Chesapeake Energy Corp (CHK) 2007 Q1 法說會逐字稿

Good day and welcome to this Chesapeake Energy first quarter 2007 conference call.

Today's call is being recorded.

At this time, for opening remarks and introductions, I would like to turn the call over to Jeff Mobley, Senior Vice President of Investor Relations and Research.

Please go ahead.

Good morning and thank you for joining Chesapeake's 2007 first quarter conference call.

Hopefully you have had a chance to review the press release and updated investor presentation that we posted to our web site yesterday afternoon after the market closed.

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

Statements that describes our beliefs, goals, expectations 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 will 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 we will also mention several items that we believe are typically excluded from analysts' estimates.

These are all non-GAAP financial measures.

Reconciliations to the comparable GAAP measures can be found on pages 19-20 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 20 minutes this morning and then we will move to Q & A.

Aubrey?

Thanks, Jeff.

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.

Obviously you have already heard from Jeff.

We have Marc Rowland, our CFO, with us Mark Lester, our Executive VP of Exploration, and finally, Steve Dixon, our Chief Operating Officer, joins us from out of town today.

While we have quite a bit of good operational and financial news to discuss, I thought I would just focus on operational highlights this morning.

However, before I begin, let me address two topics that have come up overnight that I believe need to be hit head-on.

The first is the question, will we issue equity any time soon to close some or all of our funding gap for this year.

The answer to that is, no, because we believe the debt markets appear very attractive to us at the moment.

But there are many additional funding opportunities that are out there for us, and I know that Marc will have time to speak about this topic in a few minutes.

Secondly the question has arisen as to whether our production guidance is overly conservative.

I will just say, as you know, it has been our practice to keep our production outlook very conservative and this quarter's outlook is no different.

However, we will admit if present production trends continue, we will obviously need to raise our production guidance this summer, as our current production in early May already exceeds our estimate for all of the second quarter on a daily average.

So with that as a segue, I will move into our discussion about operations.

First, I hope you notice that our proved reserves increased by 5% during the quarter to 9.4 trillion cubic feed of gas equivalent or Tcfe.

In February, we have provided a projection for our proved reserves to reach a year-end 2007 level of 10 Tcfe and a year-end 2008 level of 11 Tcfe.

Given that we reached almost 50% of our 2007 target in just the first quarter of of the year, it should be clear that we will not have any problem reaching either of these targets.

It also seems clear that, in the second half of the year, we may need to increase our year-end '07 and '08 proved reserve targets as well as and obviously revisit our production targets as well.

I might also point out that we believe we can go sell this year's projected 1 Tcfe of proved reserve additions for around $3.5 billion in today's market.

We believe this provides further confirmation that Chesapeake is capable of increasing its net asset value by, at the very minimum, of $7 per share per year.

That works out to be about $0.02 per day per share, and we think we can do that this year and everywhere -- and every year, through at least 2010.

Secondly, I hope that you notice our production growth momentum is very strong.

With this quarter's production exceeding our forecasted production midpoint by 24 million cubic feet of gas equivalent per day or 1.5%.

Given that our early May production has already exceeded 1.8 Bcfe per day, it also seems likely that any doubts about our ability to achieve 14% to 18% production growth target for 2007 would be misplaced.

I also wanted to remind you of the scale of what we are going to accomplish this year in production growth.

For example, in December 2006, we produced about 1.68 Bcfe per day.

And one year later, in December 2007, we project that we will be averaging about 2.0 Bcfe per day in December of 2007.

Now, that's an increase of 320 million cubic square feet gas equivalent per day in just one year.

To help you understand the significance of that achievement, in one year Chesapeake will add in production to our company, an amount of production that is, in fact, bigger than the existing production of any of Southwestern, Cabbot or Range or about the same size as Ultra is today in terms of current production.

We believe that will be an unprecedented achievement in our industry.

Before I leave the topic of production growth, I would like to point out that in the first quarter of 2007, Chesapeake passed Exxon Mobil to become the nation's sixth largest gas producer.

During the first quarter our U.S.

gas production increased by 3.7% over the 2006 fourth-quarter gas production, while Exxon's declined by exactly the mirror image of 3.7%.

While not a specific goal of the Company, we believe that Chesapeake is on track to inevitably become the number one gas producer in the U.S., probably by year-end 2008 or early 2009, a position perhaps that most might have thought improbable a few years ago.

Next let's talk about what is driving Chesapeake's growth and proved reserve production and net asset value.

The simple answer is the drill bit.

Although drill bit growth is occurring across all of the Company's districts today, in the interest of time, I will highlight three areas of important drilling success.

The first will be in the Barnett Shale.

The second will be to discussed our upgrading of the Fayetteville Shale and Deep Haley areas from our emerging unconventional play category to our confirmed unconventional play category.

Third, I will want to visit about drilling for big gas wells, wells that can move the needle even for a company of our size.

In the Barnett, our drilling ramp-up continues as planned.

Let me offer up some history first.

Two years ago in May 2005, we were only running three Barnett rigs.

A year later in May 2006, we were running 10 Barnett rigs.

And one year later -- another year later, today, we are running 28 operated rigs and will soon have 30 running.

By midsummer, we should be at 36 operated rigs in the Barnett Shale.

We use drilling rigs to turn unproductive acreage into cash-flowing, producing assets.

Let's review our historical Barnett production ramp-up as well to see how well we have done at converting acreage into assets.

Two years ago this month, we were only producing 38 million cubic feet of gas equivalent per day, net from the Barnett.

One year ago, we were producing 108 million per day and, currently, we are producing 200 million per day, and that means about 300 million per day growth.

To give you a feel for the way the Barnett is ramping up on a quarterly basis, in the fourth quarter of 2006, we averaged 157 million a day from the Barnett, and in the fourth -- in the first quarter of 2007, we averaged 177 million per day.

Today, May 4, not quite midway through the second quarter, we are already up to 200 million per day from the Barnett.

These Barnett production gains should continue to accelerate through the year as we increase our rig count, and by the end of the year, our Barnett net production volumes should exceed 300 million per day and gross volumes should exceed 450 million per day.

We expect to see further impressive increases in Barnett production through 2008 and, in fact, we can see our Barnett production increasing through 2010, as we remain on track to complete just over one well per day from the Barnett, every day for at least the next four years.

One final thought about Chesapeake's Barnett assets.

There have only been about 300 net horizontal Barnett wells drilled on our acreage today, yet we still have about eight times that many left to drill on our 200,000 net acres Barnett leasehold.

In addition, we continue to have success acquiring more acreage in the play.

Primarily in Johnson and Tarrant counties as we lead the way in urban acreage acquisition.

For example, in the first quarter of 2007, we acquired 13,000 net acres.

That followed 10,000 net acres we acquired in the 2006 fourth quarter.

So assuming all this acreage gets drilled on approximately 60 acres spacing, Chesapeake's first-quarter acreage acquisitions increased our Barnett drilling inventory by over 200 wells, yet we only spudded 84 wells in the Barnett during the quarter.

Our goal is to acquire at least 25,000 net acres of prime Barnett real estate in each of the next four years.

In doing so, we would replace almost 100% of the wells that we will be drilling from our existing backlog of 2500 net wells during those four years.

When it is all said and done, we do hope that Chesapeake will have been able to drill more than 3500 net Barnett wells from a land inventory that should ultimately reach about 300,000 net acres in the core area of Johnson and Tarrant counties.

Please recall that 3500 net wells would generate ultimate reserve recoveries of about 6.3 Tcfe for Chesapeake.

Again, there have only been about 300 net Barnett wells drilled on our acreage today.

So you can see we have an enormous amount of underappreciated upside imbedded in our Barnett franchise.

The second area of Operations I would like to highlight today is our decision to upgrade two projects from emerging unconventional to confirmed unconventional, these two projects are the Fayetteville Shale and the Deep Haley area.

In the Fayetteville, we more than tripled our production during the 2007 first quarter, from 4 million per day to 14 million per day, and we more than tripled our drilling rig count from three operated rigs to ten.

We will further increase that rig count to 12 during the second quarter and if Fayetteville continues to work for us, Chesapeake's 370,000 net acre core leasehold position could easily handle a 20 rig drilling program.

Why the Fayetteville upgrade?

Quite simply, the play is working very well for us.

Our costs continue to come down to around the $3 million level per well, while our production levels and estimated ultimate reserve recoveries continually -- continue to generally exceed our expectations.

As most of you know, Chesapeake has always favored drilling longer laterals than other companies have in the play.

Industry consensus now seems to confirm that longer laterals are the way to go.

I think it is fair to say that what we have learned drilling and completing hundreds of Barnett wells, has definitely given us a technological leg up in the Fayetteville play and we expect that to continue in the years ahead.

Speaking of years, ahead as we ramp up to 12 rigs in the Fayetteville, we soon should be able to complete a new operated well about every other day in the play.

In addition, the last time I checked, we are in about 75% of Southwestern wells.

So our nonoperating production will grow pretty quickly in this play as well.

As I share with you in the Barnett I will now give you some math to think about in the Fayetteville core area.

On our present 370,000 net acre, we are projecting the per-well spacing pattern will ultimately -- ultimately lead to about 80 acres used per well.

So if all of our core acreage turns out to be good, that means we will drill about 4600 net wells in the Fayetteville.

As per well recoveries, 1.4 Bcfe after royalties, we could ultimately develop over 6.4 Tcfe from the Fayetteville, making the play potentially equivalent to the Barnett in terms of future reserve additions to Chesapeake.

And please remember, that we have only drilled 20 net operated wells to date, out of a potential backlog of 4600.

So virtually all of this upside lies in front of us, and I believe there is very little value reflected in our stock price for Chesapeake's very real Fayetteville upside.

Now I would like to move on to a discussion of why we also upgraded the Deep Haley play to the confirmed unconventional from emerging unconventional.

The answer is simple.

The seven wells that we have completed in Haley to date in 2007 are now producing at a gross combined rate of 95 million cubic feet of gas per day.

That's an average of 14 million per day per well, and that's current production, not initial production rate.

That has led to a tripling of Chesapeake's net Haley production in just the first fourth months of 2007.

And given that we are now bringing on a new operated Haley well every two to three weeks, we should expect Haley to be a big growth area for Chesapeake for many years to come.

Please also keep in mind that Chesapeake is also participating in many of Anadarko's wells in the area.

We continue to work well with Anadarko, and working together has enabled both companies to crack the Haley code faster than we could have each done on our own.

Before I move on I would like to provide with you a brief West Texas Shale update.

We presently have two operated rigs in the area, but will soon be using six rigs, as we begin testing various theories about how we might successfully be able to unlock the potential 50 Tcfe of gas that we own below our West Texas Shale acreage.

We have had some tantalizing vertical well results lately, and we will keep you informed as the year progresses.

My final operational highlight this morning is to talk about where big gas wells can be drilled in America today.

Given that Chesapeake is the most active driller in America today, we have been able to develop a view, in fact a proprietary view, on where the best places are in America to drill big on short gas wells.

In our view, there are just three such areas: the deep Anadarko basin in Western Oklahoma, the Deep Haley Play in West Texas and the Deep Bossier Play in East Texas.

And by big wells I mean really big, the kind that can come in for 25 to 50 million cubic feet of gas per day and can develop 20 to 50 Bcf of proved reserves per well.

I think I've already established this morning that Haley is a great place to look for big gas wells.

Now I'd like to review the Deep Bossier and Deep Anadarko areas with you.

I hope you saw our press release on Monday of this week about Chesapeake's $92 million Deep Bossier investment with Gas Star.

As a result of that transaction, we will have more than 350,000 net acres of potentially prospective Deep Bossier acreage and we will be steadily ramping up our drilling activity in this plate.

For example, today we are using one rig to drill our first 22,000-foot Deep Bossier well.

Next week we will be at two operating rigs.

And by year-end 2007, we will be at six operated Deep Bossier rigs.

This means that almost every three weeks we will be taking a shot at drilling the kind of wells that EnCana recently has completed very near and on trend with our Gas Star acreage.

I'll remind you, in EnCana's two nearby wells are producing a combined 100 million cubic gas of feet per day.

We believe these two wells may be the best pair of wells producing onshore in America today.

The third area for finding big gas wells in the U.S.

is the Anadarko Basin of Western Oklahoma.

Our great results in this basin have often been overlooked in the past few years, as most of the market's focus on unconventional plays.

However, the Anadarko district is still Chesapeake's largest single area of production, producing about 280 million cubic feet a day in the 2007 first quart.

And despite the view by some that the Anadarko is fully developed, we believe otherwise.

For example, in 2002, we revitalized deep gas exploration in the basin with our 20,000-foot Buffalo Creek deep gas discovery.

This well has been on-line 52 months and has now produced 47 billion cubic feet, on its way to an estimated ultimate recovery of 60 Bcfe.

I might add that we initially booked this well at less than 25 Bcfe of proved reserves.

It is also a reminder -- a reminder of why we look for big gas wells.

Today, a well like the Buffalo Creek could be drilled for about $10 million, while it could end up producing over $500 million of gross revenue, a return in excess of 50-to-1.

Since the Buffalo Creek discovery, we have drilled a large number of successful deep vertical and intermediate depth horizontal wells throughout the basin.

For example, our most recent eight Anadarko wells are now producing a combined 80 million cubic feet of gas per day, with our best well of those eight producing 33 million a day.

While it is important to recognize the importance of the 13 Tcfe of unconventional upside that I identified earlier in my presentation, that underlies our Barnett and Fayetteville acreage, I do wish to remind that you that Chesapeake is the only company with a position in all three big gas well areas onshore in the U.S.

All in all, I believe Chesapeake offers investors an opportunity you could not obtain anywhere else.

The number one unconventional asset base and the number one potential big gas well asset base in the U.S.

I will now turn the call over to Marc for his review of the quarter.

Thanks, Aubrey and good morning to everyone.

My comments, as usual, will be fairly brief.

It is pretty difficult to cover much new ground with a press release that is 28 pages long.

First though, let's talk about our funding needs this year.

We are not contemplating any equity issuances at this time, as Aubrey stated.

In fact, we believe we have many other alternatives.

The debt markets are robust.

We have investment bankers pitching us ideas for MLPs for our midstream and compression assets daily.

And we have numerous sales leaseback opportunities, as evidenced by our drilling rig leases that we have entered into.

Any of these can easily provide nearly $1 billion to us and are generally not valued at all by investors or rating agencies.

One idea we have begun to warm to is stripping a small piece of our PDP reserves in Appalachia, say 10 to 15% and monetizing those assets by selling to an MLP while keeping the upside in the deep formations.

We think this could be done for up to $1 billion and the Company would suffer almost no production loss on a percentage basis and the proceeds could be reinvested into extremely high-rate drilling, rate of return drilling, and result in no equity issuance.

Said another way, the current MLP market has helped us value an asset we bought for $3 billion in November of 2005 at perhaps as much as $5 billion to $7 billion.

Let's turn to our reserve replacements, which Aubrey also mentioned.

We are unique in the publication of quarterly reserves I believe.

The preparation of complete reserve reports each quarter by our reservoir engineering team has led to very high quality estimates that have been characterized by positive revisions, both performance and, I guess, price as well for many quarters now.

This quarter was no exception.

While our exploration and development cost number of $2.66 per Mcfe was slightly above our expectation for the quarter, we do expect it to trend down throughout the year.

Several items affected this number for the quarter.

One, our percentage of proved developed total reserves moved up during the quarter to 63%, meaning numerous PUD locations were drilled for wells that had already been booked.

Second, we have a number of science projects going on and Aubrey mentioned operationally the diverse number of projects we're in, but particularly in West Texas, money has been spent where reserves have not been booked.

Some investors have apparently compared this $2.66 until to our $2 number for all of 2006.

While that $2 number was the average for every quarter in 2006, costs were, of course, moving up dramatically throughout the year and in the fourth quarter actually exceeded the $2.66 that we booked this quarter.

The quarter was down sequentially and headed in the right direction.

Discussing drilling and completion costs further, we have seen recent decreases in both rig costs and, even more recently, in stimulation services, particularly in the Fort Worth Barnett Shale play, as new companies have moved in and to gain market share for their unused equipment had to bid the prices down.

Additional equipment is being added in both drilling and stimulation companies and some vendors are moving equipment out of Canada or the Rockies into the more active areas that the Chesapeake is involved in.

This should continue to allow for more competitive pricing throughout the year.

Some folks missed the fairly extensive contributions our marketing and service operations provide to Chesapeake.

This quarter, the gross margin contribution from those operations was about $27 million or $0.18 per mcfe of production.

This is over $100 million on an annualized basis.

One small housekeeping item that I typically throw in.

Our capitalized interest and internal costs for the quarter were as follows: interest was $63.6 million this quarter compared to $31 million one year ago and other capitalized costs related to our drilling programs were about $51 million as compared to $35 million one year ago.

A very notable benefit from our extensive hedging program shows up again in this quarter's realizations.

Our pricing per mcfe equivalent was $9.33 versus $6.52 per mcfe that we would have realized without any hedging, a pretty amazing $2.81 pickup.

Actually earlier, I thought our realizations would have approached $10, but weaker basis in both oil and gas held us back, particularly as gas moved back down in terms of wellhead pricing, the basis differential did not narrow as it has in the past.

However, this $2.81 compares to a fairly healthy $1.81 pickup from one year ago or, put another way, this $2.81 increased revenue per unit exceeded our total cash cost of $2.21 this quarter, which included production taxes, LOE, G&A, interest in dividends, all by itself and produces a margin of $.60 per unit.

This resulted in an overall cash market per unit of $7.12 for produced mcfe, our highest ever.

Some investors seem to be surprised or at least do not understand our marked-to-market moves for hedged oil and gas volumes to be produced after this quarter.

In the second paragraph of our release we reverence an unrealized loss of $193 million.

This simply reflects that prices for oil and gas went up, , a good thing, between 1/1/07 and 3/31/07 the end of the quarter, and for those volumes hedged, the market value for them went down in opposite movement to the prices going up, since we had sold at a fixed price.

No cash was lost, and the move down simply offset prior noncash gains.

There is tremendous benefit to be able to deliver long-term hedging gains on a realized basis, as we did this quarter and last year exceeding $1.2 billion, and we believe this speaks volumes about the significant benefit imbedded in a long-life, low-risk asset base which is optionality.

And optionality together with volatility are two of the hidden assets we pride ourselves in taking advantage of.

That's it for our prepared remarks.

And Mr.

Moderator, we will open the lines up

Thank you.

(OPERATOR INSTRUCTIONS) We will go first to Joe Allman, JP Morgan.

Good Morning, everyone, can you hear me?

We hear you.

Great, thank you.

Aubrey, what can you say about the noncore Fayetteville Shale.

What kind of results have you have seen?

And any comments on that?

Yeah, Joe, we have been pretty clear that we view that our noncore leasehold, which is about 700,000 acres, which mostly lies to the east and some of it a little to the south of our core leasehold position has little value at this time.

The wells that we drilled over there -- there were a handful -- and the other couple of handfuls of wells that were drilled by other companies, show that the Fayetteville basically east of White County will not likely be productive from the Fayetteville.

All righty.

Thanks, Aubrey.

Yes, Joe, thank you.

Next to Brian Singer, Goldman Sachs.

Hi, Brian.

A couple of questions.

First at Haley, what would you say changed there that allowed you to crack the code?

I think a couple of things.

One, more well control, as a starter.

Secondly, our 3D seismic information has been more fully integrated into what we are doing.

And I think we have changed some of our completion techniques.

So it is everything that we have been talking about for the past year that we thought would allow us to generate belter results would -- did come through and is coming through.

And keep in mind that we are also trying to hold by production a lot of acreage out here with just one well per section.

We are pretty confident that we can drill at least two wells per section and maybe as many as three or four down the road.

We kind of look at this area and say it reminds us a lot of the Anadarko basin in the, say, mid-1970s, where you are drilling wells a mile apart from each other and a great deal of Stratographic and some structural differences between those wells and we think we will be drilling here for many years, if not decades to come, and our results could get better over time as our knowledge of the area continues to increase.

Are you planning on testing the greater wells per section any time soon in.

I'm sorry, say it again.

Are you planning on testing down spacing?

Not at this time.

We are in kind of a desperate rush, along with Anadarko, to get our production -- or get our leases held by production.

So that is not a feature -- a planned feature of our drilling program for at least the next year.

Great.

And on capital spending, could you discuss, A, where you plan to spend the incremental $300 million this year and next and B, it looks like you spent about $465 million or so in acquisitions for the first quarter.

Can you talk through what you bought?

Yeah, I will take the latter and let mark take the former of your question.

Really not anything too big.

We bought $100 million or so of assets in -- in the cement area, plus some assets in the Arkoma, a fair amount in the Barnett.

Plus our small acquisition program continues to do quite well.

We have a small working interest buying team and a middle owner buying team that is capable of spending $15 million to $20 million per month.

Those are always our best deals.

Keep in mind that we have many thousands of working interest owners and many tens of thousands of royalty owners, which we systematically try and pick off.

Those should be our best transactions, as they have fewest options to sell and we have better knowledge about the assets than they do.

So that's part of it.

And as we said earlier, we thought that we wouldn't be making any headline-grabbing acquisitions this year, but instead thought we would continue to make a series of tuck-in or niche tactical acquisitions and still intend to do that.

Our number one focus will remain on the Barnett at this time.

I will let Marc take the first part or your question.

Brian, the areas that the additional money is being spent is pretty diverse.

We have just moved up our expected rig count in the Barnett Shale through -- as a result of a number of smaller transactions that we've made.

Some come with rig commitments.

Some leases come with drilling obligations.

So I would highlight that area as probably being a third to half of the increase.

There's a couple of other areas that we are also moving the rig count up, as we become successful and we do have a very active ongoing urban leasehold program, that is adding quite a few acres in the Fort Worth Barnett Shale area as well.

So no one real particular area other than the Barnett, just a series of increased rig counts.

We actually think we could move up to as high as 150 rigs now by the end of the year.

Mark, you might also mention compression and gathering assets.

Sure.

We are spend a lot of money on gathering and compression.

We probably ran at the rate of 15 to $20 million per month last year.

We have increased our budget to $40 million per month currently.

We have a whole series of compressors that on order to add to our Fleet extending out to 2009.

Virtually every one of these tight gas wells or unconventional shale wells requires compression at some level, whether that be at the field level for a large compressor on an individual well basis in some situations.

So the future of our business as we look -- looked ahead several years ago, just like drilling rigs, we believe that we would need to have lots of compression on order, and that it will be something that we could provide less expensively than the compression -- compression companies, have better service on it than an independent compression company, since it would be people working for our own account and it would provide two-to-three-year payouts.

As it turns out now, those assets will make an ideal MLP candidate and it's one of the items I mentioned up front in my presentation as being something that we are considering.

And so, you know, $40 million a month -- that is almost half a billion dollars of capital expenditures.

So --

Thank you.

Thank you, Brian.

We will go next to David Heikkinen, Pickering Energy.

I just ad a question, as you think forward in the Fayetteville Shale.

Any concentrated development areas?

Or are you still appraising acreage?

Or how is that rig ramp going to happen throughout the year.

We won't really concentrate, although we will focus -- we will focus on some areas where we control operations.

And Wyatt county is probably the area where we have the biggest concentration, an area we call Little Creek.

There we are trying to HVP acreage as well.

So that will be our primary goal.

We also are going to try to test closer in drilling, to see what impact that will have on EURs, estimated ultimate recoveries.

Keep in mind, when we drill wells in the Barnett, on average they are about 2.45 Bcfe in Johnson and Tarrant counties, but that is from a range of wells, some of which have 2,000-foot spacing between them, where reserve recoveries can average about 3.6,\ down to on 500-foot spacing, you get down to about 1.8.

So we see that when you reduce spacing in Barnett by half, or said another way, increase density by a factor of 2, your reserves for wells go done by about 30%.

So you go from 3.6 to -- let's call it 2.5 to 1.8 in the -- in the Barnett.

In the Fayetteville, we really don't know what that answer is, and I think it is one reason why we're reluctant to take our per well EURs up from 1.6 Bcfe now in the Fayetteville.

We are seeing results that will indicate our average wells will be, and are, better than that, but we don't know what happens when we go in and drill wells on closer spacing there.

The plan is to drill a series of 560-foot offsets from each other in a couple of sections this year.

So we are going to do a little bit of science, but for the most part, it is going to drill those wells to hold that production, so we can come back in and drill those 4600 wells that we think can be drilled on our acreage in the years to come.

Okay.

So in that area how much capital will you put into gathering and infrastructure as well, given that your holding a lot of acreage with -- with new wells?

I don't have the answer we have spent to date.

I know it has been a very significant commitment in terms of infrastructure, plus water issues are an increasing importance -- of increasing importance over there.

We are -- we have been plan to build a lake in that area and are building a dam for it right now and will be a big impoundment area for us for fresh water, which we will pump from the White River it times when we are able to do so.

It is a pretty massive industrial undertaking over there, spread over an area of about 100 miles, let's call it by 20 miles wide, and to go drill 4600 wells, that's -- you know around $13 to $15 billion of Cap Ex, associated Cap Ex on gathering and other infrastructure projects, would probably, just off hand, I'd have to think, probably 4 or 5% of that number.

It is a Mammoth undertaking and it requires companies of enormous scale to really be able to tackle projects of that size.

And then, just going to shift to West Texas Barnett.

Timing of wells and what type of expectations.

Are you testing shallow and deeper?

vertical and horizontal?

Can you give us some splits as far as what you expect and what your plans are?

Yeah, we are keeping that pretty tight to the vest, but let's be sure that whenever you refer to the West Texas shale play or the Delaware shale play, you refer to it as both the Barnett and Woodford play, because it may be that the Woodford ends up a better target for us than the Barnett.

There are other targets out there as well, and we are looking at those, some of which we are looking at for horizontal.

Some of which will be drilled vertically.

We have two -- in fact three big 3-Ds under way right now.

We are going to shoot a million acres of seismic in the next year or so.

I think that's probably an unprecedented amount of seismic in any one area, that's 3-D seismic in any one area kind of ever been shot in a year, and so we are pretty comfortable that we are going to find some conventional structural targets.

Some shallow or unconventional type sand plates, and we are also optimistic that we can convert all the shale gas into something that is commercial.

But it might not be a Barnett.

Might be a Woodford.

Or might be something else in addition.

So stay tuned is the best answer.

I wish we had more to say.

I will say that we have drilled a couple of vertical wells, and they are producing some pretty interesting amounts of gas from our two newest vertical wells.

Okay.

So if the traditional kind of 3 or 4 to 1 horizontal multiple over vertical works, then we've got a play on our hands.

But we have got to convert that vertical into horizontal production.

Thanks, I will let some people ask some questions.

Thanks.

We will go to Jeff Robertson, Lehman Brothers.

Aubrey, as a follow-up to the West Texas play.

Are there infrastructure issues out there that you all are needing to spend money on to where you can test those wells over long periods of time?

Jeff here.

Sure.

This is an enormous area.

I think we have 680,000 net acres, but we have got partners, and so I think our gross acreage is like 1.3 million, 1.4 million acres and that covers an area again longer than 100 miles long and 20 to 30 miles wide.

It is a desolate place, but luckily we do have two interstates that intersect -- Interstate 20 and Interstate 10 do bisect the acreage and so we have some signs of civilization, I guess, but water is an issue as well as gas infrastructure.

But we are -- we are on top of them, and we have got a team of individuals that are capable of doing -- of building infrastructure projects like that.

And secondly, Aubrey, in the Deep Bossier play that you talked about that where you recently expanded your acreage, do you have seismic or is there regional seismic available that you can tie your acreage to some of the characteristics that have made those EnCana wells so good.

Jeff, I think that is probably what is so remarkable.

To date, all the Deep Bossier drilling that EnCana has done, Anadarko had done some, Burlington/Conoco has done some -- all of this has been done on 2-D.

And the first big swath of 3-D from our hill-top shoot is just rolling in right now.

It's one of the reasons we held back.

We did not want to drill 2000-foot wells that can cost $10 million, $12 million, $14 million on 2-D.

Having said that, of course, obviously, very fine wells have been drilled and these two EnCana wells are extraordinary.

We are in the process of seeing the 3-Ds start to roll in.

We have more shoots underway, and that's why we are picking up our activity from one rig now to six rigs by the end of the year.

Thank you.

Thank you.

We will go next to Tom Gardner, Simmons & Company.

Good morning, guys.

Good morning.

Aubrey, in the release you talked about gas being a premium fuel and traded at a BTU parity -- or excuse me a BTU discount to natural gas -- excuse me to oil.

Let me get this right.

And this relationship has been historically volatile.

Can you further elaborate on that and comment on your views going forward?

I think we are in a real exciting time in our industry when, I think, our fuel, natural gas is in the process of getting revalued.

What's the knock been on natural gas -- over the last couple of years anyway, from a consumer perspective, it's that it's too expensive relative to coal.

Everyone knows it is a bargain relative to oil, but relative to coal, the knock has been that we are too expensive.

Well, in my view, that's only because many of the external costs of burning coal have not been captured.

And I think it's a foregone conclusion that the consensus that has developed about global warming and the causes of it, being increased greenhouse gas emissions, principally C02, will lead to some element of a carbon tax or some other series of issues that are going to make building and operating coal plants significantly more expensive in the years to come, and we think that there will be a day in the not-too-distant future when historical BTU premium that natural gas has traded at relative to coal will go away.

Natural gas is the single-best solution to the Company's issues, twin issues, about how do we produce more electricity; while, at the same time, reducing greenhouse gas emissions and how do we also further enhance National security.

Clean-burning, domestically-produced natural gas, is that absolutely the answer to that.

Our fuel has been cheap for too long, and I think we are in the process of a historical revaluation of our product.

And along those lines, to further enhance that process, Chesapeake has announced that we are the sponsoring founder of an organization called The American Clean Skies Foundation.

That will be based in Washington D.C.

It will be run by a woman named Denise Bode, who is one of three Oklahoma Corporation commissioners.

She has announced she will be resigning at the end of May to take this position in Washington.

This will be an educational think tank.

We hope broadly supported by natural gas producers, as well as environmentalists, and our goal will be to make sure that the truth is told about natural gas and -- and also the truth be told about competing fuels, as well, and we think this can have a very significant impact on the future value of the product that we sell.

Excellent.

A lot of attention has been given to your hedging strategy.

I noticed you were slightly more hedged in '08 than '07.

Can you elaborate on your view of the gas markets?

I will let Marc take that, but I think part of it is because you are probably not given credit for lifted hedges in '07.

Marc, do you want to take that?

I think that's right.

The fact is, though, we are very heavily hedged in the first quarter of '08 because prices have been so strong there.

In fact, I think we are over 95% hedged for Q1 '08.

Always, as people anticipate the coming of winter, those markets have typically reflected prices that have -- have moved to as much as $10 or even over $10.

And we have always viewed that as being a great price, as well as one of the riskiest periods of time if we don't have any cold weather during the winter.

So '08 -- you know we have just had opportunities to take some great hedge prices, and as usual, as it moves toward that $10 number, you see us heavily -- more heavily hedged.

Thanks, guys.

I will let someone else hop on.

Thank you.

We will take our next question, Wayne Cooperman, Cobalt Capital.

Hey, guys.

I was going to ask you about coal and gasification and carbon.

Do you have any sense of how tight the gas markets are?

How much market share, if we took away some coal, what would that do to the gas markets?

How much more incremental demand can we supply without prices going crazy?

Well it is really more of a function of weather.

The question is -- is difficult if not impossible to answer.

I couldn't figure it out myself.

I figured maybe you could.

I have no doubt that your IQ is higher than mine, but I will say that what -- what we see is a potentially dangerous scenario setting up for the industry, and we want to make sure that we are combating that, which is -- look, there is no doubt that the world is getting warmer.

We employ three meteorologists in Chicago that remind us of that all the time.

There has been some debate about what has caused that warmer weather.

We view that debate as largely irrelevant.

We think the risks of global warming are such that to ignore them, the human race does so at its own peril.

o we want to recognize that the potential of consistently warmer winter weather, where we lose the consumption of natural gas in the winter and we replace that by more gas consumed in the summertime through the consumption of electricity, mainly in the South, that's not actually a very good trade-off for us particularly in the short-term.

And so we want to make sure that going forward, the story isn't told that coal is or can become clean without regard to recognizing that clean coal technology is not all that clean and it is certainly not proven and certainly not commercially available for every coal plant that will probably get built.

And secondly we need to combat the notion that somehow natural gas is the air supply in the U.S.

Three or four years ago, I was actually a proponent of the view that gas supplies in the U.S.

were -- were going to be more limited in the future.

That is before I understood how much gas there is locked up in shales and other unconventional formations.

So today, the message that we intend to take to policymakers in our country is that there is plenty of gas left in the U.S.

to be found.

We think we sit on it more of it than any other company, so it is obviously in our best interest to convey this message.

Now it is true, that this gas can't be developed at $3 Mcf but it's also also true you can't find oil produced at $$20 to $25 a barrel either.

Nevertheless, we believe that gas is attractively priced today, is a bargain compared to its environmental benefits, and that there is a lot of upside associated with owning the cleanest fuel that can be produced and consumed here in the U.S.

and it is our goal to roll more and more of those reserve as we go forward and to be a bigger and bigger voice in talking about natural gas and energy policy overall.

Thank you.

I will next go to Ellen Hannan with Bear Stearns.

Good morning.

Hi, Ellen.

A quick follow-up.

Could you remind us Aubrey of the economics that you're looking at?

I think you gave the well costs in the Fayetteville of $3 million and the average EUR of 1.6, if I got that right.

What is the similar well cost in the Barnett shale in your acreage?

We are using 2.45 Bcfe, developed at a cost of $2.5 million.

Marc has turned -- I will turn it over to Marc for a second.

Ellen, we on our web site have the usual, what we call our May investor presentation.

On page 38 of that presentation, the play economics and type curves are listed for each one of the plays.

So rather than repeat them all here, if you would go to that presentation.

That's fine.

I'll do that.

One other question.

Aubrey, at one point, you said in terms of the macro gas outlet that you ran the Company, in quotes, in fear of LNG.

That's the one topic you haven't addressed today.

Could you give us any thoughts you have on that?

You have good notes, Ellen.

We have certainly talked about that in the past couple of years, and that actually would be something I would have said probably in 2006, 2005.

Before I saw more evidence of what I think is pretty clear to anyone who looks at worldwide natural gas markets today, which is that you have got a pretty tight worldwide gas market.

And the notion three or four years ago that all this gas is going to come to the U.S.

and flood the U.S.

and drive gas prices down to $3 to $4 and bankrupt the U.S.

gas producer obviously was a misguided view.

I want to throw out one statistic to make sure everyone is aware of.

The U.S.

consumes about 60 billion cubic feet per day.

The world consumes about 275.

And actually worldwide gas consumption has been increasing about 3 to 3.5% per year.

So that's about 8 Bcfe a day of new gas consumption every year.

If you just look at the liquefaction schedule for the next five or six years, you can begin to see that there is really not 8 Bcfe a day of that coming on.

Some of that gas demand has to be laying additional pipeline from various areas.

I think the notion that the U.S.

could get swamped in LNG is probability unlikely to happen.

As you know, in the past year, there have been times when we have been hardly been able to attract any LNG.

I do think the increased LNG importation capacity into the U.S.

is a very good -- very good news for the U.S.

gas producer, because it does knock down some volatility, which, I think, helps maintain market share going forward.

If, you know, events like Katrina, for example -- I don't think $14 or $15 gas prices are good for our industry.

So the ability to ratchet up LNG imports, when for some reason we're short of gas in the U.S.

and then scale them back down when we don't need them as much, is a very desirable feature and a welcome feature of present day U.S.

gas markets.

That's it for me, thanks.

Thank you, Ellen

We will go next to Scott Hanold, RBC Capital Markets.

Good morning.

Good morning, Scott.

Could you guys clarify for me, on the commentary you had when you talked about the fact that you are not looking at issuing equity, you mentioned that you are looking at potentially -- or you at least have the opportunity to sell some PDP Appalachian assets to an MLP.

Just to clarify, recently you had some talk about the fact that creating a MLP that is Chesapeake controlled is more of a headache versus the value it creates.

Are you talking just an outright sale here?

Yes, Scott.

This is Marc.

We have had with most of the people in the industry extensive discussions with investment banks on the various pros and cons of the formation of MLPs.

I know that some of our peers or competitors are looking at -- or are in the process of forming MLPs.

We have been a little reluctant to go that route.

We don't have the classic drop-down scenarios that some of the other players have.

We don't have assets, for example, that are -- have full tax basis so we'd have some tax leakage in that kind of a deal.

We really don't want to divide an excellent growth story and form what would sort of be a competitor in that business and would have to have stand-alone management and some fiduciary questions.

But if we can achieve the same thing by selling some assets, and it would be an outright sale, of a sliver of nonoperated assets that we could receive the valuations for that the MLPs would be trading at and perhaps even better a valuation than formation of our own MLP because we have some new issuance discount.

Then we'd achieve all of the goals, which would be to take a -- a mature asset that has a long-life characteristic, retain the upside of the drilling locations, either increased density or deeper, and receive valuations that today, a lot of these MLPs have handles of 5% to 5.5%.

It is our understanding that the market value that they are willing to pay for the assets like that would be PV-7 or perhaps 8 on a future strip pricing.

We can take those monies and invest them in the Barnett shale, for example, for rates of run that are 60% to 70%.

And it almost becomes a virtual cycle where we develop assets that, a small portion of which can be transferred to fund a much larger growth profile, and that's why we are considering it.

Nothing has been done.

We are not negotiating with anyone, but it is a real viable alternative to the alternative of issuing equity to fund our growth.

Could you sort of quantify sort of the range of the daily production that you have in Appalachia that could potentially fit into that sort of mechanism?

Well, I can quantify our daily production.

Appalachia is running a little over 130 million a day.

Any or all of that could be put into one.

What we are talking about will be a small percentage of that.

So, you know -- to quantify that, that is 7% or 8% of our overall production, and if we were to do 15% of 7% or 8%, it is 1% of our production where the -- the proceeds from that would go toward developing, you know, 14% to 18% production growth per year.

Okay.

Moving to the Fayetteville shale, can you talk a little bit about the conventional opportunities you may be seeing there?

Well not so much -- I mean -- there are not so many in the Fayetteville shale area itself.

We have drilled a couple of Pennsylvanian wells, shallower wells and we do believe we will be able to successfully map a series of Pennsylvania and sands across there.

It will probably about around in there at the end of the day.

We do have other conventional targets in Arkansas and, we'll be targeting or using one to two rigs later this year to drill some pretty interesting structural plays that we have built some nice leasehold positions more in western Arkansas than in central Arkansas.

Okay, thank you.

Okay, thought

We will go next to Gil Yang, Citigroup.

A couple more shale questions.

Just some details first, the 1.6 B that you talked about recovering, that's first gross and also it's what assumed spacing?

That is gross, yes.

And that really doesn't have a spacing assumption to it because we haven't drilled enough wells to know.

Right now --

Sort of an infinite spacing in some sense?

We thinks it is a reasonable assumption to use for our present spacing pattern, which is projected to be about eight wells per section, average lateral length of around 3,000-foot per well.

So that's what we are working on right now.

We have frankly seen average reserve recoveries for our last, let's call it, ten wells that are above that number, but we are reluctant to honor that data, because those wells have not been drilled very closely together.

As you go to 80-acre spacing, which is the ultimate spacing you suggested would be there, would that be close enough that you would expect to see well interference or based on what you see in the Barnett or is it still far enough apart?

We will see interference, no doubt about that or let me say, you'll see intersection.

Your fractiles will reach out and touch other wells.

What we have consistently seen in the Barnett, of course, that we just come back up and hit the curve that the wells were on.

So you do -- you do through tighter spacing find incremental reserves.

But the incremental reserves are not the same reserves that you'd find on 1,000-acre spacing or 2,000, say 1,000-acre foot spacing or 2,000-foot spacing.

Remember in Arkansas we are drilling inside of governmental spacing units that are 640 acres.

Just the geometry of the well path.

And drilling within that one-square-mile constraint actually sets up 560-foot offsets compared to, in the Barnett we are able to go to mathematically down to about 500 foot exact offset laterals.

Okay.

Is there any reason to think that as you get tighter spacing, that simulfracting the wells will actually give a synergistic effect where the wells will begin to rise before they start dropping off?

We are familiar with the theory.

How we simultaneously fract wells is a little different than what some companies are talking about.

We developed a far more efficient way to simultaneously fract wells, which to use one fract crew rather than two on a pad and fract an interval on one well and, while you are doing all your wire line work to get ready for the next interval on that well, you go over to your next well and fract the equivalent zone there and then you go back and forth.

So some -- the simul fract involves having two fract crews at a time pushing against each other.

Our view is that you really can't pressure up the formation so some abnormally high level, that the fract will always search for pressure equilibrium and so really what you end up doing is pushing your fract way in opposite direction and we feel like our version of simultaneously fracting is both cheaper and mechanically more efficient as well.

Okay.

And then -- this final question is -- you know you talked about the ramp in production of the Barnett.

Could you give us some idea where you think you think you might peak out in the Barnett production rates, both either gross or net?

Our gross numbers are -- are over a Bcf a day.

I am not going to give you a year, because it is too scary to contemplate.

You do the math on what we have accomplished with just having drilled 300 wells, and imagine drilling eight times that number to as many as 12 times that number to give you a sense that there is a lot of growth in the Barnett to come.

So clearly that is one of the reason why I am optimistic of being plenty of gas to meet gas demand going forward and why the Company will continue to take advantage of price spikes to lock in prices, that there will be a lot of demand or a lot of supply, rather, coming out of north Texas in the years ahead.

And we will be a primary generator of that.

Okay.

Thanks, Aubrey.

Okay, thanks

We will go next to David Cameron, Wachovia.

Congratulations on a good quarter.

Thank you.

A couple of quick questions.

And in Haley, seven wells averaging 95 million a day.

What is the variability in there?

The best well is 39 million a day, and our worst well, I think, is 6 or 7 million.

Okay.

And you mentioned that -- did you ever give us how -- how aggressive you are going to get out there with your rig count and well count?

I don't think I did.

I am not sure if it says in the release or not.

But I know we are at 6 rigs right now, and I believe Marc, we are going to eight.

Eight.

We are going to eight by the summertime.

Yeah.

Pretty consistent.

It will be -- remember this is within 50 miles of -- of part of our shale plays.

We will be at -- at six rigs and then we have one or two rigs working on ValVerde kind of overthrust play.

In the Delaware basin we will have about 15 rigs and have a great deal of flexibility to move rigs back and forth between different plays.

Okay.

And then, when you are up in New York at (inaudible), you talked briefly about -- kind of mid-continent differentials, the impact perhaps that Rex has for '08 and what you are doing on the hedging side.

Can you refresh me on that?

Well, our view is generally that as Rex opens up, there will be pressure on mid-continent basis and, in face, the futures market for basis currently reflects that.

We have been active basis hedgers going back to 19 -- or 2002, excuse me, when we could lock in a basis on a couple of points for as little as $.14.

The future market for basis generally is around $1.

And what we have been doing is taking additional hedges when it approaches -- which haven't been very often, approaches the firm transportation amounts, and there is really two ways to hedge basis.

One is to enter into long-term firm transportation arrangements with pipes that are either in existance or to be built.

And we have done that extensively for bases across the Barnett, Oklahoma, and some in the Fayetteville as well, and to the tune of, you know, a half of Bcf, three-quarters of a Bcf a day, and the other is to go into the future market and try to hedge that.

It is not attractive to hedge right now, in our view, because it is substantially above the firm transportation that we can arrange, but generally speaking to your first question, Rex should have the same effect that the other pipes coming out of the Rockies have had, which is to, at least temporarily, increase the wellhead realizations in the Rockies and, against that, decrease the realizations in the mid-continent.

I will say today I looked at several delivery points in the Rockies and they were $4 to $4.65.

Mid-continent today will range from -- for delivery week -- it will range from $6.85 to $7.15 and our Dominion delivery points in the Appalachian basis were in excess of $8.

So you compare the value of an Mcf over in Appalachia at $8 versus the some of the Rocky delivery points at the wellhead will be below $4.

That's a pretty striking difference as to what the value of an Mcfe should and could be treated.

Does that answer your question?

Very good color.

One final question, Marc.

Is -- I guess the assumption is -- I couldn't believe the Rockies will trade in parity with mid-continent.

What is kind of Chesapeake's view on that?

Well I think that it could trade briefly in parity as a new pipeline is opened up.

But there have been a number of but pipes built over the last several years, each of which are going to permanently cure the basis differential.

None of them have ever permanently cured the basis differential, and Rex, in our opinion, won't either.

It may until some additional gas comes on and you have gas-on-gas competition but likely it won't for very long.

So our view would be consistent with yours, which is the Rockies will not in most time periods trade at parity with mid-continent.

Our view has simply been the Rockies have been a good place to look for gas, but a pretty tough place to make money, and I don't see that changing in all arguments that we heard about Rex changing basis were the same ones that were heard about Kern river before this and Cheyennes Plains after that.

I will say that our basis hedging on mid-continent alone has realized value and in marked-to-market value is about a billion dollars.

Over a billion dollars.

Over a billion dollars and will be entered into that when we recognize there will be pipes that try to arbitrage that gap between Rockies basis and the Mid-Continent basis.

One other thing I would add too which is, the gas-on-gas competition for phase two of Rex will also -- could also effect the basis in Appalachian.

Accordingly, we have been hedging quite a bit of basis out through 2010 at levels from plus $.31 to plus $.37, feeling like that there was some exposure that the basis could shrink there and we might as well take a free insurance policy to lock in exceptional value.

All right.

Thank you.

We have a follow-up question, Jeff Robinson, Lehman Brothers.

Thanks.

Part of it was asked around the MLPs, but Marc, can you talk a little bit with Chesapeake's ability to offset taxable gains on a potential asset sale with the use of either your NOLs or if you were able to match it up with some of the acreage-type investments that you are making, kind of on a 1031.

Yeah.

There are really three ways that I have examined what could happen.

You touched on two of them.

We have significant NOLs presently.

In excess, at least of non-AMT of $600 million.

The second one could be a theoretical matching up of a 1031 either for acreage or some other acquisition.

And the third, of course, is our IDCs.

The Company is in combination with its acreage and seismic drilling more than its operating cash flow.

And to the extent we do that, we create additional tax deductions.

So it actually might be a very good time to look at disposing of something like that in the manner I talked about, because we could offset it with IDC reductions and, at most, we would have some exposure to AMT tax.

Right now we are a very minor AMT player.

We pay $5 million of ATM tax for last year and we're looking at 15 to 20 this year, and we pay no regular income tax.

So also our basis in the properties in Appalachia was $3 billion.

That was a purchase transaction where we were able to have pretty high tax basis in the assets we bought, and of course we've expanded our tax basis by acquisition of acreage and drilling there to date as well.

Secondly, you mentioned possibly something around your midstream assets, but do you worry at all about putting some of those assets into a separate entity that may then not be as tied in to Chesapeake's oil and gas operating areas and, therefore, losing a little bit of control in terms of getting things hooked up and being integrated with them?

Sure.

And that's been one of the reasons that I haven't been a proponent of pursuing that exactly.

I am probably much more of a proponent of putting our compression assets into such an entity, because those assets are going to continue to be run to the exclusive benefit of Chesapeake, and essentially what we will be doing is monetizing the future revenue stream without a change of operational control at all there.

Our -- our compression assets to date, I think we have $165 million invested.

We have another $195 million or so on order.

The monetization of those, I think, could result in us receiving back all of those monies and giving up at most 50% ownership in them.

And so, it becomes sort of a two-to-one value proposition for each dollar we have invested or would invest in a compressor, essentially we would monetize that by giving up half interest to a MLP while keeping half and having absolute operational control.

Okay.

Great, thanks.

We will go next to Monica Verma, thanks.

We will go next to Monica Verma, Gilford Securities.

Monica, are you there?

Hey, there.

How are you doing?

We are doing fine, thank you.

Couple of questions.

One, just looking back, you said that you mentioned that the costs were coming down.

I was wondering if you could just give a couple of examples of sort of your internal day rate versus certain areas -- in certain areas versus what you are seeing with other operators, and if you see it in any one particular area or not.

I won't compare it with other operators are seeing, but I will compare to what we were seeing four to six months ago.

And we're seeing basically 15% reductions in -- in day rates on drilling rigs and 15% reductions on fract jobs.

Those are our two biggest elements of drilling of horizontal wells these days.

And so we -- we certainly did not see lower costs in any meaningful way filter down to our first-quarter numbers.

But we certainly believe that through the course of the year, that as these lower costs drives through our system, that we will probably see lower and lower planning costs during the course of the year and there will be other service costs that will continue to go lower as well, as we see service infrastructure expansion continue throughout all of 2007.

We expect that it will continue into 2008 as well.

Okay, great.

The second part of that question, the areas that we are seeing it now.

On the drilling rigs we are pretty much seeing it across the board.

Barnett shale rigs have moved from -- oh, a going rate of 21,000 into the 17,000 or 18,000 rate currently.

The fract stimulation services, the most notable declines have been in the Barnett shale area as, I think, it is logical that several new entrants have gone there because of the drilling activity that we and others have, and each one of these wells requires 3 to 5 stages of fract.

So that alone, seeing -- seeing some new entrants there with 15 to 25% price reductions have been very encouraging for us.

Okay.

Great.

And just one other question in dealing with -- you mentioned also with the -- when you were talking about the MLP, that you retained the deed rights in the Appalachia area.

Can you talk a little bit about that and, like, any future Cap Ex planning that you might have for that?

I will just speak about it briefly, which is one of the big areas of upside we always anticipated developing some day in Appalachia was -- what were deep targets.

And we've already shot three large 3-D projects in Appalachia I guess -- finish one and two and about to start a third.

We have more projects under way there.

So we think that we are the premiere deep gas explorationist in the U.S., and really looking forward to taking that that skillset to Appalachia in the years ahead and excited about the possibilities that lie below say 10,000 feet in the very complicated geology of Appalachia.

Great.

Thank you, guys so much.

Thank you, Monica.

As a reminder, (OPERATOR INSTRUCTIONS) We'll to next to Jeff Hayden, Pritchard.

Quick question for you on the Fayetteville.

You mentioned on the fourth-quarter call that your wells have been averaging about 2 Bs and you actually hope to push those up going forward as far as the recoveries go.

Have you seen anything which changes your opinion with regard to that?

No, I think I would just reiterate what I said before, which is officially we are still using 1.6, again we don't know what the final number will be as we go to tighter spacing, but I can confirm what I said then is what we are seeing now that our present round of wells is significantly better than 1.6.

And just -- I guess -- we brought a new well on this week that is good, but our single best well we brought on about ten days or so ago.

And it might be the best well on the play to date from what we have seen.

I think we are getting better at being able to keep our wells in zone and using 3-D to stay away from faults, where we have drilled some unsuccessful wells, where we haven't been able to keep the fault or keep the fract job in zone as it has leaked away off of a fault.

So just a lot yet to learn and lots of efficiencies yet to drive into the drill-in program, but we are making steady progress and we will continue to see costs go down.

And I think reserve recovery is likely to inch up over time.

Okay.

thanks a lot guys.

Thank you.

Having no further questions, I'd like to turn the call over to Jeff Mobley for any additional or closing comments.

Thank you again for joining the conference call and your interest in Chesapeake.

We will be available for comments the rest of the day and you can call me directly and the contact information is available at the top of our earnings release from yesterday.

Thanks again and we look forward to talking to you in the future.

There will be a rebroadcast of this conference available today at 11:00 a.m.

Central Time, running through May 17th at midnight Central Time.

To access this, simply dial 1-719-457-0820 and use the passcode 9507142.

Thank you and have a good day.