Chesapeake Energy Corp (CHK) 2003 Q3 法說會逐字稿

Good day and welcome to this Chesapeake Energy third quarter 2003 earnings release conference call.

Today's call is being recorded.

Our speakers today will be Aubrey McClendon, Chesapeake's Chairman and Chief Executive Officer, and Marcus Rowland, Executive Vice President and Chief Financial Officer and Tom Price Jr., SVP, Investor Relations.

Good morning and thank you for joining Chesapeake's 2003 earnings conference call.

Before I turn the call over to Aubrey and Mark, I need to provide you with this disclosure that Chesapeake will make during this conference 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 S.E.C. filings.

Our prepared comments should last about 15 minutes, and then we'll provide 45 minutes for questions and answers.

Aubrey?

Thanks, Tom.

Good morning and happy Halloween to all of you.

As I hope you've seep from our earnings release, once again our company has reported excellent results both operationally and financially.

Our net income was $82 million.

Operating cash flow was $248 million.

And EBITDA was $285 million.

All of these were records for our company.

These strong financial results were driven by an equally strong operational performance.

Oil and gas production reached the record level of 71.0 bcfe, which was our ninth consecutive quarter of record production.

Our daily production was 692 million cubic feet of gas and 13,220 barrels of oil and natural gas liquids, for a gas equivalent production rate of 772 million cubic feet of gas equivalent per day.

This quarter's production was up 52% from the year-ago third quarter, and 5.4% sequentially from the second quarter of 2003.

One-third of our sequential production increase came from drill bit growth and two-thirds came from acquisitions.

Therefore, our annualized organic growth rate this quarter was approximately 8%, which is about double what we project as our core organic growth rate.

The major reason for our higher than expected organic growth rate is the ongoing exceptional performance of our exploratory drilling programs.

We believe these are a testtament to the my caliber of our explorations and to the high quality and land and 3D seismic inventories both of which continue to grow during the quarter.

In fact during the quarter we invested another $42 million in undeveloped leasehold and three dimensional seismic, raising our total capital invested during the past two years on these two important investment categories to $200 million.

Investments in undeveloped land and seismic are the building blocks for the future of an oil and gas company, and our willingness to make these substantial vests investments is a key reason why we have been able to keep growing through the drill bit, even though we are a 50% bigger company than just one year ago.

In addition we recently opened our new GS sciences building in our main campus in Oklahoma City, that contains a state of the art, 3-D visualization room, the only one in, I might add, in the entire state of Oklahoma.

Our ongoing commitment to excellence, is a key distinguishing feature of our company and is the primary reason why we believe Chesapeake can continue delivering strong organic growth rates at very attractive finding costs.

Because of this quarter’s especially strong operational performance, for the fourth time this year we have needed to increase the company's 2003 production forecast.

For the 2003 fourth quarter we are now projecting production in a range of 74 to 74.5 bcfe, and for the full year 2003 we are now projecting production of 269 to 270 bcfe.

We have also increased our 2004 production forecast to 297 to 303 bcfe, which represents a projected 11% increase in production in 2004 versus 2003.

In addition, our estimated proved reserves as of September 30th have reached the record levels of 3.0 tcfe, up 800 bcfe in 2003 to date--an increase of 36% so far this year.

Reserve replacement to date this year has been a very impressive 500%.

None of these numbers include the approximately 100 bcfe approved reserved we acquired in the Laredo transaction.

I would next like to highlight to highlight two other achievements this quarter.

The first is continuing cost control in an industry where cots control is becoming ever more difficult.

Hopefully you notice that Chesapeake's lease operating expenses of 51 cents per mcfe, and our G&A costs of 8 cents per mcfe remain among the very lowest in the industry.

In addition our interest expense continues it downward trends as the company's increases have far outweighed any leverage increases during the past few years.

And finally our DD&A rate increased 1% since the 2003 second quarter, again reflecting our ability to economically explore for and acquire new reserves of natural gas.

While we are please Wednesday our record of building and maintaining one of the industry's best cost structures we are especially proud of what we have been able to accomplish by enhancing our revenue line.

Make no mistake we definitely want to continue grinding our cost down to their lowest possible number.

However that exercise is measured in just pennies per mcfe, where the biggest money is made these days is on the top line.

We believe this is a development many investors may have missed.

Because of the extreme volatility in today's gas prices we believe management of revenues is equally important to management of cost.

Again, please don't misunderstand we have and will continue to have one of the very best cost structures in the industry, that is and will remain a key element of our business strategy.

However, the best performers in this industry during the next few years are likely going to be companies that can be price makers rather than price takers.

As such a price maker since 2001, we have enhanced Chesapeake top line by $125 million through astute hedging decisions, and we are currently up another $130 million on our open hedges.

As for those open hedges we hope you have noticed that for the 2003 fourth quarter, we have locked in 100% of our oil productions at a NYMEX plies of $28.69 per barrel and 83% of our gas production at a NYMEX price of $5.64 per MCF.

On a gas equivalent basis, we have hedged 85% of our 2003 fourth quarter production of $5.56 per Mcfe.

If December gas price end up closing at $4.50 per MCF or so, Chesapeake's hedging gains for the fourth quarter should exceed $70 million.

For 2004, we have hedged 94% of our projected oil production at a NYMEX price of $28.61 per barrel, and 51% of our projected gas production at a NYMEX price of $5.28 per MCF.

On a gas equivalent basis we have locked in 54% of our projected 2004 approximate at a NYMEX price of $5.23 per Mcfe.

We believe that most cell site analysts are using a 2004 gas price forecast of somewhere in the range of a NYMEX price of $3.75 to $4.25 per MCF.

If we picked $4.00 as the consensus forecast in the middle of that range, then Chesapeake's 2004 hedges should create more than $175 million of additional cash flow or about 80 cents per common share.

If invested wisely, that would represent a 7% increase in net asset value next year, just through our existing hedge positions.

The trick, though, is not just to hedge, but to hedge high prices.

We believe our track record in this area is among the very best in the industry, and is a key reason which Chesapeake stock has been a leading performer during the past few years.

It is also a reason why Tom Ward and I have invested more than $25 million in purchasing Chesapeake common stock in the open markets during the past year.

We believe Chesapeake represents great value today and even better in the years ahead.

Finally, he we're excited about today's announced acquisition of $200 million of South Texas gas properties.

Some you may have wondered if we have strayed off message in making this acquisition.

I would answer by saying maybe yes from a purely geographical perspective, but definitely no from a gas perspective or from an operating expertise person expectative.

First of all, while we absolutely will continue focusing on the Mid-Continent it is not the only area where we believe our understanding of deep gas reserves can create value.

For example, in the third quarter, about 11% of our production came from areas outside the Mid-Continent--mainly from the Permian Basin and onshore Gulf coast areas, including South Texas.

Pro forma Laredo 14% will come from outside mid continent.

We plan to keep that range inside 10% to 20% in the near future.

We will definitely remain active in these areas where we believe we can generate returns that are competitive with our Mid-Continent returns.

In South Texas specifically we have been building strong teams during the past few years and we now feel comfortable in operating in the environment of this area.

In addition, we see other similarities to the Mid-Continent--tough land issues, fragmented ownership base, pipe line infrastructure, high operating margins, complicated l geology, good weather and underexplored deep potential.

Furthermore, I would like to emphasize that we have locked in excellent returns from the Laredo acquisition by hedging 100% of the first 14 months of production of this acquisition at the very attractive NYMEX gas equivalent price of $5.28 per Mcfe.

Being able to hedge five dollar plus gas is especially helpful, because Chesapeake is not a strip price bidder.

We bid on acquisitions using price decks with a 4 in them.

Finally, some you have called us after yesterday's release wanting a bit more info on the numbers behind the Laredo acquisition so here goes.

For $200 million we purchased 30 million per day in [current production.] Within one year, we believe we will have increased this number by at least 50% and in the outyears there is still further growth potential.

As for reserves, we have acquired 196 bcfe of reserves, 108 of which are proven, and 88 are unproven.

By comparison, the sellers third the party reserve report contain 275 bcfe, or 50% more than our own.

That reserve report conservatism is pretty normal for us in the acquisitions we make.

I will admit however, that there is one aspect that is a little different from us.

The Laredo proven reserves are only one-third developed and two-thirds pud.

Normally, what we by 75% to 80% [pru] developed and only 20% to 25% pud.

This property is just different.

It is much more immature than a typical Mid-Continent acquisition, and it also has lower operating cost which means every Mcfe worth more than a typical Mid-Continent Mcfe.

Does this property's immaturity make it more risky than others we have completed this year?

Sure, but it provides more upside through the drill bit, in this case a lot more upside, and in this case an excellent tradeoff we believe.

One more question asked was how did we arrive at the $48 million allocation for the [nonproven] assets?

For competitive purposes, I cannot provide you with our exact allocation methodology.

But I can tell you that we simply use a longstanding proprietary model that allocates certain value to probable and possible reserves and to exploratory acreage and (inaudible).

The allocation to such assets normally runs 10% to 20% of an acquisition's value, in this case it is 25%, again reflecting the different nature of these assets.

One final reserve classification observation for you.

Of the 12 largest independent oil and gas producers in the U.S., Chesapeake carries the second lowest percentage of puds in our reserve report.

Only 26%, for those of you with inquiring minds, Oxy is the lowest, PUD and Devon is the highest at 46% pud.

On average, the 11 of the others have an average pud inventory of 35%.

If we were to increase Chesapeake's pud reserves to the average percentage carried by our peers, then our reserve would reflect 3.4 tcfe in pru reserves, rather than the 3.0 tcfe that we carry today.

That extra 400 bcfe would easily be worth an additional $2.00 to $3.00 dollars per share in increased NAV.

You might be wondering why don't we go ahead and get with the program and increase the pud to the industry averages average.

Five years ago, we simply decided that the new Chesapeake would need to be a lot more conservative than the old Chesapeake and so we settled on maintaining a conservative 3 to 1 ratio between proved developed and pud reserves.

While we have stayed with this ratio over time the industry has continued to slip down into a much more aggressive ratio, reflecting, we reckon, rapidly decreasing depletion rates.

I hope this foregoing analysis helps demonstrate that Laredo with its higher than normal pud content is quite easily digested by Chesapeake, and in our view, will have outstanding reserves in years to come.

With regards to elsewhere in the company I can say we remain very pleased with the ongoing results of our developmental and exploratory drilling rates programs and believe our numbers speak for themselves.

With all of our programs generating excellent results and with more than half of our 2004 production locked in at the terrific price of $5.23 per Mcfe, we expect to maintain our present range of around 45 operated drilling rigs through the remainder of 2003, and throughout 2004.

We also are participating in about 50 wells being drilled by other companies.

This activity level assumes that service costs remain reasonable, which they show every indication of doing.

This completes my assessment of the quarter and I will now turn the call over to Mark.

Thanks Aubrey and good morning to everyone.

We'll promise only treats and no tricks today for this Halloween call.

As is our usual custom I won't be repeating numbers already presented in our release and outlook, but will try to provide some color on trends in our business and some lesser details not included in any release.

I'd like to start by adding on to something we touched on in our last quarter, which is a series of note exchanges that we've done--improving the maturity profile of our unsecured notes.

To date, we have exchanged $40 million of our 8 and 3/8 due in 2008, $72 million of our 8 and 1/8 s due 2011, and $32 million of our 8 and ½ s due 2012--a total of $144 million, exchanging them into a combination of notes due in 2013 and 2015, specifically $64 million of the 7 and ½ notes due 2013, and $86 million of our 7 and ¾ notes due 2015.

Those issuances also included payment of all accrued interest on the notes we exchanged.

I'd like to review our maturity schedule now.

We have only $42 million due in the short term.

That's due in 2004; $210 million due now in 2008; $729 million due in 2011; $111 million due 2012; $300 million due 2012, also; and then $363 million now due 2013, and $237 million, 2015.

I know that's a lot of detail but I've been asked some questions on that recently.

Of course it will be included in our 10-K to be released in the next ten days or so.

I would also remind you that of our notes scheduled, $111 million of our 8.5 notes are due in 2012, but callable in March of 2004 at 104 and a quarter, giving extensive use of our substantial excess operating cash flow.

As of September 30th our debt to book cap has decreased to 56% down from 58% in the previous quarter.

Our projections remain that we will be at least 50/50 equity to book capital during 2004, just through the normal course of executing our business plan.

Let's turn to capitalized costs for a second.

Capitalized interest during the quarter was $3.4 million bringing the total capitalized interest during the first 9 months of the year to $8.8 million.

I don't see any change in the trends there.

As our unevaluated leasehold remains relatively low for the size of our company, at $175 million, and it's been pretty stable over the last several quarters.

It will increase obviously some for the allocation in our recent acquisition to close to date with Laredo.

Other capitalized internal cause being G&G and personnel directed towards our drilling programs was $9.9 million this quarter, 9 months total $25.7 million.

As of September 30th, and not including the Laredo acquisition, our proved reserves as Aubrey pointed out now exceed 3 trillion cubic feet equivalent, for the first time in the company's history.

These internally evaluated in interim numbers show 74% [proved] developed, 26% undeveloped, with 90% being natural gas.

All finding cost this quarter remain stable with an estimated $1.61 per MCF all in FD &A cost year to date.

This year $1.56 with acquisitions added at a low $1.18.

Our present value of the reserve position as of the end of the quarter, off of a base gas price of $4.67 was $514 billion, each 10 cent change in gas prices we see adding or subtracting 5 BCF equivalent approximately and about $138 million in a delta PV 10.

These estimates are good for a price range of about 50 cents.

Talk briefly about cost trends.

Cost trends this quarter were flat in almost every area, to slightly down in some service cost.

Our view is that the current quarter being the fourth quarter that we're in and even into the first quarter of next year, cost will remain basically stable to slightly down.

Review our capital expenditures for the quarter.

We spent $143 million on drilling expenditures, $5 million on our capitalized workover program.

I digress for a second and say that constituted 314 separate optimization projects, and the optimization program that we have ongoing now has become a significant part of our cost control and reserve enhancement program.

During the quarter we spent $42 million on acreage and seismic, a little bit higher on acreage particularly than our normal run rate, given the developments in our mountain front play.

We had total capitalized internal cost net of all reimbursement and adjustments of $13 million.

Acquisitions were $46 million, primarily being the property acquired from Exxon out in Beckham counting including gathering and processing systems.

Few miscellaneous points, and we'll move into question and answer questions and answers.

Our debt balance is approximate approximately $95 million.

Our booked tax rate remains predominantly deferred, although we had a very small $300,000 alternative minimum tax for the first nine months that we paid during the quarter.

We project this trend to continue, meaning that small alternative tax payments may be due in the next couple of years, but we project no regular tax, and at the current drilling pace with our net operating losses, expect no regular tax cash payments through 2005.

On the hedging front, from a trend standpoint, we see plenty of counterparty interest and credit liquidity.

As noted, recently we were able to execute nearly 100 BCF equivalent of volume at the market without disruption within just a few trading days.

Our current gas hedging positions, including the basis swaps, today are in the money by over $130 million and we have more financial counterparties making credit and volume available to us today than ever before.

With that we'll turn to a question-and-answer session, monitor, please.

Thank you. (Operator’s instructions) We'll take our first question from Mark Meyer with Simmons and Company.

Good morning gentlemen.

Hi Mark.

Unrelated questions about Laredo.

Aubrey, could you talk a little bit about the pud backlog and perhaps some of the drilling inventory related to the acreage (inaudible)?

Certainly I can, Mark.

We've found out of 108 bcfe, roughly two-thirds of that or roughly 70 bcfe is pud.

We close on the transaction today.

And we'll have rigs out there very shortly.

Tom, I'll let you --

1st of November which is tomorrow we're set up to start drilling the first location the first part of November and go with a two-rig schedule at the first of the year and have kind of a three-year drilling schedule for the property.

And that would be just for the puds.

We hope to be active on probables for many years thereafter.

Second question, you mentioned 275 bs was Laredo's number, and you guys have haircut that obviously.

What was the equivalent prued number that Laredo had?

Mark, I don't have that with me.

And it wasn't Laredo's I mean it was Laredo's but it was a third party engineering report and we'll have to get back with you on that.

Okay, thank you.

And we'll take our next question from Jess Mobley with Raymond James.

Good morning, gentlemen, great quarter as usual.

Thank you.

Question for you on the acquisition environment, particularly in the Mid-Continent.

Have you seen a significant amount of price creep on acquisitions here lately?

And then a second question, I wonder if you could address particular areas where the results are exceeding your expectations versus others that aren't quite up to what you're looking for.

Let me answer those I guess in reverse order.

Right now we're really not drilling in an area that's not working.

All of our areas are I guess what I would call well experienced.

We have had I'd say you know right now we have 43 rigs, and we're active in at least a dozen operating areas.

And there's not one that we feel like we need to shut down or reduce because it's not working.

Now, several of them obviously are developmental in nature.

But in terms of our exploratory activity, clearly Mayfield continues to lead the way with our series of deep Springer wells being drilled out there that are far exceeding our budgeted expectations.

As for Mid-Continent acquisitions, it's always been a competitive arena.

It is certainly so today.

And I guess -- I guess there's been creep in valuations.

Although, I guess the good news for those is that they -- that creep tends to be measured in pennies per Mcfe, and given increasing pricing in the past years, we feel like the value that can be unlocked from an acquisition is probably greater today than it has been in the past.

When we are uncompetitive in the Mid-Continent, it is not because of what we are willing to pay per Mcfe versus what the other company is willing to pay.

It is simply we would have a different view of the reserve potential of the property, and the beauty is always in the eyes of the beholder and we are going to have a different look and feeling about some of the things that go for sale.

And sometimes our Mid-Continent knowledge works against us.

Sometimes we feel like we know too much about a property, and cannot get carried away with some of the upsides that some of the companies see.

But things come and go in this area, and we'll remain focused here and I think do some good acquisitions in the years ahead here in the Mid-Continent.

Great.

Obviously you put on some great hedges and there is a lot of volatility.

Are there levels you might consider taking those hedges off?

Yes, there are levels.

But it is really more than just absolute pricing.

It's pricing with regard to underlying fundamentals.

For example, in the first two weeks of October, we saw a run in prompt gas on NYMEX of over a dollar.

We felt like that was unsupported by underlying supply-demand fundamentals.

And so we hedged basically every day into that run.

And as it turns out, it was probably a short squeeze, and we felt that way at the time.

And one of the wonderful things about gas price volatility these days is that you're going to get some kind of weird price movements that are unsupported by fundamentals, this one happened to be a big move up.

We could imagine a scenario where you'd see a big price move down that maybe is a down move too much, and we might be willing to unleash or unlock some of our hedges, and wait for another time to hedge.

So I will remind you for our 2003 volumes, some of our production in 2003 was hedged 3 times, and we made money on each trip.

Good, thank you very much.

Thanks.

We'll go next to Jeff Robertson with Lehman Brothers.

Good morning, Aubrey.

Couple of questions for you first on the Laredo properties.

Can you all characterize a little bit more the nature of the probable and possible type reserves?

And in particular, are those extension of the existing Laredo producing horizons or are you -- I'm sorry, the Lobo?

Or are you looking at deeper, a little bit higher risk exploration type projects?

Jeff, this is Tom.

We are -- we're looking at both, the majority of the possibles and probables are just extending the Lobo, the Lobo 1 I guess.

But we're also looking a little bit deeper for some Lobo 6 production.

So we'll take the wells down to 14,000 feet.

We have 3D over the entire project.

And while looking at booking the reserves, we only booked what was actually producing so far.

Are there other, Tom, is there other activity in the area that makes you feel good about looking at the deeper Lobo zones?

Well, somewhat.

Laredo had drilled a couple of wells at depth, and that made us feel favorable towards some deeper zones.

Plus the 3D view we have Jeff gives us a reason to think that we might have some potential down there as well.

Okay.

And I think in the release y'all talk about 9 cents per M operating cost down there?

Yes, sir.

Which is very, very low.

Can you talk a little bit about what makes those properties such low operating cost?

Well, it's just brand-new wells, you know, gas wells in an area that it just doesn't cost much to operate it.

I will say over time, those operate operating expenses will increase and in fact our projected LOE over the life of the project when we're all done, developed all the proved reserves would be 43 cents per Mcfe.

So the 9 cents is the current rate, and we think that obviously it will go up over time.

It's pretty extraordinary right now, and it is one reason can you pay a little more per Mcfe.

One further question on Laredo, the gathering and transmission assets that are needed for that production to expand what you all want to do there, is that assets that you all control or are you going to have to go through somebody else?

Yeah, we have to just sell into the existing infrastructure down there.

We are going to have to do some gathering line improvements, I think we've got a little bit of suppressed production right now.

But we'll be kind of de-bottlenecking that in the first 90 days of the acquisition.

So I've heard that could be as much as $5 million a day that's restricted right now.

Okay, one question for you in Oklahoma, Aubrey you talked about buying some Exxon assets in Beckham county.

Is that in the Mayfield area?

Effective July --

Effective July 1st but we closed on it the end of July.

It was actually right at the time we did our last conference call.

Yes, those were assets in Northeast Mayfield and existing infrastructure.

We have a gas plant there, and pipeline, needed to be able to sell some gas out of that.

So the mid stream assets there were as important as the production was.

So that alleviated some of the issues you all had a year or so ago trying to hook up some of the deeper wells and go through that plant?

Yes, and also, Jeff, it's been a -- there's been so much focus in that area from the gas pipeline community that we've had I guess three different projects now that have been built to accommodate it.

I mean, (inaudible) has done one energy transfer, which is the successor in interest [Aquilla].

And then we have our own gathering system out there as well, and then I'm forgetting one other.

But at any rate, we're not restricted out there.

We have been building infrastructure as fast as we've been drilling, and do not view that there will be a time in the foreseeable future when we will be rate-restricted out of Mayfield.

Thank you.

Thank you Jeff.

We'll go next to Ken Beer with Johnson Rice.

Hi guys.

Hi.

What kind of capex are you looking at if you got a 3 year pud development schedule?

What sort of capex are you putting into Laredo?

Ken, that would be about $38 million to $39 million.

And obviously that's included in your capex estimate for next year?

Pardon me?

I'm assuming that's obviously part of the capex estimate for next year?

I mean that's over a 3 year time frame.

That's $38 million total for the 3 years?

To develop the pud, right.

Okay.

So any rate, I would say probably 40% of that next year.

So it's really not, you know, call it $15 million.

Got you.

Okay.

And then second just staying on that for a moment, as I appreciate it, some of these wells are pretty strong wells with really minimal decline curves.

What sort of overall decline curve would you be looking at at, let's say, the 30 million a day today, if we move forward a year which the reserve engineering report suggests would be at a year from now?

Ken, I think I heard you say flat decline.

These would definitely not be characterized as flat decline well.

Sounds like a couple of these wells are pretty strong --

Okay, yeah, a lot of them produce we'll have them coke restricted or pipeline restricted.

They well produce at a flat rate, artificial flat rate.

We would think of these wells having 50% to 75% first year decline rates.

Anyway, I got kind of wrapped up on it.

What was the second part of your question?

Actually you just answered it.

Year from now where would it be?

You're going to see it flatten over time but as long as we stay active.

By staying active instead of it declining, 30 million would be up to 40, 45 million?

We are targeting a 50% increase just in the next year.

With high decline rates you're going to have exceptional internal rates of return.

And so this is a nice kind of adjunct to our lower rated decline projects here in the Mid-Continent.

Thank you guys.

Looks good.

All right bye-bye.

And we'll take our next question from Joe Allman from RBC Capital Markets.

Do you see south Texas becoming much more important as you go forward, not with just this recent acquisition, are you looking for additional acquisitions, acquiring additional acreage there?

Joe, we have been look at South Texas for really a couple of years.

We have actually been active there in what would I call the upper onshore Gulf coast for two years.

We've been slowly building technical teams for those areas.

And so while this is the first time we've talked about it we have targeted that area.

We targeted that area a couple of years ago.

And again, we just felt like it was an area with complicated deep geology that we thought we had a chance of being able to understand, and apply some of our deep drilling capability to that area, our tight sands expertise to that area, and maybe with El Paso slow down and some other kind of macroevents like major slowing down, there might be a chance to establish a toe hold down there.

We have looked at other acquisitions and haven't been competitive on those and this happened to be one where the seller knew what they wanted, I believe we were the first ones in the data room, and we quickly made our evaluation and were able to negotiate a mutually acceptable price.

So I can't tell you if we'll be able to do anything more down there because I don't know what will come available but it will be an area we'll continue to focus on.

The Mid-Continent is going to stay the place for us and we don't anticipate that changing.

But the percentage from outside the Mid-Continent will move around right now between 10% and 15% over time, maybe as much as 20%.

But I would doubt it would get larger than that.

I mean, would it be problematic just strategically to kind of really build up a second, you know, major core area outside the Mid-Continent?

I don't think so.

If you are thinking about from a management, capability or bandwidth, if you will, I think we're capable of it.

We do have technical teams that are in place, we are buying leases and shooting 3D and had planned really to build a presence without ever making an acquisition.

It just so happened that this one came along and it fit our pistol, and so we were able to jump start our presence down there.

So, the whole company is 50% bigger than a year ago.

So certainly, there are days when we have to work a little harder than we used to.

But you know we're getting adjusted to it and I think doing okay.

There seems to be an increase in competition for assets in the Mid-Continent?

There is competition everywhere.

Stuff getting harder to find through the drill bit so you're absolutely going to have more and more companies make acquisitions and it will certainly drive up the price of acquisitions and I think it will drive up the price of public company valuations.

There is a scarcity factor at work here that's only going to get worse.

Look at this quarter's production numbers, for those observers of the industry who thought production was going to be up this year or flat this year.

I don't see any indication of that from the public companies.

I think it's probably actually getting worse, which is somewhat unbelievable given the increase in rig activity, until you go back and compare it to what happened in 2001, in which case I think it's very believable what's going on right now so I'm --

Just a keep question on the deep gas program in the Anadarko basin.

In the pass year to year and a half, what is the track record?

Last time you guys had talked about it you had drilled 12 wells, below 15,000 feet, 2 dry, 2 okay and 8 great, and great defined as reserves between 15 and 40 BCFs each.

What is the update on that?

The update on that is that that's all more or less the way it is.

When you talk about deep drilling in the Anadarko basin the specific numbers that you were thinking about really apply just to Mayfield, where we've drilled 1 Huntin well, four Morrow wells, we have drilled one Huntin well, 25,000 foot zone, we have drilled 6 Springer wells, 20,000 to 21,000 feet, and then 4 Morrow wells at 18,000 to 19,000 feet let's call it.

The Huntin wells are [Cat Creek wells,] and it is going to end up giving about 6 bcfs so turned out to be a disappointment for us.

The Morrow wells have been okay, not great.

But we will continue to work that.

The Springer wells have been exceptional.

And so far, out of 6 wells, it looks like we're generating returns that would -- well, not returns, but looks like we're finding about 20 BCF on average, and IPs of around 20 million a day.

Whether or not we can continue that remains to be seen.

We've got -- let's see, we've got 6 or 7-- 6 rigs out there ruing for Springer right now so we're kind of in a little bit of a lull.

In fact we thought this quarter that we might even just have flat production compared to the second quarter because we just kind of the funny way the sequencing of the wells, we weren't bringing on any big wells this quarter, this quarter being the third quarter.

Turns out our other areas outperformed and so we were able to increase our production organically by about 2%.

The fourth quarter and the first quarter though should have some new big springer wells come on.

So you know we're excited about the area.

We're not talking about the area a whole lot in terms of specificity, not showing a lot of maps.

There's still room to run out there.

Lot of the wells we're drilling are wildcats right now, and we are really playing a 100 mile front--from Bray in Stevens county in south central Oklahoma, 21 north 7 west in that general west, out to 10 north 26 west over 100 miles.

And we're not going to be successful finding Mayfield type fields along that whole front, but we're going to take some whacks at it, and hopefully find a couple along the way.

And when we find them they can be exceptionally Prolific, and we are the only game in town.

We control the acreage, we've got the 3D and while we control it, we're not at 100% ownership yet so that's why we're not talking about it much.

Thank you.

Next Ellen Hannan from Bear Stearns.

If I have the math correct you indicate that you think that the overall cost all in to develop will be 196 BCF times $1.51-- about $296 million.

Would that suggest you your finding cost on the puds and the probable be around 60 cents per M?

That is lower than that Ellen, really closer to the 50 cent range.

So that's one reason why you pay a lot for the leasehold, is that the trick here is not so much how much money it cost to drill the wells, it's how much the acreage cost to get you the opportunity to drill the well.

Why are the finding costs so low?

It's relatively shallow, at least in the way we think about things and pretty good reserve.

I'll let Tom address --

It's also fairly unique in deals that we've looked like and that when a company has gone out and drilled three or four wells to define a project, and then was willing to sell it without drilling the puds themselves.

And that is what I believe was unique about this project.

So it left you a lot of upside.

doesn't explain why the F&D costs are so low though.

You're saying they're so low because the depth are shall owe and the drilling time is relatively short?

You're finding 6 BCF plus and they're rare to be able to find that, because, well, to answer your question yes, you can drill 14,000 feet and find 6 BCF of gas.

Okay.

Ellen, our Mayfield finding cost are 25 cents per MCFE.

Sometimes you get lucky in this business and you find amazing wells.

And like in Mayfield, you know, we pay a lot for acreage in Mayfield.

And in Laredo, this is a situation where a small company drilled some great wells, based on some 3D and that's why we're so excited about the property is at 10,000 feet we're finding a lot of gas.

Always better to be lucky right?

Given all other possibilities yes.

Do you have a forecast for your '04 capex?

Yeah, it's in our guidance.

That hasn't changed in other words?

You turn to page --

On the front of our outlook at $675 million to $725 million, and that includes acreage and seismic.

That's page 12 of our press release, apologize for having an18-page press release but we wanted to get as much information as we could.

I have many pages in front of me, great.

Thank you very much.

We'll go next to Kelly Cringer with Banc of America Securities.

Combines for fourth quarter and next year, looks like if you annualize fourth quarter, year long run rate ach you integrate the acquisition that it is kind of flattish relative to next year and based on the $700 million of capex, is the right way to look at it that the $700 million would be the right maintenance capex to keep production flat next year or you guys -- do you believe that is kind of conservative number to start with?

I'll take one whack at it and let Mark go.

If you look back at our performance over the last eight quarters, it's been pretty consistent that our forecasting has been conservative.

And I would just tell you that we intend to keep it that way.

And if we outperform, we outperform.

In terms of maintenance capex, it is much slower than $700 million.

I'll let Mark take you through the math.

The way we think of maintenance capex is basically to take current production rates, do it by day or year.

I'll just take a stab at it by year.

We've been around 280 BCF, we're moving that up of course, but 280 BCF at a current finding cost of about 60, if you look at that as our all-in FD&A implies a $425 or so million dollar capex requirement, just to keep production and reserves flat, assuming that your RP and reserve profile doesn't change.

If next year production is 300 BCF equivalent and planning cost are $1.50 to $1.60, you're at $450 million to $475 million or so,$480 million maintenance capex.

So the way I think about it is operating cash flow that we've hedged in will generate somewhere between $850 million and $925 million of operating cash flow, maintenance capex is roughly half of that.

And so you've got $450 million or so of growth providing for acquisitions, supplemental drilling, which obviously we've outlined part of that.

And if that grows or we are effective at replacing reserves at that same $1.50 to $1.60, then we're looking at net asset growth on a per share basis everything else being the same of roughly 25%.

That's what we've experienced this last year.

Our hedging and drilling inventory shows that we should be able to do that for the next several years.

And so that's the way I look at maintenance capex.

Okay.

One more thing.

We would normally throw some leasehold and seismic on top of that.

I'd say if we were just trying to keep things flat it might be as little as 25 million in a growth mode that's going to be 100 million.

Okay.

That's helpful.

And then secondly on the acquisition, that I think you said closes today, Mark I think you said you had 95 million of bank debt.

I think the acquisition is a couple of hundred million.

Could you give us a sense of kind of what your current revolver is and what it will be post -- or pro forma the acquisition?

Well our current revolver borrowing base is $350 million, and the $95 million outstanding is prior to funding the balance of the acquisition.

We've already got some deposits on -- in place.

Pro forma I would guess that the acquisition -- post funding is going to be $275 million revolving borrowing base leaving about $75 million.

Obviously that's on the high end of what we like to have.

We haven't made any decisions, final decisions on how we would permanently finance this.

Clearly, a question has been raised frequently, as to what uses of excess cash flow are you going to have.

We'd like to use some of that operating cash flow to pay this down.

I.e. finding it out of ongoing and equivalent of retained earnings.

Okay, thank you guys.

We'll take our next question from Dan Morrison with Aperion (ph).

I'll try to keep this short in getting you in under an hour.

Follow-up on Laredo and details.

What is the current well count and idea on the scope of the acreage and are you 100% there?

I can give you the well count. 35 wells of which we would operate 34 of them and gross acres of about 25,000, and net acres of about 17,000.

Great.

And on your capex for the year, the $143 million drilling, could you break that down between exploratory and development?

You said for the year?

I mean for the quarter.

For the period.

Roughly two-thirds developmental, third exploratory.

Our overall budget if you look at just the deep zone being the controlling factor, as to whether or not we classified as exploratory, Dan, would be between 35% and 40%.

The fact is that virtually every exploratory deep prospect has backup zones that are developmental in nature and hence, we have 90-plus percent completion rates.

Great.

And so I've always thought that that 35% or 40% was --

Sounds bigger.

Sounds bigger, than it turns out to be.

We have simply stuck with a definition that if it's not a proved, undeveloped well, i.e., a probable, possible or exploration zone four our deepest or zone of most interest, we'd classify that as an exploration dollar, when in fact most of those dollars tend to be developmental in nature at the end of the day.

Thanks.

John Gerdes with Southwest Securities.

What about the deep Arbuckle, years ago, that was something that was worked in the late 70s, early 80s, you guys were drilling deep as anybody in Arbuckle basin.

We don't have any wells in the Arbuckle for a long time.

That area and the Mayfield was productive, we operate some Arbuckle wells in an area known as West Mayfield.

But in terms of wanting to go drill to 30,000 feet, which is what it would take, our appetite is pretty much zero at this point.

You mentioned the Huntin, mixed lesser success, how do you feel about the Huntin?

We feel like to drill any more Huntin wells-- We just don't have any appetite for it right now when we can drill wells that cost a third what the Hunton wells cost and in our view can find as much or more.

We are Springer men.

That's helpful.

You fill in the gas along the mountain front, talk about your activity along that area.

I mean, it's got two kind of book ends to it.

One would be Mayfield, that's in Beckham county Oklahoma, in the area of 10 north 25 west, 10 north 26 West and 11 north 25 to 26.

That's active play, St. Mary's, dominion and St. Mary's are the to the north of this.

In this area where we are talking about our Springer wells we have virtually 100%. [The east book end] is an area we call Bray.

And in Stevens County and I mentioned that is kind of 1 north 8 west, 2 north on both those townships, and every area in between is in play.

Along the way we'll run into cement, where we have an active project.

And then further out, to Cordell and Elk City.

You're active all along there?

We are.

Spoken like a true land man with all those sections.

That is what I am.

What about some quick observations, you studied this intensely with the gas market.

Some quick thoughts there?

We've been hedgers lately, we've been sellers, we've not liked what we've seen in terms of injections in the past few weeks.

Right.

If you followed what we put -- we hedged 25% of our '04 production in the run-up that happened in the last winter.

And we said we were going to wait and see what happened through the course of the summer.

And we thought there was a chance we'd see a fly-up this summer and didn't get it and I don't know if it was weather, or just that we've had a real substantial change in industrial demand.

But any rate, we've been kind of pessimistic the last few months, and then saw this incredible gift from speculators the first couple weeks of October so we jumped on it.

And so we're 50% done.

And if this thing moves down 50 or 75 cents from here, it just sets the next run, because as my colleague Tom reminded us all yesterday, depletion rules the day.

And so at the end of the day, if supply continues to drop like it has been, we will find ourselves back in a pickle here before, you know, 2008, 2009.

So we're going to get multiple opportunities to ring the bell, and we'll just hope to have spent enough time studying the underlying fundamentals to sell out early but to keep enough powder so that we can really hedge at extraordinarily high prices, not just okay or average prices.

Congratulations or y'all's quarter.

Thanks John, appreciate it.

And we'll go next to Van Levy with CIBC World Markets.

Good morning, gentlemen how are you?

Hi Van.

Congratulations on the hedging.

Right thing to do and you're a leader.

Wish more companies would follow you in that vein.

Hope they don't.

Thanks.

Psych up your liquidity.

Along that those lines certainly you did a good job.

Why not hedge longer and more?

Well, there are limits to what a guy can get done on any day.

And I would say that had that run-up in gas prices lasted one day longer, we would be more hedged, and had it lasted a couple weeks longer we probably might have been close to 100% hedged.

So –unfortunately, it is one aspect of our size, that it does take a little bit of time to get some things done, if you don't want to move markets.

And we have not wanted to do so.

So it's not even 2004 yet and we're 54% hedged on Mcfe basis.

We're -- it will be cold at some point this winter and we'll get some chances at some point.

And if we don't, we feel okay with what we've done today.

Okay.

Second question, in the deep basin or the exploratory areas, how much have you spent so far this year?

Well, let's see.

Van --

Take me through the metrics.

How much you spent, how many wells?

I mean that's -- we drilled if you take away the Cat Creek which was a 2002 well we've drilled 10 wells, and those are going to be roughly $5 million per well.

So I'd say $50 million just on drilling.

In terms of land and seismic, we would have spent easily another $10 million would be my guess on top of that and would still be active.

I guess, John referred to Tom's background and my background as land men.

And we do have 250 land men in the field today buying leases, in addition to our 100-person land department here that's focused on new lease acquisition as well.

So we are as aggressive as it gets when it comes to building the foundation for the future growth of the company.

So you have $60 million in the exploration.

Are there any other exploration areas?

I'm trying to get a sense of total high-risk kind of budget.

I mean, we're drilling 7 wells right now in the Mayfield area.

So that's -- we're in the process of spending another let's call it $35 million.

Those wells cost or take rather about 4 months to drill.

So, roughly, let's call it nine to $10 million a month of expenditures out there and certainly we'd be spending at least $1 million a month in leasehold and seismic.

So you know, you'd be on a run rate, for the year, let's call it $100 million out of a $700 million overall budget.

So --

Van I would just add that back to Dan's question and answer, company-wide, from an allocation standpoint, about a third of our budget, 35% or so, is what we call exploration.

So if you do the math, add the seismic and acreage, 35% of a $600 million drilling budget, $200 million per year.

Right.

And out of this $100 million per year, can you or $100 million, can you give a sense of your finding costs so far this year?

Well, yeah, to date, in the Springer, we found six wells, we found 120 BCF.

And those 6 wells would have cost us $30 million to drill.

So --

Can you book all those reserves this year?

Those --

Year end?

Those are producing wells.

We have these other wells that are drilling, that I don't know which of them would be pud, but you know, this is an area of important potential reserve growth for us because we have not done, you know, when you are -- you only have six wells, there's not a whole lot of pud.

Right.

So what I'm driving at Aubrey, at the end of the day, this year, year and a half, I'd be surprised to see, go back do this calculation over the year, two years, to see the finding cost to be at $1.50 to $2.00, it would likely to be the $1.00 to $1.20 range?

Are you talking about this project or for the company overall?

No, for the [deep play.]

In our deep play right now we're around 89 cents.

Okay.

So I mean -- but we'll continue to drill wildcat tests also that some them won't be successful.

Right.

But when you roll those in, obviously that's part of the deep play.

That's why we're doing this Van is A, we've got a proprietary understanding of the science.

We have a hammer lock on the acreage and we're drilling great wells so --

And it's working out is your suggestion?

I don't know where our final company wide finding costs are going to be.

But in this deep program they're going to be less than our overall finding cost, which I think if you look at other deep drilling potential place in the country, like deep shelf, I think it would be difficult to say that that's going to provide you with lower finding cost than kind of what else might be out there.

So again, it's early.

Tom and I believe that we'll be drilling wells in Mayfield a decade from now and along the mountain front for probably the rest of our careers.

Great.

These drill in- wells at $1.50 finding cost that really have no risk.

Last question, I don't want to beat this Laredo thing to death.

But my understanding of the Lobo Trend, it's pretty mature.

There certainly were some big wells there, but the average reserve per well on the Lobo is somewhere around, I don't know, about 1.5 Bs, clearly at 6 Bs a well you're on the double or almost triple the average.

I would answer that by saying if you took the Springer average across the Anadarko it is not 20 BCF.

What we're about is targeted exploration in areas where the reserves are going to be enhanced.

In this particular area, Laredo has driven a number of wells that are 5, 6 bcfe and we believe we can duplicate this.

Do we dispute your math across the entire Lobo Trend, absolutely not.

What county?

Zapata.

This is right in the town of Laredo.

One of the reasons that -- I'm sorry the town of Zapata.

The reason this opportunity exists is we've had to do a lot of town lot work.

Right.

Again, complicated land work is something that we're kind of accustomed to.

There were some 20 or 30 BCF Lobo wells, big ones.

That is bucking the conventional wisdom.

That is the issue that this is undrilled because you had the town lot impediment, is that correct?

I think that's part of it certainly.

We're not trying to buck the trend, because we're not saying that we're going to go out in over half a million acres find 5 BCF.

We think in 15,000 to 20,000 acres we can drill some 5 to 6 BCF wells.

And what's the cost per well?

About $2 million.

$2 million, okay.

That includes -- that's one, one and a half racks or --

Well, that's just set up for a single -- single zone completion.

Single zone, okay.

All right gentlemen, thanks.

Okay, anything else?

We appreciate participation and if you have any follow up questions give us a holler later in the day.

Thank you.

This does conclude today's conference.

Thank you for your participation.

You may now disconnect.