Chesapeake Energy Corp (CHK) 2009 Q2 法說會逐字稿

Good day.

And welcome to the Chesapeake Energy conference call.

Today's conference is being recorded.

At this time, I would like to turn the conference over to Mr.

Jeff Mobley.

Please go ahead, sir.

Good morning and thank you for joining our 2009 second quarter earnings and operational conference call.

I'd like to begin by introducing the other members of our management team who are with me on the call today.

Aubrey McClendon, our CEO; Marc Rowland, our CFO; Steve Dixon, our COO; and joining us, by a separate line is Mark Lester, our Executive Vice President of Exploration.

I would like to call your attention to two press releases.

One, from yesterday afternoon, which was our financial and operational release, with earnings as well and also, last Thursday we had an operational update release.

Our prepared comments should last about five to 10 minutes and we'll then move to Q&A.

I'll now turn the call over to Aubrey.

Thank you, Jeff and good morning.

We are hopeful that you found it easier to process all of Chesapeake's operational and financial information this quarter through two press releases, rather than our customary one press release.

We are also hopeful that you noticed as a result of our asset quality and the benefit of our carries, that Chesapeake's drill bit finding costs in the quarter were only $0.87 per mcfe.

Certainly, that will be the lowest in the industry reported this quarter.

Furthermore we hope you notice that returns on drilling in our two granite wash plays are above 100% even in today's low gas price environment.

Moreover, we hope you notice the financial power of our joint venture carries, which paid $311 million of Chesapeake's drilling costs during the quarter.

I don't really believe investors have fully focused on what these carries do for our returns on investment.

In the Haynesville, for example, our 50% carry from PXP decreased our drill bit finding costs during the quarter to the incredible level of only $0.47 per mcfe, while boosting our rate of return to 345% from 42% pre-carry.

That's more than a 700% better return, than the rest of the industry will likely be able to achieve in the Haynesville.

And remember, this carry doesn't include what we have already collected up front on the initial acreage sale.

For example, the per acre costs for Chesapeake's industry leading 510,000 net acres in the Haynesville, is now just $6,000 per net acre, which compares very favorably to a recent valuation of such acreage in the EXCO/BG joint venture at almost $20,000 per net acre.

In the Marcellus, it's even better, as our 75% carry from Statoil reduced our drill bit finding costs during the quarter to the also incredible level of only $0.43 per mcfe, while boosting our rate of return to more than 1,000% from 71% pre-carry.

That's more a 15 times better return than our competitors will likely be able to achieve in the Marcellus.

And remember this carry also doesn't include what we've collected up front on the initial acreage sale to Statoil.

The acreage costs for Chesapeake's industry-leading 1.45 million net acres in the Marcellus is now just $80 per net area, which compares, of course, very favorably to recent off-the-ground leasing at more than 30 times its cost.

Finally, in the Fayetteville, we actually had a negative cost of more than $8,000 per net acre and our returns during the past year and into the end of 2009 will be infinite because BP is paying for 100% of Chesapeake's drilling costs in the Fayetteville.

Infinite returns are, of course, pretty tough to obtain and to beat but we have done it in the Fayetteville for all of 2009.

It's really very simple.

The combination of our JV's and our huge core acreage positions in America's greatest gas plays should enable Chesapeake to lead the industry in value creation for years to come.

Ah, but some of you may question our financial discipline.

Can Chesapeake live within its cash resources?

Well, of course we can.

And we are.

And we have.

Through our operating cash flow, augmented by our asset monetizations, we expect to deliver 4% to 5% production growth in 2009 and 7% to 8% production growth in 2010.

Plus, increase Chesapeake's proved reserve during '09 and 10, from 12 tcfe to 16 tcfe, all the while generating excess cash of $1.1 billion to $2.1 billion in '09 and '10.

By generating this excess cash and by increasing proved reserves by 33%, we will substantially deleverage Chesapeake's balance sheet and have investment grade credit metrics by year end 2010.

Chesapeake's second quarter results should be just the beginning of a very long string of quarterly results that will showcase the power of our assets and the strength of our financial returns.

In our view, it will be an unbeatable combination and will create very substantial amounts of shareholder value for years to come.

I'll now turn the call over to Marc Rowland for his comments.

Marc?

Good morning, everyone.

Like Aubrey's comments, mine will be brief this morning as well.

One very positive trend over the last few months has been a dramatic improvement in narrowing basis.

Therefore, an improvement in well head realizations compared to Henry Hub.

For example, August basis for Midcontinent, as measured at Panhandle Eastern, is only a minus $0.26.

We have not seen basis this narrow since 2004.

Likewise, Waha, another delivery point, is minus $0.08, not seen since 2003.

Houston ship channel is actually a positive $0.03 compared to the Hub.

We continue to receive positive basis in the East of around $0.20.

We think this trend can continue, as gas volumes drop and once again, there is more takeaway pipe capacity than production in many of our operating areas.

On the asset monetization side of our business, the market continues to improve, with many more investors now interested and at improving discount rates.

To put the sales in some perspective, VPP's numbered five and six have about 123 bcf of total volume, associated with them and will sell for about $5 per mcf on a weighted average between them.

Yet in just three months, we added 836 bcfe at a cost of just $0.87.

We think that's a pretty good program.

Finally, one note on cost trends, as you can see from our release just about all of our production and other cash costs are down or at worst, flat from quarter-to-quarter.

We continue to see some downward trend in drilling and completion costs as well, although not at the rate of decrease we saw in the fall and first half of 2009.

We expect this trend to remain a positive development for the balance of this year, at least.

Moderator, we'll now go to questions please.

Thank you, sir.

(Operator Instructions) And we will take our first question.

It comes from Jason Gammel with Macquarie Capital.

Please go ahead, sir.

Thank you and good morning.

I was wondering if you could address the decision to increase drilling CapEx in 2009 and 2010 and maybe also address where that incremental drilling is going to be done?

Sure, Jason, this is Marc.

Good morning.

We've got a little bit of an increase, Steve, I know going on in the wash plays specifically.

And continue to ramp up in the Haynesville and Marcellus.

We're trying to get ahead of schedule, really, with low capital costs and our carries in those areas.

So, Jason, I'd say it's principally in those three areas.

I don't think we've increased in the Barnett at all and don't intend to and of course, we are ramping up some in the Marcellus as well.

Okay, great.

And maybe one more if I could.

There was a little bit of a change to the profile of the average Haynesville well that you're expecting a higher initial production rates and higher first-year declines.

Can you talk about whether that is more a decision on how you're fracing and the lateral link or this is this really just more an issue of now having some production history from the rock?

This is Steve Dixon.

It's really more production history.

Though, we are making, we think, improvements in our fracing processes.

But the last 15 wells have averaged over 14.3 million IP's and we just continue to see higher initial rates and to keep that curb at the 6.5, it's just higher initial declines to stay there.

Okay, thanks guys.

Our next question comes from Michael Hall with Stifel Nicolaus.

Thanks.

Good morning.

Quickly, in the Marcellus, I was wondering if you could talk to kind of distribution by aerial extent of the wells you've drilled thus far and any color on variability in the play?

Michael, it's Aubrey.

We're probably not at the point of wanting to say a whole lot more about the Marcellus.

There's still some acreage available in our two key areas and those I define as northeastern PA, where we're strongest and counties like Bradford and Susquehanna.

And a pretty wide distribution in those two counties, probably across 25 miles, 30 miles would be my guess but maybe much more so.

The other is in northwestern West Virginia, particularly in our Victory prospect area and that's an area we've focused in.

We're drilling our first wells in southwestern Pennsylvania.

Right now, we have a good acreage position in Washington and Greene counties.

Of course, that's where Range has been active for the last year.

So for reasons of rock quality, we're really not playing much in between those two areas but those areas that I just described are, of course, multi-county and measure in the millions of acres in size.

And that's where we continue to acquire new leases and continue to increase our drilling activity.

Okay.

Thanks.

Any commentary as to why you all decided to resume curtailed production volume so quickly?

It doesn't seem the curve worked in your favor in that endeavor.

Just curious on any additional color there...

You're saying the curve did not work in our favor?

It didn't seem like -- if I recall, prices are lower during the timeframe from when you shut in versus when you turned production back on.

I think a couple things.

The first thing is that basis actually improved pretty dramatically and so actually, well head prices did improve.

Okay.

And so, by holding some production off we certainly did benefit by basis coming in.

Of course, as Marc mentioned, the basis story is a really important one.

We've had bad basis for the last two years or so.

We've been long gas, the industry has been long gas and short pipe.

We're getting ready to move into a world where we're going to be long pipe and short gas.

And so, we've already seen basis differentials really, come together in the last few months.

I think the second thing is, given where storage is, it was our analysis that we're going to be full up on storage by the end of the year.

And as we get closer to that, pipeline pressures are going to increase and that is going to cause involuntary curtailment.

So, I think our view was that there was no reason for us to voluntarily curtail gas, when pretty soon, everybody is going to start involuntarily curtailing gas.

And so, we didn't see any reason to take it on the chin for the team more than we did.

And instead, we'll just let the system work, to spread the pain across the whole industry here over the next couple of months.

Okay, one more, if I could.

As to any updates on your oil projects that you've talked about in the past, given the big disparity between crude and gas at this point?

Well, we're still working on those.

Of course, the biggest oil project we have is Colony Wash.

Steve, we are finding how many barrels now, per well there?

Let's see, 186,000 but --.

Okay.

I thought it was around 200,000 barrels and we have several hundred wells left to drill there.

So, that's a 50-plus million barrel project and that's a big discovery for us.

In the shales, we're still working on developing some oil shale activity in the west Texas and New Mexico portions of the Permian Basin.

It's tough to move oil through shales but we continue to work on some projects.

We are producing oil from, if I recall correctly, three different shale prospects but I wouldn't say yet that we've established kind of firm commerciality there on any of those but we continue to plug away at it.

Okay.

Appreciate it.

Okay, thank you.

Our next question comes from Scott Hanold with Royal Bank of Canada.

Good morning.

When you look at your spending activity, obviously, you did uptick it a little bit in '09 and '10 and when you think about the acreage you might have to hold and requirements to drill under your JV's.

Is that going to influence expectations going forward or do you think you're pretty well covered, at least, in the next couple years?

We have designed our drilling program over the last couple of years and entered into these JV's with a plan to be able to hold all of our acreage by production, in the Fayetteville and the Haynesville, the Marcellus and the Barnett.

So, that has not changed and we continue to, in most of these plays actually, acquire additional acreage that we also believe we can help by production as well.

Okay, and that's based on the current '09 and '10 program, and what kind of pace would you have to look at in '11?

Would that need to be stepped up to continue that?

At this point, we've not really spent a lot of time on '11 but our preliminary budget just holds drilling capital flat for 2011 versus 2010.

Okay.

Appreciate it - and one more, if I could.

In the Granite Wash, obviously some pretty tremendous industry results up there.

What's your ability really to ramp up activity, given some of the premium economics out there?

Is there the infrastructure capacity to do so?

Yes, in Colony Wash, which again, we dominate in that play, we could be at 10 to 15 rigs pretty easily.

We believe all the takeaway capacities there, this is on western Oklahoma, Farmland and Washita and Custer counties, pretty easy drilling, no administrative or regulatory issues.

So, it's really just a matter of how we want to allocate capital and the dilemma here is that you spend dollars there, they're your best dollars in the Company, on a pre-carry basis.

When you include carries, obviously, drilling in the Haynesville and Marcellus and Fayetteville beat those plays.

So, right now, we're just using four rigs in Colony to HBP acreage, I think we have HBP'd something like 60 sections and have another 50 or so to go before we even begin to expand the boundaries of the play.

At this point, we're not doing any real increased density drilling work.

In the Texas panhandle, the dilemma is a little different in the sense that all of our acreage there is held by production.

And so, really, it's just completely selective drilling and you want to pick and choose your time.

If we didn't have any carries, those two Granite Wash plays would be the best in the Company but right now, we are favoring our plays with carries because you can't beat finding costs of less than $0.50, as we're generating in the Haynesville and Marcellus right now.

Understood.

And with the Granite Wash plays, how predictable do you think you can get those results, obviously, some recent results coming up from you all and Newfield has been tremendous, is that fairly repeatable?

Do you feel more or less competent in doing that in the Granite wash than say the Marcellus or the Haynesville?

Well, first of all, we've been drilling in Colony Wash for 2 and a half years now, so we have a pretty wide distribution of drilling results and it all depends on rock quality.

I guess you could say it's a blanket play over 100,000 or more gross acres but there are certainly differences in rock quality there and we're looking at different zones in the Granite Wash, as well there, from A all the way to C.

In the Texas Granite Wash, some people call it Buffalo Wallow some call it Stiles Ranch.

And we just call it greater Texas Panhandle because really there are about seven or eight traditional Granite Wash fields across the Texas Panhandle in Wheeler and Hemphill and Roberts Counties, that over time will be developed horizontally.

And you're going to see widely different results.

Again, it's going to depend on being able to map out the sweet spots.

What is nice on our acreage, and I presume on other some Company's acreage there, is that again, there are four or five different zones.

And Steve or Mark Lester jump in here but in the Texas Panhandle, if I'm not mistaken we have tried at least three different --.

Yes, sir.

Benches of Granite Wash and found them all to be successful.

Successful, yes, sir.

So, at any rate, it's a great play.

We're a little weaker in the Texas Panhandle than we'd like but very strong in this field in Custer and Washita County, as we discovered in February '07 and call it the Colony Granite Wash.

Our next question comes from Tom Gardner with Simmons and Company.

Thank you, operator.

Aubrey, given your excellent cost performance for the quarter, I was surprised to see that your guidance going forward was left unchanged.

Can you comment on that?

Yes, Tom.

I think it's just a little difference in philosophy.

Where you may have also noticed, last quarter, we stopped putting out quarterly guidance.

And now, just going with kind of first of the year guidance and that's our goal for the year is to beat those numbers.

And so, it looks like we are on course to do that.

And we'll let you guys do your jobs of analyzing and predicting and we'll just set forth our goals for the year and do our best to beat those.

I see.

In a more general sense, with regard to service cost deflation, do you see some of the -- having industry give some of that back, when prices recover and to what degree do you think there's inertia there on that deflation?

We're probably bottoming and have bottomed and we'll probably give some of it back but we don't expect the rig counts to pop-up too meaningfully going forward.

I'd be surprised to see it above 1,000 or 1,100 over the next 12 months or so.

So, I think you're in a time when service companies are realizing the same things a lot of E&P companies have realized, which is, everything is different as a result of these shale plays.

And we're not going back to a service industry supporting 1,700 or 1,800 rigs in the US.

So, there's going to have to be rationalization of capacity, I think, in the industry.

In the meantime, I think most of that capacity will stay around and will keep prices reasonably low for us.

Marc, do you want to add anything to that?

Yes I would just focus on the capacity.

We've got an environment where you had nearly 2,000 rigs running, less than 50% of those now -- I know in our service businesses that we've invested in, rigs are mostly down.

Frac service equipment has been stacked.

People have been laid off.

So, there's a tremendous amount of recently built-up new capacity that has idled and I think it will take quite a while even after prices start to return on the gas front, before much of that trickles into the service side of things.

Thanks for that, Marc.

And just one last question more general to the commodity.

I wanted to get your thoughts on the accuracy of the 914 data and is that telling a story consistent with your view of what's happening with natural gas?

We'll let Jeff take that.

Go ahead, Jeff.

There are some flaws in the 914 data.

And a change in their methodology that they announced earlier in the year does make you a little bit curious about the data.

But at the end of the day, we think it is probably the most current and most reliable data that you can find in the market in an aggregate basis.

As you might have seen in our prior presentations, we've done quite a bit of work to try to model out U.S.

gas production.

And so far, the numbers that we've seen reported for the EIA are right on top of the model that we've outlined.

So I have a reasonably high degree of confidence in those numbers.

I would point out, though, that with the rig count having dropped for natural gas to well below 700 and kind of leveled out in the 675 or so rig count range, that really sets the stage for natural gas prices to decline materially into the back half of this year and the first half of next year.

We've seen a slow steady climb in gas production from 2005 through March of 2009.

And it's leveled off to a very slow sequential decline through the summer but that should pick up dramatically.

And we can see production declines on a year-over-year basis of perhaps as much as 2.5 bcf to 3 bcf per day by the end of the year, approaching 5 bcf a day down year-over-year by late spring early summer next year.

Thank you, Jeff.

Thank you everyone.

I appreciate your comments.

Our next question comes from Brian Singer with Goldman Sachs.

Thank you, Good morning.

Can you talk about where you stand from a leasehold acquisition perspective in the various plays?

Obviously, you have guidance that you put out but just, as you look forward over the next year, where that stands?

And I also noticed, you did put out a little more granularity on well results than you usually do.

How should we look at that?

Do you view further acreage acquisition as a good thing or a bad thing?

It probably depends on one's view on the individual plays, I would think.

Right?

Well, if you like the Marcellus, we continue to acquire acreage there, 150,000 net acres in the core in the last three months.

And I think in the Haynesville, when we went up by 40,000 net acres and that was again, inside the choicest part of the play.

In the Barnett and Fayetteville, we continue to pick up around 1,000 acres a month or so.

So the main areas of further acreage acquisition are in the two biggest plays for us, Haynesville and in the Marcellus.

With regard to well results, I thought we had put out individual well results in our last quarterly release.

But basically, by splitting the release into two, Brian, we're able to give a little more granularity on our highlights.

And it seems like a lot of other companies give highlighted production and analysts seem to like that.

So, we did that, plus we thought investors and analysts would benefit by seeing our decline curves, which we have provided in all our plays.

But we didn't do it in the Marcellus simply because we don't have statistically significant sample of wells yet to be able to do that.

But clearly, from what we've seen on the decline curve, so far, we've felt comfortable in going from 3.75 to 4.2 bcfe there.

Thanks.

And then, on line pressures are you seeing any impact now from pressure back-ups?

And do you have any expectations regionally for where you would expect to see these happening first?

Haven't really seen it yet but we will, over the next couple of months.

And it is hard to predict regionally, because so much of it's going to depend also on where declines are kicking in and 914 data is beginning to show, we track it here, of course, our conventional production, or our non-big four shale production peaked actually in the second quarter of 2008 and has been in decline now for five quarters.

So, we know that that's happening across the industry and will accelerate in the second half of the year.

And so, that will have some relevance as well.

And then the pipeline system is so big and integrated that it's really hard to imagine -- or to exactly be clear on where it's going to happen.

But just from what I read, on analytical commentary, it does appear the Rockies and Canada are probably going to have the biggest problems in terms of getting to full storage faster than other areas, which of course, will create some pretty significant production problems there as well as price problems.

Great, thank you.

And if I could ask one more.

When you think about your guidance for some of the year end numbers you threw out for the Haynesville and Marcellus for next year, how are you thinking about pipeline delays?

And are you factoring -- it would seem like in the Haynesville, you may be factoring in some pipeline delays.

Where do you think your production could otherwise go to in the absence of those plays?

Brian, we believe that we'll have all the pipeline projects we need in place and any that we're not building ourselves will be in place as well.

This is something that our midstream group works with our operations group on every day.

And we're quite confident that the levels of production that we estimated at year-end in '09 and '10 will be met, based on what we ourselves will be doing with putting pipe in the ground, as well as what others will be doing.

Thank you.

Our next question comes from Lewis Ropp with Barrow, Hanley.

Good morning, guys.

Listen, I do appreciate the disclosure that you guys have done with the separate release and also, the fact that you released the night before this conference call.

So many of your peers put their releases out first thing in the morning and then hold the call and we really haven't had a chance to absorb any of it.

My question in looking at some of the sell-side research that's out this morning, there's an implied percentage of hedges for 2010 and one of the pieces that's only at 21%.

It talks about lifting some of your hedges.

And I think they're just omitting the call options that are written in 2010.

And that kind of made me question if I really understood the way those call options work.

And so, I was hoping you could just clarify that that is the bulk of the hedges that are in place for 2010, the way I understand it.

Lewis that is correct.

I do believe that most people eliminate the calls because you do not have price protection.

When we write a call, we collect a premium.

Some of them are deferred but we generally are paid a premium that, depending on the strike price, can range from $0.50 or so to up just over $1.

I think most analysts correctly view the -- in a low price environment that that price protection is only for the premium that you've received, it doesn't protect you for falling prices.

Most of the hedges that we've lifted have been in the back half of 2010 where it's our belief that between now and then, you'll see a substantial rise in the price levels and will be able to reassert ourselves at that time period and rehedge, with our new facilities giving us plenty of capacity to do that.

So 2009, of course, we're nearly fully hedged there.

Most of the calls have been purchased back.

Almost all, I think all but five Bcf of the kickout hedges were eliminated and converted into either collars or into pure swaps.

So hopefully, that answers your question.

Yes, thank you.

My next question was, I know that Statoil had some folks seconded to you guys and given Exxon's recent press releases about their interest in looking for shale gas globally, if you had any progress you could report on your joint venture with Statoil?

Well, of course, the JV in the Marcellus continues to work well.

I presume you're talking about the world wide initiatives that we have.

I'm really not wanting to show our hand there.

I think a few months ago, Statoil did comment that we were working on 14 different areas and that's where we had narrowed our worldwide search to.

So, we're really excited about the potential of that.

We're working with a world class partner who today, I believe has operations in almost 50 countries around the world and so, we couldn't be happier than to be affiliated in a partnership with Statoil.

And I think, of course, what we bring to the table is we can find rocks around the world that we can analyze and determine if they look like they're going to be prospective.

For kind of an overall world economy in the future, we're very encouraged by the fact that we think natural gas will be able to carry the load, as oil production stagnates and probably continues to decline at some point.

And gas will increase its market share along the way.

So, all good there.

And also, Lewis, I appreciate your appreciation for the way that we split our earnings and operational announcements up.

We just realized that we were probably overwhelming people with data.

And this gives people a few days to focus on our operations before they begin to focus on our financial results.

Great.

Thank you very much.

Okay, thank you, sir.

Our next question comes from Jeff Robertson with Barclays Capital.

Good morning, Aubrey.

In the Haynesville Shale, you all have drilled 56 wells with the 10 stage frac stimulations.

Can you talk about how much of your acreage, and it looks like in Louisiana, has been derisked at this point?

Well, a vast majority of it, I think -- Jeff, what risk factor do you have -- are you at reducing by 40%, it seems like, he'll check on that.

Yes, we're risking our total acreage position by 40%.

I don't think we've changed that from the first quarter and probably could, just decided not to.

But the vast majority of our Louisiana acreage is now well within what we would call the core -- we've got some acreage kind of north of Shreveport and a little bit west of Shreveport but not significant.

So my view is that that risk factor should be zero, in terms of; are you going to find gas?

All of the acreage that we count as being prospective has gas under it.

The question is, is it going to be 4 to 5 bcf or is it going to be 6 to 7 bcf, or is it going to be 9 to 10 bcf.

I think what you're see develop in the play is what you see, of course, in every shale play is that you're going to see range of outcomes and those companies who have acreage focused on the Texas side of play, are going to see lower EUR's.

While companies with acreage focused in that core area, where kind of Red River, DeSoto, and Caddo and Bossier all come together, that area is going to be the best and that's where you're seeing the 20 million a day, plus wells.

So, right now, we're focusing exclusively on getting our acreage held by production.

While also testing some of our outlying acreage just to see how good or prospective it may be.

But right now, it looks like our petrophysical and geological model that we built three years ago for the Haynesville is absolutely proven to be spot-on.

And I congratulate our geoscientists and our petrophysicists and those guys in our research laboratory for really getting it right in the very beginning and allowing us to concentrate our acquisition right in the gut of the play.

Can you talk about the current cost per well and how far away you might be from your targeted $7.5 million per completed well costs?

Yes, we're actually below our target right now.

I'll let Steve handle that.

Yes, we're drilling a number of wells you know below that 7.5 today but we still have stepouts to do and some signs to do but feel very confident that we'll be able to get that down to $7 million.

Steve, have we completed some wells under 7 yet?

That was one of the questions.

Yes we've done at 6.5 even but not that we won't have higher cost wells.

And Steve, are some of those low-cost wells, is it something you're doing differently with the fracs on those wells or are you getting better penetration rates or a combination?

Well, it's a combination.

A lot of the lower ones have been some extremely high penetration rates where we've got the wells drilled very quickly.

That's the other thing we'll be looking at here in the Haynesville is increase in our cycle time forecast also because our days are coming down as costs.

Okay and lastly on the Haynesville shale.

Aubrey, on the acreage that you all control, in what you have leased in the last year or two, how much of that do you just own rights to the Haynesville versus owning all zones?

I noticed in the Indigo sale, you all reserved the Haynesville rights and sold the more traditional Cotton Valley zones?

Yes, is your question directed at Bossier shale rights or is it directed at the Cotton Valley rights?

Cotton Valley.

I don't know the answer to that offhand but the vast majority of our acreage, we control from surface to as deep as we drill and sometimes there are no depth limitations at all.

I imagine in some of our farm-ins from Goodrich and Matador, for example, I'm pretty certain that we don't have uphold rights but I would say probably 80% or 90% of our acreage, we're going to have all rights.

And of course, we're focused on making sure that we have Bossier shale rights, as well.

And the Bossier is right above the Haynesville, so every time you drill a Haynesville well, you're penetrating the Bossier.

And so should be HBP-ing or holding that acreage as well.

Okay.

And then, Marc, just a quick question on the costs, will the midstream sale, if you get that done, will that have any material impact on operating costs?

It won't change, Jeff, the operating costs at all.

The structure, as we are currently negotiating with our future partner, basically keeps the revenue stream that we have been paying to ourselves virtually identical.

We will handle the cost side of that, either through seconded employees or service agreements built essentially at fixed costs per mcf and they're relatively minor, I think, currently, we're projecting about $0.03 an mcf for our service support to the midstream entity.

So, these are all volume fee-based, no commodity risk.

There's no processing involved, so there's no liquid stream.

So it's basically a molecule moves through, we measure it and send a check over.

So the cost will remain the same.

I might interject here, we've received a couple of comments about how the midstream project has taken a long time to bring to fruition.

I thought I might give Marc the opportunity to just mention why it has stretched into the third quarter from the second quarter and maybe comment on the complexity of it and the number of agreements that actually have to be negotiated and written and go from there.

It has taken me, I think, about half my life to do this project but it is nearing completion.

We've got, we think, an excellent party that wants to be our partner in this transaction.

It is complex.

It does cover the Barnett and a number of our midcontinent systems.

Obviously, the Barnett has been an area of big growth, with lots of moving parts in terms of hook-up costs, in terms of volume projections and trying to get all of that right has taken a long time.

It is a complex transaction.

There are gas service agreements, the partnership agreements.

There are -- everything to do with our ultimate strategy of, hopefully, taking it public which we recognize that the market has improved in this area and this would be an excellent candidate, we think, that would measure up with some of the top MLP candidates and we're looking forward to perhaps doing that as early as the first half of 2010.

So, it has taken longer than I expected.

It has been more complex but I think we're nearing a successful completion here, within the next few weeks.

Thanks Mark.

And our next question comes from David Tameron with Wachovia.

Hi, Good morning.

On the operations side, if you think about your assets, can you tell me internally, over the last two to three quarters, what asset has outperformed expectations or what asset continues to?

Yes, I'm not sure we are drilling on one that hasn't gotten better over time.

The Barnett continues to do well.

Our two best wells we've drilled in the last three or four months in the Barnett.

Fayetteville - I think we're the only company to have a 6 million a day well there and both we and Southwestern continue to increase results in that.

We've recently increased our estimated recoveries there.

The Haynesville gets better and better.

We're working on the Bossier shale in the Haynesville area and have high hopes for it.

We increased our EUR's on the Marcellus here this go round and then, of course, we've been more quietly than others, working on the Granite Wash to bolster our leasehold position.

We weren't talking about it too much but given all the industry chatter the last month or so, we felt we would be a little more forthcoming on what we've done there.

So, everything that we're working on today, that we have active rig programs on or that 90% of our active drilling program, is doing great and getting better and you can see it in our finding costs.

You can study our finding costs before carry and after carry and see that we're able to find gas below $1.50 and with our carries below $1 and, in fact, this quarter we were at $0.87.

So, I haven't seen a lot of analysis that tells us what happens to a company that can find gas at $0.87 an mcfe over time or increase their reserves by 700 bcfe a quarter.

But my gut tells me it's a pretty good outcome.

And it will result in pretty serious shareholder value creation and that's all driven at the end of the day by, we think, by having the best assets in the business and now the best financial plan to lay on top of those.

So, if we're in it, it's getting better.

But is there one that jumps our when you think back a few months.

We knew the Haynesville would be good but we didn't realize it would be this good or the Marcellus continues to get better.

Can I pin you down a little more or will you give me a little more?

No, we thought the Haynesville would be good.

That's why we went and spent $5 billion acquiring acreage.

We thought the Marcellus would be good.

That's why we went and bought 2 million acres and that's why we have the biggest position in Johnson and Tarrant Counties.

There's quite a science story here that people don't fully appreciate that gets done before the land machine kicks in.

But I think it's a combination of geology and land, which distinguishes us for sure.

Okay.

Can I ask one industry question?

Aubrey, if you look out a year from now, next August, would you care to venture where you think the U.S.

gas rig count would be?

Yes, I think somewhere in the 1,000 to 1,100 and I think that's kind of what's likely to be equilibrium going forward.

On the gas prices?

Well, total rigs, of which, 90% or 85% will be gas.

So, we're at this week, on the gas rig count -- yes, 675, so I would expect we'll say, let's call it around 900, then with another 200 working on oil projects.

And I think you'll see gas prices in the $6, $7, $8 range and there's a lot to like about 2010.

I think it's all setting up right now and there's going to be a lot of kind of wailing and gnashing of teeth here in the next 60 days, as we get slow on storage but after that, you've got an improving economy.

You've got oil at $12 per mcf gas equivalency.

You've got decline curves starting to kick in pretty aggressively.

You've got every E&P company that I watch pretty scared about gas prices and you've got a net speculative short position that will have to turn around at some point.

So, I think it's all shaping up to be a pretty favorable summer of 2010 and you're not likely to get weather as unhelpful as it has been this summer, with New York having the second coldest summer since 1888, I think and Chicago having the fourth coldest summer since 1935 or something like that.

So, our hope is that that foreshadows a little colder winter and we would suspect next summer would be a little warmer.

So, we like 2010 and we're looking forward to getting there.

All right, thanks.

Okay, David.

And our next question comes from Biju Perincheril with Jefferies and Company.

Hi, Good morning.

Aubrey, you had mentioned in the past that you're looking at different joint venture opportunities and I think you mentioned Marcellus and Haynesville.

Is that something that you're still pursuing and can you talk a little bit about an appetite for potential acquirers for such deals, currently?

Sure, Biju.

Actually, we already have partners in the Haynesville and Marcellus and so, are not looking for additional partnerships there.

I think we have said that the Barnett is the only place where we don't have a partner and we have had discussions with various parties, over the last six months, about either small deals or big deals in the Barnett and those discussions continue.

I can confirm that there is enormous world wide interest in U.S.

gas shales and you've already seen that in view of what we have done and of course, the EXCO/BG deal.

There are acquirers from all parts of the globe currently kicking tires on US shale plays.

A lot of them come see us because we've already done these JV's and we've got big positions and we've already said that we would be interested in doing something with somebody in the Barnett.

So we'll remain -- you'll have to just stay close and watch but these things do take time to play out.

We met Statoil in May of '08 and didn't get a deal done until November of '08.

So, these things typically take six months or so to wind their way forward.

So, we wouldn't expect to get anything done before the end of the year.

Okay.

So the acreage that you're adding now in Haynesville and in the Marcellus is something that you want to keep.

Okay.

And then, for your 6.5 bcf type curve for Haynesville, can you say what's the well life that you're using there?

How many years?

Yes, that's 65 years.

And I believe that's our standard across all shale plays, which is actually a pretty interesting point to talk about.

I've seen a number of other EUR's from companies that are at 40 or 45 or 50 years and that actually means that our curves are more conservative, that it takes us 65 to get to say, 6.5 bcfe.

So, if somebody else is at 6.5 bcfe at 50 years, then it means that we probably have some upside in our EUR's over time.

If they're getting there in 50 years and our curves take 65 to get there.

And can you tell what is the terminal decline rate that you were assuming in that curve?

Well, we can give you that - 5%, Steve, in any of our other shale plays, do we have a different terminal decline rate?

Not on the shales in play.

Those big four shale plays, we all use, five year terminals on a 5% terminal decline.

It takes a long time to get there.

I saw something last -- in one of our plays, it took over 20 years to get to the 5%.

From 10 to 20 years it takes to get to that 5% terminal decline rate.

Okay.

And then, one last question from me.

There's been a lot of chatter recently about increased regulations of over the counter derivatives.

I'm sure have you had conversations with folks in D.C.

Anything you would like to share and your thoughts there?

Sure we've been on it from the get-go.

In fact, we have somebody going today or tomorrow.

Thursday.

Thursday, in front of the CFTC.

So, our basic approach is, look, if you want to reduce the industry's ability to mitigate risk, then you're going to reduce the industry's ability to invest dollars and that will cause supply to go down and price to go up.

So, if that's your goal as regulator, the best way to do that is to take away our hedging ability and take away our counterparty's ability to book that, the other side of those hedges.

We'd like to believe that they'll make the right decision but we are talking about Washington D.C.

So, we'll be mindful of the risk there.

Any thoughts that they will continue to allow you to use reserves as collateral or is there a move towards cash?

Is that too early to tell?

Biju, that's been one of the main talking points that we've had with Congressmen, their staff and the various SEC and CFTC.

First of all, explaining how this works, explaining the need, when you produce as much gas as we have, to have the ability to hedge not 1,000 contracts but 350,000 contracts.

Our belief is that the security hedging facilities that we have in place function exactly the way that the regulators have said they want it to function, which is to de-risk the collateral positions that either counterparty have.

And so, once we've explained that and the unique use of those, generally, we've had the people nodding their heads that yes, that doesn't make any sense to take that ability away.

We're all for transparency.

We already report all of our hedges through our SEC reporting.

We're all for other people reporting their hedging, as well but I think we need to maintain the ability to have these secured hedging facilities, which are unique and cannot be traded on the exchanges.

We need to continue to do that to run our business the way that we have run it in the past successfully.

Thank you.

Our next question comes from David Heikkinen with Tudor, Pickering, Holt.

Every question except for one has been answered.

The second quarter interest expenses ended up being lower, kind of looking at where guidance is.

Is there anything going on there and how should we think about overall interest costs?

Well, David, I think interest costs if you think about it on a cash basis, which is what we usually think about, not necessarily the income statement reported, is unlikely to change.

All of our senior notes are fixed in rate and we have an average of under 6% there.

Our bank debt is unlikely to change in rate either.

Generally speaking, as we build a little bit of cash availability by repaying our bank facility from these other items, cash interest costs will generally decline a bit.

Now, there is movement, unfortunately, in the income statement.

Our unevaluated leasehold, we are required to capitalize the interest as part of that and so, that does not show up on the income statement.

But as that unevaluated leasehold becomes more evaluated, there's less interest capitalized and more that flows through the income statement, although, that doesn't change the cash nature of the interest.

So, as you think about capitalized interest, it probably runs about the same as second quarter level, but --?

It was down in second quarter, compared to first quarter because we had taken and moved quite a bit of unevaluated leasehold into the full-cost pool.

Okay.

So, how much is capitalized interest?

Well, it shows up in our 10-Q...

153.

153 for the quarter?

Yes, sir.

I was looking it up but Jeff had it on the top of his head.

Man, it's like he knew my question.

Thanks, that's all I had.

He's insightful, I'll tell you.

He's on top of it.

Our next question comes from Joe Allman with JPMorgan.

Thank you, good morning, everybody.

Aubrey, the total net acreage for the Company appears to have dropped to 14.3 million from 15.2 million, down on a net basis 900,000 acres.

Could you elaborate on that?

Jeff is in charge of that figure, so, my guess is it's just expirations or did we finally drop the -- Jeff it's the decline from 15.2 million to 14.3 million in our total acreage position?

I think part of it was the decision to turn back some farm-out acreage in west Texas to be part of that inventory.

And then, there's some acreage in the Rockies and then, a few expirations on some conventional stuff that we aren't going to get to.

Yes, but if you look at, of course, anything that we have that's remotely core, it actually has been increasing over time.

Yes.

Okay.

That's helpful.

And then you increased the Haynesville and Marcellus - the Haynesville by 40,000 acres and the Marcellus 150,000 on a net basis.

Did you lose any acres such that you actually bought more than 40,000 and more than 150,000 in any significant way?

No, not in a significant way, Joe.

It's possible, somewhere in the Marcellus we let 100 acres go or 1,000 acres that we're no longer crazy about but so much of our acreage there is either HBP from legacy days at Columbia, or it's new leases.

And they typically have at least five years and sometimes 10 years to run.

So, I would just think about our acreage positions in Haynesville and Marcellus and Fayetteville and Barnett, as simply, when they go up, that's a result of new acquisitions.

Okay, that's helpful.

And then, in the Haynesville was that pretty much all north Louisiana or was a chunk it east Texas as well?

No, we're focused basically almost entirely in center cut of the play there in northwestern Louisiana.

Okay.

And then, in all three JV's, do you have a promote in acquiring acreage?

In all three JV's, we do.

Although, our partners have a monthly or quarterly election opportunity to decide whether or not they want to be in that acreage and to pay that promote.

And sometimes they have and sometimes they haven't.

Okay - very helpful thank you.

Okay Joe, thank you.

I think one of our friends in the industry has got a call starting at 9:00 so we'll let the boys at Anadarko take it from here and appreciate everybody's attention today.

Call us back if you have any additional questions.

Thank you.

This concludes today's presentation.

Thank you for your participation.