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Chesapeake Energy Corporation (NYSE:CHK)

Q2 2009 Earnings Call

August 04, 2009 9:00 am ET

Executives

Jeff Mobley - SVP of IR and Research

Aubrey McClendon - CEO

Marc Rowland - CFO

Steve Dixon - COO

Mark Lester - EVP of Exploration

Analysts

Jason Gammel - Macquarie Capital

Michael Hall - Stifel Nicolaus

Scott Hanold - Royal Bank of Canada

Tom Gardner - Simmons & Company

Brian Singer - Goldman Sachs

Lewis Ropp - Barrow, Hanley, Mewhinney & Strauss

Jeff Robertson - Barclays Capital

David Tameron - Wachovia Capital Markets

Biju Perincheril - Jeffreys and Company

David Heikkinen - Tudor, Pickering, Holt &Co

Joe Allman - JPMorgan

Operator

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.

Jeff Mobley

Good morning and thank you for joining our 2009 second quarter earnings and operational conference call. I would like to begin by introducing the other members of our management team who are with me on the call today, Aubrey McClendon, our CEO; Marc Rowland, our CFO; Steve Dixon, our COO; and joining us via separate line is Mark Lester, our Executive Vice President of Exploration.

I would like to draw 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 call. Our prepared comments should last about five to 10 minutes and we will then move to Q&A.

I will now turn the call over to Aubrey.

Aubrey McClendon

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

We're also hopeful that you noticed that the results of our asset quality and the benefit of our carries that Chesapeake's drill bit finding costs in the second quarter were only $0.87 per Mcfe. Certainly that will be the lowest in the industry reported this quarter.

Furthermore, we hope you noticed that returns from drilling in our two granite wash plays are above 100% even in today's low gas price environment. Moreover, we hope you noticed the financial power of our joint venture carries, which paid $311 million dollars in 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 cost 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 is more than a 700% better return than the rest of the industry will likely be able to achieve in the Haynesville.

Remember this carry doesn't include what we have already collected upfront on the initial acreage sale. For example, the per acre cost 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 is even better as our 75% carry from Statoil reduced our drill bit finding cost 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 is more a 15 times better return than our competitors will likely be able to achieve in the Marcellus.

Remember, this carry also doesn't include what we collected upfront on the initial acreage sale to Statoil. The acreage cost for Chesapeake's industry leading 1.4 million net acres in the Marcellus is now just $80 per net acre, 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 have a negative cost of more than $8,000 per net acre. And our returns during the past year 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 JVs 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.

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 monetization's 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 now turn the call over to Marc Rowland for his comments, Marc?

Marc Rowland

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 mid-continent has 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 $0.8, 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, BBP's numbers 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 cost are down or at worst to 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 will now go to questions please.

Question-And-Answer-Session

Operator

(Operator Instructions) And we will take our first question; it comes from Jason Gammel with Macquarie Capital.

Jason Gammel - Macquarie Capital

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

Marc Rowland

Sure, Jason, this is Marc, good morning,. We have got a little bit of an increase, Steve, I know going on in the wash plays specifically

Aubrey McClendon

And continue to ramp up in the Haynesville and Marcellus. We're trying to get ahead of schedule, really with low capital cost in those areas.

Marc Rowland

So Jason I would say it is principally in those three areas. I don't think we have increased in the Barnett at all and don't intend to, and -- of course we are ramping up some in the Marcellus as well.

Jason Gammel – Macquarie Capital

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, where you're expecting higher initial production rates and higher first-year declines. Can you talk about whether that is more a decision on how you're fracking and the lateral link or is this really just more an issue of not having some production history from the rock.

Steve Dixon

This is Steve Dixon. It is really more production history. Though, we are making, we think, improvements in our fracking processes, but the last 15 wells have averaged over $14.3 million IPs and we are just continuing to see higher initial rates and keep that curb at 6.5, just higher initial declines to stay there.

Operator

Our next question comes from Michael Hall with Stifel Nicolaus.

Michael Hall - Stifel Nicolaus

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

Aubrey McClendon

Michael, this is Aubrey. We're probably not at the point of wanting to say a whole lot more about the Marcellus. There is 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. It’s a pretty wide distribution in those two counties, probably across 25, 30 miles would be my guess but, maybe much more or so. And the other is in Northwestern West Virginia, particularly in our Victory Prospect area, and that's an area we are focused in.

We are drilling our first wells in Southwestern Pennsylvania. Right now we have a good acreage position, and Washington, Green County, of course, that's where our range has been active for the last year. So, for reasons of rock quality we are really not playing much in between those two areas but those areas that I just described are of course, multicounty 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.

Michael Hall - Stifel Nicolaus

Then maybe, 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?

Aubrey McClendon

You are saying the curve did not work in our favor?

Michael Hall - Stifel Nicolaus

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.

Aubrey McClendon

Yes, I think a couple things. The first thing is that basis actually improved pretty dramatically and so actually well-head prices did improve.

Michael Hall - Stifel Nicolaus

Okay.

Aubrey McClendon

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 have had bad basis for the past two years or so. We have been long gas, industry has been long gas and short pipe. We're getting ready to move into a world where we going to be long pipe and short gas and so we have 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 are going to be full up on storage by the end of the year. As we get closer to that, pipeline pressures are going to increase and that is going to cause involuntary curtailments. 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 will just let the system work, to spread the pain across the whole industry here over the next couple of months.

Michael Hall - Stifel Nicolaus

One more, if I could as to, any updates on your oil projects that you talked about in the past given the big disparity between crude and gas at this point?

Aubrey McClendon

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?

Steve Dixon

Let's see, 186,000.

Aubrey McClendon

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 is tough to move oil through shales, but we continue to work on some projects. We are producing oil, if I recall correctly, three different shale prospects, but I wouldn't say yet that we have established kind of firm commerciality there on any of those but we continue to plug away at it.

Operator

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

Scott Hanold - Royal Bank of Canada

When you look at your spending activity you did uptick a little bit in '09 and '010. When you think about the acreage you might have to hold and requirements to drill under on your JVs, is that going to influence expectations going forward or do you think you're pretty well covered at least in the next couple years in that?

Aubrey McClendon

We have designed our drilling program over the last couple of years, and entered into these JVs with a plan to be able to hold all of our production -- all of our acreage, live production in the Fayetteville and Haynesville and 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.

Scott Hanold - Royal Bank of Canada

Okay and that’s based on the current '09 and '010 program and what kind of pace would you have to look at in '011. Would that need to be stepped up to continue that?

Aubrey McClendon

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

Scott Hanold - Royal Bank of Canada

Okay. Appreciate it and one more if I could, in the Granite Wash, obviously there's some pretty tremendous industry results up there. What is your ability really to ramp up activity, given, some of the premium economics out there? Is there the capacity, infrastructure capacity to do so?

Aubrey McClendon

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 and pretty easy drilling, though the administrative, 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 are your best dollars in the company, on a pre-carry basis.

When you include carry, its obviously, drilling in the Haynesville and Marcellus and Fayetteville to beat those plays. So, right now we're just using four rigs in Colony to HVP acreage and I think we have HVP, 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 acreages there are sold by production and so really it's just completely selective drilling and, you want to pick and choose your time. It's, 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.

Scott Hanold - Royal Bank of Canada

Yes, understood. And with the Granite Wash plays, I mean how predictable do you think you can get those results. Obviously some recent results coming up from you all and the new field has been tremendous, is that fairly repeatable? Or do you feel more or less competent in doing that in the Granite Wash than say, the Marcellus or the Haynesville?

Aubrey McClendon

All right, well first of all, we have been drilling in colony wash for two-and-a-half years now, so we have a pretty wide distribution of drilling results. And it all depends on rock quality. It's not, 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, all the way to the sea.

In the Texas granite wash, some people call it Buffalo Wallow some call it [Sprouts Ranch], 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 overtime will be developed horizontally. You're going to see widely different results; again it is going to depend on being able to map out the sweet spots.

What is nice on our acreage and I presume on some other 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 benches of the granite wash and found them all to be successful.

So, it’s a great play. We're a little weaker in the Texas Panhandle than we would like but very, very strong in this field in Custer and Washita Counties that we discovered in February of '07, it’s called Colony Granite Wash.

Operator

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

Tom Gardner - Simmons & Company

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?

Aubrey McClendon

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 is our goal for the year is to beat those numbers and so it looks like we are on course to do that and we will let you guys, do your jobs of analyzing and predicting and we will just set forth our goals for the year and do our best to beat those.

Tom Gardner - Simmons & Company

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 is inertia there on that deflation?

Aubrey McClendon

We're probably bottoming and have bottomed, then we probably get some of it back but we don't expect the rig counts to pop-up too many fleets, going forward. I would be surprised to see it above a thousand or 1100 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 1700 or 1800 rigs in the US so there will have to be some rationalization of capacity, I think, in the industry. In the meantime I think most of that capital will stay around and will keep prices reasonably low for us. Marc you want to add anything else?

Marc Rowland

Yes, I would just focus on the capacity. We have got, an environment where you have nearly 2,000 rigs running, less than half of those now -- I know in our service businesses that we have invested in, rigs are mostly down, frac service equipment hag been stacked, people have been laid off.

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

Tom Gardner - Simmons & Company

Thanks for that Marc. 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?

Aubrey McClendon

We will let Jeff take that. Go ahead, Jeff.

Jeff Mobley

You know, there are some flaws in the 914 data. And, you know, a change in the 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 have done quite a bit of work to try to model out US gas production and so far, the numbers that we have seen reported for that EIA are right on top of the model that we have outlined. So I have a pretty 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 have 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 decline on a year-over-year basis, of perhaps as much as 2.5 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.

Operator

Our next question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

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 also I noticed you did put out some little more granularity on well results than you usually do. How should we look at that?

Aubrey McClendon

You view further acreage acquisition is a good thing or a bad thing?

Brian Singer - Goldman Sachs

It probably depends on one's views on the individual plays, I would think right?

Aubrey McClendon

Well, if you like the Marcellus we continue to acquire acreage there, 150,000 net acres in the core in the last three months. I think in the Haynesville, 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 a thousand acres a month or so. So main areas of further acreage acquisition are in 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 highlights and it seems like a lot of other companies give highlighted production, 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 the Marcellus 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 have seen, on the decline curve so far we felt comfortable in going from 3.75 to 4.2 Bcfe there.

Brian Singer - Goldman Sachs

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 this happening first?

Aubrey McClendon

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 is going to depend also on where declines are kicking in and then the 914 data is beginning to show. We track it here. Of course our conventional production, 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 we'll accelerate in the second half of the year and so that will have some relevance as well. Then the whole -- the pipeline system is so big and integrated that its really hard to imagine, to exactly be clear on where it is 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 the full storage faster than other areas, which of course will then create some pretty significant production problems there as well as price problems.

Brian Singer - Goldman Sachs

Great, thank you. If I could asked 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 seems like in the Haynesville, you may be factoring in some pipeline delays. Where do you think your production rather could otherwise go to, in the absence of those delays?

Aubrey McClendon

Brian we believe we will have all the pipeline projects we need in place meaning that we're not building ourselves to be in place as well. This is something that our mid-stream 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 grounds, as well as what others will be doing.

Operator

Our next question comes from Lewis Ropp with- Barrow, Hanley, Mewhinney & Strauss.

Lewis Ropp - Barrow, Hanley, Mewhinney & Strauss

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 is out this morning, there is an implied percentage of hedges for 2010 and one of the pieces that is only at 21%, talks about lifting some of your hedges. And I think they are just omitting the call options that are written in 2010. That kind of made me question if I really understood the way those call options work. So I was hoping you could just clarify that you know that is the bulk of the hedges that are in place for 2010, the way I understand it?

Marc Rowland

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 are generally paid a premium that depending on the strike, price can range from $0.50 or so to up just over a $1.00. And I think most analysts correctly view that in a low price environment that that price protection is only for the premium that you have received, it doesn't protect you for falling prices.

Most of the hedges that we have lifted have been in the back half of 2010. Where it is our belief that between now and then you will see a substantial rise in the price levels and we'll 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 we're eliminated and converted into either callers or into pure swaps. So, hopefully, that answers your question.

Lewis Ropp - Barrow, Hanley, Mewhinney & Strauss

Yeah thank you. My next question is I know 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?

Aubrey McClendon

Well, Statoil JV in the Marcellus continues to work well. I presume you're talking about the world wide initiatives that we have. I am really not wanting to show our hand there. I think a few months ago Statoil did comment we were working on 14 different areas, and that's where we had narrowed our worldwide search too.

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. So, we couldn't be happier than to be affiliated in a partnership with Statoil. I think of course what we bring to the table is we can find rocks around the world that we can analyze and look, determine if they look like they are going to be prospective.

For kind of an overall world economy, and 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 begins to decline at some point and then gas will increase it market share along the way so all good there.

Also, Lewis, I appreciate your appreciation for the way that we split our earnings and operational announcements up. We just realized we were probably overwhelming people with data and this gives people a few days to focus on our operation before they begin to focus on our financial results.

Operator

Our next question comes from Jeff Robertson with Barclays Capital.

Jeff Robertson - Barclays Capital

Good morning, Aubrey. In the Haynesville you all have drilled 56 wells since -- 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?

Aubrey McClendon

Well, you know a vast majority of it I think -- Jeff, what risk factor do you have -- are you at reducing by 40%, it seems like Mark will -- he will check on that but yes, we are risking our total acreage position by 40%. I don't think we changed that from the first quarter and probably could, but just decided not to.

But the vast majority of our Louisiana acreage is now well within what we would call the core -- we got some acreage kind of north of Shreveport and a little bit west of Shreveport but not significant. So my view is, 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. The question is, is it going to be 4 or 5 Bcf or 6 to 7 Bcf, or is it going to be 9 to 10 Bcf.

I think what you are going to see develop in the plays, what you are seeing of course in every shale play is that you're going to see range of outcomes and those companies that have acreage, focused on the Texas side of play, are going to see lower [Ewarsville] 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 is where you're seeing the 20 million a day plus well.

So, right now we are focusing exclusively on getting our acreage held by production. We're also testing some of our outlying acreage just to see how good our perspective, it may be, but right now, it looks like our petrophysical and geological model we built three years ago for the Haynesville has 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 acreage acquisition right in the gut of the play.

Jeff Robertson - Barclays Capital

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?

Aubrey McClendon

We're actually below our target right now. I will let Steve handle that.

Steve Dixon

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

Aubrey McClendon

Steve, we actually completed some wells under 7 yet and I was under the impression that we were?

Steve Dixon

Yeah we're down to – we have done some $6.5 even Aubrey. But not that we won't have higher cost wells so…

Jeff Robertson - Barclays Capital

Steve, were 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?

Steve Dixon

Well, it is combination. A lot of the lower ones have been some extremely high, penetration rates where we got the wells drilled very quickly. That is the other thing we will be looking at here in the Haynesville is increase our cycle time forecast also because our days are coming down as quickly.

Jeff Robertson - Barclays Capital

Okay. Then secondly on the -- 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 notice in the Indigo sale you reserved the Haynesville rights and kept and sold the more traditional Cotton Valley zones?

Aubrey McClendon

Yeah, are you -- is your question directed at Bossier shale rights or directed at uphold Cotton Valley rights.

Jeff Robertson - Barclays Capital

Cotton Valley.

Aubrey McClendon

You know 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 farmouts from -- oh, from Goodrich, or farm-ins from Goodrich and Matador, for example, I am pretty sure we don't have uphold rights but I would say probably 80 or 90% of our acreage we're going to have oil rights and of course we're focused on making sure we have Bossier shale rights as well and the Bossier is right above the Haynesville. So every time you drill, the Haynesville well you're penetrating the Bossier and so should be [HBPing] and holding that acreage as well.

Jeff Robertson - Barclays Capital

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

Marc Rowland

It won't change, Jeff, the operating costs at all. The structure as we're 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 build essentially at fixed costs per Mcf and they are 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 is no processing involved, so there is no liquid stream. So it is basically a molecule moves through, we measure it and send a check over, so the cost will remain the same.

Aubrey McClendon

I might interject here, we received a couple of comments about the midstream project has taken a long time to bring to fruition. I thought I might give Marc the opportunity to just mention why its 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.

Marc Rowland

It has taken me I think about half my life to do this project but it is nearing completion. We have 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 mid-continent systems.

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

Operator

And our next question comes from David Tameron with Wachovia.

David Tameron - Wachovia Capital Markets

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

Aubrey McClendon

Yeah I mean I don't -- 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 have drilled in the last three or four months, in the Barnett. Fayetteville, we have -- I think we're the only company to have a $6 million a day well there, and both we and Southwestern continue increase results and that we are have 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 EURs on the Marcellus here at this go around and then of course; we have been more quietly than others, working on the Granite Wash to bolster our leasehold position before 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 have 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 $1.00. And, in fact, this quarter we were at $0.87.

I haven't seen a lot of analysis that tells us that what happens to a company, that can find gas at $0.87 Mcfe over time, or increase their reserves by 700 Bcfe a quarter. But my gut tells me it is a pretty good outcome and will result in pretty serious shareholder value creation. And that is all driven at the end of the day as we're I think having the best assets in the business and now the best financial plan to lay on top of those. If we are in it getting better.

David Tameron - Wachovia Capital Markets

That is the one that jumps back when you think back a few months. We knew the Haynesville will be good but we didn't know it would be this good. The Marcellus continues to gets better. Can I pin you down a little more or will you give me a little more?

Aubrey McClendon

No, I mean we thought the Haynesville would be good. That is why we went and spent $5 billion and acquired acreage. We thought the Marcellus would be good. That is why went and bought two million acres. That is why we have the biggest position in Johnson and Tarrant counties. There is quite a science story here that people don't fully appreciate that gets done before the land machine kicks in but I think is a combination of geology and land which distinguishes us for sure.

David Tameron - Wachovia Capital Markets

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 US gas rig count would be?

Aubrey McClendon

Yeah, I think somewhere in the 1000, 1100. I think that is kind of what is likely to be equilibrium going forward.

David Tameron - Wachovia Capital Markets

On the gas prices?

Aubrey McClendon

Well, total rigs at which 90% or 85% will be gas. So, we're at this week, on the gas rig count…

David Tameron - Wachovia Capital Markets

675.

Aubrey McClendon

Yes, 675. So I would expect let's say, let's call it around 900 than with another 200 working on oil projects and I think you will see gas prices in the $6, $7, $8 range. There is a lot I like about 2010.

I think it is all setting up right now and there is going to be a lot of kind of wailing and gnashing of teeth here on the next 60 days as we get full on storage but after that you 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 have watched pretty scared about gas prices so, and you got a net expected short position that will have to turn around at some point.

So I think it is 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. We like 2010 and, we're looking forward to getting there.

Operator

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

Biju Perincheril - Jeffreys and Company

Aubrey, you had mentioned in the past that you're looking at a different join venture opportunities and I think you mentioned Marcellus and Haynesville. You said something that you're still pursuing and, can you talk a little bit about an appetite for potential acquirers for such deals, currently?

Aubrey McClendon

Sure. Biju. Actually we already have partners in the Haynesville and Marcellus, 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 US gas shales and you have already seen that in deals that 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. So a lot of them come see us because we have already done these JVs and we have got big positions and we have already said that we would be interested in doing something with somebody in the Barnett.

So we will remain -- you will 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.

Biju Perincheril - Jeffreys and Company

Okay, perfect. So the acres that you are adding now in Haynesville and Marcellus is something that you want to keep. Then, for your 6.5 Bfc type curve for Haynesville, could you say what's the well life that you're using there? How many there?

Aubrey McClendon

Yes that is 65 years. I believe that is our standard across all shale plays, which is actually a pretty interesting point to talk about. I have seen a number of other EURs from companies that are at 40 or 45, or 50 years and that actually means our curves are more conservative, that it takes us 65 to get to say, 6.5 Bcfe. If somebody else is at 6.5 Bcfe at 50 years then it means that we probably have some upside in our EUR over time, if they are getting there in 50 years and our curves take 65 and get there.

Biju Perincheril - Jeffreys and Company

Can you tell what the terminal decline rate you were assuming in that curve?

Aubrey McClendon

We can give you that. 5%, Steve do you have anything on out other shale plays do we have a different terminal decline rate?

Steve Dixon

None of those shale is in decline.

Aubrey McClendon

Those being four shale plays we all use five year terminal on a 5% terminal decline. It takes a long time to get there. I saw something last -- one of our plays that took over 20 years to get to the 5%. So from 10 to 20 years it takes to get to that 5% terminal decline rate.

Biju Perincheril - Jeffreys and Company

One last question from me. There has been a lost chatter about increased regulations over-the-counter derivatives. I am sure you have had conversations with folks in D.C. , anything you would like to share and your thoughts there?

Aubrey McClendon

Sure. We have been -- from the [get-go] In fact, if somebody is giving a testimony today or tomorrow.

Biju Perincheril - Jeffreys and Company

Thursday.

Aubrey McClendon

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

If that is 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. That we have decided those hedges we like to believe they will make the right decision but, we are talking about Washington D.C., so we will be mindful of the risk there.

Biju Perincheril - Jeffreys and Company

Any thought that they will continue to allow you to use reserves as collateral or is there a move towards cash. Is that too early?

Marc Rowland

Biju, that has been one of the main talking points that we have had with Congressman, 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 a thousand 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 have explained that and the unique use of those, generally we have had people nodding their heads to 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 way to run our business the way that we have run it in the past successfully.

Operator

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

David Heikkinen - Tudor, Pickering, Holt &Co

Every question except for one has been answered. On the second quarter interest expenses, I know they are being lower kind of looking at where guidance is. Is there anything going on there and how should we think about overall interest costs?

Marc Rowland

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 changing 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. So that does not show up on the income statement. But it is that unevaluated leasehold becomes more evaluated there is less interest capitalized and more that flows through the income statement. Although that doesn't change the cash nature of the interest.

David Heikkinen - Tudor, Pickering, Holt &Co

So, about capitalized interest. Probably runs about the same as second quarter level, but…?

Aubrey McClendon

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.

David Heikkinen - Tudor, Pickering, Holt &Co

So how much is capitalized interest? Maybe I missed the line item in the…?

Aubrey McClendon

Well, it shows up in our 10-Q. I don't know that we…

Jeff Mobley

153.

Aubrey McClendon

153 for the quarter?

Jeff Mobley

Yes, sir.

Aubrey McClendon

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

David Heikkinen - Tudor, Pickering, Holt &Co

Man, it is like he knew my question.

Jeff Mobley

Thanks, that was in the top of my head.

Aubrey McClendon

He's insightful, I think.

David Heikkinen - Tudor, Pickering, Holt &Co

Yes, he's on top of it.

Operator

Our next question comes from Joe Allman with JPMorgan.

Joe Allman - JPMorgan

Aubrey the total net acreage of the company appears to have dropped to 14.2 million from 15.2 down on a net basis 900,000 acres. Could you elaborate on that?

Aubrey McClendon

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

Jeff Mobley

I think part of it was the decision to turn back some farmout acreage in West Texas to be part of that derivative of some acreage in the Rockies and then a few explorations on a few conventional stuff we aren't going to get to.

Aubrey McClendon

Yes if you look at of course at anything that we have that is remotely core that actually has been increasing over time.

Jeff Mobley

Yes it might Aubrey.

Joe Allman - JPMorgan

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 and more than 150, in any significant way?

Aubrey McClendon

Not in no, I significant way, Joe. It is possible, somewhere in the Marcellus we let 100 acres go or a thousand 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 is new leases and 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 is a result of new acquisitions.

Joe Allman - JPMorgan

Okay that's helpful. Then in the Haynesville was that pretty much all North Louisiana, or was a chunk it East Texas as well.

Aubrey McClendon

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

Joe Allman - JPMorgan

Okay. Then, in all three, just a last question. Ad all three JVs, do you have a promote in acquiring acreage in all three JVs.

Aubrey McClendon

In all three JVs 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. Sometimes they have and sometimes they haven't.

Joe Allman - JPMorgan

Okay. Very helpful thank you.

Aubrey McClendon

Okay, Joe, thank you. I think one of our friends in the industry has got a call starting at 9:00. So, we will let the boys at Anadarko take it from here. We appreciate everybody's attention today. Call us back if you have any additional questions. Thank you.

Operator

This concludes today's presentation. Thank you for your participation.

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Source: Chesapeake Energy Corporation Q2 2009 Earnings Call Transcript
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