Chesapeake Energy Corp (CHK) 2005 Q2 法說會逐字稿

Good day and welcome to the Chesapeake Energy second quarter 2005 earnings release conference call.

Today's call is being recorded.

At this time for opening remarks and introductions, I'd like to turn the call over to Jeff Mobley, Vice President Investor Relations and Research.

Please go ahead, sir.

Good morning and thank you for joining Chesapeake's 2005 first quarter earnings release conference call.

With me this morning are Aubrey McClendon, Tom Ward and Marc Rowland.

Before I turn the call over to Aubrey, Tom and Marc, I need to provide you with you 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 the Company's actual results may differ from those contained in such forward-looking statements.

Additional information concerning these statements is available on 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 the terms such as operating cash flow and EBITDA and we'll also mention several items that we believe are typically excluded from analysts' estimates.

These are all non-GAAP financial measures.

Reconciliations to the comparable GAAP measures can be found on Pages 15 to 17 of our press release issued yesterday.

While these are not GAAP measures of financial performance, we believe they are common and useful tools in evaluating the Company's overall performance.

Our prepared comments this morning should last about 15 minutes and then we'll turn the call over to Q&A.

Aubrey?

Thanks, Jeff.

Good morning to each of you.

Once again Chesapeake has delivered a very strong quarter featuring solid organic production growth, strong cash margins, an exceptional reserve replacement and very good finding costs.

After excluding items not generally included in analyst calculations, Chesapeake's second quarter net income available to common shareholders was $174 million, or $0.50 per fully diluted share versus the consensus estimate at $0.46.

I think I read this morning that this is the 22nd time in the last 25 quarters that we have beaten the consensus estimate.

In addition to our second quarter operating cash flow it was $513 million, or $1.41 per fully diluted share and our EBITDA was $565 million.

These second quarter financial numbers were driven by strong production growth, well-controlled operating costs, and excellent reserve replacement.

With regard to operating costs we continue to have some of the lowest costs in the industry.

Our general and administrative expenses, lease operating expenses, interest expense, and DD&A expense totaled $3.07 per mcfe this quarter versus $2.68 per mcfe for the 2004 second quarter.

Only a $0.39 per mcfe increase year-over-year in a very inflationary oil field environment.

By comparison our revenue per mcfe was up $1.23, or four times the amount that our cost structure was up.

We work hard to control all of our costs and believe it's an outcome of our focus on the details of our business and a result of our large operating scale, especially in the Mid-Continent where we have considerable negotiating power with service and equipment providers.

We believe our large and focused operating scale remains one of Chesapeake' most important competitive advantages.

I would next like to highlight that Chesapeake's strong financial results were driven by equally strong operational results.

Oil and gas production increased 31% compared to the year ago quarter and 7% compared to the sequential quarter.

Of that 7% growth, 63% came from acquisitions and 37% came from the drill bit making our quarterly organic growth rate 2.7% and our year-to-date organic growth rate 5.1%.

We are well-positioned to meet or exceed this year's organic growth rate projection of at least 10%.

Keep in mind this growth performance is from a company now the third largest independent U.S. gas producer.

Added to the strength of our production growth is the consistency of it.

The 2005 second quarter was our 16th consecutive quarter of record production and the year 2005 should be our 16th consecutive year of record production.

Consistent with strong production growth we have also produced a terrific quarter of reserve replacement.

We replaced our 113 bcfe of production with an estimated 529 bcfe of new proved reserves for a reserve replacement rate of 468% at a drilling and acquisition costs of $1.84 per mcfe.

Reserve replacement through the drill bit was 250 bcfe, or 221% at a cost of $1.87 per mcfe.

In addition we replaced our production through acquisitions by 245% at a cost of $1.79 per mcfe.

During the second quarter then, in total we increased our proved reserves by 8%, or 416 bcfe to a quarter ending total of 5.85 tcfe.

Please remember these numbers do not include the impact of the 113 bcfe of proved reserves we acquired through acquisitions made after the end of the second quarter.

Six months ago we told you that we hoped to crack the 6 tcfe level by the end of this year.

It now appears that we have achieved that goal almost six months early.

The PV-10 of our 5.9 tcfe of proved reserves using quarter ending prices was 14.6 billion.

That's up about 500 million from our March 31st PV-10.

However, in the past five weeks that PV-10 has increased by another $2.5 billion, or about $7 per share, as strip gas prices have moved up almost $1 per mcf and strip oil prices about $6 per barrel.

So although our stock has done well in the past month it's not even kept up with the increase in oil and gas pricing, much less the value we have created in the past month through our drilling and acquisition activities.

In addition, during the past five years we've worked energetically to acquire what we believe is the nation's biggest inventory of unproven reserves.

We've built this inventory in anticipation of today's highly rewarding commodity process and today's highly competitive acquisition market.

By being a first mover we gained many advantages.

Today we are executing the nation's most active drilling program on what we believe is the nation's largest land and 3-D seismic inventories.

We've now identified more than 14,000 locations to drill on 4.1 million acre leasehold inventory.

It's taken us five years and over $1.5 billion to build this inventory.

We've also high graded it by spending more than $200 million on 3-D seismic.

This inventory and the hiring of the very capable employees who manage it and prospect on it and drill on it could simply not be replicated in today's ultra-competitive industry environment.

We were able to acquire this leasehold inventory and our technical employees because we believed earlier than most in the sustainability of higher oil and gas prices, and because we staked our claim earlier than most in a significant number of very important natural gas plays in the Southwestern U.S.

Looking further at the project inventory we characterize our drilling activity by one of three play types: Conventional, unconventional gas resource and emerging gas resource.

First of all, in our traditional conventional areas such as the Mid-Continent/ Permian/Gulf Coast/South Texas and other areas, we own 2.6 million net acres on which we've identified more than 3200 drill sites, have booked 1 tcf of proved undeveloped reserves, and own more than 1.4 tcfe of non-proven reserves.

Next in our unconventional gas resource area such as Sahara, the Granite/ Cherokee/Atoka Washes, the Hartshorne CBM play, Barnett Shale, and various Ark-La-Tex-type sand plays, we've amassed 900,000 net acres on which we've identified more than 10,000 drill sites, have booked 1.8 tcfe of PUD reserves, and own more than 2.8 tcfe of non-proven reserves.

And finally in our emerging gas resource areas such as the Fayetteville Shale, Caney and Woodford Shales, Haley Deep play and others, we've acquired 600,000 acres on which we've identified more than 900 drill sites, have booked less than 100 bcfe of PUD reserves, and own more than 800 bcfe of non-proven reserves.

We are aggressively continuing to acquire more acreage in all three play types with more than 500,000 acres acquired in the 2005 second quarter through an aggressive land acquisition program that continually utilizes more than 450 land brokers in the field every day researching land records and acquiring leases.

Today we have about 73 operated rigs at work and another 65 or so non-operated rigs.

This program enables to us drill approximately 1500 wells per year so we feel pretty good about owning a nine-year inventory of drill sites.

We believe this backlog of opportunity is Chesapeake's number one distinguishing characteristic today.

We thought you might be interested in knowing where our operated rigs are currently drilling so I'm going to give you numbers by state and then by play.

In Oklahoma we have 35 operated rigs.

In Texas 30, in New Mexico 3, in Louisiana 3, and Kansas 1, and in Arkansas 1, for a total of 73.

By play type, we have 12 rigs in the Sahara gas resource play of Northwest Oklahoma. 11 rigs in the Deep Anadarko Basin of Western Oklahoma; 9 rigs in the Permian Basin, that includes 4 rigs in the Deep Haley area; 8 rigs in the Granite Wash and Red Fork gas resource plays in the Anadarko Basin; 7 rigs in the Tight Sand gas resource plays of the Ark-La-Tex region; 6 rigs in the Barnett Shale; 6 rigs in the [Bray] and Cement areas along the Mountain Front in Southern Oklahoma; 5 rigs in Zapata County in South Texas; 5 rigs in the Arkoma Basin; 3 rigs along the Texas Gulf Coast; and 1 rig in Kansas.

During the remainder of 2005 we expect our rig count to move between the low and the high 70s.

I would next like to review the $410 million of acquisitions that we announced yesterday.

The most important of these was our acquisition of Hallwood's 56% interest in our Johnson County South Block AMI.

You may recall we picked up a 44% interest in this area for free through our acquisition of Canaan Energy in June of 2002.

Then in December 2004, we bought Hallwood's 100% interest in the North Block acreage for 277 million.

Yesterday we announced the South Block deal for 249.5 million, which is clearly more expensive than the North Block deal was.

It's certainly fair to ask why we were willing to pay more per mcfe for the South Block assets just eight months after we bought the North Block.

The answer first is threefold, rather.

First, hedgeable gas prices are up more than $1.50 per mcf during that eight months.

Second, our results to date on the North Block have been exceptional with our average reserve development coming in at 2.8 bcfe rather than at the targeted 2.5 bcfe.

And finally, we are only projecting 2 bcfe per well on the South Block acreage, and it is our hope that we can do better than that over time which would thereby lower our all-in acquisition cost for that deal.

Moving on from the Barnett I'd like to discuss our activity in the Fayetteville Shale play in Arkansas, where we now own about 200,000 net acres, an increase of about 150,000 acres in the past 90 days alone.

To date we understand that Southwestern has drilled approximately 42 vertical wells, of which we are a co-owner with them in 15 wells, and they have drilled 11 horizontal wells, of which we are a co-owner in four of them.

Through these participations we have gained a good working knowledge of the play and will look forward to drilling our first operated wells in the play later this year.

Moving on to far West Texas in the Haley Deep area we own around 125,000 net acres and continue to add to our position in this expansive overpressured gas play.

We have four rigs drilling in Haley and we now have our first completion results.

To date one very exceptional well, one fair well, one poor well, and one well completing.

We are constantly learning about this area every day and currently have three proprietary 3-D seismic shoots underway covering about 200,000 gross acres.

We are hopeful that when completed later this year the 3-D shoots will help us drill more exceptional wells and fewer mediocre wells.

In the past few minutes I've highlighted our position in the three most discussed gas resource plays in the U.S. which would be the Barnett, the Fayetteville and Haley Deep.

Chesapeake is the only company that has a meaningful position in all three plays.

I believe this highlights the exceptional value of our undeveloped acreage inventory.

At the end of the day there are very few gas resource plays of any significance in the Southwestern U.S.A. in which Chesapeake does not have an important presence.

That presence along with our convention projects should enable Chesapeake to continue delivering industry leading organic growth for years to come.

I'd like to conclude my section of this by reminding you that Chesapeake is distinctive in at least three ways.

First through the backlog of drilling activities discussed above.

We believe our organic growth potential is right at the top of the industry.

Second, we have 6% of the nation's drilling rig fleet under contract although we produce only 2% of the nation's natural gas.

In today's exceptionally tight drilling market that's a serious competitive advantage especially in the acquisition market where the ability to get PUDs, probables, and possibles drilled quickly is the key factor in being able to accelerate value creation from acquisitions.

In addition, we're the only company we know of that has actively hedged its exposure to rising service costs.

We have accomplished this in four ways.

First through our 17% ownership of AMEX traded Pioneer Drilling.

Second through our 100% ownership of Nomac Drilling, Chesapeake's wholly owned drilling subsidiary.

Third, through our investments in DHS Drilling and Mountain Drilling, which are two start-up niche drilling companies.

And finally through our sponsorship of various third-party rigs that are being built.

Through all these rig investments we have an embedded gain of about $150 million already on an investment of about $160 million and we think more gains are likely to come in the future.

In addition by our investing we've helped curb the rise of drilling costs by increasing the size of the nation's rig fleet.

In fact by the summer of 2006 we believe Chesapeake will directly or indirectly have been responsible for the addition of almost 50 rigs to the nation's drilling fleet which is basically a 4% increase from today's levels which we think is a pretty remarkable feat from just one company.

Chesapeake today offers a truly unique investment opportunity.

We have visible, sustainable high level growth at a very attractive valuation.

Our management team remains very energized about our competitive position in the industry and the returns we're creating for our investors.

As you may have noticed, Tom and I were active purchasers of the Company's stock during the second quarter.

We also very much appreciate the investments that many of you have made right alongside our own.

We look forward to continuing to create significant value for you in the second half of 2005 and in the years ahead.

Now happy to turn the call over to our CFO, Marc Rowland for his analysis of the quarter.

Thanks, Aubrey.

Welcome and good morning to all of you still working in this mid-summer vacation season.

As Aubrey said, what another great quarter, substantially above analysts and our own earlier expectations, but as usual I won't cover details already reported on.

Instead I'd like to turn to the balance sheet and note that in our release we continued our ongoing process of opportunistically converting certain preferred stock outstanding into common shares.

In addition to converting the $45 million of our 4 1/8% preferred noted in the release into common during the quarter we have additionally converted 35 million, excuse me, for a total of 80 million subsequent to the end of the quarter.

We continue to receive unsolicited inquiries by holders of all of our preferred issues and we'll continue to respond positively and quickly to any inquiry.

We have basically been exchanging at an exchange parity of the preferred into common plus future dividends in a small .2 to .7% premium into all common shares.

The issue of these preferreds in the past has substantially reduced our cost of capital but it's an effective way to issue equity in our opinion.

As of the end of the quarter our outstanding on our revolving credit facility was $455 million.

And as of this week that amount has increased to approximately 900 million as a result of the acquisition activity noted in our release in the funding after the quarter.

We did mention in our release that we anticipated permanently funding the bank credit facility that's been used for this acquisition by a combination of equity and or long-term debt.

We, at this moment, view that we will remain faithful to the expectations that we put out on the Street and expect to fund this basically with a 50/50 debt and some form of equity issuance in the near future.

We're examining all alternatives including perpetual preferreds, mandatories, and even common stock alternatives.

As I look at the reserve numbers one of the things that I wanted to highlight was the distribution of our reserves.

We have continued to add reserves in all areas but as we've increased our important secondary areas that Aubrey went through today, our Mid-Continent reserves by volume are now down to 64% of the total.

Our Ark-La-Tex region has 14% being the second highest contributor.

Our Permian Basin activity accounts for 11% of our reserves by volume.

The South Texas and Texas Gulf Coast is 10% with miscellaneous being less than 1%, for a total of 100%.

Our debt per proved mcf is up slightly at about $0.70 as we speak, but of course the cash margins implied in those reserves and the value of the preserves themselves is measured in dollars in increases as opposed to the two to three pennies in debt per mcf and even this number ignores the billions of dollars and other assets that we have developed, both non-proved reserves and of course the significant non-reserve assets that we have.

Let's speak to cost for a moment.

As noted in most other conference calls this quarter, increasing costs are finally being more openly discussed by others in the sector.

Most service costs continue to be up, although percentage increases are probably no greater this quarter than they have been in the last couple of quarters, but frankly, this has been running at 5 to 10% per quarter in certain areas.

We remain substantially insulated from the drilling rig rate increase through our prudent and early investments in the various rig ownerships that Aubrey talked about.

I would note that our increase in DD&A rate per mcfe, of that $252 million in just this quarter was added to our full cost pool, excuse me, in the last six months has been added to the full cost pool through the non-cash step-up related to tax basis, frequently accounted for others in this sector in the acquisition business as goodwill.

To date, our entire addition to the full cost pool is over $800 million, accounting for about $0.14 per mcfe of our current DD&A rate which is nearly 8%.

Again, all a non-cash item.

On another cost matter I note that several other E&P firms have started to pay significant cash income taxes while our book tax rate at 36.5% is not significantly different than most domestic producers, our cash pay rate is zero due to our net operating losses and the drilling program intensity being different than most producers.

Of course, this is a superior margin performance on the cash compared to others in the sector, and we expect this advantage to continue for several quarters.

We've been asked recently about our rig activity and the accounting for each of those segments.

It's mostly disguised in our balance sheet in the sense that the rig investment, for example, in Nomac is not reported as a separate segment.

It has no income statement effect.

That's because the rigs are all exclusively being used on our own operated wells.

So what happens is that the rig depreciation and the cost associated with that are pushed into our full cost pool.

Of course, this is pushed in at a lesser rate than it would be if we were using third-party rigs at current cost, and so we pick up a cost advantage in that area.

Our investment in Pioneer Drilling does not flow through the income statement.

The variable value of those rigs is accounted for in our balance sheet, but again that investment and the increases that we have not flown through or been put through our income statement.

A couple of bookkeeping issues.

Our capitalized interest for the quarter was 17.9 million as compared to 7.4 million one year ago.

Our capitalized interest for the first six months of this year is 33.9 million as compared to last year 12.7 million.

This, of course, is the result of significantly larger balances of unevaluated non-proven reserves being carried by the Company as a result of our active acquisition area, active acquisitions in these areas.

General administrative costs that were capitalized as a result of our drilling program for the first six month of '05 were 23.5 million as compared to 12.4 million last quarter a year ago.

For the first six months of this year 45.8 million as compared to the six months in '04, 23.3 million.

Operating costs including production expenses, production taxes, and general administrative costs remain not only under control, but at the lowest end of our peer group.

Despite that you will note and some questions have arisen as to our guidance for higher costs.

We continue to believe that costs will increase in the production side of the business and certainly production taxes are a percentage of revenue and as our expectations for gas prices and oil prices continue to be very bullish we expect increases in both those areas.

I think given the extensive detail that we've had in the press release and what Aubrey has covered, we'll now go to the question-and-answer session please, moderator.

Thank you, sir. [Operator instructions] And we'll take our first question from Joe Allman with RBC Capital Markets.

Hey, good morning, everybody.

Aubrey or Tom, could you just give us some more color on the development of the Deep Haley play?

I heard your comments on the four wells so far but how's that play developing?

Joe, we continue to have four rigs working there and we have the capacity next year to increase that and we're actually scheduling, if everything goes well, to be up to eight rigs in '06.

Any color on what you're thinking about the prospectivity of the area?

We think that there are going to be some very good wells drilled.

We continue to, with the four rigs we have, as Aubrey mentioned, we have one very good well and a couple of wells that are okay, and then one well that probably will be pretty poor.

We think we'll continue to see that variability and actually in our budget we've moved down to a 7 bcf well and we think we can find that fairly easily.

We're also trying to cut our costs there.

The average so far that we've spent is about 8.5 million a well and we're hopeful that we can get down to 8 million.

Okay.

And then on the topic of rigs, might you continue building rigs beyond the ones you've laid out through mid-2006 and, you know, if not, why not?

Joe, I think it's just a matter of how far in advance we're planning.

We've started a drilling company from scratch in the last couple of years, and we're now up to 14 rigs and have another 18 on order as we accept delivery of these rigs over the next few months we will certainly evaluate the rig market and our needs and decide whether or not we want to continue to have a rolling inventory that is, say, 15 or 20 rigs out in advance.

These things do take some time to build.

We're concentrating on the size rig, say, 750 horsepower to maybe up to 1,000, which are in the shortest supply right now because of all the wells being drilled in places like the Barnett and Ark-La-Tex area where drilling depths are from, let's call it 7,000 to 12,000.

Those are the kind of rigs we're trying to add to the fleet and it's been a great investment so far.

I will highlight one other issue, it's not just the financial hedge, it's turned out to be a great operating advantage as well.

If you think about today, the amount of value that can be developed by drilling a well as opposed to not drilling it, the ability to have additional rigs come on and increase our drilling activity without putting pressure on the overall market, enables us to create a lot of value on the E&P side just through having access to a rig that maybe something else doesn't have.

I alluded to the advantage it gives us on acquisitions as well.

You might imagine in that today's market most of the deals that you see are generally going to be 50% or higher PUD, probable and possible, and if you are a competitor of ours and you don't have access to the number of rigs we have you might not be able to plan as aggressive a drilling schedule as we have for those assets and we might be willing to pay more just because of our ability to convert those non-producing assets to producing assets more quickly than probably anybody else in the industry.

So it's a financial hedge but also a great operating advantage as well.

And we'll take our next question from Ellen Hannan with Bear Stearns.

Good morning.

A couple of questions.

One, in the Barnett Shale could you describe either how or why the LOE costs are so extraordinarily low?

Just you have high productivity gas wells and we've installed, I guess we have salt water disposal facilities in the area which help, that we own, and part of, in fact, I think, $4 million of the purchase price on Hallwood South was for two saltwater disposable wells that are, I think, are set up for commercial use as well so we're not having to $0.65 to $1 per barrel for trucking water.

That's a big advantage but basically it comes down to why our overall operating costs are low, 90% of our production is gas and a gas well is cheaper to operate than an oil well.

I will highlight that most people miss this, Ellen, it certainly has a huge impact on what you can pay for a reserve in the ground.

I noticed there was an acquisition last week or the week before where the operating costs were $1.75 per mcfe.

Here, our operating costs are $0.20.

So that means that we start out being able to pay arguably $1.50 more for the same type value proposition.

So it's something we always seek and sometimes people tend to look at only one metric in looking at an acquisition, and really from our perspective we're looking at how do we best make money and that's been the combination of high productivity, low operating cost gas wells in the Southwestern U.S. provides the greatest profit margins that we've been able to see.

The other acquisitions that you talked about, the aggregate of 160 million closed post the end of the quarter.

Can you give us some kind of color on what you acquired there?

Sure.

Three different deals.

Two of them were in East Texas and one was in the Permian.

The one in the Permian was from a company we've done business with in the past who had a deep prospect idea underneath some shallower production, and it came to us because of our deep drilling expertise, and we're hopeful in the next six months of getting underway there with drilling a exciting prospect there that is in West Texas.

So there we basically kind of bought some production to get access to a large, a drilling prospect.

On the other two deals, they were in East Texas, and really are a continuation of the build-out of what we're doing there targeting various tight sand plays in those areas.

One of them was 95 million, I think the other was 20 million, and the West Texas deal was 45 million.

Does that help?

It does.

One final question from me.

You mentioned again several times how ultra-competitive the market is out there for acquisitions so should we look for more of the same for you or --

I think we've been, it's been more of the same for us for seven years now.

So, and always people are wondering if we pay too much, and the only mistakes we've really made to date on the acquisition side is not doing more of them but certainly we're happy with what we've been able to put down.

I will say that, I'm going to repeat my LOE comment, if you look at the all-in cost structure of various deals these days we actually think ours compare very favorably.

If you add LOE to the other deals I think we actually come in cheaper.

So that's an important aspect.

And then I also want to highlight that although we certainly describe the acquisition from Arka as ultra-competitive, the reality is, in the type of deals that we do, which are acquisitions that have the opportunity to provide an incline curve rather than a decline curve, there's not as much competition as you might think because access to rigs is so important.

Most of these deals come from companies that have one or two rigs active on a block of acreage and really to fully develop them you need to go to four, five, six or even more rigs and most companies don't have the ability to go get those rigs.

We either can get them or we can re-shuffle our deck, and so in that respect, in a very narrow segment of the acquisitions market where we concentrate, which is kind of the under 600 million level, high PUD content, incline curve rather than decline curve, we don't have that much competition.

You haven't seen us be very competitive at all on any deals in the last year where it's just kind of PDP only.

We're never going to be able to compete with the financial players or with some other companies that might want to shore up their production basis.

It is competitive but we have staked out some advantages that make us, we think, highly successful in the acquisition area for the reasons that I've stated.

Great.

I do.

I lied.

I have one more for Tom.

On the Deep Haley play, getting back to the original question, could you describe, what's your idea in terms of the good well versus the poor well of ultimate reserve recoveries?

What we've seen, Ellen, in the excellent wells in Haley are 20 to 30 bcf-type wells.

It's too early for us in our production curve to determine if we have that but the initial IPs look like we could.

In our budget, we only need to have first month, 7.5 million a day I think to meet our requirements for our budget.

So I think it's, that over time we'll continue to learn more and more about Haley just like we did in Western Oklahoma and the Buffalo Creek area, and as we get more seismic in we'll determine better places to drill and it will just, I believe it's still an emerging play category so it's going to take some time for us to figure it out.

We have heard several of our explorationists tell us that it reminds them of the Anadarko Basin in the '70s where, it's hard to describe this area, bit it's, first of all, it's really large.

I think you've heard Anadarko talk about having 125,000 net acres.

We have 125,000 net acres.

That's ten townships of land that we think are prospective in the overpressured gas resource area.

There are very few deep penetrations across it.

There are some in concentrated areas.

Anadarko's obviously done well, but I think in listening to what they have to say, they described it the same way which is they've had some truly exceptional wells and some average wells, but when you add it all together it's a highly commercial play and it is a highly commercial play for us right now.

We just don't want to get people's expectations too far in advance and instead want to keep people focused on average, this 7 bcfe model, for which we hope we can drill them for around $8 million and that would be a great place if we can do it.

So I think it's just an area that we're all going to have to watch going forward, but there's a lot of gas in place, and I think we and Anadarko are going to, and at the end of the day we hope will be successful in cracking the code.

Ellen, we're currently involved in four 3-D shoots that are happening in West Texas.

I might also mention in addition to our four operated wells we are a 50/50 partner with Anadarko in one of theirs, and I guess they're 50/50 in one of ours.

Is that right?

So we do have some acreage our here in common that we'll be trying to figure out together.

We'll go to our next question Ryan Zorn with Simmons & Company.

Good morning, guys.

Hey, Ryan.

I wonder if you could go into a little more detail who's building the Nomac rigs and the delivery schedule as you see it going through '06, is it pretty evenly distributed or lumpy, or how's that play out?

It's a little lumpy, and the manufacturers I don't think we're going to identify at this point.

I think there are three, and just really for competitive reasons we don't want their doors beat down any more than they already are.

I don't have an exact, do you have a rollout schedule?

We just plan on four more this year.

Those are toward the end of the year, aren't they, Tom?

From October through the end of the year, yeah.

And then we have 19 more rigs to come out and the rest of those would be just basically throughout '06.

I think we said in the press release 18, so I think we've picked up one overnight.

They'll be rolling out.

Again, tend to be the shallow or medium, let's call them shallow to medium-depth rigs that we're focused on.

Okay.

So if you can go out, as you get the last one delivered, what do you think operated rig counts go to?

Do these --

You mean of the Company's operated rig count?

Yeah.

Do these replace rigs from third parties, or are these --

They can do both.

We're going to do two things.

We're going to be changing out some rigs that other people have, and, of course, to the extent that makes a little softer rig market at the margin that's certainly helpful for everybody in the industry.

But then, we've got some plays that we're in the process of ramping up on.

I think I mentioned in my spiel that we might be up in the high 70s, so if we had another five rigs right now available to us I think we'd know where to put them.

In fact, the next group that's coming out I think most of the rigs are going to Sahara, aren't they, Tom, and that's where we plan to ramp up from where we are right now with another three or four rigs.

Next year's rig counts look like they'll have an 8 on the front of it, right?

I hope so.

We certainly have the technical capability of running that kind of program.

We've certainly got the prospects to do it on.

We'd just like to not pressure the rig environment any more than it's already pressured.

We go next to David Cameron with Jeffries Investment Bank.

Good morning.

Congratulations on a good quarter.

Thank you.

Quick question for you.

Most of them have been answered but in the Mid-Continent, it seems to me like the differentials have started to creep up a little bit.

Are you seeing the same thing, and kind of what's your outlook there?

They definitely are and I'm going to let Marc handle that for us.

I'd say, David, that they've done more than creep up.

If we went back really to 2002 when we began to see the potential for basis to widen substantially and we began to layer in long-term basis hedging, we were able to sell basis forward as little as $0.14 back there to certain delivery points in the Mid-Continent.

And at that point for many years basis had ranged from as little as zero to a nickel in hot summers to maybe $0.20 in the winter sometimes, average of $0.15 seemed very reasonable.

At one point I think we had nearly 800 bcfs sold forward.

Today a lot of that's worked off but we continue to see the same kind of things that led to us believe basis would widen, and as gas has come out of the new Cheyenne Plains systems and other gases forced competition out of the Permian onto the Mid-Continent basis today has widened substantially.

I think year-to-date our basis company-wide has increased to $0.69 before hedging.

We see that also being influenced by higher gas prices.

Basis naturally, because of fuel costs and transportation related issues, cost more to transport $10 gas than it costs to transport $2 gas.

So looking forward, in a $9 plus gas price environment we're probably going to be looking at an even wider basis substantially offset by our basis hedging.

All right.

Is it just longer term, do we need additional capacity coming out of the Mid-Continent if prices stay up here given the amount of drilling that's going on in the region?

Is that--

Well, it's really not take-away capacity.

Yeah, it's really not take-away capacity out of the Mid-Continent, we have plenty of take-away capacity today.

It's that gas is being brought into the Mid-Continent from the Rockies or the Permian basis so they can transport gas up into the upper Midwest or take it to points East.

And so what used to be a phenomena in the Rockies, which was gas on gas competition where you didn't have enough take-away capacity, that take-away capacity's been increased by bringing it to the Mid-Continent.

In our basis hedging program we've made probably $200 million to date and have another couple hundred million dollars of potential hedging profit depending on what basis does going forward.

So it's a real important issue for us.

We're watching it extensively.

Our own marketing companies entering into firm transportation agreements so that we have take-away capacity, not just out of the Mid-Continent but areas like the Barnett Shale, East Texas, and Ark-La-Tex.

It's been an interesting time because we've actually even seen Houston ship channel basis widen compared to Henry Hub for the first time ever in the last year, and that's the same issue.

It will be an interesting issue as LNG is brought into the pipes in Southern Louisiana as well because that has to, if it's brought in in quantity it has to disrupt gas coming from other places.

One other thing to think about is a lot of our, the industry sells a lot of gas on percentage of proceeds contracts.

And keep in mind that basis is effective by things like fuel and compression as well.

So all of those things result in, as gas prices go up, your basis differentials are going to widen out as well.

It's just an unfortunate side effect of higher gas prices but it's one that, in the greater scheme of things in that big of a deal particularly because of this $400 million or so gain that we've got as a result of recognizing this when we first heard about Cheyenne Plains.

Anything else?

We'll take our next question from Adam Light from Credit Suisse.

Good morning.

Hi, Adam.

A couple of quickies.

Tax exemption on these properties, excuse me, how long does that last, and what's that specifically for?

It's for the tight sands tax exemption in Texas for state severance tax and there is no, it's for the life of the well and there is no cap on the gas price.

Oklahoma, for example, had some exemptions that lasted either two, three, or, I think, five years depending upon how deep you drilled, and we were not able to take advantage of those in most of '04 and to date in '05 because gas prices were over a certain, well, $5 was the limit.

We worked hard this year to get that cap lifted.

We're able to get Bill passed through the Oklahoma Legislature and signed by the Governor which lifted those caps going forward.

So, you know, in all the areas in which we work, states are competitive for drilling dollars and Oklahoma realized they needed to attract deep drilling dollars and Texas has done a good job of setting up an incentive program that is very helpful to producers drilling both deep wells in Texas and also drill tight gas sand wells.

Okay.

And on the, another one on the acquisitions.

Can you split the proved component into the parts and how much of the proved is undeveloped?

We are capable of doing that but we've chosen not to do it here for some competitive reasons.

So that's a little different than in the past but hope you'll bear with us on that for the highly competitive nature of the Barnett Shale area.

We'd rather not show all of our cards in that area.

Okay.

And at the risk of getting the same answer, can you give us a little more specificity as to where in East Texas?

No, Tom's shaking his head on that, too.

So, sorry.

Both of those are in highly competitive areas as well, so we'd rather not give a road map to where we're working these days over there.

Okay.

Last one for Marc.

This may be my fault, but can you walk me through the arithmetic from the reported EBITDA to the adjusted EBITDA because maybe it's just too many earnings calls this week, but I can't get to the same number.

I can go back to our reconciliation and hopefully that will be self-explanatory.

On Page 16 and 17, I guess, are you looking at the six-month EBITDA, or are you looking at three months?

The three-month EBITDA to get from the 580 to the 565.

On Page 17 there's two adjustments there.

You start with 580.2 million, and the unrealized gains on the oil and gas derivatives are 84 million, so that's taken off of that, and then we added back 68.4 million, which was the loss on our repurchase of debt and the exchange of debt that we did during that period of time.

So those two, subtracting 84.1 and adding 68.4 takes you to the adjusted of 564.6.

Sorry, it's my printout that's confused me because the other part rolled over onto the second page, and I apologize.

Thank you.

That's okay.

Thanks, Adam.

We'll take our next question from Gil Yang with Smith Barney.

Good morning.

I have three questions.

Aubrey, you comment that you, having all those rigs is certainly an advantage because you can get a lot more drilling done than other people can.

Can you just comment on the staffing market to get people onto those rigs?

I know you've made some comments about that before, but could you update about?

I don't think it's much different.

I mean it's a tight people market everywhere but we've had probably an easier job than most staffing our rigs.

I'm going to say it's largely because of the offer of abilities that people have when they come to work for our drilling subsidiary.

They know they're coming to work for us, and they know that we've got 70 some odd rigs running and only own 14 of them, so if we cut back five or ten rigs for some reason we're not likely to layover our own rigs, whereas if you go to work today for another established drilling contractor, if you've done any work at all, you know that about every three or four years those companies fire about half of their workers.

So there's just not much loyalty there because of the cycles of the industry, which we've taken out that cyclical risk by keeping our own rig count significantly below our operated rig count.

But, you know, it's still hard to get people and certainly we're having to pay competitive wages.

The other thing I think I would highlight is that those guys on those rigs know they're working for the operator.

There's not the traditional contractor-operator tension that I think you find on other rigs where people get paid for really how long it takes to drill the well.

Guys who work for us really have a Chesapeake ball cap on and realize that they're on the same team as the operator, and I just think that creates at the end of the day a little better operational environment to drill wells in.

Okay.

Thanks.

Second question is, you said that the proved reserves on your North Block acquisition have improved 24% since the acquisition.

Could you comment as specifically as you're willing to what drove that 24% increase?

I think two things.

One is that our average result to date has been 2.8 bcfe rather than 2.5.

So that in and of itself is a 10% difference.

Probably the bigger difference is when we made that acquisition, we established a drilling pattern where the wells were 2,000 feet apart from each other, 3,000 foot-long laterals, and 2,000 feet apart from each other.

We now have begun to drill wells on 1,000-foot laterals and are now getting out to 3500 and 4,000 feet and have seen the impact of what that is, and the impact has been that we don't see at this point any difference in recoveries.

So what we've been able to do is drill on a tighter pattern, and I think, Tom, if I'm not mistaken, that 1,000-foot stand-off and 3500 feet gives us about a 70-acre spacing unit pattern.

It's just under 70 acres at 3500 feet.

So that means we can drill essentially nine to ten wells per every 640 acres, or square mile.

And at that point if we're able to average 2.8 bcfe that's on a basis where you could be developing 25 to 30 bcfe per section.

And when we started in the North Block we were thinking maybe about 20 bcfe per section.

So a significant advantage in what we're seeing so far.

It's what everybody has said about this core area and the Johnson County sweet spot, which is over time you probably likely to get upside surprises rather than downside surprises, and we hope that that will take us into the South Block as well.

Given that you've only been drilling these wells for maybe six, eight months, is it premature to know whether or not you've gotten additional volumes or just acceleration out of the closer spaced wells?

Just based on the curves that we've seen to date, we really do think we're finding incremental volumes, and it's really, I think, consistent with what you've heard from some other people that are in this, oh, this one I'm just going to call this Johnson County sweet spot and on up into the core area where Devon, of course, is.

It is early but at this point we feel pretty good about what we've found to date on the North Block.

Okay.

Last quick question and I'll just get back in queue.

If you look back at your acquisitions over the last few years what is the right risking of probables and possibles that we should be using?

Well, I think we've already done the risking for you, is how I would say it.

You can do whatever you want, of course, with any number we give you, but when we look at a probable and when we look at a possible, we think that we've already risked it to the get to the reserves that we show, and then I would just say that the type of prospects that we, or the type of deals that we buy, they tend to be, whether or not you call them gas resource plays or something else, they tend to be something where the reservoir is there and there's either, the geological risks are not great.

The question is really more an engineering perspective can you, from the limited base of information you have at the moment, say that you're going to be able to expand the play five miles one way or three miles another way.

And that's the kind of stuff we've done.

And so our probables and possibles have rolled up pretty nicely and I think that helps account for the Company's great reserve growth over the last few years.

Tom, did you want to add something back?

I was just going to say also on our Barnett play, the conservative nature that we've put into our model is also another way we risk it in that we're spending $2.5 million to frac 300 feet of shale, and we only need to find, well, and on top of that, our initial rate is 3.2 million a day for the first month to get to 2.5 bcf.

So comparing that to some of the other numbers we've heard we think that's fairly conservative.

We're using basically an 800 to 1 kind of ratio on IP, or first month average to EUR.

We've heard other companies talk about 1200 to 1500, and honestly, we hope they're right.

It will only mean that we're significantly underbooked in this area.

We go next to Edward Min from Raymond James.

Hi, Good morning, Just one question.

Regarding your increase in Cap Ex guidance about what percent of that increase relates to cost inflation versus acquisitions?

I would say for this quarter, for the second half of the year and into '06, at this point most of the increased Cap Ex is a result of cost inflation.

As Aubrey mentioned, low 70s to high 70 rig count, that's pretty much unchanged from where we've been.

The acquisitions that we've made in the last six months have tended to come in from a drilling activity and either supplant or have been replaced by other drilling activity such that our drilling rig count has really not changed substantially.

So at this point, as I mentioned, cost inflation that we're seeing has been measured probably in terms of 20 or 25% or in some services maybe even more on a per annum basis, and we've listened to a number of the conference calls where people have estimated that their Cap Ex program is increased and it's been 25% as a result of inflation or 50% as a result of inflation.

I think we would probably think that that's a little low.

Okay.

Thanks.

We go next to John Zahringer with Loomis Sayles.

I think the most important question I had to ask was asked by Adam regarding the breakout of PD and PUDs on your acquisition, so we'll go on from there to more arcane issues.

Your capitalized interests in particularly your capitalized G&A, are moving up a lot.

Is the Q2 level of capitalized G&A, is that indicative of where this level is going to be going forward and a contributor to the relatively low expense level?

John, I think so.

It's purely a function of the staff and related expenses that are necessary for the drilling program activity.

And clearly if you look at the capitalized costs that we gave you in G&A as compared to a year ago, and you compare the rig count to year ago, along with some cost inflation obviously on the personnel side as well, those are the two drivers.

And so if we look forward and we run an average of 75 to 80 rigs a year from now you'll have some personnel cost inflation that will drive that number up, but it's primarily a function of just your rig activity and the number of people and resources dedicated to getting that rig activity manned.

On that front, I think we've got about 2200 employees now, and I believe about 800 of them were not with us a year ago.

So as we've added most of those have not been in administrative positions, those have been in either field positions or drilling positions or in various technical professions.

Okay.

Would it be fair for to us assume that you are doing a lot more hedging right now, or very recently?

Is that fair to assume?

Probably not.

I mean if you just look at how we hedged Hallwood we only went out through March and obviously we did it when we made the deal with Hallwood, which as a month ago so we've left some money on the table from where we are today.

The reason we haven't been more expansive hedgers right now is a couple of fold.

One, we're in pretty good shape from what we've hedged for the rest of the year and into '06, but we don't believe we're in any kind of a spike environment.

Now, we've got summer gas prices at $8.50 or $8.75, whatever they are, and somebody might disagree with me on that, but our view is that gas prices are right now are at about a 20% btu discount to oil.

We think in another three or four weeks gas storage will be at a year-over-year deficit which will be first time in about three years that's occurred.

We have a large short position still in the spec side of gas market.

And in our view gas is going to move towards btu parity with oil.

The question of course is will oil stay at $60 a barrel and that means you have $10 gas, or does that mean oil comes down to 54, 55, and you've got $9 gas.

So we don't know the answer to that but right now the oil market seems pretty firm.

Gas continues to trade at a discount, I think for the reasons stated, and I think our weathermen tell us it's going to be hot for another few weeks and we should be able to completely wipe out this persistant year-over-year storage surplus which has dogged the gas market over the last really three years.

We still have the majority of the hurricane season left as well.

All kinds of natural disasters lining up in favor of your wallet.

Congratulations.

One last question.

And that is, these third-party sponsored rigs that you have I guess in construction or actually on location doing work for you, how do you account for these things?

Obviously you have a lease payment that's due the operator.

The third-party sponsored rigs really are no different than just taking the rig under contract with Nabors or any other vendor.

When we say we've sponsored it, we've entered into a longer term contract than a location by location contract that we might do with Nabors, for example.

And that might be a one-year, two-year, even a three-year contract for the use of that rig.

In exchange for entering into a long-term usage contract we've extracted a discount to the market value, first of all, from what that rig could sell for, or rent for, and second, we've tied up the usage of that rig.

In exchange for that contract the owner of the rig then is able to go and obtain equity or debt financing on the strength of the Chesapeake contract and obtain the money to go and put that rig into service.

Then as the rig is put into service, which we've paid nothing for entering into the contract, there's no up-front money or any kind of prepayment, but when the rig actually goes into service and they bill us on a monthly basis, then we write them a check under the terms of the contract and that is put in just the same as any other expense on a well.

It gets put into the full cost pool at the cost that we incur.

And so it gets capitalized in our full cost pool and then is depreciated under the units of production method.

Okay.

That's helpful.

How about one more on [inaudible]?

I think I'll let it go on that.

Thank you very much.

We go next to Eric Kalamaris with Wachovia Securities.

Good morning.

Thank you.

Good morning to you.

I have a question regarding the capital budget.

In looking at the 2006 number that was provided, how much of that is related to the 11%, or 13% production growth?

So, Eric, make sure I understand the question.

Flipping that around, is the production growth that we're projecting coming from an increase in capital expenditures, is that the question?

Yes, it is.

Okay.

It's going to be a combination of partly the acquisitions that we've made to date and will make that we've already announced, or even ones that we haven't announced or haven't even entered into yet, going against a full-year of '06 production, and then it's partly organic.

So we've led people to think in terms of an organic production growth rate for this year of north of 10% and similarly for next year.

To the extent the acquisitions come on top of that, then, you know, obviously the total growth will be higher.

There's really no way to separate the capital budget as a function of the organic growth rate.

It's mostly a developmental budget but it has some exploration pro formas like Haley in there, all of which we think we've adequately risked to give to the numbers that we've shown.

That's helpful.

Thank you.

And secondly, I may have misunderstood what you said regarding the revolver balance.

You said availability was 900 million?

No.

This week we have approximately 900 million outstanding on a 1.25 billion revolving facility.

So as of this moment, of course, it goes up and down based on our cash cycle during the month, as of this moment there'd be 350 million approximately available.

Thank you.

We go next to Jeff Robertson with Lehman Brothers.

Good morning.

A lot of questions have already been answered, but one question for you, Aubrey, on the acreage acquisitions in the second quarter I think you all added half a million acres.

Can you talk a little bit about the drilling commitments that come along with the acreage you all have been putting together and how that drives your operated rig count?

And then as an off-shoot to that, just being able to keep up with the need for petroleum engineers in both drilling and completion and geologists to get all that work accomplished.

Jeff, most of the acreage that we buy, I mean the vast majority of it, is just acreage off the ground and most of it does not come with a drilling requirement upfront.

Certainly when we make an acquisition, like on South Block, you know, these leases have already been in place, and we have to hustle around to make sure that we go get everything drilled before it expires.

But at the end of the day most of what drives us in, well, everything that drives us on the drilling schedule front is on where can we drill the best wells.

Occasionally we have some lease expiration issues that crop up but we really are not committing ourselves having to drill a bunch of wells.

With regard to technical talent, I would say for the industry it remains very tight, and as you look across the industry and look at landmen, you look at geologists, you look at engineers, the average age of these people are all about 50 today, they're all making probably two or three times what they were making three or four years ago, and over the next 10 to 15 years we're going to lose a lot of those people, maybe over the next five to 15 years.

So we've got to hire a lot of young people, and you've got to make up for the fact that we've lost basically a whole generation in between kind of where we sit and where our kids are and people just above that age.

So I mean it's hard for most people but given the excitement level of what we're doing, I mean, we are, we do have the most active drilling program in the country.

We certainly have one of the most active acquisition programs in the country.

We're perceived as a young company.

We've got an attractive campus.

Everybody gets restricted stock grants.

So we think we run a pretty progressive shop in a world where young people are attracted to action, we think we've got action and have done a nice job at being able to attract both young people and also people who are leaving other jobs.

I will say one other thing.

We are seeing a lot of people, a lot of resumes from people working for bigger companies internationally.

That is no longer the plum assignment that it used to be for a company for people who wanted to work for big companies, so that's an area of mining for talent as well.

People trying to get out of some of combat zones, Aubrey?

Yeah, I mean, I just don't think being stationed in Saudi Arabia or Indonesia or Nigeria anymore might be quite as exciting, or maybe too exciting compared to what it was ten years ago.

Is there a current limit to just how many rigs or how much activity you all can effectively control with getting all the work and all the quality control and well hookups done?

I think there is.

We're not at that limit right now.

Tom, we've been in the low 70s for how many months probably on the rig count?

I don't know off the top of my head but it's been some time.

I think even six months ago we were 75 or 76.

It was a lot hardy year or so ago, when you bring on new areas, Permian or [inaudible] East Texas.

It's a good point.

Jeff, if you go back three years ago, we basically with Mid-Continent, over the last three years we've rolled out a presence in the Permian, South Texas, Gulf Coast, East Texas, Barnett, Fayetteville now, and so the heavy lifting is getting your organizational structure in place for each area, setting up your field offices, hiring the management or promoting the management more likely for us to run those areas.

Once you have the technical infrastructure and staff it's a lot easier to run.

So I would say right now that if we added ten rigs tomorrow I know that we'd be able to handle that.

Could we go increase our activity by 20, 30, 40% in the course of a month?

I think it just adds some organizational stress that we're not eager for and also management stress would get probably to an unacceptable level as well, so I think you'll see us start to kind of ease up, ease up meaning work up in our rig activities through the rest of the year, and I think we'll be more active next year than we are this year and not have the organization become less efficient.

I think we'll become more efficient.

We go next to Richard Wolf from Zach's Investment Research.

Thank you.

Can everybody hear me?

Yes, sir, we can hear you just fine.

I want to thank you for the excellent information you provide in your earnings release and also of course congratulate you on another excellent quarter.

My question pertains to the use of hedges in your acquisitions which has typically been the case over the years.

The hedging layout that you provide in the earnings release toward the end doesn't appear to include the 850 that you hedged the South Block Hallwood volume at in that acquisition.

And what I'd like to do is just sort of, on that note open it up to you, and maybe Marc is the right person to answer this, maybe someone else, but the role that hedges typically play in these acquisitions, can you discuss that?

Yes.

Back to your first point, the hedging for the various acquisitions that we do is not readily apparent to you in the information that we provide in the detail of all of our hedging because we do not break out any of our hedging activity by specific acquisition.

When we layer an 8.50 or a $9 hedge in for an acquisition that we're making, it becomes blended with the earlier hedges that we have, and if we had previously done that amount of volume, say at $6, then what you would see is a blended price of $7.50, and a blended volume of all hedges done to date inclusive of the acquisition hedge.

So there is no way to look at our hedging schedule and identify any specific hedge done for any one acquisition, we just have never felt nor have we been asked to break it out that way.

Okay.

So the Hallwood hedges are in the table that I see later on, and it's not a case of them being, can we say, special or contract hedges that are carved out and are sort of regarded as part of the acquisition?

That's exactly correct, and that's why at some times in past conversations we've pointed out that while we've said we've hedged certain volumes, those contracts don't run to the specific well bores that we're purchasing, and that really gets into the second part of your question which is what is the strategy related to this hedging.

As we've taken on additional gas volumes or oil volumes related to a particular acquisition, we've felt it important to go out and try and lock in margins for at least that quantity of gas, and it really doesn't need to be called Hallwood gas, could it be called Chesapeake acquisition gas or it could just be called Chesapeake gas, but what we are trying to do is in the early periods of an acquisitions production profile to lock in margins that are superior to what we've just made the acquisition on.

If we can sell gas at 8.50 I would guarantee you that we don't use anything close to that in making the acquisition, because that's frankly, not the market.

It may have a 6 number on it, or a 6.50 number on it today, but if we can then turn that acquisition into an 8.50 or $9 sale we're going to do that for anywhere from six months to maybe 24 months depending on our view of gas praises at that moment.

And we might not necessarily do it exactly the day that we make the contract.

In times past, in fact, I can remember a year ago, we made some acquisitions and the question was why didn't you hedge those.

Well, we didn't the day of the acquisitions, but within a month of our press conference we had hedged all those volumes at prices substantially higher.

So the strategy all is about return and margin and locking in those crucial first 18 to 24 months of an acquisition that substantially lowers the amount of cash that we have, guarantees the margin, and frankly, leaves most of the reserves remaining for us to take advantage of in the future.

And you're just doing those regular NYMEX contract?

Well, they're actually not NYMEX contract, they're based on NYMEX pricing but they're with counter parties and not through the exchange.

They are simple swaps with those counter parties and they'd be called over the counter trades is what they're referred to.

So you basically like in the case where you wait or you have waited to do them, it's basically in collaboration with a counter party one or more counter parties working out the, looking for the right opportunity with that counter party?

That's correct.

Okay.

Thanks very much for your questions.

Moderator, do we have anything else?

I do show that it's a quarter after, gentlemen.

We have a few questions remaining in queue.

Okay.

We'll go ahead and take them.

We'll go next to Monroe Helm from CM Energy Partners.

Congratulations, Aubrey, not just on a great quarter but for probably having the best strategy in the environment that we're in today.

It's amazing that a lot of your brethren in the oil and gas industry have kind of missed the boat here on what was going to happen to supply and demand and prices and have been focused more on buying shares than going out and making acquisitions.

You guys obviously can teach them lessons on how to go out and get returns by putting on the proper hedges.

So you guys need to be congratulated to that.

One of these days Wall Street's going to wake up to what you've created here.

Appreciate it.

We had some lessons taught to us pretty early on as well.

I remember that.

It's good that you learned from them.

Had a quick question on your South Block transaction.

I know you didn't want to break out the 3P reserves into one, two, and three Ps, but are you willing to talk about what the future development costs will be for those 3P reserves?

I think we can talk about it just in general, and simply that we think we're going to be finding 2 bcfe down there for around $2.5 million to drill the well.

So you can probably back into the math.

That way, Monroe, but that's, I think, where we'd like to be at this point, obviously, if you do the math.

On that you're going to end up with finding costs of let's call it $1.50, $1.60 per cmfe and then you've a load acreage on top of that.

So it's going to be north of $2 in mcfe but south of $3.

Okay.

Thanks again.

Monroe, thanks very much.

Appreciate your kind remarks.

We go next to Ray Deason from Harris Nesbitt.

I had a question about the acreage in West Texas, Deep Haley.

Are there any re-entry opportunities?

I may be remembering this wrong but I thought there were some wells that were drilled to a shallower formation that you may be able to reenter there.

Can you just talk about, you know, well costs and what you see as the overall potential of the area as well as take-away capacity, if possible?

Take away capacity is fine due to the old fields that were there, Ellenberger fields in the area.

As far as re-entering shallow wells, that's not really anything that we can do because the casing is set up to drill the overpressured Morrow you really have to set up with larger casing sizes and be prepared to slim hole down as you go down deeper in the hole.

And then as, was there a third?

Just your thoughts about the overall value of the area.

Yeah, again, we believe that there's a tremendous amount of potential in the area yet to really uncover exactly where the potential is, but we hope with these 3-Ds that we have going along with the 3-Ds that currently have already shot, that we're going to be able to pinpoint very good places to drill in the future.

Even if you just took what we've drilled to date and average our, I mean, our exceptional well is so good that if we just quit right now and said it was a four-well play, we'd meet or exceed our pro forma actually, but we don't like a program where one out of three or one out of four wells is exceptional, we'd like it to probably be 50% or better.

We really believe that this has the potential over time and it will take some time to be as good as our deep prospects in the Anadarko Basin.

And even though it's very economical to date we think it has the chance to be an exceptional play.

Is it, I mean, these are blanket sands, but what is it that makes one well better than another?

You could go to work for Anadarko Chesapeake if you can answer that.

We do have blanket sands, they do differ in permeability and porosity and trying to pinpoint where that's going to be and how much structure influences it are things that we hope to resolve through these proprietary 3-Ds that we have underway right now as we speak.

We go next to Duane Grubert with Fulcrum Global Partners.

Aubrey, in your materials today, you talk about the 14,000 locations which, of course, is growing over time, which is great, and now you're articulating a nine-year drilling inventory.

It had been seven and obviously it's been growing in the interim.

I'm wondering if you could just comment a little bit about the philosophy of, let's say two years from now.

Would you guys be comfortable to say, oh, no, we have 10 years, or 12, what's the point where you think about your inventory in the context of when is enough enough, and when do you change your tactics a little bit either farming some of that out or just working it down?

As you know, Duane, we read your reports, and so not an unexpected question from you based on what you've been saying.

And our view on that is I'd answer that is, how much Chesapeake stock is too much for management to own.

Our view is, you know, we'd like to own more, we'd probably like to own it all.

And I think about our inventory that way as well.

I can't get enough of owning Chesapeake stock and I can't get enough of good drilling locations, because it's our view that they will likely increase in value going forward, and it's how we sleep a little easier knowing that we've got this enormous backlog.

So I know that what we have done has done two kind of contradictory things.

It has set up an upside story that I think is the best in the industry, but it has given us midling returns on capital as a result of these big investments that we've made in leasehold and in science, and so that has dragged down our returns.

I might also mention that most of this acreage is HBP, held by production, and so we do have the luxury of being able to not have our drilling program directed by lease explorations, but we can really direct our drilling program to where we're getting the best return.

So, I know it's a little frustrating for you and maybe some others that we continue to want to pile up the upside, but it is our nature and not likely to get corrected or changed at this late date in our lives.

Okay.

Very good.

And as you know I love the upside.

See you later.

Bye.

Thank you.

We have queen from Shannon Nome from JP Morgan.

Thanks.

Good morning, sorry for the late entry here.

Aubrey, you said you'd like to own more, you said you'd like to own it all.

What stands in the way of that?

I mean are you guys just too big to effectively hedge the production do that type of a drastic transaction?

Have you ever looked at that before?

We're about $10 billion short of where we want to be, but it's not realistic.

And I say that just to emphasize that we love our stock ownership and we'd like to own more and hope to own more in time, but I think the scale of the enterprise is such that that's unlikely to be a path of interest.

And I'll just say that we like very much the position that we're in.

Tom and I are hopeful to be able to own more stock over time and we hope the value of the asset base continues to increase as we continue to pile up the acreage and future drilling locations.

How liquid is the market for that?

I mean, how big could a company be and think about something like that?

There's an inter play of really how much credit your hedging consumes and right now, Marc, I think we could hedge one point --

We're probably, Shannon, at about 1.5 or 6 tcf that the Company could hedge say within a five-year period of time.

And we've worked, as you're probably very well aware of, very hard to have a number of, I won't call them proprietary, but very close relationships where we've got secured hedging facilities on.

But at 1.6 tcf, you know, that's 20% of the amount of hedging that someone would need to do to acquire a 6 trillion cubic feet enterprise.

So --

Sure.

Although that would be just three years of production and you could get something paid out, you know almost in three years, so it's fun to think about academically but not --

Not in your situation?

Probably more in our situation than most people since we start from where we start, but again, just not very realistic.

Thanks, Aubrey.

Thank you, Shannon.

Our final question is a follow-up Joe Allman with RBC Capital Markets.

Hi again.

Aubrey, could you talk about the relationship with Southwestern in the Fayetteville Shale?

Sure, Joe, and we appreciate you being both the first and the last.

That's great that you hung on with us.

I think we have a good relationship with Southwestern.

We certainly have known Harold and his team for years and have a great deal of respect for them.

We developed that on the Arkoma Basin side and then have watched them do especially well in East Texas.

And then really with very little fanfare they went out and put this idea together and it's obviously made that company and we have a great deal of respect for what they've done.

At the same time, the play is large and we recognize that when they start to talk about the play that it was unlikely that they had bought everything, and that turned out to be the case, and so we went to work.

We've acquired a couple hundred thousand acres and we're in, I guess, about 40% of their wells and so have built an information base that I think is second in the industry only to theirs, and we hope to use that to our benefit as we begin our drilling program in the Fayetteville in the last quarter of this year.

What's your interest in that 40% of their wells?

They're small.

We'll range from a couple percent to maybe we've got an eighth of some wells, but we're just in the areas where they've been drilling and we've just been only able to nip at their heels a little bit and in many cases weren't able to get in at all.

But one of our specialties is the acquisition of information in various plays and it's one of the reasons why our non-operated rig count is so high, that if anybody in the Southwestern U.S. is drilling anything interesting, we'd like to be a part of it to see if the works, and if it works, we'll hope to be competitive on the acreage side.

Just real quick, Aubrey, on rig crews, are you seeing any deterioration of the quality of rigs and crews?

I'm going to let Tom handle that.

I don't think that we're seeing much deterioration quarter-to-quarter, probably year-over-year we have and we continue to look hard to add to our crews and it's not an easy job.

We are paying a floor hand $20 an hour now, so I think it's attracting some decent laborers.

As those guys get trained up over time, what's been nice about the last two or three-year increase in the rig count is it's been fairly measured.

You've got a year-over-year rig count increase right now at 15%.

And so I don't think that's too much to ask of the industry to be able to staff up to handle a 15% year-over-year.

It's when you get to 20, 30, 40% which is obviously not possible today given that there's just not the excess rigs out there.

That business just has a very high turnover rate at this point.

Joe, anything else?

Thank you.

You are our alpha and omega, and we appreciate you being with us.

Thanks to everybody for being with us on this longest conference call ever.

If you've got any additional questions, at least for us, give us a call.

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