Chesapeake Energy Corp (CHK) 2003 Q2 法說會逐字稿

Good day, everyone, and welcome to this Chesapeake Energy Second Quarter 2003 Earnings Release Conference Call.

Today's call is being recorded.

At this time for opening remarks and introductions, I'd like to turn the call over to Mr. Aubrey McClendon, Chief Executive Officer with Chesapeake Energy.

Please go ahead.

Good morning and thank you for joining Chesapeake's Second Quarter 2003 Earnings Release Conference Call.

We believe this marks the 40th conference call that we've had in our company's history.

As we hope you've seen from our news release yesterday afternoon, Chesapeake's first quarter results were very strong.

Net income was $76, operating cash flow was $226 million, and EBITDA was $266 million.

Chesapeake's strong financial result were driven by an equally strong operational performance.

Oil and gas production reached the record level of 67.3 BCFE, which was our eighth consecutive quarter of record production.

That translates into 740 million cubic feet per day of gas equivalent production.

This quarter's production was up 55% from a year ago and 19% sequentially from the first quarter 2003.

On a product basis, gas represented 89% of our total production, or 659 million cubic feet per day, and oil production average 13,450 barrels per day.

Because of this quarter's especially strong operational performance, we have for the third time this year needed to increase our production forecast.

For the third quarter we are now projecting production in a range of 67.5 to 68 BCFE, and for the full year 2003 we are now projecting 258 to 262 BCFE.

We have also increased our 2004 production forecast 277 to 281 BCFE, which represents 6% growth in production in 2004 versus 2003.

In addition, our estimated proved reserves as of June 30th have reached the record level of 2.95 TCFE, up in the past six months, up 750 BCFE in the past six months, an increase of 33% in just one-half of one year.

What drove the company's strong operational performance in the second quarter?

As you can see from the news release, second quarter 2003 production exceeded first quarter 2003 production by 10.5 BCFE.

Only 1 BCFE of this growth came from acquisitions closed during the quarter.

And only 3.9 BCFE came in from the full second quarter, impact of acquisitions closed during the first quarter, leaving 5.6 BCFE coming from the drillbit.

Said another way, 52% of our growth and production during the quarter was truly organic.

That amounts to almost a 10% sequential quarterly growth rate, or between 40 to 45% on an annualized basis.

In our view, that is quite simply an amazing performance for a company our size.

By the way, depending on our other producers report, it appears that our surge in gas production this quarter has moved Chesapeake up from the eighth largest independent gas producer in the U.S. to the sixth largest, trailing only Devon, Anadarko, Burlington, Unical, and Apache in U.S. gas production.

Among these top six U.S. gas producers we believe that during 2003 Chesapeake will have the best profit margins, the most visible growth profile, and the highest return on capital.

If you stop to think for a minute about where we were ten years ago as a 4 BCFE producer, or even five years ago when our stock price was 75 cents per share, I think you would have to say Chesapeake's ascent into the top producing gas company's is truly amazing.

While we do not expect this growth rate to continue during the quarter, we do [INAUDIBLE].

This highlights what we have been saying for sometime about our company.

Chesapeake's drilling program, deep, medium, and shallow, are working exceptionally well across all of the company's area of activities.

This is simply the calculated results of our relentless focus in the Mid-Continent and a very heavy investment in people, lapped, and science during the past [six] years that has enabled us to build a truly distinctive natural gas exploration company.

We believe the company's operational traction is the best it has ever been and may be the industry's best at the moment.

We are hopeful that we can maintain this industry-leading position during the remainder of 2003 and throughout 2004.

How might we be able to do that?

First, we have lots left to do.

During the past five years we have built an unrivaled land and seismic position in the Mid-Continent.

Today our drilling inventory consists of more than 2,000 location, our biggest backlog ever, and we continue to increase that backlog.

Today we have almost 50 geoscientists generating new ideas and over 250 field and in-house men buying those ideas to convert them.

This year we will devote over $100 million of our $650 million cap ex budget to further expand Chesapeake's 3-D seismic and leasehold inventories.

This pipeline of existing and future prospects is one of the primary distinguishing features of Chesapeake today.

Let me comment on the specific of the quarter's results.

For operated wells we successfully completed 78 out of 95 attempts for a success rate of 92%.

To drill these wells we employed an average of 35 rigs.

Because our rig count for the third quarter should average between 40 and 44 rigs, we expect to see continued organic growth for the rest of the year and throughout 2004 as well.

This morning we are drilling with 42 rigs, 11 of which are headed to target shallower than 10,000 feet, 13 of which are headed to depths between 10 and 15,000 feet, and 18 of which are headed to depths below 15,000 feet.

While this program provides us with balance across all target depth, it also gives us a unique focus on deep gas.

In fact, we are presently drilling the deepest wells on average in the U.S.

We drill deep gas wells for one simple reason.

That is where the remaining big new reserves of gas are.

We believe that our skill and commitment to deep gas exploration is a key competitive advantage of our company.

In addition to the geographic focus and the organic growth that I just highlighted, I also want to emphasize our rigorous approach to controlling costs.

I hope you have noticed that our operating interests and general and administrative costs all declined per MCFE from the first quarter.

The only expense that increased was our DD&A rate, which increased by 1 penny for MCFE during the quarter while our other expense fell by a total of 19 cents per MCFE.

I would now like to move on to our hedging activities.

During the quarter hedging lowered our realized oil prices by 52 cents a barrel and increased our realized gas prices by 3 cents per MCF for a net hedging loss of only 3 cents per MCFE.

For the quarter we ended up being 67% hedged on oil production and 38% hedged on gas production.

Looking ahead we think we have a very attractive hedging profile for the remainder of 2003 and 2004.

For the second half of 2003 we are 62% hedged at a NYMEX gas price of 561 per MCF and 79% hedged for oil prices at a NYMEX price of $28.07 per barrel.

Therefore, on a gas equivalent basis, we are 64% hedged at a NYMEX gas equivalent price of $5.50 per MCFE for the third and fourth quarter.

Looking ahead into 2004 we have hedged 31% of our gas equivalent production at a NYMEX price of $5.33 per MCFE, much of which is front-end loaded for the first quarter of 2004.

For those of you who are curious about our thoughts on today's gas prices we believe the sharp fall-off in prices during the past six weeks has been very constructive for long-term gas markets.

It has given consumers a chance to catch their breath and has reminded producers that gas prices above 550 or so seem to be pretty effective in destroying demand.

This is especially true in a weak economy and where summer weather has been much cooler than normal.

So where to from here for gas markets?

Our view remains generally the same as it has for the past three to four months.

Storage will reach 3 TCF, no matter what, and that gas prices will average whatever it takes to get to that 3 TCF.

Our best guess three to four months ago was that this would require a summer gas price strip of $5.50 to 6.50.

With oil prices, the economy and weather determining whether we were at the high or the low end of that range.

Today we would lower that range by $1 per MCF.

Many gas market observers have become very alarmed by the series of high storage injects during the past six weeks and see gas prices plunging to levels of $3.75 per MCF or even 3.50 per MCF by this winter and throughout 2004.

If oil prices remain above $25 per barrel we simply cannot see gas prices that low during fall or winter or in 2004 simply because we believe demand and supplies elasticity cuts both ways.

With a much lower August index price we would expect to see less agressive index numbers in August than we have so far -- than we have seen so far this summer.

On the other hand , if gas prices do plunge, Chesapeake is hedged at a very large percentage at one of the highest prices we've seen in the industry, and so we would do just fine during any turn-down in gas prices during the next 12 months.

We think it's important to remember what got the gas market in the pickle that it's in today.

Falling supply and rising demand over a multi-year period.

We see no quick fixes to either of those trends over the next five years so we believe gas prices will stay volatile, and again if oil prices stay firm, we think gas will trade in the range of $4 to $6 per MCF for an extended period of time.

In summary, we have built a company with many favorable characteristics that can prosper during this upcoming five-year environment.

A few of these characteristics are as follows: First, we're big enough to have very attractive economies of scale, yet small enough to be able to deliver double-digit value-added growth.

Second, we can create value through the drillbit and also create value through acquisitions.

And because of our regional focus and operating dominance in the Mid-Continent, we find that acquisition success drives drilling ideas and drilling success generates acquisition ideas.

We have developed expertise in both arenas that has enabled to us create an operating dominance in our Mid-Continent backyard that is unrivaled in any other major gas producing basin in the country.

Third, Chesapeake's profit margins are among the very best in the industry because of our focus on maintaining low cost and our ability to successfully hedge high oil and natural gas prices.

Fourth, we expect to continue generating large amounts of excess cash even as we continue to heavily invest in the continuing growth of our company.

This excess cash could easily exceed $1 billion over the next five years.

We intend to invest this cash to improve our balance sheet by either reducing debt on an absolute basis or on a relative basis, or in a combination of both.

By decreasing debt on a relative basis during the past four years, our debt to total book cap has decreased from 138% to 58%.

We expect this percentage to fall to 50% or below by year-end 2004.

Balance sheet improvement will always remain a central feature of our strategy.

We see this as an excellent path to multiple expansion, and we want to arrive in a time of possibly greater LNG supply at the end of this decade with a bullet proof balance sheet.

Finally, we believe the stock price performance does count.

To remind you, we're the number two performer in the industry during the past 10 years, number one during the past five years, and number one during the past year.

We believe the competitive advantages detailed above should enable Chesapeake to continue generating top-tier returns to investors for many years to come.

I will now turn the call over to Marc.

Thanks, Aubrey, and good morning to everyone.

As is our usual custom, we won't bore you by repeating all of the numbers in our press release and outlook but instead will try to provide color on trends affecting our business and the industry in general and some lesser details not included in any release.

Let's turn first to the acquisitions and drilling activity for the quarter.

We completed and successfully integrated all of the $220 million of acquisitions announced June 24th during the quarter and funded them by quarter end with the exception of one.

That $45 million acquisition will close this week.

The reserves and cash associated with the pending acquisition were, of course, not included in the 2.95 TCF approved reserves as of June 30th, nor was the 45 million included in our cash or reported bank debt.

Having said that, our bank borrowings as of June 30th were only $26 million, while cash balances were $36 million for net bank debt of zero.

We reduced our long-term debt to only 67 cents per approved MCF equivalent as of June 30th.

Our drilling activity resulted in these capital expenditures for the quarter.

Drilling, we expended $120 million.

Capitalized workover costs, $5 million.

Acreage and seismic, $25 million.

Capitalized G&G and overhead were $15 million, and all other prepayments, overhead recovery, et cetera, netted to 14 million for a total expenditure in all of those categories of 179 million.

Consistent with our focus, 87% of those expenditures were in the Mid-Continent.

On the acquisitions side, we expended $163 million during the quarter. [Oxley] itself represented $155 million of that total.

We had divestitures of $19 million for the quarter, for net expenditures in that area of 144 million.

Our total full cost pool adds during the quarter, or stated another way, our total capital expenditures, as recorded in our books, were 322 million.

During the quarter, we had capitalized interest of 3.5 million, or for the six months, $5.4 million.

Capitalized G&A, or overhead costs associated with our drilling programs, were $8.5 million for the quarter, or 15.8 million for the first six months of 2003.

Aubrey gave you some operated numbers on wells.

We actually participated in 259 gross wells during the quarter, 106 net wells, of which 97% of the 106 net wells were completed. 75% of the net well activities were operated by Chesapeake during this quarter.

On May 30th, we amended and extended our revolving credit facility with our bank group.

We now have 19 high-quality institutions providing us $350 million of available credit with an extended due date now of May 2007.

We are very proud of the BBB minus credit rating assigned by S&P to this new facility and extend a thank you to the participants that made it possible.

In a transaction that has closed since June 30th we have extended the maturity of a portion of our debt due in 2008, approximately $28 million of notes were swapped by issuing nearly $30 million, 29.5, exactly, of 2015 notes in exchange.

We've picked up seven years of additional maturity and lowered our interest rate by 62.5 basis points for a net present value of just about zero.

This extends our maturities, lessens our ongoing interest rates, with very little cost to Chesapeake.

Let me turn to the cost trends we're seeing in the industry.

We incurred very good lifting cost numbers at this quarter at 51 cents per MCFE.

We believe this in good part was caused by our new acquisitions, and we had predicted that our lifting costs might fall based on the One Oak, El Paso, and Oxley transactions, since they had lower lifting costs than our existing base which was already among the lowest in the industry.

We think that this trend will probably continue, but we need some more data points before we're willing to lower our guidance in this area.

We have good news to report on the drilling and service cost side.

Surprising to us, costs have not moved up during this quarter. 2000-horsepower rigs still go at under $8,000 per day, and are steady since our last report. 1,000 horsepower rigs are just over $7,000, up slightly.

Cementing services have remained flat.

Open-hole logging is up slightly, and casing costs, were already flat because we had logged in, in January of this year, a six-month agreement that extended into August and has now been re-extended, and so we're looking at very small, perhaps 3%, increases in our casing costs.

This is all a good report and somewhat different than what we would have predicted but we are fortunate to be able to continue to have great trends in this area.

Aubrey mentioned our hedging position and complete guidance is provided in our outlook in detail but I would like to emphasize trends in this area.

The increased size and length of our hedging positions continues to surprise us a little bit in the sense that we're not having difficulty at all in hedging gas out through 2007 at attractive prices of nearly $5.

There remains plenty of liquidity in the markets, and including basis hedges, which extended to 2009, we think we have some of the longest tenor hedges in the industry.

We don't see any changes in this going forward and would note new players are entering into favorable credit agreements with us, which should allow for expanded counter-party options.

On a final note, I would highlight the fact that Chesapeake still has significant tax loss carryovers.

In fact, nearly $650 million in regular NOL's, and nearly 300 million of alternative minimum tax NOL's as of the beginning of this year.

These net operating losses allow the very significant cash flows we are seeing to be sheltered from cash taxes and in fact, 100% of our tax rate reported on our financial statements is deferred.

With the book tax rate completely deferred, we project that this situation will continue into at least 2005 at the earliest and represents a significant asset for the company as compared to other players in the sector.

Moderator, I would like to turn it over to questions and answers at this point.

Thank you, gentlemen.

Today's question-and-answer session will be conducted electronically.

To ask the question you may do so by pressing the star key followed by the digit 1 on your touch-tone phone.

Please disengage your mute function on your speaker phone to allow your signal to reach our equipment.

Again, that is star one for your question..

We will go first to Joe Allman at RBC Capital Markets.

Good morning.

Hey, Joe.

Aubrey, I missed a little bit of the breakdown of your organic growth.

On your press release you said that BCS was due to second quarter acquisition.

Could you break down -- that's a BCF out of a 10.5 BCF difference.

Could you break down the rest for us?

Sure.

The way to approach it, I think, is to start with the 10.5 BCF delta between the first and second quarter and then subtract -- it's actually, if you want to get away from rounding, it's 0.8 BCFE that came from acquisitions closed this quarter.

That would be Oxley.

And then approximately 4 BCFE came in the second quarter from acquisitions closed at sometime during the first quarter.

The delta between what those acquisitions did in the first quarter on a partial-quarter basis versus what they did on a second quarter basis, you have to back that out, and then when it's all said and done, it's about 5.5, 5.6 BCFE of pure organic growth that came from the drillbit this quarter.

Okay.

Great.

Very helpful.

And then just a follow-up.

On acquisitions, I know you've been very aggressive in making acquisition, and making good acquisitions.

Do you see yourselves kind of settling back a little bit and digesting what you've got, or are you still aggressively looking at opportunities out there?

We look at a lot of things, but I guess we're characterized as being aggressive acquirers.

I would say that may be true if the definition of that is have we bought a lot over time.

But we use a very disciplined approach.

We have not been close in the past two months in things that we've been on.

I can think of three private companies that have been sold or are being sold at the present, and because they are Mid-Continent-focused producers, we bid on all of those.

And from what we could tell, we were at least 20% under on most of them.

So, you know, we see a lot of money being thrown around by kind of private capital sponsored type companies and then also some mid-cap independents that are seeking to grow in the Mid-Continent seem to be either using more aggressive pricing than we are or more aggressive reserve forecasts than what we're accustomed to.

That comes and goes, and we certainly don't mind losing, we're happy.

One of the things we talked about in the first quarter conference call, we thought our acquisitions were clouding or obscuring what we thought were one of the one or two best organic growth stories in the industry, and today's results we think put us on track to have the best organic growth in the industry, and that should come through crystal clear now that there are no present or pending acquisitions.

That's very helpful.

Thank you.

Thanks, Joe.

We'll go next to Van Levy, CIBC World Markets.

Good morning, gentlemen.

How are you?

Great.

Congratulations.

Looks like a good quarter.

Relating to the, I guess, analyst conference you had, can you give us an update on number one, just the deep drilling program in general, how that's going, what's been exposed to the, and refresh my memory of the dollar amount that's going to be exposed this year, and then second, you know, just an update, I think it was around Mayfield area, or the extension, you had a couple of players there, I don't have my notes with me, but maybe you can update us on that, on those wells.

We can generally.

We won't do it specifically for the reasons we've talked about in the past, really for competitive reasons.

But I mentioned that we had, I believe it was 18 rigs right now drilling below 15,000 feet.

I believe 6 or 7 of those are out in the Mayfield area, and in that area we are sending about $60 million net, so about, oh, I guess, 11 or 12% of the drilling portion of our $650 million Capex budget.

We have continued to see success in that area.

We're a little bit in a lull right now in terms of these things tend to come in waves.

Within the next 30 to 45 days we will have a series of wells down, I think probably three of the wells that we're drilling today will be down within that time frame.

What would those be, Aubrey?

Van, we're not going to use well names, but there are three Mayfield wells that are drilling, and I guess if you really want to dig, you can get into State of Oklahoma records and look them up.

Again, it's a play that we dominate, but it's pretty large, and there's still work to be done, so we're just not going to talk specifically about wells.

That's not the only area where we're doing well.

We're doing well in areas like cement and areas like Bray and along that whole mountain front trend that you might have remembered that we talked about, which is roughly 100 miles long, and we're playing at 10 or 20 miles wide at various points.

Big play, lots of work to do.

Some big initial success, which has had an impact on the company, and we are hopeful that we will continue to be able to do that in the months and years ahead.

Okay.

Second question, you show a chart, and I guess in your last presentation of the -- I guess distribution of ownership in the Mid-Continent area, clearly a lot of mom and pop's.

It's a bit surprising that with these prices, you haven't been able to shake out, you know, more, I guess, more sellers.

Could you comment on this and kind of what is the mentality in the -- particular with the smaller players?

Well, actually, you know, if I look at that list of top 20 producers, there's not many mom and pop's.

In the top ten, I think there's two private companies.

Samson out of Tulsa and Kaiser Francis out of Tulsa, certainly not mom and pop's.

Below that list, it's really a whole series of public independents, on the bottom half of that list public independents and some majors and utilities as well.

Savannah -- we see a fair amount of turn-over in assets here, but this is a wonderful place to produce gas.

The hassle factor is almost zero.

Gas prices are high, operating costs are low, it's easy to drill wells from a regulatory standpoint so we're never surprised when people want to keep their assets.

In fact, we are always surprised when somebody is willing to part.

So, you know, I think there's a view settling in across the industry that we're in for a period of extended prices, and unless you're kind of worn out physically, there's not a tremendous motivation right now to sell.

So we see a fair amount of churn among private equity-sponsored companies that need to get out every three to five years.

The mom and pop's, though, tend to -- in our view, will tend to produce it out.

And we don't see a lot of major turnover as well.

This is still a key part of BP's North American gas strategy, for example, for all that we can tell.

Last question.

Reserves, you're one of the few companies that gives, I guess, quarterly reserve estimates.

Are these internal estimates, number one.

And number two, what component would be from, say upward reserve revisions?

Van, we do do internal quarterly estimates from a grass-roots level up.

We are one of the few companies, I think, that do that, in listening to -- or reading some of the other transcripts.

I think some of the companies, for kind of curious reasons, don't make quarterly estimates at all.

Annually, of course, we go out to independent third-party reserve engineers, and about 75% of our reserves are done by Rider Scott, Netherland Suell, and those reports we use throughout the year on a quarterly basis and we update those internally and review all of the production curbs.

So that's the process we go through.

The second part of your question was how much of it was revisions from prior estimates?

Right.

And the fact is, this quarter we had very little in revisions either way.

Okay.

Thanks.

We'll go now to Ellen Hannan at Bear Stearns.

Good morning.

Hi.

I came on a little late, but Aubrey I just wanted to circle back on your comments about your balance sheet, your outlook for your debt level, 50% or below by year-end '04, and more importantly you made a comment about being positioned for a more important component coming from LNG in the future.

Could you elaborate?

Certainly, Ellen.

My comment on debt to total cap, we're at about 58% right now.

If you just do the quick math, our shareholders equity is about $600 million less than our long-term debt.

And if you look at net income over the next two years, 2003 and 2004 we will earn about that.

So we think by the end of 2004, if debt stays the same that we're on course to be about 50% -- equity, 50% debt.

Then I mentioned that given where we think gas prices will be, which is in the range of $4 to $6, there will be times when we'll be outside high on that, probably times when we're outside low, but I think that covers 80 to 90% of the possible predicted outcomes.

We're going to generate a loss of cash.

Even though we're active drillers, I believe this morning we're number one or number two in the country in that respect, we're still going to generate lots of excess cash, and we think probably close to a billion dollars over the next five years so.

We want to protect ourselves against the, in our view, the inevitable kind of onslaught of LNG in the second half of the decade.

We're not -- well, let me put it this way: The question is can LNG grow at a rate faster, from a base of 1 BCF per day, can it grow faster than domestic production can deplete from a base of 50 BCF a day.

I don't know.

I've got conflicting views on that.

But I do know this, I know a lot of our debt comes due between 2008 and 2015, and we want to use this period of elevated high prices to harvest a lot of cash and reduce our debt.

I believe I mentioned we'll do that through either relative deleveraging, which has served us well during the last four to five years, or absolute deleveraging, which could also be a strategy.

In all likelihood, it will be some combination of that.

So we expect to be around for awhile, and we expect to have a much better balance sheet, and we think that is an excellent way to deliver value to our investors through multiple expansion, is to have a better balance sheet.

And it's an inevitable outcome of just the simple execution of our business strategy.

Just a couple of questions, then, for Marc.

Can you give us some guidance on capitalized interest going forward, because the amount in the second quarter is quite a bit higher than in the first.

Actually, I think we'll probably be running at about the same rate as we ran in the second quarter.

It's a function of our unevaluated leasehold, which through the recent acquisitions, we've completed over 1.1 billion of acquisitions so far this year.

We have added to our unevaluated leasehold.

GAAP requires us to carry an interest rate against that and capitalize that interest and my guidance for you right now would be that we don't have any acquisitions pending, and there's no large unevaluated leasehold blocks that we are acquiring.

So I would look for Q3 and Q4 to be about flat with the rate in Q2.

One final number crunching question.

Your share count estimate is up.

Is there anything behind that?

Just by a couple million shares or so.

Just the normal execution of employee stock options and the conversion from options into actual shares outstanding.

You know, a couple million shares on 260 million shares is a pretty minor amount.

Great.

Thanks very much.

Thanks, Ellen.

We'll go next to Dan Morrison at Hyperium Capital.

Hey, guys.

I think you've covered almost everything.

The one question that I would have and I don't know, in the past I have not really tracked this -- but the number of completions in the quarter of the deep are wells below 15,000 feet, how many Wells do you have, how many of those completions were deep wells?

We'll have to get back with you on that, Dan.

That is not a number we have off the top of our head.

You're right.

We don't track that.

Our reports are tracked sim lee by operated, non-operated, and gross to net wells, and we don't break out production, nor do we break out completed wells or even drilled Wells, by depth and then track that.

And deep Wells take between 140 and 180 days to drill.

Right.

We can do it, we just don't see any value in having the information.

Throw it out there.

I see the value in it

All right.

Thanks.

We'll go next now to Jeff Robertson at Lehman Brothers.

Good morning, Aubrey.

Good morning, Jeff.

Can you talk a little bit about the breakdown of the 112 BCFE of drillbit and reserve additions in the quarter, and if you can talk a little bit about what plays those came in.

And then secondly, as you look at the rig count, your operated rig count in the low 40's, an average, I think you said, of 40 to 45 in the third quarter, which is quite a bit higher than what you've done for most of the year, is that seasonal, or is that an activity level at which you think you will continue for awhile?

Okay.

Couple of good questions.

First of all, we can know the number of reserves by depth, and we know it by we will, but it's just not something that we feel is, I guess, useful in terms of generating that number.

So we will continue to report it on a broad basis.

Happy to discuss with you the amount of revisions, which were in there, which, if I recall, Marc, was about 8 --

8 BCF is very nominal.

They're positive revisions.

That's number one.

Number two, number of rigs, I hope I said actually 40 to 44.

This morning we're at 42.

What does that reflect?

First of all, it reflects a trend up.

In the first quarter we averaged about 28, in the second quarter, about 35, and this quarter again will be similar, in the low 40's.

What's driving that is really a -- the environment we're in, which is an environment of elevated gas prices, two-thirds of which -- our exposure to two-thirds of which are hedged, and a relatively benign service environment.

So I would have told you in the first quarter of this year, based on what we thought would happen to gas prices, we thought we would have seen an increase in drilling costs of maybe 25% during the year and there would have been no incentive to increase our rig counts.

But what instead we're seeing, particularly in the Mid-Continent, is modest increase of 3% here, 5% there, maybe totaling 10%, and we're in this rare environment, in fact, I'm not sure we've ever seen a better time to be drilling wells than right now.

We hear persistent rumors that there are larger producers getting ready to lay over a large number of rigs, which I think will put continued pressure on service costs, at least for the next couple of months as the market absorbs that.

So we just are in an incredibly attractive environment to drill wells, and we can drill wells quickly in Oklahoma from a regulatory standpoint, and our company has a big fat pipeline of prospect that we can draw from to accelerate our drilling as economics -- favorable economics present themselves.

Aubrey, have costs not risen, then, as fast as you all had maybe budgeted during the year?

I think that's true, Jeff.

We have been very surprised by how low they've been.

One thing -- I mean, I want to give a little credit here.

We are a quarter of the market, in the market in which we participate, and there's not another major drilling region in the country where one company controls a quarter of the drilling.

And so, you know, as the service companies have consolidated over the past five years to try and get pricing power over producers we can only think of our situation where we've consolidated back to have, really, we think more power over them than they have over us.

So we run a very tight ship, a very tough ship with regard to our relations with service companies.

We don't do alliances, we don't do long-term contracts.

We bid each and every well very aggressively, every line item, and we think it's reflected in our ability to keep Mid-Continent's service costs at -- low, and keep the rates of increase low as well.

Last question Aubrey.

In terms of operated wells, do you have, with the activity level you have planned for the second half of the year, where do you think you end up the year in terms of operated wells, drilled or drilling, and then what were you think whing you started the year for that number?

Jeff, I would expect we would end the year at basically where we are now.

I wouldn't expect a further increase in drilling activity in the fourth quarter from the third quarter.

So I think we'll basically stay where we are.

It looks like, you know, if you just kind of add it up, we're going to be somewhere between probably 450 and 500 operated wells for the year, of which 90-some-odd percent will have been completed successfully, and we will have spent about $550 million on just the drilling side of that, so we're spending roughly $1 to $1.2 million per well, which is a pretty good average for drilling some $400,000 wells, and some 4 to 5 to $6 million wells.

Thanks Aubrey.

Okay.

Jeff.

Thank you.

And we'll go now to John Gerdes at Southwest Security.

Hey, on Sahara, spend just a few minutes and sketch out the activity level in that area, more of a development, shallower area.

Happy to.

Sahara, for those of you not familiar, is our name for Northwest Oklahoma.

It's a little greener, actually, than that name would suggest.

Well, it's been a tough summer up there, I guess.

It covers an enormous area in northwestern Oklahoma, the better part of four counties, about two and a half million acres, and we keep five rigs active there.

Basic economics for those wells are they take about 15 days to drill, and typically we're looking for five to 600 million cubic feet of gas equivalent for a cost of, Tom, about $400,000.

It's an active area.

There are lots of other operators up there.

But what we have found is that drilling density, which when we started in that area was frequently one well per 640, or two wells per 640, and we thought maybe we could get that down consistently to 160's, we're now finding that drilling that area on 80 acres works very effectively.

And so it's an area that is really a very nice bread and butter play, and, again, we've come to create an enormous position there out of just a foothold that we acquired in 1998 through DLB and Hugoton, and neither of those companies kind of realized the enormity of the play, and through some drilling different drilling techniques and completion techniques, we've been able to make it into a gas mine and gas manufacturing -- whatever term of art you'd like to use, that's how we approached that area.

Aubrey, how much drilling have you done on 80 acre space in that area?

Obviously, that kind of a breadth of area you are talking about multi-years of inventory there.

Talking really about thousands of additional locations.

Tom, I'd guess we've drilled 20 or 30 owe

Probably closer to 50, and continue to drill that now.

What we've done is, as we have success on moving to 80's, we continue to move out kind of in 80-acre location at a time

Right.

Staying within -- close to the better wells.

So we are going to go to six rigs, two in the panhandle and four in what we call the greater Sahara area around [Winoca] and Freedom.

Do you pick up a little bit of degradation of 80 acres versus 160 in terms of the reserves Aubrey has mentioned?

We haven't seen any completions yet.

Aubrey, just a general comment.

You guys do a fine job at laying out the lay of the land.

You're going to pressure the rig market just a little bit going to 40 to 44 rigs from your 35 .

Give a sense, if you can, of kind of just the Mid-Continent rig activity.

It sounds to me like there just isn't much pressure at all on these rig rates, that's what you're indicating.

Same token I guess there's really not much downside to rig rates, either, or is there?

Well, John, first of all, we're already at 42 rigs, so we haven't moved the market to get there.

Right.

And we're not planning on going

Any further.

Couple rigs higher, so we're not going to pressure the market from here.

I would say, too, we could move up some or we could move down some, and what we really look at is whether we do pressure the market, and as long as the market lets us, we have a lot of locations to drill, and as long as the market lets us, we move up a little bit, and if it looks like we're moving prices too much one way or the other, we'll move down some.

And if you look at the Mid-Continent rig count, it bounced -- well, let me go back to the Oklahoma count.

It's bounced between king of 120 and -- for really about two months.

Exactly.

What we've done is brought a few new rigs into the area for drilling the deeper wells and, really, if you kind of go back and strip out Chesapeake, we've got, I think, 36 rigs running in Oklahoma.

So, you know, two years ago that would have been probably seven or eight, and so you could argue that the Oklahoma rig count is kind of the core rig count, the non-Chesapeake rig count, is around 100 or so, which compares to a peak of 152 in August of 2001.

So there is lots of spare capacity remaining in this state, and I presume that's why service companies' stocks are doing what they're doing.

Right.

With respect to this deep Anadarko work, you guys are as active, more active, well you're more active than anybody else.

What would you argue is kind of opening that play up for you guys?

I imagine you've got better gas pricing environment.

Is there things on the drilling technology side that you feel you have a competitive advantage on is there things on the seismic resolution side?

There's not much in the way of stimulation at those depths.

What would you argue firm specific from a competitive competency perspective is kind of opening that play up a little bit more for you guys and maybe for some others?

I think there's probably three things, the most important of which is 3-D seismic, and while that certainly is a tool that has been around for a long time, the resolution that we can see today using that seismic gives us the ability to see some stratographic complexity that I think people even a couple of years ago probably couldn't have seen.

That's helpful.

So I think it's, A, we're able to visualize things better, and we've now put together a commanding leasehold position,

Right.

And I think we've put together a commanding kind of human capital component to the story as well.

Bingo.

If you talk to any geophysical company, they will tell you that the days of shooting spec shoots in Oklahoma are over, because nobody will join us -- nobody is going to join a spec shoot that Chesapeake is a part of because they know we'll beat them by resolving information faster and because we have more people to put on it.

Most of our 3-D today is proprietary, it's more expensive but we think it has more lasting value.

Great.

It's really the combination of those three things.

That's very helpful.

Marc, a question for you.

I have a little bit of negative variance in your gas price realization.

In our models for the second quarter, it sends a trend in basis.

What do you see?

Again, congratulations on locking up some of that basis spread.

Well, thank you.

Well, the trends have been negative, actually, for the first six months of the year up until July, and July actually was the first basis shrinking in the Mid-Continent that we saw.

Basis has been as high during this calendar year as 55 cents, which was quite unusual.

Historically speaking, for the Mid-Continent.

But two things are at work.

Higher gas prices does result in wider basis for the Mid-Continent, and in 2002 we saw the potential for Rocky Mountain and other supply basins to bring gas in and actually have gas on gas competition, and that's what led us to hedge almost 650 BCF

Right.

Basis over a period of time that extends to 2009, and I think it's probably unprecedented in terms of scale and in terms of narrowness of basis.

We were hedging at around 16 cents.

Back to the current period, July basis shrunk to, oh depending on the exact pipe in Oklahoma, to between 12 and 22 cents.

Of course, prices have come down, and so basis is narrowing a little bit.

And, you know, frankly, it's weather-driven.

There's a lot of heat right now in Oklahoma, and gas is being consumed in Oklahoma rather than being shipped to Chicago where there hasn't been any heat.

Trends in the area, hard to predict, although basis of 20 to 40 cents probably would be a reasonable guess, and we're hedged at 16 for a lot of our gas, and so we'll largely avoid the hickey that most of the Mid-Continent producers could have with a 40 or 50-cent basis differential.

Last question.

You did a cap G&A number of 8.5 million for the quarter.

What would your thoughts be on a go-forward basis on capitalized G&A?

At the rig rates we're running and the personnel we've got devoted to the Mid-Continent effort, I would say the trend is up there.

Okay.

And it would -- I haven't gone and identified the personnel, but it could easily be up in the next couple of quarters to 9.5 or even $10 million per quarter.

Gentlemen, thanks for the responses.

Thank you.

We'll go now to Ken Beer at Johnson Rice.

Hi, guys.

Most have been answered, but Aubrey or Tom, you might just address, with the -- particularly the deep drilling that you've done and the type of volumes that are coming on, is there any bottle-necking within the Mid-Continent that you're seeing, primarily because of your own success, or is it still infrastructure long, gas short?

That is still the case, Ken, on a -- kind of what I would call macro basis.

On a micro basis, we are having to invest in some infrastructure.

Actually, I should restate that.

The various mid-stream companies are investing in mid-stream assets to come kind of to our rescue, particularly in the Mayfield area.

But one of the neat things about Mayfield, this was an enormous field discovered in the mid '70s.

There are big pipes running out of this area, really from all directions, to all directions, and a lot of them have a great deal of spare capacity.

So the main thing is just getting the gas to those pipes and we have had to work very closely with some mid-stream companies to get additional capacity out there.

That would be companies like Energy Transfer, which is -- bought Aquila's assets in this area, Inaject, which is a division of OG&E, and there are really a handful of companies out there.

We're pretty good planners on getting the gas out, and we're working close well all these companies to make sure we don't have bottle necks.

Thank, you guys.

We're a little bit constrained in Sahara also, but we're working on some compression issues out there with the mid-stream companies.

We've added a lot of gas there.

Thanks, Ken.

Thank you.

We'll go now to Kelly Cringer, Banc of America Securities.

Good morning.

Just two quick questions.

First on your hedge position Marc, do you know what the market to market or end amount of money on that is currently?

Last I looked, it was just about $120 million, including the basis.

Obviously, with the amount of hedging that we have -- and that's positive, i.e. a receivable from our counter-parties in total.

Obviously with the amount of hedges that we have on, a small swing gets amplified pretty quickly, so that changes day to day.

Sure.

Secondly, it's pretty clear from the comments that, I guess, Aubrey made earlier that deleveraging is going to remain a priority for you all.

And you cited the 50-50 debt to cap ratio for next year.

Have you laid that out in kind of a debt per MCFE target as well?

We've talked in terms of 55-60 cents per MCFE, and if you go through the execution of the model through 2004 with no incremental acquisition of material size, the spending, the reserve growth, reserve replacement, and assumed cash application on a net basis either in the calculation or actual debt reduction, you get to 55 cents by 12/04 easily.

It's kind of a 5, 6, 7-cent per-year move.

Actually since our beginning of the year, we've moved from almost 72 cents to 67 cents.

So in six months we've had great results but we've moved that number a nickel.

I also might mention that along the way we intend to stay about 75% proved/developed.

Right now, the industry averages about 68% proved/developed.

If we were to go to that level, we would end up adding about 300 BCFE, which by my math, would, you know, lower our debt per MCFE to really below -- to already be at the low end of our range.

And so, you know, we have a lot of ability to book [INAUDIBLE] because of the prospect inventory we have, but we have basically artificially damped that number because we want to stay around 75%.

So I'd like to you keep that in mind as well.

Okay.

Thank you guys.

Thanks, Kelly.

We'll go next to Derek Wanger at Jeffreys & Company.

Yes, I just wanted to make sure that I got the capital expenditures for the quarter correct, that spending level for the quarter.

Okay.

Was there a particular question, or did you want me to repeat it?

Did it total to 179 million?

It did total to 179 million.

And you're looking for six to six fifty for this year and next as well?

I'd say it's probably 650 this year and a range of 600 to 650 next year assuming all of the things stay the same.

Thank you.

And we'll now take a follow-up from Jeff Robertson at Lehman Brothers.

Aubrey, one quick follow-up.

In terms of the activity you're seeing in the second half, has there been much of a change in the working interest you all are keeping in wells due to some of the pooling issues?

Not much.

I would just say over the last year, generally, we have more parties participating in our wells, so, you know, in kind of increased density type wells, we may be marginally lower, but we drill a large number of what I would call grass roots wells, wells where we have put the leases together ourselves, it's exploratory, we step out, and it's the first well in the section typically we end up pretty close to 100% in those instances.

One thing, Jeff, that I would also mention, is that with the increase in overall activity in the Mid-Continent, we continue to remain a big non-op player in other people's wells, and right now we're spending about $10 million a month to participate in the wells of others at any given time, while we may be drilling 40 wells ourselves, we're probably participating in another 40 wells being drilled by other companies.

Thank you.

Ladies and gentlemen, this does conclude our question-and-answer session.

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Thank you very much.

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