Norelle Lundy – Vice President Investor & Public Relations
Bruce Williamson – Chairman & CEO
Holli Nichols – Chief Financial Officer
Dynegy Inc. (DYN) 2008 Earnings & Cash Flow Estimates Call December 12, 2007 8:00 AM ET
Hello and welcome the Dynegy Incorporated 2008 guidance estimates and future earnings conference call. [Operator Instructions] I’d now like to turn the conference over to Ms. Norelle Lundy, Vice President of Investor and Public Relations. Ma’am, you may begin.
Good morning everyone and welcome to Dynegy’s investor conference call and webcast covering the company’s 2008 financial estimates and future outlook. It 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 and intentions of release about future events particularly with respect to the financial estimates and future outlook provided today. These and other statements not relating strictly to historical or current facts interpreted as forward looking statements. Actual results may vary materially from those expressed or implied in any forward looking statements.
For descriptions of factors that may cause such a variance I would direct you to the forward looking statements legend contained in today’s news release and our SEC filings which are available free of charge through our website atwww.Dynegy.com. With that I will now turn it over to our Chairman and CEO Bruce Williamson.
Thank you for joining our call regarding our 2008 estimates and view of the future. We’re in New York this week for meetings with our investors, analysts and rating agencies, joining me on the call is Holli Nichols our Chief Financial Officer, along with several other members of our management team for questions and answers.
Let’s now turn to the agenda for our call which is highlighted on slide three for those of you following along online via the webcast. This morning we will cover the company’s anticipated financial results for 2008 and what we believe is a very compelling value proposition for our investors both now and into the future. I will begin by providing a strategic overview that discusses our value proposition in more detail, this includes the solid foundation that we’ve built, the optionally in the business model and our focus on operating, building and transacting to capture current value and create future value for our investors.
Holli will then provide 2008 estimates with an in depth look at value drivers and major assumptions by region. She will cover the sensitivities for our earnings in natural gas and heat rates, then an outlook to our future earnings potential, assuming supply and demand come more into balance in our operating regions.
Finally, I will conclude with a discussion of how we plan to create and capitalize on our options for the benefit of our investors. Following our prepared remarks we’ll be glad to take your questions.
Please turn to slide four. Let me begin by providing a snapshot of Dynegy and walk you through this somewhat busy slide in a counterclockwise manner, starting at the upper left. We’re an S&P 500 company with an equity market cap of about $6.7 billion. Our single line of business is power generation with nearly 20,000 MW of well run generating capacity. We have scale and scope in our key regions of the Midwest, West and Northeast US, as I will discuss later we expect the value of our operating assets to continue to rise as barriers to entry limit the supply and US energy demand continues to grow.
Further, we have aligned our commercial strategy with our financial strategy, specifically our capital structure and debt maturity profile to significantly mitigate financial risk and enable us to pursue a commercial strategy and seek to capture more of the up side benefits through the industry cycle.
We have an operate-build-transact strategy that is capable of generating meaningful cash flow today and sustaining and growing this discretionary cash position into the future. Going forward we expect to generate between approximately $200 and $600 million in cash annually before discretionary uses. This can ad up to more than 40% of our current equity market capitalization over the next five years. Expect this cash to then be available for whatever is the highest and best use for our stockholders. This could include growth opportunities, either organic or acquisitions, or it may become part of an option to return capital to our stockholders. The driver for this will be the rate of return we can achieve.
At the same time, we would anticipate uplift in our EBITDA. While I’m sure, as with any energy and commodity cyclical company it will not be linear, we do expect to average approximately 15% growth over roughly the next five years. Based on the cash generating capabilities of our incumbent assets, we believe there is significant unrealized value that is not reflected in our stock price as earnings have not necessarily caught up with fundamentally rising values.
Now looking at the blue bars on the bottom left of the slide you can see that based on a conservative valuation of 60% of replacement costs for our existing fleet and after considering debt the inherent value of our stock on a per share basis could range between $8.10 and $12.14. We are currently trading at or below the bottom of this conservative range leading what we believe is significant upside for our investors. When you consider the difficulty in developing new power plants an 80% replacement value might even ultimately be a more reasonable valuation, this would value our stock in a range of between $12.62 and $18.10 per share.
Please turn to slide five. This is another way to look at the same sort of valuation. This slide shows a range of gas and coal asset valuations as demonstrated by the blue and orange numbers respectively. These valuations relate to operating assets only, so we are not considering the value of any development assets in this table, not even Plum Point or Sandy Creek which are under construction and have substantial commercial contracts already in place. The grey screened portion of the table then represents an associated stock price valuation that would result. You start by understanding that the current replacement costs for coal asset is probably $2,500 plus per KW and a blend of simple and combined cycle gas assets at $600 plus per KW then go to where our stock has been trading lately you get a value implied in our current stock price is closer to $17.50 per KW for the coal assets and maybe only $300 per KW for the gas assets. This demonstrates that even with conservative assumptions regarding our assets we appear to be significantly under value today.
While new assets will have some marginal costs advantages and other positive attributes it will also take many years to site license, permit and actually build. Our plants our up and running and generating cash today. Therefore you could argue that higher and higher valuation should be placed on incumbent assets as barriers to entry continue to rise.
In parts of the US, including some regions where we have a presence, bringing new capacity online is already extremely difficult and will only become more so. This is compounded by rising construction costs associated with labor and material making the replacement costs I just referenced a generally upward moving target.
We basically see on the upside in our asset valuations as the US energy economy gets tighter and tighter and the United States competes for energy on a global scale. We believe as prices rise the value of the incumbent assets will increase and the stock price should follow.
Please turn to slide six. Over the years we have created a solid business and financial foundation that we believe is the right way to position our commodity cyclical business. Our foundation is grounded in strong business fundamentals and a solid balance sheet, ample liquidity, termed out unsecured bonds and the generation of free cash flow from our core operating business. We have what we believe is the most flexible capital structure in the energy merchant sector and we are well positioned in key power markets in the US given our strong performing assets.
In addition we have a management team that is experienced in managing this balance sheet and the energy business and knows how to execute in terms of capturing value for our investors. These metrics lead to our 2008 EBITDA projection of approximately $1.1 to $1.2 billion and our estimated core free cash flow range of $200 to $300 million. While these numbers demonstrate significant growth over the prior year they still do not represent the kind of results that are diversably capable of achieving during a full market recovery scenario that we anticipate occurring in the next few years.
Holli is going to take you through the aspects of our 2008 estimates in more detail but the key take away here is that we’ve built a strong foundation and capital structure to allow us to execute our commercial strategy and capture the coming upside for our stockholders.
This takes me to slide seven. We recognize that power generation is a commodity cyclical business and as such maintaining a solid foundation for creating and attracting value for investors through various options is a key focus. As demonstrated by the top section of this slide our first priority is to never lose site of our core business which is to generate and sell electricity in a safe, reliable and economic manner. Moving to the right we must recognize that the business cycle that we are operating in and adjust for variables such as seasonality, regional market and regulatory issues and global affects on commodity prices.
We must maintain discipline throughout the business cycle and keep our options open as cycles change. This includes linking our commercial strategy and capital structure to capture benefits and mitigate risk through the various cycles. To do that we will manage a diversified operating portfolio and maintain flexibility in the capital structure. One way we do this is by having minimal debt maturities through the anticipated market recovery period as demonstrated by the box on the right center of the slide. This, as I’ve said, allows us to be more opportunistic in taking on some commodity risks which creates additional opportunities for our investors. It also means that free cash flow above maintenance and environmental capital is not available to serve our stockholders in whatever is the highest and best use rather than going for debt service.
I would now like to direct your attention to the bottom portion of the slide which considers our 2008 generation gross margin by contract term length. Since we operate in three regions with different fuel, dispatch and merit order characteristics our forward sales decisions in each region are somewhat different. This is based on market fundamentals relative to our regional fleet profile. For example, our longer term contracts range to five years and longer. These contracts are intended to run to term and include tolls or long term power sales agreements related to the development projects. They provide predictable cash flow streams while passing though to customer’s environmental fuel and other key risk elements.
Medium term contracts ranging from two to five years are structured deals and financial products. They are intended to capture value from the midterm price trends.
Our short term sales, spot sales and contract sales with a duration of less than two years are more fluid or dynamic and we may move in and out of these positions regularly. This gives us the opportunity to optimize earnings from our fleet when we see advantageous market conditions. We believe in effective commercial strategy cannot be managed in isolation or on an asset based process; therefore, we look to the overall portfolio for diversification into our capital structure for ways to optimize our tactics.
Beyond commodity price decisions we also take into consideration collateral and mark to market impact. Therefore, we’ll continuously respond to the changing market conditions in order to be opportunistic in the commercial approach with a goal of being to strike a balance between core free cash flow predictability and upside participation for our stockholders.
Given commodity price trends we generally plan on entering 2008 somewhere between 50% and 65% of our expected gross margin already commercialized through contractual arrangements. You may recall this is somewhat up from a year ago when we planned on entering 2007 at about 50%. We have seen opportunities above the price points in 2006 so we have taken advantage of some of these as we’ve gone through 2007. We believe we still maintain good upside participation for our investors in 2008 and beyond.
Based on specific market conditions at any point in time we may be above or below this range since we actively manage our near term market positions of less than two years. Let me just say again, a key component of our ability to utilize this strategy is our capital structure which gives us the solid foundation to execute from and our well timed unsecured bond financing earlier this year that restored our structure to a corporate system from the project based that came with the gas fired assets that we bought from LS Power.
Please turn to slide eight. This slide takes a closer look at our three part value creation proposition. First we are focusing on our core business of operating and commercializing our power plants in an environment where our existing assets are increasing in value in earnings power.
Second, we are focused on building and expanding power plans by leveraging off of a pipeline of development opportunities. This includes investing portfolio greenfield and brownfield development opportunities to enable us to create value at various stages over time.
Third, we will look for opportunities to transact and grow our diversified portfolio. Here we will continue to evaluate growth options through industry opportunities. Underscoring all of this is fiscal discipline and respect for all of our investors whether they are fixed income or equity. While we are always looking for the right opportunities to grow our portfolio if those opportunities do not materialize we will continue to be relentless in our operating and commercializing our existing portfolio to maximize value for our investors.
We also will look at monetizing assets if that’s the best way to capture net present value. Examples of this occurred in 2007 when we sold a 22 year old gas fired plant well above replacement costs and when we sold a piece at Plum Point at a very low discount rate. All told, we sold about $600 million of assets this past year at very attractive prices because we saw more value in selling the assets than retaining them in our portfolio.
Please turn to slide nine. Here I want to cover in more depth the operational and commercial component of our value creation strategy. We have a track record of operating our assets safely, efficiently and reliably. With strong performance metrics related to in market availability I was particularly proud of the third quarter when we reached 94% in market availability for the coal fleet. The portfolio is generating meaningful cash flow as demonstrated by the year to date financial results and is well positioned to further benefit from market improvements resulting from defining reserve margins. We believe this will increase as I’ve said before the value and earning spower of these assets.
In the future we see upside from our core fleet as declining reserve margins prompt improvements in capacity markets. We believe evolution of capacity markets is an important step in meeting regional power needs and creating additional value capture opportunities.
Please turn to slide 10. Let’s take a quick look as a reminder of how diversified and balanced the portfolio is. Today we have nearly 20,000 MW of our key geographic regions Midwest, West and Northeast. This includes our Plum Point and Sandy Creek projects which are under construction in Arkansas and Texas. Overall our portfolio is well diversified in terms of geography fuel and dispatch with enhanced diversity providing greater financial stability. This diversified portfolio positions us to capitalize on weather driven demand as well as regional power market opportunities such as transmission constraints or plant outages.
Please turn to slide 11. Our market recovery is a key factor in determining the results and value of existing portfolio. As supply tightens, existing assets should become more valuable. Here we see how the different components of our fleet are positioned in a scenario where supply and demand are more in balance. The recovery time table for our Midwest assets which are slit between MISO and PJM extends to approximately 2010, while our California and Northeast assets are currently operating in a recovery environment marketed by relatively tight supply and demand.
We believe that slim reserve margins will prompt stronger energy and capacity pricing and will encourage the new development of power plants. While this is something the country ultimately needs, the reality is that building new base load plants is becoming more and more challenging. If permits are not already in place it will be difficult to bring into operation any new base load generation in the next five years.
Holli will show some of this again shortly along with how the tightening is impacting market clear and heat rates. The key take away here is that reinforces my earlier point that incumbent assets will continue to rise in value and approaching replacement costs.
Please turn to slide 12. Our second means of creating value for investors relates to building and expanding our portfolio, leveraging off of ongoing development opportunities. We are actively reinvesting in the business with a focus on high return greenfield and brownfield development projects which currently exist through a mature development platform of natural gas, coal and renewable options. As we just discussed building brings challenges however, one advantage we have over other IPPs is the advanced pipeline projects in various stages of the development process.
The execution of our development strategy can create meaningful new sources of cash flow as we anticipate value through the future operations and commercialization of these assets such as Plum Point and Sandy Creek. We can also modify portions as we did with both of these developments in 2007.
Please turn to slide 13. This slide demonstrates the multiple options we have for capturing value at various stages in the development cycle. We have already taken advantage of this in our two most advanced development projects which entered the development process in 2001 and 2003 respectively. In regard to these projects significant progress has been made in terms of harvesting value. The growth projects there are long term contracts to support financing. We have started construction with anticipated commercial start dates of 2010 for Plum Point and 2012 for Sandy Creek.
At Plum Point there have been locked in cash flows to reduce risk with additional PPAs which we will be working to do at Sandy Creek. On points project debt has been refinance on more attractive terms and we would have plans to try to do the same thing with Sandy Creek in the future. We monetized interest to harvest value from both those projects.
At Plum Point we recently sold a non-controlling interest in the facility for $82 million in cash plus assumption of project level debt. This transaction could be viewed as an interesting benchmark for the value of incumbent assets. Essentially a buyer was willing to pay approximately $2,800 per KW for an asset that is not expected to enter commercial operation until 2010. This transaction is expected to close this quarter. Drawing the comparison with incumbent assets that are producing cash today we believe that our operating full fired assets could be worth significantly more than the implied market values through our stock price.
Related to the Sandy Creek project we recently sold a 25% ownership interest plus the assumption of pro-rata construction costs to [Inaudible] Electric which is working to secure supply of reliable and economic energy for its central Texas customers. We were looking at entering into additional contracts at Sandy creek output prior to going to the capital markets for permanent project financing as was done with Plum Point. As we have with our other project PPAs we would seek to execute long term contracts to pass through fuel, transportation and environmental risks to counter parties.
Other development options, as I’ve said include several thousand MW brownfield and Greenfield opportunities. With these opportunities the money we are spending today is modest and the development portfolio is expected to be self funding through our plan of tactical monetization. Which should not be a big drain on our discretionary cash position going forward. Brownfield options have the advantage of being located at or near existing operating facilities and with the potential of some quicker development and commercialization and potentially some lower costs.
Let’s turn to slide 14. We’ve used this slide for a while now so let me go through it quickly with just a couple points. First, the chart at the bottom provides a set of estimates relating to the range of lead times and dollars per KW that it might be required to build power generation facilities of various types. Keep in mind that any type of project could vary significantly from these estimates in terms of the time and cost based on numerous variables such as material costs, resources due to demand and in addition longer dated projects may be subject to cost increases.
All of these projects are subject to rising construction costs as well, along with the combined barriers to entry. This slide leads to our competitive advantage in the development area. Because of our more advanced development options have been in the works for years through LS we believe we have much greater potential to actually build new capacity and create value for investors. The second key point is that if barriers to entry continue to block even our development JVs projects then we will see even more upside to the increasing value of our existing operating assets.
Please turn to slide 15. Finally, our value creation strategy includes transacting to grow the scale and scope of our portfolio and create new options while harvesting the imbedded value of the existing portfolio on an opportunistic basis. This means that we will look at transacting on an asset by asset basis or larger scale through combinations or acquisitions which actually generate greater value related to the elimination of duplicate cost structures. We continue to believe that large scale combinations and acquisitions will occur in this industry and we stand ready when an opportunity arises that is accretive to value.
We have also established a track record of executing transactions and integrating operations and systems to apply these capabilities as we continue to evaluate industry opportunities. In the future we are focused on continuing being opportunistic through continuous evaluation of growth through industry opportunities.
While Dynegy is prepared should the right opportunity come along we will not grow only for the sake of growth, rather we will take a very disciplined approach in analyzing any investment opportunity. If a transaction increases stockholder value we will pursue it, otherwise will we work with our current fleet and development options to maximize financial results and cash flow returns for our investors. For Dynegy, growth through transactions is just one way of creating value but not the only way.
Please turn to slide 16. A year ago Dynegy’s to do list had three big tasks driven my experience in the oil and gas industry about how to deal with large scale acquisition, like we executed in late 2006 to maximize value for our investors. The main tasks were first; complete the merger with LS Power to fully integrate the assets. Second, streamline the right hand side of the balance sheet to simplify the debt structure, reduce the increased covenant flexibility, and maximize capital available for our stockholders. Third, optimize the left hand side of the balance sheet to release value from some assets that don’t support our strategy and scale in key regions.
In this respect we have captured value over what we believe could be achieved if the assets had been held in our portfolio. Over the past year we have executed each of these initiatives capturing value every step of the way. We closed and fully integrated the LS assets focusing on harvesting the consolidation synergies while combining the portfolios very quickly and thereby demonstrating the benefits of consolidation.
In addition, we delivered strong financial results as demonstrated by our positive earnings for three consecutive quarters this year which was achieved through our continued focus on our strong operational and commercial capabilities and strategies.
That takes us to task number two. We streamlined our capital structure by refinancing the debt associated with LS Power through the use of Dynegy holdings unsecured bonds which provide significant financial flexibility. We believe that Dynegy’s capital structure today is now the simplest and most flexible in the industry and a structure that conserve our investors over the long term.
Third, with regard to the left hand side of the balance sheet and our efforts to optimize the assets, after LS Power combination we quickly reassessed the portfolio with focus on the three key regions. As a result we sold the CoGen Lyondell facility for approximately $880 KW and announced the sale of Calcasieu facility which is expected to close in early 2008. More recently you saw us continue these fiscal disciplines optimize the portfolio. We agreed to sell portions of our interest in Plum Point and Sandy Creek that I mentioned earlier which also demonstrates our ability to harvest value from the development business.
The bottom line is Dynegy has extremely well over the past year and continues to be disciplined and opportunistic while building a solid foundation to create and capitalize options for our investors.
With that I will turn it over to Holli.
As noted on slide 18, I’ll start with a regional overview that includes market drivers and how we expect our regional results to be driven by commodity prices, power prices, spark spreads and capacity markets. In terms of our regional highlights I’ll discuss our bilateral, tolling, RMR and financial agreements as well as our fuel and transportation contracts. I’ll cover EBITDA forecasts including energy and capacity revenues, cost of sales and operating expenses. In addition, I’ll discuss capital expenditures for the next five years.
Regional overviews covered in the next several slides include a significant amount of detail to assist you in your modeling effort. Specifically we provided major assumptions such as volumes, heat rate, prices and capacity factors for each region. Also, I’d like to point out that our businesses commodity cyclical with today’s estimates based on October 30, 2007, commodity prices. Additionally, this presentation contains Non-GAAP measures that are reconciled in the appendix of the presentation.
Let’s begin by turning to slide 19 for a look at our Midwest segment. Our 2008 plan for the Midwest includes an estimated EBITDA midpoint of $855 million, which reflect energy sales of more than $1.3 billion. In addition, Midwest EBITDA reflects capacity sales of approximately $185 million or about 18% of projected gross margin. Midwest EBITDA estimates are based on 2008 forward prices averaging approximately $68 million for CIN Hub and $81 billion for PJM West. In addition, we anticipate 2008 sales volume of approximately 26.5 million MWh which is an increase over 2007.
Market drivers for this segments MISO component include the outright power price for un-contracted base load volume in the capacity prices in the spark spread for natural gas fired units. For PJM the primary market drivers are capacity sales and the spark spread for un-contracted natural gas fired combined cycle units.
In terms of regional highlights, Midwest commercial arrangements include bilateral and tolling agreements as well as financial forward sales. A note on capacity markets, we’re already seeing the benefits of stronger capacity pricing in PJM but we have approximately 4,000 MW is evidenced by the results of recent capacity auctions. PJMs next phase residual market auction for the 2010, 2011 settlement period is scheduled for February of 2008.
While we haven’t yet seen the same dynamics in MISO where our Illinois base load coal fleet is located, that is a factor to consider as recovery progresses. We believe that PJM capacity results are a good indication of a trend that should extend into MISO. Bottom line is that we anticipate stronger free cash flow and increasing returns and values related to our existing assets as capacity markets develop.
Included in our contractual arrangements are up to 1,400 MW of bundled services related to the Illinois auction including up to 1,200 MW that expire on May of 2008 and then to another 200 MW that expire in May of 2009. These are the round the clock price of $65 per MWh with a load factor of approximately 50%.
As you will recall, the bundled products sold in the auction process included energy and various other services. We expect the Illinois Power Authority to solicit bids for energy only and that’s what we’ve included in our 2008 expectation. We’ve also included some level of additional services but not to the extent delivered in 2007. However, we won’t need to have as many MW in reserve as we did in 07’ to service the load following Illinois auction contract.
In terms of fuel turn your attention to our long term PRB coal and rail contracts. Approximately 100% of our coal requirement are contracted through 2010, with price re-openers about every two years. In addition to our coal contracts 100% of our rail transportation costs is contracted at a fixed price through 2013. The delivered price at our Baldwin facility a benchmark for our Midwest fleet is expected to be approximately $1.39 MMBtu. In our long term fixed rail contracts and relatively stable coal costs this $1.39 per MMBtu costs provide us a cost advantage especially as you compare that to market base rate which would likely be at or above $2.00 per MMBtu.
Please turn to slide 20 to cover our West segment. Our 2008 plan for the West includes an estimated EBITDA midpoint of $190 million which reflects energy sales of approximately $655 million; in addition, West EBITDA reflects capacity in RMR sales of approximately $190 million, that’s about 58% of projected gross margin.
Let’s look at market drivers in the West. In this segment spark spreads are a more important driver of financial results that outright power prices. This forecast is based on average spark spread of approximately $21.50 per MWh. While California doesn’t have a formal auction process we do anticipate greater demand for capacity in 2009 giving utilities reduced ability to meet resource adequacy across requirements. For our West segment we anticipate 2008 sales volume of approximately 12 million MWh which is also up from 2007. Market drivers for the West segment include the spark spread for un-contracted natural gas-fired, combined cycle and peaking units as well as ancillary services.
In terms of regional highlights less commercial arrangements include RMR contracts, tolling agreements and financial forward sales contracts. Overall keep in mind that the West has longer term contracts given the regions intermediate in peak portfolio. Additionally fuel price risk is generally past through on hedges and tolling agreements or purchased on as needed basis at index related prices.
Please turn to slide 21. Our 2008 plans for the Northeast include an estimated EBITDA midpoint of $185 million which reflects energy sales of approximately $800 million. In addition, Northeast EBITDA reflects capacity sales of approximately $225 million or over 60% of projected gross margin. Similar to the West segment spark spreads are a key driver for our Northeast segment. This forecast is based on an average natural gas spark spread of approximately $23 million. The calculated average oil spark spread is negative for our Roseton facility. However, as we have seen in the past, the fuel oil spark spread will likely be positive at times allowing Roseton to provide a contribution to earnings. Depending on weather and local conditions this contribution can be significant but for 2008 plan purposes we have included a decreased contribution from Roseton as compared to what we experienced in 2007.
Our Northeast segment we anticipate 2008 sales volume of approximately 10 million MWh which is an increase over 2007. On the New York ISO market drivers include the spark spread for un-contracted combined cycle gas, and fuel oil units and the outright power price for un-contracted baseload coal volumes. In the New England ISO the key driver is the spark spread for un-contracted combined cycle gas units.
Additionally we anticipate a formal capacity market auction to occur in New England in early 2008 for 2011 and 2010 capacity. Prices are expected to be somewhat higher than recent prices and PJM because of the cost of construction in the New England market.
In terms of regional highlights, Northeast commercial arrangement include bilateral capacity agreements and financial forward sales. Additionally, 100% of our Danskammer Coal supply is contracted at a fixed price through 2008. Taking a moment to step back EBITDA is not necessarily a good proxy for cash flow for the Northeast segment as a result of the amortization of the ConEd capacity contract and the Central Hudson Lease obligation. EBITDA differs from cash flow due to the independent facility capacity contracts with ConEd, where we receive payments of approximately $100 million per year. Of this amount only $50 million is recognized in EBITDA due to the purchase accounting treatment that resulted from the acquisition of Independent in 2006.
Also, for modeling purposes if you consider the Central Hudson Leases debt you’ll want to add back the lease expense of $50 million. Before we move on I want to provide you with more insight on the Northeast segment and specifically how to treat the Central Hudson Lease obligation in your modeling assumption as we received several questions on this topic.
Please turn to slide 22. GAAP requires that we treat our Central Hudson obligation as an operating lease. As such we will continue to recognize the $50 million lease expense on a straight line basis in EBITDA over the course of the contracted term of the lease. Our operating cash flow is burdened by the entire annual lease payment. In 2008 we have forecasted $144 million cash outflow in operating cash flows. In addition, the Central Hudson obligation is not include in GAAP on our balance sheet.
Many do consider this lease as a debt like instrument which would require adjustments to our GAAP financial statements for modeling purposes. For those who do, let me walk you through the items you should consider relative to the Central Hudson Lease’s impact on our 2008 financial estimate.
On the income statement first you would add back the lease accrual expense of $50 million to EBITDA; next you would add $74 million of imputed interest to interest expense. To get to net income you would need to include $23 million of deprecation and amortization and tax effect the higher EBITDA and higher interest expense as well as depreciation and amortization.
On the cash flow statement add back imputed principle of $70 million to operating cash flows as this would be included in financing cash flows. Imputed interest of $74 million remain in operating cash flow. Finally, you would need to include the present value of future lease payments of $770 million in debt. Regardless of how you think about the Central Hudson obligation we hope that this will help you in your modeling efforts.
Please turn to the next slide. Let’s now discuss anticipated capital expenditures over the next several years. Our plan anticipates CapEx of $640 million in 2008 but I want to take a minute to walk you through. The components start with general maintenance of $80 million and major maintenance generally related to outages of $115 million.
In terms of major maintenance CapEx from 2008 to 2012 you will notice some volatility. Here I’d like to point out that maintenance CapEx associated with our base load coal fleet is relatively static while CapEx related to our combined cycle fleet ranges more from year to year. In terms of our combined cycle fleet we anticipate outages every 24,000 run hours. While this may vary depending on unit size, equipment, age and other operating factors. However, over a five to six year period and assuming a 50% capacity factor we anticipate total costs for our combined cycle fleet of approximately $250 million.
As it relates to the consent decree program we continue to make progress in terms of our environmental assessment in the Midwest and we expect $150 million in spending associated with this effort in 2008. In addition, we expect $30 million related to other environmental project apart from the consent decree. These include mercury reduction initiatives SOx/NOx control equipment and projects related to the protection of marine organisms.
Moving to development CapEx we anticipate $220 million related to the Plum Point project which is 100% debt financed. In this case cash outflows are all set by financing inflows. Finally I’d like to point out discretionary investment CapEx of $45 million. Here I’m referring to projects that increase available capacity or lower a facilities heat rate by replacing or updating technology which in turn improves market availability. An example might be an upgrade to a steam turban on an existing unit.
With any of our discretionary projects we target an internal rate of return of 15% or better, creating an opportunity for improved earnings, cash flow and fast paybacks as its incremental in CapEx.
Please turn to slide 24. Now I’d like to cover our consolidated 2008 cash flow and earnings estimates. As this slide demonstrates, based on October 30 pricing curves we estimate total GAAP operating cash flow of $585 to $685 million for 2008. This includes a contribution of $1.1 to $1.2 billion from our generating business segment and a use of $550 to $540 million from other which primarily includes GNA and interest payments offset by interest income.
In addition to the CapEx I covered earlier investing cash flows include $200 million in net proceeds from asset sales and $125 million change in restricted cash that primarily reflects the reduction of cash collateral related to the Sandy Creek project and the release of cash from Plum Point debts facility. This brings our estimated 2008 free cash flow which is GAAP operating cash flow plus GAAP investing cash flow to the range of $250 to $350 million.
Adding back adjustments related to Plum Point development CapEx of $220 million, Illinois rate release of $10 million plus changes in restricted cash of $125 million and proceeds from asset sales of $200 million; our free cash flow for our core business is expected to be $200 to $300 million.
I’d like to point out that we had the opportunity to exceed 2007 free cash flow from our core operating business even though the Central Hudson Lease payment increased by approximately $40 million and the consent decree spending increased by approximately $60 million. In addition we will incur a full year of CapEx on the combined cycle assets added and the LS Power combination.
Keep in mind that these ranges to not make an adjustment for Central Hudson. If we presented Central Hudson as a debt obligation our free cash flow from our core operating business would increase by $70 million. If we would add back the imputed principle payment included in operating cash flow.
Please turn to slide 25. Here we have our 2008 earnings estimate broken out by segment, again, based on October 30 quoted forward curves for commodity prices. The EBITDA estimate for the company’s generation business segment is a range of $1.2 to $1.3 billion, which includes a range of $830 to $880 million from the Midwest segment, $180 to $200 million from the West segment and $175 to $195 million for the Northeast segment.
In addition, we estimate net expenses in the range of $135 to $125 million from other in the CRM segment. Other includes GNA costs of approximately $175 million primarily offset by interest income. This brings you to total EBITDA of approximately $1.1 to $1.2 billion. The interest expense is approximately $440 million with a tax expense of $90 to $130 million which reflects and effective tax rate of 39%. We project net income in the range of $140 to $200 million and EPS of $.17 to $.24 which is based on 840 million shares outstanding.
Please turn to slide 26. To reconcile 07’ estimated results with 08’ projections let me walk you through a series of adjustments all of which are based on range mid points. Starting with our 2007 core business EBITDA of $1 billion as estimated on November 8th, we first adjust our out realized mark to market income of $40 million bringing us to $965 million. These include the adjustments for looking at a $45 million increase related to an extra quarter of contribution from the former LS Power asset now included in Dynegy’s portfolio, net of course finding operating expenses. Other adjustments include $15 million increase related to higher prices and volume; a $40 million increase related to capacity sales, a $35 million improvement to EBITDA as a result a decrease insurance expense and various other efficiencies at the plant level.
A $25 million increase due to higher income as a result of increased restricted cash posted in support of our synthetic letter of credit facility and Sandy Creek collateral in addition to overall higher cash balances generated from operations. A $15 million decrease related to fees associated with development JV which may be recovered in the future, as they were in 2007. Finally a $10 million decrease related to other miscellaneous. A key take away here is that in comparing 2008 EBITDA projections to 2007 estimated results from our core operating business, excluding any mark to market impact we are anticipating an approximate 15% increase year over year with a range of EBITDA of approximately $1.1 to $1.2 billion.
Please turn to slide 27. We customarily demonstrate the sensitivity of our generation business in our EBITDA estimate natural gas commodity pricing. These sensitivities are based on full year estimates and assume that the natural gas price change occurred for the entire year across the entire fleet. If we apply mark to market accounting treatment there will be differences between EBITDA and the timing of cash received. These sensitivities exclude potential changes in portfolio value especially with contract values beyond 2008. To be clear 2008 earnings we have not attempted to estimate the impact of changing prices and the mark to market impact for contracts it will settle in 2009 and beyond.
Looking at the two boxes in the center of the slide you can see that for 2008 as of October 30th a $2.00 increase in natural gas would result in a $100 million increase in generation EBITDA as it relates to the portion of the portfolio that is not contracted whereas a $2.00 decrease in natural gas would result in a $60 million decrease in generation EBITDA. On a long term basis if you assumed an un-contracted position you could expect a $2.00 increase in natural gas to result in a $320 million annual increase in generation EBITDA. Conversely a $2.00 decrease in natural gas would result in a $200 million annual decrease in generation EBITDA.
As you can see, the downside is not linear to the upside due to the fact that assets will simply not run at a loss if the spread becomes negative. A key take away here is that natural gas sensitivities primarily impact our base load coal-fired generation in the Roseton fuel facility.
Please turn to slide 28. Let’s now turn to sensitivities relating to market by heat rate which impact our entire operating fleet. These sensitivities are based on “on-peak” power changes and full year estimates. Sensitivities assume a constant natural gas price of $8.25 MMBtu and heat rate changes are for a full year. Further, increased run times would result in increased maintenance cost which we have not attempted to reflect here.
In the box on the left which considers our 2008 contracted portfolio as of October 30, 2007, you can see that a change in market implied heat rate of 1,000 Btu/KWh would result in $130 million increase in generation EBITDA as it relates to the un-contracted portion of the portfolio. In this environment we only see heat rates moving upward, however, to show the impact of falling heat rates in our contracted portfolio we demonstrate here that a decrease of 500 would correspond with a $50 million decrease in generation EBITDA.
Looking at the long term and assuming an un-hedged portfolio and increase of 1,000 Btu/KWh would increase annual generation EBITDA by $370 million, while a decrease of 500 would lower annual generation EBITDA by $145 million. Once again, I’ll point out that downside is not linear to upside as we wouldn’t run assets in an uneconomic environment.
Please turn to slide 29. As Bruce discussed earlier declining reserve margins translate to expanded market implied heat rate. I the graph on the left we see how the different components of our fleet our positioned in a recovery scenario. The recovery time table for our Midwest assets which are primarily located in MISO with some in PJM extend to approximately 2010 while our California and Northeast assets are currently operating in a recovery environment marked by relatively tight supply and demand.
The graph on the right shows the rising market implied heat rate from January 2005 to October 2007 time frame in the Northeast the West and most significantly in PJM and MISO where our Midwest lead is located. The purpose of this graph is to show on average how much the heat rate has moved historically. For example, in MISO you see an increase of 1,000 Btu/KWh from January 2006 to January 2007. While the expansion may not continue at this rapid pace over the long term we do expect heat rates to continue to trend upward as more inefficient units come online and a tighter supply and demand scenario especially as markets reach the 15% to 20% reserve margin levels.
Please turn to slide 30. This leads us to our longer term potential in a market recovery scenario. Here I’d like to draw a comparison between our estimated 2008 total portfolio gross margin as seen on the left with the gross margin potential for our business in a market recovery scenario. You can see a flat contribution from the gas driven portion of our portfolio as seen in blue which assumes gas prices remain flat and a modest increase from capacity sales as seen in yellow. We believe that the real driver will come from expanding heat rates shown here in the red portions of the bars. As reserve margins decline incremental growth should be captured by our base load intermediate and peaking units.
While likely to be volatile an average annual increase of approximately 15% in EBITDA over the next five years would bring us to $1.8 billion. If we revisit Bruce’s earlier comment, valuing today’s assets using 80% of replacement costs we come to an inherent range of $12.62 to $18.10 per share or a medium price of $15.36 per share. If we apply and assume the EBITDA multiple in the nine to ten times range this implies future EBITDA in the range of $1.7 to $2 billion. Therefore, in the future we would expect EBITDA to largely follow gross margin and cash flow increases. This further supports Bruce’s earlier point that our stock price is currently trading at the bottom of replacement cost ranges offering significant upside for our investors.
With that I’ll turn it over to Bruce.
Please turn to slide 32. Dynegy’s 2008 projections help demonstrate the competitively advantaged nature of our business which includes a solid balance sheet with net debt to cap now below 50% and 15% growth in core EBITDA. We also will have continuing solid free cash flow. While the 2008 range is not a significant increase over 2007 it includes previously mentioned increases in consent decree spending and maintenance CapEx associated with the combined cycle facilities and the increase of $40 million as related to Central Hudson so in reality it is an overall increase in line with EBITDA growth as Holli covered in more detail.
In addition our business attributes include ample liquidity and a flexible capital structure that enables us to pursue growth options or returns to shareholders. We have no significant debt maturities until 2011. We also have well positioned and well operated assets and a credible focused management team. Together these attributes create and help maintain a solid foundation for 2008 that extends to the future.
Please turn to slide 33. We’ve talked about building a solid foundation and our success over the past year but there remain a number of uncertainties that could impact the future of all energy companies. As a management team we constantly evaluate industry issues and conditions and ask ourselves fundamental questions to analyze an issue.
These are the who, what, when, where and how at the top of the slide. They are often followed by an immediate or intermediate and secondary impact of a given issue. On an ongoing basis we are weighing the impact of issues related to the general and regional continued tightening of supply and demand. We talked a lot about that today, sector consolidation and what it may mean and the opportunities it may create with a pricing that it may involve.
Weather and the impact that it has on everything from near term prices to scheduling our maintenance to having our assets in the market when they are needed by consumers. Regulatory impacts of such items as carbon legislation and what impact that will have on the cost of electricity to all American consumers. Regional market redesigns and how they will impact our fleet and of course global and national economics such as the US continues to compete for energy sources around the world.
In this respect natural gas and truid electricity are more and more driven by global competition for energy. We believe that maintaining awareness and continually evaluating issues and cultivating options are the right tools for managing these uncertainties.
One of our strongest attributes is in the diversity of the portfolio and the financial profile that gives us the ability and flexibility to respond to changes with the right option. We believe that through this chain of uncertainty we are investors links to opportunities can also then be identified.
Please turn to slide 34. In wrapping up our prepared remarks this morning we have demonstrated how the company is positioned for the future through our operate, build and transact strategy. It provides us with a solid foundation. The foundation is a platform for managing uncertainties in a cyclical business by creating and capitalizing on options.
This leads us back to our value proposition. Dynegy has the potential to produce strong results in 2008 and even stronger results in the future as power markets tighten. We expect annual cash flow before discretionary uses to be between $200 and $600 million annually. This could add up to as much as $2.5 billion of cash over the next five years and bear in mind that this $2.5 billion assumption is based on an assumption of natural gas remaining where it is now and that all excess cash is invested simply at Libor rather than invested in the business at a higher rate of return or return to shareholders.
Additionally, we are forecasting an annual average EBITDA growth of approximately 15% during this period as we enter market recovery. As demand increases our operation excellence and reliability track record will also be a key strategy for the company to capturing value.
Finally, we have a management team with a proven ability to operate, execute and respond to change. Bottom line is that we told you what we were going to do in 2007 and I believe we’ve delivered on those initiatives and delivered on our promises. During 2008 our commitment is to maximize the potential of this business platform and deliver even more value to our stockholders.
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