Chesapeake Energy Corp (CHK) 2005 Q3 法說會逐字稿

Good day and welcome to this Chesapeake Energy's third quarter 2005 conference call.

Today's call is being recorded.

At this time, for opening comments and introductions, I would like to turn the call over to Mr. Jeff Mobley, Vice President-Investor Relations and Research with Chesapeake Energy.

Please go ahead.

Good morning.

And thank you for joining Chesapeake's 2005 third quarter earnings release conference call.

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

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

The statements 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 analysts' estimates.

These are all non-GAAP financial measures.

Reconciliations to the comparable GAAP measures can be found on pages 13 through 15 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 20 minutes, and then we will move on to Q&A.

Aubrey?

Thanks, Jeff.

I appreciate it very much.

And sorry that we are a few minutes delayed.

The conference call service needed to get some more lines ready for us, so I apologize for that slight delay.

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

After excluding items not generally included in analysts' calculations, Chesapeake's third-quarter net income available to common shareholders was $234 million, or $0.65 per fully diluted share, versus the consensus estimate of $0.62.

I read this morning that is the 23rd time in the last 25 quarters that we have exceeded the consensus estimate.

In addition, our third-quarter operating cash flow was $635 million, and our adjusted EBITDA was $668 million -- both of which were Chesapeake records.

Chesapeake's third-quarter 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, production taxes, and interest expense totaled only $1.72 per mcfe this quarter versus $1.52 per mcfe for the 2004 third quarter, which is just a $0.20 per mcfe increase year-over-year in a very inflationary oil field environment.

By comparison, our revenue per mcfe was up $1.72 per mcfe, or eight times the amount of our cost structure increase.

We believe this is a very nice trade off.

We work hard to control all of our costs and believe it's a direct outcome of our focus on the details of our business and a result of our large operating scale, which gives us considerable negotiating power with service and equipment providers.

We believe our focus on finding and producing onshore natural gas in the Southwestern US and now in Appalachia remains one of Chesapeake's 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 28% compared to the year-ago quarter and 5% compared to the 2005 second quarter.

Of that 5% sequential growth, 47% came from acquisitions and 53% came from the drill bit, making our quarterly organic growth rate 2.9%, our year-to-date organic growth rate 8%, and our annualized 2005 organic growth rate 10.7%.

Keep in mind, this impressive organic growth performance is from a company that, after the CNR transaction, will be the second-largest independent producer of US natural gas and the fifth largest overall producer of natural gas in the US.

Very few large-caps can grow their production organically at all, much less at the 10% rate that we will achieve this year.

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

The 2005 third quarter was our 17th consecutive quarter of record production, and 2005 will be our 16th year of record production.

Consistent with our strong production growth, we are also doing quite well in building proved reserves.

During the first nine months of 2005, we produced 338 bcfe and replaced it by almost five times at a drilling and acquisition cost of only $1.47 per mcfe.

Reserve replacement through the drill bit was 275% at a cost of $1.42 per mcfe, while reserve replacement from acquisitions was 213% at a cost of $1.54 per mcfe.

During the third quarter, we increased our proved reserves by 27% or 1.311 tcfe to a quarter-ending total of 6.213 tcfe.

Please remember, these numbers do not include the impact of the 1.1 tcfe of proved reserves we've recently acquired through the CNR transaction.

In addition, during the past seven years we have worked hard to build what we believe is the nation's largest inventories of unproven reserves.

We've built this 7-tcfe inventory in anticipation of today's highly rewarding commodity prices and highly competitive acquisition market.

By being a first mover, we gained many advantages over others, and today we are executing the nation's most active drilling program on what we believe are the nation's largest onshore, land and 3D seismic inventories.

Pro forma for the CNR acquisition -- we now have identified approximately 25,000 locations to drill on our 8-million net acre onshore US leasehold inventory.

It has taken us seven years and several billion dollars to build this inventory and more than $200 million to high-grade it with 11 million acres of 3D seismic.

This deep 10-year backlog of opportunities and the hiring of the very capable employees who manage it, prospect on it, and drill on it, cannot be replicated in today's ultra-competitive industry environment.

This early and sizable inventory should enable Chesapeake to continue delivering strong growth and attractive financial returns in the future, whereas many in the industry will be challenged to generate future growth and will likely face much higher reserve replacement costs in the future than we will.

We were able to acquire our 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 to a significant number of very important natural gas plays in the USA.

Today, we believe Chesapeake owns the largest inventory of gas resource plays in the industry.

Whether it is coal-bed methane in Oklahoma or in Appalachia or too tight sand plays in West Texas, East Texas, Northern Louisiana, and Oklahoma or in Appalachia, or Shale plays such as the Barnett Shale in Texas, the Woodford & Caney Shales Oklahoma, the Fayetteville Shale in Arkansas, or the Devonian shell in Appalachia, no one has what Chesapeake has in resource potential in America today.

It is true other companies may have made bigger names for themselves by focusing on just one of these plays.

However, we have been uniquely chosen to compete in more than 10 such plays.

As a result, we believe the technology and informational transfer among these plays at Chesapeake will enable us to achieve better results than if we were a company involved in just one or two of these plays.

We also want you to know that we are not done.

We are aggressively continuing to acquire more acreage in all of our play types, in both conventional and unconventional, with almost 500,000 acres acquired in the 2005 third quarter alone through an aggressive land acquisition program that is today utilizing 600 land brokers in the field.

Today, we have 73 operated rigs at work and another 71 or so non-operated rigs.

This program provides us information on more than 10% of the wells being drilled in the US today.

This program also enables us to drill approximately 2,500 gross wells per year.

We feel very good about owning a 10-year inventory of such drill sites.

This unique and valuable backlog of opportunity is Chesapeake's number one distinguishing characteristic.

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

In Oklahoma, we have 31 operated rigs, in Texas 32, in New Mexico 4, in Louisiana 3, in Kansas 1, and in Arkansas 2, for a total of 73 operated rigs.

By play types, we have 12 rigs in the Sahara gas resource play in Northwest Oklahoma, 13 rigs in the Deep Anadarko Basin at Western Oklahoma, 8 rigs in the Permian Basin, including 4 in the Deep Haley area, 13 rigs in the Granite Wash and Red Fork gas resource plays of the Anadarko Basin, 8 rigs in the Tight Sand gas resource plays of the Ark-La-Tex region, 4 rigs in the Barnett Shale, 3 rigs in the Bray and Cement areas along the Mountain Front in Southern Oklahoma, 4 rigs in Zapata County, South Texas, 3 rigs in the Arkoma Basin, 3 rigs along the Texas Gulf Coast, and 1 rig working in the Fayetteville Shale.

By the way, CNR has 4 operated rigs working today.

During the remainder of 2005, we expect our operated rig count to move up towards 80 from the mid 70s where we are today.

Before I wrap up, I wanted to let you know that we received our Hart-Scott-Rodino plans, and we are moving forward to closing the CNR acquisition later this month.

Our transition and integration processes are underway, and the more time we spend with the assets and with the CNR people, the more we like the opportunities that lie ahead.

We are already moving forward with plans to be more aggressive on drilling, land acquisitions and hiring so that we can hit the ground running when we close.

I will conclude by reminding you that Chesapeake is distinctive in at least three important ways.

First, through our 10-year backlog of drilling opportunities discussed above, we believe our organic growth potential is at the top of the industry.

Second, we have 6% of the nation's drilling rig fleet under contract, although we produce only 2.5% of the nation's natural gas.

In today's exceptionally tight drilling rig market, that is an important competitive advantage, especially in the acquisition market where the ability to more quickly drill "probables" and "possibles" is the key factor in being able to create value from acquisitions.

And third, we are the only company E&P that has actively hedged its exposure to rising service costs through our rig building and investment programs.

We have imbedded gains of at least $200 million in this program to-date and the ownership of our own rigs is proving to be very helpful across the acquisition and operational fronts.

Chesapeake continues to provide visible, sustainable, high-level, profitable growth at a valuation that remains attractive even after a 90% stock price gain in the past year.

Chesapeake's management team remains very energized about the Company's competitive position in the industry and the returns that we are creating for investors.

We thank you for your continuing support of our company, and now I'll turn this call over to Marc for his analysis.

Thanks Aubrey, and good morning everyone.

My comments will be relatively brief this morning, as Aubrey has already done a good job covering the analysis of our cost structure for the quarter, including the analysis of our reserve roll forwards, all of which is also detailed in our extensive press release.

Let's start with a few housekeeping details.

Our outstanding debt on our revolving bank credit facility was zero as of September 30th, and is $48 million as of October 31st.

Capitalized costs were as follows for the quarter.

Our interest expense that was capitalized was $20.8 million this quarter.

That compares to 10.5 million in the quarter ended September 30th of '04.

Year-to-date, we capitalized $54.8 million of interest in the three quarters as compared to $23.2 million in the previous year.

The interest costs being capitalized are a function of unevaluated leaseholds which Chesapeake is carrying on its books, which of course has significantly increased during the last year and we are at record levels of that acreage inventory.

As to internal costs related to our drilling program during the quarter just ended, we capitalized $29.5 million as compared to $12 million one year ago.

And year-to-date, we've capitalized $75.3 million as compared to $35.3 million last year.

Of course, capitalized internal costs do relate to our drilling program, which has increased in activity obviously, but also reflects increasing costs per employee in the geoscience and drilling areas.

As noted in our press release, we continue to exchange certain of our preferred stock issuances into common stock.

During the quarter just ended, we eliminated $214 million of our 4 1/8 and 5% preferred, converting it into 12.9 million shares of common stock.

Once again, I want to highlight that Chesapeake has, for the quarter, no current income tax expense, meaning no cash outlays as a component of income tax expense.

We expect that to remain the case over the next few quarters.

However, assuming prices remain at the current strip, Chesapeake could, by the end of 2006, begin to have some cash income tax liability.

But we still expect over 95% of the book expense to remain deferred.

We presently have entered into $1.275 billion of interest rate swaps, effectively converting about 29% of our total long-term debt from fixed rate to floating rate.

Something I'd like to highlight about our hedging since we've entered into the CNR transaction, which is those hedges that we mentioned in that press release we would be attempting to do.

Of course, this is contained in part and parcel to the hedging summary that we laid out.

But I thought you'd find it interesting since September 30th, the date the CNR deal was signed, we've entered into approximately 80 bcf of swaps at a weighted average -- volume weighted price of $10.67.

In 2006, the price that we hedged 41 bcf at was $11.55; 2007, 23.7 bcf at 9.70; and 2008, 10.95 bcf at $8.37.

This does represents about 59% of the total volumes that CNR are currently producing.

Our 10Q should be available by this evening.

And with that, I will turn it over to the moderator for questions.

Thank you. (Operator Instructions)

We will take our first question from Duane Grubert with Fulcrum Global Partners.

Yes.

Aubrey, when you're thinking about the CNR acquisition, when you kind of stand back and you think of the real upside case, I'm just curious if you have a bias.

Do you think that's going to come more from your increased activity level, more from a hard look at the geology, or more from something on the technology side like a change in completion?

Duane, thanks.

I think those are really all related to each other.

We have a company that has been owned by either a utility for quite some time or, the last couple of years, by private equity players.

And in my view, they really haven't been able-- hasn't been their charge to go look at their assets from an exploration perspective.

So I think we're going to do a lot more science than what's been done there in the past.

We're going to spend a lot more money on exploration than what's occurred in the past.

And I think we're going to apply a growth mentality to the assets there that simply hasn't been the charge from the owners of those assets in the past to the managers of that company.

And so we intend to change that going forward, and in my view you will see production increases there through a combination of just greater activity overall.

But also a lot more emphasis on science.

And we're really excited, of course, to be the only company that has as much black shale exposure as we're going to have from the Devonian Shale in Appalachia to the Fayetteville Shale in Arkansas to the Caney and Woodford Shales in Oklahoma and to the Barnett Shale in North Central Texas.

We believe that gives us an enormous advantage over some companies that are just playing in one of those plays.

And we think the informational transfer inside our company among all those play areas is going to give us some advantages that some other companies simply won't have.

Okay.

And then I noted you did pick up some Canadian acreage with CNR.

Is that high or low priority, or is that even something that you might think about looking for somebody else to maybe farm out to?

Yes.

That 600,000 acres in Nova Scotia, where there's actually been some drilling activity and some shows and there's a little bit of production.

That will be something that we monetize in some form or fashion.

And we will probably start that process some time in the first quarter of '06.

Great.

Thanks.

Thank you.

We'll now move on to Brian Singer with Goldman Sachs.

Good morning.

You picked up about 400,000 additional acres in the Fayetteville Shale.

Can you talk about where generally that those acres are?

And with regards to your drilling program, do you expect to have completed the six wells - at what point do you expect to have completed the six wells?

Well, the acreage is in Arkansas, and that's probably as definitive as we're going to be there.

We have drilled our first well, and we'll soon be moving on to our second well.

And we are spending quite a bit of time doing some science on these wells.

And so with 60 days left in the year, will we get another five wells drilled - Tom?

Probably not ...

We also take...

Three weeks.

...about 20 more days.

So we'll -- Brian, we'll be knocking them out about one every three weeks.

So it will probably be the end of January before we finish our initial six well vertical drilling program there.

That's helpful.

What are your thoughts on future approved property acquisition, opportunities relative to your array of organic drilling opportunities in the current market?

We'll probably continue to execute the strategy that's returned us a 25-fold increase in our stock price in the last seven years.

And that's through a blend -- a combination of inactive acquisitions program with an active drilling program.

We actually see profit margins today better than ever in acquisitions.

I mean, Marc just highlighted, I think, the biggest aspect at all that people in the industry and in the investment community just don't seem to quite get.

But we hedged 59% of our production for the CNR acquisition at 10.67.

And I can promise you the price deck we use to evaluate that acquisition was close to $4 lower than that.

So we've never seen better opportunities to create value through the difference between the forward futures curve and when assets go for in the ground than we've seen today.

So we're grateful that we appear to be in the minority and recognizing that, it's enabled us to make $10 billion of acquisitions that we probably didn't deserve to make.

And hopefully, that number of companies that see those opportunities out there will remain small.

So we love the competitive position we're in and love the arbitrage opportunity that we're able to take advantage of with almost every acquisition that we make.

Thank you.

Thank you.

And now we'll hear from Ryan Zorn with Simmons & Company.

Good morning, gentlemen.

Tom, I wonder if you might be able to talk a little bit about your entry into the Deep Bossier play.

I realize the deal is a bit delayed, and maybe you could comment on some of the circumstances that you're still working through there.

But I think the bigger question is what do you feel like you're bringing to the play?

Is it more of a expertise and completing some of those deeper, tighter sands, or is it something on the drill bit side that you can bring some efficiency there?

Well, we have some rigs and so we think we can get to the play, and we believe there's a lot of gas still to be found in the Deep Bossier.

And it's at a depth that we feel like we can drill efficiently.

So I think just in general, it reminds us a lot of the other deep plays we're in at Haley or Deep Anadarko.

It's just a good place to try to find a lot of gas.

So there's some direct technology transfer in terms of the completion exercises that you go through between what you're doing in Haley and what you've at Deep Anadarko as well?

Yes, there is.

We'd like to remind you, Ryan, though, that Gas STAR is the operator there.

So we will serve as a consultant, I guess, in our role there.

We do have other acreage in...

That's true.

We are active in the larger play.

You mentioned about the transaction itself, as you probably saw, I guess, our press release, I guess, yesterday, announcing that it had been delayed.

There is just a lot of paperwork.

There is an exploration agreement, there is a joint operating agreement, there is a stock purchase agreement, and all those documents have taken a little longer to complete than we first projected - then Gas STAR first projected.

Okay.

Aubrey, if you could comment with the initiation of your '07 guidance, what sort of rig count assumptions are driving those numbers both on the-- clearly on the CapEx side and on the organic growth front?

Something similar to your run rate in '06?

No, we're -- let me comment first on our '06 guidance.

Apparently, there are some questions that have been raised about that in terms of CapEx, so let me just go through that.

On September 7th, we were at 2.5-- let me go back.

On August 4th, we were at 2.1 billion to 2.3 billion for '06 CapEx.

On September 7th, we confirmed that did not change.

That's when we did some financing.

Remember, August 4th was when we announced in our second quarter.

On October 3rd, we announced CNR and we increased our '06 CapEx by 400 million.

Of that, about 200 million was related to anticipated CNR CapEx.

The other 200 million was a mix of service cost inflation and increased drilling activity expected, for which we were not willing to change our production guidance for.

Now in-- on October 31st, you see us bump that '06 CapEx by another 200 million and again, that's a mix of probably half inflation or 100 million, and half also increased drilling, for which we don't feel it's necessary and we want to be very conservative in our '06 production forecast.

So we did not project any additional production output from that.

As I have mentioned in my preamble, we've managed to outperform most people's expectations for years and years in a row.

You'll find that we will maintain that conservative guidance going forward.

So in summary, as I look at over the last couple of months, as we have increased '06 guidance or forecast by $600 million for CapEx, I would say one-third of it is for CNR, one-third of it is for inflation, and one-third of it is for increased drilling activity for which we have suppressed any expectation of a production increase as a result of that.

With regard to 2007, our initial CapEx estimate is $3.1 billion to $3.3 billion.

That is 400 million more than our latest guidance for 2006 or about 15%.

And I think that that reflects basically an expectation that we'll be about 15% more active in 2007 rather than in 2006.

He asked how many rigs that would imply if that had (inaudible)15% more than 85.

That's what I'm trying to say. 15%, actually not more than 85.

But-well 15% more than what we were projecting in '06, which would be in the mid-80s and so that would push it to the high-90s to even 100.

That does present some success in some plays where we have large acreage positions today.

Okay.

Thanks Aubrey for details.

Thank you, Ryan.

David Cameron with Jeffries & Company has our next question.

Good morning.

A question about the drill sites and the inventory, and this is -- I'm just looking at the second quarter to the third quarter in the mid -- I guess it's in the conventional area.

It looks like some drill sites dropped off as well as approved-or the probable possible number came down a little bit.

Is that related to any particular play or can you talk about the change there a little bit?

Yes.

Sure.

Let me get to over that with you.

In conventional before, we were at 1.4 tcfe of unproven, today at 1.0.

In unconventional, we were at 2.8, today at 3.4.

Emerging resource, we were at 0.8, now at 1.2.

Appalachia did not change from 1.4 to 1.4.

So we've gone from 6.4 tcfe overall to 7 tcfe.

That's a change of 0.6.

In conventional, it went down by 0.4, and basically that's the result of internal reclassification of acreage primarily probably in the Mountain front area and more towards our Cherokee and Granite Wash and Atoka Wash plays out in Western Oklahoma.

So overall, an increase of 0.6 in internal shuffling as we go through the quarterly portfolio review of our properties and you will see continuing moving around from classification to classification as things change.

Okay.

And then just following up on that, in the Granite Wash area, what -- I mean you guys seeing something that -- is it underperformed expectations or is it when you say reclassification what exactly...?

Well, that's the overperformaing -- we're seeing that actually we were able to add acreage to our, kind of area of prospectivity there that otherwise would have been attributed to Mountain front acreage.

And today we believe it's perspective for the Wash plays.

And in fact, you might have noticed that we increased our drilling in that area.

I think I mentioned that we're at 13 rigs in that area today and I believe that's up from 10 in the second quarter.

Okay.

And then maybe question for Marc just on share count.

What assumptions do you look in at '06, '07?

As far I think you go from 406 in this quarter to 424, 434 next year?

Is there anything we need to read into that or what kind of both into there, I guess 40..?

Well generally speaking, we've mentioned that we intend to go forward and finance our CNR acquisition with approximately 50% debt, 50% equity.

We've also thought, or at least discussed, broadly that part of that would probably be a convertible preferred.

So all you're reading into that is our estimates for share count increasing as a result of the need to finance those acquisitions.

Okay.

Fair enough.

....with that acquisition I should say.

Thank you.

Any other questions there?

Now we'll hear from Joe Allman with RBC Capital Markets.

Good morning, everybody.

Hi Joe.

Aubrey or Tom, in the Fayetteville Shale, can you comment on the science that you guys have done that makes you think that the eastern portion of that play is going to work as well as what -- where most of the activity has been kind of on the central or western side?

David, I don't think we are to that point yet.

I will tell you that we consider our results from the first well to be inconclusive, and so we will continue our drilling program.

But at this point, we regard all science conducted on that well and results of it will be confidential.

Okay.

And what about just logs kind of in the areas where you've been buying acreage, any or any two D (ph) or anything like that?

Can you comment on that?

I can comment that we consider all of that information confidential.

Okay.

Got you.

I appreciate it.

Thanks.

Thank you.

(Operator Instructions)

And now we'll move on to Daniel Morrison with Aperion Group.

Hi.

Quick question.

You've always been-- very successfully cast yourself as more offensive hedgers than defensive hedgers when it comes to commodities.

In light of, kind of, the significant charges this quarter, is there anything you can say about your playbook change in it, or just kind of expand on your current philosophy that goes behind that?

It remains unchanged and actually what you saw this quarter was a -- as a result of playing offensive in the past-- and remember when we play offense in the past, most of our hedging was conducted in association with making acquisitions.

So year from now, if we have this conversation and we look and we left some money on the table with regard to the gas that we hedged for CNR at an average of 11...

1067.

No, for 2006.

We hedged...

1155.

...90% of the production of CNR at 1155.

And if it means that in 2006, gas prices average 13, 14 or 15, that won't much matter to us because we will have been able to take advantage of an 1155 strip in 2006 to buy something that we valued at $7 or so.

So I think that the ability to hedge something $5 above where you bought it is a pretty remarkable commentary on the markets.

And in our view, that's playing offense.

And if every once in a while it means that we forego some revenue, that's okay, because that foregone revenue is what enabled us to not have to forego the opportunity to book-- to buy many, many assets at a very attractive price.

So the way we see it, it's a trade-off as occasionally you leave money on the table in exchange for which you have a much larger resource base that's unhedged down the road and getting paid for a lot more quickly than otherwise would have been possible for the hedging program.

Very well put.

Okay.

Thank you.

And now we'll hear from Andrew Coleman with Friedman Billings and Ramsey.

Hi, guys.

I believe my question was already answered a couple minutes ago.

Thank you, Andrew.

We'll take our next question from Eric Kalamaras with Wachovia.

Hi.

Good morning.

The question regarding the course of acquisitions, and particularly related to sea corps (ph).

The thought process was just because traditionally being hopes on the private assets and then the rock.

Is that attitude changed with the pullback in equities?

And so some of your competitors, particularly much smaller competitors, being pretty significantly discount the reserves in the ground.

When you say sea corps, are you referring to public companies or you referring to occasionally, we in debt tax basis step up issues related to sea corps?

Particularly on the public side.

Okay.

You've seen us in the past make acquisitions of some small, public companies.

Of course today, smaller public companies are bigger, and I suppose we are, as well.

But that's not traditionally where we have seen most of the value in the acquisitions market.

It's been through asset transactions and also through private companies, primarily companies sponsored by private equity players and CNR, of course, would be the latest example of that.

So I don't think much has changed.

We benchmarked ourselves against all companies in the sector.

We look at all companies both larger and smaller than ourselves and always looking for the opportunity to identify value perhaps before other people can.

But to date, most of those efforts have led us to acquisitions of asset packages or private companies.

Good.

Thanks.

And then additionally, I am curious about the differentials for nine max (ph) in natural gas.

It was down a fair bit more than what I was expecting.

Any color you can give me there?

The differential was higher than what you had expected or less high than you expected?

It was it was less than I expected it would be.

You might be about the only guy.

I mean, I'll say that probably the result of it is our basis hedging.

We started to think about this problem four years ago as we identified the Rocky Mountains as an area that was likely to be persistently long gas and short gas pipeline take away capacity and we felt the more logical play and then proceeding in the mid-continent, we recognize that has being short gas and long pipeline.

So felt like some people with our choice that to building some pipes to the mid-continent that happened in that possibly responsible for mid-continent basis being lighter than it has been historically.

Obviously the blowout overall in gas prices has led to higher basis differentials everywhere just on a percentage basis.

That leads to a bigger differential.

How much of a pick-up did you get from the basis hedge?

Yes.

Let me-let Marc.

Eric, if you got a page 18 of our press release, it shows the remaining basis volumes and the amounts starting with the fourth quarter of '05 and then all the way through the year 2009.

I don't remember exactly how much we would have had in the third quarter, but it would have been approximately the same as in the fourth quarter.

So you see 50 bcf there hedged at only $0.27 basis differentials.

That's going to be probably against an average basis differential, Mike, that would have been $1.50 or so for the whole third quarter.

So we're picking up quite a bit there and that does adjust the basis spread that you see these hedges go directly into that calculation.

As Aubrey mentioned, we started in 2002 looking at this and we began hedging for volumes in January of '03.

This has been tremendously successful hedge for us.

At one time, we had almost 900 bcf on.

Today, we've calculated about $300 million of gain, and our remaining 511 bcf that we have on at an average price of $0.29 is somewhere in the neighborhood of $250 million of future value.

So it will continue to benefit us to the extent basis will stay wide, which we anticipate that it will stay wide.

So we're looking for additional opportunities to hedge that basis, but right now most people now think the way that we did back in 2002.

So the market, on a forward basis, is pretty wise.

Okay.

Great.

And then additionally there is one other one-- the sequential oil production was down relative to the second quarter.

Can you just comment on that?

We don't emphasize oil production very much and we have seen that occasionally.

Oil production was down 4%, something like that.

So just right now, we are focused on gas, gas, gas, and it's not something that we've projected I think flat going forward.

So that's pretty much I think the way that you should think about it, as well.

Okay.

Right.

Thanks, guys.

Thank you.

And now we'll take a question from Ken Carroll with Johnson Rice.

Hi, guys.

How are you during this morning?

Good Ken.

Refresh my memory real quick on CNR, in terms of their drilling up in Appalachia.

Had they been drilling to the shale and testing any horizontal wells up there yet?

Well, their drilling a lot of their wells-- most of their wells-- to the Devonian Shale.

I don't believe they have made it a practice to penetrate the entire Devonian Shale section, and they have not drilled any horizontal wells to my knowledge.

I think there's only been three horizontal wells drilled in the whole basin, and they were the result of some DOE projects back in the early 1980's I believe, so...Tom, you want to add anything to that?

I think they did drill one horizontal well at one point.

But it's been a few years ago.

And the Devonian Shale also has some sand stringers and it that doesn't really lend itself to horizontal drilling at this time because you have a large section of shale that you need to open.

We might be able to work some science on that to see if there is any particular areas that we would like to go horizontal in.

But right now, our program will be vertical, Devonian Shale for this year.

Got you.

Thanks.

And I would love to hear Marc and Aubrey, your macro comments on gas.

Obviously, we know you're bullish.

But the near-term pullback here we have seen in pricing the store situation.

What are you guys looking at heading into winter?

I think it's going to be down today.

No, I think we are in a really interesting time where the market is trying to figure out what price it takes to account to remove enough demand to account for five bcf a day, more or less, of removed supply.

And when you have a record warm October, and it looks like November might be pretty warm as well, we are finding out that in this time, it doesn't take $13 or $14 gas to clear the market.

I think what's unknowable, of course, is what's the right price for January, February, and March, when it'll be a little colder and you will be consuming more gas everyday than you are producing, and you'll still be short some number of bcf.

So we have always been on record saying we like gas price volatility.

A lot of consumers have come out lately and said they do not like volatility.

I would ask them to reconsider that over the last three days.

Certainly has given consumers the opportunity to buy some gas at what may in time appear to be a very attractive price.

And I think we are just dealing with the great unknown, which is how quickly does the gas supply come back on and what kind of a winter do we have, and what price or how much demand do we actually make go away for every bcf a day that's off or for probably for every dollar change in gas prices.

It's unknowable right now.

But, it's one of the reasons we hedge is because it's not knowable.

And we've been relatively aggressive over the past months taking advantage of some higher prices, while at the same time recognizing that if November had been colder rather than warmer, than we wanted to actually drive powder.

Looking forward in 2006, the first quarter is hedged at 54% at almost $10 an mcf.

I think that's a pretty good trade-off between being hedged too low and leaving an enormous amount of money on the table.

At the same time, I think that it also shows of acting opportunistically and grabbing some high prices as they come by.

So I like the fact that we are 42% hedged at 863 and-- for 2006.

And in my view, that isn't too far away maybe from where fair value is for a strip at that knowing what we know today.

But it's all a weather-bet.

And as to next year, kind of depends on hurricanes and hot summer and what kind of winter you have.

All I know is we are going to do real well over the next few quarters with the lock-in prices that we have.

Got you.

Appreciate that.

Thanks.

Okay.

Thanks.

And now we will now hear from John Zaehringer with Loomis Sayles.

Yes.

An interesting switch that Marc was discussing in his comments in terms of swapping fixed for floating debt.

Is this - what's your macro thinking in making this change and are you going to say, devote a like percentage of the financing of the CNR deal in similar sorts of transactions swapping fixed for floating or perhaps just borrowing floating?

John, good question.

There is really no shift in our view.

We have been 0% swapped on our long-term debt from fixed-to-floating to perhaps as much 35%.

Today we are at 29%, so at the upper end of that range.

Simply, our view is that the shape of the forward curve on interest rates has given us an opportunity, we believe, to swap into floating at attractive levels and reduce our interest costs.

The studies we have done have shown historically to the extent of about 99 that the forward curve overstates what happens in the interest rates.

And the currently the push for the Fed to increase these rates has caused the expectation of the curve to change in shape.

And so we've swapped to what we think are attractive rates.

I do not, on the second question, believe that we'll be using any floating rate debt specifically to finance any of the CNR.

Our expectations are there that the long term curve at around 7% and perhaps some convertible notes with the chance to pick up much lower rates, all can be blended to have a very low capital cost.

And that weighted cost of capital being low and being fixed, along with our hedging program, really makes the transaction of CNR particularly, but just generally, our acquisitions very accretive to all of the holders of our securities.

But I guess, at some point in time, you might seem the same kind of forward curve develop and you might decide to swap some of the debt you're going to be issuing shortly.

That's possible.

Although again, we're probably -- you are not going to see us, I don't think, swapping more than 30% to 35% at any one time.

And mostly, we have been at very low levels.

It's been in a narrow trading range that has allowed us to put some on and off and capture some pretty good cash gains on this stuff, while minimizing our interest costs.

And that's really a program that has been in place now for a few years actually, and perhaps now the amounts are more noticeable because we have got a lot more long-term debt.

But we've got great counterparties and we are able to arrange our credits such a way that we've got open lines of credit on those swaps.

And it's been a very attractive program for us.

And there are no, I guess, apparent transaction costs involved in these deals.

They are outweighed by all the-by the gains that you are able to book.

Well, there are no transaction costs in the sense that when we go to a credit counterparty -- or to a counterparty to execute one of these-- they are "in bed" (ph) skinny of the gain that they are able to pick up.

So, we don't pay a fee in the terms of writing a check.

We pay a fee in the terms of a 0.5 basis point or something like that that gets deducted from the quote that they give us.

And so, there is no tax implication and there are no fee implications.

And so, that has made it an attractive proposition for us.

What is does it take to unwind one of these things?

Do you just do it?

A telephone call and...

Okay.

...about 30 seconds.

Okay.

So, it's very simple and very cheap?

Yes, sir.

Okay, thank you.

Thank you.

And now, we will hear from Robert Christensen with Buckingham Research Group.

Yes.

On the Fayetteville Shale, any horizontal wells planned out of the six this year?

Did you say out of the six, Robert?

Yes, you're going to do six, you said.

I was just wondering if any would be horizontal.

No, all six will be vertical.

Okay.

So, it's all kind of exploration.

Okay.

Thank you.

You're welcome.

Thank you.

(Operator Instructions) Now we'll take our next question from Tom Nowak with Merrill Lynch.

Hi.

Good morning.

If I recall, CNR had a large underwater hedge position.

And I'm just wondering about the delta between the new 1067 hedges in the pre-existing hedges and how that's going to be treated on the cash flow statement.

I believe there was some discussion in the last call...

Right.

... that that would be run through CFI.

Is that still the thinking?

Tom, we have arranged to keep the hedging that they had previously done in place with the existing bank group that CNR has in place today that we'll, I guess, inherit, if you will, when we close the transaction.

We did spend quite a bit of time talking about how the accounting for this will work and I won't bore everyone with a lot more detail.

But generally speaking, the day that we close, the hedges will be mark-to-market at that moment, and that will become part of our acquisition costs by booking a deferred revenue or deferred liability.

In essence, we are then resetting the hedges that they had for financial purposes to that new level.

And if they hedged it just under $5 and the market value for that hedge is 11.50 for 2006, then 11.50 becomes the new mark-to-market.

And from that point forward in our revenue statement, we will have an $11.50 revenue item that will be adjusted up and down only by the mark-to-markets.

But when its cash settled, then we will owe cash to the counterparty for any difference.

That will be in the financing activities section because it will have been booked as a liability at the time of acquisition.

So sorry for such a convoluted explanation, and it's pretty difficult sometimes to get your arms around.

But we wanted to assure ourselves that those mark-to-market numbers, we were going to be able to actually realize those and that's why we have layered these incremental hedges on.

You can think of it as incremental hedges for this transaction or part of our overall gas, however you choose to think about it.

But from a book standpoint, the mark-to-market will be the pricing that we will start from rather than what they hedged from.

Another way of thinking about it is had we just wanted to pay the hedges off and go borrow the money from the bank, that's equivalent to what we're doing.

Now I understand.

Tom, I might also mention that there is no greater cheerleaders for falling gas prices today than us because we're going to -- help us in terms of how we book this transaction, the mark-to-market will be much smaller.

So in terms of the future costs and the impacts upon our depreciation rate will be less for the lower gas prices go between here and closing.

Okay.

Great.

Thank you for reviewing that one.

Thanks.

Moving on to Geert Dhont with ING.

My question has been answered.

Thank you very much.

Thank you.

And we have time for one more question.

That question will come from Van Levy (ph) with DR & Company.

Good morning, gentlemen.

How are you?

Great, Van.

Good.

Couple of questions.

How big do you plan to get Appalachia hovering?

Let me try your second one out first?

What's the...

I was saying -- as part of that I would ask, the Belden & Blake transaction obviously happen to (inaudible), kind of the genesis of my question is can you operate as efficiently in when they -- what seem to be kind of mom-and-pop area, much smaller reserves per well, etceteras, much more intensity I would think?

And are there other people or other companies, for instance something like that, the Belden & Blake property to lay in, and again, what are your designs on the basin?

I think it will be pretty close to what we've done everywhere else, and that when we move into an area, generally it's through an acquisition.

We have to expand our infrastructure both here and there to support that.

We have to make sure we understand what we're doing as fully as others in the basin do, and as well as we understand some other areas.

So we typically go pretty slow in an area to begin with.

And then as we gain that information and experience some confidence, we go forward from there.

So we have 3.5 million acres that we are acquiring through this transaction.

Their geoscience staff is pretty small.

Their engineering staff is relatively small we think for that amount of acreage in their land stature as well.

So we've got some work to do internally there to get geared up before we really spend a lot of time thinking about further consolidations.

You are right in that I don't want to refer to them as mom-and-pop, but smaller private companies are certainly the heart and soul of that basin.

That was true in many parts of Oklahoma when we consolidated here as well.

So I think down the road, there are many opportunities for additional consolidation opportunities.

But I would guess we've got a lot of work to do to get geared up for that with what we've just bought rather than expand that footprint very dramatically at this point.

Okay.

Another big picture question for you, Aubrey.

How much can you -- I'm sure you're asked this quite a bit.

But your enterprise is certainly-in 7ts (ph) -- is a very big company now.

How much more can you grow this company, particularly at the rapid clip you you're growing?

Number one, how can you keep your controls and not stress your system?

At some point it just seems like there are so many moving parts, it's hard to maintain that.

And the last part of that is, what is your end game and when does that happen?

Does that happen in three to five years or you think can you continue this kind of consolidation growth process for 10 years or so?

Well, I don't really think we have an end game because I think when you manage for an end game, you miss opportunities along the way.

So we don't have a 5-year plan, we don't have a 10-year plan.

In my view, if you have one, you end up being more devoted to whatever result you thought was going to occur in 5 or 10 years rather than the opportunity set that presents itself every day.

So I think one of the things that Tom and I and Marc and other members of the management team feel like we've done as well as anybody else is adjust on the fly to the very dramatically different macro industry conditions that we've seen evolve over the last six or seven years.

I'd like to give ourselves some credit for being earlier than most and recognizing that those changes were likely to occur.

But they occurred at a pace and with a scale probably greater than what we envisioned.

But we've been able to adjust along the way.

In terms of managing an enterprise that is quite a bit larger today than it was five years ago, it's certainly a challenge.

We certainly have always worked hard.

We don't -- the company is five times bigger than it was five years ago.

Tom and I don't work five times as hard.

Seems like it sometimes, but so we've been able to build a very strong management team that's grown the company alongside us, and then also some additional layers of middle management, as well.

Some things that make it easier than what you might think is that we run a very centralized company.

Every - all geologists, engineers, land men are here in Oklahoma City.

We have one accounting shop.

We have one information technology shop.

They are all here.

And so it's just easier to do that than run far-flung district offices.

Our asset focus is also-- our geographical focus, that is-- is rather modest, only in the southwestern part of the US, and only recently in Appalachia.

I cannot imagine how some of my peers run companies that span the globe.

And we have no aspirations for anything like that.

So, I think by keeping our aspirations modest and keeping our goals simple and keeping our strategy simple, even people like us are capable of managing the growth that we have created over the last few years and going forward.

I would imagine that we will continue to take advantage of opportunities as they present themselves and continue to grow through a combination of the drill bit and through acquisitions.

Okay.

One last thing.

The drilling business, you have contracted to buy some rigs, is that right?

Yes sir, we have.

So we have hedged our drilling costs several ways.

We have 15 operated rigs today under our wholly-owned subsidiary.

We have another 25 rigs on order that will be here through December of 2006, I believe.

And then of course we have our 17% interest in Pioneer and to 45% to 50% interest in two newly formed drilling companies that are active today.

And again, as to just in a sense of controlling the business, how far do you plan to go on the drilling side?

Do you think this could be 50% of your wells or...?

I think there's three aspects to it, Van.

I mean, first it's inflation hedge, and we saw that pretty early.

I think there have been two advantages that have become apparent over the past couple of years that I, for one, didn't anticipate when we started down this road.

The first is the operational flexibility gives us as we move into new areas and new plays and we have the rigs that we can shift around-- and they are obviously a lot easier to shift around if you own them rather than they're owned by somebody else and you have them out of contract -- under contract.

And the third advantage is in acquisitions.

Today most of the things that you see us buy are assets, where we believe we are buying the opportunity to create an incline curve rather than a decline curve.

And the only way you can do that is through the ability to accelerate rapidly the amount of drilling that you do on those properties.

Most other companies today do not own their own rigs and do not have the ability to show up at a drilling company and say, I want five more rigs and I want them tomorrow.

I mean, we are moving rapidly towards having that kind of flexibility.

So going forward, your question, 50% is probably what we've talked about internally as being the ceiling.

As we move from 75 rigs to numbers higher than that, our projections right now are getting closer to 40%.

So I'd be surprised if we go above 50%.

But the advantages of owning those rigs are what I've mentioned threefold.

Let me give you one example of a financial benefit.

We can go build a rig today to drill out in Sahara for, Tom, how much? $6 million, 7 million -- $6 million to go drill 7,000 of wells out there that on a present value basis, Marc, create how much.....?

Its - at last strip I looked at, it was $1.3 million after cost.

Present value (inaudible)

Okay.

So we go build a rig where, on a cash basis, it pays out in three years, and then we can drill basically 25 to 30 wells per year with that new rig, thereby creating $32 million to $45 million of value through drilling wells that we otherwise wouldn't be able to drill if we didn't have that rig.

So some people focus on it as just spending $6 million to build a rig rather than go drill wells, aren't your returns better by drilling wells rather than building rigs?

And the answer to that is it's true.

It is so, and that's exactly the reason why we build rigs.

So we go capture that value by drilling wells that we otherwise wouldn't be able to drill.

That seems very smart.

And then how do you account-final, final question here- maybe this is to Marc.

How do you account in terms of finding costs?

Do you -- I guess if you have cheaper rigs, you could transfer this to your finding cost.

You should have a finding cost advantage.

Well, that's the way its accounted for is this other equipment is depreciated.

The depreciation and the operating cost -- the actual cost operating costs-- goes into our full cost pool, and so to the extent that those two items are less than the operating rate by leasing from a subcontractor, there is some small advantage in terms of finding costs.

I haven't tried to quantify that, it's probably less than nickel of DD&A cost difference over the two or three years that we've owned these rigs.

Operationally, Van, it really helps us to have the different types of rigs we're building account can move to different plays.

A Sahara rig that we build can, if we decided not to have that rig in Sahara, we could move it to East Texas.

The rigs we'll build to drill in the Barnett could also go to the Fayetteville.

So as we have all this acreage we've bought at different parts of the country, you could use a Haley rig to either drill on Haley or we could actually moved it to western Oklahoma.

It gives us just a lot more flexibility.

No.

It seems very smart, very smart.

And again, last question in terms of guidance.

This year, you talked about the drill bit planning cost by 42 acquisitions by 57.

Your DD&A rate is $2 plus I guess looking forward.

Marc, could you explain that to me, please?

Well, the DD&A rate going forward is simply a function of what we think that the CNR acquisition will add in terms of all-in (ph) costs, which of course, you have to include to prove the undeveloped costs that you're booking.

Each time costs go up in the field, we reestimate the future development costs of all of our properties.

And as you don't have any additional reserves necessarily, if everything else is the same, your DD&A rate is going to go up.

So we've done our best jobs trying to estimate all of the various components of future development costs.

That's through leasehold acquisitions transfers from the under-evaluate -- evaluated as tax basis step-up.

There is a lot of different items, including future development costs, that go in that are different than just what you might see on drilling.

I might also mention, Van, on page three, we talk about our reserve replacements at a drilling and acquisition cost of $1.47.

We also tell you in the next paragraph that if you look at that on an all-in basis, it's really $2.23, and that includes all the capitalized costs, seismic leasehold, and ....

Acreage and stuff, yes

Yes.

Tax basis step-up is not insignificant.

Got you.

And that's a number that lot of people throw in goodwill.

And I would tell that if you go look at our balance sheet and look at our acquisitions, and if you were to go strip out $1 billion or $2 billion of that and throw it into goodwill, our DD&A rate going forward would be significantly different.

We have just chosen not to employ that accounting technique in booking acquisitions.

Great.

Okay, guys.

Thanks very much.

Okay.

Thank you and I appreciated it.

And we once again, appreciate everybody for joining our call today.

And if you have any additional questions, please give us a call.

Thank you.

There will be a rebroadcast of this conference available today at 11:00 a.m.

Central time running through November 14, 2005, at midnight Central time.

To access this, simply dial 719-457-0820.

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That does conclude today's conference.

Thank you for your participation.