Chesapeake Energy Corp (CHK) 2007 Q2 法說會逐字稿

Good day and welcome to this Chesapeake Energy second quarter 2007 conference call.

Today's conference is being recorded.

At this time for opening comments and introductions, I would like to turn the call over to Jeff Mobley, Senior Vice President of Investor Relations and Research with Chesapeake Energy.

Please go ahead.

Good morning and thank you for joining Chesapeake's 2007 second quarter conference call.

Hopefully you've had a chance to review our earnings release and our updated slide show presentation posted to our web site yesterday afternoon.

Before I turn the call over to Aubrey and Marc, I need to 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 in the Company's SEC filings.

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

These are all non-GAAP financial measures.

Reconciliations 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 performance.

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

Aubrey?

Thanks, Jeff, and good 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, Steve Dixon, our Chief Operating Officer, and Jeff Mobley, who you've already heard from, is our Senior V.P.

of Investor Relations and Research.

Without a doubt the second quarter of 2007 will go down in Chesapeake's history as our best operational quarter ever.

We overtook two large independents and one major company to become the largest independent producer of U.S.

natural gas and the third largest U.S.

gas producer overall.

Given that BP and Conoco-Phillips are the only two companies that now produce more gas than Chesapeake does in the U.S., and given their production continues to decline while ours continues to increase, it seems inevitable that sometime in 2008, Chesapeake will become the largest U.S.

producer of natural gas.

I believe not many of you, or any of us, would have thought that possible eight or nine years ago.

During the quarter, Chesapeake's production increased by 161 million cubic feet of gas equivalent per day on a sequential basis, and that's a 9% increase in just one quarter.

Our production also increased by 300 million per day on a year-over-year basis, that's a 19% increase.

Virtually all of these production increases came through the drill bit.

I think the enormity of these accomplishments is best appreciated when you compare our production increases to the total production that some of our well-regarded industry colleagues have recently reported.

For example, companies such as Southwestern, Range, and Ultra all produce around 300 million per day and they all have enterprise values ranging from 7 to $9 billion.

So I think it's fair to say that in just one year we have created an equivalent company of those companies inside of Chesapeake, and believe we have created an also equivalent 7 to $9 billion of value inside of Chesapeake.

Yet, I believe we did so on a broader and more risk mitigated platform.

Further, we are projecting that Chesapeake can continue these exceptional increases in production in the years ahead.

Hopefully you noticed we are now projecting 18 to 22% production growth for 2007, that's an increase of 400 basis points from our production forecast of just 90 days ago.

Moreover, we have also increased our production growth forecast for 2008 by an identical 400 basis points to a range of 14 to 18% from our previous range of 10 to 14%.

While we will not issue Chesapeake's official 2009 production forecast until three months from now, we will likely begin with a production forecast growth rate of around 10% for 2009.

So we believe it's likely that Chesapeake could be producing around 2.5 Bcfe per day at year end 2009.

Perhaps more importantly, in 2009 we should be able to once again reach steady state equilibrium between our operating cash flow and our budgeted drilling, leasehold, and seismic expenditures.

Alongside our production growth, proved and unproved reserves have been rapidly growing as well.

At the beginning of the year we started with 9 Tcfe of proved reserve and hope to get to 10 Tcfe by year end 2007 and 11 Tcfe by year end 2008, and 12 Tcfe by year end 2009.

It now looks like those forecasts were too conservative and we have already reached our 2007 year-end proved reserve target at midyear 2007.

It now looks like we could be between 10.5 and 11 Tcfe of proved reserve by year end 2007, somewhere around 12 to 12.5 Tcfe at year-end 2008, and perhaps as much as 13 to 14 Tcfe of proved reserves by year-end 2009.

Furthermore, our risked, unproved reserves continue to expand alongside our proved reserves as our acreage and seismic inventories continue to grow.

We now recognize more than 80 Tcfe of unrisked, unproved reserves on our acreage, and almost 21 Tcfe of risked, unproved reserves.

The relationship of 2 to 1 between our risked, unproved reserves and our proved reserves, that has developed over the past few years, is likely to continue in the future, giving further visibility and confidence into Chesapeake's ability to maintain its high growth rate at attractive finding costs.

We have examined our assumptions rigorously, have mitigated our risks substantially, and now believe that the gas factory that we have been building for the past five years is running 24/7 at high speed and low-risk and should be able to generate net asset value growth of 7 to $10 per share per year for 2007 through 2009.

Working from a $35 per share base, we believe this 20 to 30% per share net asset value creation should be very attractive to our shareholders.

I would also like to remind you that our growth is being generated from multiple geographical areas and from multiple play concepts.

For example, of the 300 million per day of year-over-year production increase, approximately 1/3 came from the Barnett Shale.

13% came from southern Oklahoma, 10% came from Deep Haley, and, by the way, does not include the recent 40 million per day of production we picked up from Anadarko, 10% came from Sahara, and the final 1/3 came from our other plays.

I believe this diversified growth profile highlights the broad strength of our overall production platform.

We are not a one play company, yet we have the high growth profile associated with one, but without the attendant execution risks associated with one.

I might also add, that we have several new play concepts presently being tested, that if successful could be valuable additions to our portfolio.

Given that the Fort Worth Barnett Shale is our most important growth area, I thought a detailed operations update might be in order.

We entered the Barnett in November 2004, and one year later we are running 4 operated rigs.

Two years later, in the fall of 2006, we were running approximately 20 rigs.

And today we are running 35 operated rigs and will further increase that to 38 rigs in the next few months.

We continue to enjoy very attractive drill bit finding costs from our Barnett acreage of around $1.50 to $1.60 per Mcfe.

In case you're curious, our average acreage, brokerage, and seismic costs average around $10,000 per net acre.

Yet that only adds about $0.35 per Mcfe to our finding cost.

So think with me for a moment about the future value creation implications of being able to spend $10 billion in the years ahead to drill 4,000 Barnett Wells at an all in finding cost of less than $2 per Mcfe.

I am certain the enormity of the upside of our Barnett assets in the Fort Worth area is not yet fully understood by the market, but will be in due course.

The purpose of our large scale Barnett drilling ramp-up is, of course, to make this enormous upside more visible and tangible by turning our non-producing leasehold into cash flowing producing PDP assets.

Let's see how we've done in that effort today.

Three years ago we had no production in the Barnett, two years ago we averaged 35 million a day during the second quarter, and one year ago this past quarter, we averaged 110 million per day.

More recently, in the fourth quarter of 2006, we averaged 157 million a day from the Barnett.

In the first quarter of 2007, we averaged 180 million a day, and in the second quarter we averaged 207 million per day.

Currently, we are producing about 230 million per day net from the Barnett.

These production gains should continue to accelerate through the second half of this year and by the end of 2007, our Barnett net production volumes should exceed 300 million per day on a net basis and our gross volumes are likely to exceed 450 million per day.

Again, all of this from a standing start just three years ago.

We expect to see further impressive increases in Chesapeake's Barnett production through 2008.

In fact, we can see Chesapeake's Barnett production increasing through at least 2010, as we remain on track to bring one new well into production every 15 hours for the next four years.

If you were doing that math alongside me, you'll note that there are 35,040 hours in the next four years, and therefore Chesapeake should bring on approximately 2200 new well in that time frame.

Please think about the substantial future impact of those wells, when you consider we have drilled fewer than 500 wells in the play today.

I would also highlight that Chesapeake's Barnett assets are focused in the best geological part of the play, the core and tier 1 area of northern Johnson County, western Dallas County, and all of Tarrant County.

In this area Chesapeake has amassed 180,000 net acres and we are adding to that total by approximately 10,000 net acres per quarter.

At that rate of leasehold acquisition, we should be able to maintain a rolling backlog of some 2500 undrilled wells for years to come.

When it's all said and done, we expect that Chesapeake will have been able to drill more than 4,000 net Barnett wells from a land area inventory that should ultimately reach 300,000 net acres in the core and tier 1 area of Johnson, Dallas, and Tarrant Counties.

These 4,000 net wells should generate approximately ultimate reserve recoveries of more than 7 Tcfe for Chesapeake, of which we have only booked 1.5 Tcfe to date.

I might also add that we are routinely bringing on wells that initially produce 3 to 5 million cubic feet of gas per day, and our per-well production average will likely creep up over time as we drill more wells in Tarrant County and fewer in Johnson County, where to date about 85% of our existing Barnett wells have been located.

I might also update our DFW Airport drilling activity.

On that airport, we are utilizing five rigs to drill on this 18,000 acre lease, which is the largest single contiguous lease in the Barnett Shale play.

We have reached total depth on 12 wells to date and are reaching total depth on a new well every approximate four to five days.

Barnett Shale underneath the airport looks excellent and is the thickest we've seen to date in the entire play.

We will begin completing our first wells at the end of this month and are hopeful that these DFW Airport wells will redefine what a monster well is in the Barnett.

In summary, plain and simple, Chesapeake's Fort Worth area Barnett franchise is a tremendously valuable asset that will continue driving production and proved reserve growth and net asset value creation for our shareholders for years to come.

I will conclude my comments today with a few thoughts about the MLP market.

We have decided to not form a CHK drop down MLP, as we see potential tax and governance issues associated with such vehicles.

So instead of forming our own MLP, we have decided to sell into the MLP market a production stream of 30 million cubic feet of gas per day in the form of a non-operated, approximate 35% undivided working interest in approximately 4300 Chesapeake operated wells in Appalachia.

To maximize the appeal of this production stream to both the MLP market and also to various financial buyers, for the first four years of the life of the properties, Chesapeake will guarantee a flat production curve of 30 million per day.

And we will also guarantee a NYMEX price of $7.50 per MMBTU, a positive differential of $0.30 per MMBTU, and we will lock in our gathering transportation and overhead costs at attractive levels for the buyer.

In addition, we will assign only well bore rights and they will also be depth limited, so all of the production upside will remain with Chesapeake.

In summary, the buyer of this production will receive one net monthly check from Chesapeake, will have no operating hassles, and will be guaranteed flat production levels and attractive production pricing for the first four years of the life of the properties.

We believe this will be a very attractive offering to both the financial and MLP marketplaces and we hope to receive at least $600 million from this sale.

This offering and others like it that we can do over the next few years, will be an important part of our financial plan as we move from the heavy capital overspend of 2007 into a more moderate overspend level in 2008, and finally, in 2009 we expect to regain equilibrium between our operating cash flow and our budgeted drilling, leasehold, and seismic CapEx.

By that time, we hope to be producing around 2.5 Bcfe per day.

We hope to own between 13 and 14 Tcfe of proved reserves, and we expect to have a materially higher stock price.

On that happy thought, I'll turn the call over to Marc.

Thanks, Aubrey, good report.

Good morning to everyone on the call.

Obviously, another great quarter from an operating and financial perspective.

I won't spend any time at all going through the press release, but instead we'll provide some incremental detail to what Aubrey's already provided.

Our drill bit finding costs move downed to $2.14 per Mcfe in Q2 versus what we reported $2.66 in quarter one.

We have continued to see flat to slightly down service costs over the last few months, with some areas, such as the Barnett Shale, reflecting lower stimulation cost as more equipment and new service providers enter into that market.

Overall, we have seen an 8% reduction in intangible drilling costs in the first half of 2007.

Our expectations for service costs for the remainder of the year remain the same.

That is, some downward forces as more rigs and equipment become available.

In the Barnett alone for the quarter, drill bit costs were $1.62.

As Aubrey mentioned, leasehold adds were about $0.35 per Mcfe for an all in cost of $1.97.

As you can see, a very valuable resource in the core area and about 1/4 of our budgeted current quarter drilling efforts.

Specifically, we now see rig rates in Oklahoma based on 1,000 horsepower rigs, down to 16,500 to 17,750, which is down from six months ago, which was 17,500 to 19,000 per day.

In Texas, most recent rig rates are 15.5 to 17.5, down from 18.5 to 21.5 per day six months ago.

So a more substantial decrease as more rigs have moved in from the Rockies and even Canada, plus the new builds in that area.

Stimulation cost, which is an important part of our budget, in fact, amounts to about 40% of our overall spending, are down about 7% on average so far this year.

Cementing in less active areas is flat to down 5% while in the Barnett Shale and Sahara, areas that attract more equipment, prices are down 20 to 25%.

[Pacing] prices are down 6% from six months ago and about 12% from a year ago.

Looking ahead, continued cost declines of 10 to 12% per year result in 500 to $700 million of cost reduction in our annual run rate of drilling CapEx at the current rig count.

And that is our forecast for the remainder of this year and into 2008.

A highlight of the quarter was the profitable exit from our investment in Eagle Energy Partners.

We first invested only $6 million with Eagle in September of 2003.

Subsequent cash investments grew over time to total $33 million.

We sold for $126 million, a pretax cash gain of $93 million.

This does not include distributions received by us in cash of $10 million over our ownership period.

So our return on investment in this particular venture was in excess of 280%.

We have remaining investments in Gastar, Chaparral, drilling and stimulation company ventures, and other companies with a book value of about $650 million as of June 30.

And we believe these investments are worth much more than what we've invested and we believe that they'll be profitable, as was Eagle, in the future.

On another topic, during the past two quarters, several investors have inquired about how we plan to fund -- to close the funding gap between cash flow from operations and capital expenditures.

This gap exists currently as a result of our accelerated drilling program that has enabled Chesapeake to grow at rates at the top of our peer group and build an industry-leading drilling inventory.

We have several attractive alternatives at our disposal.

Of course, the sale of a minor amount of mature PDP-only reserves, as noted by Aubrey and in the earnings release, should result in proceeds well north of $600 million.

To be able to sell production that is less than 20% of our production increase in just this quarter, and I'm emphasizing just the increase in production, for proceeds that we expect could fund about 50% of our quarterly exploration and development costs seems very attractive to us.

Obviously, this could be repeated over time and become a very compelling financial model for you, our investors.

Other funding sources in our toolbox that we are working on currently include a second sale leaseback transaction of 33 additional drilling rigs.

We believe this will result in $250 to $300 million of proceeds by the end of Q3.

Also, we are creating a new sale leaseback transaction for our compressor fleet.

Initial proceeds will likely be in the $200 to $250 million range and then be sized to provide financing of all compressor needs for the next two to three years, which will likely be in the $300 to $400 million range.

This transaction is likely to close in the early part of Q4.

All of this will come to us at a cost of financing rates of around 5%, while we maintain complete control of operations and ultimately the assets will come back to us.

One other option we occasionally consider is selling volatility, one of our often unappreciated assets.

In the market today, out of the money $10 to $12 natural gas calls for 2009 through 2012 are trading for as much as $1 per Mcfe, and could be an attractive funding source, particularly if gas prices and volatility spikes.

All of these alternatives we rate ahead of the formation of an MLP, and certainly way ahead of selling equity.

As evidenced by the dramatic growth in reserves and production, the Company has significant opportunities to drill at very high rates of return.

While we have no immediate plans to issue common stock or preferred stock, the continued use of traditional balanced equity and debt issuance makes complete sense, given our opportunity set while maintaining and improving our credit [ratings].

It has been this strategy that has allowed us to grow this company to the largest independent producer of U.S.

natural gas, while also increasing the net asset value per share, and while improving our credit rating over the last eight years.

While the traditional [eye of] market is in a bit of a mess, the convertible market remains attractive and we view the net share convertible instrument as an attractive alternative.

To remind you of how attractive this instrument was when issued three months ago, I want to talk a little bit about the details in conclusion.

Remember that the principal is paid back in cash while accruing a cash interest cost of 2.5% per annum.

We did this three months ago by granting the buyer a warrant overlay structure that allows them to buy CHK stock when above a conversion price that was 50% or more above the price then, which resulted in a very small amount of dilution.

In fact, only about 900,000 shares at $53, which escalates to a capped amount of only 11 million shares at a price of $80.

And then, of course, this is after the stock's gone up substantially from the current level.

So, we felt like this was the right instrument at the time.

There were some people that questioned this, but we continue to view it as a very attractive form of capital injection into the company.

With that we'll turn it, moderator, over to the question-and-answer session.

Thank you.

(OPERATOR INSTRUCTIONS) We'll go first to Brian Singer with Goldman Sachs.

Thank you.

Good morning.

Good morning, Brian.

You've highlighted in the past, as you do today, the relative valuation gap between smaller single asset companies relative to Chesapeake.

I believe, historically, you've rationalized this to size-related differences, which Chesapeake formally benefited when it was a smaller company, at what point, though, would you consider spinning off some of your more growthier assets that could then command a premium to what you have today?

Brian, I don't think that's something that we plan on doing.

I think the Company's strength is it's ability -- is it's scale and all the resources that we have here that actually can, on a unified basis, continue to help move the full company forward.

So my view is that we are now at a level where we are able to produce production growth equal to or above most of the higher growth smaller companies, yet we do so without the risk associated with a one play story.

So we like the position we're in.

Frankly, we don't care if our multiple ever gets to the multiple afforded some smaller companies.

We were the beneficiary of that for many years.

All we're about is turning leasehold into PDP and know that over time, as we continue to generate greater net asset value per share, that will be recognized by the market.

Great.

On the capital spending front, in terms how far you think about CapEx equaling operating cash flow in 2009, you highlighted the MLP ongoing potential sales there.

How do you think about CapEx levels beyond '08, and do you continue to expect that you'll be ratcheting up activity levels, or do you see a more flattish CapEx as you seem to in '08 versus '07?

Right now, as we've discussed on our outlook, we have CapEx projected to be flat in 2008 compared to 2007.

We won't be putting out our official forecast for 2009 until 90 days from now, but right now we would view that we're more or less in a steady state for CapEx that would change only when new plays develop.

And I mentioned in my comments that we do have several new plays that we're working on and some of them, if successful, could require significant expansions of drilling.

It's also possible that we still have a few plays in the Company that are successful today that might need more rigs down the road.

Those are kind of high-class problems to have and we'll address those as we move forward, but right now we're looking at flattish CapEx in '08 versus '07 and also, I think that we're looking at drilling costs that likely will not increase in the future.

I think we've been hit with the brunt of those, and going forward our own drilling efficiencies and lower per unit costs should enable us to drill -- to achieve more drilling with about the same amount of dollars.

Great.

Thank you.

We'll take our next question from Shannon Nome at Deutsche Bank.

Thanks, good morning.

Nice quarter.

Thank you, Shannon.

Aubrey, you said you're completing a well on the Barnett every 15 hours.

Can you convert that into minutes and seconds?

No.

(laughter)

Indeed I can, but.

Kidding.

So two questions.

One is, wondering how we settled on July gas?

I know you have some swaps that have knockout provisions.

Did we -- how'd that come out?

We won some and lost some.

I'll let Marc discuss that.

Of course, we have now moved into the September contract, so the August contract has moved off as well.

I think July we were just fine, but it was the August contract, actually, as it went off for August that we had some kickouts.

We had moved about $70 million -- 70 million a day, excuse me, of our $6 kickouts into a cash converted position, so we maintained most of those, the $6.50 and $6.25 kickouts were the ones that we lost.

So save some on the $6.

The ones below that, we were okay on.

The $6.25, the $6.50s we lost on.

Kind of reminds you why we do these, and you may know, but maybe some of the other listeners don't.

We've been doing these for over four years now, in fact, almost five years, and of all those months and let's call it 50 months, we've had three months where we've lost any kickout positions.

So in that period of time, by selling an embedded put, we've increased the gas revenues on our positions by in excess of $150 million, while losing, at this point in time, cumulatively, about $25 million.

So a 6 to 1 reward.

And what we're doing is selling volatility and enhancing the gas price that we can receive.

Occasionally, such as the month of August, it didn't work out perfectly, but also remind you that many of those months, had we not decided to go into a kickout, the swap level by itself was such that we probably wouldn't have put the position on to begin with.

So two factors there.

One, we wouldn't hedge as much as we did without the higher level and two over time, it's been very profitable for us.

So August wasn't the best, we continue to monitor September.

Volatility actually remains quite high and we've been surprised at the back of the curve.

We've priced up just yesterday some 10, 11, and $12 calls for '09 through 2012.

You can actually sell a $10 '09 call and receive $1.01 up-front.

So we have quite a few calls that we've sold.

We have some more calls that we're likely to sell that will create cash proceeds and revenue that we think are a good thing for the Company.

But good question.

Okay, thanks.

Just a follow-up on the monetization front.

The upstream sale that you cited, clearly that -- even with all the provisions all in, I'm assuming that's coming at a favorable cost of capital relative to Chesapeake's corporate cost of capital.

Is it safe to assume it's something close to that 5% you threw out on the sale-leaseback, or more in between?

Or what's relative?

I think it's more in between.

We don't know exactly where it will be, but we've been led to think by our selling representative that it's likely to be in the 6.5 to 7% range.

That's not as inexpensive as a sale-leaseback of equipment, which currently is under 5%, but it is less than the cost of debt, currently, which would probably be in the 8.5%.

And, depending on what methodology you use for cost of equity, of course, is almost infinitely cheaper.

Finally, where would the midstream assets fit into all this on a monetization strategy, if they would?

The Midstream, we're just starting to evaluate that part.

We've got kind of a project just to start next week.

We've got heavy infrastructure spends in the Barnett and Fayetteville.

We think that those assets could easily be converted into either a sale-leaseback or some other form of sale.

And our discreet assets have a distinct signature where they will remain under Chesapeake operating control, and there's a billion or more of those that we've spent over, either through acquisitions or through our own new build construction.

So lots of opportunities to do these type of transactions at costs that are fractions of the rates of return that we can earn in drilling.

I think you can probably, as your note pointed out, determine that we're very concentrated on funding the deficit without going out and issuing common equity at this time.

Good to hear.

Thank you.

Next Jeff Robertson with Lehman Brothers.

Good morning.

Aubrey, in the Barnett Shale, you all, I think, are using 2 -- almost 2.5 Bcf in the Tarrant County part.

From the drilling you've done so far, do you think -- where do you think that number goes over time?

I'll turn that call over to Steve.

It's probably going to stay pretty close to that, because we're doing further reach wells off the pads, a little deeper as we go into Tarrant County, it was a little deeper and trying to do longer laterals.

The cost per foot is going down, but we are just drilling more footage.

Jeff, to remind you, our official, kind of overall model for the Barnett is 2.3 Bcfe for $2.5 million and the Tarrant area is 2.45.

And that's with offsets of 500 --

Yes, that's assuming offsets, wells drilled every 500 feet and laterals of about 3,000 feet.

Our first round of wells in Tarrant, are likely to be better than that because many of them will not be drilled on 500 foot offsets.

For example, in the DFW area.

I think most of our drilling there will be close to the 2,000 foot, so we should be able -- are putting big, big fracs on those 2,000 foot offset wells.

I think we're going to get some really big wells out of the DFW area and also throughout all of urban Fort Worth.

So, on the DFW Airport lease, do you all have the infrastructure where you can start moving gas right away, or is there a delay to build gathering in there?

No.

We should have that in place in September when we're just beginning to turn wells on.

Okay, thank you.

Thank you, Jeff.

Next, David Heikkinen with Pickering Energy Partners.

Good morning.

The flat CapEx '08 versus '07, what would you expect your well count to be on that capital budget with declining costs?

And then are you seeing any efficiency gains as well that would increase the well count?

I don't have the gross well count associated with that.

I don't know if Marc or Jeff does.

We reported the gross well count in our press release for this quarter.

And I wouldn't think that that would be much more than 10% greater, kind of this quarter's CapEx run rate is about what we're reflecting over the next six quarters.

I don't know that there'll be too much more efficiency gained, other than perhaps in plays like the Barnett in Fayetteville that would dramatically affect the well count itself.

Certainly, we're assuming slightly lower finding costs through service costs going forward and some efficiency gains, but, unless there's a breakthrough, Steve, do you see it much different?

It's slowly getting better.

It will generate more wells, Barnett well sales.

In the Barnett, we've gone from an average of 25 to 21 days in the last year, but that's increasing our rig count from around 20 rigs to 35 rigs, so, anytime you bring on 15 new rigs and new crews in a new area, you're going to not be as efficient as you're going to be in a year or two.

That's one of the hallmarks, I think, of our company is that we keep so many rigs active in the same place from the same companies that we get very stable crews over time and are able to drive down efficiencies -- or increase efficiencies by driving down our drilling days.

We're seeing big efficiencies as we would expect as we do less science over in the Fayetteville.

Our Woodford drilling times continues to decline in southeastern Oklahoma, and we're doing better and better in our deep plays as well.

Have some new granite wash plays out in western Oklahoma, and then in areas like deep Haley continue to drive down drilling times.

We just reached total depth on our first well in the deep Bossier, and now have three rigs running there and believe it will be able to continue to drive down times there also.

To remind you, we participated, including non-operating wells, at the pace of 950 net wells for the first half of the year.

And that was on an average rig count of about 130.

Our rig count going forward, we estimate to average at least 150.

In the first half we were on an annualized pace of almost 2,000 wells per year on a net basis, with the rig count going up to 150 to 155, on average looking forward, we could expect probably 2500 net wells, I would think, on an annualized basis.

Steve, does that sound about right?

Just trying to make sense from financial, that's just under $2 million a well, which is just about average.

[5 billion].

And then the CapEx increase, the split leasing went up a little more than drilling.

Is that fair?

I'm sorry, what was your question?

On 2007's increased CapEx, looking at that change, is that mainly leasing or leasing and drilling?

Wanted to get the exact split on the dollar amount?

I think probably the leasing activity, including the brokerage activity, which is all of our people working in the field, a lot of that relates -- although it's classified as leasing activity, a lot of that relates to preparing well bores for drilling and title opinions and so forth.

The activity actually on leasing from a dollar standpoint is heavily concentrated in the Barnett, and just as that becomes more mature, it's going to become less of a factor, I would guess, in the future, versus what it has been in the past.

So what I heard, maybe, with the 150, 155 rigs, you'll get some improvement, maybe 10% improvement in efficiency next year as you just keep that rig count running and you would think about that same rig count going into '09, right now with kind of the targeted 10% growth rate in production?

That's where we are.

If you're looking at the standpoint right now, that's right.

Okay.

Thanks, guys.

Thank you.

Next.

Gil Yang with Citigroup.

Morning.

I've got a couple of questions about the Barnett, and then another one as well.

Could you comment on how many locations you're booking with the Barnett to get to that $1.62 per Mcf of drilling costs?

If you said booking, that's PDP drilling costs, that's not a PUD drilling, that does not have a [collect] component in it.

Gil, that was actually the drilling cost of the wells drilled during the period.

Okay.

All right.

So that's sort of a weighted average of the 2.45 and the 1.5 Bcf of wells that you're drilling?

Yes, it is.

Can you give us an idea of what the overall S&D costs are?

Overall S&D costs for what?

in the Barnett.

That's what the $1.62, $1.60 to $1.65 range that I gave you, I believe, during the quarter precisely.

For the Barnett it was $1.62.

I also reminded you that that was before leasehold, seismic and brokerage burdens, which we think are running around 10,000 an acre, and we assume that when we drill a Barnett well it consumes about 60 acres, even though the precise rectangular box that you would draw with 500 foot offsets drilling 3,000 foot laterals only consumes about 35 acres.

There's always some inefficiency of acreage use.

So, at 60 acres at 10,000 an acre, that adds about $0.35 at Mcfe to our refining costs.

So, all in, we think we're just under $2 an Mcfe in the Barnett.

Okay.

As you drill out those, with 2200 new wells in the next four years, I think is the number you said, how consistent is the quality of those wells going to be over that period?

It sounds like you think they should get better in the near term, as you drill more Tarrant versus Johnson?

Yes.

Today we've drilled just under 500 wells and 85% of them or so are in Johnson County.

And while Johnson County has been very good to us, it looks like Tarrant County, with it's slightly deeper geological environment and thicker Barnett is likely to give us even better results, plus in Tarrant we pick up the Viola frac barrier as well, which should help us stay out of Elenburger water.

So while we're not moving up our estimated ultimate recovery yet from the whole play, staying at 2.45 in the Barnett and 2.3 overall, my personal view is that there will be a greater likelihood of an increase in per well reserves over time rather than a decrease given there's more favorable geological attributes of the Barnett in Tarrant County.

At some point, you will cream the best of the Barnett and at what point do you start rolling over and you start deteriorating your average quality?

Remember, our well assumption is based on drilling a well every 500 feet.

So, if you drill wells on 2,000 feet, we actually in Tarrant are seeing per well reserves of around 3.7 Bcfe per well.

If you go then to 1,000 foot spacing, we're seeing 70% of that 3.7, and when you go to 500 foot spacing, you go to another 70%.

So when you blend all that together and get all those kind of wells drilled, that's where you end up with our per well estimates of 2.3 overall for the play and 2.45 in Tarrant.

So we don't really see the possibility that going forward we would do worse than the Barnett.

We actually think we'll likely do better, particularly as the science continues to improve and our our completion skills improve as well.

I think a big part is we've focused our leasing and we're the best, so we won't be diluted through time stepping out to the outer counties.

The other thing is we're not -- people always assume in this business that you can always skim the cream in any play in the beginning.

The reality is you typically drill some of your worst wells in the beginning and then get better over time.

Most of our drilling is being driven by get gas out of urban areas in Fort Worth, where we can get drilling permits, where we have a lease expiration.

So it's not targeted the best areas and we don't, but the best areas are not yet knowable, and there's always going to be somewhat of a random factor -- X factor in a statistical play like the Barnett.

Okay.

Then going to your 2009 balanced CapEx cash flow, maybe you mentioned this, but I missed it, what kind of organic growth rate do you think you could have at that balanced cash flow to CapEx level?

We mentioned that we would probably start our forecast for that year at about a 10% production growth.

Okay.

Last question I've got is for your performance revisions upward, can you talk about whether or not that's a result of having more data about existing areas that gives you more confidence in what you think, or is it better data than improving in the data that you'd seen?

And in what regions are you seeing that these upward revisions on performance?

We have a number of plays that are being very successful.

Our conventional plays, with some high impact areas, we're bringing on large wells pretty much every week, over 10 million a day.

We're drilling a large percentage of horizontal wells, which have good, early production drilled over 200 horizontal wells during the quarter, so that will continue in the future and so we have confidence in our production forecast.

So it's pretty well distributed and sort of a variety of different things happening?

Not concentrated in any one particular sort of either area or type of technology?

Gil, I think it's just widely distributed, but, frankly, it's an element of conservatism on our reservoir's engineer's part.

If you look now, every year since 2001, we've consistently had performance -- positive performance revisions.

Last year they were enough to [overbook] our entire production, as I recall, or darn close to it.

On a base of 9 or 10 Tcf, depending on the time period, now 10 Tcf, now they have a 1/10 of 1% positive condition, you've got some pretty significant revisions coming.

As Steve mentioned, it's just consistently over a broad band and we have 30,000 some wells now.

So we're slightly positive over time with a tail of a reserve, it can positively affect you.

Okay.

Thanks.

Thanks, Gil.

Next, Jeff Hayden with Pritchard Capital Partners.

Hey, guys.

Couple quick questions.

First, kind of jumping back to the CapEx questions, Aubrey, you mentioned you guys are moving more toward a resource conversion stage from a resource capture stage.

I was just curious, going forward out of that CapEx budget, about what percentage of those dollars you expect to be for, kind of, undeveloped acreage, leasehold acquisition, etc.?

I think we've got some pretty good numbers on that Jeff, on page 25 of our press release where we break out our budgeted CapEx.

This is first time we've done it in quite this detail and we've projected leasehold acquisition costs of 6 to 800 million per year for '07 and '08.

Going beyond that, kind of hard to know.

That compares to our drilling CapEx budget of 4.3 to 4.5 billion.

So about 13 to 15% on top of our drilling budget is what we think our recurring leasehold expenditures need to be.

That's not to drill wells on that 4.3 to 4.5 billion that year, it's to continue to have a rolling inventory of 25 to 30,000 wells left to drill in our inventory in the years ahead.

That's what our goal is.

Okay.

And looked like there were about $190 million give or take of improved property acquisitions in the quarter.

What were the volumes associated with that?

We gave reserve volumes and there was very little production associated with it.

Most of the reserves were PUD.

I don't have --

I think about 90% of our year-over-year production growth was organic.

That was Jeff.

Yes.

Okay.

Just a follow-up on that response you gave to Gil about the Tarrant County volumes, that was 3.7 Bs per well at 2,000 feet, and then trim that back 30% to 1,000 foot spacing and another 35% for another 1,000 foot spacing.

Did I hear that right?

Yes, you did.

Thanks, guys.

We'll go next to David Kessler of Simmons and Company.

Good morning, guys.

Good morning.

Just looking at things in terms of being the number one driller, looking at you guys as the most hedged company in 2008 and your early commentary on service cost declines or efficiencies kicking through for the next couple years, can you give us a little bit on your 2008 view of gas?

And, I guess, a little bit on the tail end of '07 given that you increased your hedges there a little?

Well, yes, sure.

We're always nervous about gas prices.

It's our single biggest risk and the single biggest risk factor in gas prices is the weather.

We didn't have much in the way of -- haven't had much in the way of summer weather in some key gas consuming states.

So that of course follows a winter where we didn't have much of winter except for about 30 days.

So we're always nervous about gas prices, and so we'll continue to want to hedge forward a couple of years.

Unfortunately, the gas curve is not similar to the oil curve today where the backwardation in the oil curve is pretty modest on a percentage basis, it's actually pretty strong an a outyear basis in the gas market.

We're also aware that if you think about our 300 million a day of production gain on a year-over-year basis, if you were to add in the fact that we had partners in virtually all of those wells and also we have royalty burdens probably that average about 20% overall, we probably single handily, in this past year, have added about half a Bcf a day of production into the U.S.

gas system.

Going forward, if we continue to think about targets for 2008 over 2007, we'll be adding something similar to that again.

So we've always -- if gas prices were going to go down, we wanted them to go down because of our own production, not because of somebody else's.

And so we felt like we could hedge ourselves against that and it continues to be a real issue for us if we consider our own success in finding gas and what are the implications for that in the marketplace.

We're hopeful, of course, that other people, particularly majors and drillers in Canada and offshore continue to find it a challenge to find new gas and so a good bit of our production growth is offset by those declines.

I think it's really instructive these days to see there are only a handful of companies in the U.S.

that are really driving production growth forward, yet all of these companies are ones that recognized what happens when you apply structurally higher natural gas prices to new geological reservoirs that respond well to new horizontal drilling techniques.

We think we're at the forefront of that movement and accordingly have production gains that are at the top of the industry.

So we'll continue to hedge as we see opportunities to guard against our own production gains.

Great.

Switching to the Woodford for a second, you guys, I guess as the last update had a two to four rig program planned for 2007.

Looks like you're kind of stepping that up or doubling it and a little bit more than that.

What are you guys seeing that's getting you excited about it?

You mentioned earlier on the call that you're actually seeing drilling times decrease, but was just kind of curious about other economics you're seeing?

It's really a tough play.

It remains our most challenging resource play.

I've got some statistics in front of me here.

Looking at the play to date, overall finding costs are running -- this is our own finding costs and those of our partners, and we're in virtually all the wells being drilled.

Finding costs in the play today are over $3 per mcfe and a couple of companies that we track are over $5 per Mcfe.

We can't find another play that's similarly challenged.

At the same time, there is gas in place and our last five wells have EURs of about 2.6 Bcfe and IPs of around 1.8 million a day and finding costs of around $2.80.

So that is not particularly shiny, but at the same time the trend is coming down.

And if we didn't put six rigs out there, we wouldn't be able to hold that production.

All of our acreage, we have about 94,000 acres and continue to add to that a little bit over time.

So we've taken a little different approach from some companies.

We're a little bit more focused in one particular area of the play where we think Woodford is going to work great -- or will work better, sorry.

And we think that $2.80 finding cost can come down over time.

But it's not something that we're particularly proud of at the moment nor are we particularly proud of the industry's performance to date, either, as finding costs are really not economic, even at this point.

Okay.

Then last question, just west Texas Barnett, can you talk a little bit about some of the technical challenges there and how close you guys are to turning the corner on that becoming an economic play?

Well, we're not there yet.

Continue to make progress and the technical challenges are basically to figure out a way to drill a well in either the Woodford or the Barnett or in both and to stimulate those formations in such a way that we can get economic amounts of gas out of it.

We've made quite a bit of progress, costs will come down, we are finding gas, it's just we're not yet at a point where we can call a play of economics.

Steve, we've got how many rigs in the Shale out there?

Two running today, but will be running around five.

Overall.

So we're trying different things in the Barnett and in the Woodford, and again hope over the next several years that we can crack the code out there.

Great.

Thanks so much, guys.

Thank you.

Next, Joe Allman with JPMorgan.

Hi, good morning, everybody.

A question for Marc.

Marc, you talked about the attractiveness of the net settle share convertibles.

I'm not sure if you're indicating that you're looking at doing that.

If so, what would be the use of proceeds?

Are you looking at some acquisitions, or just refinancing, what are your thoughts there?

Joe, it's real simple.

We have bank line that has a little over [$1.5] billion on it outstanding, that's costing us LIBOR plus 1 1/8.

We're not looking at any acquisitions, we haven't done any significant acquisitions for quite some time.

All of the focus is here on the conversion and drilling program.

If we were to do something, and I was mostly reflecting back on just what we had done, because we haven't been on the air waves, so to speak, since we did our net share convertible, the use of proceeds would be to repay bank debt.

And that's an attractive arbitrage, because LIBOR currently around, I guess, 5.5 or so plus 1 1/8 are all in cost of funds to the bank is a little under 7%.

Joe, I think this is clear, but the reason we have bank debt is because this year we are heavily out spending our cash flows.

So the production sale and any curious transactions in the future would be designed towards closing that funding gap between our cash flow and our CapEx.

Got you.

On the acquisition front, I know you guys have made it clear that you're really kind of in harvest mode at this point and you'll make some bolt-on acquisitions, but no significant ones.

Does the MLP market -- I think you've kind of made it clear as well, but does it make you more interested in doing an acquisition because of the tax implementations, if you have a relatively high tax basis, the taxes, of course, would be less.

Can you give me your thoughts there?

Several questions embedded in there.

Just the MLP market by itself isn't forcing us or controlling us to do one thing or another.

I was on a panel this week with some very nice gentleman that have great MLPs.

They're very active in the acquisition market, and I think all of them are looking at the potential to buy properties with a cap rate less than PV-10, because they themselves trade at cap rates that are closer to 6%.

That's not attractive for us.

We haven't made a PDP acquisition in a couple of years now.

Some of the acquisitions that we do that are primarily acreage or almost exclusively acreage will occasionally have some production with it.

But we're not out looking to buy production at those kind of discount rates.

So, we're not interested in forming an MLP, we're not interested in competing with an MLP, we're not interested, generally, in the acquisition market, unless it's a tuck-in acquisition of acreage and drilling opportunities like we've been doing for a couple of years.

We are interested in perhaps selling some properties to an MLP, and I say, perhaps part to an MLP or perhaps a financial player.

We're definitely going to be marketing that very soon.

So, don't want there to be any confusion about what our strategy is here with regard to the MLPs.

They're certainly not driving anything we're doing.

The market for the kind of properties we're selling is very attractive to us and we think that those kind of cap rates or the cost of capital implicit in that will allow us to come back and take advantage of 35 to 50% kind of internal rates on our drilling.

That's helpful.

Aubrey, on the Woodford Shale, just to clarify, has the Woodford Shale in southeastern Oklahoma, has that moved up in terms of your list of attractive projects, or is it still kind of where it was before?

Still right there at the bottom.

Okay.

Could you -- I know in your press release you put out some details on the Fayetteville Shale, but can you kind of give some color on what you're seeing out there in terms of cost and well performance?

Yes.

We've been pretty open with what we're seeing there.

We've been drilling longer laterals than other companies in the play and I think that's now going to become the trend based on what I've heard and read in the last week or so.

I think estimated ultimate recoveries of 1.8 to 1.9 Bcfe are absolutely achievable.

Jeff, do you want to review our Fayetteville Shale numbers for everybody.

We have about 390,000 acres that we consider prospectives in the Fayetteville, and let me go through that with you.

Jeff, do you want to just go through our assumptions?

Sure.

On the Fayetteville, we're assuming on average about 80-acre spacing.

Our risk factor in the core play is about 40%.

That leaves risk net undrilled wells of about 2900.

To date we've booked about 140 Bcf in the play of proved reserves and have about 3.8 Tcf of risked, unproved reserves.

Joe, on a reserve basis, it's something that is the only thing that's out there right now -- well, I shouldn't say only.

It's something that can challenge the Barnett for us in overall reserve add, because we have about twice the amount of prospective acreage.

However, the Barnett tends to have, in the core area and Tier 1 area, tends to have much higher flush rates of production, and so our rates of return are much higher in the Fort Worth Barnett than they are in the Arkansas Fayetteville.

You've got a secondary permeability system in the Barnett that does not exist.

So, what we've seen today in the Fayetteville.

Aubrey, previously, the Fayetteville wasn't very high up on your list as well.

Is there any reason to think that the Woodford might not also move up further as you progress there in southeastern Oklahoma?

Joe, that's several quarters behind.

We've been pretty high on the Fayetteville for the last several quarters.

So over a year ago, it was considered lower on our scale, but last quarter we officially escalated it from an emerging unconventional to a proven unconventional.

And we're working well with Southwestern.

We are in something like 80 or 85% of their wells.

So good information flow, back and forth, and it looks like they're going on longer laterals and also exclusively to slick waters.

So we're expecting really nice results out of the Fayetteville for both us and for them.

Yes, sure, we wouldn't be using six rigs in the Woodford if we didn't think there was some hope.

It's just been a play that's had a long ways to come -- to go, it's come a ways, but it's not nearly competitive with the Fayetteville or the Barnett today.

Lastly, on the Deep Haley agreement you have with Anadarko.

What's the advantage there?

Is it just spreading risks and exposing yourselves to more opportunities?

Well, a couple of things.

They needed a partner to come in and pick up some of their CapEx costs and when it was all said and done, we ended up with about 40 million a day of new production.

We cross conveyed a bunch of acreage in various areas.

So rather than having checker boarded lease positions, we now have a consolidated leasehold position across a good bit of the play.

So this will lead us to remove ourselves from a competitive relationship that we've been in for a couple of years with Andarko into a collegial relationship and we think working together will lead to better finding costs and larger reserve recoveries.

So that's the way plays develop.

You compete hard for acreage, and once the acreage's kind of all settled, it makes sense to try and work together to solve a plays' challenges and that's what this agreement more formally did for us.

That's helpful information.

Thank you.

Thank you, Joe.

Next Benjamin Dell with Bernstein.

Hi, guys.

Aubrey, I had a macro-related questions.

You highlighted earlier on how you believe you're going to become the biggest gas producers in the U.S.

Obviously the MPs have grown as a portion of that.

And the number of the MPs quoted today have reported pretty solid gas -- gas growth volumes and the 914 data suggests that supply looks pretty good on Shale.

Does that change your view on the sort of 2 to 3 trend, especially with the prospect of cost deflation in terms of where the marginal cost of supply is and where the balancing point for natural gas prices will be?

Ben, let me make sure I understood the question.

You said, has it changed my view over the next two or three years in terms of where I think prices will be?

Yes.

I think when we spoke, historically, you had a view that gas prices were in a long term uptrend with the rising marginal costs.

Certainly there's some cost moderation or cost deflation emerging and people are getting more bang from that are buck, so to speak, on the volume side.

I was wondering if that changes your perspective?

Actually, we kind of abandoned that view a couple of years ago once we got into the $6 to $9 range, we kind of felt like gas prices would stabilize in this range.

We thought we would have a very difficult two-year period of rapidly rising costs as the producing and the drilling industry put heavy demands on the service industry and it would take them a couple years to catch up.

That's now occurred, and I think going forward, given the strong onshore demands that companies like our own and XTO and EOG and a handful of Devon, and other companies are driving, we think the likelihood of gas prices continuing to go up from the $6 to $9 range, I think there's really not a risk of that.

I think it's really good news for, I think, the long-term of our business, because I think we've lost a lot of demand over the last few years because of the view that gas prices are going to continue to go up.

I still have lots of discussions with utility executives these days, particularly some that produce or consume a lot of coal and their view is that we're worried about gas prices.

I'm trying to convince them that this rise -- these rise of the Shale plays and the rise of the unconventional plays really takes away this kind of plateau gas prices going forward.

In the meantime, as long as you have volatile weather patterns, we're going to get some opportunities to hedge some gas above that top end of the range.

That's one of the reasons why we're interested in selling volatility, though, that we don't think that with greater LNG importation and stronger onshore gas supply that we're going to be in areas where you can have long-term spikes in gas prices.

I think overall that's a good thing for the gas industry.

Okay.

Great.

Just one last technical question.

Your rig revenue of around 30 million, if I take the, sort of, average day rate of $15,000 a day times by the number of rigs you have, I come out with a number almost 100% plus above that.

Can you explain what the gap is between those?

I'm not sure I understand the question.

Are you talking about our revenues from our service on the income statement?

Yes.

Oh, okay.

You have to consolidate out our ownership of our own rigs.

I think, Steve, we're participating at the rate of about 67% on average across the board.

Our internal working interest, and so, we don't bill ourselves and report that as revenue, we consolidate that out and it goes as a credit in our full cost pool.

So only the portion of a well that our rigs are drilling on that's operating by us, that portion that's owned by a third party, a non-operating working interest, in other words, is revenue for us.

Okay.

Great.

Thank you very much.

We'll go next to John [Masslink] at [Deshaw].

My question is, at what price basis, [Henry Hub], would you consider your marginal gas production uneconomic and what actions might you consider taking were prices to fall to that level and stay there for say six months or so?

A couple components.

I'll take the first part of that.

The level of pricing at Henry Hub at a play would be uneconomic would vary widely, depending on the location of the gas.

Remember, we've got gas that stretches all the way from New Mexico to the east coast.

Gas prices in Appalachia, for example, have a basis that's $0.30 positive, and there would be virtually no price at Henry Hub that those wells wouldn't be economic to continue to produce.

On the other hand, to contrast that last September we shut in production when gas in the mid continent was under $4 and at the time the October contract had gone off the board at the end of September at about $4.10, and with basis differentials over $0.50 or $0.60, a lot of our mid continent production was down in the mid $3 range, and we elected to shut in that portion of the production that was not hedged.

Our action would be that we would consider shutting in gas production that wasn't hedged and it would vary from play to play as to what the economics would be.

In some of our lower rate of return plays, like the Woodford in southeast Oklahoma, if you were considering drilling economics, then I would say that play at $5.50 or $6 NYMEX is a fairly low rate of return play, and might even be considered break even for drilling purposes, but that's a different answer with regards to continuing to produce gas that's already been put in place with the lifting cost in our company on average are only $0.90.

And the second part of the question, maybe Aubrey, you want to talk about?

There's almost no scenario that we see where gas would be at low levels for six months.

And the reason is depletion rates.

Overall depletion rates are probably pushing 35%.

If you were to get a period of low gas prices, I think you would starve some producers out, drilling rig counts would go down, depletion would kick in, and we're back to balancing the market.

It's really hard to grasp the power of depletion because there's so few other industries that have anything similar to it.

So we view depletion as always our enemy, we have to overcome it, but it's also our friend as well.

Thank you.

Next.

David Reynolds at Tribeca.

Mr.

Reynolds, your line is open, sir.

Okay.

We'll go next to Monica Verma at Gilford Securities.

Hi.

I was wondering if you guys, given your deep well experience in for large acreage and Appalachia if you guys could just sort of give us a little bit of color on what your feelings are for the potential in the area and the cost of horizontal wells, etc.?

Thanks, Monica.

We're very excited about being in Appalachia.

We have close to 4 million acres of leasehold.

When we made the acquisition, we felt like there was a great deal of upside.

The area's produced about 50 trillion cubic feet of gas from various Shale formations, and felt like nobody had really ever gone with modern exploration techniques.

So we continue to shoot a great deal of seismic, our goal is 300 square miles of seismic a year.

We're going to start drilling some deep and some ultra deep wells in 2008 to test some of our geologic ideas.

We also kick off our horizontal Marcellus drilling program in the next few weeks.

So this is going to be an exciting time over the next several years for our Appalachian division as we move from just drilling kind of traditional vertical Devonian wells into wells that have a great deal more upside than what's traditionally been associated from drilling returns in the area.

Cool, thanks.

Thank you.

There are no further questions at this time.

Okay, great.

Well, we appreciate your participation on today's call.

If you have any further questions, please call Marc or Jeff.

Thanks a lot.

Bye-bye.

Thank you.

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