Chesapeake Energy Corp (CHK) 2002 Q4 法說會逐字稿

Welcome to this Chesapeake Energy Corporation Q4 2002 earnings call.

Today's call is being recorded.

Now I'll turn the call over to Mr. Aubrey McClendon, Chief Executive Office with Chesapeake Energy.

Go ahead, sir.

Good morning and thank you for joining the Chesapeake Energy Corporation's Q4 2002 earnings release conference call.

I've prepared comments this morning that will last a little bit longer than usual because we have a lot of ground to cover today.

I will provide a quick review of the quarter and then we'll talk about our El Paso and Vintage transactions.

After that Mark will provide more on the quarter and on the year.

After that we'll be happy to take your questions.

Our 4th quarter results were very strong , oil and gas production increased to a record level of 49.5 BCSE, this 4th quarter production 20% from last year's 4th quarter production.

Among the 20 largest gas producers in the U.S., this increase tied up for 2nd place.

In addition, our 4th quarter production was up 6% from our 3rd quarter production.

This marks Chesapeake's 6th quarter in a row of sequential production growth which stands in sharp contrast to the industry's declines.

By the way, our quarterly performance also placed us in 2nd among the top 20 U.S. gas producers.

The quality of our production increase in the 4th quarter was very high.

Only 9% of the 6% increase came from acquisitions closed during the quarter.

While we typically only forecast 1 to 1 1/2% organic production growth per quarter, we do routinely beat them.

In the 4th quarter, was exceptionally strong for us in the organic growth product.

In 2002, our year-over-year basis increased 35% over 2001.

Chesapeake went public ten years ago this month.

In each of the past 10 years we have increased our productions.

We believe we are one of the few companies in the industry that can demonstrate this achievement over the past decade.

In addition to the 35% increase in production we delivered in 2002, we are projecting a 28% increase in production in 2003.

Our new range of projected production is 230 to 235 BCSE.

For a midpoint daily average of approximately 640 million [INAUDIBLE] equivalent of gas per day. 90% of this production will be gas, and all of it will be from safe, secure, high margin assets, located on shore in the USA.

Although our production in the 1st quarter to date is running at 570 million per day, at this point our new guidance simply layers on the additional 70 million per day from the El Paso and Vintage transactions.

That 70 million per day over nine months amounts to 22.5 BCSE.

Given that we have exceeded our production guidance in each of the past 6 quarters, we believe we may likely do so again in the first quarter of 2003.

If we accomplish this, then we may well increase our guidance through the remainder of the year.

I would like to remind you that last year we increased our guidance four times.

Given the ugly supply trends in our country, we believe Chesapeake's ability to deliver production growth and production surprises on the upside is increasingly valuable.

We do believe that the significance of our ability to grow organically is not fully appreciated in the market.

In an industry where 14 of the 20 largest U.S. gas producers just posted production declines year over year that averaged 15%, we believe Chesapeake's track record of delivering consistent production growth through the drill bit, will increasingly differentiate our company from others in the industry.

We believe this will translate in a more attractive stock price for Chesapeake as our investors realize that production in our industry are real and stock valuation should be reserved for those companies that are growing their production profitably, not shrinking it.

It's fair then to ask what has been the key to Chesapeake growing organically.

Several reasons come to mind.

The first is its simplicity of our strategy.

We seek to find only one product, natural gas in only one area, the mid continent.

This singular focus gives us the chance to be the very best in the industry at one thing.

When you can be the best at one thing, you have a chance to create big increases in shareholder value year after year.

Secondly, Chesapeake has an exploration mind-set.

We truly are explorers.

We're the third most active driller in the country behind only Annadarco and El Paso Two of the three deepest wells being drilled in the U.S. today are Chesapeake operated wells.

These wells give us the chance to take our standard 5% per year organic growth rate and increase it to as much as10%.

Finally, we understand that land and proprietary science are the bases of all creation in this industry.

In a time of $5 to $10 gas is a good thing to have a land inventory of 2.2 million acres, close to 10,000 square miles of 3-D seismic.

A backlog of over 1500 drill sites and a technical staff capable of generating prospects to support the soon to be second most active drilling program in the U.S.

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

We started the year 1.8 TCFE, improved the reserves and now just 14 months later we are at 2.75 TCSE.

An increase of 55%, representing reserve replacement over 5 to 1.

Perhaps more impressively, during these 14 months, our debt improved TCFE increased only 1%.

Assuming that was the placement for 2003, we expect to exit this year with over 3 TCFE of improved reserves and 1 TCFE of probable and possible reserves.

I now want to visit about our acquisition capabilities, hopefully you've seen the exciting news, wherein we announced yesterday the $500 million acquisition of El Paso's and Arco Basin's assets.

This is the latest and largest of a string of mid continent gas acquisitions we have made dating back to 1998.

Since that time, we have systematically and opportunisticly built a gas franchise in the mid continent that is unique to the industry by its focus and by the superior financial results we have generated from our acquisitions.

With El Paso's assets in hand, our number one gas producing position in the mid continent will increase to where we will now control 14% of all the gas produced in this region.

The third largest gas supply region in the United States.

Chesapeake has built a unique position in the industry, no other company controls 14% of gas production in any other major gas supply basin.

The results of this scale are lower drilling and operating costs, higher well head revenues, greater returns on capital , and greater operational exploration and acquisition efficiencies.

Two weeks ago El Paso called us and said they needed money in a hurry.

We were ready to move when the call finally came.

From the initial phone call to the signed deal took only 15 days.

We were able to react so quickly because we've been working on this acquisition for 14 months.

That's the way most of our acquisitions end up.

The smaller $30 million Vintage deal that we also announced yesterday came the same way.

We have been working on the Vintage deal for eight months.

We lost it twice in auction, but by hanging around the rim, we were there for the rebound at the right time.

Let me tell you more about the El Paso's assets.

We have agreed to pay $500 million for them, and have allocated $50 million of the purchase price to 84 thousand acres of unevaluated leasehold.

And a 70 BCSE of probable and possible reserves.

With the remaining $450 million we are purchasing 67 million cubic feet per day of gas equivelant production and 328 in crude reserves. for a cost of [INAUDIBLE] MCSE of only $1.37 per CSE.

Amazingly, this is a penny less per MCSE than what we paid for One Oaks and ARCO basin assets in 2002, when spot gas prices were more than $5 lower.

We are confident that these assets would have brought more than $600 million in an auction, and an auction that we would have surely lost, most likely because of how conservatively we calculated El Paso's proved reserves.

We reduced their reserve estimates to from 470 BCSE to 328 BCSE, a reduction of 30%.

On the other hand we reduced Vintage's reserves from 36 BCSE to 22 BCSE , a reduction of 39%.

The El Paso assets are truly exceptional, lifting costs were awe only 23 cents per MCSE versus a 70 cent industry average.

The decline rates are unusually low.

There are more than 300 developmental drilling opportunities, plus, there's serious exploration potential in the Radon city and Sweetwater areas.

As a reminder, these assets came out of the El Paso Sonad merger a few years ago.

Shortly after, Sonad closed their Oklahoma City office and we hired most of their good technical people.

Also shortly thereafter, El Paso merged with Coastal.

The Costal management team took over El Paso's EMP efforts.

Since Coastal itself had exited from Oklahoma in the mid 1980s, these mid continent properties suffered from several years of post merger neglect.

On the El Paso asset base, 60% of the production and reserves are located in the strong city field of the central and Arco basin.

Starting in 1998 and continuing through our transactions, we have been building an ever larger presence in the city.

The city has produced 2.5 trillion cubic feet of gas equivalents since its discovery by Woods Petroleum in the mid 1970s.

Woods was El Paso's and now our ultimate successor in title.

The field still produces over 275 million cubic feet of Gas per day, and has proved reserves of 1 TCSE left.

It sprawls across parts of 33 townships or over 800,000 acres.

Today Chesapeake has emerged as the field's largest producer, having passed Apache and Burlington with the El Paso transaction.

With our commanding position in this giant field.

We plan to greatly expand exploration efforts in strong cities to compliment our ongoing developmental drilling efforts.

Because of the very fragmented nature of the field's historic ownership, it's never been shot with 3-D seismic.

Now, as the number one producer in the field, we can proceed with a 3-D evaluation of this area, most of which is remarkably underexplored at depths below 15,000 feet.

We acquired first-class assets in the El Paso deal, at a significant discount from a motivated seller in a negotiated transaction, in an incredibly attractive gas market.

In our business, it never gets any better than this.

We are indeed very proud and excited to own these assets and look forward to taking control of them in the next 30 days.

Before I turn the call over to Marc, I would like to mention that we are now 55% ahead for gas production in 2003, at a Nynex price of $4.70.

More importantly, though, we are only 46% hedged for the next three quarters and only 37% hedged for the next four quarters.

From here, we will opportunisticly layer in additional hedges as gas prices continue their search for prices that will destroy enough demand to balance the market.

On a final note, I do want to remind you that this is our 40th quarterly conference call.

Yes, it's true.

Chesapeake has been a public company for 10 years this month.

We suspect that maybe not all of you were original investors in that $25 million IPO, however, had you joined us in 1993 and held on through the good times and bad, you would be up over 600% on your investment.

It may surprise you to know that this is the best stock price performance in our industry over the past 10 years.

It's more the twice stock increase than our peer groups have generated ans over 3 times what the Dow Jones, Nasdaq and S&P industries have returned.

While we can no longer promise you the thrills of and chills of the past 10 years over the next 10 years, we believe we have a chance to outperform the industry for 2003 and beyond.

Our goals remain the same, continue delivering industry-leading value to our investors through growth, investment and reserves, through improvements our balance sheet, growth and gross share earnings and dividends and growth in our stock price.

Now I'll turn it over to Marc.

A few housekeeping matters from my side this morning, we will post an updated February 25th outlook on our website.

As well, you will be able to see today updated February presentation slides, our 10K will be available on Wednesday evening.

I'd like to emphasize how pleased we are with our quarterly production in the period, which Aubrey mentioned was up from organically driven drilling, but also on the revenue and cost fronts as well.

I'll be talking about cost trends this morning, both in drilling and in the operating side.

We'll be very pleased to note that the operating cost estimates for the remainder of this year have been reduced as a result of the significantly lower operating costs coming from the acquisitions that we've made and will be making this year.

As we think about the production increases that have come about in the last six quarters, I'd like to segue into what -- how that drill bit success has been reflected in year-end reserves.

We began the year with 1.78 BCF equivalent.

We produced 182 BCF equivalent during the year.

We had extensions and additions of 243 BCF price-related revisions of 76 BCF on top of that.

And positive performance related revisions of 14 BCF equivalent, for a total increase of 333 BCF in that area.

We extended $404 million, and depending on how you want to count it, the most aggressive cost would be $1.21 up to completely excluding the revisions that were priced for performance related the acquisition of our reserves was $1.66.

On the acquisition side, we had a 275 BCF with sales of just one BCF during the year.

We expended $378 million for an all-end cost of $1.37.

I will hasten to point out and you'll see this disclosure in our 10K as well, that of the cost incurred, 62 million were noncash charges that came in the form of deferred tax adjustments that we had to make on the acquisitions that we acquired entities of.

So of the 378 you could reduce that by $62 million which is an accounting adjustment that was noncash.

Also, we end up the year with the highest percentage of valuated reserves we've had from third party engineers at 74%.

And also, the highest proved develop reserves we've ever had.

On the plus side of the equation, let me provide you with some details, during the quarter, we capitalized interest of $1.3 million.

This compares to a cost capitalization of $1.2 million a year ago, so you can see relatively flat.

For the entire year of fiscal 2002, we capitalized interest to 5.0 million, compared to fiscal 01 of 4.7 million.

Our net internal capitalized costs related to our drilling programs. $4.6 million during the quarter compared to $3.6 million a year ago, reflecting the increase in activity level.

And also, the size of the companies geophysical and geological areas.

For the entire fiscal '02, internal costs were capitalized at the rate of $17 million, compared to $12.9 million in the previous year.

Aubrey has mentioned some of our hedging in the February 25th outlook.

We have introduced a section that relates basis hedging.

This is a new disclosure for us, and we've been very active in hedging the basis of our mid continent production.

And let me give you some numbers there.

You'll see in the outlook that we have hedged 106 BCF of our gas production of 210 BCF or 50% at 16.4 cents for 2003.

In 2004, 110 BCF have been hedged.

In 2005, 99 BCF and through 2009, ranging from 30 to 65 BCF.

So generally we're anywhere from 13 to 50% hedged on our basis at a very attractive average rate of just a minus 16 cents.

Also, I should alert you that the posted outlook today does include all of the pending acquisitions and planned finances.

While we're very limited on what we can say about our financing plans, I'd like to reiterate what we released this morning.

We have indicated that 20 million shares of common are proposed to be offered under our shelf registration statement.

We immediately intend to commence offerings of 300million of senior notes due 2013, and 200 million preferred issue stock, emphasizing that they will be offered privately.

Use of proceeds are intended to fund the pending acquisitions, reduce our bank credit facility outstandings, and general corporate purposes including potential repayment of the $42 million, 7 7/8 note that is remain outstanding and are due March 2004.

Let's talk about cost trends and our guidance for 2003.

LOE and GNA per unit have been reduced slightly.

Emphasizing the great asset attributes and the cost attributes of the El Paso properties.

Also, the nature of these property acquisitions being noncorporate.

We anticipate that they will generate GNA recoupments for us.

While our DNA guidance influenced from 1.37 to 1.38 is up.

We have been increasing our guidance in this area at a slower rate than the industry has been reporting.

Feul cost trends at this point remain unchanged in our opinion, with drilling rigs, completion and logging services still flat to the last couple of quarters.

Steal prices are down slightly.

While this no doubt will change right now, it is an unbelievably good time to be drilling and producing at these prices in the mid continent.

David, I'd like to turn it over to questions at this time.

Thank you.

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

If you'd like to ask a question, you may do so by pressing your star key, followed by the digit one on your telephone.

If you're on a speaker phone, please turn off your mute function so the Senate can signal can reach our equipment.

That's star one, and we'll pause for a moment to give everyone a chance to respond.

We will be taking our first question from Mark Meyer of Simmons and Co..

I was wondering if you could give us a current update on some of the highlight deep wells in the program?

Sure, Mark, we have 31 rigs right now, so one of the things that we talk about is that we're really not drilling well that we do highlight individually.

Instead, we talk about our program, probably the most exciting part of our program is the deep springer activity in western Oklahoma, in the greater Mayfield area.

We have four rigs, drilling to depths of around 20,000 feet out there.

And we probably will be adding a couple more in the next month.

We've drilled three wells to date out there that today are flowing between 7 million and up to 30 to 40 million out of one particular well.

And so we're very excited about the potential out there and feel like we literally have dozens of deep springer wells.

Much activity has occurred in the Arco Basin over the last 25 years.

It is remarkable how little exploration has been done at great depths in some of the most geologically complicated areas.

Particularly along the mountain front in Beckerman and Washitau counties and further down to the southeast through the cement and the bray.

Anything we should be looking to for decisions soon?

We pull logs all the time, if that's what you mean.

A particular well, we really, again, would like to focus people on the overall success of the program and our ability to continue to generate sequential quarterly production growth.

So I would say, no, that I wouldn't point you to any particular event.

Keep in mind, though, production now comes from 13,000 wells, and so one thing we would say, the bad news is, no one well can affect, really, our individual performance.

Our corporate performance.

The good news, that no one well can also do that as well.

So I would just tell you that we overall have a great program under way, and you can look for it in the sequential production growth.

Thank you.

Thank you.

We'll take our next question from Barry Sahgal with Brean Murray and Company Inc..

Marc, perhaps you could help me sharpen my pencil and go through the 4th quarter production numbers breaking them out by organic growth and the acquisitions that you made during the quart summer.

Sure.

Well, the production increase from Q3 to Q4 was 2.8 BCF equivalent, Barry.

Of the 2.8 BCF, only 9%, which I think was 270 million cubic feet approximately, came from the only acquisition that we closed during the quarter.

Was that the point of your question?

Right.

Absolutely.

And I guess another question, when do you think you're going to be going on the road to market the equity offering?

Any timing set for that?

We intend to commence that immediately.

What do you think are the details of which cities you are visiting?

I think that will be available by this afternoon.

Terrific.

Congratulations, gentlemen.

Thank you very much.

We'll go next to Louis Roth ay Merrill Lynch

Good morning and congratulations.

Thanks, Louis.

Aubrey, I was hoping that you could give us a little bit of detail on what you interpreted differently than El Paso and vintage did in taking such a conservative view of the proved reserve base that seems like a big discount.

And if there's just a couple of things you could describe.

Yeah, I think so.

First of all, we tend to be more conservative on final decline curbs, many companies use mid continent final decline curves of 5 to 6%.

We use typically anywhere from 8 to 10%.

And it doesn't affect PV-10 that much, but it does block off quite a bit of tail reserves.

So typically, we find ourselves in most acquisition endeavors that we tent to be 10 to 15% under on PVP.

Now -- and in both cases, we were a little bit more than that, but not a whole lot more.

The big wax came in parts.

We waxed both categories by half and instead called them probable.

There's a couple of reasons for that.

One is, we tend to have a pretty careful eye about what we call a plus.

A pud can be a pud for another company and not be a pud for us, in the sense that to be a pud at Chesapeake, you have to be able to break in to our drilling schedule as we have it today.

So, for example, we don't book any proved undeveloped locations that we can't get to in the next 36 months.

Most of them are front end loaded in the first 18 to 24 months.

So it can be a legitimate pud for another company, but if it can't elbow out another location that we want to drill, then we'll drop it into the probable category.

It does make it tough to be competitive on some transactions, there's no doubt.

But our philosophy is always one that we want to be conservative on volumes and are willing to be agressive on price because of what we feel like or some decent hedging capabilities.

So if we ever make a bad transaction, I always want it to be my fault or the management team's fault for making a bad price assumption, rather than a group of engineer's faults for being overly aggressive on reserve estimations.

Okay.

I did have another question.

On the mix of the offering as we discussed after your last acquisition and the common stock offering, there was a lot of demand for the stock, and I was a little curious why this morning in the announcement I see that you're basically using equity in this deal.

Couldn't you flip that around?

I think you're missing something, that's not true. 20 million shares at 850 or so is 170 million of common equity.

And then the perpetual preferred which is a noncallable preferred convertible.

So that's 370 million as compared to 300 million.

Okay, you're right, I was missing that.

Thanks, guys.

Thanks.

We'll go next to Stephen Smith with Steven Smith Energy.

Aubrey, I had a couple questions.

One, you talked about shooting some seismic over strong city, and the lack of drilling in the past at greater than 15,000.

Have there been some -- of the wells that have been drilled greater than 15,000, what can have they shown and what Targets are you going for?

First of all, it's an enormous area, 800,000 acres.

So there certainly have been lots of penetrations below the red fork, which is the main producing formation in this field.

But there are 1150 producing wells in this field from the red fork alone.

It looks like field ultimate reserves are 3.5 TCSE.

So just about 3 BCSE per well.

On average, has been found in the field to date.

Truly an extraordinary performance.

And this, by the way, I don't think I mentioned.

This production occurs anywhere from about 12 and 14,000 feet.

So there really wasn't a reason to do a lot of deep exploration, because the shower exploration -- shallow development were so attractive.

In one part of this field, the eastern part around -- I guess, just west of the town of Arapaho, we actually have a 3-D seismic program that's been designed and is in the early stages of getting it ready to shoot.

And if that plays out in terms of being able to be helpful to us, and figuring out the very complex stra tig ra if I of the red fork, then we definitely will expand that into the western part of the field.

And it is important to note that this field, because of its enormous size and development mainly in the '80s, the fragmented ownership of the field prevented any one company from being able to go out and shoot 3-D and say to others, we're going to do this regardless of whether you support it or not.

Now you can do that.

We have enough acreage that we can shoot across the entire field and have a serious competitive advantage on other companies that might not have in the past been willing to support 3-D.

So then I think the final part of your question was, what have those deeper wells found?

There have been isolated areas of strong, deeper production, in the strong city area, but to date, predominantly it's been a red fork, which is a Pennsylvania-age discovery that has led to 3.5 TCSE.

I will note as a final comment here, it's a reminder of why we have a gas supply crisis today.

The chance of finding the 3.5 TCS field on shore in the U.S. or for that matter offshore these days are zero.

And it's just a reminder of what great fields we have that have underpinned the foundation of this company's supply base over the last 20 years.

And they're just all -- they're playing out.

So that's I think a very bullish reminder of the predicament we're in.

Marc, you talked about the low cost of the acquisition, driving down your average operating cost and your new guidance.

Your circumstances went up in your new guidance, and you've proven other things in the acquisition of that rising severance tax.

Severance tax in the state of Oklahoma and for that matter just about everywhere, are a function of well-head prices.

Oklahoma you pay based on 7% of what you sell the gas for.

So that $4 gas you pay 28 cents to the state.

At 5 goods you pay 35 cents to the state, et cetera.

But on a unit cost you raised your rates, so I assume you built in a higher price deck into your expectations.

Oh, we did.

The price deck has changed from our last guidance.

Also, because of January and February rolling in.

I think we still were using 4 1/4 in our out months.

We are using 4 1/4 in the out months, but you have January and February, and March that's already been --

okay, evidence rolling in.

Thanks very much.

Thanks, Steve.

As a reminder, please press star one for questions today.

We'll go next to Joseph Allman at RBC Capital Markets.

You made a question about the inevitable increase in costs upcoming, but you indicated that so far we're seeing kind of flat costs on the rig, you know, the day rates and the logging costs.

Are you seeing any early indications of costs creep.

Or are you just looking at the screen and seeing the gas price and you think it's inevitable that gas prices are going to come up.

Certainly the latter is a factor.

But we're seeing indications.

This last round we were being asked by the drilling contractors, for example, to have day-rate increases, and if was, frankly, the week that -- the day, I think, that several contractors were in to see us that Paine announced 12 rigs, I believe it was being laid down by El Paso in south Texas.

And that put the blunt to that.

But with fuel costs up, just by virtue of diesel costs being up, if nothing else, that's something we take on on our own.

Other service costs related to transportation it diesel costs, insurance and so forth, and higher gas prices in areas, force things to be more expensive too.

And I'll also add that the billing contractors are, you know, careful with how they treat their biggest customer, and biggest customers.

And 25% of all the drilling in the state of Oklahoma, so I think they are properly charging those people who only occasionally drill a well or who now have woken up and there's $10 gas and they want to drill a well.

So that's required.

The drilling contractor to basically have kept an option open for those guys who only occasionally want to drill.

I think they are trying to price those rigs more aggressively.

And I'm sure they'll be able to.

With us, I think we'll be the last to see significant price increases, simply because of our negotiating power.

Also further balance, we do own six of our own rigs.

And then just for your guidance going-forward, have you factored in some slight increase in costs?

We have factored in a slight increase in costs.

I think that we're using $1.40 per MCF for our average acquisition cost this year in terms of drilling in all of F & D if you will.

And that's at the field level.

Thank you.

We'll go next to Dan Morrison at Peirian.

Real quick, I haven't been able to get into your new guidance, but I'm enjoying the gas market in 2 inches of snow here in Dallas.

You have 31 rigs running now.

How do you see that working through the years with the acquisitions, should that pick up a bit.

Well, Marc mentioned El Paso laying down 12 rigs, actually that did include the rigs in western Oklahoma.

I think they have 6 in that area.

We're going to add four, I suspect they will not be -- I know they won't be the same rigs that El Paso is laying it down, but we have budgeted to increase from 31 to 35 rigs and more or less, you could say those four rigs are associated with the El Paso acquisition.

The vintage acquisition will simply give us bigger working interest in wells that we were already planning to drill in that area.

I will tell you that the 31 that we're at today is about an 18-month high for us.

So we have stepped it up over the past couple of months.

I think we got as low as 22 in December when we had some weather and surface logistical issues.

We're hard at it and expect to see some pretty significant results later in the year as a result of this.

How are you doing your contracting?

Are you typically kind of multi-well big package deal so that you're setting your prices for a six-month period or your cost for a six-month period, or are you starting to get held to the shorter term?

We tried to, and over the last year, we've known that there would be higher gas prices, unfortunately, of course, the rig companies were able to see that as well.

Typically most of them are reluctant to give you six months or year deals.

We've tended to find that those kind of require higher management approval.

On the other hand, if we can string together some contracts that are multiwell contracts, those seem to get less scrutiny and maybe get us the same impact by being able to take a rig that's, say, drilling wells for 45, 60 or 90 days than stringing others together [INAUDIBLE] that's what we've been able to do.

At the end of the day, we've both contained a gas market for some time.

I think we've done the prudent thing by not locking in rigs at really low drilling rates.

Thanks.

Thank you.

We'll go next to Andy Par at Luman Sales.

I apologize to those on the call if I repeat a question.

First thing, can you guys give me a sense for what you're actual realizations are today, looking at the press release, I get 32 cents for gas, but that's excluding risk management.

And that seems like it comes up to something low.

Is that right?

32-cent differential?

Is that --

yeah.

Well, there's two ways to answer that.

The actual differential and the mid continent before hedging, or hedging of a basis which I'll get into in a second for the month of February, was 50 and 55 cents negative to Henry Hubb for the three pipes that we deliver most of our gas into.

We were 50% of our production hedged on basis, and so we had hedges that basically -- at basically 16 cents.

So you take gains from that hedging and you combine it with the 50 to 55 cent differential that we saw put you in that 32 cent -- 33-cent differential area.

In the past, as gas prices have gone up, differentials have widened.

At least they did in December and January of '00 and '01.

And so we are now, for example on our El Paso round, we estimated a 50 cent differential on those gas molecules.

I'd like to throw in that the basis hedging that Marc talked about averages 16 cents and it goes as far out as 2009.

We could obviously not have done that today or any time recently.

We started to do this over a year ago when we saw Rockies basis -- basis throw out.

And we surmised that there would be people who would spend money to [INAUDIBLE] the basis differential between the Rockies and mid continent and we feared there would be a pipe built from the Oklahoma panhandle to the Rockies which would bring gas down, which would serve two effects.

So that pipe was a Williams project, it was on the board it got canceled and today it's back on the board as a project of Colorado interstate gas which is an El Paso unit.

And it supposedly will get built by 2006.

So we I think did a nice job of anticipating this, and hedging it in.

And that's one of the reasons why you'll see basis differential stretch at this time of elevated gas prices, you will see less of an effect on us and maybe on some other mid continent producers.

Secondly.

Some time ago you talked about -- I think it was potentially San Juan assets, is that still on the table?

It's not.

We went through the process, I guess, of trying to always evaluate what you do well and clearly we talk about the mid continent as a thing that we think we do best.

We looked at other areas of the company where we have assets.

It's a two-company play, and we felt there were still lots of interest things to do there, and felt we could be a meaning player in that play for years to come.

We look at the Permean and decided we were never going to be a company that could matter, we decided to put them up for sale.

We did so and had a great process, and through that time discovered Reilly a lot of things that we didn't realize that we had.

We had increasing oil and gas prices during the process, plus we drilled three wells, two of which were over 500 barrel a day oil producers.

So while we received some cash offers that were well in excess of what we had internally valued the assets at.

Nobody had a mid continent package that was big enough to trade for.

And so we decided to keep them.

We're now going to move that magnifying glass up to the area in the Wilson basin where we only have about 1% of our assets, and I am pretty confident that we will end up moving out of that area at some point in 2003.

If we can do that with a swap grade, if not, we'll just take the cash and reinvest it in mid continent.

Thank you.

I'll get back in cue, thank you.

We'll take our next question from Andrew Halpern at Beaver Capital Corporation.

Good morning.

You've done a great job in terms of hedging on production and in terms of pricing there.

Do you have any ability, especially because of your significant position in the mid continent to do any hedging on if -- or if anything comparable to that with contractors because several years ago you sort of brought your drilling program a little bit to a halt when oil service contractors prices began going through the roof, at least as you saw it.

So I'm wondering you can do anything here to protect yourself in case the -- what now appears to be a surge in new drilling comes to the forefront.

We'll certainly be mindful of price increases going forward.

In the meantime, we have a really amazingly profitable opportunity in front of us to be drilling the day at today's rig rates.

I did just mention in answer to your question a few minutes ago, that we were able to do a little bit of forward contracting with our service providers, but mainly, it's two other issues that keep our service costs lower and analyze the scale.

And, therefore, the negotiating power, and finally we have six rigs that we use as a wee bit of a hedge against increased service quoits.

Thank you.

Thank you.

We'll take our next question from Mike Bradley at Cataquill.

Given your heavy natural gas concentration as well as the focus in one core area being Oklahoma, it seems to me that your company unlike others in your industry appears like the classic MLP vehicle.

Given the additional running room you see in Oklahoma, have you considered an MLP structure as a more appropriate vehicle for the company?

If so, can you get opposing cause as you see it now and in the future.

I'll take a stab at that.

We have considered the MLP vehicle, but we think it's premature.

One of the elements of the MLP structure is, of course, tax.

We have about $600 million or so of net operating loss that we'd like to utilize and that keeps us from paying cash income taxes.

Ultimately, the mid continent assets, though, the long-life nature of them.

The relatively small amount of cashflow that needs to be invested to maintain the production overtime should be an excellent MLP vehicle.

Also, another aspect to MLP's is typically you associate them with areas that do not have a growth prospect.

And we're not there yet, certainly, I can imagine getting to that point.

But with only 14% market share.

And if you think about a curve of efficiency shaped as an S on a graph, I really think we're in the lower part of the steeper part of that curve, and it will be some time before we find ourselves in the flatter, up half of that curve, and at that point I think certainly, a vehicle like an MLP is something that we would want to consider given all the positive attributes of the company's resource base that you just mentioned.

Thank you.

Could you provide some overall comments on your A & B market in the mid continent?

I can comment on A & B in mid continent because that's the only area we operate in.

I think it would be difficult to do a current value discounted 15%, I'm guessing, but it's probably 3.50 or $4 at MCSE.

I would be stunned if there's anybody willing to have a conference call and talk about a great deal in a three or four MCSE cap.

On the other hand, with longer life reserves in the mid continent.

It matters as much what happen notice second five-year as -- years as in the second five years, so we've seen pressure over time in reserve acquisition values.

Going back to 1998, in a $2 gas world, we were routinely having to pay 80 cents to a dollar if you look at what the company's done in the past 12 months.

We've spent close to, I guess it's now $1.2 billion.

And I believe our acquisition costs are in the $1.30 range.

So, you know, I'd love to be able to tell you that our next $1.2 billion of assets would cost $1.30 of the I suspect not.

We don't have anything planned at the moment.

We'll continue to evaluate opportunities.

But, you know, we are in an area that if you look at the top 10 producers, none of them are really trying to grow in this area, and will there be other people that want to shed assets here.

Probably.

Will we take a look at them, sure?

But we'll never doing anything that won't be profitable on a cashflow or earnings basis overtime.

So we'll continue to stay active, but don't have anything under discussion at the moment.

Could you also comment on your exploratory drilling schedule.

Overall, are those type of wells front end or back-end loaded or equally spaced throughout the year.

They're equally spaced.

We have 31 rigs today.

We spend about 30% of our money on exploratory wells, many of these end up, if they miss their exploratory Target aren't dry holes, in the sense that we typically drill through developmental formations on our way to exploratory.

So it does reduce the overall risk of what we have.

It's also an even program.

We're not -- we think it's very difficult to run a company where you're starting or stopping drilling every couple of years.

We just -- we keep a pretty steady program going of -- it's been 22 do 30 or so rigs.

Now that upper range will be 35.

We kind of modulate in that range depending on the relationship between commodity prices and finding costs.

And I think that's what we'll probably end up being in the next year or.

So.

Thank you.

Due to time constraints, this does conclude today's question-and-answer session.

I would like to turn the call back over to Mr. McClendon for any closing remarks.

We appreciate your interest today and hope to see you on the road in the next couple of days, and if you have any additional questions, log them in and we'll try to get back to you as best we can.

Thank you.

There will be a rebroadcast of this conference today available 11:00 a.m. central time, 719-457-0820.

And use the pass code 720863.

Thank you for your participation and you may now disconnect.