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Chesapeake Energy Corporation (NYSE:CHK)

Business Update Call

September 23, 2008 9:00 am ET

Executives

Jeff Mobley - Vice President of Investor Relations

Aubrey K. McClendon – Chairman, Chief Executive Officer

Marcus C. Rowland- Chief Financial Officer, Executive Vice President

Analyst

Shannon Nome - Deutsche Bank

Brian Singer - Goldman Sachs Group, Inc.

Scott Hanold - RBC Capital Markets

David Tameron - Wachovia Capital Markets, LLC

Wayne Andrews - Raymond James & Associates, Inc.

Robert Christensen - Buckingham Research Group

David Snow - Energy Equities Inc.

David Heikkinen - Tudor Pickering Holt & Co., LLC

[Ray Deacon - Richard Capital]

Matthew Warburton - UBS

[Bradley Keith - Bradley Keith Investment]

Operator

Welcome to the Chesapeake Energy Conference Call. (Operator Instructions) At this time, I would like to turn over the conference over to Jeff Mobley.

Jeff Mobley

I would like to begin by introducing the other members of our management team who are with me on the call today; Aubrey McClendon, our CEO; Marc Rowland, our CFO and Steve Dixon, our COO.

Our prepared comments should last about 10 minutes this morning and we also have more to share with you at our upcoming analyst and investor day on October 15 and 16, right here in Oklahoma City. We hope you are able to attend.

I will now turn over to Aubrey.

Aubrey McClendon

I am going to try and keep this for five minutes and I do not think Mark has any prepared comments today so this will allow us to go to the Q&A more quickly.

Essentially, what we are doing this morning is informing you about the following ten developments. Number one, we are announcing the BP Fayetteville transaction is closed as scheduled with a US$ 1.1 billion in cash and an $800 million growing carry. Please keep in mind that because of the tax efficiency of this carry, the transaction should really be looked at from the Chesapeake side as being worth $2.2 billion and from the BP side, it is costing them only about $1.6 billion. So, that is a big term win for both of us.

Number two, we are cutting drilling CapEx by $3.2 billion over the next ten quarters. About 40% of that reduction results from our BP Fayetteville carried work the interest and from our planned Marcellus sale drilling carry while 60% comes from this drilling activity in the light of lower natural gas prices.

Number three, we anticipate generating approximately $2 billion of excess cash during 2009 and 2010 and plan to direct that cash primarily to debt reduction.

Number four, we are providing an update on some hedging positions for what some fear could be a tough next two and a half years for natural gas prices. During this period, we anticipate producing excess over 2.5 Tcfe with 62% of that, or almost 1.6 Tcfe today instead of average weighted price of $9.64. That is about $15 billion of revenue locked in during the next ten quarters. We do not believe any other producer has done such a good job of locking in such high prices for over 60% of their productions in the coming ten quarters. And as to whether we plan on lifting any hedges, we may do so if natural gas prices significantly weaken from here. But our bias would be to hold to these positions for additional downsize protection in the quarters ahead.

Number five; we are informing you that we will have a big mark to market gain this quarter, maybe as high as $4 billion. What the gas markets took away from us in the second quarter, they are more than giving back in the third quarter. Our debt to total cap percentage will benefit nicely from this anticipated restoration of equity in the third quarter.

Number six, we are advising you that we have shut in approximately $125 million to $150 million per day of gross gas production in Oklahoma because of low wellhead gas prices. This is the third year in a row in September to October, that we have taken this proactive step to protect shareholder value. In the past two years in this marketing year’s low point in natural gas prices, we shall see about this year in the weeks ahead.

Number seven, we are further advising you that by reducing CapEx, we will be growing somewhat less rapidly. For example in 2009 and 2010, we now project growth of 16% versus our previous estimate of 19%. On 2008, we are estimating 18% growth versus 21% previously. We believe these are still pretty slowly growth rates for the largest gas producer in the US but this will help natural gas demand growth to catch up with supply growth that we and others are delivering.

Number eight; we are disclosing that we are making solid progress in finding the Marcellus Shale 25% partner in a structure similar to what we have used successfully in our PXP and BP joint ventures to date. We plan to have a deal closed in the fourth quarter of 2009 with a company bigger than our own.

Number nine, we are disclosing that the time is now right to reengage in discussions with a midstream equity partner. Our plan midstream CapEx for the next ten quarters will be nearly $3 billion. And given the magnitude of that CapEx build up, it only makes sense for us to bring in a partner. We believe that by the end of 2010, Chesapeake midstream business would be generating annualized EBITDA of $450 million to $500 million. It should be the biggest producer over midstream business in the industry at that time and should be worth at least $5 billion to $6 billion.

Number ten, last but certainly not least, we are enthusiastically telling you that the Haynesville Shale continue to look great with our three most recent wells all coming in at more than $10 million per day of initial production. We now have 14 horizontal wells on production, and are drilling with 12 Haynesville rigs right now and we will have 14 Haynesville rigs drilling by yearend 2008 and up to 30 rigs drilling by yearend 2009.

In addition, we look forward to initiating sales either tomorrow or the next days from our very first PXP-Haynesville JV well. Everything is looking very good for us in the Haynesville these days. Given the importance of these disclosures and the uncertainty in financial and natural gas markets these days, we thought that you would appreciate a quick update on Chesapeake’s activities and on our competitive position.

We are now ready for your questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first call comes from Michael Hall - Stifel Nicolaus.

Michael Hall - Stifel Nicolaus & Company

Can you give a little extra color as to where exactly the rigs are being drilled?

Steve Dixon

We will not kind of give you the exact number of rigs but we will tell you that we are continuing to ramp up in the Haynesville and also in the Marcellus. Steady as it goes in the Fayetteville, maybe add a couple in there. We will be dropping rigs in Oklahoma and East Texas that are not Haynesville related and South Texas and finally Permian.

Michael Hall - Stifel Nicolaus & Company

And then one more, in terms of thinking about the macro, the natural gas macro, what keeps you up at night? Is it supply or demand that concerns you most?

Steve Dixon

Oh, I think, supply. We are pretty comfortable that demand will continue to grow overtime and I think that we need to accelerate that demand and as a company, we are doing everything that we can to do that. It is a little frustrating to be producing a product that is clearly superior to foreign oil as a transportation fuel and for the country to be a little bit slow to recognize that. But given that the relative price is half and it is about 90% cleaner and when consumed in America, creates American jobs. We think that it is a pretty compelling story and we are out there telling it. I hope other producers will join with us. So, we think that can accelerate growth of gas demand going forward.

Clearly, I think we are headed towards a time of some kind of carbon constraint in years ahead. I think that will on a relative basis hurt coal and help natural gas. And finally, there are moves afoot to try and see if there are export markets or export avenues from North America for natural gas via LNG turning in to the world market which of course, as everybody knows, is generally two to two and half times better than American gas prices right now. So, we think the industry has cracked the code on how to increase supply very quickly and it has proven this year for the industry to ramp up supply than for the rest of the country to ramp up demand. But in time, I suspect that we will get back in balance.

Michael Hall - Stifel Nicolaus & Company

Great and then one last, in terms of looking at your CapEx, just a point of clarity, is that net of the JV arrangements or should we be backing that off kind of in your thinking in terms of..,.

Aubrey McClendon

That is net. The $3.2 billion is what we said we are reducing our CapEx by about 40% of that, $1.3 billion is the result of the Fayetteville carry from BP and the anticipated Marcellus carry and the rest, $1.9 billion or 60%, is actually laying rigs down.

Just to be clear, the prior guidance already included the carry from Plains and the Haynesville. Did you catch that, Michael? Okay.

Operator

Your next question comes from Shannon Nome - Deutsche Bank.

Shannon Nome - Deutsche Bank

Aubrey, I would just want to probe a little more on your statement that we are looking a rough couple of years for gas prices. You have got, just by reading through your hedge position; you have got knockouts anywhere from $5.5 to $7.5 below end and obviously the ceiling prices on your callers are up in the $11 to $11.50 range. Is it an oversimplification to say that your view is sort you are a seller at above $9 to $10 and a buyer at and below $7.50 or can we take the midpoint of that range and say your view on mid-cycle is in the $9 to $10 range? Or can you just flush out what you mean by rough?

Aubrey McClendon

Yes, I will try to do that and I think Mark may have some observations on that as well. But first of all, I think my language was some people believe that we are in for the rough two and a half years. We always try to be defensive. There are hot summers to come and maybe some cold winters to come. There will be other CapEx cuts; rigs will start to layover. You cannot make money in the industry at wellhead prices that are in existence today and so, well we may be the first, and we certainly will not be the last. We always try to lead and hopefully this demonstrates some of that leadership.

As to the knockout, the vast majority of them are in the $5.75 to $6.50 range. We also shaped them according to the calendar, so that for example, the knockout prices are lower in September and October than they are in January and February. So, generally speaking, we view that when NYMEX prices go below $7.50, we believe that is resulting in wellhead prices that are uneconomic for the industry and that if those prices stay out there for very long, the industry will have to restrict its capital expenditures.

From our perspective, we make a lot of money in the $9, $10, and $11 range. So historically, over the last couple of years, that has been the price range. That has been attractive to us. It takes some chips off the table and I suspect that that will remain an attractive price for us over the next couple of years until we can get some more gas demand ignited and get some gas exportation ability probably in place as well. Mark may have some data.

Marcus Rowland

Yes, Shannon, I do not have a lot to add to that. I would just say probably 80% of our knockouts are greater, even greater percentage. That is what we call our $6.25 average price and as Aubrey points out, that is sculpted around the years such that is ranges from $5.75 range to maybe $6.75 or so depending winter or shoulder months. We have had I think three months in the six years, we have been doing kick outs that have actually kicked out in our premium return on having those has been 20 to 1 versus the revenue that we have lost in the three months that have kicked out. So, with volatility up, we are still seeing the ability to go in like last week when prices spiked considerably, and lay in additional hedges that get us into that $9.50 to $10 receipt point with the kick out. We also were doing some straight swaps last week for 2009 and 2010 at not quite that level but very favorable levels, trying to just balance our entire portfolio.

Shannon Nome - Deutsche Bank

Aubrey, you mentioned others potentially following suit here. We have obviously been watching on this permitting data declining some. We had seen the gas rig count stagnate some over the last few weeks. And yet no one other than you has publicly admitted that they are laying down rigs or pulling in their horns at all. Is that something you are seeing behind the scenes in the industry or you expected to be forthcoming in a bigger way?

Aubrey McClendon

Shannon, I just expect it to be forthcoming. If you just look back to 2001, this was an industry that sees gas prices spikes and that sees gas price valleys and whenever those spikes are extended, you get a drilling rig response and whenever you get a turndown in gas prices, you get a drilling rig response as well. So, I do not know what the number will be. It depends, I think, a lot on early fall weather but it would not surprise me for 200 to 400 rigs to come out of the rig count over the next six months as people who are conducting business today based on decisions they made on the first half of the year when gas prices were $10 to $13.

In that world, you have to kick and run 2000 gas rigs in the United States profitably. In a world we have seen in the last 60 days, when gas prices are seven and some change to eight and some change, I just do not think the cash as far is there to support that kind of drilling activity and of course the credit crisis or crunch, whatever you want to call it, certainly will not be favorable to companies that have to borrow a bunch of money to conduct their drilling programs. So, it is another message that we want to communicate today that we have been preparing ourselves for this moment in time through our hedges and starting a year ago with our joint venture activities so that we could get to a point where we could still pursue all of our growth plans but at the same time also actually generate free cash flow from all the activities.

Shannon Nome - Deutsche Bank

Before I sign off, any guess of what kind of supply growth or production growth we can generate with 200 to 400 rigs come out of the rig count versus what we have seen over the last year?

Aubrey McClendon

I have seen numbers all over the board but I guess I would just say that I think we have a much better chance of seeing gas demand growth get squared up with gas supply growth if you have a decline in the rig count. Gas prices today also have absorbed what some people are analyzing as a record short position and speculative positions against natural gas. So you could argue that as the rig count starts to fall, that the basis for some of those speculative negative bets against natural gas prices might need to be reversed over time. So, let us see how it plays out but today’s gas prices are not supportive of today’s drilling activities across the industry in my view.

Operator

Your next question comes from Brian Singer - Goldman Sachs.

Brian Singer - Goldman Sachs Group, Inc.

Really just following up on some of the earlier questions, going forward, how should we expect the drilling program would be impacted if credit markets do continue to remain tight? Obviously, assets still are part of your expectations in terms of cash inflows and I guess, at what gas prices will you consider either further reductions or return to your prior plans?

Aubrey McClendon

Brian, we adjust plans as we go along based on conditions. So, to talk about where we have a modification to this plan going forward, sure, based on what condition is thrown at us. At this point, they are all based on what we see in the forward curve. We are very comfortable with where we are with this plan. With regard to credit markets and their impact on us, I want to remind you, of course, that from our debt perspective, from our debt, the vast majority of it, senior debt that I think has an average maturity rate of something, a maturity term of about nine years. I think the first maturity is about five years.

And second of all, if you noticed, we have been doing business with companies that really do not need a lot of access to credit markets, and finally, with regard to VPPs, the credit markets have been tough for the past year and the VPPs that we have sold have been sold to banks that appeared to be some of the big winners in it. And then finally, in terms of any additional leasehold sales, they are going to be to companies that are in likelihood bigger than us who for one reason or another, may consider their position in North American shale place, not where they want it to be. And we are happy to work some of these companies in our place and of course most of them have very large cash resources and I think credit market concerns are about the furthest thing from their minds at the moment. Mark, anything else to add?

Marcus Rowland

No, I do not think so. I think you have covered it.

Brian Singer - Goldman Sachs Group, Inc.

And secondarily, on the Haynesville, can you talk about the ramp up on the midstream side and what that means to the timing of how you see your production there and whether the need for some of the financing and midstream deals that you are playing, how that weighs into that timing?

Aubrey McClendon

When you refer to midstream, there are really two components of midstream. There is our gathering system as we referred to them and that is really what our midstream system is about, very little liquids processing at this time, mostly gathering. And then of course, those gathering lines then go into intra or interstate RRC regulated lines that provide the takeaway capacity. With respect to the midstream takeaway capacity, there are four major lines there that have both backhaul capacity and forward-haul capacity to Perryville primarily but other places as well.

We are in discussions with a whole host of people that view Perryville and points east as being critical to the overall gas market for Haynesville, and we could sit and talk about six or eight different people that have approached us that we are committing gas to, walking up additional compression availability. People are looping lines, people are talking about new lines, and those will come on anywhere from 18 months to 36 months from now, and it will not be just to provide takeaway for us. It will be to provide takeaway to the other partners and competitors that we have in the field.

Backtracking to what we are spending money on which is our gathering; we have an extensive gathering plan there. We will be hooking into both takeaway lines to the north and in the south and those facilities will be looped. There is some chance in the southern part of the play that there will be some aiming and processing required as well and we are building all of that in. So, it is no different than the Fayetteville or the Barnett where we have had to build our own gathering systems because if we were to have gone to third parties to do that, we would have ended up putting up the money and giving away the profit margin.

Now, we are giving away the money to ourselves and we are going to be raising that from partners who we hope that want to participate by keeping the profit margin or so.

Brian Singer - Goldman Sachs Group, Inc.

Great, I guess, when you add it all up and consider your expectations of rig kind of ramp up with timing of gathering, timing of takeaway capacity, what should we expect in the average or yearend 2009 production from the Haynesville to be free of gas?

Marcus Rowland

I do not have that number on me. I can tell you that the guys that are working in midstream look at a variety of plans and right now, they feel like we will have adequate takeaway capacity for anytime in the future. Obviously, we are depending on third parties to come in and build the plant, build the takeaway capacity, as they have contracted to do.

Aubrey McClendon

We have a question come in, I guess, over the night or early this morning, wondering about, with midstream’s valuations down, would not it be hard to find a partner. And I would like to reemphasize that the people Mark is talking to are basically private equity type investors who are looking at this as a growth vehicle and not something as an immediate take-to-market kind of deal. So, not part of your question so much but I did want to jump in and add that to those who might be thinking that what we are really looking forward here is an existing public MLP to come in and be our partner here, and that is not the case.

Marcus Rowland

And also I would add in addition to private equity which is certainly communications are going on with those guys and have never really stopped completely, infrastructure funds have approached us, institutional investors have approached us, and it may be that we actually put together a consortium of those kind of guys and that it may take on a more preferred investment-looking equity versus just a straight common speculative but we are just on the process. We have hired some new people in that area. We have gotten a new CFO, Nick Deloso [ph] that has just been on a couple of weeks and we are looking forward to introducing him to various investors overtime.

Operator

Your next question comes from Scott Hanold - RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Aubrey, could you sort of give a little bit of color on your activity that you are going to do over the next couple of years? CapEx obviously came down quite a bit and production quite a bit less. So, just kind of a little bit as far as how you can…, bringing CapEx overall down about $3.2 billion but production just dropped the 3 percentage points. Is that some high grading going on there or how should I look at that?

Aubrey McClendon

I think that is exactly the way to look at it. We are continuing to ramp up in the Haynesville, continuing to hold steady at least in the Fayetteville and those are two places today that obviously are working very well for us. In the Barnett, we will be starting to slow down our drilling in that area; I think we are at 43 or so rigs today. And we will be starting a slow ramp down in the Barnett that will probably last a decade or so, I think we have reached our high water mark there. So, I think it is really just what you would expect in a time like this. You look around and look at some of your least productive place and you drop rigs there and you keep rigs going in your most productive areas and especially where we have joint ventures, for example, in the Haynesville and Fayetteville. We are obviously motivated to keep our drilling activity in those areas on pace with what we have discussed before. We have partners counting on that and also we have partners taking our share of the bill. So, I think, that it really drive some of the nice points that we can cut CapEx pretty significantly and still have growth that we think will leave the large cap group in the years ahead, at least from system organic activities along.

Scott Hanold - RBC Capital Markets

Ok, and then if we kind of take a look at some of the rig count numbers that you all have out there, I think, going down to about 140 and keeping it roughly flat for the next couple of years, what was the prior expectation behind the prior capital plan? Was it somewhere close to 180 rigs? Can you kind of give us a little bit of color there?

Aubrey McClendon

We never really were public with that number, Scott, and so, we will not introduce it now. But it was, let us just say that it was moving up from the 157 in 2009 and 2010. Now, it does not look like we will be doing that.

Scott Hanold - RBC Capital Markets

With regards to your earlier comments on becoming a potential exporter into the global LNG market and you just kind of your general thoughts on whether US producers can be sort of competitive on a cost basis with some of the other global LNG players out there.

Aubrey McClendon

We are really pretty deeply enmeshed in profits right now where we are talking with global LNG players. We have hired Citibank to help us in these conversations and they have been ongoing for the last 60 days. So we have learned a lot and I think we are learning that US gas at wellhead prices, certainly today, on the forward strip compared to what could be locked in the international markets that makes US gas actually very compelling. There has been concern about whether or not we would be able to get regulatory approval for this.

I would just point out that we export gas everyday to Canada. We export gas everyday to Mexico as well. And some of you may have seen that yesterday, there was an announcement that Kitimat LNG in British Columbia is planning to build an export facility there as well. So, whether or not the exports leave Mexico or whether they leave Canada or the US, any ability for the North American gas market which is pretty well linked up to be able to link itself up to world gas markets would be very, very favorable to all gas producers in North America. We try to be at the forefront of new developments in the industry and we are trying hard to make sure that we leave no stone unturned in our search for ways to increase the value of the production and reserves that we have.

Operator

Your next question comes from David Tameron - Wachovia.

David Tameron - Wachovia Capital Markets, LLC

A couple of questions, on the rigs being laying down, what towers have you got, guys, the rig as far as horsepower and what are the specs on those rigs?

Aubrey McClendon

David, as to that we are going to get that granular. I do not want to give any comment along those lines to translate and then an issue for a drilling contractor, a friend of ours. But I think it is fair to say that the rig that is being laid down. It will be a third party rigs and not Chesapeake’s own rigs. Today we have, how many are our own rigs? We own 83 and we have 83 running. I think we have got another 24 that we will take delivery on this year and in 2009. And so we will obviously keep our own rigs running before, we lay down another rig before we lay down one of our…

David Tameron - Wachovia Capital Markets, LLC

If we think about the CapEx budget, what gets cut in 2009 and 2010 and you gave some clarity as to the regions but can you talk about what rate of return that marginal CapEx dollar, I guess I will call on drilling side, the marginal drilling CapEx dollar, what type of a rate of return you have foregoing there?

Aubrey McClendon

We are probably not prepared to get that far down into the weeds, David but let us just say that in general, I would characterize the areas that we need to be cutting as really probably threefold. One, where we would have lower returns and number two that could be influenced by tough wellhead prices. Clearly, Oklahoma’s wellhead prices right now are being impacted negatively by what has happened with Rex issues, and the Rockies and also with Gulf Coast that are onshore fractionation and processing facilities being down as the result of the hike.

We had to shut production in as far away as in Mexico and Oklahoma, related to Bellevue’s inability to take any more NGLs. So as those facilities come back on, we do think it will help Oklahoma prices. But a good bit of our drilling slowdown will be in Oklahoma. I think the third type of play that would see a reduction is a play where we already have the vast majority of our acreage HBP or held by production and therefore we have a great deal and more flexibility in managing our asset base. Obviously given the choice of drilling an infill well on a square mile of land that already is held essentially forever by existing production or drilling a well on an offsetting and that it does not have any production and we have the opportunity to HBP that unit to the drilling then we are going to savor drilling in that second unit. So I think those are the three types of plays where we would tend to drill less rather than more.

David Tameron - Wachovia Capital Markets, LLC

You may answer this as well but you mentioned minority interest in the midstream and it is still a billion dollars. Can you give us a range around what would that minority interest might be? I am trying to back into it to EBITDA multiple on the midstream.

Marcus Rowland

It is really hard to do because of the growth ramp up. Aubrey mentioned that we headed a couple of years of EBITDA to be around the half billion dollar mark so you can put a low valuation on it if you are thinking two years forward. Today's EBITDA is probably approaching $200 million on a run rate basis. The goal of the billion dollars to maybe a billion and a half dollars as I mentioned in earlier answer that could come in a form of the preferred instrument rather than just straight equity but I will say that in prior discussions generally speaking, we have values that range from $3 billion to $3.5 billion on a common basis for the entity which obviously implied people were looking forward to the growth

Operator

Your next question comes from Wayne Andrews - Raymond James.

Wayne Andrews - Raymond James & Associates, Inc.

Quick question for you on just sort of maybe more philosophically on the rigs, should we perceive this as really dropping rigs in marginal place or maybe seeing a shifting of rigs to higher return place? Many of which might actually be higher volumes such that maybe the industry can achieve similar results with fewer rigs for a while, and could you comment on your company and maybe what you think as the industry as a whole under that kind of a scenario?

Aubrey McClendon

Wayne, to me, those are a little bit two sides of the same coin. We have said that we are going to continue to increase our rig count in the Haynesville for example and so to the extent that we expect our rig count to remain relatively stable over the next couple of years. Clearly that shows that we will communicate that we will reduce the rig counts in other areas as we go along. So, when you replace Haynesville or a mid-continent rig drill underground on wash well for example with Haynesville well, you might pick up some additional productivity. We will be slowly starting to ramp down a little bit in the Barnett and I think that is a reminder to folks that there is a plateau insight with regards to the Barnett going forward and I think that will help everybody solve for future production balances as well.

So, we will be doing a little bit of both, we will be reducing rigs in poor place and continuing to dig some rigs to other place. With regards to the rest of the industry, all I can say is that there are really only about ten companies that probably matter in shale place and maybe when you really just list it down, it is no more than half a dozen. So, I kind of see the industry as having bifurcated over the last few years and I think that these $10 to $13 gas prices support a lot of drilling in some marginal areas that will probably go away first whereas I think you will see the rig count and some shale place continue to ramp up over time. But here pretty soon, I think you will see an overall ramp down of the Barnett rig count which will tend to offset some of the growth in the Haynesville.

So, in that net you will hope that you are always laying down your most marginal rigs and that is why I think probably to have an impact here on gas supply-demand balance as going forward. We need to see more than 25 or 50 rig cut across the industry that probably need to be measured in several hundreds of rigs.

Wayne Andrews - Raymond James & Associates, Inc.

Right and I would say we agree with that and the concern is that the shifting of rigs from marginal into higher volume, higher return place might support supply for a little bit longer than maybe some would think on that existing rig count.

Aubrey McClendon

I suppose it is possible but remember, every well you drill today whether it be a shale well or a horizontal Granite Wash well or a well on the Rocky Mountain or a well in any tight sands place in the US is going to have a very, very steep first year decline curve, somewhere probably at least 60% and maybe as high as 85%. So, I still think you will see lower rig counts leading to less production drills going forward even as you see some high grade in those efforts and keep in mind, you still have infrastructure constraints to deal with these wells. Certainly in the Barnett, we are seeing that and frankly, you are going to see that in the Haynesville.

So, I think that the inability of the industry to ramp up its production as aggressively as I have seen in some people’s model, just kind of ignores, on purpose necessarily but just naturally ignore some of the real challenges we face every day in the field, getting our product to the market.

Operator

Your next question comes from Robert Christensen - Buckingham Research.

Robert Christensen - Buckingham Research Group

What would the debt-to-cap of Chesapeake look like at the end of 2008 and perhaps the end of 2009?

Could you just comment about the, I guess the futures market or the hedging market. Is it still robust? Are you still finding counterparties that still want to do lots of transactions to keep the $6 billion?

Marcus Rowland

If you, as to your first question, we are showing a debt to book cap at the end of 2009 to be projected at 34% dropping to as little as 31% at the end of 2010 and our current projection show 37% at the end of this year. So as Aubrey mentioned, the second quarter was, I guess dislocated as a result of the large mark to market hedging which will, if not completely largely reverse itself in the third quarter, will show at the end of third quarter more normalized levels.

With regard to your second question, we have 22, I think, current counterparties and we were able to have a $6.5 billion negative mark as of the end of Q2 and continue to hedge very actively during the third quarter. Today, we are seeing new parties come in, whether it’s from overseas banks to new financial private equity guys that are getting in the business. So, at least with respect to Chesapeake and our secured facilities and the way we got it arranged through our non-secured players, we are not seeing any constraints on continuing to have a book of hedging that frequently will range from two to two and a half, three cubic feet

Operator

Your next question comes from David Snow - Energy Equities.

David Snow - Energy Equities Inc.

I am trying to get a little better handle on the price differences between NYMEX Henry Hub $7.75 and the reference to depressed go-ahead price of 3 to 5 in mid-continent, I have heard low prices happening at Rockies. In general, can you tell us what your price differences from NYMEX as an average? It cannot possibly be that low and you mentioned a few things, give us some more color on the differentials here.

Aubrey McClendon

I think we gave you some differential guidance in our outlet, which we have done for years, and we are targeting 10% to 14% per natural gas for the third and fourth quarter. In the mid-continent right now, I think I mentioned a few minutes ago that we are experiencing some extraordinarily low pricing, I think last weekend. Eastern Oklahoma, gas prices got even as low as $2.60 at the wellhead in a week. So, all of our gas in that area at the first of the month and they are actually closer to $6.50 but it just drives home the point that last few weeks have been tough for mid-continent producers as we experience those back-ups from the Rockies as Rex has been largely out of service during the month of September and then also the Gulf Coast natural gas processing that I have mentioned a few minutes ago as well. So, I think if you will stick with those differentials that we give guidance for most of the time, I think you will be fine. Mark may have some more precise pricing that he wants you to remind you but again, all of this is influenced by those two factors.

Marcus Rowland

I was just going to say that Platts Gas Daily does a very nice job in opening a plug for them. We use that many ways everyday, but if you are go to their daily price survey which was…, has a national average price which includes all of the Eastern and Henry Hub areas against a Hub price of $7.40 or $7.50, the national average price was $6.43, but the range yesterday in El Paso and Permian, you were at $4.84, Waha was $5.05, ANR, which is a delivery point in Oklahoma was $4.30. Aubrey mentioned Center Point which is $3.36 today. And so you can then go to CIG in the Rockies and you are $3.44, current level at $3.55 and I will remind you that those are delivered prices at those delivery points so you then have to further deduct your gathering whether it is third party or your own charges to get the gas from the wellhead to those delivery points. And the things we have looked at in the western place in the Rockies frequently that is another $0.50 to $1. So, if you are delivering in the CIG at $3.44, your wellhead price might be $2.44.

David Snow - Energy Equities Inc.

You got the same percentage differential when your schedule will be. I guess, it sounds things should have been worse today.

Aubrey McClendon

Well, not well. I mean they are but this is for the course of a quarter and I think we have already driven home the point that what we are seeing right now, we think has a specific ground in into two non-recurring events directs pipeline issues as I think as well the effects of Hurricane Ike.

Operator

Your next question comes from David Heikkinen - Tudor Pickering and Holt.

David Heikkinen - Tudor Pickering Holt & Co., LLC

I do not want to try to steal too much from your analyst stake coming up but can you give us an update as far as the productivity of the wells in the Haynesville, kind of what declines have been within along the lines of what you expected?

Aubrey McClendon

Yes. David, they have been along the lines of what we have expected, 6.50 Bcfe is still midpoint of our curves for ER outcomes rather, and a range of 4.5 to 8.5 is what we are looking at. We are just getting ready to move to ten stage frac jobs from eight stage frac jobs. So hopefully, we will have a few results for you all when it comes to Oklahoma City in three weeks or so. So right now, we like what we are seeing. Getting a lot of positive confirmation from other operators in the play and there is a fair amount of experimentation and innovation going on so.

David Heikkinen - Tudor Pickering Holt & Co., LLC

What is your current production in the Haynesville?

Aubrey McClendon

We will disclose that when we see in three weeks, which is moving ahead nicely towards our end of the year target.

David Heikkinen - Tudor Pickering Holt & Co., LLC

And then big picture as you look at your 2009 to 2010 capital budget, what are your expectations for service costs, escalating, flat, and declining versus where they are today?

Aubrey McClendon

Well I think, given our, what we put in our outlook today is that we are budgeting for $8 a gas for 2009 to 2010. So, $8 gas translates into probably $6.50. So, wellhead on a national basis and, that is a tough price for the industry to maintain current activity. So, I would imagine that we will see cost going down, I think, steel prices have already rolled over and of course, if we lose a couple of hundred rigs over the next few months, rig rates would go down as well. So, this is a dynamic business. Gas prices go up and cost go up. Gas prices go down and cost go down.

David Heikkinen - Tudor Pickering Holt & Co., LLC

Do you have any percentages that you can print? I mean, should we think about it, gas price you took from 10 down to 8, the similar percentage works on services costs or would that be too high?

Aubrey McClendon

No, I do not think it is quite linear, as gas prices go up 20% or 30% and they are all got eaten up by cost price increases, service side when you go down on gas prices, you do not pick it all back up from your service base but we will try and develop a little more specific numbers free by the time that you get here, but generally, they are going to move in tandem with probably four to six months delay in both hand.

David Heikkinen - Tudor Pickering Holt & Co., LLC

And then looking at your DD&A guidance, should we think about that as F&D guidance and modify our reserve growth targets along the same line with the tugging growing capital?

Aubrey McClendon

Well, you can if you like. We still believe that by the end of the year, we will be at 13 Bcfe and 13 Tcfe rather and 15 Tcfe in 2009. We talked about 17 Tcfe in 2010 although, it looks like now we are going to be under a different reserve recognition policy by the SEC and I would say if anybody were to going to ask me, what is the event in the next few years that will have the biggest impact on the valuation of the industry especially our Company, it will be the ability to recognize proven undeveloped reserves much more expansively than we can today.

I would be stunned if in 2010 we were not a Company with well over 20 Tcfe proved reserves given the new guidelines that are out for comment right now. So anyway, our DD$A rate will go down as we invest more of our money in shale place with funding cost of around a $1.50 per Mcfe. It will go down as service cost moderate over the next couple of years. And then our number of reserves will continue to march up pretty dramatically and then we will absolutely fly up in 2010 and obviously I think, that is going to be a huge water shed event for the valuation of the industry that I do not think anybody particularly focused on but I am looking forward to it with some eagerness.

David Heikkinen - Tudor Pickering Holt & Co., LLC

And then one final question, as you think about the organization as a whole, your leasing budget is dropping in 2010, ship people around there reducing the rig count expectation. Are there any changes to kind of where Chesapeake has grown as far as the number of people and the impact to the organization and I am just kind of curious of probably your comments and Steve too, if you have any thoughts about how people move around in your organization given these changes in plans?

Aubrey McClendon

Well, it is a pretty dynamic organization. We move people around all the time. We have 7200 employees, about two-thirds of them are on the service side, about a third are on the ENP side. We have a lot of young people. I think in Oklahoma City right now, we employ somewhere around 2300 folks and somewhat around half of those are under the age of thirty. So we have done a great job of hiring a bunch of new people and getting them trained up over the last past few years. And with a flattish rig count, clearly the amount of hiring that we have done will probably slow down and that is probably a good thing for the Company as everybody gets to see underneath them. So, I think that it is a welcome, probably a welcome development.

David Heikkinen - Tudor Pickering Holt & Co., LLC

Do you worry about losing people as you think escalating rig count, escalating activity? You got people with a lot of skills for a lot of horizontal wells, completely a lot of horizontal wells. Just that indication of slowing some of the activity or not escalating, I am just curious if that changes the dynamic as well you think.

Aubrey McClendon

No, I do not think it changes it too much, David and also, when I think back on what I said to you before, when I correct myself that 60% of our employees are on the ENP side, and about 40% are on the service side. I had my percentages goofed up there, sorry about that.

Operator

Your next question comes from [Ray Deacon - Richard Capital].

[Ray Deacon - Richard Capital]

What are you assuming in your revised budget numbers for the next 10 quarters about service cost? Did you hold those flat and in your comments reflecting, you think they will go down with a lower gas price?

Marcus Rowland

We actually have been continuing to edge up in our budget, Ray. That is probably a little bit, well it is not conservative…well, it is conservative kind of a projection perspective, clearly not what we anticipated given our view that if we budget for $8 natural gas, we really do not need to be budgeting for costs increases over time. So, I think there is a nice potential dividend here as we go forward as gas prices stay around our range that you would probably continue to see efficiencies which we really do not build in too much over time and then continuing to see cost deflation rather than inflation.

[Ray Deacon - Richard Capital]

Got it and I guess, you talked about the Marcellus joint venture with a larger company and having announced the increment with BP and the Fayetteville. Are you surprised about the change in attitude of the majors or is it the big change or just a couple of companies that seemed more interested in not conventional gas?

Marcus Rowland

I think it is a big change and I think it is a significant change. It is a huge deal for our company and I will not tell you that every major big company in the world has been to see us but quite a few have and I think that there is really a couple of things at work. One is that some of these companies, not all of them, see their worldwide playground a sense of moving in on them a little bit.

Secondly, some of them have not spent a lot of money in North America in the last few decades. BP is certainly not one of those. They have stayed very active but other companies have let their North American businesses wither a little bit. I think, some of them are interested in rebuilding their businesses and finally North America, specifically the US, is not the only country in the world with shale and so, I think many of these companies rightfully looked at Chesapeake as a leader in US gas shale development and if they partner with us, perhaps it would give them a real gap on gas shale developments around the world.

So, those are the three primary drivers. I guess the fourth would be that many big companies are attracted to the very low relative gas prices in the United States and view that either true greater demand from the transportation network or greater demand in the electrical incineration sector or LNG exportation facilities being built in years ahead that the US gas market if it does not link up exactly with the worldwide gas market or at least, not traded the huge discount that it trades out today. I see those four reasons as to why we have had so many communications with bigger companies than are on listing.

[Ray Deacon - Richard Capital]

And just one last quick one, in terms of the big swings on your balance sheet due to the hedging losses but now gained, so I guess, what is going on with the banks given their exposure in capital calls from other areas? I guess, are you having or maybe spread your lending around a little more or is there anything to talk about there?

Marcus Rowland

I do not think, this market, I do not think there is anything more to add than what we had. You might have missed our earlier answer to similar question there. We have about 22 counterparties so we have always spread the risk around recognizing that when you go to sell two or two and a half, three cubic feet that when the gas prices are $13 or $14, you got a $30 billion potential exposure, I guess.

So we have entered into what I think have been pretty creative, secured facilities so that when the marks move against us, counterparties have collateral that drive away risk and the value that collateral moves up and likewise from our standpoint, we deal with banks in our bank group where we can allocate per pursuit collateral as we call it out of our existing and revolving credit facilities so that we are not limited to just one kind of facility. Really, there is really nothing more to add to it. It is obviously a volatile time but we have managed that volatility I think incredibly.

Aubrey McClendon

Well I say this is not the first time this has happened in the world of counterparties. There was a time when Enron and Williams and El Paso and many others were active in the hedging world. And we relied on them to some extent and their business model changed and other people stepped in. So we are pretty confident that given that we have the most, I think the most active hedger, I guess the biggest hedger in North American gas market that we will continue to be able to do business with the highest quality counterparties and we will continue to manage our exposures the way Mark has mentioned.

Operator

Your next question comes from Matthew Warburton - UBS.

Matthew Warburton - UBS

Just a very quick clarification question, in your opening remarks, I think you mentioned that you expect the Marcellus joint venture be closed in the fourth quarter of 2009. I presume you meant fourth quarter of 2008.

Aubrey McClendon

Yes, thank you for correcting me, Matthew. I probably said that that was certainly wrong. It is 2008 that we are looking at.

Matthew Warburton - UBS

Just for Mark, you mentioned, Mark the debt account forecasts out for the next three years. Can you remind us what the gas price is that you are assuming on that outlook?

Marcus Rowland

Well actually, it varies on a percentage basis if you we will look at our slideshow and go to 2010, for example, there is not much change but at the $7 gas price actually with debt to book caps 32% and from $8 to $11, it is 31%. So, there is almost no change. In fact, I think there is no change on 2009 because we are so heavily hedged so 2010 we do not have so much hedged that there is any variability at all

Matthew Warburton - UBS

I will follow on the question you answering about the collateral and the hedges, given the mark to market reverse, does that mean there would not be a sizable cash return to Chesapeake given the mark to market swing..?

Marcus Rowland

Well, the mark to market swing against us and the mark to market swing for us did not involve any cash to begin with. Remember these were all paper transactions that close some time in the future and that is the only time that there is any cash effect. So, if I understood your question right…

Aubrey McClendon

And we do not have to close to cash margin.

Marcus Rowland

Yes, exactly. So we are posting collateral that is in the form of well and gas reserves or dedications out of our bank agreement and we were not called on at that $6.5 billion level to send any cash to any one nor we would be getting any cash back.

Matthew Warburton - UBS

Right, so if we then look after that back comment with the cash receipts from the BP JV. What is your current liquidity availability in terms of the..?

Marcus Rowland

We closed the BP on the 19, which was Friday, and that money came in and I have not seen the end of yesterday’s treasury report but I am going to guess their availability would be in the $1.8 billion or so range.

Operator

We will go next with [[Bradley Keith - Bradley Keith Investment]].

[Bradley Keith - Bradley Keith Investment]

Recently at a conference presentation, Aubrey mentioned about the knockout on the hedges and in months where you do go below the knockout then do you just not get anything that month or nothing below the knockout price?

Marcus Rowland

The answer to that question is on gas. When gas closes below the knockout and this, I will go to another situation pretty shortly but let just say the knockout is $6 and gas closes at $5.99, we do not get anything from our hedging counterparty. It would be as if we never entered into that.

On the oil side, they work a little differently and let us say our knockout is $100 a barrel to make up a number and oil falls to $80. We will not get what the swap was but we will get $20 from the move from $100 to the move $80. So, then we would have three way callers which has two puts a call on it and there we get the difference between the two puts but nothing below the lower puts. So each one works a little bit differently and offline, we will be happy, Jeff or I to take you through how each one works, if you care for that granularity.

[Bradley Keith - Bradley Keith Investment]

Okay and the last question on that is will it afford to be triggered to go below the knockout. Is it like a one-day price or an average for that particular monthly cycle?

Marcus Rowland

No, you can set them up either way and oil is frequently setup on an average daily price. Our gas swaps are all with either a penultimate, which is, the next to the last day or the last day. Just to make calculations a little bit easier, so it has to be below that knockout price on that one day.

[Bradley Keith - Bradley Keith Investment]

Okay and then on your various hedging counterparties that you talked about, are you concerned about any of the, I guess, credit worthiness that they have made it this time or do you feel that some companies had made some announcements that they either did or did not have any impact from Lehman Brothers and I know that was pretty low on your totem pole but I guess there is always the question of others out there that may follow Lehman Brothers.

Marcus Rowland

Sure, well, our two biggest counterparties by volume of hedges on are Morgan Stanley and Goldman Sachs and are next three largest by volume would be Credit Suisse, Barclays and Deustche Bank. And then we have got fifteen others so I do not know whether to answer that I am concerned about or not.

Aubrey McClendon

I am less concern today than I was last Wednesday that is for sure. So, we are going to wrap it up Bradley. Thanks for the question. That is all of our counterparties we are proud of and we look forward to them returning to prosperity that they have enjoyed in the past. Thanks to everyone for your questions and if you have anything else, please follow up with Jeff or Mark. Thank you.

Operator

That concludes our presentation.

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Source: Chesapeake Energy Corporation Business Update Call Transcript

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