Chesapeake Energy Corp (CHK) 2004 Q2 法說會逐字稿

Good day everyone and welcome to this Chesapeake Energy Second Quarter 2004 Earnings Release Conference Call.

Today's call is being recorded.

At this time for opening comments and introductions, I'd like to turn the call over to Mr. Tom Price, Jr., SVP, Investor and Government Relations.

Please go ahead, sir.

Thomas S. Price, Jr.: Yes, good morning and thank you for joining Chesapeake's 2004 Second Quarter Earnings Release Conference Call.

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

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

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

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

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

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

These are all non-GAAP financial measures.

Reconciliations to the comparable GAAP measures can be found on pages 13 through 15 of our press release issued yesterday.

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

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

Aubrey?

Thanks, Tom, and good morning to all of you.

As I'm sure you have seen, we have been busy lately and so we have lots of ground to cover on today's call.

I will begin with a review of the quarter, then talk about our new acquisitions, then talk to you about a new slide show that is up on our website that details the company's exposure to six very significant gas resource plays.

Chesapeake has once again delivered excellent quarterly results for our investors.

Our net income available to common shareholders was $86m or $0.31 per fully diluted share.

Our operating cash flow was $308m, and our EBITDA was $324m.

The net income and EBITDA numbers include the negative impact of an after tax non-cash $7m unrealized hedging loss.

On what some refer to as recurring numbers, our net income to common shareholders was $93m or $0.33 per fully diluted share and our EBITDA was $331m.

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

Alone, gas production reached the record level of 86.5 bcfe in the quarter.

This is our 12th consecutive quarter of record production and this year will be our 15th consecutive year of record production.

Second quarter production was up 29% from the year ago quarter, and up 10% sequentially from the first quarter of '04.

Of the 29% increase in this year's quarterly production versus last year's quarterly production, 40% was organic and 60% came from acquisitions.

Our rate of organic growth during the past 12 months has been 11%, and we are now projecting that our organic growth during the remainder of the year will remain at or above this level.

While we will continue to officially project that our organic growth rate year after year is only 5%, it should be increasingly clear to you that we can do much better than this.

And I'd also mention that, during the past 12 quarters, our production has more than doubled and our average annualized growth rate during this three-year time frame has been 30%.

In the second quarter, we produced an average of 951 million cubic feet of gas equivalent per day, of which 88% was natural gas.

Chesapeake is now the fifth largest independent producer of natural gas in the U.S., trailing only Devon, Anadarko, [Permakey] and Burlington.

And I might add, we are the youngest of these companies by at least 15 years.

For the third quarter, we are forecasting a 5% sequential increase in production to 1.0 bcfe per day.

For the fourth quarter, we are projecting another 5% sequential increase to 1.05 bcfe per day.

And for 2005, we are projecting a 12% year-over-year production increase to almost 1.1 bcfe per day.

I can't give you these numbers without reminding you that we produce in four days today what it took us a whole year to produce 11 years ago when we went public.

During the second quarter, we replaced our 86.5 bcfe of production with 429 bcfe of new reserves, which is a 500% reserve replacement rate.

Of this amount, one-third came through the drill bit and two-thirds came through acquisitions.

Our drilling and acquisition costs were a very attractive $1.52 (fe), while our G&A costs were only $0.09 (fe).

Our listing costs were only $0.57 (fe) and our production taxes were only $0.26 (fe).

We believe our production results and our profit margins are proof that, at Chesapeake, we don't have to choose between the growth or returns business models being discussed in our industry today.

We can clearly deliver value from both.

On the operations front, you can see that all is going very well.

Tom Ward and his operations land and geo-scientific teams continue to find more and more to do with our ever expanding asset base, and we continue to add to the strength of our technical teams.

We have more than doubled the size of these teams in the past three years and now have more than 75 geoscientists, 100 engineers and 100 land men generating new prospects every day.

These professionals are conducting an industry leading drilling effort and 59 operated rigs and 53 non-operated rigs.

Chesapeake is now involved in 10% of our nation's drilling and 50% of the drilling in the Mid-Continent.

We believe this is an unprecedented position to be in, and has created for us a unique powerful informational advantage at a time when the profit margins from drilling are the best Tom and I have ever seen in our 23 years in this industry.

Chesapeake is a value-creating drilling machine, one that is backed by what we understand are the largest on-shore inventories of leasehold and 3D seismic in the business, three million acres and eight million acres, respectively.

I will return to these inventories in a few minutes, but want to first review the three new acquisitions that we announced yesterday.

We are very excited about these transactions as they are characterized by the same attributes of every successful Chesapeake acquisition, high quality natural gas assets that have significant growth potential, acquired at a reasonable cost.

In these three new deals, we have agreed to acquire 310 bcfe approved reserves, 453 bcfe of probable and possible reserves, 50,000 acres of new leasehold, and 60 million cubic feet of gas equivalent production per day from three private companies: Bravo, Legend and Tilford Pinson.

The acquired assets have a reserve to production index of 14 years, are 92% gas, are 97% company operated, are 35% proved developed and have current lease operating expenses of only $0.29 (fe).

These very low operating expenses create unusually high economic values (fe) and add to the attractiveness of Chesapeake's all-in acquisition costs of $1.68 (fe).

Bravo's assets consist of 20,000 acres located in two Granite Wash producing fields in the Anadarko Basin.

The Granite Wash today has produced more than 1.2 tcfe from 10 major fields in the Anadarko, and it's currently the subject of intense industry interest.

Chesapeake manages more than 200,000 net acres of potentially perspective leaseholds in the Granite Wash play.

In our part of this play, well cost average 1.2m to 1.5m, estimated per oil reserve recoveries average 1.5 to 2.0 bcfe, and drainage areas average approximately 40 acres.

Our second acquisition is of Legend's assets in Zapata County, South Texas.

The majority of these assets are located just a few miles from the Zapata County assets we acquired in October '03 from Laredo Energy.

At the time of our acquisition, the Laredo assets were producing 30 million per day net to Chesapeake.

After better than expected drilling results, the Laredo assets are currently producing 50 million per day, a 67% increase in just 9 months.

Zapata is Texas' most prolific gas producing county.

Chesapeake will be the fourth largest gas producer in this county after we close the Legend deal.

Tilford Pinson's assets are located mainly in Pittsburg County in the Arkoma Basin of Eastern Oklahoma.

In this county, where Chesapeake is already the largest gas producer, major new zones of interest are the Hartshorne, [Goldbed] Methane Play and the Caney Shale play.

The Caney Shale is considered by some industry observers to have similar characteristics to the Barnett Shale of North Texas.

Chesapeake believes that it now has at least 75,000 acres of potentially perspective Caney Shale leasehold.

We believe we can increase the newly acquired properties' production from the current rate of 60 million per day to at least 90 million per day in 2005, and least 120 million per day in 2006.

The company has identified over 600 drilling locations on the 50,000 net leasehold acres being acquired.

Pro forma for these new acquisitions, just estimated proof reserves, are 4.1 tcfe.

I would like to finish up by returning to the three million acre leasehold inventory I mentioned a few minutes ago.

This is an inventory that has taken us six years to build at high grade.

On this inventory, we have identified more than 5,400 drill sites that, by our estimate, will contain more than four trillion cubic feet of natural gas reserves.

We have quantified this upside for you in two new slides that I encourage you to look at on our website.

Slide 20, which is entitled "Chesapeake's significant exposure to gas resource plays," and Slide 37, which is entitled "Stock price versus NAV."

On the second slide, you will notice that we have valued this four tcfe of probable and possible reserves at only $0.25 per mcfe.

However, it is our view today that we would pay at least $0.50 per mcfe per upside of this quality in any significant acquisition.

That's $2b of value, or $7.00 per share that is not recognized in our stock price today simply because investors could not have known that we owned so much upside before today.

Over the past few years, we have been very quiet about our operational success in this growing upside because we wanted to build our leasehold positions in these areas without attracting additional industry competition.

We are now in a commanding position in these areas and we can begin educating investors about the incredible value of this unrecognized upside.

I can assure you that this will be a very enjoyable project for us in the months ahead.

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

Thanks, Aubrey.

While we are coming to you from different locations today as a result of our equity and debt road show for the transactions we announced yesterday, we hope the message is as clear and consistent as ever.

All of us are very excited about the transactions in front of us.

Before I comment on those transactions, which Aubrey has mostly covered, let's look at some of the details behind the tremendous second quarter we have just reported on.

In the quarter, we exceeded earnings guidance and street consensus by several cents per share on a fully diluted basis.

This was primarily the result of higher production levels, well above our expectations and driven not by acquisitions, but by stellar organic growth.

We did it by successful drilling.

In the meantime, we were able to continue to hold costs at very attractive levels, the lifting costs, G&A costs, and the other cost items on our income statement were all at or below guidance.

Revenue was excellent but muted by our traditionally successful hedging programs.

We noted in the release that we gave up about $0.64 per mcf equivalent to hedging revenue reductions during the quarter.

Our reserve replacement and growth trends continue to exceed our stated minimum objective of replacing 150% of our production through the drill bit, despite our much larger size, and we were able to do this at attractive costs given the current cost and revenue environment.

Operating costs and drilling costs continue to be a challenge as drilling and operating cost pressure exists as a result of the sector's higher demand for services.

Since our last call, we believe costs have edged up, moderating in most categories from the significant increases we saw in the early part of quarter two, except for steel prices, which have had a very high surge in price cost to us.

One note is our insurance rates were readjusted downward this quarter for the next year, and we're happy to report price decrease in this one area.

To give you a sample of service costs, a 2000 horsepower rig in our areas traditionally are being bid out at between $8,900 and $9,200.

That's up about 6% this quarter from last quarter.

Shallow footage rates have edged up about 7% as well.

Cementing costs, up a more moderate 3%.

Logging costs, after actually remaining fairly flat for a period of time, are up about 10%.

And as I mentioned, steel prices, which account for anywhere from 5% to 8% of our well costs, are up pretty significantly.

A few housekeeping chores for the -- [inaudible]. $83m of that was non-cash tax basis step-ups, primarily related to our Greystone acquisitions, $453m was spent on proved acquisitions, with $73m on unproved categories.

Capitalized costs for the quarter, interest was $7.4m for the quarter.

For the first half, $12.7m.

Internal costs, $12.4m; $23.3m for the quarter.

My final comments before we turn it over to questions and answers are related to our acquisition efforts.

In the next few days, we hope to communicate the recent successes we have had related to the Concho, Greystone and Laredo acquisitions.

We see the same type of upside in the Bravo and Legend assets, and we'll be anxious to communicate that to investors.

Initial acquisition metrics, generally a shorthand investor metric that people look at can not possibly do these transactions justice.

Future development costs and the surety of success affect this metric.

Lifting costs affect this metric as well.

In both cases, we have concluded that the all-in costs associated with buying, developing and producing these properties is not just attractive, but downright cheap given our current and expected price environment.

And with that, we'll turn it over to the moderator.

Thank you.

The question and answer session will be conducted electronically.

If you would like to ask a question today, 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.

We ask that you please limit yourself to one question and one follow-up to allow everyone the opportunity to ask a question.

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

We'll pause for just a moment to assemble our roster.

And we'll take our first question from Joe Hill at [Empyrean] Capital Management.

Hi, guys.

What is the current level of capex pro forma your deals to keep production flat and, tied into that, what's your base decline rate pro forma the deals?

Joe, this is Aubrey.

Three hundred and 54 bcfe I believe is our mid-point production range for the year.

So, if you want to multiply that by $1.60, which is our projected [inaudible] costs for the year, you're going to see that basically about half of our cash flow under -- just right at 600m is used to maintain capex.

So, that frees up the other half of our capex to do something with, either to drill or to acquire or to pay down debt.

We've chosen to use about two-thirds of that excess cash flow to drill with.

On the decline rate, corporate decline rate pro forma the deals, is still just right under 20% on a first year basis.

And then, as you get out in the second and third years, into the fourth year, you're into a low teens rate of return on most of our -- [inaudible] decline rates of somewhere between 8% and 10% for most of our properties.

OK.

Just a follow-up.

I noticed you took the hedges off for some --.

We took some hedges off.

Not much in the front, but took all of our back hedges off in '06 and '07, and then we also lightened up a little bit in '05 as well.

Why -- what was the thought process behind doing that?

Our thought process is simply that the decline in gas prices over the last six weeks or so has given us the opportunity to take some hedges off in out years where we no longer have concerns about prices below $5 like we did when we put those hedges on.

We will look for further strength in gas prices in a form of spikes to hedge in the future.

And that's been our strategy in the past and the hedges that we have on today reflect hedging during past spikes.

Those spikes have obviously been lower than basically prices are today and we anticipate gas price spikes throughout the next 12 months.

And when we get those, we'll take full advantage of them as we have in the past.

And just out of curiosity, why are you not longer concerned about $5 gas in the out years?

Because we are noticing that the same trends that have brought us $6 gas over the last four years, which is a growing economy that drives energy demand by 2+% per year and a supply base that continues to at best be flat, to at worse, be down 2% to 3%.

Those are structural trends that we see no signs of anything changing from the economic growth side, nor do we see anything fundamentally changing on the supply side, although we could be right now in an environment where production is flat for the next couple of quarters.

But, when you get into the second half of the year, you're going to have red counts that are no more than 10% higher than last year.

We think that will lead to further supply or resumption of the supply declines that started in 2000.

And so, Joe, when you look at gas prices over the last four years, they're up $1 per year every year because of those two structural trends grinding against each other.

And over the next few years, we don't see any relief in sight.

Good enough.

Thanks, Aubrey.

Thanks, Joe.

And we'll move next to Dan Morrison at [Empyrean] Group.

Hi, guys.

Quick question on the acreage and seismic spending at $100m.

Does that reflect an increase above prior kind of budget levels, or is that kind of lumped in to the quarter?

And what's the outlook for that kind of spending?

I'll let Mark talk about the specifics of it, but it is more than normal.

We had several significant leasehold acquisitions during the quarter.

We are out there every day buying new leases.

We have close to 250 land men in the field every day buying leases.

And it just so happened last quarter, we had a couple big leasehold deals and might have had a big seismic deal.

But, if Mark has any additional information on that, I will let him jump in.

Dan, it's simply what Aubrey has said.

There were two particular transactions, both of very large size, that were added to our normal ongoing activities.

I do not see a large increase in the budget for routine activities, although from time to time, if we can make a $15m to $25m, or even $30m as we did this quarter individual leasehold acquisition, you know, you can see that.

It's hard to budget for those because you don't know when the plays are necessarily going to go and you don't know what's going to be available.

It's a little bit like budgeting for acquisitions, which we do not do.

So, more of a lumpy, unusual event for the quarter rather than signaling a big increase in the budgeted amount going forward.

OK.

Thanks.

One quick follow-up on the 30,000 acres in the Barnett.

Do you still have an ongoing program there for acquisition and can you characterize what you've got so far a little bit as far as -- particularly with respect to drilling commitments and kind of net your costs?

OK.

Sure.

We do remain active.

I think last week I saw that we picked up another 2,500 acres that we will own ourselves.

All of this is non-core acreage.

We are a non-operator with a company called [Hallwood] and the acreage is in Johnson County, Texas, and just south of the OG acreage.

In fact, I think our acreage actually abuts their acreage there at the county line.

We acquired our initial toehold here actually three years ago through a transaction with -- well, we bought a company called Canaan Energy, and really looked at the Barnett position as an afterthought.

And it's only lately that we've begun to understand the potential of it.

And that was particularly driven home in the last two or three weeks when [Hallwood] brought in a well called the Lakeview for seven million cubic feet of gas per day, a horizontal well that we're pretty excited about and it is on production.

So that acreage, depending on how you drill it on 300 acres.

It's 100 wells.

If it drills down to 150, 160 acres, it could be a couple of hundred horizontal wells.

And while we have watched the area with interest, we realize that we've been late to the play, but do have a nice little toehold here that probably has caught most people by surprise because this is the first time we've really talked about our presence in the play as we've tried to block out the remaining acreage in this block that we have with [Hallwood].

And we will continue to expand our presence I the nearby area as opportunities present themselves.

The rate again -- well, I'm sorry.

It IP'd at seven million a day.

Tom, it's actually online.

Do you have any current information on production?

I was laying it straight.

I saw -- it was stable at between six and seven million a day.

And you're 50/50 with [Hallwood] on these?

No, sorry.

I should have mentioned that.

They are 56%.

We are 44%.

Great.

Thanks.

OK.

Thank you.

And we'll take our next question from Ellen Hannan at Bear, Stearns.

Actually, all my questions have been answered, but thank you.

Thank you.

Next, we'll move to David [Percell] with Pickering Energy Partners.

Hi.

Question on '05 production guidance.

How dependent is reaching your targets?

How dependent is the execution of your growth on the acquisitions?

In other words, you're talking about 60 million a day going to 90.

How important is that in your '05 growth guidance?

And then I've got a follow-up.

OK.

Those numbers essentially do not include those numbers.

We view that that's a core production that we continue to -- that we can continue to deliver.

And so we're pretty comfortable with the almost 1.1 bcf a day average in 2005.

OK, so you think your guidance is conservative then?

It is.

And I think we've talked about in the past that we really only project 5% increases, which is basically a developmental number.

And then if we have success through the exploratory drill bit, it can be -- easily twice that last year, and actually in 2003, we delivered a 20% organic growth.

This year won't be as high, but it looks like we'll be able to stay in the low double digits for sure.

So, as usual, we try to give you a base number that, in a company our size, we think is pretty strong at 5%, and then do our best to do better than that.

You talked about these acquisitions being downright cheap at expected future prices.

What expected future price do you guys look at that makes these acquisitions downright cheap?

Well, I think you can just look at the strip of prices that would be hedgeable if we chose to do so today.

At 2005, well over $6 and then trailing down into the lower fives.

If you add the approximate $1.70 for fully developing all of the properties to a lifting cost that's under $0.30, the total cash cost of fully developing and producing that asset is just about $2.

You compare the $6 next year to the $2, and you have a cash margin of over $4.

One of the slides that we have up that's part of our presentation actually takes you through the historical acquisition prices as compared to the gas prices at the time and the resulting margins.

As Aubrey pointed out and I will repeat here, the margins have never been better for the acquisitions, fully developed and with operating costs thrown in.

We are seeing the highest margins at this time that we've ever seen in the business.

OK.

Any follow up to that?

OK.

And next we'll move to John [Zeiringer] with Loomis Sales.

Yes.

I know you're pretty excited about the acquisitions you have on the plate right now, and I assume that maybe one of them has already closed, or two?

Tilford Pinson has been closed, the smallest of the three.

Tilford Pinson.

OK.

The question I had was, could you give us a little update on the status of the Greystone properties that you just recently bought?

They're a little out of your core area.

I'm curious as to whether you've encountered anything that's new, interesting, exciting or discouraging about what you've got.

Sure.

Nothing discouraging to date.

We have had these properties now, I guess, what, six weeks.

We inherited 45 million a day of production.

I checked earlier this week.

We're at 50 million a day there.

We inherited a four-rig drilling program.

We immediately took it down to two rigs as really is our custom with a lot of our acquisitions to make sure that all the integration activities that occur go smoothly.

We're picking back up a third rig there.

We have uncovered to date several surprises, I think was one of the words you used, and they've all been pleasant surprises.

One is that the plumbing in the fields could use quite a bit of help.

And that will increase gas takeaway capacity.

Also, we have discovered that there'll be many opportunities to increase the water handling facilities in the field, which will enable us to go after another surprise, which is a few zones that we've popped in our recent wells that have been avoided in the past, even though they will produce a million or two million cubic feet of gas per day.

They also brewed some water, which was deemed too expensive, given the alternatives of some water-free zones that were available to produce in the field.

So, we think we've got a number of new zones in the field that can be produced that haven't been to date, and that could lead to large, significant increases in reserves.

We still think this is a field with over a trillion cubic feet of gas left in place, and we've only broken 200 bcfe of it.

So, I think you all heard us on our conference call last time discussing this, that this could be our best acquisition ever.

And to date, we have not seen anything to date that would discourage us from making that statement again.

Is there any chance that this is going to form the core or the center of a new core area for you?

Well, all the areas that we are involved in outside of the Mid-Continent are areas that we like, areas that we think have some characteristics that we can expand or transfer some of our competitive advantages from the Mid-Continent to those areas.

So, whether it be the Permian or South Texas or the Gulf Coast or the Ark-La-Tex region, we're always going to be open for additional opportunities, whether they be through acquisitions or whether they be through home-grown prospecting, which we are actively doing in all those areas right how anyway.

OK, thank you.

Thank you, sir.

And as a reminder to our audience, if you would like to ask a question today, please press star, one.

We'll move next to [Mark Meyer] with Simmons & Co.

Good morning.

Looks like relative to May capex guidance, you're up about $100m to $110m.

Could you break out that increase in terms of spending on the new properties, just increased base activity and how much might be related to cost inflation?

Sure.

I'll take a first stab at that.

We are continuing to see inflation and, as was pointed out, I would think quarter-over-quarter we're probably looking at 5% to maybe as much at 6% or 7% cost inflation.

So, if we were to continue to see that in the fourth quarter and into 2005 on a base program that originally started out to be about $800m, about half of the increase would be just attributable to costs related to inflation.

Breaking out the rest of the increase, Mark, you would be looking at about half being added from the new acquisitions that we're talking about, and half of the balance being added from just increased activity on our existing assets.

We're running about 59 operated rigs today.

That's slated to increase into the low 60s with the acquisition closings and other activity we've got.

Six months ago, the average number of rigs running we think would've been in the low 40s.

So, a combination of inflation, acquisition related developmental activity, and just increases on our core properties.

Very good.

Thanks, Mark.

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

Yes, Aubrey, I had a question on -- I think you had about 2,500 locations not too long ago.

And I think today maybe you said something like 5,400 potential locations.

Can you help me -- if my numbers are right, can you help me with the arithmetic on getting from one to the other?

Your numbers are right and, basically, it reflects a couple of things.

One, it's only been -- and by the way, Steve, that number first came out really probably two or three years ago and we just never took the time to update it.

We've spent the last 30 days really doing a better job of cataloging what we believe our gas resource plays and beginning conversations with people about the potential of those.

Clearly, you can't conduct the nation's most active drilling program if you don't have the nation's leading inventory of projects as well.

We think we've built that over the past six years.

We've not been as chatty as some companies have been about the upside in their leasehold bases, but we think we can catch up here in the next year or so.

The main driver of the change has been the discovery over the past six months or so that the proper drilling pattern throughout Sahara is going to be 40 acres rather than 80 acres or even 160 acres before.

If you get a chance today, please go to our website and look at the slide show.

Slide 20 will catalog those opportunities for you and you'll notice that Sahara is now 2,500 locations when we might have only thought of having around 1,000 or so there before.

The Hartshorne Caney locations, which are 2,000, would all be new.

And the Granite Cherokee Wash plays of 500 locations would all be new.

And the [Sliger] locations of 200 and the Barnett Shale locations of 100 are all brand new as well.

So, these 5,400 locations are actually in addition to what we would consider to be our probable, kind of our traditional probable and possible locations, which would be a couple of thousand of those.

So really, on an all-in basis, we have over 7,000 locations, basically at 10-year inventory of drilling at today's rates, which are obviously pretty aggressive as we stand here today.

The second question, Aubrey.

What do you think -- some of the recent acquisitions have come in with, like today's I think is 35% of PDPs, with a fairly high percentage of undeveloped locations.

If you take a look at the year in total, and you're talking about 4.1 potential Ps pro forma mid-year, what percentage would you say now of your total inventory base might be viewed as undeveloped?

We started the year at 26% PUD and pro forma for these acquisition were at 32% PUD.

We'll be similar between those two numbers, would be my guess at year end.

OK.

Thanks very much.

Thank you, Steve.

We'll take our next question from Van Levy.

Good morning.

Hey, [Vince].

Just kind of a big picture question, Aubrey.

Your -- this latest acquisition, 65% PUD, is that a -- do you think that's a trend that's kind of developing, that more reserves coming to market will have a large PUD component?

And if that's the case, how do you kind of balance this with a little, you know, lowering your hedge position?

Because it would seem to me, if the market's moving where the best economics are on the PUD side, it seems like you'd certainly want to lock in higher prices for sure in the lack of economics.

It depends, Van, on where the source of the acquisitions.

It's certainly a good question.

If you look at the acquisition opportunities that are out there today for companies our size, the two that are floating around out there today would obviously be Anadarko's assets, and Exxon Mobile also has a large package available in the Permian Basin.

We haven't seen the details of either of those packages, but they would have a very high percentage of proved developed producing.

The last six acquisitions that we've made have all been acquisitions either of or from private companies, five of which have been sponsored by what I would call private equity players.

And those are always going to have a higher percentage of PUD because they generally, if they've been successful, they have found something.

They've either bought a field that's been underdeveloped or, in the case of Bravo, they have figured out the -- they've broken the code on the new formation, like the Granite Wash.

And they go out and spend a limited amount of money to prove the concept and then toss it out to the industry and consolidators like us, and a handful of other companies tend to be the guys that gobble these things up.

And we apply our capital and technology to then extend the play to its limits.

So, we want to continue to do what we have done over the past two, three years, which is continue to make acquisitions that are balance.

Some are going to have a higher PUD component.

Of course, those bring with them greater growth opportunities and lower operating costs and we think higher returns at the end of the day.

There'll be others that really provide a nice, stable base of production from which we think we can continue to increase the company's production and keep its decline curve at a level where it takes half or less of our capex -- sorry, our cash flow, to maintain production.

And how long do you think it'll take to convert these PUDs to PD?

Well, let's look at Bravo.

For example, that is a four rig program that each rig can drill essentially one well per month.

So, you're more or less talking about being able to drill 50 wells per month --.

Per year.

Or 50 wells per year.

Thanks, sorry. 131 PUDS and 266 probables possible at 400 locations.

It's really an 8-year backlog.

We're obviously going to have to shorten that and that's where you create value, obviously.

A well drilled 8 years from now doesn't have a lot of present value.

So, that forward program will probably go up over time.

But, on the PUD component, just the PUD, 131, it looks like 2.5, 3 years certainly.

That's right.

Although again, I would expect that we would accelerate them once we've established that they're going to work as well as we'd like it to.

OK, then second kind of big picture question.

Big resource base that you're pointing out here, you know, presumably much lower risk.

The market is giving companies with resource base sort of potential, you know, much higher multiples.

How do you balance this?

It seems like you have more than you can do.

How do you balance this with your kind of deep, you know, higher risk exploration program?

And maybe you can give us an update of the exploration program.

Sure.

Well actually, we think it's a nice balance.

We think that one of the things that we do as well or maybe better than anyone in the industry right now, is to balance these lower risk gas resource plays with some pretty high charge to exploration.

And that high charge to exploration is focused in the spring or, in Morrow Place in Western Oklahoma.

In Western Oklahoma, we have 21 rigs active right now, 7 of which are in the Mayfield area drilling Springer wells.

At last count, I noticed we had 9 Springer wells producing.

We have another 5 in various stages of completion.

And I mentioned 7 drilling.

The wells take around 160 days to drill, so basically every two months or so we'll have another well coming online.

Those wells are still coming in close to that 20 bcfe on average and close to that 20m a day of production, of initial production that we've been talking about for years.

So, we're not going to sacrifice our commitment to deep exploration by taking drilling dollars away from that to go work on a lower risk, lower return gas resource plays.

Instead, we've just chosen to broaden the base of drilling and, again, we think it's a nice balance.

A third of our wells go shallower than 10,000 feet, a third below ten -- between 10 and 15,000, and then a third below 15,000.

And that's, you know, those are the wells that enable us to really go out and beat that 5% production number year after year and, most years, handily.

OK.

Thanks a lot.

OK.

Thanks for the questions, Van.

And Mr. McClendon, there are no further questions.

I'll turn the conference back over to you for any additional remarks.

OK, that's great.

We very much appreciate your interest in Chesapeake and, if you have any additional questions, let us know.

We're both traveling today, but we'll do our best to get back with you.

Thank you.

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