

Well, if we don't see much of an increase from here. I mean, I think like Holli's covered in her part, I mean, you know, given where prices are at today, I don't think we see this as a particularly attractive time to go ahead and lock anything more up. But, you know, things can turn around very quickly with weather in the short end, and we would want to go ahead and have the commercial team take advantage of that if they see some uptick. Lynn?

Lynn A. Lednicky

And the only other thing I would say is that we've down focused, as I said earlier, on more seasonal time buckets as opposed to a calendar year time bucket, so we particularly watch the first quarter and what's happening there and we think about what opportunity there is or upside versus what might happen if we have mild weather and what does that mean in terms of prices and cash flows and so forth.

So we just begin to break the year down into smaller pieces and, you know, as we get closer and closer to a time period, we think more and more about okay, are we comfortable in terms of the downside exposure that might be there.

Neal Metra - Simmons & Company

And can you talk about how the decrease in residual fuel oil prices relative to natural gas prices are going to affect your run times at Roseton? Are the spot prices relevant or does it have more to do with the cost of fuel oil that's already currently in your storage tanks?

Bruce A. Williamson

It's a mixture of both what the cost of the fuel oil that's in the tank is as well as, you know, maintaining inventory because you're going to replace the fuel in the tank, so there's, in effect, the team takes both of those into effect.

But, I mean, you know, that's, in effect, another one of the offsetting influences with gas prices being down, oil prices are down. You know, Lynn, I think Roseton was running yesterday, right?

Lynn A. Lednicky

Right.

Bruce A. Williamson

So, you know, those are things that come back the other direction in a low price environment, and then that also creates the opportunity to go ahead and put some - I'll use quotes around the term cheap - oil in the tank, to go ahead and put oil in. We've got about a million barrels of storage capability there. Put that oil in the tank and then it can then be monetized in a higher priced world when we have some adverse weather, basically, hitting the New York market. That's when Roseton tends to do well. Lynn?

Lynn A. Lednicky

Definitely, that's right. The only other thing I would say is that we can't procure oil on a daily basis. I can't decide that I need it tomorrow and just go buy it, so we can't rely entirely on the spot market for that. But we don't take big speculative positions to, say, for example, well, I'm going to fill up the tank today and then hope for cold weather next year. We have to be very disciplined about how we do that.

Neal Metra - Simmons & Company

And one last question. Are you factoring any basis issues for 2009 that carried in from 2008 at your coal plants in the Midwest or your combined cycle facilities in the Northeast?

Bruce A. Williamson

Yes, basically what we did is we went ahead - and Lynn covered on an earlier question  we basically took a look at 2008 and I would say largely have just adjusted the basis differentials to essentially the levels that were experienced in 2008, with the exception of probably the month of June. I mean, is that a fair way of putting it, Lynn?

Lynn A. Lednicky

Yes.

Bruce A. Williamson

So in that regard, if we saw a return to what we saw the year before, that would be upside. If we see what we experienced in 2008, then that would be coming in, you know, basically at plan.

Neal Metra - Simmons & Company

Do you still have hedges that your Midwest coal plants put into place at PJM [West] or has that been entirely transferred to Synergy?

Bruce A. Williamson

It's all at Synergy.

And we'll have one last question.

Operator

Your last question comes from Brian Chin - Citigroup.

Brian Chin - Citigroup

On the basis differential that Synergy had - not the basis that PJM Synergy had, but just from your generation plants that Synergy had - back when CIN Hub peak prices were at $70, an onpeak difference of 550 wasn't really that big of a deal. But as the on-peak price now is at closer to $50, it's starting to become more and more of an issue. Is there any sort of sensitivity around whether that is a percent of the on-peak price or does that basis differential remain 550 kind of the whole way through?

Lynn A. Lednicky

Well, we have to estimate what the basis differential is going to be, and it's driven by what's going on within the transmission system. And so that's partially a function of weather and it's partially a function of where the load is and what's going on in terms of maintenance on those transmission lines.

So I'm not sure that I would say it's necessarily a percentage, but it's not necessarily a fixed number, either. I mean, I know that's not terribly helpful to you. Probably the better way to think about it is we've given you the assumptions that we have for the basis differential for 2009, and you could compare that to what actually happened in 2008 and 2007 and might get a pretty good sense of what kind of range to expect. And that's probably a better way to think about it, rather than trying to say it's a fixed number, because it's not, or saying that it's a percentage, because it's probably not that, either.

Bruce A. Williamson

Thank you all for your time this morning. We look forward to seeing some of you at our spring conferences and many of you over the next day or so here in New York. More detail will be available early next year on the spring Investor Relations conferences.

I'd like to wish you all a happy holiday season and look forward to talking to you in 2009.

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