Chesapeake Energy Corp (CHK) 2003 Q4 法說會逐字稿

Good day and welcome to this Chesapeake Energy fourth-quarter and full-year 2003 earnings release conference call.

Today's call is being recorded.

At this time, for opening remarks and introductions, I'd like to turn the call over to the Senior Vice President of Investor Relations, Mr. Tom Price.

Good morning and thank you for joining Chesapeake's 2003 fourth-quarter and year-end earnings release conference call.

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

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

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

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

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

In addition, I would also like to point out that during the course of our discussion this morning, we will mention terms such as operating cash flow, EBITDA, and net income to common shareholders before special charges.

These are all non-GAAP financial measures.

Reconciliations to the comparable GAAP measures can be found on pages 12 to 14 of our press release issued yesterday.

While these are not GAAP measures of financial performance, we believe they are common and useful tools in the investment community in evaluating the Company's overall performance.

Our prepared comments should last about 20 minutes and then we will move to Q&A.

Good morning to all of you.

As we hope you've seen from our 20-page earnings release yesterday afternoon, once again, Chesapeake has reported excellent quarterly results, both operationally and financially.

Our net income available to common shareholders for the quarter was $62 million.

Our operating cash flow was $263 million, and our EBITDA was $258 million.

I would also point out that these numbers include the negative impact of various special charges described on Page 2 of our press release.

These totaled $33 million on an after-tax basis for the fourth quarter.

On what some refer to as clean numbers, our net income to common shareholders was $95 million, or 37 cents per fully diluted share.

Chesapeake's strong fourth-quarter financial results were driven by equally strong operational results.

Oil and gas production reached the record level of 73.3 Bcfe; this is our tenth consecutive quarter of record production.

This quarter's production was up 48 percent from the 2002 fourth quarter and up 3.3 percent sequentially from the third quarter of 2003.

We are equally pleased with the Company's full-year performance.

Our net income available to common shareholders for 2003 was almost three hundred -- (technical difficulty) -- dollars.

Our operating cash flow exceeded $900 million and our EBITDA exceeded $1 billion.

In addition, our production reached the record level of 268 Bcfe; this was a 48 percent increase over our production in 2002.

In and of itself, we believe a 48 percent production increase is a pretty remarkable achievement for a company our size.

However, even more remarkable is that 36 Bcfe of our 87 Bcfe production increase, or 41 percent, came through the drillbit.

Dividing that 36 Bcfe of drillbit growth by last year's 181 Bcfe of production yields an organic growth rate for the year of 20 percent -- pretty extraordinary, well above our forecast of 5 percent drillbit growth and perhaps the best in the industry last year for a mid or large cap company.

Another way to consider this achievement is by looking at our average daily production.

From a base of approximately 500 million cubic feet of gas equivalent production per day in 2002, we were able to overcome approximately 125 million cubic feet of gas equivalent per day year of first-year depletion and still had 100 Mcfe per day of net new production, or 225 Mmcfe per day of total new production.

That 225 million per day alone would have made us a top 25 gas producer in the U.S. last year -- not a bad achievement for one year with the drillbit.

Although Marc will spend more time on the details of our proved reserves and finding costs, I do want to note that we had an exceptional year with both acquisitions and the drillbit.

Overall, we found or bought 1.23 Tcfe at a cost of only $1.36 per Mcfe, roughly two-thirds of our 1.2 Tcfe and proved reserves were from acquisitions at a cost of $1.38 per Mcfe.

And one-third were drillbit reserves added at a cost of $1.32 per Mcfe.

Including Concho and two smaller acquisitions that we closed in January of '04, Chesapeake's proved reserves now stand at 3.5 Tcfe, a 60 percent increase from just 14 months ago.

We believe Chesapeake's low finding costs are even more impressive when viewed in the context of the high revenue-realization and low operating cost environment we have in our Mid-Continent stronghold.

In addition, I would also like to highlight that 74 percent of our proved reserves are proved developed and that 74 percent of the reserve report was prepared by third party engineers.

I'd like to emphasize that "prepared by" has a different meaning that audit, or a review, or a confirmation of reserve recognition policies, or even that the CEO is highly confident of the reserve estimates, or any other such description.

Prepared by means just what it says.

The reserves were not calculated by us; they were calculated by third parties.

By using the prepared-by approach for 74 percent of our reserves, we believe we are a leader in industry in terms of reserve report conservatism and transparency.

In time, we hope that the SEC, investors and analysts will demand that all oil and gas companies of all sizes have the majority of their reserves prepared by third party engineers.

By the way, in case you're wondering why we don't have 100 percent of our properties evaluated by third parties, the answer is simple; it's cost and time-prohibitive.

Roughly 5,000 of our 15,000 properties provide 74 percent of our PV-10 value.

The process of evaluating those 5,000 properties requires the efforts of three outside engineering firms and our entire reservoir engineering staff.

The third party engineering cost is $600,000.

Our internal costs are approximately $400,000, and the process takes four months.

So you can see that to do all of our properties would triple the cost and time but only improve the value coverage by one-third.

That is a 1-to-10 benefit-to-cost equation and hopefully clarifies why we don't have 100 percent of our properties prepared by outsiders.

It is also one reason why we are slower than most companies in issuing our year-end financials.

On the operations front, all is going well now that we have recovered from some fourth-quarter drilling delays in a few of our major exploratory areas.

Some of you may have noticed that our production for the fourth quarter, at 73.3 Bcfe, was 1 percent or so lower than our previous fourth-quarter forecast of 74 to 74.5 Bcfe.

The reason for this is that a few Mayfield Wells that we thought would begin producing in the fourth quarter did not begin producing until this current quarter.

Even though we were slightly under our forecast for the 2003 fourth quarter and even though the Concho acquisition effective date change will cost us 2.3 Bcfe of production in the 2004 first quarter, we are still comfortable with our forecast of production range of 78 to 79 Bcfe for this quarter.

Although we are currently running well in excess of the high point of that range, there are simply not enough days left in the quarter to enable us to get above that range for the full quarter.

Clearly, without the Concho 2.3 Bcfe loss, we would have been headed to a blowout first quarter; now, it will simply be very good with production up about 7 percent sequentially over the fourth quarter.

Recently, we've also taken advantage of the still-attractive service cost environment in our deep prospect inventory to boost our drilling from an average of 40 operated rigs during the fourth quarter of 2003 to 48 operated rigs today.

In fact, we will likely run more than 50 weeks during the next few months.

The reason is that we're doing very well in all of our drilling areas and returns on our drilling capital are extraordinary.

I do want to highlight two areas in which I thought you might have a special interest in our operations.

First, I'll update you on the Zapata County, Texas area where, on October 31, 2003, we closed our Laredo deal and acquired 24 million cubic feet of gas equivalent per day of net production.

Today, we are producing about 40 million per day, or a two-thirds increase in just four months.

I know that there was some initial skepticism about our ability to turn these puds into production but hopefully our performance so far with this new Laredo project will put to rest those concerns.

Secondly, I wanted to update you on our deep Springer play in western Oklahoma.

In this play, we now have eight producing wells and have seven rigs drilling new Springer wells.

To date, our average initial Springer production rate has been 19 million cubic feet of gas equivalent per day, per well, and our average reserves have been 22 Bcfe per well.

The only difficulty has been overcoming all of the challenges associated with drilling 20,000 wells in a high-pressure and geologically complex environment.

But we're getting better and better at it and look forward to a steady stream of new Springer wells coming online throughout 2004.

All else is going well on the Chesapeake operations front, and we look forward to being able to easily deliver on our 5 percent organic growth target in 2004.

Before I turn the call over to marc, I would like to note two other important positives for the year.

First, our hedging program continues to significantly enhance shareholder value.

In the fourth quarter alone, oil and gas hedging increased our cash revenues by $57 million.

Since we are 100 percent hedged in the first quarter of '04 at a NYMEX price of almost $6 per Mcf, we will once again add substantial value through our hedges in the current quarter.

Finally, I rarely mention our stock price on a conference call.

However, today, I'd like to make an exception because Chesapeake's stock price did increase by 77 percent in 2003.

Since performances of that kind are not easy to come by, I thought I had better make note of it.

In fact, by our review, Chesapeake was the best stock price performer in 2003 among the 25 mid and large cap E&Ps that we benchmark ourselves against.

Furthermore, we remain in first place in total stock price performance during the past five years and we are number two over the past ten years since our IPO.

In anticipation of further Chesapeake outperformance in the years ahead, Tom Ward and I have invested $40 million in open market purchases of our Company's stock during the past 14 months.

This ranks us as the number one inside purchaser of stock in our sector and number four among all U.S. public companies in terms of dollar value of insider open market purchases.

We clearly believe that Chesapeake's unique blend of organic and acquisition production growth and value-added hedging capabilities, a low cost structure, a long reserve life, a gas-focused asset base and a steadily improving balance sheet will continue to enable Chesapeake to remain a leader in shareholder value creation in the years ahead.

This completes my assessment of the quarter.

I'll now turn the call over to Marc.

Thanks, Aubrey, and good morning to all.

Continuing with our traditional and not repeating information highlighted in our press release, I will focus more on trends that we see in our business.

Those of you that have had the opportunity to review our release will note the extensive information contained in the release and the many schedules attached thereto.

Let's continue to focus on reserve reporting transparency, obviously a very hot topic to many investors in this earnings release season.

On page 10 of our release, we provide the complete reconciliation of 2003 finding costs and roll-forward, proved reserves from 2002 to 2003 for you.

We would observe that there are many ways for companies and analysts to present their version of finding costs; we've eliminated any guesswork.

Some estimates from investors or analysts include investments on unevaluated acreage, some don't.

Some analysts even include the non-cash ARO, or future retirement obligations, that won't be incurred for years, if ever.

All of these items are spiked out for you so you can determine your view of our finding cost.

Two items of special note in this section -- first, we have positive reserve revisions again this year.

Of the 56 Bcfe of positive revisions, which is 2.6 percent of beginning-of-year reserves, 45 Bcfe equivalent or 80 percent were performance related, spread out over basically all of our wells.

Eleven Bcf equivalent, or 20 percent, were price related.

The nominal amount of price related reserve revisions basically indicates that prices were basically the same.

A special note we would call your attention to, and it is presented in the detail, is the investment that we're making in our future.

Included in our costs for 2003 are the following -- acquisition of all improved acreage, where we spent $198 million; acquisition of leasehold on proved properties, $85 million; and investment in 3-D seismic, 43 million.

That's a total of $326 million of investment for the future, or nearly $1 million per day.

Given the production declines that we are seeing throughout the industry, we want you to understand one of the reasons CHK has been bucking that trend.

That's the investment in the future that we're making every year.

We are a prospect-rich company in a prospect-poor industry.

Many analysts have reported on this season's apparent lack of good drilling opportunity backlog in the sector as a whole.

Our view is a company cannot have a multi-year inventory of sustainable drilling projects without heavily investing in the future.

To sum up, our all-in finding cost, including this large investment in the future, was about $1.61, excluding the non-cash ARO items -- very respectable in our opinion but even more impressive considering this acreage of seismic expenditures that do not add appreciably to current-year reserves.

Without those costs, our finding costs all-in were $1.36.

As Aubrey mentioned, our independent consultants prepared reserve estimates on over 5,200 of the 15,500 estimates that make up our proved reserves.

We don't stop there, though, as our company engineers prepare their own report to confirm the consultants' work.

This year, out of 2.35 Tcf independently prepared, our reports were within 0.4 percent or 10 Bcf of the consultants.

Additionally, we internally prepare estimates on all reserves every quarter so that no surprises await us at year-end or throughout the year.

We believe we have industry-leading reserve report transparency and accuracy and are proud of our record in this area.

I'd like to spend some time talking about cost trends.

Our drilling engineers continue to report what I would describe as mild service company price inflation.

Since our last report to you in October about four months ago, most rig prices have increased approximately $250 per day.

Depending on whether you are speaking of 1000 or 2000 horsepower rig this is a 3 to 3.5 percent increase during this period of time for about 10 percent annually.

(indiscernible) costs are up 5 to 7 percent and there are some new Department of Transportation regulations that could cost another 1 to 2 percent increase in the very near future.

Open hole logging costs for Oklahoma are flat.

Anticipating higher tubular (ph) prices last year for this year, we entered into long-term contracts with suppliers that locked in slightly lower prices on tubulars for the first half of 2004.

Also, we placed, in an agreement, a price increase limit to no more than 5 percent for the second half of 2004.

It looks like tubular prices are headed up substantially but we should be largely insulated for that during this year.

Turning to our balance sheet, at December 31st, we had no borrowings under our $350 million revolving credit facility.

Of course, after the year end, we successfully completed our stock offering and our senior note debt exchanges.

We've reduced our interest rates and significantly lengthened our maturities.

For example, at December 31st, we had $728 million of our 2,011 notes outstanding.

Today, that has been reduced to 245 million.

We now have $670 million of notes not due until 2016.

Previously, we did not have an issuance in this time period.

We have $42 million due in March of 2004, next month, that will be retired.

Then we will have no maturities until November of 2008, where we now have only $210 million due at the time.

Our balance sheet in terms of average maturity, average interest rates, percentage of debt-to-book capital and debt per proved Mcf equivalent is at its strongest ever and we look forward to continuing these trends in 2004.

You will note that we've estimated current income tax for this quarter for the year of about $5 million.

This will be a cash payment that we will make in estimate of our taxes.

All of this is alternative minimum tax only and is an estimate at this time, since we've not completed our 2003 tax returns.

This $5 million estimate is out of a total book text of 190 million, or just 2.6 percent.

We estimate cash taxes will remain a very small percentage of our book tax deduction over the next several years.

This should remain a very competitive advantage for us as the industry appears to now be a large cash taxpayer as compared to the prior years.

A couple of capitalized cost details and then I will be done -- capitalized interest for the quarter, $3.4 million.

For all of 2003, that was 12.1 million.

Our capitalized overhead related to our exploration and drilling development program was $9.8 million for the quarter, 35.5 million for the year.

While we continue to predict upward trends in cash cost, our G&A costs per unit of production have remained essentially flat now for several years at around 10 cents per unit.

We don't see that materially changing.

Lifting cost, at 49 cents per Mcf of production, actually were lower this quarter and have generally trended down through 2003.

We remain convinced that cost trends, both for finding and operating costs, will be up through normal field inflation this year, but we are proud to report that we've held the line to this point.

Now, I'd like to turn it over to the moderator for questions and answers.

Thank you.

The question-and-answer session will be conducted electronically. (OPERATOR INSTRUCTIONS).

Phil Pace with Credit Suisse First Boston.

Congratulations on a nice year.

By moving the 48 rigs and it sounds like maybe 50, what does that do to your anticipated sort of well-count for the year and what does that do to your -- how would you calculate your years of inventory based on the backlog you see now at that rate?

That gives us a run-rate of about 500 wells per year, which is actually pretty consistent with what we've been talking about really for the last six months or so.

Our rig count in the third quarter was actually I believe as high as 47 and got as low as 37.

In either late December or early January, we needed to lay some rigs over for a couple of reasons to get caught up on some land activities in a couple of areas, plus we needed to send a message to some rig contractors that we could layover rigs.

Having achieved that message, we picked some rigs back up and again, we may bounce over 50 here for a few months but our budget contemplates this level of activity.

At 500 wells per year, we're still able to keep a rolling, five-year inventory of prospects (inaudible) about 2500 prospects on the bench.

That's been our goal really for the last four or five years is to have a rolling five-year inventory and then have your best ones hopefully percolate to the top (indiscernible).

That's helpful, thanks.

Mark Meyer with Simmons & Company.

Good morning, gentlemen.

On the rig trends, where are you currently and how does that compare to the 48 to 50 that you're going to?

We're at 47 today.

Aubrey, could you characterize a little bit in more detail as to what the tie-in (ph) or completion problems in the Mayfield wells that you referenced?

Really, it wasn't completion problems, Mark; it was really drilling problems.

We just had some plug-backs that we had to make that unfortunately we had a couple of wells get into the Springer and then do some differential pressure problems.

We had to plug them off and go back to -- I guess a shallow is about 10,000 feet -- and start all over again.

That 20,000 feet takes another 60 to 90 days, plus we lost some time fighting gas when we got into the zone.

So, we had a pretty much spotless track record in terms of our first wells not encountering any major problems.

We just kind of hit a bad streak in the late third and fourth quarters but we seem to be back on track and don't anticipate -- well, I shouldn't say that -- we will have further drilling problems.

We just doubt that it will come in the bunch that it came in the timeframe that I talked about.

Gary Stromberg with Bear Stearns.

Good morning.

Marc or Aubrey, can you just talk about how repeatable those extremely low finding cost are, both for acquisitions and drillbit?

Do you have any targets for '04?

The finding costs, I think, are largely repeatable in the sense of our reserve targets.

The diversity of our drilling program among 450 to 500 wells, the added diversity from the non-op, the concentration of our drilling budgets in areas that we've been drilling now for a long time -- to me makes it very sustainable.

Now, the question that we don't know is, what is going to happen?

Or the answer we don't know is what is going to happen to field service cost if drilling rig costs were to suddenly inflate.

You know, it has a very dramatic effect on our finding cost.

We are targeting about $1.50 this year.

As you look our presentations on the Web site or as you see us at around at conferences, the $1.36 that we have, we've used a number of $1.50.

Our acreage and seismic investments probably won't change much as a percentage of our overall budget, so you still have the discrepancy between all-in finding cost and actual drillbit finding cost.

Acquisition trends really continue.

As everyone has seen from various announcements, acquisition costs are training up as well, simply given a much higher value of the Mcfs at these oil and gas prices and the competitive nature of acquisitions right now in the industry.

I would only add one other thing, and that is I think we've been pretty upfront with investors that our finding costs are higher today than they were two years ago or five years ago, and they will be higher two years from now and five years from now.

We want to be in the bottom end of the range but you know, this stuff is getting more difficult to find.

If you haven't made the investments for the future that we've made over the last five years, I think it's extraordinarily difficult to replace your reserves at a reasonable cost today.

So, I just want to make sure that we are very pleased with where we were in this year but every year, going forward, I think the trend will be that we will be spending more money per Mcfe to develop reserves and we're just trying to be at the lower end of the industry range.

Fair enough.

Thank you, guys.

Dan Morrison with Aperion Group.

A quick question and if you gave the detail earlier, I apologize if I missed it.

On the deeper drilling in western Oklahoma, in the third quarter, it was kind of a drought on completions.

Can you say how many wells you've completed in the fourth quarter and kind of -- you commented about the schedule being on track for the rest of the year, but -- (multiple speakers) -- contribution was like in the fourth quarter?

The third-quarter drought extended into the fourth quarter -- (LAUGHTER) -- which led to the problem.

Actually, we're pretty impressed with our ability to do what we did in the fourth quarter without any really meaningful contribution.

We have bought on two new wells in the first quarter that are doing well.

These would have been wells that we would've expected to be on at the beginning of the fourth quarter, which would've made the difference in that 1 percent shortfall compared to our forecast, which I believe we made and last updated in late October, middle of October, I can't remember.

Well, it would've been in conjunction with our earnings release, which would have been the last part of October.

Right.

Have you calculated what your organic growth would've been and was in the quarter after you back out the Laredo?

Yes, I think we stated that it was flat, that all of our production growth of 3.3 percent sequentially came from acquisitions; it was like 98 percent came from acquisitions, so just a very, very slight uptick in production during the quarter.

Despite that, we still had a 20 percent organic growth rate for the year, so again, we're disappointed with the delays that we had for the fourth quarter but it's really production that we've now picked up and are going strong here in 2004.

(OPERATOR INSTRUCTIONS).

Jeff Robertson with Lehman Brothers.

Good morning, Aubrey.

Can you provide any update on (inaudible) activity on the Concho assets, understanding that you've only owned them for a pretty brief period of time?

Maybe I'll let Tom address that.

We have owned them just three weeks, so we're just getting our hands around it and making all the personnel decisions, but we are out there drilling.

I'll let Tom address what we're doing on the drillbit side.

We had one rig running in the Permian, I believe, when we took over Concho.

Now, we are up to five rigs currently and we continue to have the Midland office open and are trying to make decisions on what we should do there, but right now, we look to have four to five rigs continually running now in the Permian.

Tom, are there any particular plays you all are most interested in that you'll talk about?

It's a really good mixture of both oil and gas, so not really any one play that dominates.

We are drilling as deep as 13.5 to the marrow (ph) and as shallow as 3,500 feet in some canyon sands.

As usual, Jeff, I think you used the word (indiscernible) we talk about; we probably won't end up talking about any of these plays.

They all have expandability, in our view, and our sense has been that when we educate investors, we end up educating competitors, so we try not to do that.

Okay, two other quick questions.

First, on non-capital as a part of the budget, do you have a number for what you think that might be this year?

Is that inclusive of acreage and seismic or exclusive of that?

Just the acreage and seismic part, the leases in seismic out of the total number you have in the release.

We are budgeting roughly $100 million to $125 million for both acreage and seismic.

Okay, one last question, Marc.

Can you tell me what the belts on the 016 notes is? (multiple speakers).

I can tell you right now that the balance is 670.487 million.

One thing, I wouldn't be surprised if that leasehold and seismic is closer to 150 when it's all said and done, given what we spent in '03.

I think, over the year, we will probably be expanding those expenditures as we integrate these new acquisitions.

Just one thing to be on the lookout for.

Kelly Krenger with Banc of America Securities.

Just a couple of quick questions -- Marc, can you tell us how much you have currently outstanding on your credit facility?

Today, the amount outstanding would be roughly $250 million.

This is virtually the low point of our cash cycle where, in our business, all of our cash receipts from the sale of our product come in in the last few days of the month, between the 25th and the end of the month.

So it wouldn't surprise me that a week from now, we could have 50 million or even 0 outstanding as our revenues come in.

At the time of the acquisition when we funded Laredo, we drew down $195 million -- or excuse me, Concho -- we drew down $195 million.

So, that will show up as our pro forma capital balance sheet, if you will, in any presentations you see.

Otherwise, the variance around that is just timing differences from operating cash flows.

Okay, and then one last question -- can you guys just give us kind of your current take on the gas market?

I guess we can.

Given how hedged we are, I guess our view is we wish gas prices would go to zero.

That would give us the best differential performance from the industry and also would obviously help drilling costs and acquisition costs.

Since that's not likely to happen, we suspect that we are in an environment where, again, the price surprises are likely to be on the upside rather than the downside.

We think it might be a little more difficult than people anticipate to get gas back in storage this summer.

We will do it.

But the question is, will we do it at 4.50 or 5, or will it take 5.50 or 6?

Our view is, given production trends, given demand trends and given the possibility of average to warmer weather, we wouldn't be surprised if you see higher gas prices this summer than what you saw last summer.

We've hedged ourselves, though, against the possibility that we are wrong.

Outlined on Page 6, we've given your our gas price hedges for the year.

I guess kind of an average, eyeballing it, for the last three quarters of the year is going to be somewhere right around 60 percent and right around $5 per Mcf range on NYMEX.

Okay, thank you.

John Gerdes with Southwest Securities.

This 88 probable Bcf of probable and possible reserves that you guys noted when you did Laredo -- did you bring any of that into your proven reserved at year-end?

I mean, you only had it for a quarter.

I don't know yet.

We just have to get back with you unless Tom knows specifically.

I think we've drilled puds so far.

That's logical.

On your pro forma reserves you mentioned, what is the percent gas and the percent proved developed of those figures, guys?

The pro forma?

I've got it here in the schedule.

I'm going to dig it out. (multiple speakers).

I believe it's 89 percent gas and it should be 74 percent proved developed.

For the 34/74?

It should be the same.

Marc will doublecheck and we will come back to you if it's different from what I said.

Anything else?

No.

Thank you, guys.

Jeff Mobley with Raymond James and Associates.

Good morning, gentlemen.

A couple of questions for you on the acquisition front -- with gas prices and particular volatility moderating somewhat, has that potentially pulled down some of the expectations of some of the sellers out there and put you in a position to acquire assets more cheaply than you might have been able to do towards the last half of '03?

The second question would be, given the disconnect between where oil properties are valued and where oil prices are in the market today, do you have an interest in increasing a focus on oil-property acquisitions?

Let me go in reverse order.

We feel pretty good about oil prices.

We have felt, for the past year or actually year and a half, that there might be surprises on the upside in oil prices as well.

We maybe didn't anticipate it was going to come as much on the demand-side in Southeast Asia.

Nevertheless, we've felt pretty good about oil prices.

Does that mean we feel good about owning oil properties in the U.S.?

Marc just doublechecked and I think I'd given you 89 percent; it's actually 88.7 percent is gas for us.

So, we've got some oil.

As we continue to grow in the Permian, we will add some oil there.

It's difficult to not do that, given that the Permian is quite a bit oilier than the Mid-Continent.

But I think you won't see much deviation from the Company's focus right now, which remains on gas properties.

Will the oil percentage inch up a little over time?

I wouldn't be surprised if it does but there wouldn't be any kind of wholesale change.

In terms of the first part of your question about have acquisition prices been affected by lower volatility of gas prices, or in fact just lower gas prices?

I would say that I think acquisitions are driven more from the scarcity of production increase than they are by front-month gas-price volatility.

I think companies of all types, particularly large public companies, are finding that increasingly difficult to grow production through the drillbit, and so acquisitions are a great way to do that.

So, we've seen acquisition prices continue to move up, even as gas prices have softened in the last couple of months.

Keep in mind also, Jeff, that we buy things that typically have a PDPRP (ph) of anywhere from 7.5 to maybe 9 years, maybe 10 years occasionally.

What really matters so much is not to front month's gas price as much as the out-year gas price.

As you know as well as anybody, those prices really haven't moved too much.

You talk about movements in nickels or dimes (inaudible) front month can move in dollars.

So I would just say what that we see right now, the things that we bid on, we can make really attractive rates of return at hedge-able prices, still given today's entry price into acquisitions.

Given our view that finding costs will go up and acquisition prices will also go up, we also think public company valuations are likely to go up as well as a result of that, despite what people may think about backward-aided gas prices down the road.

Just one follow-up question -- has there been any change in interest level of majors to divest some of the properties in your backyard there?

The majors are largely gone from our area.

I guess the only ones -- BP is a major player -- in fact, the second-largest producer.

I see no change there.

They have rigs; they buy leases; they run a really good program in the Mid-Continent.

Behind them, you've got Conoco-Philips, Chevron-Texaco, even Exxon still has some properties year.

While we don't see much drilling activity on these properties, they are pretty easy to manage and pretty easy to blow down -- especially easy to blow down, given the production declines you've seen the majors have.

But I don't look to see the majors dump wholesale properties because I just don't see that they have these proceeds and it seems like the production challenges they face are pretty intense.

So, we still see private company movement up the conveyor belt as the primary source of acquisitions these days.

Great.

Well, congratulations on a fantastic year!

A follow-up question from John Gerdes with Southwest Securities.

Sorry, Aubrey, I have one or two more.

On the Springer, you guys had wonderful success in this deep Springer and you alluded to drilling complications and the cannibal complications last quarter but the reservoir recovery has been excellent.

Give a person a sense of just the trends you're seeing, the inventory picture you are seeing, the running room, in other words?

Also, what is your kind of learning?

I understand the competitive attributes here but what is your learning work in this deep trend?

We are learning that they are outstanding wells -- (Multiple Speakers) -- we've know that for a year and a half.

What we haven't yet learned, I guess, is whether or not we can find other Mayfield look likes; look alike is kind of a broad term -- (multiple speakers) -- along this mountain front.

We're doing really well in Bray right now, an area that's over 100 miles away along the mountain front.

We've talked about our success at (inaudible) we just did a big 3-D in the Cordele area that we are working on this year, and we have other kind of Beckham County mountain front ideas as well.

We are in the process of getting ready to test a number of those.

I think '04 will be an exciting year in terms of whether or not we are able to see some kind of extend ability.

You're speaking specifically of the deeper Springer sections, correct?

Yes, I am.

Just a last question -- divestitures -- I mean, you've obviously extremely active in the M&A market on the acquisition side.

What's your thoughts in terms of your assets, in terms of rationalizing components of them in '04?

I hope you will notice that we did divest (inaudible) in '03.

We divested 11 Bcfe and we got -- (multiple speakers).

I did noticed that, yes!

We wish we could do that some more, I guess, at those prices.

The reality is we -- (technical difficulty) -- a lot of things to do with wells that we inherit that just aren't very good.

We have found -- we have been surprised, in the past, at really the low level of interest that a lot of people pay to their properties (inaudible) (inaudible) guys over here that really can scour the wellbores (ph) and look for the things that weren't open before and (inaudible) systems and change -- (technical difficulty).

So we haven't yet gotten to the point where we just have wholesale groups that need to be done.

Also, frankly, at $30 oil and $5 gas, it takes a really bad well to be unprofitable.

The properties that we've sold, actually somebody came to us and were very aggressive with the bid on some properties that we felt we had accurately -- they had a different opinion about how many reserves are there, and we will find out over time who was right.

We see (indiscernible) continue (indiscernible) not in any kind of big way.

We have always joked that we are a little better on the acquisition (LAUGHTER) -- (multiple speakers) -- divestiture front.

Fair enough.

Thank you.

Enjoy your day.

At this time, we have no more questions.

Mr. McClendon, I'd like to turn the call back to you for concluding remarks.

Thanks a lot.

I appreciate everybody joining us today.

If you have follow-up questions, we will be available for the rest of the day.

This concludes today's conference call.

We thank you for your participation and you may disconnect at this time.