Chesapeake Energy Corp (CHK) 2002 Q3 法說會逐字稿

Please stand by.

We're about to begin.

Good day and welcome to this Chesapeake Energy third-quarter 2002 earnings release conference call.

Today's call is being recorded.

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

Please go ahead, sir.

Good morning and thanks for joining Chesapeake's third-quarter 2002 earnings release conference call.

Before we begin, I need to provide you with disclosure concerning the forward-looking statements that we will make during the course of this call.

The statements that describe our beliefs, goals, expectations, projections, or assumptions are considered forward-looking.

Please note that the company's actual results may differ from those contained in such forward-looking statements.

Additional information concerning these statements is available in the company's SEC filings.

Our prepared comments this morning will last about 15 minutes.

As usual, I will provide a quick overview of the quarter, and will also highlight a couple of bigger items.

I'll then turn the call over to Mark, and that, we will be happy to take your questions.

In overview, our third-quarter results were very strong.

On a recurring basis, Chesapeake earned $21 million, or 52 cents per fully diluted share on an annualized basis.

In addition, we generated cash flow of $102 million or $2.16 per fully diluted share on an annualized basis, and generated EBITDA of 130 million, providing interest coverage of over 4-and-a-half to one.

These strong results were driven by record quarterly production of 47 BCFE, which was our fifth consecutive quarter of sequential production growth, our fifth consecutive quarter of reaching a record production level, and our fifth consecutive quarter of exceeding consensus production expectations.

This quarter's oil and natural gas production was up 14.4% over last year's third quarter, and 7.5% over this year's second quarter.

Consistent production growth continues to distinguish Chesapeake from the majority of its peers. 2002 will mark our tenth consecutive year of production growth as a public company, and our 13th since the company began in 1989.

For 2003, we are projecting another strong year of production growth, up about 7% to a range of 190 to 195 BCFE.

At the midpoint of that range, we would be producing 527 million cubic feet of gas equivalent per day, on average, and we plan to exit 2003 at a production level of not less than 540 million cubic feet of natural gas equivalent per day.

During 2002, we were able to raise our production guidance four times, and we hope to be able to raise 2003's guidance on multiple occasions as well.

We consider this guidance to be conservative.

As usual, our production gains were balanced this quarter across all of our major operating areas.

However, in particular, in the deep Anadarko basin, we continue to do especially well, particularly in the deep Springer play, surrounding our Comanche lodge prospect.

Accompanying this impressive growth in production has been an equally impressive increase in our proved reserves.

We started the year with just under 1.8 PCFE, improved reserves, and after the third quarter, we now have 2.2 TCFE, representing reserve replacement of more than 3 to 1.

Assuming 2 to 1 reserve replacement in 2003, we expect to exit next year with at least 2.5 TCFE and, depending on how the acquisition market plays out, we could end up well north of that number by year end 2003.

In addition, we believe we own probable and possible reserves that exceed 1 TCFE, so by year end 2003, we should have a total corporate resource base of more than 3.5 TCFE.

In addition to the large size of our reserve base, we believe Chesapeake has the most focused of any large producer in America, with 90% of our reserves consisting of natural gas and 90% located in one region, the prolific and highly profitable Mid-Continent.

Mid-Continent is the third largest gas supply basin in the U.S., and Chesapeake is the region's number one gas producer.

As the largest gas producer with a 7% share of production, and with an unprecedented 40% interest in current Mid-Continent drilling, Chesapeake has built economies of scale that are extremely valuable and will be almost impossible to replicate by anyone else.

I would also like to point out that during the past three years, our track record of production and reserve growth has been among the top three in the industry.

To remind you, in the third quarter of '99, we reported production of 33 BCFE compared to this quarter's 47 BCFE, and proved reserves of 1.2 TCFE compared to this quarter's 2.2 TCFE.

So in the past three years, we have increased our production by 43%, and our reserves by 86%.

During this same three years, many of our industry's largest and most highly regarded U.S. gas producers have experienced very different results.

In fact, you might be surprised to know that a company the size of Chesapeake has disappeared inside of Exon during the past three years.

You also might be surprised to know that today we produce almost as much U.S. natural gas as Apache does.

Furthermore, we see no sign that our industry's production problems are coming to an end.

This quarter marks the 17th out of the past 22 in which the industry has suffered a sequential production decline in U.S. natural gas volumes.

We see no signs of those declines abating, because they are significant, they are structural in origin, and there is no way to fix them anytime soon.

The truth is that to be growing production today,

you had to be building the foundation for that growth 3 to 4 years ago.

We believe the record shows that chess a beak was one of the few companies during the industry downturn of '98 and '99 that took the actions necessary to get ready for the gas shortage of the winter of 2000/2001 and for the next gas shortage which we believe is likely to occur in either 2003 or 2004.

In the meantime, we expect to keep growing our production and reserves, and we expect continuing gas price volatility.

As discussed in the past, we welcome volatility, and believe we are well prepared to convert it into opportunity.

The second topic I'd like to highlight today is our hedging plan for 2003.

Let me remind you that today, our oil production is 100% hedged in the fourth quarter at a NYMEX price of $25 per barrel, and we are 100% hedged in all of 2003 at an average NYMEX price of $27.80 per barrel.

We have only recently begun to hedge our 2003 gas production because we wanted to wait for gas markets to strengthen.

Once the concerns of a gas glut went away, we were confident that gas prices would respond to improving underlying supply-demand fundamentals.

It was good to wait and not hedge defensively at lower prices, as many other companies did earlier this year.

For the fourth quarter of '02, we are 50% hedged at a NYMEX price of $4.47 per MMBtu, and for the first quarter of '03, we are 72% hedged at a NYMEX price of $4.12.

We are unhedged for the remainder of '03, although we do have about $10 million in gains already locked in from '03 gas positions entered into during the winter of 2000/2001 and lifted late last year.

We expect to enter into additional hedges later in 2003, as gas markets play out, again, with -- with the underpinning of better supply-demand fundamentals.

As we have said on many occasions in the past 18 months, the dye die is cast for the next big run in gas prices.

Given the persistently low rig counts of the past six months, we expect gas supplies to continue falling in 2003.

Keep in mind that the major supply, about a third of all U.S. gas, in their production is down about 15% in the past two years.

Large and mid-cap public independents produce another third of the U.S. gas supply, and their track record isn't much better than the majors.

That leaves small public independents and private independents with their third.

For them, capital is harder to obtain these days, hedging is almost impossible, and the cost and sophistication of exploration is beyond many of their abilities.

We expect their production to continue declining as well.

We see little that can change this picture.

Are the majors capable of growing their U.S. volumes?

Why would they want to?

We believe they are rightly playing a global gas game, not a U.S. gas game.

That leaves the independents, both public and private, to increase production, a task we have not been up to in the past four years and one we're not likely to be up to in 2003 as well.

Therefore, we believe supply will continue to fall in 2003, and barring an economic collapse and an accompanying significant loss of investor gas demand, we believe higher gas prices will be required to force demand to fall in lock-step with declining supply.

Any significant help from LNG appears to be two to three years away at best.

In addition, arctic gas seems further away today than it did two years ago.

So we don't expect to see an arctic pipeline until 2010 or so.

In summary it appears to us that gas prices will remain volatile but should average above $4 for at least the next few years.

We have positioned Chesapeake to prosper in exactly this kind of environment.

Our goal for 2003 is to continue delivering value to our investors.

Growth in production and reserves, improvement in our balance sheet, growth in per-share earnings, growth in dividends, and growth in our stock price.

I'll now turn the call over to Mark for his more detailed commentary on our financial results and outlook.

Thanks, Aub and good morning, everyone.

I believe certainly pleased today to comment on another quarter of very strong operating and financial performance.

On the reserves side, as Aubrey mentioned, total proved reserves have increased to almost 2.2 TCF equivalent.

The developed reserve component of this at this time is 72-and-a-half percent of total reserves.

We are 90% natural gas and to review the areas of our reserve growth, let me say that the Mid-Continent now comprises 87% of our total reserves.

The Gulf Coast region, Encompassing both Texas and Louisiana, is 6%.

Our Permian reserves are 5% of the total.

With the Williston and miscellaneous other areas filling in 2%.

Our long-term debt for proved MCF equivalent fell to 70 cents as of September 30th.

While we are posting very strong positive book earnings, our book equity has not increased in direct proportion.

I would call your attention to our 10-Q this quarter, which will be filed this week.

Please look at the comprehensive income section in our mark-to-market hedging positions which have negatively affected the growth in our book equity.

These ultimately will reverse themselves and strong book equity growth will result and follow our book earnings.

We continue to react to offers from owners of our seven and seven-eighths notes due March '04 and have now purchased nearly $90 million of those notes in the open market, leaving just $60 million outstanding.

Our average purchase price to date has been just over 103.

As of September 30th, looking back, there were $87 million outstanding at that time.

So obviously since September 30th, we've continued to purchase these notes.

When this issue of notes is retired, the company will have no debt maturities due until 2008.

I comment on this because I want to emphasize our strong our liquidity position remains.

We have just amended our revolving bank credit facility to increase the size of the facility to 250 million, and are in the process this week of extending the maturity date to June 2005 from 2003.

Examining our natural gas price realizations for the quarter, we saw basis differentials remain in the wide end of our Mid-Continent historical range, averaging a negative 37 cents for the quarter as compared to Henry hub.

We have seen that differential improve slightly in October to 35 cents, and significantly in November, where our basis has now been reduced to only 7 to 10 cents behind Henry hub posting for the month of November.

Our capital expenditures for the quarter totaled 300 million, broken down as follows: Acquisitions were 175 million; drilling, completion, capitalized work-over costs were 110 million; other adjustments, miscellaneous, and capitalized costs, were 15 million, to total 300.

Of the drilling costs, approximately 90% of our expenditures were in the Mid-Continent area, 5% in the Gulf Coast, and 5% in the Permian and Williston Basins.

Capitalized costs, including the capital expenditures breakdown just given, were, for the quarter, interest 1.3 million -- and that's running about the same rate for the fourth quarter and in fact year-to-date has been 3.6 million, so you can see that has not changed -- internal capitalized costs, including G&A were $2.5 million only for the third quarter, year-to-date 7.8, so the rate of capitalization there is unchanged as well.

As we look at production for the quarter, the mid-continent volumes were 39 BCF or 84% of the total volume, and about the same on value.

Gulf Coast was 5.1BCF equivalent or 11% of the volume and value.

Permian was 1.7 BCF equivalent for the quarter or 4%.

And our other areas were just under 1 BCF for about 1% of the total value.

In this quarter, virtually all of the quarter's production growth over last quarter came from our acquisitions that were completed during the quarter.

While this was not true in quarter 1 and quarter 2, since we made no acquisitions during that time, and all of our production came from organic drilling growth, in this quarter, as we expected, most of the production came from our acquisitions.

Production increases.

In fact, as budgeted, we exceeded our expectations both in the drilling and the acquisitions side.

This goes in cycles for us, as significant wells that require long drilling periods are added, then decline while new wells are being drilled.

For Quarter 4, the quarter that we're currently in, all of our gains are projected to come from newly drilled wells that we've added.

We saw slight improvements in cash cost per MCF equivalent, with production expenses at 53 cents per unit, production taxes of only 15 cents, and G&A dropping to 8 cents per MCF equivalent for the quarter.

This is a total cash structure of just 76 cents.

This represents a 7-cent improvement from our second-quarter results, or a decrease of about 8%.

When you compare this to $3.49 revenue recognition per unit and yielding a pre-interest cash margin of 273, we analyzed this as a significant highlight of the benefits of our hedging strategy and the focused approach to our Mid-Continent acquisition, exploitation, exploration, and extension strategy, that we are pursuing.

Even with the inclusion of interest at 61 cents per produced MCF equivalent, our all-in cash operating structure is just $1.37 cents.

Extremely competitive with our peers and other investment alternatives, we believe.

Service costs remained at about the same level as last quarter with drilling rig costs virtually unchanged.

I think this fact is important, given our counter-industry strategy of investing more in the inevitable down part of the cycles and reducing activities in the high-revenue but very high-cost periods of the cycle.

For example, today Chesapeake is operating 25 rigs out of about 850 total rigs running nationwide.

That is 2.8% of the total rig count.

Contrast that with a year ago when service costs were at least 50% higher.

Chesapeake was operating only 15 rigs out of a thousand 63 running nationwide, or 1.4% of the total.

We've increased our margin of total market share by 100%, to take advantage of the low drilling costs.

We think this is a great example of how we can use our large five-year drilling inventory, which is largely held by production, and the forced pooling laws of the state of Oklahoma, to allow us to vary our activity to improve full-cycle returns.

Let me comment on our Seven Seas investment.

Late last week, Seven Seas announced that they had arrived at an agreement with Chesapeake and the senior secured note holders to return part of the money in a voluntary prepayment.

That was accomplished last Friday, and we collected approximately $4.6 million out of the total $45 million outstanding, or about 10% of our investment.

At this point in time, Seven Seas is marketing their shallow [Guaitos] field, and we expect bids to be in on that field in the next week or so.

At that time, our understanding is that Seven Seas will proceed toward a sale of the [Guaitos]field that is likely to close in December or early January.

We are hopeful that the rest of our investment will be returned with interest at that time.

I'd like to conclude my remarks with a brief review of our acquisition activity.

Most investors that follow our company are aware that we are focused on strategic acquisitions in the Mid-Continent.

We have closed several larger transactions since June 28th when we closed on the Caenen merger.

In five transactions, we have invested about $300 million, acquiring 225 BCF equivalent of proved reserves.

With other assets acquired, all-in costs were about $1.30 cents per MCF equivalent.

Two points to make about these acquisitions.

These acquisitions were constructed in the $3.50 cents price environment and we are now in a north of $4 situation.

Obviously improving our returns beyond stated expectations at the time.

Second, all of these acquisitions are now fully integrated and nearly $10 million of general and administrative costs that was previously attached to these properties has been eliminated.

What is probably less known is our unique group of A and D professionals that focus on consolidation of non-operator working and royalty interest every day.

Apart from the five larger transactions that we have previously announced and I just discussed, so far in 2002 we have acquired about 17 BCF of proved reserves in 165 separate transactions at a cost of just 70 cents per MCF equivalent.

Not only are the preliminary economic metrics great, but these are value added in the sense that no G&A is added and nothing is built in for the additional drilling opportunities that we are adding every day.

I'd like to turn it over to question and answers, moderator.

)) OPERATOR: Thank you, sir.

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

If you'd like to ask a question, please signal by pressing the star key followed by the digit 1 on your touch-tone telephone.

If you are using a speakerphone, please make sure that your mute function is turned off, to ensure that your signal reaches our equipment.

Again, that is star 1 to ask a question.

We will come to you in the order that you signal and we'll take as many questions as time permits.

We'll pause for just a moment to assemble our roster.

We'll take our first question from Adam White, Credit Suisse First Boston.

Good morning, guys.

Hi, Adam.

Hi Adam.

I don't know if the website is conveniently down or not, but I can't get in.

I just want to get some (a) update on some of your cost guidance.

It loose like it's coming in lower than previously expected.

Can we anticipate that you'll continue to see those benefits?

And then second of all, on the borrowing base on your new loan agreement, what might that be?

And is there any restrictions other than that?

And then third, in terms of your hedges, your recent -- recently-added hedges?

Okay.

Adam, we're checking on the website.

I don't -- it's not conveniently down.

It would be inconveniently down, so we're checking on that now.

Three different questions.

First of all, cost guidance.

Production costs are down a little bit in the quarter, and are below our current expectations for next year.

Frankly, we're trying to guess a little bit about the impact of several items.

Production cost increases for next year would come in the form of principally labor cost increases which are benefit -- benefit cost push.

Healthcare costs, workmen's comp, and general liability costs are up for us.

We're just getting renewal quotes in, and I -- I think this is not unique to the oil and gas sector or certainly our company.

Health costs are running 20 to 30% year over year, general liability costs, workmen's compensation, insurance costs in general, are all up.

As we look forward to next year, and our expectations that we will have higher prices in December of this year than we did last year, and for all of next year, let me remind you that ad valorum taxes, which in Texas and Kansas are based on wellhead prices once a year, will be higher.

And typically those range from 2 to 3% of the value associated with the well bores in those areas, and when the prices are up, values are up, ad valorum taxes are recorded by us and I think most everyone else in the industry as production costs.

So as we look forward to next year, I've projected about a 10% increase in operating cost.

I hope that that's conservative guidance and we won't see the full part of that increase, but still, I -- I don't think we can maintain lifting costs in the low .$50 range.

G&A should be about the same for next year on a production basis.

Our production, we think, will increase about the same rate as our cost of G&A increases.

Turning to our borrowing base, you asked, I think, two questions there, Adam.

First, are there any restrictions on what our borrowing base is, and the answer is no.

It will be the full $250 million that's allowed under our face.

I believe, our current restrictions under our indentures would allow a secured borrowing base carve-out of around $380 million or so.

Nothing unique about the amendment to our bank facility.

Our previous bank facility had a reduction for the 150 million of 7 and 7/8 notes that remained outstanding after the summer of '03.

That now has been lifted and in fact we'll have nothing in our bank agreement about the 7 and 7/8ths notes which now stand at $60 million.

And to reemphasize, our maturity is being extended this week to June of 2005.

The terms of the hedges that you asked about, the third question generally that you have, our gas hedges that we put on are all straight swaps.

They're principally done with -- in fact, the most recent hedges have been exclusively done with Morgan Stanley, who remains our central counter-party, and those straight swaps are just simply put.

We have established a fixed price that we'll receive from them on a paper basis, and if the NYMEX closes above that price, we will pay the counter-party the difference, and if it closes below that established price, the counter-party will pay us.

So nothing unusual or distinctive about those swaps at all.

Adam, I might chime in.

I just got on our website, and started to listen to the webcast, so maybe there's a problem at CSFB.

It doesn't appear to be here.

I just couldn't get into the outlook page.

If I may follow up just you're talking about low service costs.

Are you planning on increasing your activity level, given what you're seeing?

No.

We have been running a rig count that varies between 23 or 4 and, you know, the high 20s maybe 30 rigs.

That's at today's service cost resulted in about $100 million per quarter of expenditures.

That's what we've got budgeted for the fourth quarter, and when you do get on our outlook, you'll see that's what we've got budgeted for the run rate for all of 2003, so there's no change anticipated either in amount of expenditure or in activity level.

Great.

Thanks.

Thanks, Adam.

Thank you.

We'll take our next question from Phil Pace with Credit Suisse First Boston.

Good morning, guys.

Aubrey McClendon Hi, Phil.

)) Shouldn't have to talk to two us from the same firm, huh.

We're always happy to.

Different issues.

Could you give us an update on the activity in the deep Anadarko and what reserves are recognized there versus upcoming completions that could impact that total?

I can talk to you about current activity out in that part of the woods.

We've got 25 rigs running right now.

I believe nine are running below 15,000 feet in the Anadarko basin itself.

I'm trying to think if we have any rigs -- probably have a couple of rigs in the 14,000-foot range but most of those nine would be really in what we call the deep Anadarko portion of it.

I'd say the most pleasant surprise of the quarter has been what we've been able to accomplish with the Springer around Comanche lodge, just to bring everybody up to speed.

You'll recall in our July conference call, we announced the results of our Cat Creek well.

That well is still making about 6 million cubic feet of gas per day from the upper Hunton, which is kind of a stray zone in this well.

We are waiting to bring on the middle Hunt on, which is the main pay zone in that area.

We have recently reached a gas infrastructure deal with Exon in the area that should enable us in the next 60 to 90 days to bring on that middle Hunton zone, so we're eager to do that.

On the other hand, we drilled a couple of pretty significant wells offsetting the Comanche lodge area, our Treva well is -- is one mile away and 8 million cubic feet of gas per day.

We have another well 4 miles away that looks like a significant discovery that is not yet completed.

So very excited about the Springer out there.

Hunton still looks very good to us.

And I would say that right now, if you talked to our geologists, they would probably think that the Springer has as much potential as the Hunton out there, which is a significant upgrade from where we were in July.

We have immediately in Comanche lodge, I think we have three rigs.

We have two -- we have one hunt ton well drilling a will called the Plunk.

That's about 11,000 feet going to about 25,000 and -- and have three Morrow Springer rigs working out there as well.

Adam, in terms of reserve booking per area -- I'm sorry.

Phil.

Either way.

Sorry, sorry, sorry.

I don't have those particular numbers and I don't think any of us have them that specifically.

If it's important to you, I'm sure we can dig it out and get back to you, but that's an area where we drill quite a few wildcats, and so would expect to see continuing nice reserve adds in that area.

That's a good update.

I appreciate it Aubrey.

Okay.

Thanks, Phil.

Oh, Phil, just -- let me throw -- chime in there.

We've got -- Tom just slipped me a note.

Of the -- in addition to having nine rigs below 15,000 feet, we have another 4 rigs that are at 13,000 feet and below.

So, you know, I don't know where El Paso is in their program these days, but typically we're kind of 1 and 2 in terms of average depth drilled across the country, and I imagine that would still be the same today, so deep gas exploration continues to be the main exploration and development focus of our company.

And we'll take our next question from Mark Meyer with Goldman Sachs.

Good morning.

On the fourth third-quarter acquisitions, 125 B's, do you have a PUD split?

Mark, I don't have the PUD split immediately but it's about 70% developed and 30% undeveloped.

It's within a couple of points of that.

Are most of the PUD's tied up in the new drill sites or do you have some behind-pipe stuff there as well?

I'm sorry, I missed the question.

Yeah, I'm not sure I understand the question either Mark.

I mean, what is -- what is -- I'm kind of trying to get an incremental cost to bring those PUD's forward.

Is it mostly in fills or --

What area are you talking about?

You know, the largest ones, the en can a and --

Oh, acquisitions?

Yeah.

The future development costs of those things is going to range, and most of it is infill development versus behind pipe, so to answer your question specifically, the undeveloped portion would all be virtually new drill opportunities.

Okay.

And, you know, our planning and development cost without acreage or without seismic or anything else in these areas -- and most of these are reasonably shallow -- are going to run 90 cents to $1.05 or so on the development cost.

So that would be the future development cost to bring those reserves into the proved developed category.

Okay.

Thanks.

One other question.

Aubrey, you had, I think, had a very clear demand view that you articulated back in the early part of 2001 as being a significant motivating factor in locking up a fairly significant chunk of your gas production.

As you look into '03, your unhedged physically through the end of the year from second quarter.

What kind of demand tolerance do you see out there?

I suspect you see some up side from where we are now, in looking for a higher opportunity.

Can you -- can you give me some thoughts on demand as to -- as to where you think we can go?

Sure.

We'll give you how we think about it.

First of all, the supply side is much easier for us to figure out, so we spend the majority of our time concentrating on the supply side.

We, like you guys, watch our competitors like a Hawke to see how their numbers are coming in and really no real surprises this quarter as well. reported already convention alley down about a percent, and year over year, 5 to 6%, depending on how you count.

We also watch the private companies that we're aware of here in Oklahoma, and we think they're in probably worse shape than the public companies from a supply perspective.

And so then when we feel like supply is locked in and these decline rates, we also look at the rig count, and, you know, what I think I find most perplexing about earnings' season is all these companies that report production declines, the next quarter and the next year, they're going to have production increases and frankly, analysts and investors get behind them and say, "Yeah, you know, we agree."

The reality is, if you're not drilling a lot more than you were drilling a year ago, you're not going to generate a production increase in 2003.

It's simply not possible.

And so we find it remarkable that all these projections for higher gas supply in 2003, based on company's projections, which frankly are never met by the industry as a whole.

So that's the supply side we can always count on it, basically, to disappoint.

Demand, as you know, is much more difficult, and we don't know, but know that -- I mean, here's what we think we know, which is gas above $5 tends to impact supply -- rather, gas prices above $5 tend to impact supply quite a bit, but we do think -- I need to say demand.

Sorry.

But we also think that every cycle that you go through, you've probably knocked out some more of the price-sensitive demand and we would hope the remaining consumers would be more resilient, and we also hope that volatility is giving consumers a chance to hedge as well and they can ride out some of these spikes as well.

So our consistent view over the last three years has been that we're in a band of higher highs and higher lows, and lots of volatility, and the un-knowable is, in an economy like we have, with oil prices that we have, how much supply -- how much demand, rather, do you lose at $4, 4.50 and 5, and that's un-knowable to us, but we know that supply will be down and hope that demand can hang in, in that 4 to 5-dollar range.

So we've -- overall, we view that some demand has to go away because supply is going away, so it's got to be in balance at some point.

All right.

Thanks.

Okay.

We'll go next to Ellen Hannan with Baer Stearns.

Good morning.

Just a couple of questions that haven't been answered.

One, Mark, on your hedging, your oil hedging for next year, it looks like you're hedging more than you're anticipating producing, or are you just hedging on your guidance there?

We're probably conservative on our guidance, Ellen.

We actually, on our internal forecast, have hedged exactly 100% of our projected volumes for next year.

Okay.

I would say that we are in the process of examining divestment alternatives for the Permian Basin, which is -- is quite a bit of our oil production, and that if we accomplish what we hope to, which is a trade or sale of those assets by the first quarter of next year, we'll be pulling off some of those oil hedges that are currently in the money that go along with that.

Okay.

Fine.

Secondly, you may have answered this question or someone indirectly, of the $175 million worth of acquisitions closed in the third quarter, what do you -- what's your continued development costs that go along with those?

We -- I think we probably indirectly answered that, but the answer is, in most of those acquisitions -- talking about this quarter specifically -- the Caenen acquisition, for example, is sort of a lay-down to the focus, and both of those properties are all centered in the Mid-Continent and the development that comes with that are going to be infill locations, not behind pipe.

Okay.

To drill one of those wells -- and generally you're talking about a 7 to 12,000-foot kind of well -- we are spending, excluding any acreage costs or any seismic or -- just looking at the direct infill drilling cost -- 90 cents to a dollar or $1.05 cents per MCF equivalent.

Okay.

Ellen, another quick way to get it is basically the Caenen and the four acquisitions we did, it was about 230 BCFE or so.

About 25% PUD.

So that's, you know, basically 55, 60 BCFE times the dollar or so that Mark talked about so you'd be adding 55 to 60 million to the overall cost of those acquisitions, which was about $300 million.

So we -- when we do our math, we include future development costs to get to a full -- an all-in cost of around $1.50 per MCFE, fully loaded for Mid-Continent reserves.

Okay.

Fine.

Another question.

You didn't -- you may have alluded to this when you were answering Phil's question earlier about -- I know that you've had a couple of very nice wells in the cement area, particularly in the Snowball and the Della.

I wonder if you'd update us, if you've got anything else going on there, and I think you were drilling another deep well in the Bray area that you thought was an analog.

Let's see.

In cement, Tom, we've got the Estes and what other --

Navotney and the Farris.

We have three wells drilling in the cement.

And those are on average -- well, one's going to 15,000 and I guess our deepest is 20?

Right.

It's sixteen five to twenty.

Twenty.

So three deep wells in cement.

None of those are -- well, I guess those are probably 30 to 60 days from TD.

It's -- things run in cycles (inaudible) production gains for the quarter.

And then in terms of Bray, we do have a well down and logged there.

That's the Kovar.

We think we have a discovery that's going to set up more acreage for us in that area, and I think we'll start drilling our next well in that area within the next --

It's started.

It's already started.

The name of is the Baughn, B-a-u-g-h-n, a few miles away from the --

That's also a twenty three five.

)) And that's also a twenty three five hundred foot well and I think the last time I checked with our Plunk well going to 25 and the Aughn at twenty-three five-I think those are the two deepest wells in the country right now being drilled.

And both of those are going for the Springer?

Yes, although they are -- oh, gosh, over a hundred Myles away from each other.

Okay.

Lastly, and then I'll stop.

You talked about two offset wells at Comanche lodge, one being the Treva, I believe.

This producing out of the Springer or the Hunton.

It's a Springer well.

It only went to the Springer well, and -- I'm sorry, it only went to the Springer and it is producing from one of the Springer members.

Okay.

Great.

Thank you very much.

Okay.

Thanks, Ellen.

Looks like our next question is from Van Levy with CIBC World Markets.

Good morning.

Hi, Van.

How are you?

Good.A couple things.

Could you break out the budget this year and next year between acquisition, development, exploration, and land?

The budget numbers that we gave you at 380 to $400 million does not include really any significant acquisitions, just our recurring normal acquisition program would be added on top of that.

As you know, we don't budget for any major acquisitions, and so it's those, you know, five to $10 million per quarter of miscellaneous small acquisitions that typically end up adding 30 to $50 million of budget per year.

On the detail of the $380 million budget, $325 million of it is actual drilling expenditures, which would include capitalized work-over.

How does that break between development and exploration?

That's about 65% development expenditure and 35% exploratory.

The 35% exploratory, though, would be counting the final target, the deepest target, and so while it sounds like a fairly high amount of exploratory or riskier drilling, if you will, the fact is that we count exploratory as being the final reservoir target and so if you're in the deep Anadarko , for example, headed to a Hunton zone and you've got five different members of some other zone above you, we're counting that as exploratory when, in fact, many of those wells, if unsuccessful in the deeper horizon, are re-completed in the shallower zones and I guess could be counted as partially developmental.

Added to the 325 of drilling expenditures, then we have budgeted $30 million for leasehold, and about $25 million for seismic, to get to the $380 million number I -- we talked about.

In your release, you talk about 75 million, I think on seismic over the next 12 months.

How is it broken out between the fourth quarter and next year?

That's land and seismic.

Yeah, both.

And so it's running about the same rate, and a lot of that would be processing of seismic that's already been shot.

Tom, we have three acquisitions in progress?

Or two at this moment?

Or more than that?

Oh, we have -- we have a lot in -- in line.

I think we're actually working on two right now.

Aubrey McClendon Two we're shooting -- acquiring new data and then we've got several that are coming on-line.

Okay.

And again, in the year 2002, roughly what is your acquisitions been year-to-date?

Year-to-date, acquisition expenditures, let me get you that.

I do have that number here.

Sort of at my fingertip.

And again, if you can break out between development and exploration.

While you're doing that, let me ask --

Break out between development and exploration?

Capital expenditures.

On acquisitions?

No.

On drilling.

I'm just trying to get the budget by the --

Aubrey McClendon Oh, the acquisition -- I mean, the drilling is real easy.

We talked about the '03 number.

The '02 number is no different.

We're 65% developmental, 35% exploratory.

I'll let Mark answer the acquisitions side of it.

Our total acquisitions to date, van -- and this is through September 30th and is for nine months -- is $311 million.

Okay.

And that's going to be principally the $175 million that we talked about this quarter and then add the Caenen acquisition, which was closed June 28th for another 125 million, and then prior to that time, there were virtually -- well, there were no large acquisitions at all, and just a few million dollars of small acquisitions.

Okay.

Another question.

You talk about organic growth versus acquisitions.

Can you break out the number of wells that you plan to drill this year and next year, both by shallow and deep, and this year give us a sense of -- of what percentage of your production growth or million cubic feet a day, et cetera, was really organic.

And one other thing that I'm driving at and I hope you can address, obviously as you go deeper, this is, you know, pretty risky stuff, you know, challenging drilling, et cetera, versus what appears to be a very successful acquisition program, a lower-risk program.

How do you balance that in terms of risk-reward and predictability?

Okay.

Let's see how we can attack this.

First of all, I'll talk about our ex- -- our capex program for '02 and '03, both years about the same, and both years contemplate drilling about 300 wells.

About 40 of those will be exploratory, about 260 are developmental.

So obviously in a well count, exploratory is well below the 35% we talked about, but obviously the exploratory wells tend to be much deeper than the developmental wells.

I hope that that got to the part of your question about the number of wells that we budgeted for and are required to take -- to go forward with our program.

Van, on the acquisition versus exploratory or drilling side of things, I think the best way to think about that is just to look back since 1998.

About $2 of acquisitions have been made for every dollar of drilling, and as I prepared the last slide that analyzed this, I think our acquisition cost in those four-and-a-half years was just over a dollar and a penny per MCF equivalent for that entire history, and that -- at that point -- I think was about $1.7 billion of acquisitions.

During that time, we drilled about $800 million of drilling, and our all-in cost on that was about a dollar and 15 cents, as I recall.

I don't see that really being too much different going forward.

We are focused on acquisitions that are focused, again, on -- in the Mid-Continent, and while we don't budget for -- and it would be un-budgetable for major acquisitions, historic -- historically we are spending about two dollars of acquisition for a dollar of drilling.

Then that dollar of drilling is about 65 or 70% developmental.

I think one other question maybe Aubrey didn't talk on was the split between shallow and deep wells.

The ultra-shallow wells that we're drilling in the Sahara , compared to the rest of our program, range from 70 to 90 or so per year out of that 300, so you kind of take about a third or 30% off the top, which are just statistical shallow wells where we're routinely running three or four rigs at a time, and those wells are drilled every 15 days.

The remaining 200 wells are split across the rest of the Mid-Continent.

Okay.

Last question.

Obviously, you're sanguine on gas prices for the last three quarters because you're unhedged.

What happens to your crystal ball if peace breaks out in the Middle East and oil prices decline to, you know, $20 a barrel?

What happens to the gas prices?

Well, at the margin, we'll lose some demand to oil, there's no doubt about that.

But that scenario is not likely to increase the rig count.

And nor is it likely to have any impact on gas supply.

So the question will be, will gas demand go down faster than gas supply, and our view is that it probably will not, and, in fact, I'm not sure we would be against a decline in oil prices.

It certainly would help the economy, which helps gas demand.

We're hedged at almost $28 a barrel in '03, so in our crystal ball, that would not be a bad outcome at all.

I'd also like to say that we anticipate being able to have some of our last three quarters of '03 production hedged.

We think we're going to have several opportunities between now and the start of the second quarter to have some of that hedged.

So I know that there was a lot of anxiety in our July call that we had not hedged anything in '03 and really were not very much hedged in '02, but we asked everybody to be patient and let some things play out, and they did, and I think we captured what I've seen to be the highest hedge prices of anybody in the industry right now, and I suspect we'll get a chance to replicate that in the past -- in the last three quarters of the year as well.

Thanks, and congratulations.

You've done a fantastic job on the hedging side.

Thank you.

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

Whoa.

I think you've answered a lot of those questions.

I do have one question for Mark left over and that is on the basis differential.

If I remember, Mark, I think it was last quarter that you put in a basis differential hedge kind of like '03 to continued of '04, '05, for about 15, 16, 18 cents, something like that.

Is that almost all of your production, a good part of your production?

Just remind me as to what the structure of that deal is is?

Yeah.

Ken, we're taking a very long-term view with regard to basis, and starting in '03, and actually going through '09, we've locked in basis on most of the pipes that we produce in the Mid-Continent between 14 and 16 cents negative to Henry hub.

In terms of volume, it varies by year, but generally is not more than about 40% in the first two or three years and then declines, frankly, to, you know, 20% in the out years.

We continue to monitor basis.

The liquidity in the basis market for the long-dated contracts is pretty thin, and so it's sort of a -- I won't say one-off necessarily, but it really is a -- almost trade by appointment situation, and we periodically are looking to put that on.

If you look back in the last two or three years, basis in the Mid-Continent has been in the 15-cent, plus or minus, on an annual basis, but actually is fairly cyclical through the season.

Basis tends to widen in the summer months and narrows in this part of the year, and this month is following that trend.

As I mentioned, I think the least basis in the Mid-Continent for any of the four pipes that we follow is about 7 cents this month, and the largest basis is only 10 cents, so a significant improvement for us for this month.

Okay.

Did that get to the --

Yeah.

And I'm assuming what you're talking about going forward is just having that constant throughout the year, as opposed to following the cyclicality during the -- I mean the seasonality during the year.

That's right.

Okay.

We are approaching it from just having it be the same all year around.

Gotcha.

So we might -- you know, if basis doesn't move at all, which would be great, we'll be a few pennies off and a few pennies to the good at different times of the year.

But this is sort of a -- I look at it as a no-cost insurance policy.

If basis just remains at 14 or 15 cents for the next six years, great.

We haven't benefited but we've received great margins relative to most of the country's production, and I guess that's why the counter-parties are willing to do that.

But if, in fact, additional gas comes out of the Rockies, pipelines get built from Canada or wherever that cause those gas on gas competition to affect the Mid-Continent like it did this past summer, then we've protected ourselves with no cash cost.

Fair enough.

Thank you, guys.

Okay.

Thanks, Ken.

We'll take our next question from Stephen Smith with Stephen Smith energy.

Good morning.

I have two questions.

One is you -- Aubrey, do you notice any change in the competitive environment in the Mid-Continent?

Larger players that are trying to get a little bigger position or get out?

Just kind of a general competitive environment.

Okay.

You want to give me your second question also and --

Yeah.

Second question relates to of the 40 exploration wells drilled this year and next, how many of those are Springers and also just a bit of the economics of the way the Springer is looking right now, probability of success, cost of the well, and target size.

Okay.

Let me take the competitive environment.

You know, this is a real interesting area in that the dynamics of it are shaped by a basin that's been in decline since 1985.

Production is off about 20% over the last 16 years.

And basically declines about 1% a year.

The bad news for that is it -- you know, it's not a basin that investors tend to associate growth with, as they do, say, the Rockies or Canada or even some parts of the Gulf Coast.

And I think that hurts us a little bit, because we've got a growth program in a declining basin and I don't think people are able to reconcile those things as easily as we would like.

It's also a basin that provides tremendous profitability, long-lived gas reserves, and so we think it's a -- maybe on a full-cycle basis, the best place to be in the country.

That has attracted the attention of some other producers.

You know, you've seen a number of Gulf Coast guys decide they need to further underpin their foundation in our area here in the Mid-Continent, probably New Field is the most prominent of those who have made a play here.

You saw maybe -- maybe some of you saw Petitino last week acquired a Mid-Continent oil producer that we've known pretty well for a long time, so I

suspect that there will be more mid-caps to small caps showing up here and trying to build a beachhead.

I think it's incredibly difficult to do.

The land gain here, I think, is at least 50% of your success, maybe a little more.

Geologically, if you're going to have any exploration success, you have to have a huge 3-D inventory and we've got that uniquely.

So I think there will be some people come.

More importantly, I think there will continue to be people leave, and this is the majors, I think, will continue to disengage from this area.

Not that it's unprofitable for them but just they just sit here and let people drill wells next to their acreage and kind of slowly drain their reserves.

So we think there will be additional acquisition opportunities, and also from private companies as well, who maybe thought about going public in years past and today just don't have that avenue.

With regard to your second question, on -- on say 40 exploratory wells, about half of those wells would targets the Springer formation in general within the Springer.

Keep in mind, there are five or six different sand packages in that overall Springer section that we are targeting, and it's a different -- in a different structural position and with different stratigraphic qualities in Cement versus Bray versus Comanche lodge.

So I don't know where the Springer stands in terms of overall state production of gas since the beginning of time but it's going to be one of the top three that people would target.

It's just for the first time now we're able to image the stratigraphic complexity of the -- in the Springer at depths below 15,000 feet.

Well costs, when we drill a Springer well, can be as low as 3 million to as high as 5 million, depending on whether or not you're going to 15,000 feet versus 20,000 feet.

And in that environment, we're looking for as little as 5 BCF of reserves to as much as 20 BCFE of reserves.

Great.

Thanks, Aubrey.

Okay, Steve.

Thank you.

We'll take our next question from Paul Wideman, Big Cat Energy Partners.

Good morning, guys.

Hi, Paul.

A couple of my questions have already been answered, but kind of one on the strategic plain.

It seems to me that the market perceives your success both as an acquirer and an aggressive driller that at times seems to run up against concerns about the employment of leverage and debt to finance the growth and arguably, that could be a factor holding back your valuation.

I'm wondering how you might address that going forward, particularly given your desires to continue to be a consolidator in the Mid-Continent.

Paul, I'd hit it, I guess, a couple of different ways.

One is that we have always had a higher threshold, I guess, of ability to handle debt than other companies because of the way we structure it.

As you well know, we like long-lived reserves and we like to finance the acquisition of those with a combination of debt and equity.

But the debt that we use is long-lived as well.

I think our average maturity now is about eight years, and our average interest rate, I believe, is about 8.3% overall.

I think as Mark mentioned, we've got about 70 million of debt due in March of 2004.

No, 60.

60.

And we'll slowly eat away at that and then after that, there will be no maturities between then and 2008.

In terms of overall balance sheet improvement, four years ago we had, you know, in a 250 gas world, we had debt of over a dollar per MCFE.

Today we're in a $4 gas world and that debt is down to 70 cents.

My own view is that investors should spend more time, you know, worrying about other companies' operating cost structures, which are well in excess of our operating costs, and allow us to still have more cash flow per MCFE than most companies because we have very high-quality assets and very low G&A that offset the interest penalty -- higher interest penalty that we pay by having more debt per MCFE.

I suspect that you are aware that our internal target here is for that 70 cents per MCFE to get down into the mid to high 50s in the next 2 to 3 years and we think we can do that.

The way that we've been doing it the last three or four years is not by paying off debt.

It's by having our assets grow faster than our debt and we expect that can continue to occur over the next few years and every year our hope is to work that debt down by a nickel or so per MCFE.

At the same time, on a book basis, we'll be generating lots of book earnings, and hope to improve the balance sheet in that respect as well.

We -- we, you know, wish we could have the write-offs back from 1998 and call them goodwill like a lot of companies do today, but not able to do that, so we'll just live with the balance sheet that on a book basis, you know, is weaker than what I think the reality of the situation is.

So, Paul, we certainly concede that it is the -- I think the number one issue in terms of the -- holding back the company's valuation.

At the same time, we think that we have so many other things going for us in terms of our profile, our gas concentration, our operating success, and our hedging philosophy, that hopefully investors will look at the whole basket of characteristics of our company and realize that it's one of the top gas companies in the sector

On your hedging philosophy, I guess we need to watch your policy on oil to determine when Hubbard's peak will finally arrive? ?

We believe in that, you know, and obviously don't know if it's 2005 or 2015, but I guess you can properly assume that we don't anticipate it happening in 2003.

Thanks a lot.

Okay, Paul.

Thank you.

We'll take our next question from Barry Hanes with Sage Asset Management.

Good morning.

Just following up on the debt discussion, but kind of shifting to allocating capital as between drilling and acquisitions, and I wonder if you could just talk through a little bit your philosophy on that, what sort of price deck you price deck you're looking at, whether you're looking at, you know, E&P or acquisitions and what sort of hurdle rate from a financial return point of view you would use.

Thanks.

Okay.

Barry, traditionally -- and this will be no different in '03 -- our company budget is set up so that we always match our drilling, land, and seismic and a few miscellaneous acquisitions.

We always match that up with our projected cash flow.

And then we try and protect a large amount of that cash flow through hedging, so that we don't have to stop and start our drilling program.

We think that's one of the most kind of amazing characteristics of the industry, and that everybody drills when gas prices are high, and service costs are high, and then when gas prices and oil prices decline, people stop drilling.

And I think Mark's point earlier in his presentation was that we try to act completely counter-cyclically to that, and increase our drilling when gas prices and oil prices decline.

In terms of our acquisition philosophy, we do try to use a combination of equity and debt.

We hope that the equity -- is the homegrown kind from earnings.

Occasionally, we you have seen us have equity offerings.

I think the last time we had a common stock offering was in 1995.

We have had two preferred stock offerings, one in 1998 and one in 2001.

So at this point, we don't see any acquisitions on the horizon that would require us to do any time -- type of financing, but traditionally we have tried to go about two-thirds debt, long-term debt, and about a third equity.

In terms of returns, we look at a whole vast kind of array of future gas prices, but typically we're looking in the three and a quarter to 350 range to make sure that our acquisitions work.

We try to be in the mid to high teens on our initial returns, and then through better operations, renegotiation of gas and oil contracts, and more aggressive drilling, we hope that when we look back at those acquisitions a year or two later, that the returns are solidly above the 20% range.

That is -- that is our goal with acquisitions, and to date we've been able to meet those goals with the type of acquisitions that we make here in the Mid-Continent.

Great.

Thanks very much.

Appreciate it.

Thank you, Barry.

We'll go next to Beth Farnesworth with KDP Investment Advisors.

Good morning.

Good morning.

Just a quick question regarding the possible trade or sale of the Permian Basin assets.

What would the impact be on that in your reserves and production?

Beth, just kind of to update you where we are, we have engaged an advisor in this area.

The teaser for our divestiture has been put together, and we'll will be sent out probably early next week.

From a timing standpoint, we've had numerous companies express interest, and we would anticipate through November and early December to have those companies come in and have a detailed look, and then work toward a trade or close of a sale in perhaps January of next year.

In terms of impact, I believe our Permian production is running about 5% of our total production, as I mentioned.

That's roughly 24, 25 million cubic feet equivalent a day.

It's about 60% gas and 40% oil, so it's more oily than our Mid-Continent balance overall, which is 90% gas, but still pretty gassy as a package.

In terms of reserves, about 5% of our reserves also are located in the Mid-Continent, which I think -- I mean the Permian, and it would be roughly 125 BCF equivalent, as I recall.

Okay.

Great.

Thank you very much.

There are no further questions in the queue, gentlemen.

At this time, I'd like to turn the call back over to you, Mr. McClendon, for any additional or closing comments.

Great.

Thanks.

We certainly appreciate your participation today, and if you have any questions later in the day, fell free to give us a call.

Thanks very much.

Good-bye.

There will be a rebroadcast of this conference available today at 11:00 a.m. central running through November the 19th, 2002 at midnight central.

To access this, simply dial 1- 1-719-457-0820 and use the pass code 725635.

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