Chesapeake Energy Corp (CHK) 2004 Q1 法說會逐字稿

Good day and welcome to this Chesapeake Energy first quarter 2004 earnings release conference call. [OPERATOR INSTRUCTIONS].

At this time for opening comments and introductions, I would like to turn the call over to Mr. Tom Price, Jr., Senior Vice President Investor and Government Relations with Chesapeake Energy.

Please go ahead, sir.

Good morning, and thank you for joining Chesapeake's 2004 first quarter 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.

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.

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 9 and 10 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 15 minutes and then we'll move to Q & A. Aubrey?

Thanks Tom.

Good morning to all of you.

As we hope you have seen from our earnings release yesterday afternoon, Chesapeake has once again delivered excellent quarterly results to its investors.

Our net income available to common shareholders for the quarter was $104 million, our operating cash flow was $328 million and our EBITDA was $348 million.

I'd like to point out that these numbers include the negative impact of unrealized hedging losses, and a charge in connection with repurchases and exchanges of Chesapeake's debt securities during the quarter.

These two charges totaled $19 million on an after-tax basis.

On what some refer to as recurring numbers, our net income to common shareholders was a $123 million, or $0.44 per fully diluted common share.

And our EBITDA was $369 million.

Operating cash flow of $328 million was unaffected by these two charges.

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

Oil and gas production reached the record level of 78.9 Bcfe.

This was our 11th consecutive quarter of record production and this year will be our 15th consecutive year of production growth.

The 2004 first quarter's production was up 39% from the year ago quarter and up 7.6% sequentially from the fourth quarter of 03.

Of the 39% increase in this year's quarterly production versus last year's quarterly production, half, or almost 20% annual growth rate was organic and the other half came from acquisitions.

Our review of Chesapeake's mid and large cap competitors results to date confirms that Chesapeake delivered the best year-over-year growth record in our peer group.

We also believe our 7.6% sequential growth rate will turn out to be among the very best in the industry this quarter.

During the 2004 first quarter we were busy both with the drill bit and with acquisitions.

We replaced our 79 Bcfe of production with 373 Bcfe of new reserves, which is a 473% reserve replacement rate.

Of this amount of 146% came through the drill bit and the 327% came through acquisitions, net of revisions.

Our drilling and acquisition costs were a very respectable $1.66 per Mcfe while our G&A costs were only $0.10 per Mcfe.

Our lifting costs were only $0.57 per Mcfe and our production taxes were only $0.19 per Mcfe.

We hope you also noticed our hedging program generated a realized gain of $26 million for the quarter.

We have not yet seen another company that reported a gain from hedging during this year's first quarter.

This brings our hedging gain total since 2001 to $210 million.

On the operations front, all is going well, as is obvious from our production numbers.

Earlier this year we had warned that our production was likely to be on the low side of our initial 78 to 79 Bcfe forecast because we had not been able to book 2.3 Bcfe of production in January from the Concho acquisition.

In fact, we came in on the high side of that production range and believe we are now in fine shape to deliver another excellent year production growth for our investors.

At the moment, it appears that our 2004 production will exceed 2003's production by 24%.

In addition, our production growth rate in the second quarter of 2004 versus the 2003 second quarter should be 23%, and finally, our sequential production growth rate from the 2004 first quarter to the 2004 second quarter, should be at least 4.6%.

We believe each of these production growth numbers reflect the quantity and quality of our drilling prospect inventory, an inventory that has taken us 6 years to build and that we continue to high grade so that we can continue to deliver exceptional production growth.

While all the attention these days seems to have been placed on so-called unconventional gas resource plays, we would like to point out that Chesapeake has over 2 Tcfe of probable and possible reserves from our own gas resource plays.

Furthermore, we believe our gas resource plays have much better all-in-economics than many of the other gas resource plays that we are reading about.

In addition, our gas resource plays are largely free of the regulatory and environmental issues that reduce the value and timing of some of the other gas resource plays.

Moreover, we are continuing to invest in the future of these gas resource plays.

This year Chesapeake will invest more than $100 million in new leaseholds and more than $50 million in new 3-D seismic.

We expect Chesapeake's drilling inventory to continue to provide organic growth opportunities that should be among the top two or three in the industry for many years to come.

This completes my assessment of the quarter and I'll now turn the call over to Marc.

Thanks Aub and good morning to all of our participants.

I would like to jump in and talk about a few new things that you will notice in our presentation of this quarter's results.

First, you will note that our production taxes were significantly lower than our recent historical run rate.

Why?

We have just received notice that the state of Oklahoma has completed its evaluation of the average well-head gas prices received by producers during calendar 2003.

That average price fell below levels where producers would have been exempted out of receiving severance tax abatements in place to incentivised drilling in the state of Oklahoma.

Therefore, we are entitled, as all producers are, to abatements on certain wells drilled for the period from July 1, 2003 through June 30, 2004.

The adjustment related to the first six months of this period was about $7 million pretax, and was recorded this quarter.

Also recorded in this quarter was about $4.8 million pretax related only to the first quarter of 2004.

Second, our book tax rate this quarter has been reevaluated for 2004.

We have reduced our effective tax accrual estimate to 36%, down 2% from our historical 38%.

Further, we have estimated no current income taxes are or will be due for this year.

Our federal income tax loss carryovers from 2003 are now just above $400 million for regular tax purposes, and we do not expect to have any significant tax expense for 2004 or 2005, and potentially further into the future.

Third, for the first time, CHK has issued restricted stock grants to our employees as part of our overall employee compensation program.

The number of grants issued was reduced substantially as compared to previous employee stock options that had been issued, and has been reported as a reduction in earnings for the first time.

Also, please note that we have spiked this number out as opposed to some reports we have seen where it is disguised deeply in the footnotes.

We have given guidance for the first time in our outlook as of April 26, 2004, for the future trend on this expense and will continue to do so.

Let's now turn to cost trends, where we and no doubt most everyone else, are seeing increases in the service cost of our business.

During the current quarter, as Aubrey noted, we added 389 Bcfe equivalent of new proved reserves which was 373 Bcf after 16 Bcf of negative price-related revisions at a cost of $619 million, or $1.66 per Mcfe.

We did not have any material positive or negative revisions related to reserves that were not price-related.

The $619 million, of course, is before cost incurred in unproven leasehold acquisition, asset retirement obligation cost and tax step-ups related to particularly our Concho acquisition which are all part of our full cost pool and are drivers in our current and future DD&A rate.

Some people have noted that the tax provisions for deferred income taxes have changed more than our tax provision and that is related to our Concho acquisition.

Our reserves added to production ratio were 473% this quarter.

In terms of other service cost, which of course have to be kept in the context of vastly improved oil and gas prices, we're seeing drilling rates continue to increase.

New contracts that we're letting today for 2,000-horsepower are now around $8,500 today, as compared to between $7,900 and $8,200 at my last update in February.

Which is increase of about 5%.

The 1000-horsepower type work rigs have increased between $500 and $600, which represents an average increase of that type of rig of about 10%.

Cost of (inaudible) jobs overall, the average has continued to creep up and has risen between 5 and 10% since the first of this year.

Steel prices are of course the big story in the last couple of months.

We believed that we had our steel cost largely locked in and it still acts as a moderator on steel price increases for us, but we've been receiving surcharges regularly.

We received a $90 per ton surcharge from our main mill in March, which was of course a direct pass-through and translates to about a 10% bump in the program price through our distributor.

The April surcharge from the mill was $190 per ton, including the $100 increase in March, representing about a 20% increase since the beginning of the year.

A little detail on other cost for the quarter, include capitalized interest, which -- where we recorded $5.3 million of capitalized interest during this quarter.

All other capitalized internal cost for our drilling programs were $10.9 million.

On the balance sheet side of things, today we have no outstandings under our $350 million revolved credit facility.

We do have the normal small letter of credit postings for a variety of our bonding and margin requirements.

We are in the process of amending our bank revolving credit facility, and intend to announce something definitive in May.

Basically, we are looking to increase the size of this facility to be documented at $600 million, with $500 million of bank commitment, and we expect to extend the maturity by one year to a maturity date of 2008, which is the first maturity of any of our long-term senior unsecured notes, which in that year total only $208 million.

Another administrative matter I would like to advise you of is the intention of Chesapeake in the near future, perhaps even later today or tomorrow, to file an amendment to our shelf registration on form S-3.We intend to increase or as some people would define, reload our shelf to $600 million.

This is purely housekeeping, as we have no acquisitions pending or in negotiation that would require issuance of any securities at this time, and in fact none are planned.

We have no planned use of proceeds at all for this shelf.

So, in conclusion, we believe we have just completed a great quarter, where we saw tremendous balance sheet improvement through the issuance of nearly $600 million of preferred and common equity, noted by one agency in the form of an upgrade which we received this quarter.

Earnings on an adjusted basis that exceeded consensus by $0.06 per share, or about 15%.

We saw excellent reserve replacement rates, at reasonable prices given the current price environment for selling oil and gas.

And of course now we see continued strong oil and gas price futures as we had earlier predicted.

Moderator, we will now entertain questions.

Thank you.[OPERATOR INSTRUCTIONS], Our first question comes from Jeff Mobley with Raymond James.

Good morning, gentlemen.

Great job on the quarter.

A few quick questions.

Is there any update that you can provide to us on your deeper drilling activity along the mountain front trend?

Yes, I think we can.

Good morning, Jeff.

We have completed nine Springer wells to date since we started the program a couple years ago.

And to date have found on average right at 20 Bcfe on an EUR basis and that includes two wells that are not very good at all.

If you throw those wells out we are in the 23 to 24 Bcfe per well, and our initial rates of production from those wells have been in total about $17 million.

That's our Springer -

17.

Sorry. 17 million cubic feet of gas equivalent production per day.

Our Morrow program, we have seven wells.

It has been less successful but luckily the wells have been cheaper and on average we are right at about 3 Bcfe there.

But if you throw out the first three wells which were not particularly attractive, we now are averaging about 4.5 Bcfe per well on the Morrow side of the program, and keep in mind Morrow is shallower than Springer.

And our IPs, initial production rates for the Morrow wells is also equivalent to our reserves, divided by a thousand, or about 4.5 million cubic feet of gas per day.

In the Mayfield area, which is where these wells have all been drilled, we now have 10 rigs running, six of which are on wells that have been spouted in the last 30 days.

We have been quite pleased with the program and have been accelerating the program through the end of last quarter and through this month of April.

Great.

And just a follow-up question to your production guidance for the year of roughly 24% growth.

Could you kind of provide an estimate of the breakout between the growth attributable to acquisitions versus drill bit driven growth?

I don't have that handy, Jeff.

We'd have to get back with you on that.

Yeah, Jeff, I would say our guidance hasn't changed.

Our modeling remains on developmental side about 5%.

If you just think about year over year in any one-quarter, of course it changes a little bit quarter from quarter, based on how many of the deep wells or how many of the successful exploration wells might come in, but anything incremental to 5% for this year projecting forward, not looking backwards, but projecting forward, would be on a base growth of about 5% organic

OK, great.

And finally, just on the acquisition front, obviously the recent acquisition have been largely or entirely equity financed.

What would be your estimate of the size of transactions or the total amount of transaction that you could do before you would raise additional equity, meaning with your cash on hand, excess cash flow and your debt capacity, how much additional transactions do you think you could roughly do?

Jeff, how I would think about that is we've been pretty consistent in saying, over the course of a year, we intend to finance our acquisitions about half debt and half equity.

We do count that excess cash on hand really counts as equity.

So, I can't tell you with precision what that number would be.

You know, the next acquisition, how much of it would be debt, how much of it would be cash on hand, how much of it might could be equity.

But at this point we've obviously front-end loaded the equity component of our 2004 acquisition program, and so I would expect the rest of the program to follow in a manner that would put us by the end of the year more in that 50-50 range that we've talked about being at consistently over time.

OK, thank you very much.

Great job on the quarter

Thanks.

Our next question comes from Mark Meyer with Simmons & Company

Good morning, gentlemen.

Question on your 100 million increase in CAPEX versus your month ago guidance.

Could you provide a little detail on, kind of where that's allocated, how much of it is price inflation and how much is an increase in activity?

It's actually from two months ago and we've made some acquisitions since that time.

So, it's a combination, Jeff, of drilling on -- I'm sorry, Mark, on acquired properties, and some of the price inflation that Mark has talked about.

Plus, I think just we've made -- we're in the beginning stages of developing several attractive new areas for us that have incentivised us to put some additional rigs to work.

We really like the profit margins we're seeing from our drilling right now and want to continue to be aggressive in that in that range and that is the reason for the increase in 2004 CAPEX.

Mark, the way I think about it is our previous forecast had been based on about $650 million of actual drill bit expenditures with the balance of the capital program being in acreage and G and G. Acreage and G and G, really are unchanged.

The $650 million forecast that we had earlier already had sort of a 10% inflation factor built into it for 2004.

I think this budget probably has another 5% inflation factor built onto the 10%.

So you know, another 40 million or 50 million of the increase is probably just price-related, the balance being activity-related, either due to our deep drilling success or as Aubrey mentioned, our acquisition activity

So about 50-50 on a drill bit -

That's just a rough estimate but that would be a good guess

Real quick clarification.

Mark, you cited some increase in both the 2000-horsepower and 1,000-horsepower category.

Just to clarify, that's on kind of incremental new rigging you're picking up, or I guess better question, where is activity currently, and is any of your base load activity exposed to kind of new contract pricing?

I'll ask Tom to jump in, but it's not just on incremental new rigs that we're picking up.

These rigs get bid basically every one or two locations and while 2000-horsepower rig may be on a location for 150 or 180 days, if it comes off and it's not already contracted for another location, then it's going to be bid out and so price increases would be applicable to that, even though that may be what you call a base load activity.

Right.

It's just the way the rig contracting works.

We're not able to go out, nor would any of our vendors want to go out long in the future and lock in low rates, you know low rigs, for multiple years, when they, like us, look at the futures and know that good gas prices are in store.

So Tom, do you have anything to add to that?

No, that's correct.

We bid out each location and sometimes we'll have a rig that will go to two or three locations on a contract, but usually it's each location at a time.

OK, very good.

Thanks.

Thanks, Mark.

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

Hi, guys.

Hi, Ken

Going back to your deep drilling in Oklahoma.

In terms of just the Springer wells, I guess you had non-wells down -- nine wells down to date, is the time to drill going down at all or is it staying around, I want to say around the 120-day level, is that correct?

No, we're thinking in the 150 to 180, and where we've been and we've had a couple instances where wells took longer than that and we talked about that in our last call.

But we're still in that range right now.

And while we always hope to get more efficient with our bits selection or mud program or any of our -- the technical sides of what we're doing, you always - in a time like this, lose a little bit of efficiency from crews that might not be as experienced as you'd like, but these are the rigs we're going to keep busy in this area for some time.

Many have been in this area for some time so we hope they form the heart of our most efficient rigs and our deep drilling program.

And just on that Aubrey or Tom, just the number, your current rig count and kind of that current rig count, how much is -- would be -- or how many would be the deeper drilling?

Ken, roughly it's the same as it's been for -- gosh three or four years.

It's roughly a third, below 15,000 feet, a third 10 to 15,000, and a third above 10,000 feet, with also a split of about a third exploratory and two-thirds developmental.

A. split of where we're drilling.

OK, if you all are interested -

I'm sorry, in the deep Anadarko we have 18 rigs, in southern Oklahoma 11, northwest Oklahoma 8, the Arkhoma 5, Permian 5 and South Texas 4.

That's under contract.

Adds up to -

That's 51 under contract, 50 are drilling.

And last, for kicks, in terms of the current production out of I guess one of your more prolific, the Buffalo Creek, that's still cranking away at 30 million to 40 million a day?

That's still making 42 million a day.

OK and of those nine Springer wells that you talked about, kind of the last two that came on in, I guess, January and February, were those kind of in the middle of that range, or lesser or better than kind of -- than the average?

I'd say they are OK wells and not exceptional and not poor either.

So, just about what we hoped for

OK, thanks so much, guys.

Keep it up.

Thanks, Ken

Our next question comes from Ellen Hannan with Bear Stearns

Thank you.

A couple follow-up questions on the drilling Aubrey and Mayfield.

Could you talk about the cost to drill your expected EURs, your initial production rate and also what kinds of declines you're seeing on these wells?

I'm going to let Tom answer, that Ellen.

Our projected days for a Springer well is 157 days, $7 million completed costs, and that takes you down to about 22,000 feet.

And then Ellen on specific decline curves.

Really we have wells like the Buffalo Creek that haven't declined in 16 months, yet we haven't increased the reserves in that well and sometime we'll be looking at that through the course of the year.

But we use -- well, what you can use is a pretty handy back of the envelope math as you can take IPs of wells out in this area and multiply them by a thousand and that's a pretty good EUR, it's a pretty good EUR for all mid-continent wells.

We think that probably understates the EUR, but we would prefer for people to aim low and see how the wells do over time.

The Buffalo Creek, I mentioned producing 42 million a day.

That well came on December 22nd of 2002, it's made 18 Bcf, we've only booked 30 Bcfe, so we show that it's done 60% of its production or it's produced 60% of its EUR, yet we've seen no decline in production.

The well is only, I guess, 15 months old in its production, so we're being pretty cautious out here and feel like we're drilling wells that would really stand up with anything being drilled in North America today.

Is that the oldest well or the one that's been on production the longest in that area?

It is the oldest well that we have drilled in the area.

Our first well that came on, well I say that the Treva actually came on three months earlier, but it was a well that wasn't fracked until after we brought the Buffalo Creek on, we went backed and fracked the Treva and it went from 7 million a day to 27 million a day.

And Tom, what's the Treva doing now?

About 18 million a day.

Extraordinary area, you know.

I don't know, sometimes I don't know what a gas resource play is, the way people describe them these days, but clearly the gas resources that underlie our acreage along the mountain front in western Oklahoma are quite substantial, and I don't know if they're unconventional or conventional, but to us they represent a tremendous amount of reserve and production upside we think in the years to come.

And we own virtually the whole play

Can you remind us what your land position is there or maybe Tom, what you're thinking of in terms of drilling inventory?

It's large.

If you think of Oklahoma we own a lot of acreage along the mountain front, it's a couple hundred miles long, and we've bought all along the whole mountain front.

You'd measure it in tens of thousands of acres and in dozens and dozens of hillsides.

It would take a long time to develop just because we have to shoot a lot of 3-D and these areas we're talking about are only in the tens of miles and instead of hundreds.

It's just a lot left to do.

OK.

Moving on to another area, you didn't mention anything about your drilling activity this quarter on the new South Texas property.

Any update there?

No, if you're speaking of the Laredo acquisition around Zapata, that continues to surprise and amaze.

We don't expect to make any more acquisitions that are going to be quite that good, but we're fairly routinely drilling 5 million to 9 million a day wells.

When we talked about that property we talked about EURs in the 4 to 5 Bcfe.

We're booking 5 to 7 Bcfe.

That's what we're finding, at least.

So clearly it's not the blanket low-bow that Trans Texas drilled for years, Conoco drilled, this is a very localized sweet spot that we hope will in time turn out not to be quite so localized and we'll be able to find other sweet spots in this area.

We're not the only ones bringing in good wells in this area.

GOE, and Houston also has some good wells in the area

One last question for me.

What are you seeing in terms of acquisition activity especially in light of the current prices and the recent transactions that have taken place in?

I guess one thing you could say is given prices that some other companies have paid lately, we've -- we were well served and well served our investors to spend 3.6 billion over the last five years by buying when we bought.

A lot of people thought we might have paid too much at various times during that but obviously in retrospect, the only mistakes we ever made were not to buy more.

It's a tough world on the acquisition front, mainly because it's a tough world on the drilling front.

When you can't find the stuff through the drill bits, you have to go buy, it you're going to find more and more companies in that predicament and so I think there will be more acquisitions.

Corporate acquisitions of large public companies still do not have any interest to us.

We will continue to plug away on the small to medium sized acquisitions, and the ability to predict when and if we might make another one of those is limited but I can confirm Marc's assessment that we're not evaluating negotiating or have under contract anything of any import.

I think we have one 16 million a day -- our $16 million acquisition that is actually one of the four that we announced in February that is the only one that we haven't closed that we've announced to date and we hope to get that done in the next 30 days

Great, thanks very much.

Ellen, one other thing I would say, when you're able to increase your production organically at the rate of 20%, you really are in a position where you never need to make another acquisition.

We've made a number of them, because they make sense to us both strategically and financially, and we think that they still will.

But to not -- have to subject ourselves to the organizational stress that I think other companies have when, if they don't make acquisitions their production is flat to declining, it's a real nice even luxurious position to be in.

So I think that's a clear differentiating factor between our company and most other companies in the industry today.

And what's remarkable to me, is we're the biggest size we've ever been yet I think we have the best organic growth rate that we've seen in the last seven years right now.

Thanks very much.

OK, thank you.

Our next question comes from John Zarin with Louis Sails (ph).

Thanks but both of my questions have already been asked.

Appreciate it.

Thank you, John

We'll go next to Dan Morrison with Aperion.

Covered a lot of ground but keep harping on the deep stuff.

You had some completion problems in the fourth quarter as I recall on a couple of wells.

Is it safe to say you had at least two new completions contributing in the first quarter that were deep Mayfield area?

Let's see.

We had two wells -- yeah, you're right.

Two wells come on in the first quarter, rather, in -- and both of those were wells that probably should have come on in the fourth quarter, we talked about that.

And then we will have, in the second quarter, it looks like two or three wells start producing in the second quarter.

One of which we just logged, and looks pretty good, if I recall from the report.

OK.

Great.

Thanks.

Thank you, Dan.

Our next question comes from Jeff Robertson with Lehman Brothers.

Good morning, Aubrey.

Hi, Jeff

Can you talk geographically about the 146% replacement on -- or reserve replacement in the quarter?

Is there one area that those mostly came from, or is it spread across the different operating areas?

Anywhere we have production, Jeff, we're active.

I'm going to ask Tom to reread the drilling rig numbers, because it's pretty instructive and I'll come back and comment on them when he's done, in case some of you all missed writing it down if it's important to you.

Deep Anadarko 18 rigs, Southern Oklahoma 11, Northwest Oklahoma 8, Arkoma 5, Permian 5, and South Texas 4.

Really, the only area that we would have kind of legacy production where we're not doing any drilling would be in the Chalk, which that production is down to what percent of our -

Less than 5, but I don't have the exact numbers, it's so immaterial.

We don't do any drilling down there we have got I think less than 1% of our production from the Williston basin, we don't really drill up there, occasionally participate in some non-opps.

So I think a hallmark of our strategy, Jeff is to be balanced, balanced between acquisitions and drilling and then in terms of where we drill, balanced between, or among all the operating areas.

And essentially wherever we're producing gas today, we're there because we see growth.

I guess one other area we would produce gas and not be reinvesting, that would be Kansas, and then in Texas Panhandle field where we occasionally drill some wells there but in terms of being able to keep production flat or growing in those areas, that would not be happening.

I think also that our 3-D program, we spend 50 million a year on 3-D, most of that is adjoining other 3-D shoots that we have so if you think Mid Continent or Oklahoma in particular, as we continue to drill wells, we have 3-D shoots that join each other, so you can understand the larger picture of what it looks like, what the formations look like and it gives us a big advantage to have hundreds of miles of 3-D that connect with each other.

So, as you look in time going forward, that we'll continue to blanket the state with 3-D, and I think that will be a big advantage for us.

And we are focused on 3-D, and I think a couple of areas of interest today.

One would be the most geologically complex areas along both the mountain fronts of the Andarko basin and also the Arkoma basin.

We just completed a 3-D, over in the Arkoma called La Fevers, which we're drilling I guess our initial well on now and have high hopes for that.

But that's a proprietary shoot that we didn't want anybody else to be in.

We're also looking at doing some shooting in northwest Oklahoma and our -- in our shares area.

We have actually shot a couple new 3-Ds out there.

Most people don't think about using 3-D in that environment because typically its is never geologically complex as the deeper plays that we're involved in.

Yet we think that there's some applicability of 3-D seismic in those areas and if they should happen to be successful for us, there are additional hundreds of thousands of acres that we can shoot up there.

Keep in mind we have about 3 million acres of leasehold.

I don't know where that ranks in the country, but it's got to be pretty high.

And we have about 800,000 acres of that that's been shot with three-dimensional seismic, so very aggressive program, and do we have a couple of crews out working these days?

We have a couple of shoots that are just finishing that we're getting data in.

Transition to our next round of shoots.

So we continue to find things to do, and also most companies do not want to shoot 3-D seismic in Oklahoma because it tends to prove up Chesapeake's acreage rather than their own.

So we more or less have the 3-D seismic market to ourselves in this part of the country

Thanks, Aubrey, one question for Marc can you talk a little bit more about the production tax credits, and how long those may last and what -- I guess the wells, I think you said the wells you drilled between July 1 '03 to June 30, '04, does the credit run out after a certain period of time?

Jeff, this is sort of an area of expertise that few people are as active in as we are, and the whole thing is a little bit funky.

There have been series of severance tax abatement programs that have been passed to incentivise drilling in the state at different times and those of course get amended from time to time as well and they're depth-dependent.

The types of incentives in terms of the percent that is abated and in terms of the length of abatement vary by depth.

But basically, if you think about a deep well below, say, 15,000 feet, and I don't have the exact depth right off the top of my head, but below 15,000 feet, that is drilled, not just during this abatement period but let's say was drilled a year ago.

The incentive could last as long five years, but it's determined at least this year it's determined in a look-back scenario where the Oklahoma legislature said if prices at the well head exceed $5 on average per million BTU, during the period of January 1, '03, through December '03, and we and you won't know that until after the end of this period, and during February or March we will evaluate and then tell you if your incentives for the period from July 1, 03 through June 30, '04 apply and in fact it turned out the well head price averaged per million BTU, below $5, then you get to file for your abatement, and a refund, and then you get to claim your abatement through the period June 30, '04.

So, said another way, we now know retroactively it applies for that 12-month period of time.

We have one more quarter we're in now that we know the abatement applies, and then we won't know going forward whether it applies until the average price is determined for calendar '04 which won't be known until early '05.

So we weren't trying to sandbag anybody by not accruing it.

We thought that the prices probably would average above $5.

It turned out that they were below that by the state's calculation, which we agree with.

And so, we're now reducing our severance taxes.

That reduction will be in place this quarter at least, and then we will start accruing again in the third quarter of calendar '04, because we won't know the outcome for another six months after that.

OK, so you go back to your normal severance tax rate in the second half of this year?

We will, and that's what our guidance says

OK, good, thanks for clearing that up.

Our next question comes from Lori Woodland with Schroeder Investment Management.

Good morning.

Hi, Lori.

You had mentioned on an earlier call that you think that debt to capital will be 50% by year end and as I look at your numbers, you're already there with an even better number.

Could you talk about where you want your leverage to be at this point, and where your discussions with rating agencies have been?

Sure.

Lori, you're absolutely correct.

Today, our debt to book capitalization is about 46%.

As we look at our projected earnings based on the guidance that we've put out, if no other activity occurred this year, we'd be moving toward the low 40%.

We hope activity does occur, and as Aubrey mentioned earlier in the conversation, we front-loaded our equity issuance such that the remainder of any acquisitions, which we have none planned and they're impossible to project because we don't know the timing of sellers' wishes, nor do we know if we'll even be successful if a property comes op the market, likely we will finance part of that from operating cash flow and bank debt or even long-term debt, depending on the size.

What we've told the rating agencies, and we've been recently in front of them.

Fitch has recently upgraded us as a result of those meetings.

We're still pending on any announcement from Moody's and S&P, but I can guarantee they're reviewing us as we speak.

What we've told them is we're going to be moving in a direction that we've been at, a strategy we've been at for last several years, which is to use the appropriate amount of equity and debt on any acquisitions, and otherwise fund our drilling program from operating cash flow.

The operating cash flow exceeds our drilling program this year by a couple $100 million, at least.

That drilling program, as we've mentioned, allows for a 5% organic growth rate.

So at the end of the year the inevitable outcome is that our debt continues to decrease as a result of that activity in terms of both debt to book cap, which some people follow, some people don't.

But the rating agencies, more importantly, follow debt per proved Mcf equivalent and at this point we're at $0.59 which is a record low for the company.

We want upgrades.

We're working hard to get upgrades.

We think we deserve upgrades as we look over the sector.

Our bonds trade as if we were higher rated.

And we've become a large really conservative holding as far as, I can tell, in the high yield universe.

So we're working hard to get those upgrades and I can only hope that they're forthcoming.

OK, thank you.

Our next question comes from Joe Allman with RBC Capital Markets

Good morning, everybody.

Hi, Joe.

Question on reserves that you've acquired but weren't recorded at the end of the first quarter.

Do you have a number?

He Joe, it's the same number that would have come in the press release for the acquisition that we last talked about, which I believe were 68 Bcfe, so those would not be included.

So on a pro forma basis you would have to add those to the 3.5 that we talked about in the press release.

Yeah, and that includes the small acquisitions you referred to earlier that gave you reason to increase your CAPEX budget?

Although the increase in the CAPEX budget was driven not so much by those but by the earlier acquisitions in January of Concho and the properties in West Texas and in South Texas.

Gotcha and I'm not clear on how much you spent in the first quarter on the drill bit and then separately on acquisitions.

Can you clarify that?

Sure.

I can clarify it by giving you the exact number, I believe.

I'll come back to that, Joe, I'm going to have to flip to that piece of paper that has that exact number on -

I know you guys are obviously buyers.

Have you considered divestitures, what's your thinking about divestitures of assets?

Oh, we try to always be in a divestiture mode.

We're not very good at it, compared probably to the acquisition side.

We certainly have not identified any geographical area that we feel that needs to be divested.

We do, with 15,000 properties, we attract a lot of unsolicited offers on individual wells and we do look at those from time to time.

But we really haven't made acquisitions where we get a whole bunch of bad wells.

We do a pretty good job of plugging our ones that need to be plugged and selling some of the low-end stuff to some other people who might be able to do more with it than we can.

We're pretty good in wringing in the last barrel or last Mcfe of gas out and with these prices; it's hard for a well to be bad.

So, we do a lot more acquiring than divesting, obviously.

And then on your probable, you've identified about 2 Tcfe, probable and possible and I know you guys want to drill up your puds over the next, 1, 2, 3 years.

When do you start drilling for the probables, or is that sort of just an ongoing thing?

Yes, we do it right now.

We drill really 4 times of wells, we drill puds today, we drill probable, we drill possible, and we drill exploratory wells.

So it's all, we really don't have a policy of needing to drill up our puds.

We're certainly not overbooked from a percentage basis, we're 26% puds and would guess that will continue to hang around the 25% mark going forward.

I would also guess that roughly 60%, you could take 60% of our proved developed reserves at any one time and that would be a pretty good guess of where we are on probable or possible.

It seems to have been a percentage that's worked for us over time.

So Joe it's just an ongoing process where we possibles and probables roll up to puds, puds roll up to PDP and we're out constantly out there buying new leases that should 3-D to keep, all three action will include the exploratory bucket of four those buckets as filled up as we possibly can.

Got you.

Joe I have got those numbers for you now.

Actual drilling costs during the quarter that we had cash activity on, what we call cash activity, we had $166 million of expenditures.

Then, leasehold cost, buying acres on the ground, seismic and then other capitalized internal cost, is 71million for a total full cost full cost pool add of $237 million.

On the acquisition side, we actually spent on a net cash basis, $416 million, and then added to that would have been unproven acreage acquisitions and miscellaneous costs that was about another $64 million.

Great, thanks and just one last one.

On your different, can we talk about your differentials in your press release.

What are you using for sort of a benchmark, as I couldn't come up with you, I think you said like $0.71 differential or something for the first quarter for gas.

What are you using to compare your wellhead price, what's the benchmark?

Is it bid week average or -

No, well what we would be using is NYMEX, on the last day close, basically, as Henry Hub has said each month, which is I guess is another way of saying the forward looking contract, average for the month and not volume sensitive.

And so if NYMEX averaged $5.66 for last quarter then whatever our actual wellhead price is company wide, would be our differential.

All right, thank you.

We'll go next to Chris Edmonds with Pritchard Capital.

Hello guys, good morning.

Couple of questions, Aubrey, could you just give us a broad-base macro view.

I know you're 27% hedged in '05 today on the gas side.

Sort of what your thinking is there and where you hope to be or where you want to be, say, the end of next quarter and going forward?

I think it's totally dependent on the opportunities that are presented to us.

We would not be just blanket hedgers today.

At today's prices we're always looking to hedge spikes.

Our positions to date, while for 2005 are below the 2005 strip today, they were placed when there were spikes in 2003, mainly 2003.

So, we're going to be looking for other events that are likely to cause spikes.

We think that we may have a different summer injection pattern and maybe a different summer usage pattern than we had last summer, which could cause some elevated prices, and we think basically every winter for the next four years, whether you go into winter at 3.0 Tcfe or 3.4 Tcfe, there's always going to be a chance of a winter spike, that depending on how you're headed in could happen earlier in the winter or towards the backend.

Our view is that we're well hedged for this year and have a nice wedge on for 2005, and now it affords us the opportunity to completely play offense with future opportunities and our best guess is we'll probably get some of those opportunities in the months ahead.

Great.

And then the rig profile that Tom laid out, is that consistent with where you want to be going through the balance of the year?

I mean, do you expect that diversification and that sort of breakup to break down to be about the same?

Yes, I would say, Chris, in terms of number of rigs, I could see it work down a few rigs, I could see it work up a few rigs.

In terms of geographical distribution we're going to stay basically where we are and I think in terms of depth distribution we're likely to stay about where we are and in terms of exploratory versus developmental, I think we'll stay there as well.

This is really a program that we've developed over time, it's working very well for us and while we fiddle at the edges a little bit we're pretty pleased with everything that we have going right now, and expect to continue delivering or continue using the same type of rig program profile that we have out in the field today.

Fantastic, thanks very much.

Our next question from Byron Limb (ph) with Spikes Investment Advisors.

Yes.

When you talked about the steel prices going up, what type of impact does that have on your cost, sort of on a Mcfe basis?

Is it the pennies or nickel types of impact, or less or more?

Yes, fortunately, we are basically talking about nickel or less type of impacts.

The steel program on the type of well we drill, the steel embedded in an AFE, our estimate of cost for a well is 5% to 8% or 9%.

And so, if you're talking about price increases of as much as 50% to 100%, you're still only talking about increases that overall impact the well by 2.5% to 5% or maybe 6% or 7%.

And if you're finding costs are running just to pick a number, $1.50, you can do the math and see that while it is an upward increase it's still only pennies per Mcfe and it's an important point to recognize when gas prices are up $0.50 Mcfe on the curve that the margin still is very respectable for us and in fact has improved despite increasing costs of acquisition by drilling or by property purchase.

Great, thank you.

Our next question comes from George Kucera (ph), private investor.

Hello, congratulations on another wonderful quarter.

You guys know how to make investors very happy.

I have a couple of questions.

I've been trying to model your earnings for the last three quarters and my background is in tax so I really don't understand the hedging that well.

I talked to your CFO at the end of last quarter and I told him I thought my estimate for year was about $1.45 and I've been close on my estimates so far but the hedging I've never gotten right and I have got some questions that will help me understand it a little better.

I've never been able to figure out how it is possible you could only make $1.05 this year.

So maybe there's nonlinear aspects of the hedging you can help me understand.

In your example on Schedule A, you've got a price using NYMEX price of $5.00 and you're hedging at $5.00 or close to $5.00, you've got a gain of $0.13 and I don't quite understand that.

OK Well How it works is that we have our own internal model, based on this production level, and based on NYMEX prices, then the hedging gain is $0.13, as you point out, for the year.

Now, the 4.96 for the next quarter or the 5.04 for the remainder of the year actually implies actual prices received to date, with a $4.75 estimate for the remainder of the year.

So, said another way, we're very conservatively pricing -

Yeah, I'm sorry to interrupt.

I understand that.

Let's just talk about June 30.

Let's just pretend that the price was correct in your estimate so that we don't have to worry about the variance.

And then my next question will about the actual price, 5.60 and how much the deviation affects it.

If it, let's assume with 5.60 because there seems to be a nonlinear relationship between the price change and your effective hedging.

Well, there would be a nonlinear relationship as you go forward, because the hedging percentage by each quarter is different.

And so -

I'm calculating that in.

You've got 75% hedge for Q2.

If the price of NYMEX is exactly 4.96, as you put in your estimate for Q2 and you have 99% hedged at $5, if I saw the hedging numbers right, that would mean that it would come out to three pennies approximately hedging if my understanding of the hedging is correct.

George, why don't we do, rather take up a lot of investors time if you would call in after the call we would be happy to go through at a time model

Alright, I'm sorry for asking such a naive question -

It's fine but we would be happy to help you specifically off line

Alright.

Thanks.

We have a follow-up question from Dan Morrison with Aperion.

I'm actually taken care of, thanks

It appears there are no further questions at this time.

I would like to turn the call over to our speakers for any additional or closing remarks.

Thank you all for joining us today and if you have additional questions, please give us a call.

Thank you.

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