Chesapeake Energy Corp (CHK) 2004 Q4 法說會逐字稿

Good day, everyone.

And welcome to the Chesapeake Energy Fourth Quarter 2004 Earnings Release Conference Call.

Today's call is being recorded.

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

Please go ahead, sir.

Good morning, and thank you for joining Chesapeake 2004 fourth quarter and yearend 2004 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 this morning, 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 such terms as operating cash flow and EBITDA, and we will also mention several items that we believe are typically excluded from analysts' estimates.

These are all non-GAAP financial measures.

Reconciliations to the comparable GAAP measures can be found on Pages 15 through 17 of yesterday's press release.

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

Our prepared comments should last about 15 to 20 minutes and then we'll move to Q&A.

Aubrey?

Thanks, Tom.

Good morning to each of you.

We have 4 primary takeaway points to highlight on today's call.

First, Chesapeake continues to deliver excellent financial returns to our investors, quarter after quarter and year after year.

Number two, these financial results are being driven by organic production gross and reserve replacement achievements that are at the top of the industry, yet we do not trade with the top of the industry multiple thereby creating a great investment opportunity for our investors.

Number three, in anticipation of today's strong oil and gas prices, during the past 5 years we have made major investments in people, land and seismic that we are now - that are now paying off in a big way.

We believe these investments will help Chesapeake to continue delivering top tier operational and financial results for years to come.

And number four, our projected future growth is based on a strong and diversified foundation of multiple play types from traditional exploitation of conventional gas resources to an industry leading deep gas exploration program to a gas resource inventory that is second to none in the industry.

To begin discussion of our first key takeaway point, let's review some numbers for the fourth quarter and for the year.

After excluding items not generally included in analyst calculations, Chesapeake's fourth quarter net income available to common shareholders was a $154 million or 44 cents per fully diluted share.

For the full year, net income available to common shareholders was 511 million or $1.56 per fully diluted share.

And for operating cash flow, we generated $424 million or $1.35 per share in the fourth quarter, and for the full year, $1.4 billion or almost $5 per share, which is especially remarkable since our stock can be bought at less than 4 times 2004's trailing cash flow.

In addition, we continue to tightly control operating costs.

The controllable cash operating cost of our business, which are general and administrative expenses, lease-operating expenses and interest expense totaled $1.60 per Mcfe this quarter versus $1.12 per Mcfe for the year-ago quarter.

Very few companies have been able to deliver lower controllable cash operating costs during the past year.

We work hard to control all of our costs and believe it is an outcome of our relentless focus on the details of our business and an outcome from our large operating scale, especially in the Mid-Continent, where we have considerable negotiating power with service and equipment providers.

We believe our large and focused operating scale remains one of Chesapeake's most important competitive advantages.

Moving to see my second takeaway point.

I would like to highlight that Chesapeake's strong financial results were driven by equally strong operational results.

Oil and gas production increased 40% quarter-over-quarter, 35% year-over-year and 9% sequentially.

In addition, the organic portion of this growth was exceptional, 20% year-over-year and 8% sequentially.

Keep in mind that this is from a company that is now the ninth largest producer of natural gas in the US.

Of the 8 companies that produce more gas in the US than we do, 7 had year-over- year production declines.

In addition, there are now only 3 independent companies that produce more US gas than us;

Devon, Anadarko and Kerr-McGee, and we expect to pass Anadarko in 2005.

And an interesting historical footnote; during 2005, the largest 3 independent producers of gas in the US will all be headquartered in Oklahoma City.

We think that is a pretty remarkable turn of events and all the more reason for you to come see us some time in 2005.

In addition to the strength of our production growth is the consistency of it.

The fourth quarter was our 14th consecutive quarter of record production, and 2004 was our 15th consecutive year of record production.

We are frequently asked, when does the law of big numbers kick in and make further organic growth impossible.

It is certainly a fair question and one we often ask ourselves.

In thinking through the issue, please consider that in 2001 we produced 470 million cubic feet of gas equivalent per day in the US and grew organically that year by 9%.

In 2002, we averaged 497 mmcfe per day and grew organically by 6%.

In 2003, we averaged 735 mmcfe per day and grew organically by 18%.

In 2004, we averaged 991 mmcfe per day and grew organically by 20%.

So in the past 4 years, we have more than doubled the size of our company and yet have averaged organic production growth of 14% per year, and have seen our organic growth actually accelerate in the past 2 years to an average of 19% per year.

We have examined the performance of every other mid - excuse me -- E&P company worth more than $2 billion and cannot find a better track record of organic growth during the past 4 years.

We would quickly point out, however, that you can certainly, pay much more for track records of much lower achievement.

We are very optimistic about the opportunities ahead for our shareholders, because in addition to closing the present valuation gap, we believe we can deliver 10% organic growth in each of 2005 and 2006.

If we are able to do so, it means that over the 6 years ending in 2006, we will have delivered an annual average organic growth rate of 12% from a company that will have more than quadrupled in size during that time.

This will be an impressive if not unique accomplishment in our industry.

We believe this is further evidence that our business model is scaleable and capable of continuing to deliver top tier shareholder returns for years to come.

Consistent with our remarkable production growth, I would also like to highlight a terrific year of reserve replacement.

We replaced our 363 Bcfe productions through the drillbit by 265% at a cost of only $1.30 per Mcfe.

Moreover, we replaced our production through acquisitions by 313% at a cost of only $1.36 per Mcfe.

In total, we replaced 363 Bcfe of production with almost 2 Tcfe as new reserve at a drilling and acquisition cost of only $1.21 per Mcfe, which increased our total proved reserves by 55% to 4.9 Tcfe at yearend 2004.

After the recently closed BRG acquisition, we now have 5.1 Tcfe of proved reserves and also have another 4 Tcfe as estimated non-proved reserves.

I would like to highlight that the PVT-10 of our proved reserves using yearend 2004 prices which are lower than today's prices, was $10.5 billion, and yet our current enterprise value is less than $10 billion, meaning that our 4 Tcfe of non-proved reserves and all of our other assets are being valued by the market for nothing.

Perhaps that makes it easy for you to see why Tom Ward and I together have acquired 5 million shares of Chesapeake common stock in the past 18 months.

We believe that we know great value when we see it.

My third takeaway point is this; we were early to believe that natural gas and oil prices were headed to sustainably higher levels.

And we invested billions of dollars accordingly and we are now distinctively positioned to continue reaping the rewards from those timely investments and to continue delivering top tier shareholder value for years to come.

In addition to the $5 billion of acquisitions made during the past 5 years, each of which can now properly be seen as a bargain.

We have also invested $3 billion of drilling CapEx during that same timeframe, which has created more than 500 million cubic feet of gas equivalent per day of new organic production.

And we have also invested $1.3 billion in new leasehold and 3-D seismic, which are the building blocks of future shareholder value creation.

While the aggressive investments in new leasehold and 3-D seismic have certainly been a drag on our earning costs during the past 5 years.

Today, it represents a serious competitive advantage.

In our view, companies that are just now beginning to believe in today's price decks will find the going tough when it comes to accumulating the human capital, the leasehold and the science necessary for delivering sustainable future organic growth.

And in the many areas where Chesapeake is already the dominant player, we believe it's game over in competing with us for future growth opportunities.

This leads into my fourth and final takeaway point.

Chesapeake's organic growth over the past 4 years has been the best among mid and large-cap E&P companies, because of the strong foundation of large and diversified drilling programs that we have built.

In the past several years, aspects of our deep gas exploration program have properly received considerable investor attention.

Today, I would like to highlight the broad inventory of gas resource plays that we have put together.

Many investors have focused on the upside potential from various companies and have successfully build 1 or maybe 2 gas resource plays.

In contrast, we have built an inventory of 7 very significant gas resource plays.

These are listed in our press release, but I would like to repeat the names for you here;

Sahara, in northwest Oklahoma, the Mountain Front Deep gas play in southern and western Oklahoma, the Granite Wash and Atoka Wash plays of western Oklahoma and the Texas Panhandle, the Hartshorne Coal and Caney, Woodford and Fayetteville Shale plays of the Arkoma Basin in eastern Oklahoma and western Arkansas.

The Barnett Shale play located in and around Fort Worth and the Cotton Valley play in Northern Louisiana, and most recently the Haley Deep gas play in southwest Texas.

In these gas resource plays, we own more than 1.3 million net acres on which we have identified more than 5,000 drill sites that have upside potential of at least 3 Tcfe.

In contrast, to many other companies' exposure to various gas resource plays, all of ours have already been proven to work.

We know that because we have already drilled almost 1,000 wells in total in these projects to prove them up.

Simply stated, net of Chesapeake's projected organic growth requires a new or untested play to work.

Therefore, the risk profile assigned to our growth projections should be much lower than if we were a company with a weak track record of organic growth that all of a sudden had a new play that just might work out.

By comparison, virtually all our growth will come from plays in the areas that have been working for us for years.

I will conclude by reminding you that the 2 keywords that define Chesapeake are focus and consistency.

Our focused business strategy works and through consistent execution of it, we plan to continue delivering large increases in the shareholder value by first delivering top tier per-share growth in production, achieved through a balance between drillbit growth and acquisition growth.

Secondly, by exclusively focusing on finding and producing natural gas, thereby taking advantage of very strong long-term natural gas supply and demand fundamentals, thirdly, by building dominant regional scale to achieve low operating costs and higher returns on capital; and fourth and finally, by building large acreage positions in some of America's most promising gas resource plays.

I will conclude by offering up Chesapeake today as a truly unique investment opportunity.

We have visible, sustainable, high level growth at a very attractive valuation.

As the Company's largest shareholders, Tom Ward and I remain very energized about Chesapeake's competitive position in the industry and the returns that we have created for our investors overtime.

We appreciate the investments that many of you have made alongside our own and we look forward to continuing to create significant value for you in the years ahead.

I'll now turn the call over to Marc Rowland our CFO.

Marc?

Thanks Aubrey.

Good morning everyone.

We have included in our press release what we consider to be the most thorough presentation of information possible.

So as our custom, we will not simply repeat numbers already presented to you.

There are a few items to comment on and to highlight, perhaps put a little more color on.

The most recent First Call consensus numbers for Chesapeake for Q4 earnings were 36 cents per share, and as Aubrey mentioned and we've highlighted on page 2 of our release, several items which are not normally included by analysts in the writing at their estimates, without those items as mentioned in our release, quarterly earnings were 44 cents per share.

So, we handily exceeded the expectations.

This was caused principally, by production that came in higher than even our expectations, higher revenue per unit, and cost that continue to be at the lower end of our guidance range.

The SEC has certainly clouded the issue on what companies can say about their finding and development costs, so we won't say anything that includes the words all in F&D cost.

We will instead point you to page 13 of our release where we reconcile all the cost incurred by various category by Chesapeake in 2004, and also present a full reconciliation or roll forward of the change in our proved reserves from the beginning till the end of 2004.

I would like to highlight that we once again enjoyed positive performance related revisions of 141 Bcf equivalent, which is about 4.5% of our beginning reserves, and only 5 Bcf of positive price related revisions.

The reason the price related revision is lower than one might expect is due to our gas concentration and the fact that gas prices actually did not change much between the end of 2003 and 2004.

Our exploration and development cost incurred directly drilling and working over wells was 992 million compared to extensions in discoveries with revisions of 962 Bcf equivalent, which calculates to a number of $1.04 per Mcf equivalent.

Without revisions, the extension in discovery calculations were 817 Bcf equivalent or $1.21 per unit.

Proved reserves added through acquisitions were 1.13 Tcf equivalent, and an initial cost incurred at 1.542 billion or $1.36.

Adding the cost of acquisitions allocated towards non proven properties, in other words direct leases acquired and G&G, less divestiture, adds another $725 million in cost incurred during the year, which brings the calculation of those costs incurred to $1.55 per unit.

That number is before a 22 cent tax basis stepup recorded on certain corporate acquisitions which of course, is not a cash cost to us in 2004, and is frequently recorded as goodwill by many acquirers.

And those costs, I would point out, are also before asset retirement obligation accruals.

Future development costs for proved undeveloped reserved are not included in any of the calculations that I gave you.

So, barring excruciating painful detail for you to calculate, that metric as you will, but, I think by any recent comparison, given the sectors performance, a very good year indeed, especially given the quantity of our reserve replacement numbers.

Let me discuss income taxes for a moment.

You may notice that we have increased our guidance for 2005 for our book tax rates to go from 36% to 36.5%.

I would like to remind you that this remains a non-cash or non current accrual, meaning our deferred tax liability will be increasing by our book tax expense and no cash is expected to go out the door for this expense in 2005.

We ended the year 2004 with about $550 million of federal net operating tax-loss carryovers.

We now expect to not pay any cash income-tax until at least 2008 when we may have a small AMT tax bill.

We do not expect to pay regular federal cash taxes until at least 2010.

We believe this tax position is a competitive advantage for our Company that will become even more obvious in the years ahead when many of our peers and competitors will be significant federal income-tax payers.

I should explain something about what may appear to be anomalously low number for Q4 which is our average common equivalent shares outstanding assuming dilution.

That number was only 328 million shares.

An accounting rule prohibited us from assuming the conversion of our 6% preferred stock issuance which was substantially converted into common stock by the end of the quarter because that conversion would have been anti-diluting.

I say this because you might be tempted not to follow our guidance for 2005, where we have guided towards 352 million shares fully diluted for quarter 1 and 355 million shares for all of 2005, but you should use those numbers.

A few housekeeping items that we normally cover.

For the quarter ended December 31st and for the full year 2004, we had capitalized internal costs related to our drilling programs of 16.4 in the quarter and $51.7 million for the full year.

That compares to 9.8 million in Q4 of 2003 and 35 million for the entire year of 2003.

Our capitalized interest cost for the year in 2004 was 13.1 million, and for the full year 36.2 million.

Again compared to quarter 4 of 2003 of 4.3 million, and 13 million for the full year 2003.

Our share position in Pioneer Drilling Company is 6.5 million shares at a cost of $28.5 million or $4.36 per share.

Recently, Pioneer has traded at around 12.25 per share for a net unrealized value to Chesapeake of $80 million, which amounts to a mark-to-market gain of over 40 -- of over $52 million for us today of course, which has not gone through our income statement.

This gain, along with the increased value of our own operated drilling rig fleet has partially mitigated the significant increase in drilling and service cost trends we saw in the last 6 months.

Finally, one item that we don't frequently speak about is our basis hedging program.

For some time now, and in fact going back to the summer of 2002, we have been concerned that Mid-Continent bases would widen compared to Henry Hub as most gas came on in the Rockies and as pipelines such a Cheyenne Plains were built to get that production into markets that could compete with Mid-Continent Gas.

As a result, we initiated a basis protection hedging program that has been remarkably successful.

Today, we have about 650 Bcf equivalent of gas swaps on for volumes starting in 2005 and going through 2009.

In 2005, for example, we have about 189 Bcf hedged and that number descends to a volume of 87 Bcf for 2009.

As of December 31, those swaps had a market-to-market value of $122 million positive to Chesapeake.

And this is in addition to having collected $79 million for these favorable basis hedging during 2003 and 2004.

So, in basis hedges alone, about a $200 million gain including our market at this point.

In conclusion, we look backwards to 2004 as the most successful year ever for Chesapeake, while simultaneously looking forward to 2005, 2006, and beyond, and seeing in equally bright future.

Moderator, we will now turn the call over to questions and the answer portion of our call.

Thank you.

The question and answer session will be conducted electronically.

If you would like to ask a question, please do so by pressing the "star" key followed by the digit "one" on your touchtone telephone.

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

Once again, that is "star" "one" to ask a question.

We'll go first to Joe Allman at RBC Capital Markets.

Good morning, everyone.

Good morning, Joe.

Aubrey or Tom, could you comment on your results so far in the Haley Deep play and actually, if you -- what kind of drilling you have done to date and what your results are?

And what was your acreage position about 6 months ago?

This is Tom.

We currently have 4 rigs that we are drilling, one rig actually just getting ready to start drilling, 3 drilling now.

In Haley Deep, we currently have about 100,000 acres of net acreage in the deep Delaware play, and 6 months ago, we probably would have been about, just guessing, 30,000 acres or so.

So, we have increased that dramatically and it could have been 50,000, we might have just doubled it in the last 6 months.

We have one -- none of those well are TDed yet.

And I might add to that, of course, this is a play that Anadarko kicked-off about -- what -- Tom, year ago - year and half ago?

Probably year and half ago.

Yes, year and half ago.

I heard at a recent conference that they are producing right about 100 million per day of gross-production from about 7 wells, they said.

And I believe, Tom, how many rigs, they are drilling out?

I think they have 5.

5 rigs in that area.

We are in an AM with them covering a significant minority of our acreage position there.

So, we're both competing with them but also cooperating in the development of those areas, so, probably the newest and most exciting aspect of our drilling inventory as we look into '05 and beyond.

And then my understanding is that -- I heard that one operator had a well that IPed at something like 40 plus million a day.

Are those the kinds of wells we might see here?

Yes, Joe, at least 2 wells that have IPed over 30 million.

Just looking at production to date, I think we see some reserve potential of any where from 20 to 40 Bcfe per well.

Okay.

And then those, I guess, those 4 rigs will get you how many wells down this year?

Pardon me, Joe.

I am sorry.

Those 4 rigs will get you how many wells down this year?

It take about half a year to drill, 6 months and we drill rig -- could 2 wells in a year.

We have one well that is near TD, to others that are probably about half way.

So, my guess, by the end of the year, we could get probably 5 to 7 or 8 wells down.

That's it.

Thank you.

Okay, Joe.

Thank you.

We will go next to Jeff Mobley at Raymond James.

Good morning.

Good morning, Jeff.

Guys congratulations on a great quarter.

Thank you.

Following up on Joe's call, could you also maybe talk about some of the recent results in your Mountain Front trend and the Mayfield areas?

We can.

I have a print out of that I need to get.

Tom, why don't you talk about - Jeff, rather, we may have to come back because I forgot to bring it over here.

I can run through where our rigs were.

We have got 10 rigs working in the Granite Wash, Red Fort portion of the play.

So in Sahara locations, we also have 11 rigs working in the deep portion of Anadarko.

Aubrey has, as he said, a sheet that's going to show what the average reserves are, on (inaudible).

Okay.

Great.

Also it sounds like the initial drilling on the Sligo Field that you guys have done has been pretty productive.

Could you comment on how much running room you have there?

We still have at least 2 to 3 years of drilling there with a 3-rig program.

So still a lot to do in the rig, the wells have been coming in just really as we expected.

Okay.

Great.

And just lastly, in terms of service costs, obviously day rates are starting to get a little bit of pricing power.

Could you comment of how you all plan to manage that pricing environment and any other risks on the service cost that you see to, what is that, really an outstanding drilling program?

As we build rigs, we are releasing some rigs.

So that's our hedge would be with their own rigs and through owning in Pioneer and then other than that, would be just our scale that we tend to get a little better pricing.

But as we release rigs, they're being utilized, so we're still seeing a very tight market.

Okay.

Now, correct me if I'm wrong, is it 6 rigs that you all build recently?

We have 9 rigs, Jeff, that are up and operating for our own account.

And as of today, we have 11 additional rigs that are on order.

So those rigs will be coming on basically at 1 or 2 a month all throughout 2005.

Joe, let me also jump in.

The cost basis of our total investment in Pioneer and in our rigs is about $85 million.

And we have a valuation in now, I think, fair market of that of about 175 million.

We, I think, Marc mentioned that we were headed -- we have got 20 total, but, I think, we are in the process of approving another 4 or 5, so we could see by early '06 having a 25 rig fleet.

And our view is if the service industry -- if the drilling contractors are not going to build them, we will.

We believe they're reasonably good store value and we don't expect to get any value from shareholders for these, although we think we should, but we are fully expecting not to.

But for -- the biggest risk in our program today is a rapidly rising service cost environment.

So, we have to do a couple of things to try and offset that.

We have to have scale that allows us to have access to rigs, and we have to have scale that allows us to have negotiating power, and then if the service industry is not going to build capacity to handle our needs, we will.

And that's what we do through our program of building rigs inside of no-MAC drilling, which is our subsidiary and through holding a stake in Pioneer, which gives us exposure synthetically to about 11 or 12 different rigs.

And last one for me, your production guidance appears conservative given the strong organic drilling results you guys have had in 2003 and 2004.

Is that mainly a kind of a baseline forecast and there is upside through some of the exploration work that you are doing through the year?

Jeff, I would say, it's just entirely consistent with how we've approached it in the past.

We've told investors and analysts that we don't really budget for exploration success that we drill fair number of exploration wells and to the extent that they exceed what we are budgeting, then that's where we have upsides.

Surprises -- you may recall in Deep Springer play in western Oklahoma, we were originally planning for about 5 Bcf fee per well, and 5 million a day initial production, and we ended up doing much better than that.

In fact, the sheet that I was referring to, I meant to tell you, we've now drilled 16 Springer wells with average reserves of 21 Bcf.

So that play has exceeded our initial expectations by 4-fold.

Out on Haley, Tom, our per forma would be what kind of IP and reserve estimate?

We should IP in the 20 million a day range and look for 10 to 11 Bcf per well.

So we think there is still upside there, Joe, so I would say that our guidance is based on the same kind of outlook we've had towards our business in the past.

And if we do better than it in '05, it will be because of our exploration programs working at rates and recoveries higher than what we initially estimated.

All right.

Great.

That's it for me.

Congratulations on a great quarter and a great year.

Thanks Jeff.

We will go next to Ken Beer at Johnson Rice.

Guys, you've hit all my questions.

So I will let you go.

Thanks, Ken.

Next, we will go to Ellen Hannan at Bear Stearns.

Good morning.

Good morning, Ellen.

Yes.

Thank you.

A couple of questions.

One, Aubrey, on your outlook for your reserve adds going through 2005 and 2006 in your production growth.

It would seem that you are indicating 20% production growth in '05.

And my first question is, 10% organic, 10% from acquisitions, for those acquisitions, that's why you completed in '04 or are these yet to completed?

Those are the full year contributions from...

The '04.

Positions made in '04 plus one, we have made today in '05, which is our BRG.

Okay.

And that explains, why in '06, we have an 11% production gain forecast versus a 10% organic forecast for '06.

That 1% comes out of full-year contribution in '06 from BRG versus the partial year contribution in '05 from BRG.

Very good.

The second question is looking at you, where you're starting 4.9 Tcf, excluding the BRG acquisition in your forecasted production.

Where you're going to forecast your end year at 5.4 T that would imply reserves adds of about 2 to 1 relative to your forecasted production now.

Can you comment on, would you think, that's going to come from problem possible into the pipe category, is that acquisition oriented or how do you expect to account for that?

Probably, I mean, for sure, a combination of all the above.

Keep in mind, Ellen, we ended at 4.9, we're at 5.1 right now with BRG.

And so we did pickup 200 -- and I think, 223 Bcfe on February 1st from that acquisition.

So we tried to be conservative in all of our projections and at this pace given the 200 that we've got from Bcf -- from BRG.

We were actually projecting well under 2 to 1 reserve replacement but hopefully, we will get there.

Okay.

And I guess, the same would be true that if you follow that -- if my math is true, for the end year projections for end of '06 to get to 5.8 T, that again would imply about a reserve replacement about 1.8 times.

How much of that do you think or are you planning -- I'm just pulling in from your kind of your unproved inventory today versus any future acquisitions?

Well, we are not budgeting for any acquisitions in '06.

So all of that reserve growth would come through the drilling well.

All right.

One another question too then on - this is just a little bit unusual for you, your percentage of reserves at the end of the year, the percent is undeveloped, it's a little bit higher than usual, can you comment on that?

Yes.

We made a lot of acquisitions this year that were of different nature than acquisitions that we have made in previous years.

And that reflects the fact that in many acquisitions, we may have very large PUD components to them.

In the years going by 2000, 2001, 2002 we were more looking to expand our foundation, if you will, of production.

And so we were much more focused on deals that had -- that base of production and perhaps a little less upside today.

Given the strengths of the company's foundation of production, we are attractive to acquisitions that do provide a large degree of drilling upside.

We feel like we are distinctively positioned to be able to create value in these acquisitions because with our command of 67 operated rigs, this morning.

We can take probable and possible reserves and convert them into -- and PUDs for that amount and convert them into cash producing assets.

We think more quickly than almost anybody else in the industry.

Okay.

Just two other quick questions.

One for Tom, on the heavy deep play, the Anadarko talked about some pretty high well cost initially out there.

Can you comment on what are your cost per well and kind of what you're projecting?

We anticipate spending about $8 million per well that does include some price depreciation or cost depreciation.

So starting out with 7 million and probably move into 8 million depending, if we have any trouble on any of the wells.

All right.

And I guess, one final question for me, kind of a broad question Aubrey, in terms of owning 25 rigs, can you comment about the crew availability and kind of the cost of managing that operation within an E&P Company?

It has been a real pleasant surprise.

We were initially -- frankly quite a bit nervous about building this inside of an E&P Company, worried about management diversion and having a big slug of workers that had a reputation for not sticking around and being not the highest quality individuals, let's say.

But we've really attacked that through a couple of different programs.

One, we have put our rigs to work in areas, where they stay for a long, long time.

In fact, we're talking about multiple years, and so we can attract workers, who are living on locations that can be going home every night to a more stable family environment.

In addition, we have 401 Ks, we have full health, we have some very forward-looking safety programs.

And so, our view is that we run the best drilling contractor that we work with and we think we should.

We have all the attributes that we think can lead to successful drilling contracting efforts.

And so, we think, it would be difficult for drilling contractor to run an E&P Company, but given the right effort and focus, we think it's possible for an E&P Company to run a top-notch drilling company.

And that's what we have done.

The question will be ultimately on exit strategies and if you may recall, we successfully executed an exit strategy from our previous rig investments, which remained in the 1994 to 1997 timeframe.

And in that time, we helped build the fifth largest drilling contractor in the country called Bear drilling, to get public.

And Marc, we had a 80 or $90 million...

$83 million gain.

Yes, in that on and probably $10 million investments.

So today we are already up almost a 100% on our 80 to $85 million investment in rigs and before it's all over with, I'm sure, we will do a quite well.

And this is how -- it's a very significant hedge to our exposure to what I think, it's the biggest risk that we face, as a company, which is rising service cost.

Great.

That's it for me.

Thanks very much.

Thank you, Ellen for your interest.

Next, we will go to Phil Pace at Credit Suisse.

Good morning, guys.

Hi, Phil.

A couple of things.

Could you give us an update on the activity in the Barnett and how you see those reserves playing out?

And second, beyond rigs, where do you see the tightness on the service and equipment side?

And Aubrey, I guess, maybe finally, I would like to -- Aubrey to hear your comment on $6 gas and a $50 world is that an opportunity or how does it make you nervous?

Phil, this is Tom.

On the Barnett area, we currently have 2 rigs running on their way to 4 and we continue to run our reserves at 2.5 Bcf per well.

And so far, we are pleased with what we're seeing there and we might even been able to be a bit above that on the pro forma basis.

On the cost side, we're continuing to run at 2.2 million per well.

I might also say Phil, our strategy in that area is to play it pretty tight into the areas that are working in Feather Turrent (ph) and Johnson counties.

And Tom, did you mentioned, how many non-op rigs we were in through Hallwood?

No that was just our operated.

So we -- I think, they currently have 2 rigs running and it would be -- they might be moving to 3.

This would be on the South Block, which is continuing to work as well.

So we're on the ground out there everyday and are having success adding to our existing Barnett leasehold.

But I don't think yet you will see us way out west chasing, what we think is highly expensive and highly speculative acreage.

With regard to commodity prices, we have no trouble -- and being bullish on the long-term basis.

The short-term outlook, as evidenced by our hedge book, I hope you all have noticed that, and some people have a hard time reconciling, how we can be both.

But in reality, we think that it's not inconsistent at all.

And particularly, when we look at our hedges for the first quarter, we are 68% hedged at 682 in Mcf and for the year about half hedged at 624.

So, I don't think that reflects fear as much as it reflects some real opportunities.

With regard to $50 oil and $6 gas, I think, it's a great opportunity for gas.

A lot of people have been concern about ending inventories, and they're certainly going to end pretty high 1300, 1400 Bcf and some people will say that means lower gas prices.

I think we have lower gas prices.

We have gas prices trading and Btu discount right now was almost 30% that have been very few times in last year's when the discount to oil has been that high, and I think, it's probably reflects the fact that we had another disappointing winter weather season and we've got a lot of gas innovatory that we've got to get rid of it and to do so we've got to see it be burned at a Btu discount to oil.

So, we're optimistic going forward that we think we will see a spring rally and depending on the weather, we will see gas prices moved to Btu parity with oil this summer or perhaps beyond if you get really warm summer or get an active hurricane season.

Few with regard to areas that are raising prices that we see here, obviously, the steel, the pumping services are continuing to rise and something we are working on here fairly hard.

And then, really everything else from locations to, I guess, any service that you're seeing in the business is rising right now?

Not the least of which is people.

Yes.

I mean, we're very thankful that we are an early mover and have now added over 300 Landman Geologist, and engineers to our staff and now have a total of 400 in those departments.

If you're just trying to gear up today, I really don't know how you go about doing it.

It would be very, very difficult.

We also have over 450 Landman in the field so that's would be hard for anyone else to put together that crew.

Sounds pretty solid.

Thanks Aubrey.

Okay.

Thank you Phil.

We'll go next to Dan Morrison of Aperion Group.

I think you guys have covered all of things that I have.

Good quarter.

Thanks Dan.

And next we'll move to Ryan Zorn of Simmons & Company.

Good morning.

I think one of the more impressive part reserve, what was the magnitude of revisions upward from performance and I wonder if you could give us some details perhaps regionally where those originated?

Ryan again it's a good question.

You know, positive revisions of the 140 Bcf, I think, that was 4.4% of the beginning reserves.

There really wasn't anything material or notable about that.

I think there are 20,000 entries in our reserve bookings, so it's across the board really.

It doesn't take very much turning on some of these resource plays to go from 0.6 Bcf to 0.62 Bcf when you got a lot of wells those are performing very well to get that kind of revision.

Basically, our reserves are spread across so many different plate tags that I wouldn't point to one and say, we had a significant revision in one field or one well, that's just really across the board.

At the Tight Gas Sands and Mitchell place lean to better reserves over time, so as people get more comfortable with those types of plays, I think, we tend to start out with lower expectations and the rise in over times -- rise in over times.

So, I'm not that surprised and we will look for that to happen really in the future also because more and more companies, including us, are drilling those types of wells.

Tom, you've mentioned -- I wondered if you could break out the numbers of people you've added in each one of the 3 departments that you recorded and having a total 400 folks in-house, inland, G&G engineering side?

It's a -- Ryan it's really we add about 100 in geoscience and would be about 150 in engineering and about 150 inland and of course Tom mentioned on top of the 150 in-house people.

We have about 450; you've seen this is high as 480 workers out in the field buying leases every day.

You might notice that we spent $300 million in '04 on land, so for every business day, we are spending about $1.3 million on new leases.

So we're out fighting every day and I guess really more people are fighting us as we tend to have the dominant lease acquisition programs in areas which we choose to work.

Yes.

The threefold increase there is big.

The reserve base has probably increased little bit above that over the same period.

You probably continue to put people on board?

We do one of the things that we haven't talked about is, probably, how little some of our other departments have grown over the last 4 years in terms of percentage get to the scale ability of our operation, if you go back to 1998, we had about 600 employees after DOB...

I think when we finally trimmed all down; we got down to about 550.

Yes.

And so today we have about 3.5 times more employees and about 7 times more assets than we had then.

So, again, in the departments were you would expect scale to bring you the ability to add more assets without adding people or certainly able to do that.

But we felt like there would be a day when people were in short supply and we scooped a lot of folks up and cleverly done so.

We got them locked down with an attractive equity compensation packages that's worked well.

We are out there every day after new folks because we have added in the some new geographies where we were initially weaken people -- need to add in that.

One final thought on people, as we are aggressively hiring young people.

Tom and I think may be about the youngest E&P lead executives out there in large cap companies, and we don't feel so young anymore.

So we are aggressively have been over the last 3 or 4 years aggressively targeting young people.

I will say this is not easy.

Last year, the USA graduated 480 petroleum engineers, and graduated 43,000 lawyers.

So as long as you have that relationship between petroleum engineers and lawyers, I think, our country is going to have some long-term energy issues to deal with.

Okay.

I'm wondering just on the tightness not only rigs but getting to the completion services as well.

How much more man hours are you dedicating to keeping things scheduled given your industry leading activity levels?

I mean, probably not as much as you think.

Because of -- if you are a contractor, I mean, if you are a service provider of any size in the Southwestern US, we probably are your number one customer.

So it's been quite a bit of time focused on our count as you showed and we respond or reciprocate by making sure that you've got a stable course of high quality business.

So which we expect your best people and we expect your best pricing.

Okay.

I would also think that rig activity in Oklahoma has been stable past couple months and that's our biggest area.

Just few points.

The rig activity in Oklahoma has been the centered between 150 to 160 rigs actually since last April.

One of the reasons why we think '05 and '06 might be surprisingly difficult years for the production and you are seeing a narrowing of the year-over-year rig increases and the numbers of rigs in use today and across the country and as well as in places like mid-continent that have been some of the best performers onshore in the last couple of years.

You know that's a combination, people ask why, that's a combination of either there are no rigs or there no crew or there is no prospects or executives, E&P executives are listening to analysts tell us about 450 gas or $4 gas or real watching future prizes and predict lower gas in the future.

So, probably a combination of all those things and we are attacking each one of them with a distinctive strategy.

Can you comment on the basis market and then kind of quickly where is it today and where your trigger points for adding more your basis position there?

The current basis curve is at - depending on exact point negative 50 to negative 54 or 5 cents.

That would say be a panhandle type of basis and that's minus 51 cents let's called at to Henry Hood.

As you look on the forward basis curve, it's basically cyclical depending on the season.

The summer bases is slightly tighter at -- call at minus 40 to future winter bases over the next several years about the same as it is today, call it did ask if minus 52 to minus 55.

We remain concerned, most of our basis, now that 650 Bcf forward basis locks is locked in the low 20s we've got some that we put on as little low 2 years ago as minus 14 cents.

So, we've done a good job in retrospect, we probably should have done a whole lot more when it was available.

But now, people are as Cheyenne Plains has come on and the capacity to move additional gas into the Mid-Continent and ultimately up into the Chicago markets is just bringing that same gas on gas competition that the Rockies saw over the last several years and which caused their basis to blow out to sometimes as much as several dollars negative.

We're not seeing that kind of an effect and I don't think we will.

But it certainly -- it is certainly an area where we're continuing to focus on.

Sounds like your target still is to be below 50 cents to lock in.

Yes, I mean the reason we're not just going out latching on to it is that the market, to begin with is dim and you don't have a lot of people willing to take it on.

And at 55 cents let's call it the bid, we would, for any significant volume its probably just even risk/reward for us.

So, we don't like to hedge those, we like to hedge when its to our advantage.

Okay.

Thanks a lot.

We're done.

Yes, thank you Ron.

We'll go next to Kelly Krenger at Banc of America Securities.

Good morning.

I just had a couple of questions.

The first one is, Marc can you tell us what the year-end balance on your revolver was and what it is now?

I can.

What it is today, we're kind of in the low part of our cash cycle because revenues won't start coming in until this next week.

And last I saw a revolver day before yesterday, we were at about 600 million drawn after the BRG financing.

So, that's what the actual (multiple speakers)

After the revenue cycle...

The revenue cycle adds about 250 million, so I'd expect it to go down between 300 and $350 million.

Okay.

Let me tell you what it was exactly at the yearend, 59 million outstanding at 12/31 Kelly.

Okay.

And then the second question, it seems like typically your -- at least over the past few years your internal CapEx has been about 40 or 50% of your total CapEx and the rest is acquisitions.

Based on what you see out there in the acquisition market now, is that -- do you think you'll have a similar ratio in 2005?

Kelly, its completely unknowable.

We could easily imagine a scenario where we are not able to find anything.

And that's the way we run our business, completely content to do nothing but drill wells on a go forward basis.

The reality is we probably will find some things to buy out their that will likely be add-ons to our existing geography.

They're likely to be small, certainly relative to our enterprise value today.

And likely to be private companies, and so given that though, it's a highly competitive environment.

There are a lot of companies that are our competitors and obviously from what they released this year have struggled in '04 with finding costs and a way to try and fix finding costs as to bid up personal acquisitions.

So, we're mindful of that, but we do feel like we have some pretty serious competitive advantages when it comes to making these acquisitions.

We've got operational scale in the areas in which we compete, and we've got the ability to put the drillbit to the properties more quickly than most people can.

And oftentimes, we have a seismic advantage as well that may give us a deeper insight into the potential upside of the properties than may be some other bidders.

Okay.

Thank you.

Okay Kelly, thank you.

And we'll take our last question from Ken Beer at Johnson Rice.

Yes, just real quick, you all are obviously producing upwards of a B a day, as you look to your hedging, how is the liquidity in that market, Marc?

Is that something where you're not worried about getting off hedges or do you have to wait for the market to want your gas to go and put the hedges in place?

Ken, this is Marc.

Actually over the last year, I would say that the depth or liquidity of the hedging market has actually improved.

Again, we've seen new players come in, large players.

Today we can execute hedges with 10 or 12 different players if we wanted to.

You have very sizable positions being able to be offered by Morgan Stanley, Goldman Sachs, BP, Bank Paribas, Deutsche Bank, UBS, just you know, Sempra Energy, it just goes on and on.

I would say that liquidity for the first 3 years in the net gas market is significant.

Could we do 200 million a day in 5 minutes?

Probably wouldn't want to because of the bid ask but if we wanted to hedge 20% of our production in for the first 3 years in one day, I think we could actually get that trade-off fairly easily.

We frequently do 30 or 40 million or 50 million a day, and basically it can be quoted in a minute.

If you get to the outer years, which we don't do much hedging in, we haven't -- its been backward dated so we haven't seen the opportunity.

You're going to give orders to people and let them work it.

Quantities could be done, you know, 50 million might take you a couple of days to get the price you wanted and say you're 5 through 7, but it can be done.

Okay.

That's helpful.

Because sometimes you just look at the screen and you're not sure of that, the price but it sounds like at least in the first 2 or 3 years, what you're looking at on the NYMEX screen is not a bad indicator.

Yes, I would say 18 months to 24 months it's spud on and then from years 3 through 6 you're probably going to have as much as a nickel to 10 cent bid ask with it getting wider in the back but the screen is relatively indicative of what can be done.

Okay.

Ken, I would also add that we tend to be hedging on updates.

Right.

And its just easier to get things off.

You like to hedge when other people are scared and don't want to be hedging on down days when maybe other producers might be scared.

Fair enough, Thanks again, guys.

I appreciate the questions.

And Mr. McClendon, there are no further questions.

I'll turn the conference back over to you.

Yes, Ma'am.

Thank you very much.

I appreciate everybody's participation in today's call.

If you have additional questions, please let us know.

Thank you very much.

Bye-bye.

And that does conclude today's conference.

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