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Chesapeake Energy Corp. (NYSE:CHK)

Q2 2007 Earnings Call

August 3, 2007 9:00 am ET

Executives

Jeff Mobley - IR

Aubrey McClendon - CEO

Marc Rowland –CFO

Steve Dixon - COO

Analysts

Brian Singer -Goldman Sachs

Shannon Nome - Deutsche Bank

Jeff Robertson - Lehman Brothers

David Heikkinen - Pickering Energy Partners

Gil Yang - Citigroup

Jeff Hayden - Pritchard Capital Partners

David Kessler - Simmons and Co

Joe Allman – JP Morgan

Ben Dell - Bernstein

John Massling – D.E. Shaw

Monica Verma - Gilford Securities

Presentation

Operator

Good day and welcome to this Chesapeake Energy second quarter 2007 conference call. Today's conference is being recorded. At this time for opening comments and introductions, I would like to turn the call over to Jeff Mobley, Senior Vice President of Investor Relations and Research with Chesapeake Energy. Please go ahead.

Jeff Mobley

Good morning and thank you for joining Chesapeake's 2007 second quarter conference call. Hopefully you've had a chance to review our earnings release and our updated slide presentation posted to our website yesterday afternoon.

Before I turn the call over to Aubrey and Marc, I need to provide you with disclosure concerning the forward-looking statements that Chesapeake's management will make during the course of this call. The statements that describe our beliefs, goals, expectations, projections or assumptions are considered forward looking. Please note that the company's actual results may differ from those contained in such forward-looking statements. Additional information concerning these statements is available in the company's SEC filings.

In addition, I would also like to point out that during the course of our discussion this morning, we will mention terms such as operating cash flow and EBITDA and will also mention several items that we believe are typically excluded from analyst estimates. These are all non-GAAP financial measures. Reconciliations to the comparable GAAP measures can be found on pages 21 through 24 of our press release issued yesterday. While these are not GAAP measures of financial performance, we believe they are common and useful tools in evaluating the company's performance.

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

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Aubrey McClendon

Thanks, Jeff, and good morning to each of you. I would like to begin by introducing the other members of our management team who are on the call today. Marc Rowland, our CFO; Steve Dixon, our Chief Operating Officer and Jeff Mobley, whom you have already heard from, is our SVP of Investor Relations and Research.

Without a doubt, the second quarter of 2007 will go down in Chesapeake’s history as our best operational quarter ever. We overtook two large independents and one major company to become the largest independent producer of U.S. natural gas and the third largest U.S. gas producer overall. Given that BP and Conoco-Phillips are the only two companies that now produce more gas than Chesapeake does in the U.S. and given their production continues to decline while ours continues to increase, it seems inevitable that sometime in 2008, Chesapeake will become the largest U.S. producer of natural gas. I believe not many of you or any of us would have thought that possible eight or nine years ago.

During the quarter, Chesapeake's production increased by 161 million cubic feet of gas equivalent per day on a sequential basis, and that's a 9% increase in just one quarter. Our production also increased by 300 million per day on a year-over-year basis, that's a 19% increase. Virtually all of these production increases came through the drill bit. I think the enormity of these accomplishments is best appreciated when you compare our production increases to the total production that some of our well-regarded industry colleagues have recently reported. For example, companies such as Southwestern, Range, and Ultra all produce around 300 million per day and they all have enterprise ranging from $7 billion to $9 billion. So I think it's fair to say in one year we have created an equivalent company of those companies inside of Chesapeake, and believe we have created an also equivalent $7 billion to $9 billion of value inside of Chesapeake. Yet I believe we did so on a broader and more risk-mitigated platform.

Further, we are projecting that Chesapeake can continue these exceptional increases in production in the years ahead. Hopefully you noticed we are now projecting 18% to 22% production growth for 2007, that's an increase of 400 basis points from our production forecast of just 90 days ago. Moreover, we have also increased our production growth forecast for 2008 by an identical 400 basis points to a range of 14% to 18% from our previous range of 10% to 14%.

While we will not issue Chesapeake's additional 2009 production forecast until three months from now, we will likely begin with a production forecast growth rate of around 10% for 2009. So we believe it's likely that Chesapeake could be producing around 2.5 Bcfe per day at year end 2009. Perhaps more importantly, in 2009 we should be able to once again reach steady state equilibrium between our operating cash flow and our budgeted drilling, leasehold, and seismic expenditures.

Alongside our production growth, Proved and unproved reserves have been rapidly growing as well. At beginning of the year we started with 9 Tcfe of proved reserve and hope to get to 10 Tcfe by year end 2007 and 11 Tcfe by year end 2008, and 12 Tcfe by year end 2009. It now looks like those forecasts were too conservative and we have already reached our 2007 year end proved reserve target at midyear 2007. It now looks like we could be between 10.5 and 11 Tcfe of proved reserve by year end 2007, somewhere around 12 to 12.5 Tcfe by year end 2008, and perhaps as much as 13 to 14 Tcfe of proved reserves by year end 2009.

Furthermore, our risk unproved reserves continue to expand alongside our proved reserves as our acreage and seismic inventories continue to grow. We now recognize more than 80 Tcfe of unrisked, unproved reserves on our acreage and almost 21 Tcfe of risked unproved reserves. The relationship of 2:1 between our risked and unproved reserves and our proved reserves that has developed over the past few years is likely to continue in the future, giving further visibility and confidence into Chesapeake's ability to maintain its high growth rate at attractive finding costs.

We have examined our assumptions rigorously, have mitigated our risk substantially, and now believe that the gas factory that we have been building for the past five years is running 24/7 at high speed and low-risk and should be able to generate net asset value growth of $7 to $10 per share per year for 2007 through 2009. Working from a $35 per share basis, we believe this 20% to 30% per share net asset value creation should be very attractive to our shareholders.

I would also like to remind you that our growth is being generated from multiple geographical areas and from multiple play concepts. For example, of the 300 million per day of year-over-year production increase, approximately one-third came from the Barnett Shale. 13% came from Southern Oklahoma, 10% came from Deep Haley, and by the way, that does not include the recent 40 million per day of production we picked up from Anadarko; 10% came from Sahara, and the final one-third came from our other plays.

I believe this diversified growth profile highlights the broad strength of our overall platform. We are not a one play company, yet we have the high growth profile associated with one, but without the attendant execution risks associated with one. I might also add that we have several new play concepts presently being tested and if successful could be valuable additions to our portfolio.

Given that the Fort Worth Barnett Shale is our most important growth area, I thought a detailed operations update might be in order. We entered the Barnett in November 2004. and one year later we are running four operated rigs. Two years later, in the fall of 2006, we were running around 20 rigs and today we are running 35 operating rigs and will further increase that to 38 rigs in the next few months. We continue to enjoy very attractive drill bit finding costs from our Barnett acreage of around $1.50 to $1.60 per Mfce. In case you're curious, our average acreage, brokerage, and seismic costs average around $10,000 per net acre, yet that only adds about $0.35 per Mcfe to our finding cost.

So think with me for a moment about the future value creation implications of being able to spend $10 billion in the years ahead to drill 4,000 Barnett wells at an all in finding cost of less than $2 per Mcfe. I am certain the enormity of the upside of our Barnett assets in the Fort Worth area is not yet fully understood by the market, but will be in due course.

The purpose of our large scale Barnett drilling ramp-up is, of course, to make this enormous upside more visible and tangible by turning our non-producing leasehold into cash flowing producing PDP assets. Let’s see how we’ve done in that effort to date.

Three years ago we had no production in the Barnett, two years ago we averaged 35 million a day during the second quarter, and one year ago this past quarter, we averaged 110 million per day. More recently, in the fourth quarter of 2006, we averaged 157 million a day from the Barnett. In the first quarter of 2007, we averaged 180 million a day, and in the second quarter we averaged 207 million per day. Currently, we are producing about 230 million per day net from the Barnett.

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

We expect to see further impressive increases in Chesapeake's Barnett production through 2008. In fact, we can see Chesapeake's Barnett production increasing through at least 2010, as we remain on track to bring one new well into production every 15 hours for the next four years. If you were doing that math alongside me, you'll notice there are 35,040 hours in the next four years and therefore Chesapeake should bring on approximately 2,200 new well ifs that time frame. Please think about the substantial future impact of those well when you consider we have drilled fewer than 500 wells in the play today.

I would also highlight that Chesapeake's Barnett assets are focused in the best geological part of the play, the core and tier 1 area of Northern Johnson County, Western Dallas County, and all of Tarrant County. In this area, Chesapeake has amassed over 180,000 net acres and we are adding to that total by approximately 10,000 net acres per quarter. At that rate of leasehold acquisition, we should be able to maintain a rolling backlog of some 2,500 undrilled wells for years to come.

When it's all said and done, we expect Chesapeake will have been able to drill more than 4,000 net Barnett wells from a land area inventory that should ultimately reach 300,000 net acres in the core and tier 1 area of Johnson, Dallas, and Tarrant Counties. These 4,000 net wells should generate approximately ultimate reserve recoveries of more than 7 Tcfe for Chesapeake, of which we have only booked 1.5 Tcfe to date. I might also add that we are routinely bringing on wells that initially produce 3 to 5 million cubic feet of gas per day and our per-well production average will likely creep up over time as we drill more wells in Tarrant County and fewer in Johnson County, where to date about 85% of our existing Barnett wells have been located.

I might also update our DFW airport drilling activity. On that airport, we are utilizing five rigs to drill on this 18,000 acre lease, which is the largest single contiguous lease in the Barnett Shale play. We have reached total depth on 12 wells to date and are reaching total depth on a new well every approximate four to five days. Barnett Shale underneath the airport looks excellent and is the thickest we've seen to date in the entire play. We will begin completing our first wells at the end of this month and are hopeful that these DFW airport wells will redefine what a monster well is in the Barnett.

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

I will conclude my comments today with a few thoughts about the MLP market. We have decided to not form a CHK dropdown MLP, as we see potential tax and governance issues associated with such vehicles. So instead of forming our own MLP, we have decided to sell into the MLP market a production stream of 30 million cubic feet of gas per day in the form of a non-operated, approximate 35% undivided working interest in approximately 4,300 Chesapeake operated wells in Appalachia. To maximize the appeal of this production stream to both the MLP market and also to various financial buyers, for the first four years of the life of the properties, Chesapeake will guarantee a flat production curve of 30 million per day and we will also guarantee a NYMEX price of $7.50 per MMBTU, a positive differential of $0.30 per MMBTU, and we will lock in our gathering transportation and overhead costs at attractive levels for the buyer. In addition, we will assign only well bore rights and they will also be depth limited, so all of the production upside will remain with Chesapeake.

In summary, the buyer of this production will receive one net monthly check from Chesapeake, will have no operating hassles, and will be guaranteed flat production levels and attractive production pricing for the first four years of the life of the properties. We believe this will be a very attractive offering to both the financial and MLP marketplaces and we hope to receive at least $600 million from this sale. This offering and others like it that we can do over the next few years, will be an important part of our financial plan as we move from the heavy capital overspend of 2007 into a more moderate overspend level in 2008 and finally in 2009 we expect to regain equilibrium between our operating cash flow and our budgeted drilling, leasehold, and seismic CapEx. By that time, we hope to be producing around 2.5 Bcfe per day. We hope to own between 13 and 14 Tcfe of proved reserves, and we expect to have a materially higher stock price.

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

Marc Rowland

Thanks, Aubrey. Good morning to everyone on the call. Obviously, another great quarter from an operating and financial perspective. I won't spend any time at all going through the press release, but instead we'll provide some incremental detail to what Aubrey's already provided.

Our drill bit finding costs move downed to $2.14 per Mcfe in Q2 versus what we reported $2.66 in Q1. We have continued to see flat to slightly down service costs over the last few months, with some areas, such as the Barnett Shale, reflecting lower stimulation cost as more equipment and new service providers enter into that market. Overall, we have seen an 8% reduction in intangible drilling costs in the first half of 2007. Our expectations for service costs for the remainder of the year remain the same. That is, some downward forces as more rigs and equipment become available.

In the Barnett alone for the quarter, drill bit costs were $1.62. As Aubrey mentioned, leasehold adds were about $0.35 per Mcfe for an all in cost of $1.97. As you can see, a very valuable resource in the core area and about one-quarter of our budgeted current quarter drilling efforts.

Specifically, we now see rig rates in Oklahoma based on 1,000 horsepower rigs down to $16,500 to $17,750, which is down from six months ago, which was $17,500 to $19,000 per day. In Texas, most recent rig rates a $15,500 to $17,500 down from $18,500 to $21,500 per day six months ago, so a more substantial decrease as more rigs have moved in from the Rockies and even Canada, plus the new builds in that area.

Stimulation costs, which is an important part of our budget, amounts to about 40% of our overall spending are down about 7% on average so far this year. Cementing in less active areas is flat to down 5% while in the Barnett Shale and Sahara, areas that attract more equipment, prices are down 20 to 25%. Basin prices are down 6% from six months ago and about 12% from a year ago. Looking ahead, continued cost declines of 10% to 12% per year result in $500 million to $700 million of cost reduction in our annual run rate of drilling CapEx of the current rig count. That is our forecast for the remainder of this year and into 2008.

A highlight of the quarter was the profitable exit from our investment in Eagle Energy Partners. We first invested only $6 million with Eagle in September of 2003. Subsequent cash investments grew over time to total $33 million. We sold for $126 million, a pretax cash gain of $93 million. This does not include distributions received by us in cash of $10 million over our ownership period. So, our return on investment in this particular venture was in excess of 280%. We have remaining investments in gas tar, chaparral, drilling and stimulation company ventures and other companies with a book value of about $650 million as of June 30 and we believe these investments are worth much more than what we've invested and we believe that they'll be profitable as was Eagle in the future.

On another topic, during the past two quarters, several investors have inquired about how we plan to close the funding gap between cash flow from operations and capital expenditures. This gap exists currently as a result of our accelerated drilling program that has enabled Chesapeake to grow at rates at the top of our peer group and build an industry-leading drilling inventory. We have several attractive alternatives at our disposal. Of course, the sale of a minor amount of mature PDP-only reserves, as noted by Aubrey and in the earnings release should result in proceeds well north of $600 million. To be able to sell production that is less than 20% of our production increase in just this quarter, and I'm emphasizing just the increase in production, for proceeds that we expect could fund about 60% of our quarterly exploration and development costs seems very attractive to us. Obviously, this could be repeated over time and become a very compelling financial model for you, our investors. .

Other funding sources in our toolbox that we are working on currently include a second sale leaseback transaction of 33 additional drilling rigs. We believe this will result in $250 million to $300 million of proceeds by the end of Q3. Also, we are creating a new sale leaseback transaction for our compressor fleet. Initial proceeds will likely be in the $200 million to $250 million range and then be sized to provide financing of all compressor needs for the next two to three years, which will likely be in the $300 million to $400 million range. This transaction is likely to close in the early part of Q4. All of this will come to us at a cost of financing rates around 5% while we maintain complete control of operations and ultimately the assets will come back to us.

One other option we occasionally consider is selling volatility, one of our often unappreciated assets. In the market today, out of the money $10 to $12 natural gas calls from 2009 to 2012 are trading for as much as $1 per Mcfe and could be an attractive funding source, particularly if gas prices and volatility spikes. All of these alternatives we rate ahead of the formation of an MLP and certainly way ahead of selling equity.

As evidenced by the dramatic growth in reserves and production, the company has significant opportunities to drill at very high rates of return. While we have no immediate plans to issue common stock or preferred stock, the continued use of traditional balanced equity and debt issuance makes complete sense given our opportunity set while maintaining and improving our credit ratios.

It has been this strategy that has allowed us to grow this company to the largest independent producer of U.S. natural gas while also increasing the net asset value per share and while improving our credit rating over the last eight years. While the traditional high yield market is in a bit of a mess, the convertible market remains attractive and we view the net share convertible instrument as an attractive alternative.

To remind you of how attractive this instrument was when issued three months ago, I want to talk a little bit about the details and conclusion. Remember that the principal is paid back in cash while accruing a cash interest cost of 2.5% per annum. We did this three months ago by granting the buyer a warrant overlay structure that allows them to buy CHK stock when above a conversion price that was 50% or more above the price then, which results in a very small amount of dilution. In fact, only about 900,000 shares at $53, which escalates to a capped amount of only 11 million shares at a price of $80. And then, of course, this is after the stock's gone up substantially from the current level. So we felt like this was the right instrument at the time. There were some people that questioned this, but we continue to view it as a very attractive form of capital injection into the company.

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

Question-and-Answer Session

Operator

We'll go first to Brian Singer -Goldman Sachs.

Brian Singer -Goldman Sachs

You've highlighted in the past, as you do today, the relative valuation gap between similar single-asset companies relative to Chesapeake. Historically you've rationalized this to size-related differences, which Chesapeake formerly benefited when it was a smaller company. At what point would you consider spinning off some of your more growthier assets that could then command a premium compared to what you have today?

Aubrey McClendon

Brian, I don't think that's something we plan on doing. I think we believe the company's strength is its scale and all the resources that we have here that actually can, on a unified basis, continue to help move the full company forward. So my view is that we are now at a level where we are able to produce production growth equal to or above most of the higher growth smaller companies, yet we do so without the risk associated with a one play story.

So we like the position we're in. Frankly don't care if our multiple ever gets to the multiple afforded some smaller companies. We were the beneficiary of that for many years. All we're about is turning leasehold into PDP and know that over time as we continue to generate greater net asset value per share, that will be recognized by the market.

Brian Singer -Goldman Sachs

Great. On the capital spending front, in terms of how you think about CapEx equaling operating cash flow in 2009, you highlighted the MLP ongoing potential sales there. How do you think about CapEx levels beyond '08 and do you continue to expect you'll be ratcheting up activity levels, or do you see a more flattish CapEx as you seem to in '08 versus '07?

Marc Rowland

Right now, as we discussed on our outlook, we have CapEx projected to be flat in 2008 compared to 2007. We won't be putting out our official forecast for 2009 until 90 days from now, but right now we would view that we're more or less in a steady state for CapEx. That would change only when new plays develop. I mentioned them in my comments that we do have several new plays that we're working on and some of them if successful could require significant expansions of drilling.

It's also possible that we still have a few plays in the company that are successful today that might need more rigs down the road. Those are high-class problems to have and we'll address those as we move forward, but right now we're looking at flattish CapEx in '08 versus '07 and also, I think that we're looking at drilling costs that likely will not increase in the future. I think we've been hit with the brunt of those and going forward our own drilling efficiencies and lower per unit costs should enable us to achieve more drilling with about the same amount of dollars.

Operator

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

Shannon Nome - Deutsche Bank

Aubrey, you said you're completing a well on the Barnett every 15 hours. Can you convert that into minutes and seconds? No.

Aubrey McClendon

Indeed I can.

Shannon Nome - Deutsche Bank

I was kidding. So two questions. One is, wondering how we settled on July gas? I know you have some swaps that have knockout provisions. How'd that come out?

Aubrey McClendon

We won some and lost some. I'll let Marc discuss that.

Marc Rowland

We have now moved into the September contract, so the August contract has moved off as well. I think July we were just fine, but it was the August contract actually as it went off for August that we had some kick outs. We had moved about 70 million a day of our $6 kickouts into a cash converted position so we maintained most of those, the $6.50 and $6.25 kickouts, were the ones that we lost. So save some on the $6. The ones below that, we were okay on. The $6.25, the $6.50 we lost on.

Kind of reminds you why we do these, and you may know, but maybe some of the other listeners don't. We've been doing these for over four years now, in fact, almost five years and of all those months -- and let's call it 50 months -- we've had three months where we've lost any kickout positions. So in that period of time, but selling an embedded put, we've increased the gas revenues on our positions by in excess of $150 million while losing, at this point in time, cumulatively about $25 million. So a 6: 1 reward.

What we're doing is selling volatility and enhancing the gas price we can receive. Occasionally, such as the month of August, it didn't work out perfectly, but also remind you that many of those months, had we not decided to go into a kickout, the swap level by itself was such that we probably wouldn't have put the position on to begin with.

So two factors there. (1) we wouldn't hedge as much as we did without the higher level and (2) over time, it's been very profitable for us. So August wasn't the best, we continue to monitor September. Volatility actually remains quite high and we've been surprised at the back of the curve. We've priced up just yesterday some $10, $11 and $12 calls from '09 through 2012. You can actually sell a $10 '09 call and receive $1.01 upfront. So we have quite a few calls we've sold, we have some more calls that we're likely to sell that will create cash proceeds and revenue that we think are a good thing for the company. But good question.

Shannon Nome - Deutsche Bank

Just a follow-up on the monetization front. The upstream sale that you cited, clearly even with all the provisions all-in, I'm assuming that's coming at a favorable cost of capital relative to Chesapeake's corporate cost of capital. Is it safe to assume it's something close to that 5% you threw out on the sale leasebacks, or more in between?

Marc Rowland

I think it's more in between. We don't know exactly where it will be, but we've been led to think by our selling representative that it's likely to be in the 6.5% to 7% range. That's not as inexpensive as a sale leaseback of equipment, which is currently under 5%, but it is less than the cost of debt currently, which would be in the 8.5%. Depending on what methodology you use for cost of equity, of course, it is almost infinitely cheaper.

Shannon Nome - Deutsche Bank

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

Marc Rowland

The midstream, we're just starting to evaluate that part. We've got a project just to start next week. We've got heavy infrastructure spends in the Barnett and Fayetteville. We think that those assets could easily be converted into either a sale leaseback or some other form of sale. Our discrete assets have a distinct signature where they will remain under Chesapeake operating control and there's a billion or more of those that we've spent either through acquisitions or through our own new build construction.

So lots of opportunities to do these types of transactions at costs that are fractions of the rates of return that we can earn in drilling. I think you can probably, as your note pointed out, determine that we're very concentrated on funding the deficit without going out and issuing common equity at this time.

Operator

Your next question comes from Jeff Robertson - Lehman Brothers.

Jeff Robertson - Lehman Brothers

Good morning. Aubrey, in the Barnett Shale, you're using almost 2.5 Bcf in the Tarrant County part. From the drilling you've done so far, where do you think that number goes over time?

Aubrey McClendon

I'll turn that call over to Steve.

Steve Dixon

It's probably going to stay pretty close to that because we're doing further reach wells off the pads, a little deeper as we go into Tarrant County, a little deeper and trying to do longer laterals. The cost per foot is going down, but we are just drilling more footage.

Marc Rowland

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

Aubrey McClendon

That's with offsets of 500.

Marc Rowland

That's assuming offsets, wells drilled every 500 feet and laterals of about 3,000 feet. Our first round of wells in Tarrant are likely to be better than that because many of them will not be drilled on 500 foot offsets. For example, in the DFW area. I think most of our drilling there will be close to the 2,000 foot, so we should be able to put in big, big fracs on those 2,000 foot offset wells. I think we're going to get some really big wells out of the DFW area and also throughout all of urban Fort Worth.

Jeff Robertson - Lehman Brothers

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

Steve Dixon

No. We should have that in place in September when we're just beginning to turn wells on.

Operator

Your next question comes from David Heikkinen - Pickering Energy Partners.

David Heikkinen - Pickering Energy Partners

Good morning. The flat CapEx '08 versus '07, what would you expect your well count to be on that capital budget with declining costs? Are you seeing any efficiency gains as well that would increase the well count?

Aubrey McClendon

I don't have the gross well count associated with that. I don't know if Marc or Jeff does.

Marc Rowland

We reported the gross well count in our press release for this quarter and I wouldn’t think that that would be much more than 10% greater this quarter's CapEx run rate is about what we're reflecting over the next six quarters. I don’t know that there'll be too much more efficiency gained other than perhaps in plays like the Barnett in Fayetteville that would dramatically affect the well count itself.

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

Steve Dixon

It's slowly getting better. It will generate more wells.

Aubrey McClendon

In the Barnett, we've gone from an average of 25 to 21 days in the last year, but that's increasing our rig count from around 20 rigs to 35 rigs, so anytime you bring on 15 new rigs and new crews in a new area, you're going to not be as efficient as you are going to be in a year or two. That's one of the hallmarks, I think, of our company is that we keep so many rigs active in the same place from the same companies that we get very stable crews over time and are able to drive down efficiencies, or increase efficiencies by driving down our drilling days.

We're seeing big efficiencies as we would expect as we do less seismic over in the Fayetteville. Our Woodford drilling times continues to decline in Southeastern Oklahoma and we're doing better and better in our deep plays as well. Have some new granite wash plays out in western Oklahoma and then in areas like deep Haley continue to drive down drilling times. We just reached total depth on our first well in the Deep [Bojour] and have three rigs running there and believe we'll be able to continue to drive down times also.

Marc Rowland

To remind you, we participated, including non-operated wells at the pace of 950 net wells for the first half of the year. That was on an average rig count of about 130. Our rig count going forward, we estimate to average at least 150. The first half we were on an annualized pace of almost 2,000 wells per year on a net basis with the rig count going up to 150 to 155 on average looking forward, we could expect probably 2,500 net wells, I would think, on an annualized basis. Does that sound about right?

Steve Dixon

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

David Heikkinen - Pickering Energy Partners

The CapEx increase, the split leasing went up a little more than drilling. Is that fair? 2007's increased CapEx, looking at that change, is that mainly leasing or leasing and drilling to get the exact split on the dollar amount?

Marc Rowland

I think probably the leasing activity, including the brokerage activity, which is all of our people working in the field,, a lot of that relates to, although it's classified as leasing activity, a lot of that relates to preparing well bores for drilling and title opinions and so forth. The activity actually on leasing from a dollar standpoint is heavily concentrated in the Barnett and just as that becomes more mature, it's going to become less of a factor, I would guess, in the future, versus what it has been in the past.

David Heikkinen - Pickering Energy Partners

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

Marc Rowland

That's where we are. That's right.

Operator

Your next question comes from Gil Yang - Citigroup.

Gil Yang - Citigroup

I've got a couple of questions about the Barnett and then another one as well. Can you comment on how many you're booking with the Barnett to get to that $1.62 per Mcf of drill bit costs?

Steve Dixon

You said booking, that's PDP drilling costs, that’s not PUD drilling, that does not have a PUD component in it.

Marc Rowland

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

Gil Yang - Citigroup

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

Marc Rowland

yes, it is.

Gil Yang - Citigroup

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

Marc Rowland

Overall F&D costs for what?

Gil Yang - Citigroup

In the Barnett.

Marc Rowland

That's is $1.62 to $1.65 range I gave you, I believe during the quarter precisely for the Barnett it was $1.62. I also reminded you that was the four leaseholds, seismic and brokerage burdens which we think are running around $10,000 an acre and we assume that when we drill a Barnett well it consumes about 60 acres, even though the precise rectangular box that you would draw with 500 foot offsets drilling 3,000 foot laterals only consumes about 35 acres. There's always some inefficiency of acreage use. At 60 acres at 10,000 an acre, that adds about $0.35 at Mcfe to refining costs. All-in we think we're at under $2 an M in the Barnett.

Gil Yang - Citigroup

As you drill out those 2,200 new wells in the next four years, I think is the number that you said, how consistent is the quality of those wells going to be over that period? It sounds like you think they are actually going to get better in the near term, as you drill more Tarrant versus Johnson?

Aubrey McClendon

Today we've drilled just under 500 wells and 85% of them or so are in Johnson County. And while Johnson County has been very good to us, it looks like Tarrant County with its slightly deeper geological environment and thicker Barnett is likely to give us even better results plus in Tarrant we pick up the viola frac barrier as well, which should help us stay out of Ellenberger water.

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

Gil Yang - Citigroup

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

Steve Dixon

Remember, our well assumption is based on drilling a well every 500 feet. So if you drill wells on 2,000 feet, we actually in Tarrant are seeing per well reserves of around 3.7 Bcfe per well. If you then go to 1,000 foot spacing, we're seeing 70% of that 3.7, and when you go to 500 foot spacing, you go to another 70%. So when you blend all that together and get all those kind of wells drilled, that's where you end up with our per well estimates of 2.3 overall for the play and 2.45 in Tarrant.

So we don't really see the possibility that going forward we would do worse than the Barnett. We actually think we'll likely do better, particularly as the science continues to improve and our completion skills improve as well.

Marc Rowland

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

Aubrey McClendon

The other thing is people always assume in this business that you can always skim the cream in any play in the beginning. The reality is you typically drill some of your worst wells in the beginning and get better over time. Most of our drilling is being driven by get gas out of urban areas in Fort Worth, where we can get drilling permits, where we have lease expirations. So it's not targeted in the best areas and we don't, but the best areas are not yet knowable and there's always going to be somewhat of a random X factor in a statistical play like the Barnett.

Gil Yang - Citigroup

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

Marc Rowland

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

Gil Yang - Citigroup

Last question I've got is for your performance revisions upward, can you talk about whether or not that's as a result of having more data about existing areas that gives you more confidence in what you think, or is it better data, improving the data that you have seen? And in what regions are you seeing the biggest up upward revisions on performance?

Aubrey McClendon

We have a number of plays that are being very successful. Our conventional plays with some high impact areas, we're bringing on large wells pretty much every week, over 10 million a day. We're drilling a large percentage of horizontal wells, which have good, early production; we drilled over 200 horizontal wells during the quarter, so that will continue in the future and so we have confidence in our production forecast.

Gil Yang - Citigroup

So it's pretty well distributed and sort of a variety of different things happening? Not concentrated in any one particular sort of either area or type of technology?

Marc Rowland

Gil, I think it's widely distributed, but, frankly, it's an element of conservatism on our reservoir's engineer's part. If you look now, every year since 2001, we've consistently had positive performance revisions. Last year they were enough to [move] our entire production, as I recall, or darn close to it. On a base of 9 or 10 Tcf, depending on the time period, now 10 Tcf they have a 1/10 of 1% positive revision, you've got some pretty significant revisions coming. As Steve mentioned, it's just consistently over a broad band and we have 30,000 some wells now. So we're slightly positive over time with a tail of a reserve that can positively affect you.

Operator

Your next question comes from Jeff Hayden - Pritchard Capital Partners.

Jeff Hayden - Pritchard Capital Partners

First, jumping back to the CapEx questions, Aubrey, you guys mentioned you're moving towards a resource conversion stage from a resource capture stage. I was just curious, going forward out of that CapEx budget, about what percentage of those dollars would you expect to be for undeveloped acreage, leasehold acquisition, etc.?

Aubrey McClendon

I think we've got some pretty good numbers on that Jeff, on page 25 of our press release where we break out our budgeted CapEx. This is first time we've done it in quite this detail and we've projected leasehold acquisition costs of $600 million to $800 million per year for '07 and '08. Going beyond that, kind of hard to know. That compares to our drilling CapEx budget of $4.3 billion to $4.5 billion. So about 13% to 15% on top of our drilling budget is what we think our recurring leasehold expenditures need to be. That's not to drill wells on that $4.3 billion to $4.5 billion that year, it's to continue to have a rolling inventory of 25,000 to 30,000 wells left to drill in our inventory in the years ahead. That's what our goal is.

Jeff Hayden - Pritchard Capital Partners

It looked like there were about $190 million give or take of improved property acquisitions in the quarter. What were the volumes associated with that?

Aubrey McClendon

We gave reserve volumes and there was very little production associated with it. Most of the reserves were PUD.

Jeff Hayden - Pritchard Capital Partners

Just a follow-up on that response you gave to Gil about the Tarrant County volumes, that was 3.7 Bs per well at 2,000 feet and then trim that by 30% to 1,000 foot spacing and another 35% for another 500 foot spacing. Did I hear that right?

Aubrey McClendon

Yes, you did.

Operator

Your next question comes from David Kessler - Simmons and Co.

David Kessler - Simmons and Co.

Just looking at things in terms of being the number one driller, looking at you guys as the most hedged company in 2008 and your early commentary on service cost declines or efficiencies kicking through for the next couple years, can you give us a little bit on your 2008 view of gas and a little bit on the tail end of '07 given that you increased your hedges there a little?

Aubrey McClendon

We're always nervous about gas prices. It's our single biggest risk and the single biggest risk factor in gas prices is the weather. We haven't had much in the way of summer weather in some key gas-consuming states. So that of course follows a winter where we didn't have much of winter except for about 30 days. So we're always nervous about gas prices and so we'll continue to want to hedge forward a couple of years.

Unfortunately, the gas curve is not similar to the oil curve today where the bifurcation in the oil curve is pretty modest on a percentage basis, it is actually pretty strong on an out year basis in the gas market. We're also aware that if you think about our 300 million a day of production gain on a year-over-year basis, if you were to add in the fact that we had partners in virtually all of those wells and also we have royalty burdens probably that average about 20% overall, we probably single handily in the past year have added about half a Bcf a day of production into the U.S. gas system.

Going forward, if we continue to think about targets for 2008 over 2007, we'll be adding something similar to that again. So if gas prices were going to go down, we wanted them to go down because of our own production, not because of somebody else's. So we felt like we could hedge ourselves against that and it continues to be a real issue for us if we consider our own success in finding gas and what are the implications for that in the marketplace?

We're hopeful, of course, that other people, particular majors and drillers in Canada and offshore continue to find it a challenge to find new gas and so a good bit of our production growth is offset by those declines. I think it's really instructive these days to see there are only a handful of companies in the U.S. that are really driving production growth forward, yet all of these companies are ones that recognize what happens when you apply structurally higher natural gas prices to new geological reservoirs that respond well to new horizontal drilling techniques. We think we're at the forefront of that movement and accordingly have production gains that are at the top of the industry. So we'll continue to hedge as we see opportunities to guard against our own production gains.

David Kessler - Simmons and Co.

Switching to the Woodford for a second, at the last update you had a two to four rig program planned for 2007. Looks like you're kind of stepping that up or doubling it, a little bit more than that. What are you guys seeing that's getting you excited about it? You mentioned earlier on the call that you're actually seeing drilling times decrease, but was just kind of curious about other economics you're seeing?

Aubrey McClendon

It's really a tough play. It remains our most challenging resource play. I've got some statistics in front of me here. Looking at the play today, overall finding costs are running -- this is our own finding costs and those of our partners and we're in virtually all the wells being drilled -- finding costs in the play to date are over $3 and in a couple companies we track over $5 in Mcfe. We can't find another play that's similarly challenged.

At the same time, there is gas in place and our last five wells have EURs of about 2.6 Bcfe and then IPs of around 1.8million a day and finding costs of around 280. So that is not particularly shiny, but at the same time the trend is coming down. If we didn't put six rigs out there, we wouldn't be able to hold that production. All of our acreage, we have about 94,000 acres and continue to add to that a little bit over time. So we've taken a little different approach from some companies. We're a little bit more focus in one particular area of the play where we think Woodford is going to work great or work better, and we think that 280 finding cost can come down over time. But it's not something that we're particularly proud of at the moment nor are we particularly proud of the industry's performance to date, either, as finding costs are really not economic, even at this point.

David Kessler - Simmons and Co.

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

Aubrey McClendon

Well, we're not there yet. We continue to make progress and the technical challenges are basically to figure out a way to drill a way in either the Woodford or the Barnett or in both and to stimulate those formations in such a way that we can get economic amounts of gas out of it. We've made quite a bit of progress, costs will come down, we are finding gas but we're not at a point where we can play all of the economics. Steve, we've got how many rigs?

Steve Dixon

Two running today, but we run around five.

Aubrey McClendon

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

Operator

Your next question comes from Joe Allman – JP Morgan.

Joe Allman – JP Morgan

A question for Marc. Marc, you talked about the attractiveness of the net settled share convertibles. I'm not sure if you're indicating you're looking at doing that. If so, what would be the use of proceeds? Are you looking at acquisitions, refinancing, what are your thoughts there?

Marc Rowland

Joe, it's real simple. We have a bank line that has a little over $1.5 billion on it outstanding, that's costing us LIBOR plus 1 1/8. We're not looking at any acquisitions, we haven't done any significant acquisitions for quite some time. All of the focus here is on the conversion and drilling program. If we were to do something, and I was mostly reflecting back on what we had done, because we haven't been on the air waves, so to speak, since we did our net share convertible, the use of proceeds would be to repay bank debt. That's an attractive arbitrage, because LIBOR currently around 5.5% or so plus 1 1/8, so all-in cost of funds to the bank is under 7%.

Aubrey McClendon

Joe, I think this is clear, but the reason we have bank debt is because this year we are heavily outspending our cash flows. So the production sale and any curious transactions in the future would be designed towards closing that funding gap between our cash flow and our CapEx.

Joe Allman – JP Morgan

On the acquisition front, I know you guys have made it clear that you're in harvest mode at this point and you'll make some bolt-on acquisitions, but no big significant ones. Does the MLP market , I think you've kind of made it clear as well, but does it make you mar interested in doing an acquisition because of the tax implications? You have a relatively high tax basis, the taxes, of course, would be less. Can you give me your thoughts there?

Marc Rowland

Several questions embedded in there. Just the MLP market by itself isn't forcing us or controlling us to do one thing or another. I was on a panel this week with some very nice gentlemen that have great MLPs. They're very active in the acquisition market and I think all of them are looking at the potential to buy properties with a cap rate less than PD-10, because they themselves trade at cap rates that are closer to 6%. That's not attractive to us. We haven't made a PDP acquisition in a couple of years now. Some of the acquisitions that we do are primarily acreage or almost exclusively acreage will occasionally have some production with it. But we're not out looking to buy production at those kind of discount rates. So we're not interested in forming an MLP, we're not interested in competing with an MLP, we're not interested, generally, in the acquisition market, unless it's a tuck-in acquisition of acreage and drilling opportunities like we have been doing for a couple of years.

We're are interested in perhaps selling some properties to an MLP or perhaps a financial player, and we are definitely going to be marketing that very soon. So don't want there to be any confusion about what our strategy is here with regard to the MLPs. They're certainly not driving anything we're doing. The kind of properties we're selling is very attractive to us and we think that those kind of cap rates or the cost of capital implicit in that will allow us to come back and take advantage of 35% to 50% kind of term rates on our drilling.

Joe Allman – JP Morgan

That's helpful. Aubrey, on the Woodford shale in Southeast Oklahoma, to clarify, has that moved up in terms of your list of attractive projects, or is it still where it was before?

Aubrey McClendon

Still right there at the bottom.

Joe Allman – JP Morgan

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

Aubrey McClendon

We've been pretty open with what we're seeing there. We've been drilling longer laterals than other companies in the play and I think that's now going to become the trend based on what I've heard and read in the last week or so. I think estimated ultimate recoveries of 1.8 to 1.9 Bcfe are absolutely achievable. Jeff, do you want to review our Fayetteville Shale numbers for everybody? We have about 390,000 acres that we consider prospective in the Fayetteville. Jeff, do you want to go through our assumptions?

Jeff Mobley

On the Fayetteville, we're assuming on average about 80-acre spacing. Our risk factor in the core play is about 40%. That leaves risk net undrilled wells of about 2,900. To date we've booked about 140 Bcf in the play of proved reserves and have about 3.8 Tcf of risked, unproved reserves.

Aubrey McClendon

Joe, on a reserve basis, it's something that is the only thing that's out there right now -- well, I shouldn't say only. It's something that can challenge the Barnett for us in overall reserve adds, because we have about twice the amount of prospective acreage. However, the Barnett tends to have in the core area and tier 1 area, tends to have much higher flush rates of production, and so our rates of return are much higher in the Fort Worth Barnett than they are in the Arkansas Fayetteville. You've got a secondary permeability system in the Barnett that does not exist.

Joe Allman – JP Morgan

Previously, the Fayetteville wasn't high up on your list as well. Is there any reason to think that the Woodford may not move up further as you progress there in southeastern Oklahoma?

Marc Rowland

Joe, that's several quarters behind. We've been pretty high on the Fayetteville for the last several quarters. So over a year ago, it was considered lower on our scale, but last quarter we officially escalated it from a conversion unconventional to a proven unconventional. We're working well with Southwestern. We are in something like 80% or 85% of their wells. So good information flow back and forth and it looks like they're going on longer laterals and also exclusively to slick water. So we're expecting really nice results out of the Fayetteville both for us and for them.

We wouldn't be using six rigs in the Woodford if we didn't think there was some hope. It's just been a play that's had a long way to go; it's come a ways, but it's not nearly competitive with the Fayetteville or the Barnett today.

Joe Allman – JP Morgan

Lastly, on the Deep Haley agreement you have with Anadarko. What's the advantage there? Just spreading risks and exposing yourself to more opportunities?

Aubrey McClendon

They needed a partner to come in and pick up some of their CapEx costs and when it was all said and done, we ended up with about $40 million a day of new production. We cross-conveyed a bunch of acreage in various areas so rather than having checkerboarded lease positions, we now have a consolidated leasehold position across a good bit of the play. So we'll lead to really remove this from a competitive relationship that we've been in for a couple of years with Anadarko into a collegial relationship that we think working together will lead to better finding costs and larger reserve recoveries.

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

Operator

Your next question comes from Ben Dell - Bernstein.

Ben Dell - Bernstein

Aubrey, I had a macro-related question. You highlighted how earlier on how you believe you are going to become the biggest gas producers in the U.S. Obviously the NPs have grown as a result of that. The number of the NPs who have reported pretty solid gas growth volumes and the 914 data suggests the outlook is pretty good onshore. Does that change your view on the two to three year trend, especially with the prospect of cost deflation in terms of where the marginal cost of supply is and where the balancing point for natural gas prices will be?

Aubrey McClendon

Ben, let me make sure I understood the question. You said, has it changed my view over the next two or three years in terms of where I think prices will be?

Ben Dell – Bernstein

I think when we spoke historically, you had a view that gas prices were in a long term uptrend with rising marginal costs. Certainly there's some cost moderation or cost deflation emerging and people are getting more bang from their buck, so to speak, on the volume side. I wonder if that changes your perspective?

Aubrey McClendon

Actually, we kind of abandoned that view a couple of years ago once we got into the $6 to $9 range, we kind of felt like gas prices would stabilize in this range. We thought we would have a very difficult two-year period of rapidly rising costs as the producing and drilling industry put heavy demands on the service industry and it would take them a couple years to catch up. That's now occurred and I think going forward, given the strong onshore demands that companies like our own and XTO and EOG and a handful of other companies are driving that we think the likelihood of gas prices continuing to go up from the $6 to $9 range, I think there's really not a risk of that.

I think it's really good news for the long term of our business, because I think we've lost a lot of demand over the last few years because of the view that gas prices are going to continue to go up. I still have lots of discussions with utility executives these days, particularly some that produce or consume a lot of coal and their view is that we're worried about gas prices. I'm trying to convince them that the rise of the shale plays and the rise of the unconventional plays really takes away this kind of plateau gas prices going forward.

In the meantime, as long as you have volatile weather patterns, we're going to get some opportunities to hedge some gas above that top end of the range. That's one of the reasons why we're interested in selling volatility, though, that we don't think with greater L&G and stronger onshore gas supply that we're going to be in areas where you can have long-term spikes in gas prices. I think overall that's a good thing for the gas industry.

Ben Dell – Bernstein

Just one last technical question. Your rig revenue of around $30 million, if I take the average day rate of $15,000 a day by the number of rigs you have, I come out with a number almost 100% plus above that. Can you explain what the gap is above those?

Marc Rowland

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

Ben Dell – Bernstein

Yes.

Marc Rowland

You have to consolidate out our ownership of our own rigs. I think, Steve, we're participating at the rate of about 67% on average across the board. Our internal working interest, and so we don't bill ourselves and report that as revenue, we consolidate that out and it goes as a credit in our full cost pool. So only the portion of a well that our rigs are drilling on that's operating by us, that portion that's owned by a third party, a non-operating working interest, in other words, is revenue for us.

Operator

Your next question comes from John Massling - D.E. Shaw.

John Massling – D.E. Shaw

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

Marc Rowland

A couple components. I'll take the first part of that. The level of pricing at Henry Hub that a play would be uneconomic very widely, depending on the location of the gas. Remember, we've got gas that stretches all the way from New Mexico to the east coast. Gas prices in Appalachia, for example, have a basis that's $0.30 positive and there would be virtually no price at Henry Hub that those wells wouldn't be economic to continue to produce. On the other hand, last September we shut in production when gas in the mid-continent was under $4 and at the time the October contract had gone off the board at the end of September at about $4.10 and with basis differentials over $0.50 or $0.60, a lot of our mid-continent production was down in the mid$3 range and we elected to shut in that portion of the production that was not hedged.

Our action would be that we would consider shutting in gas production that wasn't hedged and it would vary from play to play as to what the economics would be. In some of our lower rate of return plays like the Woodford in southeast Oklahoma, if you were considering drilling economics, then I would say that play at $5.50 or $6 NYMEX is a fairly low rate of return play and might even be considered breakeven for drilling purposes, but that's a different answer with regards to continuing to produce gas that's already been put in place with the lifting cost in our company on average are only $0.90.

The second part of the question, maybe Aubrey, you want to talk about? There's almost no scenario that we see where gas would be at low levels for six months.

Aubrey McClendon

And the reason are depletion rates. Overall depletion rates in the industry are probably pushing 35%. If you were to get a period of low gas prices, I think you would starve some producers out drilling rig counts would go down, depletion would kick in, and we're back to balancing the market. It's really hard to grasp the power of depletion because there are so few other industries that have anything similar to it. So we view depletion as always our enemy. We have to overcome it, but it's also our friend as well.

Operator

Your next question comes from Monica Verma - Gilford Securities.

Monica Verma - Gilford Securities

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

Aubrey McClendon

We're very excited about being in Appalachia. We have close to 4 million acres of leasehold. When with made the acquisition, we felt there was a great deal of upside. The area's produced about 50 Tcf of gas from very solid formations and it felt like nobody have ever gone in with modern exploration techniques. We continue to shoot a great deal of seismic. Our goal is 300 square miles of seismic a year. We're going to start drilling some deep and ultra deep wells in 2008 to test some of our geologic ideas. We also kicked off our horizontal drilling program in the next few weeks, so this is going to be an exciting time over the next several years for our Appalachian division as we move from just drilling traditional vertical Devonian wells into wells that have a great deal more upside that what has been traditionally been associated from drilling returns in the area.

Operator

There are no further questions at this time.

Aubrey McClendon

We appreciate your participation on today's call. If you have any further questions, please call Marc or Jeff. Thanks a lot. Good bye.

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