Chesapeake Energy Corp (CHK) 2008 Q2 法說會逐字稿

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, please go ahead sir.

Good morning and 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 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 October 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?

Thanks Jeff, and 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 petrophysical analysis of the play predicted that the horizontal core and tier one 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 Bcfe for every 100 acres to about 2.65 Bcfe per every 55 acres.

This increase has been caused by steady improvement in the technology to drill, complete and produce horizontal Barnett wells.

We now believe the Barnett will ultimately produce at least 60 TCF of natural gas and the majority of that will come from Johnson and Tarrant counties.

But before before the 60 TCF number makes you want to throw in the towel on current or out year natural gas prices, please remember it will take more than 50 years to produce all that gas.

Please also remember that the decline rate from the first month of Barnett well until its twelfth month is about 65% and to its twenty-fourth month, it's almost 80%.

So 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 Bcf 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 witnessed from the Barnett over the past year.

Back to the Haynesville.

Two years ago, our geoscientists and petrophysicists began studying the Haynesville shale on the heels of our Barnett and Fayetteville successes and concluded 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.

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 play as 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 9/64ths choke is making about 700 Mcfe per day.

It was a five stage frac job in a short lateral.

For ten months, we have kept it on 9/64ths choke so we can obtain more consistent rate and pressure information on this constant choke over time.

Four wells are short lateral reentries and one of which is also only making 700 MCF per day because of a mechanical problem with a fish down hole.

The other three have been on line an average of four months and are producing around 3 million per day each through 14/64ths or 16/64ths chokes, again for the same reason as the first well I described.

The next four wells have been on line 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 24/64ths 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 used -- 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 days, we are already -- sorry, 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 24/64ths choke 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 pressured 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 wellhead gas price exceeded our Barnett wellhead gas price by about $1.50 per Mcfe.

This month with gas prices about $4 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 one Haynesville shale contains an average of 180 Bcf of 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 we will recover about 52 Bcf per square mile to 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.

How much gas is there really in the Haynesville play?

That math is actually pretty easy as well.

With 3 million acres in the blob, that means roughly 4,700 square miles.

At 52 Bcf of recoverable gas per square mile, that equals about 245 TCF of recoverable gas in the Haynesville, exactly consistent with what we have predicted from the beginning.

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.

Those of you who have followed Chesapeake will recall how conservatively we have historically been in estimating the initial potential of the Barnett, Fayeteville, 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.

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, its 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 about is 11,500 feet deep on average and takes rigs that must have at least 1,000 horsepower engine, 600,000 pound weighted mast, 1,600 horsepower trip-plex pumps and top drives.

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 transportation 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 flowing growth from the Barnett over the next few years and very little incremental growth possible for the next two to three years from the Rockies and ongoing declines in the Gulf of Mexico and in Canada plus increasing demands 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 to $11 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 Independence Hub.

Taking those two one time events away, we believe you are left with organic gains of somewhere around 2 to 2.5 Bcf per day or so.

We believe these gains are likely to be about the same to slightly less than in 2009 and 2010 and we believe demand can grow quickly enough, particularly in the price range that I have 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 ten 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 begin 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 awhile in the nine to 11 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 volume metric production payments, or VPPs.

They give us the ability to monetize some of the low decline mature gas assets that are valued in the stock market of Chesapeake at less than $3 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 volume sold were 395 Bcfe.

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 per Mcfe.

So if we can find it for $2 and the stock market only values it at $3 and we can sell it for nearly $6 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 these 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 per Mcfe VPP proceeds, you will see that these VPPs will reduce our DD&A rate going forward, 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 our 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 to this enormous asset.

In time, we believe this acreage will be worth at least $50,000 per net acre to us or $37 per share.

I might note that last week, there was an announcement of a transaction in the Barnett that valued nonproducing, 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.

Similarly to the VPPs, as sale proceeds go into our full cost pool as credits well in excess of our costs incurred to date, our future DD&A rate 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 growth 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 Bcfe per well compared to our overall average of 2.65 Bcfe.

In the Fayetteville, we are drilling our best wells ever due to improvements and where we position our laterals within the Fayetteville, longer lateral length, better completion techniques and the arrival of new 3D information that helps us avoid geological pitfalls such as faults.

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 550,000 net acres of leasehold there.

We plan to increase our rig count gradually to about 25 rigs in 2009, then keep it there for the foreseeable future.

Finally, I mentioned on our PXP conference call a month ago that we 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 we believe these wells have a combined EUR of about 11 Bcfe.

Last week, we read Range's announcement of their activity in southwestern Pennsylvania and their view that horizontal Marcellus EUR of 3.5 Bcfe to 4 Bcfe 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 estimates.

That makes the play very, very attractive.

However, again I would caution gas market observers to not expect the 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 country's gas production until at least the 2013, 2015 timeframe.

That's why we are pleased that so much of our 1.6 million net acres is 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 be as large as we previously stated?

Why should gas prices stay in 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 our business strategy shift of advancing present value creation through VPPs and partnerships is working so well, and how will it will cause our costs to go down as the industries are going up?

Thanks for your patience today as you listen to these longer than usual comments.

I Hope you have found them useful.

I'll now turn the call over to Marc 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 second quarter, our open hedging positions on future natural gas and oil production generated an unrealized pretax 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 25, our mark-to-market position moved in our favor by a staggering move of $4.6 billion in just over three weeks.

We have previously discussed the current accounting requirements for derivative securities can substantially distort the reporting of current period financial results for companies such as ourselves in 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 that 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 highlights the need and substantial value of the hedging arrangements we have 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 counter parties in our bank groups that have collateral pledged from our revolving credit facility which we call pari passu 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 a 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 on to 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 31 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 VPP's for much more than we have invested in them, which reduces our full cost pool by much more than reserves are reduced per unit..

Going forward, the Haynesville 20% shale to our partner PXP and the 100% Arcoma Woodford sale to BP will further accelerate this downward trend.

In fact, had those third quarter transactions been effective at June 30, our DDA 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 increasing a decreasing -- while also enjoying a decreasing book cost structure that many other E&P 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 have 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 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 30 at $51.5 billion.

Obviously, that was at very high prices.

I had those reserves revalued 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 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 a la PXP.

That puts a residual value of 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 then return to a net asset value of about $60 per share.

Now that's before the Fayetteville, the Marcellus, the Barnett nonproved, west Texas shales and the substantial number of other plays that we 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 are 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 have ever seen.

Finally, I would 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 to date that to date this year we have increased our proved reserves by 1.3 trillion cubic feet equivalent and by the end of the year, we will likely have increased our proved 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.

Thank you.

The question and answer session will be conducted electronically.

(OPERATOR INSTRUCTIONS) We will pause for a moment to assemble our roster.

We will take our first question with David Tameron with Wachovia, please go ahead sir.

Good morning, thanks for all the detail on the Haynesville, Aubrey.

A question for you, just looking the your level of activity, 156 rigs you have running.

We 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, over the next -- if you look out over the next six months, next year.

We will let Steve Dixon handle that.

It is very tight right now.

We are scrambling to stay ahead of those 156 rigs, but getting it done.

We have long-term arrangements and have been a major pipe buyer for years, so we think we will get er done, but prices have gone up significantly in the last few months.

One of our board members is Pete Miller from National Oil Well, we talked to him yesterday, and of course through his acquisition of Grant, has some pretty good insights.

He thinks it's mainly maybe topping out perhaps a bit, so we will see.

But again, we have been the number one consumer of oil field tubulars for years and years, so we will get our share of tubulars, they will be more expensive, but we will not be running out of tubulars.

Okay.

Then one more question, I'll let other people jump on.

If I'm looking big picture US domestic market, you mentioned -- you back out REX and Independent Hub, 2% to 3% organic growth, what level of drilling, or what gas price do you think -- where's the marginal cost supply in the US today to continue on 2% to 3% base?

That's a discussion question people have been trying to answer for years and years, of course it changes.

But you use the word percent, I think you meant Bcf per year.

Yes, I'm sorry.

-- everybody's on the same page, 2 to 2.5 Bcf per year of kind of organic growth.

My thought is that the market is bifurcating.

That shale plays and tight sand plays are ones that can be profitable at probably an $8 NYMEX price.

But what I think we see in many plays across the country that are what you would call conventional, those plays are at an increasingly large cost disadvantage to the shale plays.

There are -- you think about our plays in the Barnett, Fayetteville, Haynesville, et cetera, we're able to drive costs down over time as we drill dozens, hundreds, 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 kind of yourself as -- through these smaller targets.

So I think if gas prices were to stay below $9 Henry Hub for some period of time I think that the shale plays probably continue to move forward, but I think you will 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 price is.

Remember that basis differentials in the mid-continent in the month of July are about $1.30 to $1.40 per Mcf, when you start talking about compression and things like that $8 gas these days means probably something close to $6 at the wellhead.

So there's kind of been a quiet or silent creep of about a dollar 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 wellhead is kind of less and less related to what you read in the headlines at Henry Hub.

So I -- we think gas prices will stay in this $9 to $11 range.

There will be times, like in July when -- there will 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 nine you would see a drop off in drilling activity, particularly among the conventional drilling, 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 analyst had come up with production in 2010 was going to be up by something like 8 Bcf to 10 Bcf a day and gas prices were going to be $6.25.

That's that kind of analysis, I think, can only come at the dangerous intersection of Excel and PowerPoint.

It can't happen in

Alright, thanks, I appreciate it.

We will take our next question with David Heikkinen with Tudor, Pickering and Holt, please go ahead.

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

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 had a lot of people express concerns to us and when you consider who all's involved in that play, the well results to date, it's just not very smart to start dogging that play, because the well results to date are so exceptional and are only going to get better over time.

So 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, and that's after our monetization, 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 will stay 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.

Hi, David.

I do have a couple 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 VPP's or outright sales of our mature properties, will just continue to highlight the vast different 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.

And 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.

One final thought David, also this decline in our cost structure is something that -- which is going to run completely counter to what's going to be happening at most of our peer companies.

I think.

We have caught -- our stock is, I think, the second best performer in the sector over the last five and 10 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 overinvestment and you felt like we've added too much to our cost pool and our DD&A rate is 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 wade into acreage markets and pay many, many multiples of what we have had to pay going forward.

So thinking about land people, science and capital, Marc, just your comments I guess are highlighting that one of the ways you think you will fill that capital gap is -- and you have highlighted it in your IRs through asset sales and 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.

Sure we can.

In the last couple of months, we have really kind of 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.

And so 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 a partner into and to start to attack it.

It's just so vast, we have over 1 million acres in the area that -- and there's so many kind of different play types, whether you drill vertical Barnett and Woodford wells or drill a vertical -- or drill a horizontal well and complete the Woodford vertically and the Barnett horizontally, and there's all kinds of formations kind of up and down the whole.

We think that's going to be attractive to some partners.

So it's taken 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 bring a big boy in to help us take -- advance the ball forward from here.

Of course, that's not a play that, anybody's 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, if successful, have resource play potential as well.

Okay.

And then oil shales anything that you can update there.

I think in March was the first time that we began to talk about that 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 geoscientists 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 WEHLU, West Edmond Hunton Lime Unit's field area northwest Oklahoma City, and that's working quite well.

Petrohawk has a significant interest there as well, I think they have released some positive information about it.

That's an old abandoned oil field that we're 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 oil right now in the first of these plays and we will have the other three tested by the end of the year.

Okay.

So 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.

I'll let other people ask, thanks guys.

Dave, thank you.

We will take our next we with Jeff Robertson with Lehman Brothers, please go ahead.

Thanks.

Aubrey, you made comments about pressure in Haynesville.

Can you talk a little bit about the operating costs in that play.

Then secondly, can you talk a little bit about where you think that ranks in your overall asset mix in terms of returns.

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 plays, 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.

So -- and finding costs that are going to be, again, without the carry, somewhere between $1.33 and $1.50.

With the Plains 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 an Mcfe.

So there won't be a play in the country of course.

I'll let Steve talk to you about operating costs.

That's really the big deal, is that there's no compression.

So these other shale plays, a lot of your lifting costs are compression costs and we don't have that, these shale plays don't make much water, some flow back initially and then that dries up.

So plays should have very low lifting costs.

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

No, it does not.

It's kind of right on the edge.

There is some CO2, but we're able to sell that.

We will just keep an eye on that.

We haven't crossed over yet.

Okay.

Thank you.

We will take our next question with Michael Hall with Stifel Nicholas, please go ahead.

Thanks, congratulations on another great quarter.

Thank you Michael.

You bet.

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

Michael, I'm not going to get too granular about that, because there is -- we do have competitors for pipe space out there.

I will say that if you are an operator of long distance pipeline in America or want to build a long distance pipeline in America, you have 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.

So in terms of -- so we have tied up all the take away that we can, we think it will be sufficient for us during the timeframe that I talked about, and at the end of that timeframe, we believe we will have new transmission capacity out of the area.

In terms of how big the play can be, and you've heard I guess you 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.

The reason for that, of course, is that you don't build infrastructure for the very peak of production, you built 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 do.

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, 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.

So I kind of see the Haynesville as this enormous big gas resource and we can -- it's 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 will just see normal year to year supply increases out of the Haynesville that will meet demand, but will not overwhelm demand.

Great, 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 kind of high prices we saw toward the end of June, early July, maybe if there's any signs in your eyes of some marginal demand instruction 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?

Yes, sure.

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 a gas price 85% higher than last year, you might see a couple Bcf of demand go away, and I think that's what we saw happen.

I think yesterday or 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 thinks 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 a first of the 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 regard to CNG, 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 American 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, and particularly with the Haynesville included in the analysis.

And what they concluded and we announced on Wednesday was that there's plenty of gas in this country to begin thinking about energy policy with a clean sheet of paper.

The math is pretty compelling.

The US consumes about the equivalent of 10 million barrels a day 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 into our transportation network.

It's our analysis that about every 1% of our car and light truck fleet that gets converted over would consume about 250 Bcf per year or roughly about -- well sorry, about 225 Bcf a year, sorry, which would make it about .8% increase in supply needed.

So the Emanuel Boren bill which came out a couple weeks ago, has the goal of getting 10% of the American transportation fleet over from gasoline and diesel to CNG.

I think that's reasonable, I'd certainly like it to go faster and that would only require an increase of supply from our industry of around 7.5% to 8%.

So we think that's very achievable and we will provide consumers of gasoline a real price break as CNG is about half price, at the same time producers, a real nice alternative market for our natural gas production.

Very good, thanks, appreciate the clarity, congratulations again.

Thank you.

We will take our next question with Tom Gardner with Simmons and Company, please go ahead.

Aubrey assuming we're in the fourth quarter of the US land grab, what are your thoughts on the Canadian and European resource plays.

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 it gas, it's a tough place to make money.

So I'm glad our shales are down closer to markets.

Internationally, what I'm excited about for kind of the rest of my life, is that I think that 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 and we can start to move the transportation fleet around the world to CNG.

Right now, they 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 as 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 will see the use of gas rise, I think, to make up for inevitable shortfalls in the production of oil going forward.

Interesting thought.

You did so well, I'll give you another one here.

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

Oh, gosh, Tom we have 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 last, if you think about 2006, it occurred in the October contract, if you think about last year, it occurred in the September contract, this year it occurred in the August contract and I think there's 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 in our experience from '07, '06 and going back to 2001, shows you that the industry doesn't stay below break even very long.

Whether or not these 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 will see 40% first year declines kick in and the market correct.

One thing 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, floor is higher than it was before, as it should be, because of higher coal prices and higher industry refining 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.

Thank you Aubrey, I appreciate your thoughts.

I'll let someone else hop on here.

Thanks Tom.

We will take our next question with Joe Allman with J.P.

Morgan, please go ahead.

Yes, good morning everybody.

Hello big Joe, how are you?

Doing good, Aubrey, thanks.

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 Bcf, 6.5 Bcf per day.

I think you said 2012, just to clarify that.

And then when you'll peak, and what you think your volumes will be at that point.

Joe, we think -- I think I said 6 Bcf to 6.5 Bcf a day, depending on some things and whether it's 2012, 2013, 2011, kind of hard to know.

Our production is what, 775 million a day right now, and I think Steve, we have it modeled up to about 2 Bcf a day.

I think we hit that in 2012.

So our market share will actually increase in the Barnett over time, 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 focus producer, you'll probably get a production ceiling well before we do.

Also, with all the urban drilling challenges and logistical nightmares we go through every day, there's just limits to how rapidly things can ramp up and so you will -- 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 to three years, I think is making a mistake.

We think that growth and supply will go in half next few years.

So our share will get bigger of a pie that probably expands to 6.5 to -- 6 Bcf to 6.5 Bcf a day by 2012 or so.

Okay, that's helpful.

Then 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 timetable, what are the key triggers for that to happen in your view?

In some ways it's already happening.

Close to 20% of American bus fleets already run on natural gas.

Many municipal fleets are beginning, cars and trucks are beginning to -- port of Los Angeles, Long Beach goes a hundred percent natural gas by the end of this year, Kenworth and Peterbilt 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 years you've been hit by fuel surcharges, I think you're going to be asking your trucking company why they haven't built -- 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 from the shipping sector here to -- for the truck fleet to move to natural gas very quickly.

Joe, the market is recognizing this, you have a fuel 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 in working with congressional leaders is to get the market moving more quickly.

And the reason for the urgency is I think that we could wake up six months from now, a year from now, two years from now and not be grappling with $4 gasoline prices, but maybe $6 or $8 if something blows up in the Middle East.

So 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.

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.

And everybody will want that.

So the Emanuel Boren bill will provide financial incentives for service station owners to install CNG pumps, for car manufacturers to make CNG cars and for consumers to buy CNG 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 2 or 3, but I think at least 1% per year is certainly a reasonable possibility.

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

I don't think it's necessary, Joe and not the best place for us to spend money.

I think that will happen away from us.

I mean just imagine as you drive down the street, you pass an intersection with three gas stations on it.

The one guy who gets his CNG pump in faster and advertises $2 gasoline, he will sell a lot more beer and a lot more cigarettes and a lot more Twinkies, so I think everybody's going to be pretty motivated to be the first on the block to get their CNG pump.

Now we will look at investing in LNG export facilities and we are studying that right now.

We have got to figure out a way to get some linkage to the world markets and we are dedicated to trying to find a way to achieve that linkage.

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

Well I can't talk too much about it other than tell you we read the papers and see that gas around the world goes for twice what it goes for here.

And so, my view is we make a great widget here and that widget is valued at X here and 2 X around the world, and so I'm trying to figure out a way -- we're trying to figure out a way to get it on a boat and get it to some overseas markets as well.

The additional of a potential linkeage to world prices as well as toward natural gas into 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.

Got you.

And Mark, what's the extent that you're seeing in terms of rising service costs?

Well, Joe, they have definitely turned.

I would say, 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, they've got a little bit of transportation they're trying to pass along, and I think that those are in the zero to 5% range on a per annum basis, but obviously, Steve mentioned steel prices which have easily doubled, I think --

They're doubled.

And you heard our comments earlier probably that maybe they're at a peak right now.

Drilling rig costs, Steve, have been going up for the new rigs that are new builds, I know.

Yes, I mean, they're trying to create some pressure.

I don't know that overall inflation will be that high.

I mean, besides steel and diesel.

But we want to remind you that Chesapeake's unit costs will be going down.

Right.

It's an ideal time to own a fleet of -- what, Steve, we have 83 operating today and 20 something, 25, 27 on the way.

So I think it makes our plan to operationally have the rigs available to move them around and to have them be custom made for the play types that we've put them in, smart, but also just is a terrific hedge against the demand in the business to put more rigs out that cost a lot more today and will -- some people will pay a lot more for those.

Plus you can finance them, basically, a hundred percent and get them paid for in three plus years.

Exactly.

We have been using sale lease backs to convey tax benefits that we have not previously been able to use.

So those have come at implied capital costs of anywhere from 4.5% to 5% on basically eight year financing plans.

Got you.

That's all very helpful, thank you.

Okay, Joe, thank you.

We will take our next question with David Snow with Energy Equities, please go ahead.

Yes, terrific call.

Can you give us a profile of -- as you would see it for the Fayetteville, you gave it for the Barnett.

When you say profile, David, I'm sorry.

What --

Buildup overall and for years over time.

You mean in terms of ceiling or a peak.

Yes, the rate of growth from here to there in the peak years.

David, we don't have that.

So much of that is dependent on Southwestern's rate of rig increase.

I think we did say today that we're at 17 rigs today in the Fayetteville going to 25, and that's probably a level at which we will stay indefinitely.

So, 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 the Rockies are bottle necked again for the next couple years, you really only have to solve for the Barnett and the Haynesville.

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 need to even bother with, and that would be the Fayetteville and the Woodford and we think those increases a year are 200 million, 300 million, 400 million a day, certainly not market movers.

Finally, the play that people have expressed concern would be the Marcellus and it's not going to be anything significant for probably another five years or so.

Are those 200 to 300 to 400 a day each, or both Woodford and Fayetteville.

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

Yes.

This is -- I'm remiss, I'm a little hesitant to throw in a negative on this beautiful call, but is there any chance that your rate of equity increase will slowdown as you monetize in the sale of assets.

Yes, 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 monetization 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 all of our asset monetizations with the exception, I think, of --

One VPP.

-- one VPP and one whispered 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 and we had to do that twice this year, and I think it's the right thing to do.

But going forward, we are moving into 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 anything, has any kind of capital demand, anything remotely close to what we had to go through with the Haynesville this year.

So we would expect to see a slow down in the rate of equity increase and a per share acceleration ,I would imagine, in the volume of Bcf's per share.

That is the goal.

Okay.

Thank you.

Thank you David.

We will take our next question with Brian Singer with Goldman Sachs, please go ahead.

Thank you good morning.

Hey, Brian.

Listening to your comments today and your testimony earlier this week in Washington it seems 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 as 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?

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, 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 have to convert those resources of gas into 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 $6 or $7 an Mcf, we think that's 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's pretty fair value.

If you think about transportation fuels, remember that from , an mmbtu of natural gas, you can get 8 gallons of transportation fuel.

And so, $4 gasoline at the service station is $32 per mmbtu, 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.

And we don't have -- we run 24/7 manufacturing business here, and you can't start and stop the factories.

So that's why we hedge, and we like to hedge for a rolling 24 month period.

There are times on June 30 where you look pretty stupid and you're down billions and billions of dollars, and then you wake up three weeks later, and you have made $5 billion plus on your hedges in three weeks and you feel a little bit better about yourself.

So going forward, our view is that when we can hedge at the mid-point of that range from 9 to 11 or higher, we're going to do that, take risk off the table and insure ourselves that going forward, we can continue to run our factory 24/7.

So I think that's how I would ask you to look at our program going forward, given the really extreme volatility that we have seen in the market

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 your other -- some of the other players in the Haynesville to move their rig count in the event that that does not materialize as quickly, since it seems like you maybe more sticky in shifting your capital program.

Well, a couple things to think about.

First of all, somewhere around 40% of the play is probably HBP held by production, and I think this my spiel I talked about maybe some of those leases have been HBP for 50 years, it's actually, as I think more about it, closer to probably 80 years from the day of the east Texas boom and then discovery of Carthage, I think in the 40s.

And so, if you are a holder of acreage in east 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.

You're going to pick your spots.

So don't think about this as the Barnett where everything is wild and wooly and you got to get wells drilled in two years or you lose the acreage.

You start off with a big advantage.

The second thing is 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, 250 acres in size and many times, they're smaller than that, because of lease restrictions.

And so when we go out and drill our first well in a 640 acre unit, we have guaranteed ourselves then that lease is HBP and we can warehouse seven other locations or seven-eighths of our inventory.

So, 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.

That's helpful.

When we look at your guidance for CapEx in production growth in '09 and '10, it would seem that if entirety of the ramp up of the Haynesville recount to 60 by year end 2010 were all incremental, then both CapEx and production guidance should maybe theoretically be much higher.

Can you comment on that in the extent to which there are shifts in your spending and drilling plans elsewhere?

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

It just looks like if we assume some of the well performance seen in Haynesville, I assume you go up to 60 rigs by the end of 2010, that your guidance for CapEx 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 in CapEx in those areas.

Well, we hope you're half right.

We hope you're right that we have been -- that we have understated production growth.

But in terms of thinking about going forward, remember that of 60 rigs is by the end of 2010, so we certainly are unlikely to -- I think we talked about being at 30 rigs by 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 costs, 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 the Haynesville.

Our overall rig count will not go up that much as we peel some rigs off from other areas in the company that are drilling on HBP units right now.

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

That's right.

Going to sell the Woodford, that's five rigs, we may layoff 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 CapEx the way maybe you think that it might.

Thank you.

Okay.

Anything else?

Thank you very much.

Okay.

Thanks Brian.

We will take our next question with Jason Gammel with Macquarie, please go ahead.

Thank you.

I was wondering if you could talk a little bit more about the specifics on the Haynesville, if it's possible.

You mentioned the eight stages of frac, I'm assuming that's going to be about 4,000 foot 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.

I'll let Steve take on that for us.

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

Although going from 6 to 8 stages has increased our completion costs a little bit.

So we hoped to be at 6.5 by now, and we're really closer to 7

Okay thanks.

And then, just in terms of the acreage that was stated in the press releases, it still mentions 450,000 acres.

Are you guys still looking to increase that position and if so, is there anything left to actually lease organically or is any increment going to have to come from the acquisition market?

No, actually, the big deals are pretty much all spoken for.

I think it's well known that Exco is looking for 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 we have some real advantages, because we have, I think 800 brokers, I don't remember the exact number, 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 tracts, and 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 landowner for your 10 acres and that's where I think going forward we will get a lot of really attractive leases bought well below the kind of headline numbers of the last 90 days or so.

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 I think is interesting.

Maybe you can contrast -- 2.5 TCF reserve adds is pretty impressive by anyone's standards, but is 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/or organic drill bit drilling -- drill bit activity.

Is it just in terms of maybe rough percentages?

Oh, I don't know how to do that, really, on a percentage basis.

I would just tell you 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 going to do probably 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 reserved and I think that's 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 into 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, then I think you will see a big increase in proved reserves as unproved slide over.

Final thing on monetizations, there's a certain amount of that 48 TCFE 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 Fayetteville and we will do it in the Marcellus and probably do it in the west Texas shales as well.

Okay, thanks, I appreciate the comments.

Okay, thank you.

We will take our next question with Monroe Helm with CM Energy Partners, please go ahead.

Thanks a lot for a very interesting call.

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.

Monroe I'm glad you asked.

We happen to be an outside shareholder in a company called Fractec which is marked today as the third largest pressure pumper.

Third or second.

Our goal -- or I think the inevitable outcome what we're building out there will have us be, by the end of '09 the number one company with American Pressure Pumping.

Stop for just a second.

This is a company that didn't exist -

started in 2002, and Dan and his brother Faris Wilkes have done an excellent job, and we were fortunate enough to invest to help that along a couple of years ago.

Seven years ago from nothing to the largest pressure pumper in America is pretty remarkable.

And they were just out visiting with us and they're building out tremendous capacity.

We have several new sand lines and so we will have adequate capacity, and again, are encouraging Fractec 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 providing private services on the Barnett, Steve, today there are 10?

Yes.

Nine or ten of all sizes.

And they're -- the service industry is very, very interested in the Haynesville.

They're very excited about it.

You can concentrate assets in a close area, they already have operations in east Texas or in Shreveport.

You couldn't have asked for a play to get developed in a better area or easier area from an infrastructure buildout perspective.

So I don't think that will be one of the constraints, Monroe which I think is at the core of your question.

Right.

As -- just Jeff slipped me a note, as I complimented Fractec on what they have 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, so --

So it's not that big a deal.

(laughter)

Right.

Can you talk about what tech's horsepower capacity is today, and what you think it will be over the next 12 or 18 months?

I don't have those numbers handy.

I think that they're published in the industry.

I think they were headed towards $1 million --

That's the goal in 2009.

I'm going to say it's 575,000 today, it may be 625,000 and I'm one quarter behind.

I go down and talk to him on a quarterly basis as a representative of Chesapeake on their board.

Okay.

One other question.

As someone who's 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 the cost of that be and should we expect to see Chesapeake Natural Gas stations here in north Texas that you can advertise with?

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 is helpful to us from a taxation perspective.

So we're going to leave that to people like Boone Pickens' Clean Energy Company and I think other -- 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, so --

I'm on a diet.

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

Right now, that cost is basically, on a non-assembly line scale is 12,000 to15,000 to convert, let's say, a pickup or a SUV.

You get, if I'm not mistaken, $5,000 federal tax credit and then 2,500 in Oklahoma.

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.

Right.

A third of the cars in Argentina are an CNG, a quarter of the cars in Italy are CNG, GM makes something like 10 models of cars around the world that come off factory lines running on CNG.

Until three years ago, they made pickups in America, so did Ford with CNG, so this is not tough stuff at the end of the day.

There has to be some refueling infrastructures.

So we think at the end of the day, the best way to approach that, address that is going to be through fleets, going to be through urban stations and then to string some along the interstates, at truck stops because I think the trucking industry will be all over this at the end of the day.

It's just too -- 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 American national wealth overseas.

This is something that's going to pick up speed, we're just trying to push it along a little bit.

Okay, thanks for your comments.

You bet Monroe, thank you, keep on the Twinkies.

We will take our next question with Paul Bennett with Boulevard Trust, please go ahead.

Thanks, gentlemen.

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.

Anything, well, just add this.

Are you going to do anything locally in Oklahoma with Boone Pickens' operation?

Wind operation.

We support Boone and all of his initiatives.

Our plan is just a little less grandiose, a little more focused, a lot cheaper and I think can happen faster.

Boone's focused on electricity, I'm focused on transportation fuel and I did not think you have to back natural gas out of the power stack to be able to fuel cars and trucks.

I think we can do that through domestic supply growth.

So that's probably about the only nuance that is different in what we're trying to accomplish versus what he's trying to do.

Okay, thanks very much.

Good luck.

Okay, thank you sir.

We will take our next question with Suvas Tandra with Jeffries, please go ahead.

Hi Aubrey.

Just kind of a philosophical question, I guess.

I the sustainability of paying 10,000 to 50,000 for undeveloped acreage, I guess in large swaths, not like few hundred acres here, 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 environment where maybe external financing won't be there, where the bottom line is that if you sort of held your powder, you might see these overall trends begin to decline.

Well Suvas, a couple different thoughts there.

The first is that 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 million.

There are just not many companies at the end of the day that can write that check, then also have the technical resources to go out and drill the wells.

Having said that, to spend $30,000 an acre as Plains did for acreage from us is kind of chump change when it comes down 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.

There's this big gap between the value proposition for acreage and then at the other end of the spectrum, there's the enormity of the capital itself.

So 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.

And one follow up, these rigs -- 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.

Well, we have got 20 some odd rigs coming on.

We have our own rig-up facilities, we're the fifth or sixth largest contractor in America, so we know how to get them built, get them rigged up, get it all done on time, so that's not really an issue for us.

And going forward, we don't have deliveries planned for 2010.

I think all our rigs we have got are coming in '08 and '09.

So we will evaluate 2010 when the time comes, but right now that's pretty much where we are.

Perfect, thank you.

Okay, 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.

Once again ladies and gentlemen, this will conclude today's conference.

We thank you for your participation.

You may now disconnect.