Chesapeake Energy Corp (CHK) 2006 Q3 法說會逐字稿

Good day and welcome to this Chesapeake Energy third-quarter 2006 conference call.

Today's call is being recorded.

At this time for opening comments and introductions, I'd like to turn the conference over to Mr. Jeff Mobley, Senior Vice President of Investor Relations and Research.

Please go ahead, Sir.

Good morning and thank you for joining Chesapeake's 2006 third-quarter financial and operational results conference call.

Before I turn the call over to Aubrey and Marc, let me first provide you with disclosure concerning the forward-looking statements that Chesapeake's management will make during the course of this call.

The statements that describe our beliefs, goals, expectations, projections or assumptions are considered forward-looking.

Please note that the Company's actual results may differ from those contained in such forward-looking statements.

Additional information concerning these statements is available on the Company's SEC filings.

In addition, I would also like to point out that during the course of the discussion this morning we will mention terms such as operating cash flow and EBITDA and we'll also mention several items that we believe are typically excluded from analyst estimates.

These are all non-GAAP financial measures.

Reconciliation to the comparable GAAP measures can be found on pages 21 through 24 of our press release issued yesterday.

While these are not GAAP measures of financial performance, we believe they are common and useful tools in evaluating the Company's overall performance.

Our prepared comments this morning should last about 20 minutes and then we will move to Q&A.

Aubrey?

Thanks, Jeff, and get morning to each of you.

I would like to begin by introducing the other members of our management team who are on the call today, Marc Rowland, our CFO;

Mark Lester, our Executive Vice President of Exploration; and Jeff Mobley, our Senior Vice President of Investor Relations and Research are with me here in Oklahoma City; while Steven Dixon, our Chief Operating Officer joins us from out of town.

There's obviously much to talk about this morning given all the Company accomplished during the third quarter and in fact during the first three quarters of 2006.

In the interest of time I'll focus on just three topics.

The first will be our thoughts on the gas markets and our hedging strategies and results.

The second topic will feature some operational thoughts and the third topic will focus on what I believe is a key strategic transition for Chesapeake as we move our focus more from resource inventory capture to resource inventory conversion.

This shift is probably the most important strategic change at Chesapeake in the past seven years and we hope that today you understand its significance.

So let's begin with natural gas markets and hedging.

In the fall of 2005 after Katrina and Rita, natural gas prices rose to record levels and Chesapeake responded by aggressively hedging more than one trillion cubic feet of its expected gas production in 2006, 2007 and 2008.

Our study of gas fundamentals led us to conclude that such high gas prices were unsustainable.

Further, our meteorological team advised us in early October of last year to expect a much warmer than normal winter and that was all we needed to hear to even more aggressively hedge our expected gas production.

And finally, even if we believed gas prices had been sustainable at double-digit prices, we believed it would have bordered on management malpractice to not take some chips off the table.

So take off the chips we did and the results to date have been remarkable; over $800 million of realized cash gains through the first nine months of 2006 plus $540 million of loss gains from -- lifted hedges for future periods.

And finally, a mark-to-market gain of approximately $700 million for our remaining open positions.

In addition because of the strength of Chesapeake's underlying hedge positions, we have not exposed you, our investors, to the risks that less hedged companies have exposed you to in the past year.

I understand that some observers of Chesapeake have considered our past hedging successes to be just dumb luck but hopefully what we have delivered from our 2006 hedging activities will remind investors that we are very capable risk managers and revenue maximizers and we take pride in what we have delivered to you from our hedging activity.

Any discussion of hedging necessarily requires a follow-on discovery about natural gas markets.

So I will share with you our current thoughts on the subject.

Having recognized last fall that the seeds of a natural gas price collapse had been sewn, we also recognized this fall that the seeds of a natural gas price recovery have also been sewn.

That is why on September 28th we announced that we were [shutting in] 6% of our October 2006 gas production.

This was the portion of our expected monthly gas production that was unhedged.

That week we also started lifting some of our hedges because we believe the bottom was likely in for gas price.

I would like to remind you that after our announcement that day, gas prices rallied and it has never looked back.

Current month gas prices are now up over $3 per MMBTU or 70% from the date of our announcement.

I am not saying that we caused the rally.

I'm just saying it appears we correctly called the bottom in the market and have now realized a $500 million further hedging gain from lifting approximately 13% of our hedges.

I will also add that we have recently rehedged some of our November and December gas volumes at several dollars higher than at levels where we took the hedges off, further increasing our expected fourth-quarter natural gas price realization.

Those of you who have talked to us about natural gas prices in the past few months know that we have believed that investors obsession with the 300 Bcf overhang in the gas storage market was much ado about nothing.

We consistently have said that all the talk about potential gas supply growth or potential industrial demand collapse or potential surge in LNG importation or anything else did not matter and all was simply background noise.

All that mattered is that the U.S. gas market has been in an oversupply position in 2006 for one reason and one reason only.

Last January we did not consume 400 to 500 Bcf of gas that in an ordinary January would have been consumed.

It is as simple as that.

We have consistently asked investors to imagine what their thoughts about gas prices would be if today's gas storage number were say 300 to 400 to 500 Bcf less than where it is today.

I guarantee you that gas prices in that scenario would today be close to $10 per MMBTU and this conference call would be dominated by a discussion about how high gas prices could spike if we have a normal or cold winter.

Speaking of gas balances, we doubt that despite all of the concern in the past few months about storage levels reaching 3.6, 3.7 or even 4 Tcf of gas and storage on November 1, we believe storage will fail to even reach 3.5 Tcf by November 1.

Further we believe the year-over-year storage overhang which in April of 2006 reached a staggering 700 Bcf will be down to 300 Bcf or so after next week's storage report.

We further believe that by no later than mid January of 2007 we will have a year-over-year storage deficit and that by March or April of 2007 such a deficit could become quite large, maybe even in the range of 300 to 500 Bcf.

If we are correct, all the talk of a permanent new gas bubble will quickly fade away and all conversations will then focus on how high summer gas prices can go if we have another hot summer and have multiple summer storage withdrawal.

How quickly investors will forget the past few month's worries about gas prices and we predict they instead will wish they had loaded up on Chesapeake and other high-quality E&P stocks in September and October when they were dirt cheap.

As my second topic, I'd like to provide some operating highlights.

The biggest highlight of course would be our continued ramp up in drilling activity.

This morning we have an industry leading 121 operated rigs drilling.

Of these, 53 are working in Texas; 43 are in Oklahoma; 8 are in West Virginia; 5 are in Louisiana; 4 in New Mexico; 3 in Arkansas; 2 in Kentucky; and one each in New York, Ohio and Virginia.

We believe that by the end of 2006 we will be operating approximately 133 rigs and in 2007 we should reach approximately 150 operated rigs.

These rigs will all be focused on converting resource inventory to cash flowing and net income generating proved developed increasing reserves.

In doing so, we believe that Chesapeake can increase its proved reserves from 8.4 Tcfe today to almost 9 Tcfe by year end 2006 and our goal is to reach 10 Tcfe of proved reserves by year end 2007 and 11 Tcfe by year end 2008.

And we believe we can achieve this all through the drillbit and all on acreage that we own today.

By year end 2008, we would also expect Chesapeake to be a top three producer of U.S. natural gas, up from seventh today and a top three owner of proved natural gas reserves in the U.S., up from fourth today.

We would also expect at year end 2007 and 2008 to continue leading the industry in acreage and 3-D seismic owned on shore in the U.S.

The key driver of our growth during the next two years will clearly be in the Barnett Shale sweet spot of Johnson, Tarrant and Western Dallas counties in North Central Texas.

This sweet spot is proving to be by far the best area in which to drill horizontal shale wells in the Barnett and may in fact be the best place in all of America in which to develop natural gas reserves.

I'm happy to report that in three years we have built Chesapeake's acreage position in this area from zero to approximately 150,000 net acres.

This is the largest leasehold position owned by anyone in the industry in these three counties and we believe on this acreage we can drill 400 to 500 wells per year during the next four to five years and can develop as much as 4 Tcfe of additional proved reserves from our future drilling activities in these counties.

Let me share some other Chesapeake Barnett Shale fun facts with you.

At the moment we are producing about 170 million cubic feet of gas per day from the area.

We believe that puts us in third place in Barnett Shale production.

And we also have 17 operated rigs drilling today.

By year end 2006 we will be at 24 rigs and in 2007 we will further increase our operated rig count to 30 to 35 rigs.

With 30 to 35 rigs, we should be able to drill 400 to 500 Barnett Shale wells per year in the Ft. Worth area sweet spot and we should be able to develop 700 to 900 Bcfe of new proved reserves assuming that our costs remain at $2.7 million per well and our expected reserves per well continue to average to 2.45 Bcfe before royalties and 1.8 Bcfe after royalties.

That would replace our projected companywide production of 670 Bcfe in 2007 by 110 to 130% from just the Barnett alone and from using just 35 of our 135 rigs leaving at least another 100 operated rigs to provide further growth.

One more noteworthy fact about our Barnett Shale operation, if we were to hypothetically separate it from the main body of our company, Chesapeake's Barnett Shale company in 2007 would rank among the eight most active operators in the U.S. and by year end 2007, we believe it would be a top 20 natural gas producer in the U.S.

Again I remind you that we did not have a single dollar invested in the Barnett three years ago so I would like to publicly compliment the dozens of Chesapeake employees who have worked so hard for our investors in the past three years to build this extremely important, and increasingly valuable Barnett Shale franchise.

I believe it would also be fair to say that we have built the most powerful unconventional gas resource machine in the industry today.

If it's unconventional and it's east of the Rockies, then Chesapeake is there.

And in most every case we are the leader or top three participants in the play.

Some of the more noteworthy of these various unconventional plays are the Barnett, Woodford Shale plays in far West Texas; the Deep Haley overpressured type sand play also in far West Texas; the Fayetteville Shale play in Arkansas; the Deep Bossier play in East Texas; the Woodford Shale play in Southeastern Oklahoma; thermogenic new Albany shale play in Southern Illinois and North Western Kentucky;

The Floyd Chattanooga and, Conasauga Shale plays of Alabama; and the various shale plays of Appalachia.

In addition of course, I want to emphasize the strength of our traditional plays in the MidContinent Permian Basin and also in South and East Texas.

Our assets teams in these conventional areas continue to deliver excellent results without getting much public attention and so I especially appreciate their effort to keep Chesapeake's conventional areas growing as well.

Finally, I would like to highlight what I hope has been increasingly clear to you over the past few quarters, Chesapeake is clearly moving out of the era of resource inventory capture and into a new era of resource inventory conversion.

I understand that many of you have wanted us to begin this transition for years; however the time was not yet right as we still had some major land grabbing work to do.

The time is now right and we are in an unprecedented drilling ramp up mode.

In 2006, we will double our operated rig count and in so doing we will add more rigs in one year to our drilling program than the next month most active driller is currently using.

Looking at it another way, Chesapeake will be responsible for approximately 30% of all the new rigs put to work in the U.S. in 2006 while producing about 3% of the nation's natural gas.

While we still will continue increasing our acreage inventory levels in the years ahead, I do want to reemphasize what I said in our second-quarter conference call and that is that the land grab for unconventional resource plays in America is now largely over and I believe that Chesapeake came in first place in this modern-day version of the Oklahoma land run.

I also believe that having won this contest we will have sustainable and distinctive competitive advantages for years to come.

Some of you have noted in the past few years Chesapeake has delivered top of the industry growth in production and reserves but only middle of the industry returns on capital.

I simply ask you to consider that our middle of the pack returns are actually quite remarkable when you consider the debt and equity issuances of the past few years that were needed to pay for this unprecedented land grab.

The cost of the acreage has increased the amount of capital utilized in our company but obviously much of the acreage has not yet generated any returns for us.

We believe that is all in the process of changing and also believe that our newly expanded production growth targets of 14 to 18% for 2007 and 10 to 14% in 2008 will result in especially significant per share value creation and much higher returns on capital in the years ahead.

I would also observe in any discussion on returns that in our $12 billion of E&P acquisitions in the past seven years, we have never booked any goodwill for tax base step up or for any other reason.

By making that conservative accounting decision, our net income has been lower, our capital inputs have been higher and as a result, our returns on capital have been lower than they otherwise would have been had we recorded goodwill as many in the industry routinely do in making acquisitions.

Remarkably to me, I have never seen an analyst take this into account in comparing returns on capital across our industry and hope that they will do so in the years ahead.

I hope that my excitement about Chesapeake's accomplishments in the third quarter and in all of 2006 is obvious to you and I also hope that my excitement over the years to come is equally apparent.

Chesapeake has never been in better financial or operational position and I believe you'll be very impressed with what we will deliver to you in shareholder value creation in the years to come.

There are probably 10 other topics I'd like to touch on but in the interest of time, I will now turn the call over to Marc and hope that some of these topics will come up in our Q&A session.

Thanks, Aubrey.

Good morning everyone and thanks for joining us today.

I'd like to highlight just a few items this morning.

First, let's discuss our proved reserves.

The Company continues to experience record-setting reserve replacement results.

On page 19 of our press release, we have set forward our nine-month roll forward of proved reserves from January 1 '06 to today.

Particularly notice please the 541 Bcf equivalent of positive reserve revisions due to performance.

While we have experience several years of positive revisions, in this nine months our revisions amount to 7.2% of beginning reserve quantities and exceed year-to-date production by 27%.

Of course due to the long-lived nature of our production, we have had some curtailment of reserve quantities due to the very low prices we saw at the end of September.

In fact, this leads me into my second point that I want to discuss this morning.

At September 30th, we saw gas prices that were set for delivery in October based on an index of about $4.18 per Mcf.

Many of our wellhead prices had we not been hedged would have been set at $3.50 or less.

We elected to shut in some production that was unhedged and the result have been well discussed here this morning and in our release.

However, we like many others were basing the possibility of a full cost ceiling test.

This became a frequently asked question and many analysts were in print with various analyses.

Gas prices however not only recovered but roared back nearly doubling in three weeks.

Today in fact instead of the potential loss we may have had, we have a full cost ceiling cushion of about $3.7 billion.

I suppose this highlights the inaneness of the single date pricing system that we must live with.

Next, we accomplished some attractive finding financing transactions during the quarter.

We entered into a rig financing with a group of very fine banks in September.

We sold them 18 of our rigs for $188 million and then leased them back for eight years.

Of course the rigs remain under our custody and control and we have the option at the end of the lease to repurchase the rigs or enter into some other type of financing transaction.

Our cost of capital here was less than our revolving bank credit facility.

Additionally, we have an expanded facility in place now in excess of the $188 million where new rigs to be delivered in the future that we have on order currently will be acquired directly by the financing syndicate and leased to us.

Our hedging facilities continue to offer us great financial flexibility.

To remind you, we have several very large secured facilities that support are hedging program.

These are with some of the finest and largest investment-grade counterparties available.

At one point in September, we had over 1 trillion cubic feet of future gas production hedged; our positive mark-to-market position at 930 was nearly $1.5 billion of accounts receivable.

Of course as gas prices dipped to what was in our opinion unsustainable lows, we unwound many of those positions and Aubrey mentioned this and have collected in cash over $400 million out of the $540 million of total gain from these unwinds.

Many of these positions of course were re-established when prices shot back up.

Let's finish up by recapping our capitalized internal costs for the quarter and after which we will move to the question session.

Our capitalized interest for nine months ended September 30th was $119.2 million as opposed to last year's number of $54.8 million, a doubling reflecting the amount of unevaluated leasehold.

For the quarter alone, $49.3 million versus a quarter a year ago at $20.8 million.

Our other G&A costs reflecting our extensive expansive drilling program resulted in year-to-date costs of capitalized G&A of $119.3 million, up from about $74.6 million last year and again in the quarter, $49 million versus $29.5 million last year.

I believe everything else of financial detail has been adequately discussed and disclosed in our press release and we do intend to file our 10-Q this next Monday following the weekend.

So with that, I will turn our session over to the moderator to help us with questions please.

(OPERATOR INSTRUCTIONS) Scott Hanold, RBC Capital Markets.

Some of you guy's actions that you spoke about and written about are fairly positive for the gas market.

Could you just sort of give a little bit of color on you obviously made a pretty good decision in I guess monetizing some of your hedges but with the prospects of a potentially warm winter at least that is what the forecasters are talking about at this point in time, do you see some risk at this point to the early part of '07?

Scott, I think there is always risk when you are talking about weather events that are a couple of months out.

But we are still largely hedged for the first quarter of '07 and I refer you to the table on the bottom of page 5 of our press release.

We are still 74% hedged in the first quarter of 2007 for gas at [1068] per mcf.

So as we publicly stated for months, the best scenario for us is for gas prices to collapse and go to zero.

We doubted of course they would do that and have taken actions recognizing that it would be impossible for them to do so.

We also, on page 6, would direct you to the fact that we've also locked in $109 million of gains for that quarter by lifting some of those first quarter hedges.

One further thought.

You mentioned I guess a meteorological consensus about a warm winter, certainly the trend has been toward that but our own meteorological team which I think is unique in the industry and is exceptionally well regarded having worked for Citibank for years before we hired them three years ago had a completely different view than consensus last winter and believed that they nailed it.

They have been so far right on for calling for a cold September and October.

So they have a different opinion about the remainder of the winter than the consensus that you reference as well and we certainly take that into consideration in thinking about gas markets and our activities and decisions related to those markets.

Is that sort of I guess then at least a normal to I guess they have more of a tendency to believe that there's going be a more normal winter versus the consensus of warm winter?

And is that sort of why you guys believe that we could be in a deficit position to historical norms with gas storage as we move into the middle of '07?

It's part of the reason.

First of all I think that their view is more toward normality this winter but I think you have to be careful how you define that whether or not you are talking about a thirty-year normal or a ten-year normal.

If you are normal for 30 years, that would make you one of the coldest three winters of the last ten.

So important to recognize that distinction.

And their view is that it is likely to be closer to a normal winter despite the trend clearly in the direction of warmer winters over the past 10 to 15 years.

Certainly those are factors that we take into consideration when thinking about the continuing diminishing amount of storage overhang that is out there.

But keep in mind we've already worked it down from 700 Bcf to 300 -- and let's call it 20 Bcf or so and I think by the end of next week, we will be down to 300.

So if we just look at the comparisons and the weather comparisons that we have coming at us, we think it is inevitable that we will soon be in a storage deficit and that that deficit could be quite considerable given particularly the storage comparison numbers we have looking at us in January.

Keep in mind last January was the warmest January in 112 years of recorded meteorological history.

That means it could have been the warmest in the last 200 or 300 years.

And if you think about then that that winter was two standard deviations away from normal, the reality is this winter-- this January would statistically almost by definition have to be different and certainly our forecasters see the whole winter shaping up as dramatically different than last winter.

Okay, thank you.

And just one last quick question.

I'm assuming your obviously outlook is predicated on their view on the next several months.

What would happen if in fact we did get say another mild January and February, would that change your current outlook for activity?

Can you just talk about a couple basins in general which could potentially see some adjustments in activity?

I know costs vary even within a basin but just looking for some generalities.

If you did slow down drilling activity, where would the first areas likely be?

Scott, in the interest of time and other folks have questions;

I think I will just say that weather forecasts are just a portion of our reading of the fundamentals underlying the gas market.

And so while we certainly consider it, I think we've been on record in looking at many other aspects of the supply and demand equation.

And I think we are in great shape either way.

If gas prices go up from here, we've got a lot of unhedged gas in the years to come.

If we do have another mild winter this winter then as I mentioned, we are 74% hedged at 1068 in the first quarter.

In terms of basin, the basin we are in good shape, have not reduced any drilling activity and have been encouraged that other companies are finally doing so.

It's one of the reasons why we've hedged.

And we will look forward to continuing the ramp up of our drilling activity in the months and years ahead.

Thank you.

Thank you.

Shannon Nome, Deutsche Bank.

Great quarter and a great call, thanks.

What concern one gets relates to the debt and more importantly I guess the equity offerings you all have undertaken in the past few years.

And your comments before I think hinted that this enormous funding need may be winding down somewhat.

I guess you could say that even in your latest batch of acquisitions you essentially funded them with the hedging gains you monetized.

Nonetheless, at 4.8 billion a year over the next couple of years, it looks like on our model that's still above and internally generated cash flow.

A, is that off?

And B, if it is not off, how are you going to fund the heavy drilling phase that you are entering into?

Well, I don't think your numbers, Shannon, are off at all.

We ourselves show that there is at $7 or $7.50 price estimates some deficit given the level of drilling that we are entering into.

We will continue to fund this.

Our intentions are to continue to fund this just as we've done in the past, a combination of equity and the use of either our hedging gains or our bank facilities.

So certainly we've talked in terms today particularly about a ramp up that moves into a resource conversion phase from this resource acquisition phase.

They are not mutually exclusive but clearly the focus is going to be on increasing the drilling activity and converting that up.

You notice in our projections we've increased the amount of production gains that we expect.

I suspect that that could be conservative as well.

So we hope that as we move particularly into the Barnett Shale conversion that the amount of gas coming out of these plays will significantly increase even above the levels that we've projected and further decrease that proposed deficit amount.

I hope that is specific enough for you.

We don't have any equity offerings in mind at this moment.

So just a matter of moving forward, we've got plenty of cash and liquidity to fund what we are doing right now.

Sure.

Thanks, Marc.

The one housekeeping question and I'll sign off.

Where are cash and bank debt currently or pro forma after the affect of unwinding your hedges?

Our bank debt outstanding today I believe is about $1.3 billion.

And essentially other than just working capital going up and down, we use that as our cash position so to speak.

So our total bank facility is about $2.5 billion.

We have only collected, as I pointed out, I think $407 million or maybe it was $409 million of the total gains that we've monetized so far.

And that would be the working capital or cash on hand?

Yes.

It goes into the bank paydown numbers.

So like I said, it varies -- our cash collections now on any one month can vary $500 million from the end of the month when we're collecting revenues to midmonth when we are like we are right now paying out.

Right, but the 1.3 does not accommodate the paydown from that 400 some odd million?

It does accommodate.

It does.

Okay, so that is net of it.

Okay, thank you.

At this moment, yes.

Gil Yang, Citigroup.

Aubrey, could you just quickly comment on you said that you recently put back some hedges on for the fourth quarter.

Did you do the same for the first quarter?

I will let Marc take care of that.

Thanks.

Yes.

We have put some on not only for the first quarter but for the entire period of 2007.

We have not taken -- a small amount in '08 and '09 that we took off we have not put any of those back on, Gil.

Okay.

Marc, second question is at the end of the quarter what was your deficit, the full cost ceiling test deficit?

At the end of the quarter using the $4.18, the deficit would have been on a pre-tax basis $670 million and on an after-tax basis, $415 million.

And as I pointed out, that has changed by $4.5 billion to a cushion now of $3.7 billion.

Right, okay.

And just finally, you comment on the rig activity picking up as part of your resource development program moves forward.

Should we expect to see a decrease in your acquisition activity or is that still -- I mean implicitly you are saying that you will slow that down at some point but do you really see that slowing down in the near future or is there still some work to be done?

Well I think what you just said is exactly accurate that we will continue to add acreage to our inventory and we will certainly always be on the lookout for accretive proved developed producing acquisitions as well.

Just certainly on a relative basis when you are doubling your rig count, our emphasis on drilling will naturally increase to be a bigger part of the program.

And given the fact that we've staked out attractive acreage positions everywhere we want to be, we would now be looking more for bolt-on acquisitions in these areas as opposed to initial positions which tended to be pretty large and pretty expensive in some of these plays.

So, yes, I think that clearly on both the relative and absolute basis our drilling efforts will continue to command an increasing portion of what we focus on around here.

Okay, thank you very much.

Brian Singer, Goldman Sachs.

Thank you, good morning.

Could you talk about how you think about the value creation opportunity when you make additional service investments?

Is there a cost inflation number that you are assuming for industry over the next couple of years and how much less should we expect cost inflation at Chesapeake given your service (inaudible)?

There are probably three aspects to it that I see and I'd like for Marc to add his insights as well.

But when we first started to make investments in the service industry -- gosh, it's been five years ago I guess --

2001.

Yes, five years ago -- in a major way I guess starting two or three years ago, we were thinking about a couple of things.

One, we thought service costs would likely rise if we were right about gas prices so we wanted to provide ourselves with a hedge against that.

And our $120 million gain or so on Pioneer drilling earlier this year represents an example of that.

But we also wanted to build for ourselves additional operational flexibility and acquisition flexibility.

We've certainly done that through our rigs by the end of a rig build out which is projected to last into the first or second quarter of '07, we'll be at 82 rigs.

So I think in four or five years we will have built the sixth largest drilling fleet in America and it will give us complete independence, not complete independence, large independence I guess from actions that are taken by others in the industry and others in the service industry.

For us to conduct the program that we've embarked on, to buy the acreage that we've bought, we had to have 100% assurance that we would be able to get our hands on the rigs necessary to convert that acreage into [PVP] reserves.

So we've done that.

Now as we examined where we were, we also noticed that our biggest problems were looming in the pressure pumping area.

That's where the delays were and in many of our wells today, frac jobs are more expensive than drilling rig costs.

And so we looked around for a way to hedge our costs there but also as a way to expand the capacity of the industry.

We were not satisfied with the existing build-out plan for the industry so we backed a private company that has been a rapid builder of services into the pressure pumping area.

We would hope on this acquisition or this investment as well as several other investments that we've made in two drilling companies that those companies will go public or at some point be consolidated or at some point continue to thrive as independent entities and give us a chance to exit.

And we hope at exit multiples well in excess of our cost basis.

Marc, do you want to add to that?

Yes, I do.

I've got two thoughts on it, Brian.

First of all, when we make these investments -- when I'm running my cost of capital and return analysis I don't really view future inflation as being an item that comes into consideration.

The investments that we make in these rigs, the investments we make for example in compression equipment we feel like that those are pretty rapid paybacks given today's cost structure and the margins that people are passing along to us whether it be a Hanover or some third-party rig company.

So we don't need inflation or estimates of inflation to have very adequate returns and relatively quick paybacks.

The second part kind of is a tack-on to what Aubrey said about operational efficiencies and controls.

Many of the items of equipment that we're ordering we are ordering because defensively the other companies were not ramping up, whether that is fracing services or compression equipment particularly.

Long lead items, we are in the business to ramp our production up and we know that every day we're going to need compression, additional compression of all sizes.

And so we've got compressor orders going out to 2008 that probably exceed many of the public company compression.

And for example just in this quarter, we spent about $24 million on various gathering systems and almost $15 million on incremental compression equipment.

So it's a large operation producing nearly 1.7 billion cubic feet equivalent today and with our ramp we are going to be the number one consumer of additional gathering transportation and compression services.

Should we then expect future investments in pressure pumping or do you feel you are there for now with this new acquisition?

I think with this investments we are there.

And in fact this company is rapidly expanding the capital that we have provided and that they are generating on their own will cause them to be able to ramp up and enter into new areas.

So we've picked a horse that we think is a strong candidate and we're going to stick with that one.

Great.

If I could just ask one more.

It looked like the language on the Fayetteville and Woodford Shale, Oklahoma Woodford Shale seemed a little bit more positive than in the past.

Is that right?

And could you just give us an update?

Sure, be happy to.

I will include a comment on Fayetteville as well.

We've drilled wells now successfully in both areas at the end of -- second quarter we had not yet operated a well in the Woodford Shale in Southeast Oklahoma, and I believe we'd only drilled two or three horizontal wells and completed them in the Fayetteville Shale.

So both plays are looking better.

The Fayetteville Shale I think is looking much better and we are responding there with a rig increase of two rigs now up to seven rigs by the end of the year.

We do have about 340,000 net acres in a core area of the plays compared to Southwestern I guess is about 800,000 acres or so.

So we believe that we've got about 2100 net wells to drill in the play in the years ahead and are comfortable that we can spend $2.5 million to develop 1.4 Bcfe on 80-acre spacing.

So we will hold out some hope for what we can do in the 700,000 acres of noncore leasehold which today we are basically saying has no value.

In the Woodford, we completed one vertical well and one horizontal well.

The vertical well is excellent and the horizontal well is okay.

In fact the vertical well is better than the horizontal well and it just appears to be in an area of better rock.

So the area continues to be challenged by some cost and clearly in our opinion Woodford is not going to be as good as the Fayetteville and not close to what the Barnett is but that is unfair to compare anything to the Barnett in Tarrant and Johnson Counties where results to date have simply been exceptional.

Thank you very much.

Chris Edmonds, Pritchard Capital.

Good morning, guys.

Just a follow up on Brian's question on service costs.

Aubrey, can you talk a little bit about your feelings about overall costs?

There's a lot of chatter about a letter that was sent to a service provider suggesting fuel surcharges were no longer kosher and that you were looking for some rollback given what's happened in the market.

Can you address a little bit what your expectations are in '07 and what you are thinking of going forward?

Sure, Chris.

Not surprised that that letter surfaced since we sent out 4000 of them.

But at any rate, our thoughts I think have been the same that we've expressed to you and others over the past year that we thought the hyperinflation of 2005 and 2006 was likely to be a thing of the past in 2007 and beyond.

And the reason was simply this.

That when you get a structural move up in gas prices it is naturally going to be the producers who see the cash flow first and see the opportunities first with and we respond.

When we respond the way we responded in '05 and '06 as an industry, we put tremendous pressure on the service industry's infrastructure and naturally there is a delay between how we as producers respond to higher gas prices and how service company providers respond to those same gas prices and obviously they want to use up all their spare capacity and want to make sure that they have a future backlog before committing to an increase in their underlying capacity.

We predicted that private companies and public companies alike would rapidly rush into that void and you would see a rapid buildup of drilling rigs and after that I think buildup in other parts of service company infrastructure.

And based on that view, we have projected for the past year that even with a rig count that was 10 to 15 to even 20% higher in 2007 or 2008 we would actually see per unit service cost declines as the investment in the service company infrastructure expanded at a rapid pace.

We've certainly been a driver of that through our rig investments.

I believe by the time it is all said and done and we've built 81 rigs by 2007 and Chesapeake will have been responsible for perhaps a 4% increase in the drilling rig fleet in America just by ourselves.

So that underpins our thoughts about where we've anticipated service costs to go into future.

We certainly have been hit with the worst and think it gets a lot better from here even if there is higher rig count.

With specific regard to the letter, we noticed that hundreds of our vendors were hitting us with fuel surcharges and since oil was down 25% in the past month or so we felt those were especially egregious and notified the service industry that we would no longer pay for any fuel surcharges.

And we also offered a view that we felt like the rollback of 10 to 20% in service costs was in order given where gas prices are today relative to what service costs were when gas prices were last at $6 of $7.

So we've -- as the largest consumer of drilling and related expenditures in the U.S., we feel like we need to be a leader in the all things that we do and especially in leading the charge towards a rollback in pricing to more moderate levels that are reflective of today's gas prices.

We knew somebody had to take that lead and that somebody had to be us and we've done that.

And I think we will see lower costs as a result of taking that action.

And, Aubrey, how would you characterize the response?

Are your vendors enthusiastic?

It has been enthusiastic measured in lots of different ways.

Steve Dixon is on the phone.

Steve, do have anything to offer other than thoughts that we've received all kinds of responses?

Most of them actually have been positive.

I mean gasoline prices have gone from $3 down to $2 so out of that is pretty obviously that the surcharge needs rolled back.

But it is mixed.

Yes, some claim they've never charged us anything which some haven't.

It has been mixed.

But I think very positive.

And, Marc, if I could just address one question on that subject to you about the $250 million investment in the pressure pumping simulation company.

Can you give us some benchmarks or metrics as to what that represents?

What is the revenue or EBITDA of that company?

Yes, it is a private transaction, Chris, so I don't want to offend my partner by saying too much.

We purchased our 20% approximately at a rate that basically would value the Company at five times what we invested it in.

And I think on an EBITDA basis for this coming year, that is probably in the 7.5 to 8 EBITDA range.

Got you.

And then Aubrey just one housekeeping item on basins.

The Energen transaction, can you just talk a little bit about what your rationale was there and sort of what you are thinking about Alabama, Mississippi and the prospectivity there?

Sure.

If you kind of look at the Mississippi and Devonian Age shale belt that extends along the Old Continental margin all the way from Ouachita over in far West Texas where they are active in the Delaware and Barnett -- or sorry, the Barnett Woodford Shale plays in the deep Delaware Basin all the way up to Ft. Worth Barnett, following into Southeastern Oklahoma with the Woodford across Arkansas with the Fayetteville and then dropping -- the shale belt drops down into Northern Mississippi and across Northern Alabama and then basically intersect with Appalachian shale.

And as we had moved across Oklahoma and Arkansas and as we were over in Appalachia we knew that there was one little area that we had not put a big position together in and that was Alabama and Mississippi.

We evaluated the Floyd and the Chattanooga.

Keep in mind the Floyd is Mississippi in age so it is the equivalent of the Barnett and the Chattanooga is Devonian aged and equivalent to the Woodford; just different names over there.

So we were interested in some areas not interested in some other areas where we saw some competitors, but we specifically also targeted the Conasauga Shale which is an extremely old formation and more related to Appalachian tectonic events than anything else.

And then started to acquire acreage about a year ago, and Dominion had a well that blew out in the Conasauga earlier this year at some pretty high reported rates.

So by the time we got there in size, Dominion and Energen had staked out some pretty key positions already.

So we approached Energen and asked them if they needed a partner and they said no.

But we were persistent and explained to them what we thought we brought to the table, which is a company that drills more shale every day in more different plays than anybody else in America.

We complete more wealth in shale than anybody else in the country.

We're building a rock technology lab to make sure that we don't have to rely on outside bottlenecks in terms of getting cores evaluated and performing other tests on the rocks that we drill.

And I think over time, James McManus at Energen became convinced that we'd be a great value-added partner, and lots of people have money but not everybody has -- in fact, nobody has the shale expertise that we have.

And I think he admired that and we were able to make a 50-50 deal, and we will be shooting some seismic and drilling some wells together in 2007.

And given that it's Energen's home state, we believe that we now have a kind of home field advantage by having partnered with somebody that has been operating in that state in one form or fashion for over 100 years.

Very good.

Thanks, guys, I appreciate your time.

David Heikkinen, Pickering Energy.

Good morning.

On your increased capital budget, is there any escalation in costs assumed in that budget?

No, David, there is really not.

What we are starting to see to amplify a little bit is we've started to see actually a downturn in some of our rig rates.

That's sort of a leading indicator to us as typically the completion cost lagged on the way up and probably will lag on the way down.

But at this point in time, given the current gas price that we see, we feel like we're in a time where prices actually could trend down slightly.

So this is basically for '07 reflecting current rates and projected activity.

The acquisitions you made in the quarter, can you give us a breakdown of reserves and cost per transaction?

We don't have those numbers for you, but we did give you percentages.

What page is that on?

I think it is on top of page 7 where we tell you that 47% was in South Texas, 45% was in the Barnett and 8% in Northwest Oklahoma.

It's pretty linear relationships that you can just divide the cost and the reserves and all the other numbers we give you by those percentages, and they will be pretty close to --.

Not trying to be too transparent; just trying to get to the Dale acquisition costs, but I guess you're not going to give us that.

That was about $200 million.

We had actually two Dale transactions, so I guess together it's about $300 million.

And I guess in one of those, Parallel, has an interest in the second transaction -- we acquired 100% of what was in the --

Perfect, that answers that.

And then on the supply side on the natural gas macro and overall demand side, what are you guys thinking excluding weather just think normal weather of rate of supply growth onshore, declines offshore and then overall demand growth next year?

We'll let Jeff handle this.

Sure, David.

We've spent a lot of time trying to get our arms around that an have wrestled with trying to find the best data source and to us it appears like the EIA's new 914 survey seems to be the best.

It's clear that onshore production growth is up probably to the magnitude of around 4.5 or more percent.

The Gulf of Mexico still seems to be struggling and plateauing out at about 8 Bcf a day versus well over 10 pre-storms.

And if you talk to a lot of the operators that are focused on the Gulf of Mexico shelf, it is a pretty challenging environment from an area that has been heavily picked over.

Rig rates are exceptionally particularly with rigs having left the market.

And basically no mystery left on the shelf as the entire shelf has been shocked multiple times on seismic.

Going forward we still expect to see a ramp up in production growth out of Texas and Oklahoma.

Chesapeake and some of our respective partners are going to be a big part of that.

Wyoming continues to go up but New Mexico, Louisiana appears to be flattening out and Gulf of Mexico is still a challenge.

So in net-net we think overall supply is maybe up in the neighborhood of 1 to 2% and going forward with a rig count if it stagnates, may not be enough to sustain that trajectory and may see it level off.

And some of that increase has been offset obviously, David, by reductions in LNG imports.

One further thought on that.

We started to say last year that we thought 2006 would go down as the first year in five or maybe six years that you'd see a production increase.

We also thought it might be the last time in the next five years that you see a production increase because we believe that the relationship of rigs to production increases must be nonlinear.

And so it will require further or let's say the same percentage increase in rig count in the years ahead which obviously requires a larger and larger erythematic response on number of rigs and we think that is likely unsustainable.

And for example to be three or four years out we would think it might take anywhere from 2200 to 2500 rigs to keep production flat.

It's really the dark side of technology and it doesn't get talked about nearly enough.

But when you apply better and better technology to worse and worse rocks, you gets steeper and steeper decline curves.

And so you people can get excited over a 1 or 2 or maybe even 3% production increase this year but I would say that I think it is unlikely that such a increase is sustainable year in year out for the next five plus years unless you have very strong gas prices that are in rough BTU parity to oil.

One last thing I would add, David, is when you think about the total supply picture, one thing that we are giving some thought to is the reliability of imports in Canada particularly with the growth of the tar sand project up there.

They can be great consumers of the (indiscernible) limit to total import in the U.S. making the U.S. market even further total supply challenged.

Okay, thanks a lot, guys.

Ken Carroll, Johnson Rice.

Good morning.

A quick update, you mentioned acquiring a couple hundred thousand acres in New Albany play and Illinois and Kentucky.

If you could give us a quick overview of that and near-term plans there?

And also kind of back to the Fayetteville second question, other operators there have talked about using new frac techniques which have led to lower IP to potentially higher EURs -- kind of what your view is there and how you'd play that out?

Sure, we will talk about Fayetteville first.

I suppose what you are referring to is Southwestern's move to slick water frac earlier this year as opposed to the nitrogen frac that they started out with.

It's not clear to us why they started with the nitrogen frac.

I presume because they were concerned about maybe apparent low pressure of the reservoir.

I would like to have thought that we would have started out with water fracs but no matter both of us are now using those and certainly the slick water fracs kind of Barnett style slick water fracs have resulted in wells that are now highly commercial and look pretty good to us.

In the last few months, Southwestern has made a further refinement as I understand it of their completion process and have moved more to some cross-link gel frac jobs and I presume that is to reduce the amount of water that is needed to frac a well with and the water that is needed to be trucked away afterward.

I believe that they are seeing the same results with cross-link as with slick water and we are in virtually every one of their wells that's being drilled these days.

SO we have pretty much perfect information on what is going on there.

And we will just be in wait and watch mode right now.

We're proceeding with our plans to continue fracing our wells with basically a Barnett style frac.

With regard to the New Albany, really two plays there.

There is a biogenic play that is really more Indiana focused and we watched it over the last couple of years and don't believe that it is proven to be economic.

On the other hand we were interested in a thermogenic New Albany play centered in Southeastern Illinois and Northwestern Kentucky and started to put acreage together there probably a year and half or so ago.

Two wells are actually drilled in the play by Vintage.

They were not completed because they were drilled just about the time that they were undergoing their change of control event.

And so we approached Oxy after the deal and ended up buying Vintage's acreage through Oxy.

So together then through our own efforts and through the acquisition of the Vintage acreage, we now have 220,000 acres in that play and we will be (technical difficulty) with the drillbits probably early in 2007 to see if we've got a play there or not.

Got you.

So the two wells drilled by Vintage (technical difficulty) as well?

Pardon me?

Those two wells drilled by Vintage partner, you still have not completed those?

That is correct.

We've been blocking up acreage in the area.

Got you.

Appreciated it, great quarter.

Tom Gardner, Simmons & Company.

Good morning, guys.

Aubrey, concerning that rig asset sale leaseback, can you walk us through the terms in that?

I can and could but I'm going to let Marc do it because he will do a better job.

It's pretty straightforward; 18 rigs, $187.8 million or $187.9 million transaction.

It's a classic operating lease situation.

We sold the rigs to them and then leased them back for a period of eight years.

There's a couple of different option dates in there but basically at the end of the period there is a residual amount and we have the option to purchase those rigs back at the residual amount.

Or I guess an option we always have is to re-enter into a different lease or a subsequent transaction.

We pay I believe $26 million per year for those 18 rigs and all of the terms of that broken down by year and so forth will be in our Q next Monday.

If you compute the residual value which is in essence the option repurchase value, the stream of payments and the cash received up front it all discounts to a discount rate or a cap rate that is less than our bank financing so it is a cheaper alternative financing method for us.

And it is fixed.

So to obtain eight-year fixed-rate financing at less than our bank cost today on a floating basis, we thought that was pretty attractive.

And of course the reason that all of this can occur is because we do not take utilization of the depreciation from a tax -- income tax paying standpoint because with our drilling activities we are not paying cash taxes to the federal government.

So the rig financing companies or banks, if you will, can take advantage of those and so their after-tax yield on this is sufficient to compete with other investments they can make.

Thanks, Marc.

That is helpful.

Can you all give us a status update on those gas production curtailments?

Is all that gas back online now?

The gas is back online and we're running about 1.65 Bcfe of production per day.

Great.

And just with regard to commercializing that Delaware Basin Shale, any breakthroughs there?

Not yet but we've got a well now that we drilled horizontally in the Barnett and we will be completing that in the month of November.

So if we get commercial gas out of that, then we'd have a breakthrough given the history or how these plays work it typically takes a little more time than your first well to get it right.

So we will continue to push forward.

We basically have two rigs out there drilling right now.

And we are producing gas from these formations right now.

It's commercial quantities of dry gas that is basically pipeline quality gas.

But it is not in amounts that would be commercial to sustain a drilling program.

So that gas though I would tell you comes from wells that were drilled and completed by other people using drilling techniques and frac jobs that would not be considered state-of-the-art today.

So we are optimistic that here in the next few months we will have some commercial gas but more than likely it will take more than a few months to crack the code in the play and off we go.

I will say this, that if anybody is capable of cracking the code I think it will be us given our experience with the shale and four other companies that brought us in as joint venture partners in that play, I think must have agreed with that.

So that remains a very important competitive strength of the company that people who have shale acreage today come see us because they know that we are seeing more shale than anybody else every day and we've got technology and experience to share.

So I think partners are recognizing that more and more these days.

Thanks, Aubrey.

And great release and great quarter.

Joe Allman, JPMorgan.

Good morning, everybody.

Aubrey, your CapEx budget in '06 and '07 is up about $1 billion each year and from what you forecast at the end of July.

Could you just kind of talk about the big drivers and that bump up in the CapEx?

Sure, the big driver is increase in drilling activity.

At the time in July we were not projecting 150 rigs in 2007.

Right now we'll probably get there with some success in the Fayetteville and a few other plays.

So more rigs turning to the right means more CapEx and so we've budgeted accordingly.

Okay.

Is the '06 bump up mainly due to the acquisitions or --?

Almost all of that in '06 is the acquisition of this incremental acreage versus just off the ground activity in these various joint venture transactions we've chosen to classify that as capital expenditures that are not related to asset acquisitions although in fact they are more akin to an asset acquisition.

And the fact that you've kind of lowered your fourth-quarter production guidance, you've got these additional acquisitions which some of them bring on some production.

The issues and the Barnett shale with using the multiwell pads, does that completely offset the incremental production from the acquisitions?

It's the primary driver and why we were a little light in the third quarter and why we expect to be a little light in the fourth quarter.

Steve, I might ask that you kind of explain the concept of pad drilling and how -- what happens when you move from drilling individual wells one right after another and completing those to a pad where we might drill four or five, six, eight, 10, 12 wells and then are delayed.

So carry on from here if you would.

It really creates a big delay when you start that program which we did here in the third quarter.

As you start loading those rigs onto a pad and will skis over and drill multiple wells without starting the completion activities, it may be as long as five months from the time you drill your first well to it's actually goes to sales waiting on the other wells in the pad to drill and then starting the completion activities.

It's kind of a onetime big delay as we get our fleet drilling these pad locations.

We're starting to roll off our first set of those now and so our production for the fourth quarter should ramp up pretty quickly.

But it can be certainly initially a pretty significant delay.

Joe, one other thing, the other idea with regard to pad drilling is that pretty much simultaneously you are putting a large number of frac jobs to work in a fairly contained area.

And so all this -- what you are trying to accomplish through a frac job obviously is to energize the rock to break it apart to communicate or allow gas molecules to get to your wellbore and there's been a school of thought around here and perhaps some other places that if you can concentrate that energy pretty much simultaneously you might end up with a more thorough fracing of the rock in a certain area.

And so we've got several of those programs under way.

I will say that the results from the most notable program today to date are three wells called the [Goex] wells in Johnson County where I believe we frac three wells back-to-back on a pad and they came on at around 17 million cubic feet of gas per day which would be well above pro forma.

So we will withhold judgment to see if it is actually going to change our production rates and EURs from these wells but for sure the pads help us with land owner relationships as we are consuming much less land per well and also down the road will make operations easier when you have an operation that's concentrated kind of the way you do it offshore with a large number of wells from a single platform and that is essentially what we are doing right here.

That is helpful.

And then the description of the different plays that you are in -- I mean back in July you were expecting I think some more rigs by the end of '06 and you are not expecting especially in the unconventional resource plays -- so for example in Ark-La-Tex region I think you are expecting like up to 17 and now you are expecting 13.

Is there some issue with just kind of getting your hands on those rigs?

That's part of it.

Also this is a very dynamic process every month that we go through in allocating rigs.

In fact, the drilling schedules in the company probably change every week.

Marc and I and Jeff and Steve and Mark Lester get together every month to review the budget and move rigs around or the operation guys bring their rigs -- movement recommendations to us and we discuss them.

Some areas we will add rigs, some we will subtract from quarter to quarter as we put that information out.

I would say that we have continued to experience rig delivery slides through the last six months and while I can't specifically answer your question as to four or less in Ark-La-Tex, I would just tell that overall the ramp is a little slower than maybe we would have hoped 90 days ago.

And with your natural gas market comments, it's pretty bold to suggest that we're going to go from a 300 Bcf surplus to a 300, 400 Bcf deficit.

So there must be something beyond the weather if you are calling for somewhat normal weather there must be some other driver.

Is that driver the demand for gas and electric power sector or is there some other factor that you think the market may be missing in its forecasted natural gas?

Joe, I would say first of all that certainly the electrical generation market has helped reduce the overhang from 700 Bcf in April to 300 Bcf today.

I don't think anybody anticipated two storage withdrawals this summer.

And at the time we highlighted that for investors that we thought that go down as probably the single most important change in the gas market in the past three or four years.

And the implications for the future are I think potentially profound.

I think that has been totally missed by the market because of everybody's concern and borderline obsession with the amount of gas that was going to be in place on November 1.

We always said we thought it was irrelevant whether it was 3400, 3500, 3600, 3700 Bcf of storage.

Because if you had a normal winter it wasn't enough and if you had a cold winter it wasn't nearly enough.

And if you had a warm winter then it was way too much and gas prices would go down.

So right now when you ask what else are we looking at?

We are looking at supply and demand that we think are largely on a normalized basis pretty much in balance with each other with maybe supply going up 1 to 2% per year and demand probably wanting to do the same.

But I think you just have to come back to January weather.

If we didn't burn 400 or 500 Bcf last January and we do burn that 400 or 500 Bcf this January, then you are all done.

You've gone from a 300 Bcf surplus to a 200 Bcf deficit and you haven't done anything but just recognize that last January was extraordinary.

And in our view it accounts for everything in 2006 gas prices.

I think people overanalyze things sometimes and maybe that is what they are paid to do.

But we are paid maybe to do the same thing but also take a step back and look at the big picture and we try to do that.

We are fine either way.

If it's a mild winter we're at hedged over $10.

If it's a normal winter then we are off to the races for 2007, 2008 and we're going to get some hedging opportunities for 2008 and 2009 and we'll continue to roll it forward from there.

Aubrey, just real quick.

You continue to grow and I just wonder at some point if you start producing 2 Bcf a day or up 3 Bcf a day, do you get too big to really operate optimally?

And just to be able to replace 2 Bcf a day or 3 Bcf a day it's a pretty big order.

Can you just comment on that?

At some point might you actually right size your asset base?

Sure.

Joe, I think you asked us that question when we producing 500 million a day.

I think so.

It's a good question and one that we get all the time and one we think about all the time.

The easy answer is to say sure, scale gets in your way and the law of big numbers catches up to you.

The reality though for Chesapeake over the last couple of years has been different.

Scale, particularly focused scale, I'm not talking about worldwide scale -- I'm talking about regional scale, has given us tremendous advantages.

Those advantages extend from having relationships with vendors that really matter.

We're the number one customer of most every significant vendor in the U.S.

Informational advantages are huge.

We are collecting close to 15% of all the daily drilling information being generated in areas that we care about.

You just you can't overemphasize the value of information in the information age and that is the age that we are in.

And so the advantages should be to the companies that have more information and then what you do with it.

So right now we are enjoying -- by the way and scale it allows us to extend technology across areas.

We are better in the Fayetteville then we would be had we not been in the Barnett.

We're going to be better in Woodford because of where we are in the Barnett.

And if we are successful in cracking the code and far West Texas for the t Woodford and Barnett down there, I think it will be because of our scale in other shale plays.

If we change the culture in Appalachia which I think we're in the process of doing, our production there is up over 8% from second quarter.

I think it is because we had the scale to be able to bring a corporate culture change to Appalachia and I think when you look at that base in five years from now it will look very different from the way it does today and I think we will have been a prime mover in that.

And then a real quick one.

The Fayetteville shale, what price Henry Hub gas do you think you need to get a decent rate of return?

Say like a 15% pretax rate of return?

That wouldn't be very decent in our view.

We think we need to be looking at 30 to 40 to 50% rate of return for a play to be interesting to us.

I always have a hard time answering that question because it presumes a certain gas price and it presents then that -- which is generally low and presumes current finding costs.

Our view is that as finding costs or rather gas prices go down, finding costs will go down.

So if gas prices go up, finding costs may go up although we are hopeful again that the unit prices will stay the same.

At $6 gas, at a 1.2 Bcf well in the Fayetteville, we think that is by the way $2.5 million we think that is about an 18% unlevered internal rate of return.

At a 1.8 Bcf, that is going to be about 35, 37%.

And at 2.4 Bcfe, that's a 60% rate of return.

So clearly the play to us is marginal at 1.2; at 1.8 over 2 it becomes very competitive with anything else that we are doing.

Okay, that is very helpful.

Thank you.

Dan Morrison, Aperion Group.

You answered absolutely everything including the simultaneous fracing in the Barnett question.

So, thanks.

Ellen Hannan, Bear Stearns.

Good morning.

My questions have either been answered or belabored I think.

But I do have one question for you, Aubrey, in your opening remarks you talk about the I think when you mentioned the goal of getting to a proved reserve base of about 11 Tcfe by year end '08 if I understand you correctly.

I'm curious as to is that based on your planned drilling for 2007, 2008?

Does that include acquisitions?

What were your assumptions behind that?

Our assumptions are that there are no acquisitions in that time although obviously I would be surprised if we didn't make any.

It is simply the execution of the plan that we've laid out in this is press release with the inputs that we have into our gas factory, if you will, in which we manufacture molecules gas and those inputs are people, land, seismic and capital.

We've got all four of those and we tell you how we're going to input them.

And the outputs are that we think we can increase our proved reserves to the levels that I described ending with about 11 Tcfe by 2008.

It's probably -- I use the word goal -- it's really just an outcome from our manufacturing operation.

It's not, we don't set out to be at 11 Tcfe and then back into the inputs.

We start with the inputs that we want to make and then calculate what the outputs is likely to be.

And it to so happens that we think in the next couple of years we can add about a Tcf of proved reserves per year with the drilling program that we've laid out here.

What if any risk is there to that execution?

Well, there's risks lots of places but one of the things that I think we've done as well as anybody is examine the risk, analyze the risk and then try to strip it out of our business.

We basically had very little exposure to lower gas prices during that time.

We've hedged our oil production.

There's not going to be any risk to us not getting the rigs.

There is no risk to us not having the acreage.

There is no risk to us not having the people.

There is no risk to us not having the compression and the gathering systems.

So everything that we believe that we needed including the capital we have got.

So that's peaking with my shareholders hat on, I just when I look at other companies today and think about their plans over 2007, 2008, I believe the operational and financial risks embedded in those companies are substantially higher than ours where we have systematically tried to evaluate and mitigate every angle of risk in our business on all the way down to what is the weather going to be in January.

Very good.

That's it for me.

Thank you.

Eric Kalamaras, Wachovia.

Good morning, Aubrey.

Could you tell me in the capital spending budget can you break out the difference between drilling, seismic and any leasehold?

Yes, we do that on page -- I can't find it right now.

We are basically going to be if you think about a $4.9 billion budget for '07 and '08, think about drilling in those years of about 4.1 billion and recurring leasehold expenditures of about 600 million and seismic of about 200 million and that adds up to -- that should add up to about 4.9 billion.

At out of the drilling portion, could you refresh me again on the wells for '07 and '08?

In terms of number of net wells?

Yes.

It should be around 2500 net wells I believe.

If you look at the net wells to date we've drilled 845 operated net wells for the year and 141 nonoperated.

That is basically 1000 wells and add one more quarter that will not be proportional.

So you know you are at 1400 wells drilled with a number of rigs that when we get up to 130 to 140 to 150 that well count should probably exceed 2000 net wells and in time might approach 2500.

We think about having 25,000 net locations left to drill and we kind of round up to get to a 10-year inventory because it's kind of awkward talking about 11, 12 or 13-year inventory.

But right now it would look like around 2000 net wells.

So even at 2000 it looks like your development well costs will come down a fair bit.

How do you think about the variance from where you are today versus going out into '07, '08?

Well I think that we are likely to have lower costs.

One thing that has not been mentioned at all by you guys or by us is the great finding costs that we've had through the first nine months of the year.

We've conducted the industry's most active drilling and acquisition program and we're all in at $1.89.

Some of that is influenced by performance adds which I'd like to highlight as well that nobody has caught that we have increased our proved reserves 7% this year just through upward performance revisions.

We've more then replaced our reserve, our production this year just through positive performance revisions.

It's a powerful story here that I think shows how conservatively we initially book our proved reserves.

So going forward, our target has been to be at around 225 Mcfe all in and given the fact that a good bit of our acreage that we will drill on in the years ahead is already in our full cost pool, we view that we will be able to hit that target and hopefully to be under as apparently we look like we're going to be this year.

It is somewhat hard to gauge from this side to determine the investments that you've made in the rigs.

What that really has translated to in terms of a dollar amount.

Have you looked at that and how do you think about that versus what you would have paid just as going with other counterparties instead of actually making your own investments?

First of all, I think we did say what we've spent.

You have.

I'm thinking in terms of the actual benefit to you --

You can kind of get to that through -- we're now spiking out our net margin from service activities.

Marc may want to address that.

But if to go to the income statement for the quarter on page 16, you'll see that our service operations revenue was $38 million and our service operations expense was basically 19.

So we had a 50% margin.

And so at 19 million times 4 -- at a run rate of an $80 million gross margin, some of that was from trucking but most of it was from drilling.

And compare that to our overall investment in rigs, I think you'll see that it calculates to a very healthy return.

I'll turn it over to Marc.

I understand that it is hard on the other side to get to this and we have a lot of internal discussions about A, how we have to present it for gas purposes and B, how we can present some of this.

If you think that those rigs are drilling 75% for our own account on average, just to make the mat easy, and using Aubrey's calculation here of roughly $20 million of margin per quarter, that's $80 million of margin per quarter servicing 25% of interest that we don't own in a well.

So the other 75% gets put in as a reduction to our full cost pool, or said another way our finding cost to reduce by that because we can't book income or margin on the service side that we provide for our own account.

It's an intercompany elimination so to speak.

So if you just did the simple math $80 million a year from our service operations, if you were to have 100% of that being a service company then that margin would be $320 million per year.

And I think you can compare that to the investment that we've got and you can see that we're on a period of 1.5 years payback.

It's not reflected in the income statement part of that payback, in fact most of its going to go to reduce our full cost pool.

So we make the assumption that we are providing service at exactly the competitive price that is being charged by third parties.

In fact we go out and survey that and frequently for example in our trucking operations we're actually providing services to third parties where we don't have any stake in that service being provided.

So we have to be competitive.

I hope that helps in trying to evaluate where the value might be there.

I've got one other way to think about it which is if we have 60 company-operated rigs or company-owned rigs out there right now basically if you think about on a pro forma basis a rig rate being $20,000 a day and our profit margin 50%, so that tells you that our cost is about $10,000 a day.

So we are saving about $10,000 a day in cash that would go to Nabors or [Unit] or Gray Wolf or Patterson or someone like that.

Per rig.

Per rig.

So if you have a 75% working interest in all of those rigs then you are saving $450,000 per day times 30 days is -- what 14 million or so times 12 -- you are approaching $175 million just thinking about it that way.

You can come at it a couple of different ways but either way kind of approach is toward a couple hundred million dollars of value creation every year for us which I think is an extremely attractive return.

Plus you remove all operational risks of not being able to conduct your ramp up because you can't get hold of a rig.

That is great.

Thank you for the thorough explanation.

David Snow, Energy Equities.

You've answered almost everything.

I'm wondering a couple of questions in the -- where is the noncore acreage in the Fayetteville?

What is your direction that you are going there?

Basically if you just take the eastern part of White County and head east to the Mississippi River that is what we consider our noncore acreage.

And has that been drilled by anybody?

Sure.

We drilled a handful of wells in it.

There have been three or four other operators drill wells in it and to our knowledge nobody has established commercial production in that area.

It looks like the rock has been overheated or overcooked in that area and we seem to not have commercial gas left in the rock.

Okay.

And I'm wondering if you could just take the non Barnett shale plays and give them in the order of attractiveness?

It sounds like Fayetteville was your top one, isn't it?

And how would it go?

I would recommend that you go to our website and look at our slide shows.

Jeff has done a wonderful job in putting the economics of each one of the plays.

And so you can go back right into the slide show and each one of the plays is identified.

It shows the production, the amount of acreage, the pro forma cost and recoveries and then charts at different prices the rates of return.

So you yourself can just then look at every one of those plays and get a sense of what we think the economics are and of course that by nature is our ranking.

You can also see it through our projected rig use that we give you area by area.

Yes, I was looking at the rig use as well.

Well that is great.

Thank you, appreciate everybody's participation.

I think we've extended far into overtime here and if you somehow were left with a question unanswered, please call Jeff later today.

I'm sure he'll be happy to get back with you and appreciate your interest in our company.

And we will talk to you after the start of the year.

Thank you.

Goodbye.

Thank you everyone.

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