Chesapeake Energy Corp (CHK) 2006 Q1 法說會逐字稿

Good day, everyone, and welcome to the Chesapeake Energy first-quarter 2006 conference call.

Today's call is being recorded.

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

Please go ahead, sir.

Good morning, everyone.

This is Jeff Mobley.

Thank you for joining Chesapeake's first-quarter 2006 earnings release call.

Before I turn the call over to Aubrey, I need to provide you with disclosure concerning 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 on 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 and EBITDA, and will also mention several items that we believe are typically excluded from analyst estimates.

These are all non-GAAP financial measures.

Reconciliations to the comparable GAAP measures can be found on pages 15 and 16 of our press release issued yesterday.

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 this morning should last about 15 minutes, and then we will move to Q&A.

Aubrey?

Thanks, Jeff, and good morning to each of you.

I would like to begin by introducing the other members of our management team, who are on the call today -- Marc Rowland, our CFO;

Steve Dixon, our Chief Operating Officer;

Mark Lester, our Executive VP for Exploration; and Jeff Mobley, our Senior VP of IR and Research.

We're clearly off to a great start in 2006.

Production is up for the 19th consecutive quarter, and production is also up 31% year over year and 7% sequentially.

Our trailing 12-month organic growth rate is 13%, and we expect to reach double-digit organic growth for the calendar year 2006 for the fifth year in a row.

Our proved reserves are up to 7.8 Tcfe on the strength of 312% reserve replacement at a cost of only $2.13 per Mcfe.

Our hope is to end the year north of 8.5 Tcfe of proved reserves and to keep our reserve replacement costs inside of 2.25 per Mcfe.

We correctly anticipated the direction of oil and gas prices in this quarter and collected $248 million in cash as a result of our favorable hedges.

I hope that you have noticed we have taken virtually all commodity risk out of the CHK equation in 2006 and seriously reduced such risk in 2007 and 2008, which will likely help Chesapeake achieve margin expansion while others in the industry may endure margin compression.

Just to remind you, we are 80% hedged in 2006 at 9.45 per Mcfe, 56% hedged for 2007 at 9.98 per Mcfe and 41% hedged in 2008 at 9.36 per Mcfe.

So, all of you guys out there who trade us every day as just a proxy for natural gas prices, let me remind you that we are no such proxy.

Instead, we are a high-powered organic growth machine that has virtually no exposure to potentially lower oil and natural gas prices for the next 2.5 years.

We have a top-of-the-industry organic growth track record and similar double-digit future growth potential.

We have an industry-leading gas resource position accompanied by favorable drilling rig arrangements.

In addition, we communicate with our investors using an unusual level of candor, disclosure and transparency.

We hope that you have also noted that in addition to successfully mitigating oil and natural gas price risk, we've also been very proactive in mitigating our exposure to rising service costs.

The first tangible reward from that program was the sale this quarter of our Pioneer Drilling stock for a gain of $117 million.

By the way, if figured into this quarter's calculation of finding costs, that gain would have lowered our finding costs by $0.23 per Mcfe or approximately 10%.

Behind Pioneer, we have two other private drilling company investments that will one day be harvested.

We hope for similar-type gains.

Just to remind you, those drilling companies are Mountain Drilling, where our partner is Lehman Brothers, and DHS Drilling, where our partner is Delta Petroleum.

Plus, we're continuing to build out our wholly-owned subsidiary, Nomac Drilling Corporation.

By the end of the year, we should have 57 rigs owned and operated and drilling, which will make our fleet one of the 10 largest drilling rig fleets in the US.

And, literally, we have built this very valuable rig fleet in our spare time in just the past four years.

As to our drilling operations, since we have locked in our revenue at very high levels and have successfully mitigated some of our exposure to any further increases in service costs, we believe it's time we get after it with a drillbit on a scale the industry has not seen since 1984.

It's been 22 years since the Company in our industry operated more than 100 drilling rigs.

Way back then, both Amoco and Exxon did it and we should be there as well by late summer.

As I recall, Amoco had 3 million net acres of leasehold at that time and this was widely considered the largest leasehold position in the industry.

I would also point out as a historical point of information that Exxon today is using 10 rigs in their drilling program versus over 100 22 years ago in the US.

Today, by comparison, Chesapeake is operating 87 rigs and we own almost 9 million net acres on which we believe we could drill as many as 29,000 wells and where there may be an additional 9 Tcfe of unproved reserves to accompany our 7.8 Tcfe of proved reserves.

The best news is our shareholders get all this upside virtually for free, given that the PV-10 value of our proved reserves and the book value of our non-oil and gas reserve assets was $19.2 billion at quarter's end.

So, basically, when compared to our current enterprise value of about $21 billion, you get 9 million acres, 29,000 locations and 9 Tcfe of upside on top of one of the industry's very best organic growth track records for just $2 billion -- a bargain in our view.

You might keep in mind that the PV-10 of $17.6 billion that we gave you at quarter end assumes that -- a, gas prices remain at $7.18 forever, which is well below the strip today; b, costs stay at levels associated with $10 gas; and c, basis differentials stay wide.

Using a gas price that's closer to the strip, our PV-10 exceeds our enterprise value.

So actually, you get all the upside for free.

As you know, we don't trumpet our individual well results because we don't like to tip off our competitors to anything we're doing.

We believe what really matters are the actual full Company production results quarter after quarter, year over year, not with some individual well IP sort during the summer.

This quarter, however, we did want to single out and congratulate our Barnett Shale geological drilling and operations team for establishing Chesapeake as the team to beat in the Barnett Shale in terms of per-well productivity.

Bringing on so-called monster horizontal Barnett Wells in Johnson County, Texas is a CHK specialty these days.

We have the independently-validated results to back up that claim.

I hope you will take the time to study the Barnett horizontal per-well productivity table on page 8 of our release.

This is one of the many reasons why we are rapidly excelling our drilling activity in the Barnett to as many as 20 rigs by the end of this year.

We also look forward to transferring some of what we have done so well in the Barnett to our other shale plays in Texas, Oklahoma, Arkansas and Appalachia.

During the rest of the year, we will continue to power forward and accelerate our drilling activity Company wide.

We look forward during the remainder of 2006 to our production reserves going higher, gas prices going lower and our investors making money.

On those happy thoughts, I will turn the call over to Marc.

Thanks, Aubrey, and good morning, everyone.

My theme this morning will be on margins, the great margin creation and protection that we have been pursuing.

Let's turn to hedging.

One of the most important events and resulting disclosures in this quarter's press release is the extensive additional hedging we have entered into in the last month.

We have now hedged over 1 trillion cubic feet of future gas production and 7.5 million barrels of future oil production and have hedged it at really phenomenal prices.

This is a record level of volume production hedged for Chesapeake.

We've done it for margin creation and protection, not fear that prices are set to crash.

What has made this hedging possible, while at the same time not creating a liquidity shortfall or dangerous situation caused by margin requirements if prices were to continue to rise substantially, is the hard work we have done over the last several years to create unique, secured hedging facilities and separate capped margin arrangements.

These many counterparty arrangements are all with substantial investment-grade industry and financial players.

The depth of this market continues to expand for Chesapeake, with yet another substantial player offering us totally unsecured lines this last week for what could easily be 20,000 to 30,000 gas contracts.

It's all about margins.

Chesapeake has guaranteed strong future margins, reaching all the way into 2008.

You will also notice that when we file our 10-Q in a week or so, the Company has been busy locking in additional basis positions, this time in the Appalachia area for the newly-acquired CNR production.

We have hedged a substantial amount of our basis now for future production there through 2008 and 2009 at positive basis differentials to Henry Hub.

Only this area provides the opportunity for substantial positive basis compared to the rest of the Company's production.

Let's turn to costs.

Costs are up; this is not new news.

Margins remained strong, in fact, at record levels given our hedging.

But, in fact, costs are up.

This includes operating costs, drilling, and completion costs.

Every component of operating costs from labor, benefits, fuel, insurance, ad valorem taxes particularly, vehicle cost and compression are higher.

But, fortunately, as Aubrey says, we're talking about cents per Mcf equivalent versus revenue increases of dollars per Mcf equivalent and yet another reason for us to be hedging at record high prices during the last month.

I will give you just a few examples of what we are seeing in the area of cost.

Due to the extensive use of pressure pumping and hydraulic stimulation, pumping services are up.

We've seen per-job costs go up anywhere this quarter from 3 to 28%, depending on the type of frac in the region.

The volume weighted average that you might use would be 12%.

Most of this has occurred in Q1, as some of our previous umbrella agreements that had maximum pricing arrangements are rolling off.

On the drilling rig side, rig rates do continue to climb.

We are very proud of the investments we've made in our various drilling rig ventures, particularly Nomac Drilling.

So a lot of these costs are mitigated for us.

But, new contracts for all operators on 2,000 horsepower rigs now range generally from 21,000 to $25,000 per day.

This would be both Mid-Continent and into the Gulf Coast at the higher rates, with Chesapeake's current high rate at $22,500, which is in the Gulf Coast.

To give you a sense of how much that has escalated, six months ago, these rates were between 15,500 and $18,000 per day.

Going back a year ago, a sample would've been 14,000 to 17,000.

Similar increases have occurred at the lower horsepower rates.

For example, 1,000 horsepower rig currently range from 17,500 to $23,000, with our current high being about 18,750.

Cementing services are up approximately 5% in the last six months and in the last 12 months, have risen about 11% overall -- similar things in logging and in casing.

We have taken and are continuing to take steps to mitigate our cost of course.

Our $117 million profit on PDC for example is equal to about 5% of our entire CapEx budget for 2006 to put it in perspective.

Our rig investments made originally beginning in 2001 now total just over $280 million for 34 rigs.

We believe these could easily be sold for 150 to $200 million more today if we chose to capture the value that we have created there, again, accounting for 4 to 8% or so of our CapEx budget.

We are investing in additional rigs today, trucks, compressors, and other equipment to further mitigate not only costs but supply issues going forward.

Let's look at our service operations income, another way that Chesapeake is creating margin.

Given the size and the scope of our drilling, trucking and compressor businesses lodged within our core E&P business, we have this quarter begun to break out the gross margins for this segment.

In this quarter alone, we generated just less than $15 million in operating margin, all from third-party, non-Chesapeake receipts.

By the end of this year, this segment could easily be on a 75 to $100 million annual run rate for gross margin.

To put it in net profit perspective, this quarter alone, we generated $6.4 million of after-tax net income contribution for the service income segment.

A few bookkeeping items and we will turn it over to questions.

Our bank debt at 12/31 -- or at 3/31, excuse me, was $444 million outstanding.

We converted $26 million of various preferred stock issues into common stock during the quarter.

We paid no cash income taxes during the quarter and expect 100% of our booked tax liability to be deferred in 2006, 2007, and 2008 if prices remain less than $9 per Mcfe equivalent.

At $9, some small percentage of total booked taxes will become cash paid in 2009, three years away and thereafter, while no cash taxes would be due in those years at $8 or less per Mcfe equivalent -- a substantial asset and another way that the Company is creating cash margins.

One final item, our capitalized costs for the quarter.

During Q1, we had $31.3 million of capitalized interest cost as compared to 16.0 million one year ago in the comparable quarter.

All other cost related to our drilling and completion programs that were capitalized during the quarter were $35 million in the current period versus $20.5 million in the prior period, simply a reflection of the level of activity and the scope of our drilling program.

With that, we will conclude our comments.

Moderator, we will turn it over to the question-and-answer session.

(Operator Instructions).

Joe Allman, RBC Capital Markets.

Aubrey, could you give us your thoughts on the gas market over the near-term and a little bit further out?

Sure, Joe.

I think that we have been concerned about gas production trends being a surprise on the upside.

And over the last six to nine months, we were concerned about winter gas demand disappointment and we have positioned the Company in a defensive posture accordingly.

I guess another way to think about it is we have certainly played offense by locking in gas prices at close to 9.50 in Mcfe.

So, it sure seems like gas prices probably need to be lower to stimulate additional demand.

But, whether they go lower from here, not as largely irrelevant for us as we again have locked in prices well above today's strip.

What may very well happen towards the end of injection season is you'll have pressures built throughout the system at such levels that basically every producer will involuntarily be shedding in enough production to balance the system.

If you are at 3.4, 3.5, 3.6 Tcfe in October for example, it's not clear to us that gas prices would then have to go to $2 to keep more gas from going into the system.

Because basically, more gas physically can't get into the system.

So, basically all producers will voluntarily be cutting back -- or involuntarily will be cutting back at that time.

And you still might have reasonably decent gas prices in the cash market at that time because you physically can't get the gas to move from the wellhead to the injection caverns and storage supply areas.

So, beyond that, it's largely a call on oil prices and that's difficult.

I think we can all see a scenario, where oil prices go higher and oil prices go lower.

And so, our view is simply, we are trying to lock in margins that are expanding rather than contracting.

We are trying to support a drilling program that is really inefficient to be started and stopped.

There are just times to take chips off the table.

We've seen a couple rallies in the past couple of months, where we thought it was prudent to lock in some prices.

Particularly when people value your Company as if gas prices are going to retreat to $6 and stay forever every time you can go out and hedge a Tcfe of gas in the future at prices 3 to $4 above that, you create a lot of stock market value.

And that's what we have consistently done over time -- is what we're doing here as well.

Just one last one.

I know you had some good reserve adds in the first quarter, but you also had some negative reserve revisions based on pricing.

Could you point to where those revisions were, what particular plays?

(multiple speakers) Joe, they are just all across-the-board on these long life properties.

When you reduce prices, your economic limit is reached earlier and your value is a little changed because it is so far in the future.

But your volumes on a small percentage basis are truncated, and it would've been virtually in every area where we have long life production.

You know, you're talking about 88 Bcf of truncation over an 8 Tcf equivalent to reserve base.

It's 1% truncation.

Those truncations occur -- accrue 40 and 50 years in the future.

What is far more important is the 1% positive reserve revision from performance.

I think we've had now four years in a row (multiple speakers) --

This will be the fourth.

This will be the fourth year of positive reserve revisions.

So, I like that part of it.

The pricing situation of course will take care of itself.

Is there any particular area where you had the positive performance that was somewhat surprising?

Steve, do you --

Only in the Barnett continues to look better and better.

I think generally just across-the-board, all of our areas are working pretty well right now.

So, I hope that is helpful.

Brian Singer, Goldman Sachs.

Could you talk about any new data points from Fayetteville/Haley and Woodford/Caney that have made you more optimistic or pessimistic on these emerging plays?

I think our story on those plays stayed mainly the same as it has been.

I will just go kind of from West to East.

Haley, we continue to remain optimistic about our long-term ability to more consistently hit our performance in that area.

We certainly have some very strong wells.

We've also drilled some weak wells.

Today, I think we have four rigs there or six rigs.

What have we got, Steve?

I think we only have two running today.

Okay, well, we generally have averaged though for the year four rigs and do expect to accelerate that through the year as we will get more additional or (multiple speakers) --

We will be at seven by the end of the summer.

We'll be at seven by the end of the summer.

We will have additional 3D seismic by later in the year.

Our hope is that that will help us crack the code out there and also working with Anadarko should help us as well.

I will note that we have had recent success in the shallow formation called the Strawn, which really helps out the economics of the play as well.

Let's see, you asked about Caney/Woodford.

Clearly, Newfield and others are very positive on that play.

We are in I think 75% of the wells that they've drilled in the play to date.

Costs have been the issue.

Certainly, their recent IP rates have been very nice and were very complementary as of that.

Those kind of rates are hard to find in the industry.

The question is, is it economical enough for us to use some of our 87 operated rigs to go to that area from areas that right now we think are performing better economically.

Since costs have been the issue in there and since we drilled -- do drill more horse on a well than anybody else in the country, we're going to give it a go and see if we can drill some wells in there and reduce cost.

We will remain on the sidelines there, participating in all the wells that they drill where we have acreage, and of course cheering them on.

In Fayetteville, we have a schedule that does have us increasing rigs through the year if our results justify it.

I believe Southwestern has kind of laid out a rectangular East to West box that they consider to be an area in which they are willing to declare victory.

In that box right now, we have 270,000 acres of our 1 million acres.

So, certainly, some of our acreage is much higher risk than the acreage that's inside of that box.

There, costs continue to be a challenge.

Reserve recoveries are also I think still an open question.

It's very early in the play to say exactly what we're doing.

We tend to be a little lower than they are on EURs and higher on costs because many of the costs I think that other companies review as non-recurring aren't going to be recurring for sometime into the future.

So, we do have a lot of acreage in the play.

We are exploring to the East, and our results there remain inconclusive.

And to the extent that that changes during the year, we will certainly let you know.

Thank you.

If I could ask one more -- what is driving both the higher oil production and higher capital spending for the year?

Well, the capital spending is being driven by an increase -- a ramped-up rig activity level that has ramped a little faster perhaps than we had previously estimated.

And then costs continue to be a challenge across all areas.

Then I'm sorry your first (multiple speakers) --

Oil production.

Oil production?

I mean, it's up what 5%, something like that.

We're just not bad oil finders as well I guess is what I would say.

Most of that oil is going to come out of areas like New Mexico, West Texas.

We have put together in last year secondary recovery team that certainly in many of the properties that we have acquired out in the Permian in the past were secondary recovery units, were not economical.

Today's prices certainly are.

You'll notice in our guidance though or our forecast, we have treated that basically as a non-recurring event and have projected 2 million barrels a quarter for all quarters into the future.

Ellen Hannan, Bear Stearns.

Just a couple of questions.

Aubrey, on the rigs that Chesapeake owns, how many of those rigs are now being used by companies other than yourselves?

0 (multiple speakers) --

Sorry, sorry, sorry.

You are right.

Of the ones we have built are all working for us.

Of the 13 Martex rigs that we bought, Steve, are 8 or 9?

It was 10, 9.

8 or 9 are still working for other parties pursuant to contracts that were in place when we purchased it.

Those will roll off.

And as they roll off, the Martex rigs will be transferred to working for Chesapeake-operated locations.

I think, Steve, the longest Martex rig was about one year or so?

Yes, it was January I think.

Yes, when we bought it in January, it was a one-year contract.

So, it will continue to be that some small portion of the rigs will operate all the way through January of '07 and maybe it was two rigs.

But, does that answer your question?

It does.

I guess what I'm getting at is Aubrey's comments about getting to a run rate of 75 to $100 million in your service kind of Company subsidiary operating earnings.

If these rigs that you are either constructing or that you've bought are going to go work for you, is that a reasonable assumption going forward?

Well, it was my comment and I think it is quite reasonable.

First of all, it's not just rigs.

It's also compressors and it's our trucking business.

And our trucking business right now, about 87% of the activity is for third parties.

We think that that will continue to be a very high component.

Also, remember that every rig that goes to work for a Chesapeake-operated location typically will have a non-Chesapeake partner in it.

And so, if xyz company participates for 40% on a Chesapeake location, (multiple speakers)

You are charging that cost out, okay.

Then that gets charged out to them at current rig rates and the profit from that third party then is recognized as service segment income rather than as a pool reduction.

To be totally clear, we have two of the Martex rigs under contract for two years, up in January of 2008.

So, --

Oh, it was all the way through two years?

(multiple speakers) Three deal for two-year rigs.

Sorry about that.

So, not only do we have that but obviously we are increasing from 34 Nomac rigs to 57 Nomac rigs.

And so, just if we continued at the same pace, that alone is a doubling of that segment if everything else remained the same.

All right.

Non-related question -- you flipped a little note in your press release about participating in some acreage in the New Albany Shale, which looks new at least to my eyes.

Could you expand on it?

Are you just leasing acreage?

Are you actually drilling any wells or participating with anyone else?

That is a new area for us.

We had highlighted that -- we have highlighted that as one of our new plays, and we're not in a position to say too much about it.

But we have a couple 100,000 acres in that area, have made an acquisition in that area that gives us a couple of wellbores that need to be completed or drilled horizontally.

So, we will be working on that later in this year.

We have other shale plays underway as well, just not in a position to talk about them at this point.

Jeff Robertson, Lehman Brothers.

Aubrey, on your leasing activity, after spending I guess close to 175 million in the first quarter, how do you see that going forward?

Do you expect similar investments as you go through the year?

Jeff, we have budgeted to spend a lot of money on leasehold.

Leasehold is finally reacting in many areas to the underlying reserve value of natural gas in the ground.

And so, we are spending more money.

But, we are spending it in areas, where we think the capture value well exceeds the value.

I mean, you just think about recent acquisitions in the Barnett Shale at $10,000 an acre we have heard about in last morning's announcement from Devon -- is well north of that.

But, those acreage costs on a -- assuming 100-acre unit of which 20 acres is not good for [carsting] and faulting, you're basically at $3 million for 2.5 Bcfe on gross reserves.

You are in there at about $1.60 per Mcfe in acreage, even at 10,000 an acre -- adds only another $0.60 per Mcfe to that equation.

So, generally, when we are buying acreage from $200 an acre to $1,000 an acre in most of our plays, the leasehold portion of our finding costs is generally lower than $0.05 an Mcfe.

It's been one of the great frankly I think -- or well-kept secrets of the industry over the past five years that acreage has been much cheaper than it probably should have been, considering where proved reserve values were and where gas prices were.

And I think that's partially our skill set as landmen here that we probably do a better job than most scooping up acreage.

I think this morning, we have something like 900 landmen in the field buying additional leases.

What we're not very good at is initially capturing in our reserve report the reserve adds from those newly-bought acres that normally takes a couple of quarters, whereas a lot of that acreage does hit our full-cost pool almost immediately if it's in broad areas that we consider of value to it.

A question for you on the Fayetteville, Aubrey, where you all are leasing out to the East, is that a similar -- the way you all think about it is a similar geologic model to the Western part of that play?

Or you all thinking things are any different out there than where you have the acreage on the Eastern half of the play?

Well, we knew it would be different.

It's different depositionally.

It's different from a structural perspective.

And so, the question was can different bases of the Fayetteville Shale and different parts of Arkansas produce gas?

And that's what we are -- in commercial quantities -- and that's what we're trying to determine as we speak.

So, that's why we remain consistent and calling the results to date inconclusive and also expressing some nervousness about the economics of the play, even back in the box.

Because some of these non-recurring -- so-called non-recurring costs can be up to $0.5 million for example to haul off a slick water frac.

That's going to be a recurring cost for quite some time and into the future.

And that $0.5 million can make the difference on whether or not a wealth rate of return is 35% or 15 or 20% for example, which makes a lot of difference in whether or not a well like that would be able to crack our starting lineup of wells that we like to drill.

David Heikkinen, Pickering Energy.

Beer to everybody on that one.

The first thing -- just wanted to understand the Barnett production results.

What's kind of the special thoughts you guys are using?

Is it just the area you are located in or is any of this completing two wells simultaneously, using surfactants and gasless mandrills?

What's all driving the out-performance of your wells versus everybody else just technically speaking?

I'm going to take a whack at it and then turn it over to Steve as well.

I think first of all, it's a combination of good geology and good operations.

We are not a company that has ever expressed any interest in acreage to the west of Tarrant and Johnson Counties.

It's not that we haven't believed that there is -- or to the south for that matter.

It's not that we haven't believed there is not gas out in that area.

We just feel like the economics of it would prove to be much skinnier than other prospects that we have.

Keep in mind what may be a PUD to another company or even a good probable or possible might not be attractive to us because we already have an inventory of 29,000 drill sites and a lineup of 2,500 wells we want to drill this year, all of which have well-established rates of return that we consider to be pretty attractive.

So, a new deal has to break into our starting lineup, which is tough.

The second thing I would remind you is that we've drilled more horizontal wells and have completed more horizontal wells than anybody else in the Company -- in the country rather, since horizontal drilling really began in earnest around 1990.

And so, people sometimes forget that the chalk was mainly a good thing for us and also may forget that we have a huge legacy of experience in that.

Third thing I would say is we're all the only Company involved in the Barnett in Texas and Woodford in Oklahoma and the Fayetteville in Arkansas.

Plus, we have our shale plays underway in Appalachia.

So, we have an informational advantage, where the guys fracing our Fayetteville wells for example are sitting right down the hall from the guys fracing our Barnett wells.

We are all here in the same office.

Technology and information transfer across divisions here happens very easily because of the centralized nature of our Company.

And that's one of the reasons why we seek a centralized engineer and geology and operations staff compared to maybe what some other companies do.

So, these are the general thoughts that I would give you why I think we are better.

Steve might have some more specific thoughts in general about some of the things we may do differently.

Let's -- I have to agree that what's important is being in the right spot.

We are drilling in a good area.

We do bring a lot of experience.

There is no magic formula or bullet.

We get better every month and learning through the various plays, and it is just an ongoing process.

The team has done real at it.

Just thinking about services costs and the escalation on pressure pumping, any thoughts about actually owned service equipment as well beyond just the rig market and where that could actually go, guys?

Funny you should ask.

We are -- a lot of entrepreneurs come to us with ideas about starting various service companies, and some of those guys are not capable in our view; others are very worthy.

Clearly, pressure pumping is an area where we need more capacity in the industry.

I think the big pressure pumpers are certainly working hard to expand capacity.

But, you may find us supportive of some entrepreneurial activities in that area as well.

Our work can create a fair amount of equity value by helping some smaller companies get started.

And then, on the emerging plays on the tight gas side, Deep Bossier, any updates and specifics as far as what makes you think that play works versus not work.

I just wanted to get some thoughts on that.

Well, we haven't drilled a well there yet.

We are in some oils drilled by -- with Gastar as the operator.

I think they just announced a good-looking log on their Wildman 2 well I think it was the other day, which was -- was that in middle Bossier, Mark?

It was upper (multiple speakers) -- upper Bossier.

So, we will start our first well this summer.

Of course, it will be towards the end of the year before we get results on that.

But, our acreage count continues to increase pretty dramatically in that area.

I think we are up to 100 -- I want to say 150,000 acres.

About 150,000 net.

Yes, 150,000 net in that plus in other East Texas plays for 125,000 acres.

So, we got kind of a late start in East Texas, as we were more focused in Oklahoma three or four or five years ago but have caught up pretty rapidly.

I'm pretty impressed with what we've seen in that play.

And again, it's all about acreage capture and we own a lot of acreage.

So, I think some other companies wish they had tied up after they had drilled some initial big discovery wells in that area.

[Lewis Roke], [Barrow Handley].

Congratulations on a great quarter.

I apologize if I missed some of this in your earlier remarks.

But can you comment a little bit on the commitment to the Continental Connector Pipeline?

Yes, I sure can.

We are the largest producer in Oklahoma.

We have about 23% of the gas production share in this state.

And as a consequence of that plus our presence in the Barnett plus our presence in the Fayetteville, anyone wanting to build a Mid-Continent pipe from the Mid-Continent to Southeastern markets is going to probably come see us first.

Keep in mind right now, we are selling about 1.4 Bcf a day.

So, what we have done is tried to work with a number of pipeline companies to get additional pipes built and have been supportive of Continental Connector as well as we are supportive of another pipe that's been proposed.

Our goal is to get back to the days, where differentials in the Mid-Continent are reflective of the true costs of transportation rather than where they are today, where you have had so much gas on gas competition in the Mid-Continent, particularly if you define the Barnett as being part of that.

So, I think the capacity charges on these pipes are just a fraction of what we have been experiencing from basis differentials over the past -- well, ever since the hurricanes came through.

So, our job is to get as much gas capacity out of this area.

We want to be in an area that is long pipe and short gas, and that's the way Mid-Continent was before the Barnett.

The Barnett has changed those dynamics, and we intend to help change them once again back to where we are going to get favorable transportation rates out of this area.

Can you share with us how much capacity you've taken on El Paso's line?

I cannot, nor can I share the rate that we have agreed to pay.

I assure you that we've got a lot of gas left over to support other projects, and the transportation rates are very attractive to us.

And then, now that the news is out on the Chief sale, would you share with us your thoughts on that process and what else you see coming?

Sure.

We offer our hearty congratulations to our friends downtown.

Devon clearly is the leader in that play from both historical perspective and through the amount of production they have and through the acreage they have.

So, it's clear to me that they know what they're doing in the area.

We did look at Chief, and we did bid on Chief.

But, we're not especially close to where they were.

So, my hats are off to them.

I hope that they turn this into a great acquisition.

It does -- if you run the math on it, it will turn out to be fairly expensive.

But, the rate at which the gas comes at you I'm sure makes that an accretive transaction for them.

I think in a few minutes, they will want to dominate the airwaves to talk about that.

David Khani, FBR.

Could you give me an update on Appalachia, sort of where production is, the well counts and what are you seeing positive or negative on the area?

I don't think we're seeing anything negative right now.

I'm going to hit a couple of just operational points and then let Marc talk to you about gas prices in the area, which have been just extraordinary for us this quarter.

But, let's see, we are running now 8 rigs and headed to kind of 10 to 12 later this year, and most of this is shallow activity.

We I believe have three big seismic chutes that are planned for the next 12 months in this area, targeting deeper exploration targets.

We're also continuing to develop our ideas on various shale plays in Appalachia.

So, production is still running I think around 120, 125 million a day and wouldn't expect to see a ramp on that really until the end of the year into 2007.

I'm pleased with the way we are building our staff.

Oil and gas employees in Appalachia have reacted quite favorably to our enhanced-pay scales in the area and getting to pick and choose some prone -- the whole base of employees in that area and I think build a team that will be second to none when we are all done there.

I will turn it over to Marc to talk to you about gas price values in that area.

Yes, David, the I guess thought that we had when we entered in the area and closed on our CNR transaction were that costs were a little bit higher in that area to operate.

But, we viewed margins as being substantially higher and more valuable molecules in that area, and it certainly was confirmed this quarter.

We averaged selling gas at the wellhead at $11.50 per Mcf during the quarter in the Appalachia area.

That comes from positive basis differential to Henry Hub and it comes from the BTU content.

Contrast that with all of the other gas that the Company sold at a wellhead price of $7 during the quarter for this Q1, you've got margins that are $4.50 higher.

So, while CNR's production did contribute on the full quarter basis to a few cents of our production cost increase, as this was the first quarter we had the production in for the full quarter.

Again, back to the theme of margins, this Appalachian Basin production has margins that are -- that exceed anything else in the country right now.

Okay great, great.

Aubrey, when you were talking about natural gas and the risk I guess at the end of injection season that there's no place to put the gas.

Why don't you either -- a, have more hedges -- have basis hedges in place?

Because it looks like you are only about 45% hedged.

Second, maybe how are your basis hedged laid out?

Is it back-end weighted so that -- because you only give us the annual number here?

I will say that I don't think anybody else three years ago went out and hedged Tcfe to gas.

Right now, on those basis hedges, it looks like we're probably going to make $1 billion.

So, I would like to put your question in the context of (multiple speakers) --

You definitely get credit, no doubt.

-- for that.

Beyond that, once basis differentials started to move up, we stopped hedging them because we felt like they represented basically equal-weighted risk.

Clearly, we were wrong, as the hurricanes came through and changed everything.

Today, to go out and hedged basis at minus $1.70 in the Mid-Continent makes no sense.

Instead, what makes more sense is to go support through taking firm transport on some of these new pipeline projects that will reduce basis differentials back to say $0.50 or $0.60 in the area.

So, that's I guess the way we would today talk about hedging basis differentials.

It wouldn't be to do it in the financial market.

It would be to do it in a physical market.

Marc, do you want any other part of that?

No, (indiscernible).

Last question.

We haven't seen this in a while and being that you guys are full cost, could you give us a sense of -- a, what is your full cost pool and how does it -- how much cushion do you have at today's pricing?

And then, where do prices have to go before you would start to see either full cost write-down?

B, does your hedges in place protect you from that?

Well, there's three elements to that question that I heard, Dave.

In reverse order, yes, the full cost test is helped by any hedges that you have in place.

So, to the extent prices were to dip substantially from this level, the volume that we have hedged at the levels could be used to adjust or mitigate any difference.

Right now, we have over $2 billion of cushion in our full cost pool.

It would take prices that would be down around $4 at the wellhead, of course depending on what well is doing, before the Company -- and this is without hedges -- before the Company would be looking at a full cost ceiling test.

Wonderful, great.

Thank you, guys, good quarter.

Dave, you might see some companies think about moving to the so-called more conservative method of successful efforts to avoid a write-down.

It's hardly a more conservative move in our view, but you might keep your eyes open for that.

Dan Morrison, Aperion Group.

A couple of quickies, back to your thoughts on the gas market.

The extreme contango that we see in the strip right now, if we get in the situation where you have gas on gas competition, do you think that that contango can hold?

Yes, I think the contango makes a lot of sense.

Because you're going to get a reset on November 1st.

So whether or not you have 3.4 Tcfe in storage or 3.7 Tcfe in storage, it really doesn't matter for 2007 and certainly for 2008 gas prices if you get favorable winter weather for producers and if you were to get favorable summer weather in '07 for producers as well.

So, that's what we know right now.

Storage is not nearly big enough to give us a multiyear gas price hangover.

So, from that perspective, I view a contangoed gas market as absolutely rational.

We just --

Last quick question -- you mentioned in your comments about -- in your prepared comments about other shale plays.

I know you might be reluctant to talk in too much detail.

But, you did mention another shale play in Texas beyond the Barnett.

Could you comment on where that is?

Yes, in Texas.

And we're working on it as we speak and probably more to come.

Ben Dell, Sanford Bernstein.

I guess I had a couple of macro questions, just following up from some of your comments.

You mentioned you were surprised by the onshore gas supplies.

Is that with respect to the sort of growth we've seen in response to the higher commodity price?

My second question on the macro is you just recently -- just obviously mentioned about the reset scenario.

If everyone has forced involuntary or voluntary shut-ins at the wellhead, doesn't that mean if everyone keeps on drilling, we just put that supply on to the market at the start of '07?

Is that a concern of yours on your hedging when you're looking at '07 and '08?

Certainly, it is.

And you know, what we are paid to do around here is to deliver the highest risk-adjusted returns to investors that we can.

I think we focus around here a lot more on the risk side of the equation than other companies, who are constantly seeking out where we have risk and trying to mitigate it.

Other companies prefer to just run totally unhedged on both revenue and service, and that's the way they run their businesses.

We don't think about the world in the same way.

So, when we look and see that we can hedge in 2007 gas it turns out at $10 or 2008 gas at $9.50, we look at that and we look at how we are valued in the marketplace.

We look at the economics of our drilling, which we run at $7 gas.

We look at the equity.

We look at our acquisition matrix, which runs generally in that 6.50 to 7.50 run, and we say -- you know what, we do pretty well in a 10 to $11 gas price world.

So, there comes a time when we think it borders on management malpractice not to lock in these successively high returns that we can generate by locking in gas prices.

Is that a statement about where gas prices are headed?

Sure.

In some form or fashion, it is.

But, what it is a bigger statement on is how our stock is valued and the returns that we can get from employing capital in the sector.

With regard to the reset question, you know, are we concerned about all that gas coming on in '07 if it can't come on in '06?

I mean, sure.

That's absolutely part of our concern.

We can't count on another hurricane to further reduce Gulf production.

So, the question is -- all we're doing is continuing to steepen the decline curve.

If we were to get an extended string of $5 or $6 gas, then the rig count would go down and things would balance back out.

As you know, as closely as you study this industry and the macro side of it, it's very difficult to discern where production trends are headed.

But, I think it's completely rational, given the consistent 20% year-over-year rig activity increases that we've seen for the last three years, would be enough to overcome declining per-well prospectivity.

So, we -- our equation is that gas prices or gas production might be up as much as 1 to 1.5 Bcf a day year over year, which would cancel out basically most of what we have lost in the Gulf.

So, going forward, will that continue?

It may.

But, the more important part of that equation is at what gas price will the rig count start to go down and people start to get tired of selling $6 or $7 NYMEX gas, which translates back into $5 at the wellhead.

In our view, most of the industry is losing money today on new projects based on actual wellhead prices today.

And, there will be a number of checkbook-type drillers, which will get tired of that we think going forward.

Thank you and just on the sort of outlook in terms of your strategy going forward, clearly, given your hedges, you're going to build equity and you'll have the potential take on additional debt.

I'm assuming if this sort of plays out as you see, you're going to -- or you would hope to see additional acquisition opportunity pop up over the next 9 to 12 months at least that you're going to try to take advantage of.

If that is your question, yes, we will continue to pursue our business strategy, which remains focused on aggressive drilling and active acquisition prospecting and anything that's in our area that we think is accretive to NAV and to our financial measures going forward, then we will pursue those opportunities.

Generally, we're not very successful at that, given the aggression of some of our competitors.

But we are pretty dogged and we will just stay after it.

We never have to make another acquisition because we've got plenty to do around here, executing what -- this year will be I think another record-breaking year in terms of drilling activity for the Company.

Gil Yang, Citigroup.

Just a quick question, from your answers to one of the previous questions, it sounds like you think rig costs and the service costs are higher -- or pricing at a higher commodity price than where we're currently at.

Could you just confirm your thoughts on exactly what kind of commodity price you think those prices are discounting?

To me, they are discounting where prices were last fall and maybe over the winter a little bit.

But, to me, they are discounting kind of $8 to $10 gas prices.

And today, you've got $6 to $7, which, again, I think translates back to $5.

Nobody -- or very few companies will admit this but most plays in America, you can't be spending 20,000 to $25,000 a day on rigs and selling gas for $5 and make any money.

I mean, just look at the economics of Devon's announcement this morning.

I think they have future development costs, it's 3.50 or something.

With future development costs, it is probably 4.50 and that's before LOE and all that.

So clearly, companies are acting as if gas prices will go to levels that are supported in the futures markets in 2007, 2008.

Present gas prices simply do not support 1,600 rigs in our view, and so something will give.

Either gas prices will go to where they -- physically where they are predicted to go in the futures curve or the futures curve is wrong -- gas prices will come down and the rig count will come down.

What -- you mentioned earlier, you thought that production was growing.

Could you comment on what rate you think it is growing at?

What do you look at to see that, and should prices stay where they are?

What would the growth rate go to?

Really difficult to answer.

I did say a few minutes ago, I thought perhaps as much as 1 to 1.5 Bcf per day.

But, that is totally a wild guess and not supported by a whole lot of science, just some back of the envelope work.

If it stayed at -- gas prices stayed here, would it be flattish?

If gas prices stay where they are, in my view, the rig counts comes down and gas production within 6 to 12 months thereafter will start to trend back down as well.

Keep in mind you are by drilling all these Barnett wells and all these [Pion swells] and all these Pinedale wells, you are doing nothing but steepening the decline curve from where it was before.

So, any kind of corrections at all will be pretty dramatic I think in terms of gas prices.

(Operator Instructions). [James Howard], [James B. Howard Investments].

Congratulations on a great quarter and also on your ability to forecast, reflected in the number of acquisitions you've made.

I have a question on the linkage between oil prices and gas prices.

Do you think this linkage gets tighter as oil prices rise or looser and what is the rationale for this linkage?

Well, the rationale is simply BTUs or BTUs.

And around the world, people need to burn BTUs and whether or not in Japan they burn oil to generate electricity or whether or not they liquefied natural gas to generate electricity, it's all BTUs.

And the BTU equivalency of course is 6 to 1 so that's why that relationship is generally referred to.

In the US, right now, obviously that relationship is 10 or 11 to 1, reflecting the relative overabundance of natural gas compared to the relative scarcity of oil.

So, going forward, it depends a lot on weather patterns in North America.

But, in our view, gas prices around the world will tend to move towards probably 7, 7.5 to as low as 6, 6.5 to 1 with weather being the primary determining factor as to whether or not it's wider than that.

So, that's how we see it.

We see the world as increasingly short of light sweet crude.

So a big support for natural gas prices going forward around the world will be the strength of light sweet crude prices.

Listen, I appreciate it.

In deference to Devon and some other companies that have conference calls right now, we will sign off and appreciate everybody's questions.

And if you have further questions, you can get back with Jeff or Marc.

Thanks very much.

That does conclude today's conference.

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