Chesapeake Energy Corp (CHK) 2006 Q2 法說會逐字稿

Good day, and welcome to this Chesapeake Energy second quarter 2006 conference call.

Today's call is being recorded.

At this time for opening remarks and introductions, I would like to turn it over to the Senior Vice President, Investor Relations and Research, Mr. Jeff Mobley.

Please go ahead, sir.

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

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

The statements I describe are 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 18 through 21 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 remarks this morning should last about 15 minutes 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, joins us from out of town; while Steve Dixon, our Chief Operating Officer;

Mark Lester, our Executive VP for Exploration; and Jeff Mobley our Senior VP of Investor Relations and Research, are all with me here in Oklahoma City.

I hope by now you've had a chance to review our results for the second quarter and also hope you agree that Chesapeake continues to hit on all cylinders.

Our drilling program is working great, and so is our acquisitions program, our natural gas hedging program, our cost control program, and so are our investments for the future in more employee talent, more science, and more leaseholds.

Let me highlight some of our recent successes in the various programs that I just mentioned.

For starters, we're pleased to deliver a 64% year-over-year increase in adjusted fully diluted earnings per share, an achievement that I believe will rank at or near the top of the industry this quarter.

I also hope you noted that Chesapeake's production was up for the 20th consecutive quarter.

I believe that only XTO has equalled us in that statistic during the past 20 quarters.

I trust you'll recognize what an incredibly difficult achievement it must be if only two public companies in the entire industry have been only able to grow for 20 quarters in a row.

I might also remind you that 20 quarters ago Chesapeake was producing only 395 million cubic feet equivalent per day.

In the past quarter, Chesapeake produced 1.568 Bcfe a day, so we are a four times bigger Company than we were five years ago, and yet, despite that vastly larger size our growth rate remains among the highest in the industry.

In the second quarter our production was up 26% year-over-year and 3.2% sequentially.

The 26% year-over-year increase was generated 55% from acquisitions and 45% through the drill bit making our trailing 12-month organic growth rate 12%.

The 3.2% sequential quarterly production growth was generated 95% from the drill bit and only 5% from acquisition.

In the past, some of you have asked for an acquisition three quarter to double-check our organic growth rate calculations and so here you have one that was in fact, virtually free from acquisitions.

As you can see, our quarterly organic growth rate was 3.1%, a remarkable achievement in our view and one that makes achieving our 10% organic growth goal for the year very reachable.

Furthermore, we expect to deliver at least a 10% organic growth rate for 2007, as well.

In addition to delivering very strong production growth so far this year, we are also generating impressive gains in proved reserves growth.

During the quarter, our proved reserves increased 4% from 7.8 tcfe to 8.1 tcfe, and, perhaps more importantly our unproved reserves increased even more, from 9.2 tcfe to 14 tcfe.

During the quarter, our reserve replacement was 308% at a drilling and acquisition cost of only $1.80 per mcfe.

As we stated 90 days ago, our hope was to end the year with at least 8.5 tcfe of proved reserves and to keep our drilling and acquisition costs inside of $2.25 per mcfe.

It looks like we'll probably achieve both goals.

Once again, our hedging programs work very well also.

In the first quarter of 2006, we collected $248 million in cash as a result of our well-designed hedges.

In the second quarter, we collected even more, $257 million which raises our hedging gains for the year to $506 million, or $1.81 per mcfe.

I would like to remind you that at Chesapeake we pay at least as much attention to managing our revenue structure as we do our cost structure.

While we do not expect future credit for having astutely hedged in the past, we do hope that in time investors will more fully appreciate how successfully we have mitigated commodity price risk at Chesapeake over the years.

We believe it is a very under appreciated aspect of our management skill set.

As importantly, we have taken virtually all commodity price risk out of the Chesapeake business model for the second half of 2006 and have significantly reduced such risk in 2007 and 2008, which will likely help our Company achieve margin expansion while others in the industry may have to endure margin compression.

Just to remind you, we have 90% of our expected natural gas production hedged in the second half of 2006 at 917 per mcf, 72% hedged for 2007 at 988 per mcf, and 57% hedged for 2008 at 937 per mcf.

I have heard that we often traded a proxy for natural gas prices.

In fact, I noticed last week that we were approximately America's 200th largest public company, and yet we are one of the top 30 shorted stocks in America.

I presume this is because we have the greatest exposure in the industry to potentially lower natural gas prices.

Let me remind investors again that Chesapeake is not just a proxy for natural gas prices.

Instead, we a are highly profitable, low risk, high margin gas manufacturing Company that has very limited exposure to commodity price risk for at least the next two and a half years.

In addition, we have a top of the industry organic growth track record and double digit future growth potential.

Plus we have an industry leading gas resource position accompanied by favorable drilling rig arrangements.

We hope you also noticed that in addition to successfully mitigating oil and natural gas price risks, we have also been very proactive in mitigating our exposure to higher drilling costs.

The first tangible reward from that program was the sale in the first quarter of our Pioneer drilling stock for a gain of $117 million.

Behind Pioneer we have two other private drilling company investments that one day will be harvested.

We hope for similar type gains.

Just to remind you, these drilling companies are mountain drilling where our partner is Lehman Brothers, and DHS Drilling where our partner is Delta Petroleum.

Furthermore we're continuing our buildout of our 100% owned drilling rig subsidiary, Nomac Drilling, and by the end of the 2007 first quarter we should have 79 drilling rigs owned by Chesapeake which we believe will then be one of the six largest drilling rig fleets in America.

Literally we have built this very valuable rig fleet in our spare time in just the past four years.

Were we to monetize that operation today we believe we would be able to harvest a several hundred million dollar gain.

As to our drilling operations, since we have locked in our revenue at very high levels and have successfully mitigated our exposure to further increases in service costs, we believe it is the right time to continue accelerating development of our 10 plus year backlog of drilling opportunities.

Keep in mind the industry's acreage land grab that has occurred in the past five years is largely over.

Virtually every conventional and unconventional gas resource play in the U.S. is totally locked up.

The winners for the next 10 to 20 years have already been chosen and the losers will pay the price for years to come for being left behind.

History has shown that Oklahomans did very well in the land run of 1889.

I believe that history will also note that Chesapeake did very well in the land run of 2000 to 2006.

As you're thinking about the scale of our prospect inventory and the scale of our present planned drilling program, please keep in mind that it has been 21 years since a company in our industry has operated more than 100 drilling rigs.

Way back then both Amoco and Exxon did it.

Chesapeake has now reached that level with 101 operated rigs and is accelerating even further.

As I recall at that time Amoco had 3 million net acres of leasehold.

This was widely considered the largest leasehold position in the industry at that time.

By comparison today Chesapeake owns 9.7 million net acres on which we believe we could drill as many as 24,000 additional net wells where there may be an additional 14 tcfe of highly risked, unproved reserves to accompany our 8.1 tcfe of proved reserves.

I hope that you noted in our release that our risking factors are very conservative.

In plays such as the Fayetteville shale and the Deep Delaware, Woodford, and Barnett shales we have applied risk factors to our acreage at 85% and 90%, respectively and have used very conservative wealth-basing assumptions.

If you are curious about our unrisked, unproved reserve number, which is a common number thrown around by some analysts about other companies, ours is a mind boggling 56 tcfe.

Keep in mind the numbers should be mind boggling.

We own more leaseholds onshore and east of the Rockies in the U.S. than anyone else in the industry.

The best news for our shareholders, I believe, is that they get all that upside virtually for free given the TB10 value of our proved reserves using a 7.50 per mcf flat price deck plus the $1.8 billion net book value of our non-oil and natural gas reserve assets essentially equals our enterprise value today.

As you know we don't trumpet our individual well results because we don't like to tip off our competitors to anything that we're doing.

We also believe what really matters are the actual proved reserves and production results themselves which should show consistent growth quarter after quarter and year after year.

However, this quarter, in a break from our usual format, we have provided significantly more operating detail on the Company's production, reserve levels, drilling activity, and drilling ramp-up plans and acreage upside in some of our most important operating areas.

I hope you've had time to study that disclosure in detail, but the short version of the story is that in the last few years we have built the top three positions in virtually every significant conventional and unconventional gas resource play in the U.S. east of the Rockies, and you basically get it for free given the net asset value map I just provided to you.

I believe the depth, the breadth and the diversification of our inventory is unmatched in the industry today.

I further believe that the combination of talented employees, cutting edge science, and the immense inventory of leaseholds that we have acquired in the past few years have helped further differentiate Chesapeake's performance in the years ahead.

I encourage you to study the disclosure about the upside we have captured and described to you on pages 7 to 11 of our press release.

I hope that you'll understand why we believe Chesapeake's upside story is the best in the industry, and especially so when such upside is as conservatively presented as ours is.

In conclusion, I love Chesapeake's competitive position in the industry and believe that in the second of 2006 and throughout 2007 we will continue to power forward in executing our distinctive and successful business strategy on behalf of our investors.

I would also like to acknowledge that without your capital we would not have been able to produce the 24-fold increase in our stock price in the 13 years since we went public.

I can assure you that Chesapeake's management team appreciates your support of our Company each and every day.

I will now turn the call over to Marc for his review of the quarter.

Thanks, Aubrey and good morning everyone.

My comments this morning will be very brief as we attempt to include all relevant detail in our press release and outlook.

A few items warrant amplification, though.

Aubrey touched on our hedging position and for the first six months of the year we have enjoyed enhanced revenue of $506 million, more than we would have had had we been unhedged.

However, I want to point out that this does not include an additional 430 million in unrealized gains that we had as of June 30, related to our open hedge positions for that time.

This is a value creation in the first six months of the year of nearly $1 billion from our hedging program.

In fact, from inception to date when we began this hedging program back in late 2000 the Company, while significantly reducing risk all along that time period, has had positive revenues from our hedging program.

Second, I want to highlight our positive reserve revisions of 351 bcf equivalent so far this year.

To put this in perspective, we had 7.5 tcf of proved reserves to begin the year and, therefore, these positive performance revisions amount to 4.7% of those beginning reserves.

Said another way, compared to production of 279 bcf year-to-date the revisions are 125% of year-to-date production.

Hopefully, this emphasizes the conservative nature of our reserve bookings.

I believe we are going on our fifth year of positive performance revisions.

A few accounting details.

Capitalized interest for the quarter just ended was 38.6 million, that compares to 17.9 million in the quarter one year ago.

And year-to-date just under $70 million at 69.9 million capitalized compared to 33.9 million last year.

Our capitalized internal costs related to our extensive drilling program for this program for this quarter were 34.0 million as compared to 23.5 million last year, much less of an increase than the drilling activity picked up.

Year-to-date we've had 68.7 million of those costs capitalized in our full cost pool against 45.8 million last year.

As a result of our recent successful stock and note offerings our bank credit facility had 0 liability as of June 30, 2006, or $2 billion in total availability to the Company.

There was some white noise in a few of our income statement items this quarter.

Texas during the quarter changed the method of calculating its franchise tax and began to apply a new law, or a margin tax, that is applicable to our operations in Texas.

While this tax is not effective until 1/1 of '07, FAS 109 requires any company to make an adjustment to the methodology in the quarter the tax is adopted legally.

So we've increased our effective tax rate slightly going forward.

We expect to have nominal cash taxes beginning in 2007 as we pay Texas and some other, perhaps, other state income taxes less than a couple percentage of points certainly.

For federal income taxes though, I'd like to remind you that we currently do not pay any cash taxes and based on an $8 gas price forecast do not expect any cash taxes to be paid to the federal government until 2010 at least.

This change is projected to reduce Texas ad valorem taxes, or at least by the politicians there, which we characterize in our income statement as production taxes.

So these actually could be a positive cash savings on a net basis going forward but that remains to be seen.

Our G&A expense was up slightly this quarter as the result of some, hopefully anyway, non-recurring legal accruals.

Without these expenses our G&A would have been $0.15 per mcf equivalent.

These were offset by a positive legal development related to production taxes where we had been accruing for a potential interpretation of state severance taxes that was held not to be necessary during the quarter.

In either case, we are not expecting significant changes in any of these items going forward and, therefore, as you see in our new outlook our guidance is basically unchanged in all of those areas.

Moderator, I'd like to turn it over to questions, please.

[OPERATOR INSTRUCTIONS] Our first question will come from Brian Singer of Goldman Sachs.

Good morning.

Good morning.

In addition to mitigating any potential rig rate inflation to what extent does the acquisition of additional rigs in Appalachia allow for faster drilling, and how do you expect that this will all be allocated between the different play types, maybe if you can give an update on the different play types and anything in the last quarter?

Okay, thanks, Brian.

The drilling contractor that we bought had 15 rigs, of which two, I believe, we are using in our own operations there.

What we wanted to do was accomplish two things.

One, as we accelerate our shallow drilling program in the years ahead that we would have ready and steady access to the type of rigs that we needed.

It's been our experience in this part of the country that it's been very, very helpful to run our own rigs.

We felt like that would be the case in Appalachia, as well.

The second reason that we acquired the Company is that we needed a platform from which to launch some rigs that had deeper drilling capabilities.

As we get going in Appalachia we're going to be drilling more medium and deeper depth wells.

And the rigs available for those type wells are quite small.

Through this new drilling platform we have out there we'll either build or buy some deeper rigs that will enable us to go forward with a more aggressive, deeper drilling program in that area.

As to play types, Appalachia has it all.

We have a whole suite of conventional plays.

We have unconventional plays, many of them in shale but also many of them in tight sands, as well.

We have some emerging ideas, and then we have some deep ideas, as well.

We also have a fairly significant coal bed operation.

So it's a large area extending from southern New York down to northern Tennessee, which if you're a geography buff that's farther than Tulsa to Houston, for example.

It covers a large area of the eastern U.S.

We are pursuing a large number of play types there and are excited about the growth potential of the CNR assets plus what we have been able to buy off the ground since we closed on that transaction.

When would you expect to begin testing deep opportunities and, separately, what production rates are you expecting at the end of the year at Appalachia overall?

You may recall that we inherited a deep drilling program that CNR had with Talisman.

We basically shut that down pretty quickly after taking it over because it was designed around, to [INAUDIBLE] which in our view was producing sub-optimal results.

We now have three large 3-D seismic programs that are under way and should be completed in the first half of 2007.

Between the third quarter of this year [INAUDIBLE].

Mark Lester chiming in with our 3-D seismic update.

So, Brian, once those are in and interpreted, we'll kick off a deeper program.

I would suspect it's the second half of 2007 before we really probably get serious, can get serious about our deeper drilling program.

We don't produce area by area production targets.

So we'll just say we're doing fine in Appalachia with our production, when we bought it we told people and we remain consistent with that advice today we wouldn't see big growth out of Appalachia until 2007.

If I could just ask one more, switching to the the Delaware Basin you put out some estimates in terms of well costs and more importantly ultimate spacing and per well rates.

What level of confidence do you have in that?

And if you could give us an update, I guess there's about 1 million a day of total production right now.

We have a high degree of confidence that we've been exceptionally conservative in what we've laid forth.

We have basically said out of our 385,000 net acres of leasehold we believe 90% of that acreage will prove to be nonproductive.

I believe that's pretty conservative.

We have talked about using spacing unit size of 160 acres.

We've seen some estimates from scientific work that maybe 40 acres is the right spacing for vertical wells.

The jury remains out and will be for some time as to whether or not this is a vertical play or horizontal play.

It's likely different parts of the play will respond differently to different types of drilling.

Steve, you want to go through what our drilling activity is there to date?

Two rigs that we got from [Hallwood] that are drilling.

We have a couple wells that need completion.

So we're, a lot of science going on.

Initiating 3-Ds.

It's very, very early.

Mark Lester, how many 3-Ds do we now have planned for the Delaware?

I think it's three.

We have three currently planned and currently being permitted.

Brian, we're out there and, you know, right now, again, just what we've seen is we've seen five wells that have been completed, none of them properly.

All have had frac jobs that are inconsistent with the slick water fracs that have been working so well in the Barnett and now working so well in the Fayetteville, so what we do know is this, there's an enormous amount of gas in place.

You've got a Barnett, Woodford section and in some places exceeds 1,000 feet thick and it's three times thicker than what we see in the best places in the Barnett around Fort Worth.

We're excited about the potential of the play.

We are producing gas.

We have two producing wells making about 1 million a day, as we disclosed in here and we do have two rigs operating.

So it's just one of these areas that, again, I think if we were a single play Company, people would be ascribing value of tens of dollars of stock value to this asset.

We have a more broadly diversified portfolio and have been pretty careful about our upside assumptions.

I hope you can begin to grasp here as we lay this out just how significant this play could be for us in the future.

Thank you very much.

Thank you.

We'll now here from Jeff Robertson with Lehman Brothers.

Aubrey, as a follow-up to Brian's questions about West Texas, how long do you think it takes out there to move from a lot of the preliminary work to more, or knowing enough to move more toward a development phase?

That one year, two years, three years?

Jeff, it's probably unknowable at this time.

I think you can look back at Johnson County, Texas, and consider the experience there.

You may recall in our Hallwood One acquisition which we closed in November of 2004, I believe, if I can recall that correctly, they had drilled 20 or 30 vertical wells in 2002 and 2003 in Johnson County before making the switch to horizontal drilling.

Clearly, they were pioneers at that time.

They also, by the way, have been pioneers out here as well in one of the acquisitions we made which requires 60% of Hallwood's leasehold out here in the Delaware Basin.

Clearly, we as an industry will move more quickly to kind of crack the code out here because of the experience we've had around the Barnett in Fort Worth.

And I think for that matter in the Woodford in Oklahoma, and the Fayetteville in Arkansas.

I don't think it will be a bright line that we cross, and say, here we are and we've got it all figure out.

I think like most plays it will be a series of steps we take.

Those steps are all going to be taken through the drill bit and through completion.

We have two rigs out here.

I think by the end of the year we get to three rigs.

That will again -- four rigs actually, four rigs.

That will start bringing in the data points pretty quickly.

We're going to be drilling vertical wells, we're going to be drilling horizontal wells.

A broad base, a broad stream of information will be coming into us.

Plus, we are a partner of three other companies out there so we'll be gathering information from their results, as well.

Secondly, Aubrey on your other assets line, on your net asset value, you've got a value of about 1.5 billion, or that that includes Midstream, can you say how much of that number is actually Midstream assets?

Marc, do you want to handle that?

Yes, I misread that, Aubrey.

I think on our balance sheet to have other assets of $1.5 billion Jeff was pointing out.

He wanted to know how much of that was Midstream as opposed to perhaps other types of assets like drilling rigs or compressors or something like that?

I'm looking to see if I have that detail in front of me on that right now.

Let me get back to you on that, Jeff.

Okay.

I think it's less than a $1 billion, but more than $500 million, that's kind of a wide range.

I think Marc will be able to pin it down here before too long.

Just on a quick follow-up on that, Aubrey, how much of those assets are dedicated to CHK production versus handling third-party volumes, as well?

Do you have a feel for that?

We make some money handling third-party volumes.

You can see that in our marketing if you look at our income statement.

Marketing sales for the -- for six months was $772 million against marketing expenses of $747 million.

So I think that's $25 million of profit for the first half of the year.

So we'll make about $50 million handling the gas of third parties.

That is not because we built systems out into areas where we're not.

It's simply that in most all of our wells we have third-party gas and charge a fee for moving that gas through our pipeline.

Our Midstream operation is completely designed to service just these wells.

It's a much lower rate of return.

Investments in drilling wells but sometimes it's an investment we have to make.

For example in the Fayetteville, there's nobody over there to go build gathering systems.

So we're doing that ourselves.

And to the extent it means we gather some third-party gas we'll make some money at it.

We always will have the option if we wanted to of spinning that out and having it valued in the 12 times EBITDA rather than at five or six times EBITDA inside our own Company.

Jeff, I have a little bit of detail on this for you right now.

The undepreciated value as of June 30 of what we call property, plant and equipment was $1.3 billion.

The most important segment of that was our drilling rig equipment where we had investment of $368 million.

That does not include any investment in either Mountain or DHS.

The field equipment then is actually broken down into two categories, but it totals just under $500 million, about $490 million.

Trucking was $30 million.

Our other field equipment and so forth was $200 million.

And the rest of it was our office buildings and various field offices and land and so forth.

Jeff, one other thing.

The number that I gave you, I guess I anticipated four sevens Midstream being in there and we didn't close that until July.

Actually we closed -- I think we closed it today.

That's another 55 million, right?

Yes, you're right.

Jeff, anything else?

No, that's it.

Thank you.

Thank you.

Moving on to Wayne Andrews with Raymond James.

Good morning, gentlemen.

Impressive results and disclosure.

I applaud your efforts to detail all your future resource potential.

I was wondering, is there an implicit long-term natural gas price that you used when you were factoring in that future resource potential?

Thanks, Wayne.

Appreciate your comments and observations.

The Company uses a matrix of prices for evaluating all of our drilling operations and our acquisitions.

That matrix starts at $6 per mcf and then we multiply that by 750 to get the equivalent oil price.

We go as high as $8.

So basically test everything we do in between a flat price range of $6 to $8 with the accompanying oil prices at 7.5 times the gas prices.

Very good.

That was helpful.

Thank you, Wayne.

Thank you.

We'll now here from Shannon Nome with Deutsche Bank.

Thanks.

Good morning.

Aubrey, I was curious to get your thoughts on EXCO's recent MLP announcement.

I was thinking concerning the cost basis of your Appalachia assets.

Is that something that could be in the cards for you guys down the road?

Thanks, Shannon.

I'll let Marc take a whack at this, too, but I would just say that it certainly highlights kind of the optionality embedded in our assets.

I've known Doug Miller like like maybe many of you all for years.

This is something he's wanted to do for a long time.

I'm highly complimentary of him taking a stab at doing it.

I'm hopeful it doesn't reprice assets in the acquisition market.

Of course, I wouldn't mind if it reprices EMP assets inside companies like our own.

It's an interesting model, we have assets not just in Appalachia, but we have assets in east Texas and western Oklahoma, in the Texas panhandle.

We think in all three out of Appalachia that would fit this model.

We have the option of doing so.

Whether or not we move forward with it remains to be seen.

Certainly, we'd like to see how EXCO does with their plan, but, Marc, you may have studied it a little more in financial detail --

Well, hi, Shannon.

We have certainly studied it off and on and of course many investment bankers have brought these ideas to us.

Generally we've concluded that these are generally too small to be of significant value to Chesapeake given the scale of our operations.

They're generally a retail-oriented product.

Most have said that to be successful they're going to be in the $200 million to $300 million or $400 million size with none really that I'm aware of being much more than $500 million.

We'll see how big Doug's gets to be here.

There were rumors out even for us this week that we were considering doing some type of a Midstream or MLP type of action.

That's just not true.

We don't have that under consideration right now.

Thanks, Marc.

Just a quick follow-up.

Just scanning down the list of your emerging unconventional gas resource plays that you went through in your release, it looks like on a simplistic F&D basis the one that seems the most challenged is still the Fayetteville shale.

You cited $2.5 million cost to drill.

Where do you see that going directionally, I mean, does that bake in slick water fracs?

What do you think can be done to improve the cost profile there?

Probably the cost profile is one that will be the most difficult to work on.

I think the most promise for that play is higher reserve recoveries.

I haven't had time to study Southwestern's most recent announcements.

I think they were somewhere in about the 2.1 bcfe, I'm sorry $2.1million for about 1.4 bcf.

1.4 bcf.

I will tell you the last map I saw were that the 10 most recent horizontal wells, slick water fracs in the Fayetteville including Southwestern's and our wells shows about 1.6 bcfe.

We have a well there called the ET gentry which is now about a 2.5, 2.6 bcfe well.

I think it's one of the two best wells drilled in the play to date.

Falling back, the well called the Barker right now that looks pretty strong so --

Directionally?

Yes.

I think it will be tough to drive the well costs down too much more.

But certainly I think there's a lot of upside for us in the pro well reserve, anticipated reserve recoveries.

That's just through getting the frac right or do you think there's the ability to drill a little closer than 80 acres?

I think it's all about putting your well bore in the right place in the Fayetteville.

We're the first company to start logging the entire horizontal well bore.

We're now being more selective in our performance, not just random layers, every few feet perforating we're now being more selective as to how we complete.

Certainly, as we get going we will understand more about frac responses.

We're certainly doing a lot of micro seismic work here. 3-D seismic is also going to be important.

Mark, how big is our first --

First shot is 130 square miles, planning stage of an additional 150 squares.

I think by this time next year we'll have 280 square miles shot.

This will enable us to direct our well bore into precisely this spot in the Fayetteville that we want it to be.

I think we all over there have found that it's a little more structurally complex than what we had anticipated.

Our first horizontal well, for example, which is a very modest producer, we now have determined was largely drilled out of zone through faulting.

Lot of science left to do there.

It's been very helpful to us to be able to transfer the knowledge from the Barnett, our knowledge from the Woodford in Oklahoma, and now our knowledge from the Barnett in west Texas to be able to bring all those scientific resources to bear in trying to crack the code in Fayetteville.

Got it.

Thank you, Aubrey.

Thank you.

Moving on to David Heikkinen with Pickering Energy Partners.

You just prompted one specific question.

The 1.6 bcf on the last 10 wells, is that a net number to Chesapeake?

No, that is a gross number pre-royalties.

Can you give us apples-to-apples of what that means to the 1.2 bcf net in the summary or is that 1.2 bcf gross in the --

All these are pre-royalties.

So it goes from 1.2 to 1.6?

Just trying to make sure I understand that.

Kind of get back to Shannon's point.

She's right.

We've been saying this for months.

The play, while it's significant in scale, just based on the results to date, as we said last quarter it's not in our top 15 list of plays.

And it's still not.

But it's starting to nudge up a little bit.

If we can see enough performance and do enough science to improve the -- where our drill bit heads and how we complete those wells and if we can get those wells to 1.6 bcfe, rather than 1.2, it becomes a more interesting play.

You might also notice that we said 85% of our acreage there will ultimately prove to be no good.

I think that is very, very aggressively conservative and gives us substantially more upside there than I think people give us credit for.

Just to put that in perspective.

With only 15% of our acreage being worthwhile or valuable and only using 1.2 bcfe per well we still have 2 tcfe of upside in that play.

Yes.

Kind of thinking along those same lines and compliments to you for all the detail on each of the areas, have you looked at how Chesapeake ranks on efficiency, drilling days, F&B costs, those types of things versus the peers, along those same lines of how you'd rank yourself as far as activity and production?

Sure we're America's most active non-operator, as well as America's most active operator.

And that would see more peer information than we do and we benchmark ourselves all the time.

For example, we've been spending a little more money in the Fayetteville than others right now.

We've still been drilling pilot wells as we want to see the whole Fayetteville vertical section.

We've been taking a lot of core work.

We generally cut more cores than anybody else in the country because we see more shale every day than anybody else in the country.

We've been doing -- our work to date in Fayetteville has been a whole lot of science.

Again, it's not been necessary for us to prove a valuation model to everybody because no one gives us any credit for the Fayetteville so we've been free to do what we want to do, which is to make sure we build a strong foundation of science and then we can take it into commerciality if the science supports that going forward.

Certainly, our Barnett Shale results we'll stack them up against anybody's at $2.7 million to find 2.4 bcfe.

That's on pretty wide spacing there, 55 acres as opposed to 35 acres.

We're good at what we do.

And we compare ourselves every day, sometimes we're cheaper, sometimes when we're more expensive it's generally because of a greater commitment to science.

And whenever you think about things, is there a goal to be top one or two on each of the areas as far as costs and efficiency?

Or what do you think about as far as getting into an area and establishing it as a dominant position?

Well, couple things.

First of all, we're paid to generate the highest risk adjusted returns to investors in the business.

We're always striving to achieve that.

Cost is only one side of the equation that we don't always aspire to be -- to spend less money than somebody else in a play.

We're all about ultimate recovery.

And if that means we spend a little bit more to do it the right way, we think that gives us greater reserve recovery over time then we're certainly going to go that way.

We can afford it and be the right way to develop certain plays.

When it all shakes out, we think when you think about our acreage positions, which we tend to get too early, and when you think about the science that we can apply the ultimate reserve recoveries and our costs, we think that we're always in the top of the industry in any of our plays and our aspiration is always to be number one in those plays.

That's just the corporate culture and the way it's always been.

Whenever we reconcile numbers of both corporate level, F&D costs, operating expenses versus trying to reconcile versus the numbers of each one of these plays Chesapeake always seems to drop down a little bit on the corporate level.

Why do you think that is?

A couple reasons.

One, we more aggressively move acreage I think into our full cost pool than perhaps some other companies do.

We burden ourselves with seismic and acreage costs that go into our full cost way before the reserves go in.

You also might have noted goodwill on our balance sheet.

There are other companies in the business that have billions of dollars of goodwill.

If you were to throw their goodwill into their cost pools you might come up with different returns on capital invested, so we have recorded hundreds of millions of dollars of tax-based step-up costs for example that wouldn't be captured in these play economics.

A billion dollars up.

Over $1 billion of tax-based step-up that other companies would have stuck in goodwill that we go ahead and fully load into our finding costs.

That helps.

Thanks a lot, guys.

It hurts, actually.

Well, I understand.

In our view, there is no such thing as goodwill in this industry.

If you want to compare apples-to-apples in companies you have to adjust for these companies because there's a lot of goodwill with regard to your acquisitions.

It's simply a way to artificially manipulate some the returns from some of these investments.

Thanks.

Thank you, moving on to Ben Dell with Sanford Bernstein.

Hi, guys.

I'm sure Conoco's chief accountants are loving you at the moment for your comments on goodwill.

Yes, they probably loved us before, too.

I had a couple of quick questions.

There's been indications that rig rates have been suffering in the mid-continent region.

I was wondering if that's something you've been seeing of more rigs becoming available.

My second question was around the Delaware Basin, again, EnCana talks about they've farmed out some of their position.

Do you think that's due to the fact that I have seen something they don't like or some other reason?

I'll take the second part and let Steve talk about the first part.

I'm looking at a map on the wall of our acreage position in the Delaware and EnCana's position.

They have some nice acreage.

They have some acreage we're not as crazy about.

They may say the same thing about us.

It's hard for me to say.

I will say, though, that we've not seen their well results to date.

We have seen they're going to offer some of our acreage up for joint venture.

That probably makes sense.

They have 540,000 net acres in the play.

It's the largest commitment to the play to date.

We have 385,000 net acres.

I think that's the second most.

Our acreage come from a combination of acquisitions off the ground, as well as we've made deals with three private companies, one of which sold us 50% of what they had, one of which sold us 75% of what they had, and the other sold us 60%.

So we're in joint ventures throughout the basin.

I think one of the things that anybody would recognize there is the potential enormity of the play, as such, that it's difficult for any one company to say that they can take it on themselves.

I think these companies recognize that as the most active shale driller in America, we brought a lot to the table for them.

So in time we'll talk to EnCana probably about their acreage.

I'm sure other companies will, as well, and we'll see what happens down the road.

We do like to have a diversified acreage position across it.

I'll let Steve talk about potential weakening of [INAUDIBLE]

We're starting to see a lot of marketing by the contractors and so I take that as a strong sign of weakening.

I haven't seen prices go the other direction.

Seems like there's more rigs available.

We're getting a lot of calls and hear our partners are getting a lot of calls also.

We're marketing some rigs.

Great.

I just have a couple of follow-ups.

Given the amount of hedges you have in the clarification on your cash flow, where would you put the upper range of your, that you'd be willing to take your debt-ex ratio to follow along with additional acquisitions?

Marc, you want to handle that?

Yes.

I think that you probably would just continue to see us about the same levels that we are today.

We've talked about any acquisition being done fundamentally over a period of time based on a 50% debt, long-term debt, and 50% equity.

Some of that equity is being grown every day in the execution of our business strategy.

You saw recently that we funded more than 50% of the recent acquisitions with equity because we hadn't used any equity this year.

We think that the -- if you're looking at it and thinking at it from a book capitalization standpoint, which I'm not encouraging anyone to do, but many people seem to do it anyway, I would expect our long-term debt-to-book capitalization to remain in the low 40% numbers or be directing -- going in that direction anyway.

Our debt per approved mcf which is what made most of the rating agencies and many of the high-yield analysts look at is in the low $0.70 number.

I would expect it to stay in that same area also.

Great.

Lastly, can you just confirm what the average after including the hedging gas price you used for your reserve analysis?

Yes.

I think it's in the press release actually.

Let's see, Ben, on page four is where we talked about that.

Top of page five.

Ben, top of page five as of June 30, 2006, estimated cash flow [INAUDIBLE] is discounted at 10%. 15 billion using field differential adjusted price of $69.10 per barrel, that compared to NYMEX of $73.86 and gas at 572 compared to NYMEX of 609.

Thank you.

Moving on to Joe Allman with J.P. Morgan.

Ben, come back to us if you need something else.

I hope that took care of it.

Sorry.

Good morning, everybody.

Hi, Joe.

Hi, Joe.

Hey, Aubrey.

In terms of that rig contract you're buying in Appalachia, could you give us the status of the other 13 rigs?

I believe they are all drilling.

By the way we did close on that deal yesterday.

I can't tell you who all they are drilling for, although I think Atlas is one of them.

I think maybe 40% of the rigs are drilling for Atlas.

And the others, just a whole series of mom-and-pop, the drilling contractor is based out of southern, south central Pennsylvania, so he drills a lot in Pennsylvania and a lot in West Virginia.

You expect to take hold of those rigs once they're done drilling for third parties?

Not necessarily.

We're fine where we are.

We have nine rigs this morning.

Two of them are from this contractor.

So we don't need, right now, to claim all those rigs, but we wanted the option going forward of being able to ramp up our activity and met with ramped-up drilling programs from other public and private companies in the area.

We wanted to make sure that we weren't scrambling to acquire rigs.

But then the second point I mentioned before was we wanted a platform from which we could do some deeper drilling off of and this would give us that platform.

Okay, that's helpful.

And in terms of a play like deep Haley.

Could you give us an incremental rates on the Fayetteville.

Can you give us some incremental data on recent results of deep Haley?

Is there anything incremental beyond in the west Texas Barnett, Woodford that you haven't talked about beyond that one vertical commercial well you purchased?

Well, we actually have two wells producing out there.

One is horizontal and one is vertical, or are both vertical? -- asking Steve.

We'll research that.

Let me talk about deep Haley.

Haley, like all of our emerging resource plays we think has potential to make it out of the emerging area certainly and Anadarko continues to speak favorably of their results there.

You notice our production is up to 30 million a day.

You notice that we're drilling with four rigs and are going to move up to eight rigs by the end of the year.

I think we're making significant progress there and understanding the log signatures that indicate things that we should be excited about and things we shouldn't be plus we've got more 3-D on the way there.

I think Haley will emerge from its status in emerging play and be a fully blown, unconventional play.

We regard it as unconventional simply because it's deep, it's overpressured and log analysis is very, very touchy, tricky there.

So we're pretty excited about it.

I guess the only other thing I would say lately is the emergence of the Strawn Formation as a reliable contributor to production across the area is probably something we hadn't counted on a year ago and feel pretty good about it right now. [TURNS TO MANAGEMENT TEAM] Any highlights that you all want to throw out?

We have two drilling, one vertical, one horizontal in the Delaware, one producing and two completions.

We're a non-operator and other producing wells --

Okay.

Is there anything besides those two wells you mentioned in the Fayetteville and the Gentry and the Barker, is there anything interesting of late related to you guys?

In the Fayetteville?

Yes, on the Fayetteville.

That's it.

We've got two rigs right now.

And then as you guys see in the press release, we're moving from two rigs now to eight by the end of the year, so clearly we're ramping up there.

We're doing some large scale infrastructure work there.

We're building a lake that will hold frac water.

I think that's the first indication we've seen anybody decide to build a lake.

The amounts of water we'll need out there are so enormous.

We'll do that.

We're designing a whole frac water disposal system that will cut down on the haul offs that have reached as much as half a million dollars in some wells.

I will say that I notice other investors or analysts sometimes dismiss those kind of costs as non-recurring, but they'll be recurring for a long time into the future until companies build the kind of infrastructure that we are going to do.

That kind of scale over there that we're going to have will give us some advantages there.

On the production side I think the next big data point will be the Barkley well and we're pretty excited about it so far.

Okay.

On another topic, I'd love to get your comments on the natural gas market.

I think you folks are starting to see some kind of pressure is used, a little bit of curtailment in a few spots.

Can you talk about the natural gas market in general and what you folks are experiencing in your operating areas?

Sure.

You might have caught that we threw a sentence in there in our production estimates that don't take into account the possibility that we'll see some involuntary shut-ins across the industry as a result of higher line pressures and full storage later in the year.

Clearly, people are excited about what we saw yesterday, our first draw from storage in the summer time.

I think that's a pretty significant marker for the industry.

For the industry as you think about going forward, what we've seen is when you dig down into the pool of available generation capacity, a lot of it ends up being some pretty inefficient gas plants at the end of the day.

So going forward as you think about electricity demand increasing by 1.5% to 2% per year pretty much ad infinitum, you see over the next three to four years, I could see a scenario where you go to from one week a summer where you have a draw to three or four weeks a summer where you have a draw.

That would significantly pressure gas prices from here if investors and analysts in the natural gas industry recognize that you no longer can count on July and August as reliable. [INAUDIBLE] What have we seen?

We haven't actually seen line pressures that are actually forcing shut-ins on other people's wells or our own.

But we do see a lot of flimsy excuses from downstream facility operators, compressors, when they go down seem like they take a little longer to get fixed these days.

We're just a little bit suspicious that maybe that's an excuse for some people to keep a little bit of gas out of their systems.

We'll see.

We've had a tough couple of weeks in terms of we lost some production from a series of compressor problems, some of which was related to heat.

This equipment doesn't run as well at 110 degrees as it might at 85 or 90 degrees.

There's some efficiency losses there, as well.

As we've said in the past, we have our own marketing company, having our own compression company and having generally newer, higher pressure wells than most, we think, would give us a little better position if you were to get to a point where you have shut-ins.

That's why we don't really subscribe to the Pye review, for example, that gas prices have to plunge by the end of the year, or by the end of the storage season, to go compete with coal.

We've always believed that's a flawed analysis.

It's not how the gas market will work that instead you'll see pretty decent gas prices every day.

And accompanied by though by involuntary shut-ins across the system, which will balance the system at the end of the day and will get a pretty decent reset opportunity come November 1.

Okay, that's helpful, Aubrey.

Thank you.

Thank you, Joe.

Are there any other questions, operator?

Yes, there are.

We'll now hear from Adam Leight with Credit Suisse.

Morning.

Hi, Adam.

One detailed question to follow-up on this MLP asset carve out philosophy or potential.

What is the size of your restricted payment basket and is there a tax basis to justify doing something like this in any of your regions?

The restricted payment basket question has recently come up.

The restricted payment basket is enormous.

I can't honestly remember, Adam, whether it was 5.7 billion or even higher, but it's some number like that with the equity we've issued and with the methodology as stated in our covenants with respect to that.

For practical purposes you could consider we don't have a restricted payment basket.

I will get you the exact number later.

With respect to the tax basis of any of these assets, each one of the areas would be completely different.

For example, our Appalachian Basin assets, as I remember, we had pretty much full step-up in tax basis there.

Other assets, when we've purchased them, other assets we've taken in corporate form and we have very low tax basis as a result of picking up the existing basis at the time, and while we stepped it up for book purposes, we didn't get a step-up for tax purposes.

Honestly, we have not pursued this even to the extent of going to a detailed examination and studying what asset might have a tax basis to do this.

It's just not something we're in the market to pursue right at the moment.

That's great.

That $6 billion number was kind of where I was thinking.

But thank you.

As I recall, it was $5.7 billion.

I'll get you an exact number soon.

That's great.

Thanks.

I'll move on to Scott Hanold with RBC Capital Markets.

Good morning.

Hey, guys, a couple quick questions.

First on CapEx, you did bump it a little bit from our last outlook.

Can you talk on how much of that was your organic versus just higher cost than previously expected?

Are you talking about our forecast or our actual --

Yes, forecast.

Forecast is really a combination of a little more activity and probably a little inflation.

But I kind of view the days of big inflation are over for awhile.

As I've talked about in the past, service industry capacity buildout is occurring rapidly and going forward in the second half of this year in 2007.

We would like for a pretty benign service cost environment and view that it would be a good time to be drilling wells.

In terms of the incremental activity, is there a specific area that multiple consigners have, or is that pretty much spread around?

I hope what you saw today is a pretty diversified program.

I'm going to say it's certainly spread around although I will say that all the CapEx we're planning to spend in the west Texas Barnett shales and Woodford shales could not have been anticipated until 90 days ago.

There is certainly an incremental element there, as well.

We have an incremental element in the Barnett as we picked up four sevens and the four rigs there we wouldn't have budgeted for a quarter ago, as well.

Generally across the board, but specifically more and more capital being spent in the shales.

You guys did provide a lot of good detail on your potential upside and your ability to continue to do what you do best.

Can you give us thoughts on how you approach development of those various areas?

Where can we expect to be most aggressive where you see the best rates of return and how do you balance that with doing some science on certain areas?

I think it is a balanced approach.

We meet once a month.

Our budget changes once a month.

We evaluate our results from the month and the months before.

And then we look out and see where we want to redirect our activity.

Again, controlling our rigs gives us enormous flexibility in terms of transferring rigs to areas where we think the highest returns are.

Clearly, the best area for us and I think the whole industry right now is the Barnett in Fort Worth and that's why we're moving to 25 rigs there by the end of the year.

We chase returns, but we also are looking for attractive finding costs, as well.

If you look at where we're drilling, where we'll be at the end of the year, the most important place for us will be the Fort Worth Barnett, the [Herra] in northwest Oklahoma, Appalachian shallow, and then places like east Texas, and also perhaps, if things play out, the Fayetteville.

Short term returns can't always enter into the budget process.

For example, our discussion about Fayetteville earlier in this conversation, a lot of science is being down there so we know what we can ultimately expect.

That's a moving target of hopefully lower costs and hopefully better results.

Some of our allocations have to be thought of as more of a scientific or long-term budgeting process rather than just ultimate short term returns.

Thanks, guys, good quarter.

Thank you.

Thank you.

We'll now hear from David Tameron with Wachovia.

Good morning.

Aubrey, a question about your rigs.

Obviously, the strategy if getting rigs to protect against service cost inflation has worked well.

Do you foresee a time, you know, a year down the road if the scenario you just mentioned plays out that you would be a seller of rigs or be something you plan to hold on to?

We talked about that quite a bit.

If it were just a financial issue, I hope we would have sold them at just the time we sold Pioneer.

I think, Marc, we sold Pioneer at $21 a share.

And it's at $13 right now or something like that.

I haven't seen it recently.

I think it's down substantially.

We almost picked the top of that particular market.

We do have alternatives because we've got different investment strategies where we're operating our own rigs.

Clearly, that's not just financial.

In fact, it's primarily operationally driven.

That in return returns us more present value by being able to accelerate the drilling and move them around.

So you could see us perhaps doing something with a Mountain investment, perhaps doing something with our Delta partner, with DHS, and whether that's taking it public or selling it or some other monetization that could happen at some time in the future a lot sooner probably than what we would do with our own rigs.

Our own rigs provide us so many opportunities with acquisitions, being able to accelerate the development of acquisitions which enables us to pay a little more maybe for probables and possibles than some other companies can, and just the core flexibility better operational efficiency we get from drilling our own wells with our own rigs.

It's pretty substantial.

To monetize those financially, it would have to be an extraordinary opportunity to give up those acquisition operational advantages I just talked about.

That's why we've made those investments in the other two companies Marc just mentioned.

Those would be good monetization candidates down the road.

Okay, and it's fair to draw the same analogy to the Midstream operation then, right?

I think so.

There will also be a day when we probably have some investments and pressure pumping companies as well that we might be able to harvest and make some money on, as well.

Right now we spend as much money generally on frac jobs as we do on drilling rigs in many of our wells.

That's an area we're kind of focused on trying to make some money there to hedge some costs and also encourage the expansion of the infrastructure for pressure pumping in the industry.

Okay, fair enough.

Thanks.

Okay, thank you.

We'll now move on to Gil Yang with Citigroup.

Could you comment on the terms under which you purchased your interest in the Delaware Basin?

Is it just sort of straight up working interest purchase on what is the cost of acreage or do you carry any wells?

There are some carries and there is some acreage costs involved.

And due to the highly competitive nature of that basin, we won't be disclosing that information.

It certainly, compared to Barnett valuations these days around Fort Worth, it's a bargain and we're pleased to have made these three deals as quickly as we have.

And I think really captured a commanding position in that play.

Okay.

Aubrey, second question is you commented that land grab is over, almost over.

What's the next step for Chesapeake if that's really the case?

I think it is to do what we're doing this year which is to accelerate the development of that.

We entered the year as the nation's most active driller with 70 rigs operating.

We'll end the year as the nation's most active driller with 135 rigs.

If you think about that delta of 65 rigs, just taken by itself, that would make Chesapeake the most active operator in America besides ourselves.

I think EnCana is number two.

They have 64 rigs.

In my view, it's breathtaking what we have undertaken this year, which is to basically double the nation's most active drilling program in the course of one year.

Said another way to build a drilling program in one year that is bigger than the drilling program of any other company in the industry, and some of these companies have been around for 20, 30, 40, 50 years.

We're doing what we should be doing, which is we saw gas prices were going to go up.

We hired the people.

We acquired the science.

We acquired the land.

We bought the rigs.

We hedged the gas and now we're going out there and approaching it as a manufacturer would, which is I've got my margins set, they are high and we're going on to go really attack it.

We're accelerating the development of our backlog and that huge backlog is our biggest advantage, I think, in that it enables us to consistently high grade and, hopefully, always be drilling the best wells, while at the same time taking on a few new plays.

There's some more land to be acquired.

For the most part, you look at any significant play in America today, the land has been acquired.

And so it requires somebody to go find a new play.

And they're hard to do.

The shale cat has been out of the bag for a couple of years.

So I'm pretty confident in telling you that if you think there are a bunch of new shale plays that somehow somebody doesn't know about, they just don't exist.

We've gone from capture to now it's acceleration of the present value capture or present value acceleration game that we'll be playing here for years to come.

Would that imply that the mix -- you started our a mix of 50% acquisition growth, 50% organic growth.

Will that begin to shift more towards organic growth--?

It certainly could.

I mean, every year we start out and we say this might be the year we do 100% drilling, we never know.

We never budget for acquisitions.

We never know what our competitors are going to do.

We never know what sellers are going to expect.

It still makes sense for us to continue to make some acquisitions.

But going forward, clearly, we saw a kind of once in a generation opportunity to establish a acreage base that I think will create differential returns on our investments for years and literally decades to come.

And a history student, if you go back in the industry and look at periods like this, they don't come very often.

I think that we have carved out a franchise here that will pay many, many dividends.

Now the key is to make sure that we accelerate present value capture from that inventory.

Thanks, Aubrey.

Thank you, Gil.

Referencing that earlier question, I have now been able to research the restricted payment basket and it is now, as of this quarter, 6.1 billion, up from the previous 5.7 billion at the last quarter.

We'll now hear from Rob Dulong with Ron James Capital Management.

I wanted to talk a little bit about east Texas, specifically the deep bossier and what your strategy is there.

It looks like your investment in Gas Star hasn't worked out quite the way you anticipated.

I think the last well there is producing mostly water.

I'd like to know what -- what you see in the deep bossier what you're doing with Gas Star and outside their area and what you think the opportunity is there.

I'll probably let Gas Star speak for their own wells.

But I would not characterize it as having not worked out.

What we did is we jumped in and bought some stock in the Company in return for getting a very low priced position in their assets.

So our view was that over time the stock would perform as the play performed.

Actually I think we're reasonably pleased with the progress made to date in the play.

This is big, deep, expensive stuff.

It's why, I think if you look at the four leading companies in the play, it's Chesapeake, it's Anadarko, it EnCana and Burlington/Conoco.

It requires companies that have the kind of resources in human capital and engineering talent that we have.

So Gas Star is but one aspect of what we're doing there.

Hopefully their hilltop prospect will work.

To the extent they've had some uneven results to date, I am hopeful they will do better going forward.

We have a lot of confidence in them and we're working side by side with them.

That's only a small part of our presence in the play though.

We do have 190,000 net acres of leasehold across that play.

Our first well gets underway -- actually, we're drilling our first well right now.

By the end of the year we'll either be still at that one rig or two.

We have a lot of experience drilling wells at 16, 18m, 20,000 feet, and those are the depths that are found in this area.

The stuff's going to be overpressured.

We deal with that all the time in western Oklahoma and west Texas and we're in pretty good shape there.

Hopefully that helps you with our approach to the deep bossier play.

That's good.

Thank you.

Okay.

Are there any others?

We do have a question from Dan Morrison with Aperion

I'm just trying to push it to the new conference call time record.

You made the comment about being the most active shale driller.

Do you have offhand how many rigs you've got drilling in shale plays right now?

Let's see, in -- count that up.

In the Fayetteville we have -- help me out here, guys.

That's not shale.

Two, two, that's four, Woodford, one, that's five, Barnett is 15, that's 20.

And then if you want to -- that's 20 outside of Appalachia on just shale itself and in Appalachia we have nine rigs.

So we have 29 out of 101 rigs today drilling shale well.

Pretty good percentage?

Yes.

And the consideration paid for the Appalachian contractor, was that disclosed anywhere or could you just tell me what that was?

It wasn't.

It was for competitive reasons not something we want to discuss.

But the per rig value is pretty modest compared to rig valuations out here.

Okay, thanks.

Thank you, Dan.

We do have a question from Eric Kalamaras from Wachovia Securities.

Hey, Aubrey and Marc, I'm curious about the capital spending.

How much of that is truly discretionary in your mind if you were to take into account current service inflation, but say, going over the next year to 18 months with your drilling profile?

We can go through the math of what would be maintenance CapEx.

Marc, you want to do that.

I would start by asking the question, Eric, if you think about discretionary CapEx, there's really two ways to answer it.

One is to say what do we have to do because we've got commitment steps in that we carry someone or we've contracted with somebody that's going to be a very small percentage of our CapEx.

In that stance, virtually everything we do is discretionary.

If you go back and you think about lease expirations, then most of our bigger plays that we've recently acquired, west Texas, Fayetteville, the Appalachian, really big acreage positions either are held by production or have pretty long lease terms on them, some of them extending to 10 years with renewals.

So from that perspective, quite a bit of it is discretionary as well.

The Barnett shale is probably a little tighter.

Obviously we're ramping up there.

In terms of maintenance CapEx, if you think in terms of what do we need to spend just to maintain, throw out a rough number of production of 650 Bs and think of replacement cost at 225 to 250.

You're spending 1.4 billion, 1.5 billion out of 4 billion of operating cash flow to maintain your reserves and production level, all other things being equal.

So the Company's got tremendous flexibility and in most senses almost everything we do is discretionary.

That's why we've been able to change it around so much from month to month as we move the rigs around.

Appreciate it, thanks, guys.

Appreciate all the details in the press release.

Thanks, Eric.

We'll now hear from David Khani with Friedman Billings Ramsey.

This is Andrew Paulnia.

A couple of quick questions here for David and myself.

Are you still there?

Yes, we're ready for you.

The first was just a data question.

Was there any stock based compensation for the quarter?

Is there any stock based compensation during the quarter?

Yes.

I didn't see it in the--.

We're not allowed to split it out, I think, on the income statement.

I believe we show it on page two in the key statistics.

First of all, Marc, am I correct that we can't show it on our income statement any more?

I think that's right.

We break it out in the footnotes, but we would have had little stock based compensation in the quarter, a few cents per mcf equivalent.

It's well within our guidance.

In fact, I think it's on the lower end of our guidance.

We actually didn't have any stock option or stock grants during the quarter.

Of course, that's not the controlling issue.

It's when stuff vests.

And virtually every quarter we have options, or previously issued stock grants that are maturing and therefore become compensation expense.

Just to remind everybody, since July of '03, we've been on a restricted stock program of twice a year grants that started in January of '04.

So just to be clear, Andrew, we had $0.05 this quarter of stock based compensation expense per mcfe and the same for first quarter a year ago at $0.02.

So as our stock options roll-off and our restricted stock programs roll forward, you won't see that go forward.

I think our outlook shows that that number going forward will be -- sorry, sorry, sorry.

It's on page 22.

And we are projecting next year that will be $0.08 to $0.10 per mcfe.

Talking about the technical talent here and kind of getting the staff to continue your operations, you mentioned that drilling cap or drilling rates are perhaps softening a little bit.

That you still see a high demand for people in the industry?

That hasn't stopped.

The only thing I would say is that we are as aggressive as anybody else in going after people.

One of the advantages I think we recognized earlier in some other companies a need for people.

So we've got a lot of people pretty fairly weighted down with some restricted stock grants that are unvested and it would be pretty difficult to price some people out.

Plus we think people like working for us.

If you like to drill.

If you were born to drill wells, this is the place to be.

If you were born to find gas, this is the place to be.

If you were born to buy a lease this is the place to be.

We still get over 125 resumes a day and are continuing to hire to fit our needs.

You mentioned early in the call that it is a relatively clean quarter here for you on the acquisition front.

Looks like you spent most of your money on buying leasehold and unproved properties.

Have you seen any change in the volume of deals that have come to you or things that you're looking at as the price came down or is it?

No, I don't think so -- I think once people get in their minds that they are going to sell, they tend to move forward and their advisors would tell them that as long as the back of the curve doesn't weaken significantly the prices they get is going to be more -- depends what the back of the curve is doing rather than the front of the curve.

You saw Four Sevens come to market, you saw Chief come to market.

There have been -- EXCO just bought Progress Energy.

There have been some pretty significantly sized deals come down the road the last 90 days and do well at the relative gas price weakness.

We would rather buy assets in a weakened gas price market simply because we view that most of our competitors are unhedged and certainly a little more apprehensive about near term issues than we are when we hedge and so . we kind of never have to worry about near term gas prices.

The last question I had is how much cushion remains in your full cost pool, I guess looking at how you book your reserves and kind of pricing assumptions and that?

Well, it's always a moving target because as prices come down, you have expectations for lower costs.

But without that, we have about $1 billion of cushion as of June 30, with -- and that's always a moving target with regard to hedges and all that stuff as well.

I would estimate still, that somewhere $5 and below, we would have a ceiling test issue or could have depending on what costs do at that same time.

And that would be NYMEX.

Great quarter organically.

It looks like you beat our numbers.

Keep up the good work.

Thanks a lot.

We'll now move on to Ray Deacon with BMO Capital Markets.

I was wondering if you could talk about where specifically the organic growth quarter to quarter came from primarily?

Was most of it out of the Barnett or was it kind of more broad based?

It's really broad based wherever we're drilling wells, we tend to be in a growth mode.

I'll just highlight areas like the Barnett, areas like Sahara, areas like east Texas, we continue to see increases in our production.

But I don't want to slight any of our hardworking teams out there that are active throughout the Company.

That's to me the single greatest distinctive attribute of the Company is tha we're not a single play company.

We were ten years ago.

It can be fun for a while and it can be not so fun for a while.

We really like this broad-based, diversified portfolio of assets that we have.

It's geographically diversified.

It's depth diversified.

It's play type diversified.

And nobody has us overvalued so we don't have a lot of pressure to exaggerate results.

We can be very conservative and still deliver I think some pretty attractive returns to investors.

Great.

Just one specific one on Haley.

How many of the deep Haley wells are, in your experience so far, could say that that 10, $10.5 million number is going to be a good number going forward?

I think we're very confident about that.

What's always been a challenge is where are you on that 7 bcfe of reserves?

That's tended to be a much more broad-based distribution of outcomes.

We've got I guess some 1 and 2 bcfe wells.

I guess our best well is 15 bcfe or somewhere in there.

We've had a train wreck or two on the cost side but have adjusted our casing program and have adjusted the way we complete and flow basket wells.

I think we're in pretty good shape on the 10.5 million and just trying to develop an approach that gets the more consistent 7 bcfe returns that we are expecting.

Right.

And is it a completion issue or is it a seismic issue trying to find the structural component in the play?

I'll let our Senior VP of Exploration address the challenges to cracking the code in Haley.

I think it's really both.

We continue to work with 3D.

We continue to acquire additional 3D data in that Haley area.

That is a challenge, is cracking the code.

But a couple of -- some good things that have come out of it is, as Aubrey mentioned earlier, we've identified, the certainly Strong as a somewhat consistent contributor to the production in addition to the Atoka and Morrow which has been a little bit more challenging.

And really the completion part of it is part of it also.

What is pay and what isn't.

We have done better.

In fact, we are currently at four rigs planning to do at eight rigs.

So we are still encouraged with, certainly with the potential of that play.

Great.

Thanks very much.

Thank you, Ray.

We'll now here from Ellen Hannan with Bear Stearns.

Good morning.

Ellen, hi.

I'm not trying to set a record here.

I did have one quick question for you.

On your slight on the Barnett shale, when you talk about your existing acreage before adding the 4.7 from the other land, you upped your estimate of your net unproved reserves since the end of March significantly.

I just wonder if you could give us some color or how much of that might be due to recent drilling results or reserve adds per well and/or what you're looking at in terms of down spacing?

A couple things there.

First of all, during the second quarter we did up our expected reserve estimates per well.

And so we now feel like drilling 500-foot laterals, or wells lateral 500 feet apart out to a depth of approximately, call it 2500 or 3,000 feet that we're going to develop 2.4 bcfe per well consistently.

That will be a combination of some wells that will be in the 1.6, 1.7 bcfe range and it will be some wells that are the first in the area that will be 3.5 to 4 bcfe.

If you do the math on that length of lateral and that distance between laterals, you really get down to a spacing pattern of something like 35, 36 acres are consumed across the play.

You may notice here we've gone with 55.

Not only did we risk our acreage by 25% but we also risked our acreage another way by saying that our spacing pattern is actually going to end up being a third bigger -- or sorry, 50% bigger than what that kind of drilling would indicate.

A couple of things are at work.

We have more acreage.

We have more confidence about the amount of acreage -- or the amount production that we're going to get out of each well, while at the same time we've offset that I think with a pretty conservative approach to valuing that acreage and creating those spacing patterns.

Thank you.

And one, -- you've gotten great compliments today as you should on your disclosure.

I just want to tell you too, I think your proxy statement is one of the best out there.

Thank you.

I didn't write that, but I'll pass that compliment on to those that did and--.

You should.

It's got lots of good disclosure.

Thank you.

We really try hard to tell you all everything that I would expect to be told if I had a scale of investment that you guys have.

I guess I do.

So that's why we think about telling you everything that we possibly can.

Thanks, Ellen.

Thank you.

We'll move on to--.

Pardon me?

You have a question from Jeff Dansey, Cutler Capital Management.

Thanks a lot.

Actually, my questions are answered.

You are our favorite guy so far, Jeff.

Thank you.

All right.

And we did have a follow-up from Shannon Nome with Deutsche Bank.

Actually, I'm good too.

Thank you.

Thank you, Shannon.

Well, it sounds like that's a wrap.

Thank you very much.

We appreciate everybody spending so much time with us this morning and also for complimenting us on the detail.

Some guys around here worked very, very hard to gather that information for you.

We thought it was important information and now we just expect you guys to get the valuation right.

Talk to you later, and call us back if you any questions.

Thanks so much, bye-bye.

We thank you for your participation.

Have a great day.