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Chesapeake Energy Corp. (NYSE:CHK)

F2Q08 Earnings Call

August 1, 2008 9:00 AM ET

Executives

Aubrey K. McClendon - Chairman of the Board, Chief Executive Officer

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

Steven C. Dixon - Chief Operating Officer, Executive Vice President - Operations

J. Mark Lester - Executive Vice President - Exploration

Jeffrey L. Mobley - Senior Vice President - Investor Relations and Research

Analysts

David Tameron – Wachovia Capital Marcets

David Heikkinen - Tudor Pickering & Holt

Jeff Robertson – Lehman Brothers

Michael Hall – Stifel Nicolaus & Company

Thomas Gardner – Simmons & Company International

Joe Allman – JP Morgan Securities, Inc.

David Snow – Energy Equities

Brian Singer – Goldman Sachs

Jason Gammel – Macquarie Research Equities (NYSE:USA)

Monroe Helm – CM Energy Partners

[Paul Bennett – Boulevard Trust]

Operator

Good day everyone and welcome to the Chesapeake Energy hosted 2008 second quarter earnings release conference call. Today’s conference is being recorded. At this time I would like to turn the conference over to your host, Mr. Jeff Mobley.

Jeffrey L. Mobley

Thank you for joining Chesapeake’s 2008 second quarter financial and operational results conference call. 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, Steve Dixon, our COO, and Mark Lester, our Executive VP of Exploration who also joins us from out of town.

Our prepared comments this morning should last about 20 to 25 minutes which is a bit longer than usual but we believe you will find the additional detail useful. We will 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’re able to attend. We have lots of ground to cover this morning so I’ll have Aubrey jump right in.

Aubrey K. McClendon

Good morning to each of you. Jump right in, I will. It’s been quite a while since I’ve been this fired up for a conference call as there are many important issues to discuss. My discussion topics will include the Haynesville Shale, our other important plays, natural gas prices, gas supply and demand trends, and our overall business strategy.

Let’s begin with a review of some recent negative comments about the Haynesville Shale from a friend and colleague of mine at another company. To begin perhaps it would be best to go back in time a bit and remind you that when Chesapeake arrived in the Barnett Shale in 2004 we did not arrive thinking it was a 10-county play. Instead, our careful petro physical analysis of the play predicted that the horizontal Core and Tier 1 area would include only about 1.2 million acres situated primarily in Johnson and Tarrant Counties. Other companies might have thought the play had greater aerial extent but we knew then and we know now that the heart of the Barnett horizontal play is only about 1.2 million net acres in size, almost exactly what we predicted four years ago.

What has changed over the past three years is that our estimated ultimate recoveries in the Barnett have increased from about 2.45 BCFs for every 100 acres to about 2.65 BCFs per every 55 acres. This increase has been caused by a steady improvement in the technology to drill, complete and produce horizontal Barnett wells. We now believe the Barnett will ultimately produce at least 60 BCF of natural gas and the majority of that will come from Johnson and Tarrant Counties. But before the 60 BCF number makes you want to throw in the towel on current or out-year natural gas prices, please remember that it will take more than 50 years to produce all that gas. Please also remember that the decline rate from the first month of the Barnett well until its 12th month is about 65% and to its 24th month is almost 80%. Yes, we believe Barnett gas production will steadily increase over time but depletion rates, pipeline constraints, and urban drilling issues are likely to keep those incremental volume gains much more modest than most observers are predicting, probably on the order of less than 750 million per day per year over the next few years and then leveling off to a plateau of no more than 6 or 6.5 BCF a day by 2012 or so. This is a sharp contrast to the 1.5 to 1.7 BCF per day increase in production we have witnesses from the Barnett over the past year.

Now back to the Haynesville. A few years ago our geosciences system petro physicist began studying the Haynesville Shale on the heels of our Barnett and Fayetteville successes and concluded that the Haynesville could be an attractive target. I suspect other companies did not arrive at the same conclusion because they either did not have the right geoscientists or did not think that a shale as young or as deep as the Haynesville could economically produce. We were fortunate in that there were over 100 historical penetrations of the Haynesville in our study area and we were also lucky to get our hands on a Haynesville Core from a well drilled by another company. And once analyzed by our team, this Core confirmed the potential of the play. We then outlined an irregularly shaped buy area for leasing, something we have internally called the Blob. The area our scientists outlined two years ago was about 3 million acres in size, the approximate same size that we see the plays being today. The Blob’s outlines have evolved over time but the same basic area where we have focused our leasing is about 90% unchanged. What has changed is that we are now producing about 45 million cubic feet of natural gas per day on a gross basis from our first 11 horizontal wells.

Let me tell you more about these 11 wells. The first well has been on about 300 days and is on a 9/64 choke and is making about 700 MCF [feet] per day. It was a five-stage frac job in a short lateral. For 10 months we have kept it on a 9/64 choke so that we can obtain more consistent rate and pressure information on this constant choke over time. Four wells are short lateral re-entries, one of which is also only making 700 MCF per day because of a mechanical problem with the fish down hole. The other three have been online an average of four months and are producing around 3 million per day each through 14/64 or 16/64 chokes, again for the same reason as the first well I described. The next four wells have been online an average of two months and are producing an average of 4 million a day from six-stage completion wells. And our final two wells are producing on 24/64 chokes and are making a combined 20 million cubic feet of gas per day.

One of these last two wells is the only well we have completed using eight stages in our completion techniques and this well is making 14 million cubic feet of gas per day after its first week, the best shale well we have ever drilled among the more than 2,000 we have been involved in. It is remarkable that after just 11 wells we are already able to bring in wells making 14 million cubic feet of gas per day. The learning curve in every other shale play has taken dozens if not hundreds of wells and we know of no other shale well in any other shale play that has averaged more than 9 million per day during the first several weeks.

From here on all of our wells will be long laterals with at least eight completion stages and we will likely produce them on 24/64 chokes rather than the smaller chokes we completed our first wells on. This will greatly increase the likelihood of completing wells that will begin producing at 10 million cubic feet of gas per day or even better.

I’d also like to point out that the Haynesville is over pressure very substantially and as a result, the Haynesville wells have a very real advantage as the compression cost can be avoided for years as the reservoir pressure will exceed line pressure. Another very positive attribute of the Haynesville will be its superior gas price compared to the Barnett, Woodford, and Fayetteville. In July our Haynesville well head gas price exceeded our Barnett well head gas price by about $1.50 per MCFE. This month with gas prices about $4.00 lower, it will still be about $1.35 higher than in the Barnett.

As to recently expressed doubts about our calculation of Haynesville gas in place, if you’d studied the 100 existing Haynesville logs and taken Haynesville shale Cores from your first four vertical Haynesville wells and had been able to evaluate them in your own proprietary shale Core laboratory, then maybe you might have been able to do the same math on gas in place and recoverable gas that we have. Our experience and analysis tells us that on average every square mile of Core and Tier 1 Haynesville Shale contains an average of 180 BCF gas in place. This is based on an average formation thickness of 220 feet across this 3 million acres, original formation pressure of almost 10,000 pounds per square inch, and porosity, permeability, and water saturation measurements that for now we will keep confidential. From that gas in place we are estimating that we will recover about a 52 BCF per square mile through the drilling of eight wells per square mile. This would result in per well average recoveries of about 29% of the gas in place, which is consistent with expected Barnett recoveries although Barnett drilling is 50% more dense than planned Haynesville drilling. This is a somewhat smaller recovery factor than expected from the Woodford and Fayetteville.

Now how much gas is there really in the Haynesville play? Well, that math is actually pretty easy as well. With about 3 million acres in the Blob, that means there’s roughly 4,700 square miles. At 52 BCF of recoverable gas per square mile, that equals about 2.45 BCF of recoverable gas in the Haynesville, exactly consistent with what we had predicted from the beginning. So rather than this number being hype, it is instead an entirely reasonable number based on thorough scientific examination reinforced by actual drilling results to date.

And those of you who have followed Chesapeake will recall how conservatively we have historically been in estimating the initial potential of the Barnett, Fayetteville, Woodford and Marcellus shale plays. Our approach with the Haynesville has not changed. Of course these reserve estimates are not proved under current SEC definitions nor have we ever claimed otherwise. But rather, these are reasonable early estimates of the total resource that we and others plan to produce over time, a time like in the Barnett that will probably require at least 50 years.

Now before you become concerned about longer term natural gas prices as a result of the sheer size of the Haynesville, please remember some likely natural constraints to the play’s growth. First, it’s sheer size. The play will require decades to fully develop and since much of the play includes leases that have been held by production for as many as 50 years, many companies will take a very methodical approach to developing their Haynesville assets. Secondly, the shale is found at about 11,500 feet deep on average and takes rigs that must have at least a 1,000 hp engine, 600,000 pound rates mass, 1,600 hp triplex pumps, and top drive. There are not many spare rigs with these capabilities so the availability of rigs will be the second serious impediment to the play’s production ramp up. Third, we believe that for the next two to three years there’s probably not more than 1.5 BCF per day of incremental pipeline capacity out of the Haynesville, much of which we have tied up. In the meantime, major new transmission pipelines will be planned and will be built to serve rapidly growing southeastern markets but we do not believe you should model for the Haynesville to be producing more than 1.5 BCF per day by more than three years from today. This pipeline constraint along with slowing growth from the Barnett over the next few years and very little incremental growth possible for the next two to three years in the Rockies and ongoing declines in the Gulf of Mexico and in Canada plus increasing demand from the US power sector should be sufficient in our view to prevent a US gas glut from developing and we believe gas prices will generally settle in an average range of $9.00 to $11.00 per MMBTU at Henry Hub pricing.

One further thought, please recall that roughly 30% of today’s US gas production comes from wells placed in service in the past year and approximately 40% of current gas production comes from wells less than two years old. So should gas prices decline further, we would see less drilling and therefore less production growth, if any, as these aggressive first and second year declines kick in.

I have a few other thoughts on gas markets these days. First of all, by all accounts production gains in 2008 have been simply extraordinary running somewhat greater than 4 BCF a day above last year’s levels. As we analyze those gains we quickly note there have been two one-time production gains that have accounted for about 50% of that increase - the Rockies Express Pipeline and the Independent Sub. Taking those two one-time events away, we believe you are left with organic gains of somewhere around 2 BCF to 2.5 BCF per day or so. We believe these gains are likely to be about the same to slightly less in 2009 and 2010 and we believe demand can grow quickly enough particularly in the price range that I’ve outlined to absorb these additional volumes in the years ahead.

I’d next like to update you on our other big shale plays and on our business strategy evolution during 2008. As many of you will recall, starting about 10 years ago we became very bullish about natural gas prices and created an aggressive business strategy focused on building a very significant asset base of US natural gas especially in unconventional reservoirs. However, during the past year you’ve begun to see a powerful new aspect of our business strategy develop. We have now become a seller of assets occasionally rather than just a developer of assets. Why the change, you might ask. Well, in our view if gas prices are likely to remain relatively flat for a while in the $9.00 to $11.00 range, then it makes sense to bring some of our more distant present value forward and monetize it at today’s attractive prices.

We have chosen two ways of advancing this present value forward. The first is through volumetric production payments or VPPs. They give us the ability to monetize some of the low declined mature gas assets that are valued in the stock market of Chesapeake at less than $3.00 per MCFE and monetize them at about double that level. So far, including a third VPP we should close on later today or Monday, we have sold VPPs for proceeds of $2.3 billion. The reserve volumes sold were 395 BCFs. So we monetize these assets for cash at $5.90 per MCFE and took the cash and reinvested it in our gas manufacturing machine that today is consistently developing reserves at around $2.00 per MCFE. So if we can find it for $2.00 and the stock market only values it at $3.00 and we can sell it for nearly $6.00 through a VPP and still keep the tail reserve, what’s not to like about that. In addition, for income tax purposes these VPPs are treated as loans so there is no cash income tax leakage from the transaction. Furthermore, the proceeds from those VPPs go into our full cost pool as credit and so as we offset an approximate $2.50 per MCFE current DD&A rate with about $6.00 per MCFE VPP proceeds, you’ll see that these VPPs will reduce our DD&A rate going forward and enhance our profitability and improve our returns on capital. In all likelihood we will sell another $500 million VPP in the second half of this year and probably $1 billion to $2 billion worth next year as well.

The second part of this new aspect to our business plan is demonstrated by the recent transaction we entered into with PXP in the Haynesville. In that transaction we sold 20% of our 550,000 net acres for $3.3 billion, half in cash up front and half over time in the next few years. To date our total investment in the Haynesville is around $4 billion so by selling 20% for $3.3 billion we have recouped 80% of our cost, lowered our per acre average cost by 77% from $7,100 per net acre to $1,600 per net acre, and established a remaining value of about $22 per share for remaining 80% of this unique asset. This transaction reduced our risk, lowered our cost, aggressively advanced present value creation forward, and has provided valuation transparency for this enormous asset. In time we believe this acreage will be worth at least $50,000 per net acre to us or $37.00 per share.

I might note that last week there was an announcement of a transaction in the Barnett that valued non-producing high quality Tarrant County leaseholds at more than $50,000 per net acre. If it happened in the Barnett, it will happen in the Haynesville over time.

Our next two areas for potential partnerships will likely be in the Fayetteville and in the Marcellus. We are also planning to pursue one in the West Texas shale play because we have recently drilled a series of excellent wells there. So in the past, once we found gas we only had one way to make money from it and that was to sell the gas over time as the well gradually depleted. Now, however, we have developed a way to accelerate that process and that’s by selling off a portion of our new plays to partners at very attractive prices. And similarly to the VPPs as the sale proceeds go into our full cost pool as credits well in excess of our costs incurred to date, our future DD&A rates should decline as well which will lead to higher profitability and greater returns on capital. Just at the time other companies are experiencing rising finding costs and higher DD&A rates, Chesapeake will be headed in the opposite direction.

Next I’d like to update you on some of our other important shale plays. First an update on the Barnett. We are currently producing about $775 million per day gross from the Barnett and $500 million per day net. During the quarter we averaged $466 million a day net from the Barnett which is a sequential quarterly increase of 13% and a year-over-year increase of 126%. Clearly all is well in the Barnett for Chesapeake. We are running around 45 rigs there and are on pace to drill about 700 wells per year in that play for many more years to come. Our best new Barnett wells continue to be located in southeast Tarrant County in an area of particular leasehold strength for us where our 2008 drilling has averaged over 3.8 BCFs per well compared to our overall average of 2.65 BCFs.

In the Fayetteville we are drilling our best wells ever due to improvements and where we position our laterals within the Fayetteville, longer lateral lengths, better completion techniques, and the arrival of certain new 3-D information that help us avoid geological pitfalls such as falls. Today we are producing approximately $150 million per day net from the play, are utilizing 17 rigs, many of which are drilling to HPP or 500,000 net acres of leaseholds there. We plan to increase our rig count gradually to about 25 rigs in 2009 and then keep it there for the foreseeable future.

Finally I mentioned on our PXP conference call a month ago that we had drilled two very nice horizontal Marcellus wells. They are located in West Virginia and are today producing at a combined basis of about 7 million per day and believe these wells have a combined EUR of about 11 BCSE. Last week we read Range’s announcement of their activity in Southwestern Pennsylvania and their view that horizontal Marcellus EURs of 3.5 to 4 BCSE and their tier one area were reasonable. Based on our study of their area and our own in Northern West Virginia we concur with their EUR estimate. That makes the play very, very attractive.

However, again I would caution gas market observers to not expect a Barnett style ramp up of gas production from the Marcellus. There are way too many regulatory topographic water and infrastructure issues that will keep the Marcellus from making a meaningful contribution to our company’s gas production until at the least 2013 to 2015 timeframe. That’s why are pleased that so much of our 1.6 million net acres of Marcellus leasehold is either HBP or on 10 year leases. We have plenty of time to work through the substantial challenges of developing this very promising play.

In conclusion then I believe we have addressed these important questions this morning, why is the Haynesville so good and why can it be as large as we had previously stated? Why should gas prices stay at an equally consumer and producer friendly range of around $9 to $11 per MMBTU? Why is it good to be hedged for the next two years just in case? Why are business strategies shifting to advancing present value creation through VPPs and partnerships is working so well and how will it cause our costs to go down as the industries are going up?

Thanks for your patience today as you listened to these longer than usual comments and hope you have found them useful and I’ll now turn the call over to Marc Rowland.

Marcus C. Rowland

Good morning, welcome to everyone. I have just several topics to cover with you this morning. First on oil and gas hedging, as stated in our release our mark-to-market losses relating to the change in value during the quarter for open hedging positions on future natural gas and oil production generated an unrealized pre-tax hedging loss of $3.4 billion. This caused the unusual situation of reporting negative oil and gas revenues for GAAP reporting purposes. Remarkably by Friday, July 25th, our mark-to-market position moved in our favor by a staggering move of $4.6 billion in just over three weeks.

We had previously discussed the current accounting requirements for [derivate] securities can substantially distort the reporting of current period financial results for companies such as ourselves and this industry. I can think of no better example than our second quarter GAAP results and now likely our third quarter results which will completely reverse and move in the opposite direction if future prices hold where they currently are trading. We believe the adjusted revenues EBITDA and earnings that we also report help analysts and investors better compare current period financial results to prior period results market expectations and our peer group.

The recent swings in prices highlight the need and substantial value of the hedging arrangements we’ve put in place to mitigate market volatility. To remind you we have six secured hedging facilities that allow us to pledge natural gas and oil properties as collateral for hedges rather than cash and we also hedge through about 15 other counterparties in our bank group that have collateral pledged from our revolving credit facility which we call para-pursue collateral also removing the need for cash collateral with our hedging program. To be able to weather a negative $6.5 billion mark with no cash margin calls is pretty impressive. Our goal in hedging is to capture high margins when prices briefly spike and mitigate risk. Our facilities put us in the position to safely hedge in excess of 2 trillion cubic feet of gas and we are now substantially hedged at great levels with strong profit margins captured for the better part of the next three years.

Next, let’s move onto our cost structure. You should particularly note our oil and gas DD&A rate for the quarter ended June of 07 our rate was $2.60 per thousand equivalent. By March 31st of 08 that had moved down to $2.52 and in the current quarter only $2.47. So year-over-year this important measure reflects a 5% reduction in cost structure in a rising oil field service price environment. This of course is partially driven by our improved drilling finding costs and partially driven by our new strategy of capturing embedded value gains in our asset base by selling mature properties into VPPs for much more than we have invested in them which reduces our full cost tool by much more than reserves are reduced per unit.

Going forward the Haynesville 20% shale to our partner PXP and the 100% Arkoma Woodford Shale to BP will further accelerate this downward trend. In fact had those third quarter transactions been effective at June 30th, our DD&A rate would have been as low as $2.30 per equivalent unit. This strategy will help highlight much improved accounting metrics of our return on investment and return on equity going forward better reflecting the real economic returns we have been creating while also enjoying a decreasing book cost structure that many other ENP companies will not likely be able to benefit from in a rising cost environment.

Now just a minute on cash income taxes, a few questions have arisen due to our transactions that we’ve recently announced. While the VPPs for tax purposes are treated as loans our transactions with PXP and BP will be taxable and they will cause us to pay cash income taxes that we estimate will be between $100 million and $250 million in 2008. Going forward we still do not estimate paying ordinary Federal income tax on our normal operations due to our drilling program but future cash income taxes will of course be dependent on additional sales, timing and the structure of any sales we do and those could have ordinary tax rates on a portion or all of any such transaction.

Next, I’d like to discuss the fair market value of our assets. We recognize that it’s been a very difficult July for most oil and gas investors, it’s not fun around here either when we are hard at work creating great increased value per share while the market reacts negatively. A few things for you to consider, our 12.2 TCF approved reserves were valued at current market prices on June 30th at $51.5 billion. Obviously that was at very high prices. I had those reserves re-valued today using a couple of different price decks and the number drops to between $37 billion at strip prices and about $34 billion at $9 flat. Those numbers book in per share value of about $58 per share for our approved reserves alone. Now if you consider the Haynesville transaction alone we have a current market third party valuation at 20% for $3.3 billion ala PXP, that puts a residual value at about $13 billion for our remaining 80% or $21 per share. Adding those two numbers together results in fair market value of about $48 billion to $55 billion. After subtracting out obligations that total $14 billion we again return to a net asset value of about $60 per share.

Now that’s before the Fayetteville, the Marcellus, the Barnett non-proved, West Texas Shales and the substantial number of other plays that would begin to deliver value markers on in the near future, plays we believe could easily add over $40 billion in value or $65 per fully diluted share. In addition of course our midstream gas business and the book value of our other assets is worth at least $5 billion. Our current market price of approximately $50 per share is a discount of over 55% to this total implied value of between $115 and $120 per share, a compelling value proposition in our book and the largest discount to net asset value we’ve ever seen.

Finally I’d like to remind you of another way to think about value at CHK and that’s how we are creating value every day. Recall that we consider ourselves to be in the gas manufacturing business and that requires four inputs in our opinion. Those inputs are land, people, science and of course capital. From these inputs we believe we’re able to create outputs of natural gas at a cost of about $2 per MCF equivalent. MCFEs that have shown through VPPs and our other sales are worth at least $6 per thousand equivalent. Please remember that to date this year we have increased our crude reserves by 1.3 trillion cubic feet equivalent and by the end of the year we’ll likely have increased our crude reserves by 2.5 trillion cubic feet creating up to $15 billion just this year of shareholder value. That’s more than $25 per shareholder value creation achieved through our gas manufacturing process. We think that’s pretty impressive and hope you do as well.

Operator, we are now ready for your questions.

Question-And-Answer Session

Operator

(Operator Instructions) We’ll take our first question with David Tameron – Wachovia Capital Marcets.

David Tameron – Wachovia Capital Marcets

Question for you, just looking at your level of activity the 156 rigs you have running we’ve heard some concerns from other EOG Apache talking about steel and pipe and tightness in the tubular market, can you address how you guys are set up for that if you look out over the next six months, the next year?

Steven C. Dixon

It is very tight right now and we’re scrambling to stay ahead of those 156 rigs but getting her done. We have long term arrangements, have been a major pipe buyer for years so we think we’re going to [git-r-done] but prices have gone up significantly in the last few months.

Aubrey K. McClendon

One of our Board members is Pete Miller from National Oil Well, we talked to him yesterday and of course there is acquisition of grant had some pretty good insights and he thinks it’s mainly maybe topping out perhaps a bit so we’ll see. Again we’ve been the number one consumer of oil field tubulars for years and years so we’ll get our share of our tubulars, they will be more expensive but we will not be running out of tubulars.

David Tameron – Wachovia Capital Marcets

Then one more question for you and I’ll let other people jump on, if I’m looking big picture US domestic market, you mentioned your back out wrecks and independents of 2% to 3% organic growth, what gas price do you think, where’s the marginal cost supply in the US today to continue on the 2% to 3% pace?

Aubrey K. McClendon

That’s a question people have been trying to answer for years and years and of course it changes, but you used the word percent and I think you meant BCF per year because our [inaudible] just so everybody’s on the same page 2 to 2.5 BCF per year of organic growth. My thought is that the market is bifurcating, that shale plays and tight sand plays are ones that seem to be profitable at probably an $8 NIMEX price but what I think we see and many plays across the country that are what you would call conventional those plays are at an increasingly large cost disadvantage to the shale play. We think about our plays in the Barnett, Fayetteville, Haynesville, etc. we’re able to drive costs down over time as we drill dozens, hundreds and even thousands of wells. If you look at companies that are out trying to find five and 10 well fields, you just don’t have the opportunity to drive your costs down, you’re always inventing yourself through these smaller targets.

I think if gas prices were to stay below $9 Henry Hub for some period of time I think that the sale plays probably continue to move forward but I think you’ll see a lot of rigs drop out of what you would call conventional drilling. And another thought, people get fixated on what our Henry Hub prices, remember that basis differentials in the mid-continent in the month of July are about $1.30 to $1.40 per MCF and when you start talking about compression and things like that, $8 gas these days means probably something close to $6 at the well head. There’s been quiet or a silent creep of about $1 into basis differentials over the past 12 months on average that I think a lot of investors probably don’t fully appreciate that what companies get at the well head is less and less related to what you read in the headlines at Henry Hub.

We think gas prices will stay in this $9 to $11 range, there’ll be times like in July when they’re above it, there’ll be times when they’re below it and of course the weather will matter a lot as well. But we’re pretty confident that much below $9 you’d see a drop off in drilling activity particularly among the conventional drilling and then those pretty aggressive 35% to 40% first year declines are going to kick in and rebalance the market.

I saw something the other day where some analysts had come up with production in 2010 was going to be up by something like 8 to 10 BCF a day and gas prices were going to be $6.25. That kind of analysis I think can only come at the dangerous intersection of Excel and PowerPoint, it can’t happen in reality.

Operator

We’ll take our next question with David Heikkinen - Tudor Pickering & Holt.

David Heikkinen - Tudor Pickering & Holt

Just thinking about the valuation and the $115 to $120 a share, Marc what do you think it takes for the market to unlock that value?

Aubrey K. McClendon

I’ll take one whack at it. First of all you’ve got to have some stability in gas prices and I think just over time I think more and more confidence about the Haynesville obviously the negative comments about the Haynesville last week, I had a lot of people express concerns to us and when you consider who all is involved in that play, the well results to date, it’s just not very smart to start dogging that play because the well results today are so exceptional and are only going to get better over time. I feel like over time people will not be able to ignore the fact that every quarter we’re going to be increasing our reserves by at least half a TCF per quarter and that’s after our monetizations, that’s on a cash neutral basis that contemplates no issuance of securities and at the end of the day gas prices are going to go up and down but I think they’ll stay in an attractive range and I think investors will be able to see that every quarter we ought to be able to add at least $2.5 billion to maybe as much as $4 billion or so of value here. Marc may have some other thoughts.

Marcus C. Rowland

David I do have a couple of other thoughts which is I think the continuation of the rollout of our strategy of bringing partners into these large acreage plays like we did in the PXP transaction, transactions that we see happening perhaps even this year in the Fayetteville, this year or next year in the Marcellus and in West Texas along with the monetizations either through VPPs or outright sales of our mature properties will just continue to highlight the vast difference between how the value per acre of these plays is valued in our stock and in the public markets versus how they’re truly trading in the natural gas sector. So continuation there will just I think set up a series of catalysts to give people the opportunity to revalue the company and look anew at our strategy.

Aubrey K. McClendon

One final thought, David, also this decline in our cost structure is something which is going to run completely counter to what’s going to be happening at most of our peer companies I think. Our stock is I think the second best performer in the sector over the last five and ten years so we’re not complaining about stock price performance, just simply pointing out that if you’ve been a critic of Chesapeake over the years, it’s probably been as a result of over-investment and you’ve felt like we’ve added too much to our costs blowing our DD&A rates too high and our returns are too low.

Going forward though as a result of being an early mover we’re now going to see our returns go up, our DD&A rate go down as everybody else has to now weight into acreage markets and pay many, many multiples of what we had to pay going forward.

David Heikkinen - Tudor Pickering & Holt

So thinking about land, people, science and capital, Marc, just your comments I guess are highlighting that one of the ways you think you’ll that capital gap is, and you’ve highlighted in your IRs through asset sales on some of these mark-to-market values for the Fayetteville and Marcellus. You just mentioned West Texas as well, can you give us an update on what’s going on in West Texas?

Aubrey K. McClendon

Sure we can. In the last couple of months we’ve really achieved some completion breakthroughs there, we have some vertical wells that actually are very commercial. We have horizontal wells that are quite good as well. While certainly that play hasn’t arrived at a point where we want to go throw 10 or 20 rigs at it, I think we have cracked the code there enough that it would be a great area to bring in a partner into and start to attack it. It’s just so vast, we have over 1 million acres in the area and there’s so many kind of different play types whether you drill vertical Barnett and Woodford wells or drill a horizontal well and complete the Woodford vertically and the Barnett horizontally. There’s all kinds of formations up and down the whole. We think that’s going to be attractive to some partners. It’s taking us longer than I would have personally liked to have gotten to this point but from here forward it’s continuing to drive costs down, continuing to enhance these completion techniques and I think to bring a big boy in to help us advance the ball forward from here and of course that’s not a play that anybody is giving us credit for right now.

Plus we have two or three different types of wells planned for other formations out there that we think is successful have resource play potential as well.

David Heikkinen - Tudor Pickering & Holt

Then oil shales anything that you can update there?

Aubrey K. McClendon

I think in March was the first time that we began to talk about we were targeting oil shales and this 20 to 25 person team that we have over in our shale laboratory has been very helpful in working with our team GSI just to come up with some new plays. I think I mentioned to you that we were working on five unconventional oil plays and four of these were in shale and one of the five was already producing at the time and we also said that all four that were not producing would be tested by the end of the year. The non-shale play is our [Wayloo], West Edmonton Hunt line unit field area Northwest Oklahoma City and that’s working quite well. Petrohawk has a significant interest there as well and I think they’ve released some positive information about it. It’s an old abandoned oil field that we’re now going back in and drilling horizontally and it’s working well for us.

The other four are shale plays in four different states. We are drilling a well right now in the first of these plays and we’ll have the other three tested by the end of the year. We’re real excited about the potential of those and again feel like our core lab and our people might give us the jump in being able to find some new shale oil plays.

Operator

We’ll take our next question with Jeff Robertson – Lehman Brothers.

Jeff Robertson – Lehman Brothers

Aubrey, you made some comments about the pressure in the Haynesville, can you talk a little bit about the operating costs in that play? Secondly, can you talk a little bit about where you think that ranks in your overall asset mix in terms of returns?

Aubrey K. McClendon

I think I’ll take the second part of that and let Steve Dixon take the first. From a return perspective even without the carry from planes we believe it would be the best area for us when you combine lack of compression costs, when you combine gas prices that are $1.30 to $1.50 higher than the Barnett and finding costs that are going to be again without the carry somewhere between $1.33 and $1.50. With the plane and carry for the next two to two and a half years our finding costs in the play are going to be we think around $0.67 to $0.70 in NCFE. So there won’t be a play in the country of course [inaudible]. I’ll let Steve talk to you about operating costs.

Steven C. Dixon

The big deal is that there’s no compression so these other shale plays a lot of your lifting costs are compression costs so we don’t have that, these shale plays don’t make much water, you have some flow back initially and then that dries up. So the play should have very low lifting costs.

Jeff Robertson – Lehman Brothers

Steve, the gas doesn’t need to be processed either, does it?

Steven C. Dixon

No it does not. It’s right on the edge, there is some CO2 but we’re able to sell that. We’ll just keep an eye on that. We haven’t crossed over yet.

Operator

We’ll take our next question with Michael Hall – Stifel Nicolaus & Company.

Michael Hall – Stifel Nicolaus & Company

Can you talk a little bit more about the Haynesville export capacity and you talked about the 1.5 feet CF per day coming out of the play over the next few years and just maybe give some more granularity on exactly where that’s coming from and maybe what you think will be needed over the longer term to be added and what you’re doing to help bring that on?

Aubrey K. McClendon

Michael I’m not going to get too granular about that because we do have competitors for pipe space out there. I will say that if you are an operator of a long distance pipeline in America or want to build a long distance pipeline in America you’ve been to see us in the last 30 days or so to pitch your plans about how to get more capacity out of the Haynesville. We’ve tied up all the take away that we can, we think it will be sufficient to for us during the timeframe that I talked about and at the end of that timeframe we believe we’ll have new transmission capacity out of the area.

In terms of how big the play can be and you’ve heard Mark Pappa from EOG talk about his thoughts this week about the peak of the Barnett our peak is higher than his but I think probably less than what other people or some gas market observers are modeling and the reason for that of course is you don’t build infrastructure for the very peak of production, you build for a plateau and then have that plateau carry out for a certain number of years before declines kick in. The Haynesville is fascinating in the sense that I think it can do whatever the market needs it to. If we’re successful in developing alternative uses for our gas for example in the form of compressed natural gas for cars and the market for natural gas takes off in the next three to four years, the transportation market begins to rely on natural gas then I think the Haynesville will be there. If that market doesn’t develop then I think the Haynesville will not develop as quickly.

I kind of see the Haynesville as this enormous big gas resource and its tempo of development I think will be determined by the growth in gas demand and if that gas demand skyrockets then I think production can do the same. If it doesn’t I think you’ll just see normal year-to-year supply increases out of Haynesville that will meet demand but will overwhelm demand.

Michael Hall – Stifel Nicolaus & Company

That kind of leads into a macro question I have regarding demand, could you walk through perhaps where you see marginal demand falling off in the face of the high prices we saw towards the end of June, early July, maybe if there’s any signs in your eyes of some marginal demand destruction in that regard? Then longer term as it relates to CNG and transport fuel growth and demand there what can we think about in terms of what kind of needle moving demand figures can come from that market do you think?

Aubrey K. McClendon

First of all I think when everybody kind of freaked out on the first few storage numbers in July I think probably what we all forgot is that we were comparing year-over-year numbers where last year’s index for July if I recall was around 750 or 775 and this year’s index was 1350. Well in a market of 54 BCF a day of demand and would it not be logical that with the gas price 85% higher than last year you might see a couple of BCF of demand go away and I think that’s what we saw happen. I think Wednesday’s storage number shows that as the month wore on perhaps some of that demand came back a little bit. I will also tell you that producers struggle in hot weather, compressors struggle in hot weather and I would not be surprised to see the industry’s production on August 1st 2% to 3% down from where it was on July 1st if for no other reason than compressors across the industry not running as efficiently. Nobody really things about that but 2.5% to 3% lower production across the industry is a BCF and a half per day. So, when you combine that with the a first of month August price, it’s considerably lower than July, it would not surprise me at all for us to get a series of bullish storage numbers in August as demand comes back and as supply struggles during the hot weather.

With regards to C&G, I took my little show on the road this week to go talk to members of congress about a study that was unveiled by the America Clean Skies Foundation and this Washington based think tank which we founded over a year ago had commissioned Navigant Consulting to look at supply in a post shale, or in a world where shales were well understood particularly with the Haynesville included in the analysis. What they concluded and we announced on Wednesday was that there is plenty of gas in this country to begin thinking about an energy policy with a clean sheet of paper.

The math is pretty compelling, the US consumes about the equivalent of 10 million barrels today of oil equivalent in the form of gas. We consume, as you know, 20 plus million barrels a day in the form of oil, about 70% of which goes in to our transportation network. It is our analysis that about every 1% of our car and like truck fleet that gets converted over would consumer about 225 BCF a year which would make it about .8% increase in supply needed. The Emanuel Born Bill which came out a couple of weeks ago has the goal of getting 10% of the American transportation fleet over from gasoline and diesel to C&G. I think that’s reasonable. I’d certainly like it go faster and that would only require an increase of supply from our industry of around 7.5% to 8% so we think that is very achievable and we’ll provide consumers of gasoline a real price break because C&G is about half price. At the same time for producers a real nice alternative market for our natural gas production.

Operator

Our next call comes from Thomas Gardner – Simmons & Company International.

Thomas Gardner – Simmons & Company International

Aubrey, assuming we’re in the fourth quarter of the US land grant, what are your thoughts on the Canadian and European resources plays?

Aubrey K. McClendon

Tom, that’s a great question. We’re not Canadian players and we’re not international players. I’ve read a little bit about what Apache and EOG and others are doing in Canada and that’s certainly seems exciting. I have been a producer in Canada for four years, from 97 to 2001, for us it’s a little bit like the Rockies, it’s a great place to look for gas, it’s a tough place to make money so I’m glad that our shales are down closer to market. Internationally, what I’m excited about for kind of the rest of my life is that I think the world as we start to approach or roll through a time of peak oil production, I think gas shales around the world will get developed until we can start to move the transportation fleet around the world to C&G.

Right now there are about 800 million cars in the world, I believe, and only about 8 million of them run on natural gas. Obviously, the United States and Canada are not the only countries with shales that would work for gas supply. What nobody else has is an industry like we have to go out and extract that. But, presumably in the decades ahead, that expertise will be exported to other countries and you’ll see the use of gas rise, I think, to make up for inevitable shortfalls in the production of oil going forward.

Thomas Gardner – Simmons & Company International

Concerning North American natural gas supply, if some point down the road we do get in to an oversupply situation, what is your view on the lag time before the market corrects itself?

Aubrey K. McClendon

Oh gosh Tom, we’ve seen the market get in oversupply almost every year for the last four or five. What’s kind of interesting is you get a gas price collapse the last three years that has occurred each year a month earlier than the month last. If you think about 2006, it occurred in the October contracts, if you think about last year it occurred in the September contracts, this year it occurred in the August contract and I think there are some reasons for that. But, if you were to get a further decline from here I think you would see the rig count start to go down and our experience from 07, 06 and going back to 2001 shows you that the industry doesn’t stable or breakeven very long and whether or not that’s a month or two it just doesn’t happen and people can get very, very negative on gas prices in a hurry as we certainly found out the last three weeks. This is an industry that always spends its cash flow, often times more than its cash flow and if we don’t have the cash we can’t spend it so you’ll see 40% first year declines kick in and the market correct.

One thing that I would say is a real feature of the market is that every time we go through one of these draw downs in gas prices, the floor is higher than it was before, as it should be, because of higher coal prices and higher industry planning costs and higher oil prices. So, I would suspect those people looking for $6 and $7 gas prices out of this draw down are likely to be disappointed.

Operator

Our next question comes from Joe Allman – JP Morgan Securities, Inc.

Joe Allman – JP Morgan Securities, Inc.

Just to clarify your points about the Barnett shale, could you just again clarify when you think the industry will peak production? And, I think you said is it 6 to 6.5 BCF per day, I think you said 2012, could you just clarify that? And then, when you’ll peak and what you think your volumes will be at that point?

Aubrey K. McClendon

Joe, I think I said 6 to 6.5 BCF a day kind of depending on things and whether its 2012 or 2013, 2011 is kind of hard to know. Our production is 775 million a day right now and I think Steve, we have it modeled up to about 2 BCF a day and I think we hit that in 2012. So, our market share will actually increase in the Barnett overtime as some other companies that are not in Tarrant County will reach a point where their production plateaus faster than our production. For example, if you’re a Johnson County focused producer you probably hit a production ceiling well before we do. Also, with all the urban drilling challenges and the logistical nightmares we go through every day, there are just limits to how rapidly things can ramp up and so anybody who extrapolates from what’s happened in the past 12 months where production is up 1.5 plus BCF per day and extrapolates that over the next two or three years, I think is making a mistake. We think that growth and supply will go in half over the next few years. Our share will get bigger of a pie that probably expands to 6 to 6.5 BCF a day by 2012 or so.

Joe Allman – JP Morgan Securities, Inc.

On the issue of natural gas demand from transportation, I heard your comments but what do you think the likelihood of that happening in the time table? And, what are the key triggers for that to happen in your view?

Aubrey K. McClendon

Well, in some ways its already happening. Close to 20% of America’s bus fleets already run on natural gas, many municipal fleets cars and trucks are beginning to [inaudible] Los Angeles and Long Beach go to 100% natural gas by the end of this year. Kenworth and Peter Built are coming out with tractor Trailer cabs that are natural gas, those will be out by the end of this year. So, if you’re a shipper of a good across this country and for the last couple of years you’ve been hit by fuel surcharges, I think you’re going to be asking your trucking company why they haven’t bought natural gas engine trucks to haul your products because when they do so you’ve got diesel prices at $5 and natural gas price equivalency of about $2. I think there will be enormous pressure for the shipping sector here, for the truck fleet to move to natural gas very quickly.

Joe, the market is recognizing this. You’ve got a fuel that’s half the price of gasoline, it’s at least two thirds cleaner and it’s made in America. Tell me the consumer who’s going to rise up and say, “I don’t want any of that.” Everybody would want something like that. So, my goal and working with congressional leaders is to get the market moving more quickly and the reason for the urgency is I think we could wake up six months from now, a year from now, two years from now and not be grabbling with $4 gasoline prices but maybe with $6 or $8 if something blows up in the Middle East. I think there’s a real sense of national urgency here and people in congress have been looking for years for a way to go to their constituents and say, “I have an energy plan and the energy plan is to bring you a fuel that’s made in America, it’s clean and it’s half the price of gasoline.” Everybody will want that.

The Emanuel Born Bill will provide financial incentives for service station owners to install C&G pumps, for car manufacturers to make C&G cars and for consumers to buy C&G cars and also to install them in our garages. The bill calls for basically 1% per year transition from traditional fuels over to natural gas. I’d love to see that accelerate by a factor of two or three but I think at least 1% per year is certainly a reasonable possibility.

Joe Allman – JP Morgan Securities, Inc.

Aubrey, would you be involved in investing in the infrastructure just to get that going faster?

Aubrey K. McClendon

I don’t think it’s necessary Joe, and it’s not the best place for us to spend money. I think that will happen away from us. Just imagine as you drive down the street and you’re passing an intersection with three gas stations on it. The one guy who gets his C&G pump in faster and advertises $2 gasoline, he’s going to sell a lot more beer and a lot more cigarettes and a lot more Twinkies so I think everybody is going to be pretty motivated to be the first on the block to get their C&G pump. Now, we will look at investing in L&G export facilities and we are studying that right now. We’ve got to figure out a way to get some linkage to the world market and we are dedicated to trying to find a way to achieve that linkage.

Joe Allman – JP Morgan Securities, Inc.

Aubrey could you talk about that a little bit? What are you doing right now in that regard?

Aubrey K. McClendon

Well, I can’t talk too much about it other than to tell you than to tell you that we read the papers and see that gas around the world goes for twice what it goes for here. So, my view is we make a great widget here and that widget is valued at x here and 2x around the world so we’re trying to figure out a way to get it on a boat and get it to some overseas markets as well. So, the addition of a potential linkage to world prices as well as to work natural gas in to the transportation network, I think really creates two huge value added out year markets for the industry and I’m doing all I can on both fronts.

Joe Allman – JP Morgan Securities, Inc.

Marc, what’s the extent that you’re seeing in terms of rising service costs?

Marcus C. Rowland

Well Joe, they’ve definitely turned, I would say and I’ll let Steve jump in here too but Steve, frac costs have turned and are headed a little bit up if for no other reason than they’ve got a little bit of transportation they’re trying to pass along and I think those are in the 0 to 5% range on a per annum basis. Obviously Steve mentioned Steel prices which have easily doubled I think.

Steven C. Dixon

Right, they’re doubled.

Marcus C. Rowland

And you heard our comments earlier probably that maybe they’re at a peak right now. Drilling rig cost Steve, have been going up for the new rigs that are new builds I know.

Steven C. Dixon

They’re trying to create some pressure. I don’t know if overall inflation will be that high besides steel and diesel. But, we want to remind you that Chesapeake’s unit cost will be going down.

Marcus C. Rowland

Right. It’s an ideal time to own a fleet of – let’s see we have 83 operating today and we have 20 something, 25, 27 on the way. I think it makes our plan operationally to have the rigs available to move them around and to have them be custom made for the play types that we put them in. It’s smart but it is also just a terrific hedge against the demand in the business to put more rigs out that cost a lot more today and some people will pay a lot more for those.

Marcus C. Rowland

Plus, you can finance them basically 100% and get them paid for in three plus years or so.

Steven C. Dixon

Exactly, we’ve been using sales lease backs to convey tax benefits that we have not previously been able to use so those have come at implied capital cost of anywhere from 4.5% to 5% on basically eight year financing plans.

Operator

Our next question comes from David Snow – Energy Equities.

David Snow – Energy Equities

Can you give us a profile as you would see it for the Fayetteville as you gave it for Barnett?

Aubrey K. McClendon

When you say profile, David I’m sorry but what do you mean?

David Snow – Energy Equities

The growth build up overall and for you overtime?

Aubrey K. McClendon

Do you mean in terms of a ceiling or a peak?

David Snow – Energy Equities

The rate of growth from there to there and the peak years.

Aubrey K. McClendon

David, we don’t have that. So much of that is dependent on South Western’s rate of increase. I think we did say today that we’re at 17 rigs today in Fayetteville going to 25 and that’s probably a level at which we’ll stay indefinitely. It’s going to continue to increase over time but if you’re worried about a gas surplus in America, if you recognize that the Gulf of Mexico is going nowhere but down, if you recognize that Canada is really going nowhere, if you recognize that the Rockies are bottlenecked again for the next couple of years, you really only have to solve for the Barnett and the Haynesville and if you listen to what EOG said this week and believe what we said today, and if you believe what I said about the Haynesville that it won’t be able to exceed pipeline constraints then there are really only two other shale plays out there that you really need to bother with and that would be the Fayetteville and the Woodford and we think those increases a year are 200, 300, 400 million a day and certainly not market movers. And finally, the play that people have expressed concern about would be the Marcellus and it’s not going to be anything significant for probably another five years or so.

David Snow – Energy Equities

Is it 200 to 300 to 400 a day each or both Woodford and Fayetteville?

Aubrey K. McClendon

200 million is probably too low so let’s talk more probably 300 or 400 a day and those would be, I think, per play although in time the Fayetteville will be much bigger simply because it is so much larger than the Woodford.

David Snow – Energy Equities

I’m a little hesitant to throw in a negative on this beautiful call but is there any chance your rate of equity increase will slowdown as you monetize in the sale of assets?

Aubrey K. McClendon

Yeah, I mean that’s the whole point in doing these monetizations is to get out of the equity issuance business. The problem for us is that we had this enormous mismatch this year between the cash needs of what we had to get done in the Haynesville and how to get these asset monetizations done. In the first half of the year basically we had to spend or commit to spend around $4 billion for the Haynesville at the same time we were ramping up leasing in the Marcellus and the Barnett as well and then all of our asset monetizations with the exception I think of 1 VPP and 1 Woodford sale, basically all but $1 billion of our asset monetizations came in the second half of the year. So, we just had an enormous mismatch if you will of cash flows this year which required us to go out and kind of underpin the fundamental financial strength of the company with equity. We had to do that twice this year and I think that’s the right thing to do but going forward we are moving in to a timeframe where we are going to be generating cash as a result of these asset monetization programs and don’t see another shale play on the horizon that has any kind of capital demand, anything remotely close to what we had to go through with the Haynesville this year.

David Snow – Energy Equities

So we would expect to see a slowdown in the rate of equity increase and a per share acceleration I would imagine in the volume of BCFs per share.

Aubrey K. McClendon

That is the goal.

Operator

Our next question is from Brian Singer – Goldman Sachs.

Brian Singer – Goldman Sachs

Listening to your comments today and your testimony earlier this week in Washington, it seems that there’s a dual goal of finding the right gas price that optimizes value creation for Chesapeake stock with stimulating more accommodative public policies for demand that you’ve talked about. I guess my question is, is it the $9 to $11 range that does that? And, how specifically would Chesapeake respond if prices were to move above or below that range.

Aubrey K. McClendon

Brian, you absolutely have captured obviously the challenge of my life here at Chesapeake because I am searching for a gas price that is helpful to consumers and at the same time it is profitable enough for our industry to continue to bring supplies to market that we think we can. Obviously what our American Clean Skies study showed is that there are enormous resources of gas. You’ve got to convert those resources of gas in to flows of gas and to do that you have to have a price at which you can make a profit. We don’t think that is $6 or $7 in NCF we think that is somewhere around $9 to $11.

For consumers of gas, some of them are going to consider $9 to $11 too high but given where coal prices are, given where oil prices are, I think it is pretty fair value. If you think about transportation fuels remember from a [MMDTU of natural gas you can get eight gallons of transportation fuel and so $4 gasoline at the service station is $32 per MDTU so clearly we can deliver great value to the American consumer if we can begin to consume more natural gas.

With regard to our plans, we just always assume that prices will spend a fair bit of time above that range and a fair bit of time below that range. We run a 24/7 manufacturing business here and you can’t start and stop a factory so that’s why we hedge. We like to hedge for a rolling 24 month period. There are times on June 30th where you look pretty stupid and you’re down billions and billions of dollars and then you wake up three weeks later and you’ve made $5 billion plus on your hedges in three weeks and you feel a little better about yourself. Going forward, our view is that when we can hedge at the midpoint of that range from $9 to $11 or higher, we’re going to do that, take risk off the table and ensure our selves that going forward we can continue to run our factory 24/7. I think that’s how I would ask you to look at our program going forward given the really extreme volatility that we’ve seen in the marketplace.

Brian Singer – Goldman Sachs

I guess though when you comment that the Haynesville is likely to only grow more rapidly if some of the additional demand markets open up like transportation. Are you then dependent on some of the other players in the Haynesville to move their rig count in the event that does not materialize as quickly since it seems like you may be more sticky in shifting your capital program?

Aubrey K. McClendon

Well, a couple of things to think about. First of all, somewhere around 40% of the play is probably HBP, held by production. And, I think in my comments I talked about maybe some of [inaudible] have been HBP for 50 years, it’s actually I think probably closer to 80 years from the days of the Texas boom and discovery of cartage I think in the 40s and so if you are a holder of acreage in Texas that’s been held by production for 75 years you’re probably not likely to rush out there in a $6 market and go drill a bunch of wells because of $6 gas. I mean, you’re going to pick your spots. So, don’t think about this as the Barnett where everything is wild and wooly and you’ve got to get wells drilled in two years or you lose the acreage, you start off at a big disadvantage.

The second thing here is we can make – our units are 640 acres. In the Barnett, it’s been very difficult to establish units much more than about 200 to 250 acres in size and many time they’re smaller than that because of lease restrictions. So, when we go out and drill our first well in a 650 acre unit, we have guaranteed ourselves then that if that lease is HBP and we can warehouse seven eighths of our inventory. We’re going to go out and HBP our acreage but I don’t think that you necessarily see an industry here that’s going to be under the same type of use it or lose it pressure that many of us have been under in the Barnett.

Brian Singer – Goldman Sachs

When we look at your guidance for cap ex and production growth in 09 and 10, it would seem that if the entirety of the ramp up of the Haynesville count to 60 by year-end 2010 were all incremental then both cap ex and production guidance should maybe theoretically be much higher. I guess, can you comment on that to the extent that there are shifts in your spending and drilling plan elsewhere?

Aubrey K. McClendon

I’m not sure I followed your question exactly, would you try again?

Brian Singer – Goldman Sachs

It just looks like if we assume some of the well performance that you’ve seen in the Haynesville and assume you go up to 60 rigs by the end of 2010, that your guidance for cap ex and for production growth in 2009 and 2010 would both seem low. So, my question is a) what is your perspective on that and b) are you shifting rigs out of other areas that would then lower the spending and rig count and cap ex in those areas?

Aubrey K. McClendon

Well, we hope your half right. We hope you’re right that we’ve understated production growth. But, in terms of thinking about going forward, remember that is 60 rigs by the end of 2010 so we certainly are unlikely to – I think we talked about being at 30 rigs at the end of 09 so an average rig count in 2010 of course won’t be 60, probably in the 40s. Also, keep in mind that those will function as 40 plus rigs in our production ramp up but in our cost half of those costs will be paid by PXP so we get quite a bit of bang for the buck there and don’t spend so much when we add an incremental rig. Then, finally we are laying down some other rigs as we ramp up in Haynesville. Our overall rig count will not go up that much as we peal some rigs off from other areas in the company that are drilling on HBP units right now.

Marcus C. Rowland

And we’re losing rigs on some of these plays that we’re selling.

Aubrey K. McClendon

That’s right. We’re going to sell the Woodford, that’s five rigs. We may lay off other assets from time-to-time that have rigs on them today. So, a combination of some asset sales as well as moderating our drilling on HBP assets in Oklahoma and Texas will enable us to accommodate increases in rig count in the Fayetteville and in the Haynesville that will not pressure our cap ex the way maybe you would think that it might.

Operator

Our next question comes from Jason Gammel – Macquarie Research Equities (USA).

Jason Gammel – Macquarie Research Equities (USA)

I wanted to talk a little bit more on the specifics at Haynesville if possible. You mentioned the eight stages of frac, I’m assuming that’s going to be about a 4,000 lateral roughly. Would you be able to talk about potential completed well costs? And also, the rough time to drill? And, I know you’re pretty early in the process here.

Steven C. Dixon

We’re on $6.5 to $7 million range on these wells and we feel very confident that we can get that down to $6.5. We’re at 45 to 50 days drilling the wells and that should go down also with experience and time.

Aubrey K. McClendon

Although, going from six to eight stages has increased our completion cost a little bit.

Steven C. Dixon

Yeah, so we hope to be at $6.5 by now and we’re really closer to $7.

Jason Gammel – Macquarie Research Equities (USA)

Then just in terms of the acreage that was stated in the press release, it mentions 450,000 net acres. Are you guys still looking to increase that position? And if so, is there anything left, at least organically or is any increment going to have to come from the acquisition market?

Aubrey K. McClendon

No actually, the big deals, they’re pretty much all spoken for. I think it’s well know that [Mexico] is looking for a joint venture partner but the kind of big land rush that occurred in May and June by people who had 2,000 to 30,000 acres, if you were inclined to sell, that’s largely, largely happened and now we’re getting down to rooting out the five acres, 10 acres, 40, 80, maybe 160 acres and that’s where I think we have some real advantages because we have, I think 800 brokers, I can’t remember the exact number but I think we have close to 800 land brokers in the Haynesville play in East Texas and in Louisiana so we have a proprietary information base about land ownership that enables us to go out and find these smaller tracks and we should be able to find them without a great deal of competition. Obviously, it’s not hard to find 10,000 acres when the owner of it is running a process but it’s a lot more difficult to get competition if you’re a land owner for 10 acres and that’s where I think going forward we’ll get a lot of really attractive leases bought well below the kind of headline numbers of the last 90 days or so.

Jason Gammel – Macquarie Research Equities (USA)

And it does seem that leasing is sort of a core competency that Chesapeake has that others can’t duplicate which is why the divestiture process is interesting and maybe you can contrast 2.5 TCF reserve adds is pretty impressive any anyone’s standards but it’s relatively small compared to the 48 TCF that you have in terms of your risk potential. Can you maybe talk to us about how you see monetization of the 48 TCF of potential between the divestiture process and organic drill bit activity just in terms of maybe rough percentages?

Aubrey K. McClendon

Oh, I don’t know how to do that really. On a percentage basis that at the start of this year we had the goal of increasing our proved reserves by 2 TCF this year and next year and I think we’re probably going to do 2.5 this year and at least 2.5 next year, maybe 3. One thing to look for is that if the [SEC] changes their definition of what a proved reserve is and they’re going through public comments right now on a proposal to do exactly that, some part of that 48 TCF is going to become part of our proved reserves and I think that is something investors probably are not thinking about which is something I’ve said for years which is you’ve never had a cheaper entry point in to these companies because we have the equivalent of proved reserves off the books and yet you don’t have to pay for them really. And, going forward, if the [SEC] recognizes the nature of these shale plays geologically and recognizes the technological ability to access them I think you’ll see a big increase in proved reserves as unproved slide over.

The final thing on monetization, there’s a certain amount of that 48 TCF that needs to kind of have a cash price put on it and have it move forward and we’re in the process of doing that in the Fayetteville and we’ll do it in the Marcellus and probably do it in the West Texas shales as well.

Operator

Our next question comes from Monroe Helm – CM Energy Partners.

Monroe Helm – CM Energy Partners

When you were talking about the impediments to getting to more than 1.5 BCF per day in the Haynesville, you didn’t say anything about whether or not frac capacity could be an issue. Can you talk about that? And, how you’re positioned for additional frac capacity given you’re going to these bigger fracs?

Aubrey K. McClendon

Monroe, I’m glad you asked. We happen to be an outside shareholders in a company called Frac Tech which is [inaudible] the third largest pressure pumper, the third or second.

Steven C. Dixon

I think our goal and the inevitable outcome of what we’re building out there will have us be, by the end of 09, the number one company [inaudible].

Aubrey K. McClendon

Stop for just a second, this is a company that didn’t exist, it started in 2002.

Steven C. Dixon

Dan and his brother Ferris Wilks have done an excellent job and we were fortunate enough to invest to help that along a couple of years ago.

Aubrey K. McClendon

Seven years ago from nothing to the largest pressure pumper in America is pretty remarkable. They were just up visiting with us and they’re building out tremendous capacity. We have several new sand lines and so we’ll have adequate capacity. And again, we’re encouraging Frac Tech and I’m sure others will join in just like they did in the Barnett. Four years ago Monroe, there would have been three players max probably planning tech services in the Barnett, Steve today there are nine or 10 of all sizes.

Steven C. Dixon

And there the service industry is very, very interested in the Haynesville, they’re very excited about it.

Aubrey K. McClendon

You can concentrate assets in a close area that already have operations in East Texas or in Shreveport. So, you couldn’t have asked for a play to get developed in a better area or an easier area from an infrastructure build out perspective. So, I don’t think that will be one of the constraints Monroe which I think is at the core of your questions. Jeff just slipped me a note, as I complimented Frac Tech on what they’ve done in eight years, he reminds me that we went from pretty much nothing to the number one gas producer in America in eight years.

Monroe Helm – CM Energy Partners

Can you talk about what Frac Tech’s horsepower capacity is today and what you think it will be over the next 12 or 18 months?

Aubrey K. McClendon

I don’t have those numbers handy. I think they’re published in the industry.

Marcus C. Rowland

I think they were heading towards the [inaudible].

Steven C. Dixon

That’s the goal in 2009. I’m going to say it’s 575,000 a day, it may be 625,000 and I’m one quarter behind. I go down and talk to them on a quarterly basis as a representative of Chesapeake on their board.

Monroe Helm – CM Energy Partners

One other question, as someone who has been addicted to Twinkies his whole life, I’m always looking for ways to buy more Twinkies and would like to convert my car from gasoline to natural gas. What would be the cost of that be and should we expect to see Chesapeake natural gas stations here in North Texas that you can advertise with?

Aubrey K. McClendon

Well, the inconvenient truth of Chesapeake natural gas stations is that we would lose our status as an independent producer if we were to begin retail sales of natural gas and that independent producer status has helped us from a taxation perspective so we’re going to have to leave that to people like Boone Pickens Clean Energy Company and others. Really, at the end of the day, every station operator will want natural gas and most of them have natural gas already piped to their station right now. Monroe, I did mention beer also and I had heard that beer and Twinkies was a good combination.

Monroe Helm – CM Energy Partners

What would be the cost to convert a car over do you think?

Aubrey K. McClendon

Right now that cost is basically on a non-assembly line scale is $12 to $15,000 to convert let’s say a pickup or an SUV. You get, if I’m not mistake $5,000 federal tax credit and then $2,500 in Oklahoma and I think you get it in other states as well. Then of course, you save $2 a gallon. The key though is to get them to come off the assembly line. A third of the cars in Argentina are C&G, a quarter of the cars in Italy are C&G, GM makes something like 10 models of cars around the world that come off factory lines running on C&G. Until three years ago they made pickups in America, so did Ford with C&G. So, this is not tough stuff at the end of the day. There just has to be some refueling infrastructure. We think at the end of the day the best way to address that is going to be through fleets, through urban stations and then to string some along the Interstate at truck stops because I think the trucking industry will be all over this at the end of the day.

Very rarely in our lives does a solution to a problem come along where it’s half the price and two thirds cleaner and when you use it, it creates American jobs rather than just shift American national wealth overseas. So, this is something that is going to pick up speed, we’re just trying to kind of push it along a little bit.

Operator

Our next question comes from [Paul Bennett – Boulevard Trust].

[Paul Bennett – Boulevard Trust]

I think my question was whether you have any corporate initiatives with natural gas fueling stations? And, I think you partially answered that question about five times over so I’ll just add this, are you going to do anything locally in Oklahoma with Boone Pickens’ operation?

Aubrey K. McClendon

[Inaudible] I mean, we support Boone and all of its initiatives. Our plan is just a little less grandiose, a little more focused, a lot cheaper and I think can happen faster. Boone is focused on electricity, I’m focused on the transportation fuel and I do not think you have to back natural gas out of the power stack to be able fuel cars and trucks. I think we can do that with domestic supply growth. That’s probably about the only nuance that is different in what we are trying to accomplish versus what he is trying to do.

Operator

Our next question comes from [Subash Tandrum – Company Inaudible].

[Subash Tandrum – Company Inaudible]

Just kind of a philosophical question I guess, is the sustainability of paying $10,000 to $50,000 for undeveloped acreage I guess in large swats, not like a few hundred acres there, I see how big companies like yourselves can do it but do you think industry can sustain that kind of model in an environment where maybe external financing won’t be there? Where the bottom line is if you sort of just held your powder you might see these overall trends begin to decline?

Aubrey K. McClendon

Well [Subash] a couple of different thoughts there. First, the amounts of money involved in grabbing acreage in places like the Barnett or Haynesville are absolutely staggering. To go out and buy 10,000 acres in the Haynesville today, if you could do it, would cost you over $300,000 million. They’re just not many companies at the end of the day that can write that check and then also have the technical resources to go out and drill the wells. Having said that, to spend $30,000 an acre at [inaudible] for acreage from us is kind of chump change when it comes down to finding costs. If you think about that $30,000 an acre on 80 acres is $2.4 million and you’re finding 6.5 BCF in that 80 acres and after royalties that number gets down to be about $0.50 an MCF. So, is it rational for the industry to pay $0.50 for the right to go develop gas reserves at $1.33 in the ground, absolutely so there’s this big gap between the value proposition for acreage and then at the other end of the spectrum there is just the enormity of the capsule itself. I think what it does is it really bifurcates further the industry. If you’re in the shale plays and you’re in early you are a long term winner. If you’re not in these shale plays, I think you’ve got some challenges in the out years because your finding costs are going to be a whole lot different than our finding costs going forward.

[Subash Tandrum – Company Inaudible]

One follow up, these new rig deliveries and new rig construction, any comment on perhaps the pace of delivery? Are they on time, are they taking longer? And, sort of what requirements you might have for additional new builds in 09?

Aubrey K. McClendon

Well, we’ve got 20 some odd rigs coming on. We have our own rig up facility, we’re the fifth or sixth largest contractor in America so we know how to get rigs built and get them rigged up and get it all done on time so that’s not really an issue for us. Going forward, we don’t have deliveries planned for 2010. I think all of our rigs we’ve got are coming on in 08 and 09. We’ll evaluate 2010 when the time comes but right now we’re pretty much squared away.

I think that’s it. I appreciate everybody’s attention today and hit Jeff with any follow up questions if you have any. Thank you.

Operator

Once again ladies and gentlemen this will conclude today’s conference. We thank you for your participation. You may now disconnect.

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Source: Chesapeake Energy Corp. Q2 2008 Earnings Call Transcript
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