Chesapeake Energy Corp (CHK) 2005 Q1 法說會逐字稿

Good day and welcome to the Chesapeake Energy first quarter 2005 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 Corporate Development.

Please go ahead, sir.

Good morning and thank you for joining Chesapeake's 2005 first quarter earnings release conference call.

With me this morning are Aubrey McClendon, Tom Ward, Marc Rowland and our newest addition to the Chesapeake management team, Jeff Mobley.

This is Jeff's second day on the job as our Vice President of Investor Relations and Research.

Many of you know that Jeff has joined us from Raymond James, where for the last three years, Jeff was a well-respected sell-side analyst following the E&P sector.

I'm especially pleased to welcome Jeff to our team this morning because this will allow me to return to my position of Senior Vice President of Corporate Development.

For old time's sake, I would love to read one last time our Safe Harbor language, since I do not want to steal any of the thunder from Jeff.

I will now turn the call over to Jeff Mobley.

Thanks, Tom.

Obviously I'm very pleased and excited to join Chesapeake's organization.

Many of the key attributes of Chesapeake that framed my recommendations of investors on Chesapeake shares in my former career are really the very same reasons that attracted me to this new opportunity.

I very much look forward to meeting with current and potential investors, and also discussing the Company, as well as the energy industry from my new vantage point.

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

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

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

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

In addition, I would also like to point out that during the course of our discussion this morning, we will mention terms such as operating cash flow and EBITDA, and will also mention several items that we believe are typically excluded from analysts' estimates.

These are all non-GAAP financial measures.

Reconciliations to comparable GAAP measures can be found on pages 11 and 12 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 should last about 15 minutes, then we will move to Q&A.

Aubrey.

Thanks, Jeff.

Great to have you on board with us.

And good morning to each of you on the phone with us this morning.

Once again, Chesapeake has delivered a very strong quarter, featuring solid organic production growth, exceptional reserve replacement, and very good finding costs.

After excluding items not generally included in analysts' calculations, Chesapeake's first quarter net income available to common shareholders was $193 million or $0.56 per fully diluted share versus the consensus estimate of $0.50.

In addition, our first quarter operating cash flow was $505 million, or $1.44 per fully diluted share, and our EBITDA was $549 million.

These first quarter financial numbers were driven by strong production growth, tightly-controlled operating costs and a $40 million after-tax hedging gain.

With regard to operating cost, the controllable cash operating costs of our business, that is general and administrative expenses, lease operating expenses and interest expense, totaled $1.19 per Mcfe this quarter, versus $1.15 per Mcfe during the 2004 first quarter.

Very few companies have been able to keep controllable cash operating costs essentially flat during the past year.

We work hard to control all of our costs and believe it's an outcome of our focus on the details of our business and the result of 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 the Company's most important competitive advantages.

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

Oil and gas production increased 34%, compared to the year-ago quarter and 4% compared to the sequential quarter.

In addition, the 60% organic portion of this growth was exceptional, resulting in organic growth of 20% year-over-year, and 2.3% sequentially.

We are well on track to meet or exceed this year's organic growth rate projection of at least 10%.

Keep in mind this growth performance is from a company that's now the fourth largest independent U.S. gas producer, and eighth largest overall producer of natural gas in the U.S.

Of the seven companies that produce more gas in the USA than we do, we believe at least five had year-over-year production declines.

In addition, there are now only three independent companies that produce more gas in the U.S. than we do.

Devon, Anadarko and Kerr-McGee, and we expect to pass Kerr-McGee in 2005 after their asset sales are completed.

It's also quite possible we'll pass both Shell and Conoco-Phillips in U.S. gas production this year, which surely is a point of some historical significance in highlighting the majors' ongoing shrinking act in U.S. gas production and Chesapeake's surging U.S. gas production.

Added to the strength of our production growth is the consistency of it.

The 2005 first quarter was our 15th consecutive quarter of record production, and the year 2005 should be our 16th consecutive year of record production.

When we go around and talk to investors, we're frequently asked, when does the law of big numbers kick in and make further organic growth impossible?

Certainly a fair question and one we often ask ourselves.

In thinking through the issue, please consider that in 2001 we produced 417 million cubic feet of gas equivalent per day in the U.S. and grew organically that year by 9%.

In 2002, we averaged $497 million a day and grew organically by 6%. 2003, we averaged $735 million a day and grew organically by 18%.

In 2004, we averaged $991 million a day and grew organically by 20%.

In 2005, we expect to average 1.23 Bcfe per day. and should grow organically by at least 10%.

So in the three years ending in 2005, Chesapeake's organic growth rate should average at least 16% per year.

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

Consistent with our strong production growth, we also produced a terrific quarter of reserve replacement.

We replaced our 105 Bcfe of production with an estimated 637 Bcfe of new proved reserves for a reserve replacement rate of 609%, at a drilling and acquisition cost of only $1.20 per Mcfe.

Reserve replacement through the drill bit was 333 Bcfe, or 318%, at a cost of only $1.13 per Mcfe.

In addition, we replaced our production through acquisitions by 291%, at a cost of $1.26 per Mcfe.

On a net basis, then, we increased our proved reserves by 11%, or 532 Bcfe to a quarter-ending total of 5.434 Tcfe.

I would also like to highlight the PV-10 of our proved reserves, using quarter-ending prices, was $14.1 billion.

That's up $3.6 billion from our 12/31/04 PV-10.

If you include the acquisitions we announced and funded after the quarter's end in April, we now have proved reserves of more than 5.6 Tcfe and have a PV-10 of approximately $14.7 billion, which compares quite favorably to our enterprise value of only $11 billion.

It seems very likely now that we will end 2005 with at least 6 Tcfe of proved reserves, up at least 400 Bcfe from where we are today.

And here's why: We've identified a deep inventory of more than 7,000 locations to drill on our 3.5 million net acre lease-hold inventory.

We believe this is the largest inventory of onshore lease hold owned in the industry.

And it's taken us five years and over $1 billion to build this inventory and we've also hydrated it by spending more than $200 million on 3-D seismic.

This inventory, and the hiring of the very capable employees who manage it, prospect on it and drill it could not be replicated in today's ultra-competitive and costly operating environment.

We were able to acquire this lease-hold inventory and the technical employee base associated with it because we believed, earlier than most, in the sustainability of higher oil and gas prices and because we staked our claim earlier than most in a significant number of very important natural gas plays in the southwestern USA.

These plays include such notable projects as 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 south of Fort Worth.

The tight sand gas plays of east Texas and northern Louisiana, and most recently, the Haley deep gas play in the Delaware basin of west Texas.

In these seven gas resource plays, we own more than 1.5 million net acres, on which we've identified more than 5,000 of our 7,000 drill site backlog, and have an upside potential of at least 3 Tcfe in these gas resource plays.

We've already drilled approximately 1,000 wells in these plays in the past few years and plan to keep right on drilling.

Today, we have about 75 operated rigs at work and another 65 or so non-operated rigs.

This enables to us drill approximately 100 -- excuse me -- 1,000 operated and 1,000 non-operated wells per year.

We thought you might be interested in where our operated rigs are currently drilling, so I'll give you the numbers by state, and then the numbers by play description.

In Oklahoma, we have 38 operated rigs, in Texas, 28 rigs, in New Mexico, six rigs, and in Louisiana, three rigs.

By play type, we have 12 rigs drilling in the Granite Wash and Red Fort gas resource plays of western Oklahoma and the Texas Panhandle.

Eleven rigs in the Deep Springer and Morrow gas resource plays at the deep Anadarko Basin in western Oklahoma.

Ten rigs in the Sahara gas resource play of northwest Oklahoma.

Ten rigs in the Permian Basin, including four in the deep Haley area.

Eight rigs in the [Typsean] gas resource plays of the Ark-La-Tex region, including four in the Barnett shale.

Seven in the Bray and Cement gas resource plays along the Mountain Front in southern Oklahoma.

Six rigs in Zapata County in South Texas, four rigs in the Arkoma Basin and four rigs along the Texas Gulf Coast.

In most of these plays, we have a commanding lease-hold position.

You don't hear too much industry chatter about those because we have been able to keep the competition away.

However, there are a few plays that have been talked about in this quarter's conference calls, in which Chesapeake had a smaller interest, but a growing one.

For example, in the deep Haley play in west Texas, Chesapeake and Anadarko, both have about equal interest in an area that now looks potentially prospective over about 200,000 acres, that's about 125 sections of land.

It's too early -- it's too early to declare victory there, but we now have our first log in the area and it looks very promising.

We will have production from that well in a month or so and should have two more logs by then, as well.

We are ramping up drilling in the area and by a year from now we should have from 8 to 12 rigs running.

We are hopeful of per well reserves of 10 to 20 Bcfe from Haley deep, and believe this can become a very important source of future growth for Chesapeake.

In the Barnett shale, we are now producing about 65 million cubic feet of gas equivalent per day on a gross basis, and 36 million per day on a net basis.

With our horizontal wells averaging about 3 Bcfe and estimated ultimate recoveries per well in the very narrow area of central Johnson county, where we believe the best returns outside of the core area will be realized.

This is an increase from the 2.5 Bcfe we've been using to date and it's predicated on continuing to drill 3 to 4,000-foot horizontal laterals and using three to four stage frac jobs on those wells.

Keep in mind, when we acquired Hallwood in December, our net Barnett shale production was only 20 million cubic feet of gas equivalent per day, so we're up about 80% in six months in our Barnett production.

We have almost 500 operated and non-operated wells to drill in this Johnson County sweet spot so we're going to be very active here for a long time to come.

Finally, in the Fayetteville shale play in the eastern Arkoma basin in Arkansas, we own about 50,000 net acres.

While that's dwarfed by Southwestern's acreage position, we do expect to become a more significant participant in this play in the years ahead.

In addition, we also believe we have the largest acreage position on the Oklahoma side of the Arkoma, where the Fayetteville is known as the Caney shale.

We are hard at work on determining the viability of the Caney play as we speak.

At the end of the day, there are very few gas resource plays of significance in the southwestern USA in which Chesapeake does not have a meaningful presence.

That presence, along with our traditional exploratory and developmental projects, should enable us to continue delivering industry-leading organic growth in the years ahead.

I'll conclude by reminding you that Chesapeake is distinctive in at least three ways.

First through the backlog of drilling activities discussed above, we believe our organic growth potential is as good as anyone else's in the industry.

Second, we have 6% of the nation's drilling fleet under contract, yet we produce only 2% of the nation's gas.

So in today's exceptionally tight drilling rig market that is a very serious competitive advantage, especially in the acquisition market, where the ability to get PUD's, probables and possibles drilled quickly is the key factor in being able to accelerate value creation from today's acquisitions.

In addition, we are the only E&P company that we know of that is actively involved in hedging its exposure to rising service costs, which we have identified as the single biggest risk to our business.

We've accomplished this in three ways.

First, through our 17% ownership of AMEX-traded Pioneer Drilling.

Second, through our 100% ownership of Nomac Drilling Corporation, which is Chesapeake's wholly-owned drilling subsidiary that currently has 12 rigs drilling, and has 13 more rigs on order.

In these first two rig investments, we have an embedded gain of about $150 million already, and likely more to come.

So those have both turned out to be very effective hedges for us.

Finally, we are actively sponsoring the building or refurbishing of another 17 rigs by various private drilling companies.

In fact, by the summer of 2006, we believe Chesapeake will single-handedly have been responsible for the addition of almost 50 rigs to the nation's drilling fee -- fleet.

Basically, a 4% increase from today's levels.

A pretty remarkable feat, we think, from just one producer.

There would obviously be much less service cost inflation if other active operators would use some of their surplus cash flow to increase service industry capacity as Chesapeake is now doing.

I believe Chesapeake today offers a truly unique investment opportunity.

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

Chesapeake's management team remains very energized about the Company's competitive position in the industry and the returns that we are creating for our investors.

We appreciate the investments many of you have made alongside our own, especially those of you who have contributed to the success of our $1 billion securities offering two weeks ago.

We look forward to continuing to create significant value for you in 2005 and in the years ahead.

Now I will turn the call over to our CFO, Marc Rowland, for his analysis of the quarter.

Thanks, Aub.

Welcome, Jeff.

Good morning to everyone.

This will be pretty brief this morning, and is our custom, I will not simply repeat all of the numbers presented in our press release.

I will begin by updating you on our recent security offerings that Aubrey just mentioned.

In somewhat choppy debt and equity markets, we were successfully able to issue 600 million of 11-year senior unsecured notes at an attractive rate of 6 and 5/8%.

With these notes, we also issued 460 million of 5% perpetual convertible preferred stock.

The over-allotment option was exercised and has already been funded.

After earnings for quarter one, and pro forma for the offerings closed in April, our book equity remains at 49% compared to total book capitalization, and our long-term debt is only $0.68 per proved Mcf equivalent.

A few housekeeping issues, our revolving credit facility had been $724 million outstanding as of March 31st.

Of course, that was prior to the fundings from the senior notes and preferred stock offerings that we've now accomplished.

Capitalized interest for the quarter was $16 million.

That's compared to $5.3 million for the quarter ended one year ago.

Net capitalized internal costs related to our drilling programs were $20.5 million in the first quarter of this year versus $10.9 million for quarter one of '04.

Once again, Chesapeake has virtually no cash income taxes for 2004.

We do not expect any for 2005 or 2006, either.

As we exited last clear with a healthy $546 million of federal income tax net operating loss carry-forwards.

This is an asset that is sometimes overlooked by investors.

Let's turn to cost and service company inflation for a moment.

To date, this quarter's conference calls and releases have prominently featured discussions of increasingly higher rates of oil field service inflation.

This is not news to us.

And, in fact, is a topic Chesapeake has been focused on for two years.

As the nation's most active driller, we have a very good feel for the trends in these sectors.

Unlike most of the others in the producing sectors, however, we have been proactive in solutions to mitigate these price increases, as Aubrey has mentioned.

Today, for example, as we look at our investment in Pioneer Drilling Company, we own 7.7 million shares at a cost to Chesapeake of $42.7 million.

Today, that investment is worth approximately $103 million for a book profit of $60 million.

Despite the higher costs, our investments in our own operating drilling fleet continue to pay dividends as well.

After a very successful year in 2004 with drill bit reserve replacement at very attractive costs, we have continued that success into 2005.

We have provided a full reconciliation of our finding costs for the quarter, on page nine of our press release.

Aubrey highlighted the $1.13 per Mcf equivalent from drill bit only, when adding acquisitions and all unproved property costs, lease-hold, G&G, etc., the number increases to only $1.65 per Mcf equivalent.

What any investor should conclude is that this is a very attractive all-in number.

So, despite the higher service costs that we and the others are facing, our costs remain not only in control, but cash operating margins and our reinvestment success are among the highest that we've ever experienced.

Another point to highlight in this quarter is our positive reserve revisions.

For the quarter, our reserves were revised upwards by 45 Bcf equivalent, or about 1% for just this quarter.

This continues a multi-year trend of positive revisions.

Last year, for example, our reserve estimates increased 4.4% from the beginning of the year to the end of the year, and it looks like that we're on course to do that, as well, this year.

Finally, I would like to highlight that our hedging program, once again generated positive cash gains as described in our release, of just over $40 million for the quarter.

We believe this is a very unique performance in this sector of this quarter and despite the fluctuations for a non-cash FAS 133 reporting, remains a highlight of our continued successful performance.

I'd like to now turn the call back to the moderator for questions, please.

Thank you.

[ OPERATOR INSTRUCTIONS ] We will pause for just a moment to give everyone an opportunity to signal.

We will take our first question from Joe Allman with RBC Capital Markets.

Please go ahead.

Good morning, everybody.

Hi, Joe.

Aubrey or Tom, I'm not sure if Tom's there, could you talk about what you've done so far in the Arkoma Basin in the shales and the coals in terms of drilling?

Joe, we've really just been watching.

We have one rig that drills coal-bed methane wells, but there are currently a couple of other operators that are drilling some horizontal wells in the Woodford and the Caney and we have a lot of acreage, so we're non-op in some of those and we're planning to -- to drill a couple of horizontal wells later in the year.

Okay.

I appreciate that.

And then in terms of the Haley, what do you expect to be the biggest challenges over there in the Haley deep program?

Oh, the cost -- right now, well costs are moving up a little bit, so we started out thinking we'd drill the wells for $7 to $8 million and now we're more in the $8 to $9 million range, and -- but we think we're -- we're getting a feel off of the 3-D we have to be able to pick some locations, we still think it's a very good area to drill in.

Okay.

And did I hear you right, do you have three rigs running there in the Haley at this point?

We currently have four.

Four rigs.

Okay.

And within a month or so, we'll hear -- we'll probably hear about three rigs -- three completions or so?

I think we'll have three completions by the time our next quarter's report.

Joe, I think what I said was that we've got one log now and that well should be completed in the next 30 days.

Then in -- by the end of that 30 days, I think we'll have two more logs and then these will be multiple-stage completion operations as we're targeting from top to bottom the [Strahan], the Atoka and the Morrow.

So, I think Tom's right, by the end of the second quarter we should have, I would think we'd have three producing wells and would think we would have four or five logged at that time.

Okay, appreciate it.

Thank you.

Okay, Joe, thank you.

We will take our next question from Ellen Hannan with Bear Stearns.

Please go ahead.

Good morning.

Hey, Ellen.

Hi.

I just had a follow-up on Joe's question there.

That was my question -- what sands do you think you're going to be producing out of in the Haley?

And you say the [Strahan], the Atoka and the Morrow?

Primary objective -- I'll go ahead and turn it over to Tom?

There could be some [inaudible], but those are the primaries.

The [Strahan], Atoka and Morrow.

What's the depth you're going down to?

Most of the wells will be between 16.5 and 18.5.

And you mentioned 125 sections.

Is that net to Chesapeake?

Or are you in this 50/50 with Anadarko or are you each 100% in our own acreage?

I was describing that.

We think it's about a 200,000 acre play, maybe 225,000, so, the number of sections involved, at a minimum, would be 120 to as much as 150 sections.

Anadarko, I noticed in their conference call, talked about having around 110,000 acres.

We call it 100,000, we may be exactly about where they are.

Some of our acreage, we do hold 50/50 with them.

We did cooperate on a lease sale together but -- and we formed an AMI, Tom that covers, about a township?

Maybe a little more than that.

So, let's call it, Ellen, somewhere between 30 to 40,000 acres.

We're in a 50/50 deal with Anadarko.

And then, they have their own 100% acreage and we have our own.

But when you toss it all up and let it fall down, we're going to be 50/50 in the play with some very, very minor interests owned by some other companies.

And is 3-D obviously one of the keys here?

We believe it is, yes.

We believe we can see these three formations.

Keep in mind, the [Strahan] is really the Permian equivalent of the Granite Wash, which we're highly active in in the Texas Panhandle and Oklahoma Panhandles.

So, this is an example where we think some of our skills from deep gas exploration are transferable from the Anadarko Basin to an area such as this.

The other neat thing is that, there's just not too many companies in the country these days that have the people, the skill and the desire to drill 18,000-foot wells to go explore for gas.

Anadarko is one of those companies.

Certainly we are the most active deep driller in the country.

So, it's a really neat area for us.

We've acquired so much acreage, have only one other company as a competitor and I think this will form a -- a foundation of our Permian Basin business unit for quite some time.

We also contracted six rigs to be built that we can have ready for the first quarter of '06 and it will be very difficult for most companies to be able to ramp up like that.

Is this from the -- the drilling company that you own?

Or is this your Pioneer investment?

Neither one.

This would be that third element I talked about of hedging our service costs.

The first being our investment in Pioneer, second being our own drilling company, which has 12 rigs today on its way to 25, and the third is that we are sponsoring the building of another 17 rigs that other private companies are building and we are supporting those through use contracts, which typically extend anywhere from a year to two to even three years.

And so, if we wanted to go from four rigs in Haley today to eight rigs or 12 rigs, we couldn't -- we don't think we could do it without materially increasing rig rates.

So, instead, what we're going to do is encourage other people to use their capital to build additional rigs, which we will agree to contract for a certain period of time.

Does that give you any break on the contract or no?

Well, sure, yes, I mean definitely, because these people want to build them and the thing that they want to do is take away the risk that there won't be a use for them.

So, we can lock in what we think is a very attractive rig rate, they can get a guaranteed source of revenue, and we don't bump up the demand for deep rigs in the area, which then doesn't have the ripple effect across the existing fleet of drilling rigs.

We've effectively been able to maintain today's rate for the next two or three years.

That contract, Ellen, this is Marc, also allows them to go and obtain capital at a much less cost because they're actually looking through what would be just a private company's equity-standing toward Chesapeake's debt rating.

And, so, it's a just a win-win situation for many of these small companies.

And what would be the current day rate for a deep rig that you're -- what kind of rate are you able to lock in?

We've -- we have contracts ranging from 13 to 16,000 feet per day, depending on what kind of a rig.

Dollars per day.

Dollars per day?

In the Permian?

Well, yes -- well in the Permian and in Texas.

Okay.

Just one quick last one from me.

On your reserve ads due to performance of the ]45-B's], any one particular area or just widely scattered?

Ellen, it really just continues what we saw last year, which is a broad-based performance upgrade.

One percent improvement on what was about 4.9 per -- 4.9 Tcf beginning of the year.

There's not a single well, there's not a single field.

It's just across a broad base of successful performance.

Aubrey highlighted that we've gone from 2.5 to 3 Bcf kind of numbers in the Barnett shale.

We're seeing similar performance upgrades just across most of our resource base plays.

That reminds me, one last question and I'm done, I promise.

The three Bcf per well, Aubrey, that you talked about in the Barnett, is that a gross or a net number?

That's a gross number, Ellen, and it's for a very, very narrow portion of the county.

It's the central portion of the county, and it's [inaudible], where we're in where we have thick Barnett and we're drilling 3 to 4,000 horizontal foot -- laterals.

That would not be our number if we were drilling 1,000-foot laterals or 1500 or 2,000 feet, or if we were drilling 3 to 4,000-foot laterals and weren't fracing them with three to four stages.

It also requires us to spend quite a bit more -- quite a bit of money to do that.

Yes, that's for a $2.5 million well.

So, our well costs remain what we targeted in the past, but recoveries are up, but, in our view this is not an applicable number across other acreage blocks.

You have to be right here where we think the sweet spot is in central Johnson County.

I'd like to follow up something Marc said, which is last year, I think Marc, our -- our reserve revisions up were 4.4%?

Yes, exactly.

We had reserve revisions positive last year just on performance of about 140 Bcf, and when you begin the year, last year, at where we were, which was about 3.3 Tcf as I recall, that was a 4.4% positive performance revision for the year.

Hopefully we can continue that.

That will end up being half an Mcfe per share.

So, it's a pretty nice way to create value through creep, through reserve revision performance creep through the year.

Thanks, Ellen, for all of your questions.

Thank you.

[OPERATOR INSTRUCTIONS.]

And we'll go next to Ken Beer with Johnson Rice.

Please go ahead.

Good morning, guys.

Hi, Ken.

Most of the focus is on, kind of, your expense of exploitation plays.

Would love to get to get an update on -- what I’d term more your exploration play, which is the deep Springer plays, just to get a sense as to maybe the type of production, or maybe the additional reserves, that have come out of what was nothing several years ago or a couple of years ago, and now seems to be one of the drivers -- one of the many drivers behind your production growth.

Ken, Aubrey.

I am looking for my cheat sheet on that area, while I gather this information, Tom, why don't you talk about generally our approach there?

And even, just to give a sense, because obviously it's been somewhat overshadowed by a lot of the other plays that have come into existence over the last two years, but just to give a sense as to the number of rigs you do have going there, and maybe the type of reserve ads that may have come out of the exploration effort as opposed to just the acquisition/exploitation effort.

Ken, we continue to have 11 rigs in the deep Springer Morrow play.

But, on top of that, we have 22 rigs running in western Oklahoma and the Texas Panhandle throughout the western -- what we call the Anadarko division.

So, it continues to be the most active division in the Company and we -- we also continue to focus on trying to acquire new acreage there, plus looking for acquisitions.

It's what we look for, and continue to think of it as -- as the primary [thrust] and driver in the future.

Ken, in total we drilled 16 -- we have 16 Springer wells producing today.

Our average EUR per well is 21.1 Bcfe, that's a gross number.

And then average production rate, 10.8 million a day.

The last four wells we've drilled, the EUR's have been 13 Bcfe, 37, 25 and 22.

So, we continue to drill some very nice wells in that area.

Our Morrow program is shallower and not nearly as attractive, but still certainly economical.

We've drilled 11 Morrow wells and have per-well reserves of about 4 Bcfe there, and almost all of our Springer wells that I mentioned, we have Morrow behind pipe, as well, oftentimes we have Atoka and Granite Wash behind pipe, as well.

So, when I give you these reserve numbers, these are for Springer only, and really ignore the big behind-pipe reserves that we're able to -- that we will some day be able to access either through twinning these wells or through recompletions over time.

Ken, the Springer wells we’re drilling are usually the first wells in the section.

These are deep wells between 18.5 to 20,000 feet, but as Aubrey was saying, the Morrow is usually present -- one of the Morrow sands in each of these.

That's really going to be our focus in 2006, especially in the Buffalo Creek area, is to drill more Morrow wells as we get -- as we receive more information from the subsurface on the Springer wells that we've drilled.

Ken, just another way of thinking about it, the ultimate recovery from the wells that we've drilled so far out of the Atoka-Morrow-Springer combination in this area is over 435 Bcf of gross ultimate recovery.

You know, it's about two years ago that we were just talking about bringing on this play.

Our first well in the area really started about 27, 28 months ago now.

And as I think about the potential of continuing this, we spoke about it being a quarter to a half of Tcf play.

Well it's already that and more, and now we're kind of thinking about the deep Haley potential, kind of makes me think about two years ago, when we were in the same position with this play and what we might be able to do with the new play as well.

Let me jump in, one more thing, I want to talk about that one -- the Buffalo Creek well, I want to highlight.

That's the well that we started two years ago.

It's now, looks like it's going to be a 59 Bcfe well.

We originally booked it --

35, I think --

No, I thought it was 30 --

Do you have it at 25?

I had it at 17. [ laughter ] Okay.

Well, whether or not it's 17, 25 or 35, it's now a 59 Bcfe well.

So, I think one of the things we probably don't get enough credit for is the value of exploration, and very few companies today are set up that drill deep to find deep gas.

Here we found almost half a Tcf to date, and Haley has that kind of potential, and we're certainly a long ways from being done with our deep Springer program in the Anadarko Basin.

I think it is a very important competitive advantage that the Company has, that I think is probably underappreciated, but a few more discoveries like this and I doubt that it will be.

Great, thank you, guys.

Keep drilling.

Thanks, Ken.

We will take our next question from Dan Morrison with the Aperion Group.

Please go ahead.

Hi, guys, you covered a lot of ground.

Just a quick question.

Looks like you had the mark-to-market at a pretty good peak on your -- on the gas prices.

And they kind of reached to high right at the end of the quarter --

The gas and the well.

How would that -- those positions look now?

Or do you have that off the top of your head?

Our mark-to-market on everything has probably swung about half of that position, just in the last couple of weeks.

You ask how does it look today?

I could say it looks better because prices have gone down, but the fact is is that we still benefit from higher prices, so, yes, our mark-to-market position has improved and if it continues on this quarter, unfortunately, we'll see a big gain, but prices will of course be off for the product we realized.

Right.

It's a FAS 133 conundrum, in that you'd like to have higher prices but if you've hedged at all, even though we have remarkably high-priced hedges, typically you can show a loss.

Now, the fact is is that our cash gains on our hedging program since 2001 now are about $70 million, so, we're $70 million better off than we would have been had we not hedged at all during that period of time.

And I think that's -- if not the best, it's among one of the very best performances in the sector.

Plus, during that time, we took out virtually all financial and operational risk by being hedged as much as we were.

So, the combination of reducing the risk of running the business in conjunction with being able to actually gain an increase in cash is something we are proud of.

Great, thanks.

Thank you, Dan.

We will take our next question from Jeff Robertson with Lehman Brothers.

Please go ahead.

Thanks, Aubrey a lot of the questions have also been answered, but at the Haley play in west Texas, are there any transportation constraints as you and others ramp up activity out there?

No, we're actually in remarkably good shape there.

We've got a number of big transmission lines in the area, plus fields like Gomez, which are 99% depleted today, were found in the 60's and 70's and so there's an existing gas infrastructure there that we will be able to take advantage of.

And at this point we don't anticipate problems getting gas out.

Okay, you talk about scaling the Company's business model.

Can you talk for a minute about what you think Chesapeake's natural decline rate is?

We talked about that in our February 22nd release, where we gave our decline curves by year.

First-year decline for us is 26% and second year decline, I believe, is 18% and then it goes to --

Ultimately gets to --

It goes to -- it gets to 10%, I think, in the fifth year, but we're looking it up in our 10-K right now.

It's an important distinction.

A lot of times companies are asked, what's their decline rate?

It can be lots of different things, depending on how you choose to answer the question.

And our first-year decline reflects a lot of early -- or big declines from recently-drilled wells.

But if you want to know what our ultimate decline rate is, it's close to 10%.

We'll pull those numbers out for you again here in just a second.

And offsetting that first year decline, is the -- some of the mature production you're buying through the acquisitions?

Yes, although it's actually – it’s the whole base we have.

Remember, Jeff, our most recent acquisitions really, for the last couple of years, we're not buying much PDP these days.

We've established a broad foundation of production in the Company from about 21,000 wells and so, really don't want to buy a decline curve, we want to buy an incline curve.

So, all the acquisitions that you see us make are typically of small companies with a large percentage of PUD reserve.

For example in the most recent sales of properties by Anadarko and by Devon, we were not really interested or competitive in those processes because in our view, those companies had done a good job of locating their low-end reserves or low-end production, which was a decline curve and didn't have much upside.

And while we looked at those, we certainly -- we're not competitive.

So, I would say that we're going to continue to see the Company, when it makes acquisitions, find acquisitions that have upside associated with them.

That's what fits our model and that's what we expect to continue to do.

Okay.

While at the same time maintaining a very low out-year decline rate as a result of the tight rock in which we operate in the Mid-Continent and other places.

Thanks.

One question, Mark, I know you mentioned it, but can you say again what the capitalized interest was in the quarter?

Yes, I can say it again.

And that number was $16.0 million.

Okay.

Thank you.

At this time there are no further questions.

Mr. McClendon I will turn the call back to you for closing comments.

Okay, that's great.

Thank you all very much for your time today.

If you have any follow-up questions, please direct them to either Mark or to Jeff.

Thank you.

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