Chesapeake Energy Corp (CHK) 2006 Q4 法說會逐字稿

Good day, and welcome to the Chesapeake Energy fourth quarter and full year 2006 conference call.

Today's call is being recorded.

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

Please go ahead, sir.

Good morning.

Thank you.

We appreciate everyone joining us today for Chesapeake's 2006 fourth quarter and full year financial and operational results conference call.

Hopefully you've had a chance to review our press release and updated presentation that we made available yesterday afternoon on our website.

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 statements.

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 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 21 through 24 of our press release issued are yesterday.

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

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

Aubrey.

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

I would like to begin by introducing the other members of our management team who are on the call today.

Marc Rowland our CFO;

Steve Dixon our Chief Operating Officer; and Jeff Mobley our Senior VP of Investor Relations and Research are me me here in Oklahoma City, while Mark Lester, our Executive VP for exploration joins us from out of town.

There is much Chesapeake good news to talk about this morning given all the Company accomplished during the fourth quarter and the full year 2006.

However, in the interest of time, I will focus on just three topics, first, the strength and quality of our production growth and proved reserve growth, second, the excellent finding costs that we reported for both drill bit reserve additions and acquisition reserve additions, and, third, I will review some key operational developments.

Let's begin with a discussion of production growth and also proved and unproved reserve growth.

For the year we reported production growth of 23% and proved reserve growth of 19%.

Our production growth was generated roughly 50/50 from drilling and acquisitions while our proved reserve growth was generated two-thirds from the drill bit and one third from acquisitions.

For 2007 we are forecasting 14 to 18% production growth, 10 to 14% reserve -- proved reserves growth and for 2008 our initial targets are to achieve at least 10% growth in both production and proved reserves.

We expect to end 2007 with proved reserves in excess of 10 Tcfe and 2008 in excess of 11 Tcfe.

Please keep in mind these reserve growth targets are for our proved reserves only.

Our industry-leading inventory of conventional and unconventional plays provides us with unrisked, unproved reserve potential of a mind boggling 71 Tcfe.

After applying risk factors much higher than we have seen used elsewhere in the industry, we have use reduced that inventory of unproved reserves down to a risk number of 18 Tcfe or approximately 25% of our unrisked number and approximately double our proved reserve number.

This uniquely deep and broad inventory of unproved reserves assures this company and its investors of at least two things.

First, we will have strong and visible double-digit growth in production and proved reserves for years to come, and, secondly, we will have differentially better finding costs and returns on equity as the acreage costs for these unproved reserves has already been paid for and financed.

Among many durable competitive advantages that Chesapeake has created for our investors over the years, I believe this one has become the most important.

Second, I would like to highlight the strength of our finding cost numbers for the year.

The purest way to evaluate these numbers is simply to determine what costs were incurred to drill and complete wells and what were the results of those wells.

For Chesapeake that number is very straight forward.

We invested $2.7 billion in drilling and completing wells, and we delivered reserve adds to the drill bit of 1.345 Tcfe resulting in finding costs of exactly $2 per Mcfe.

We believe that in an industry that may have seen $3 finding costs on average in 2006, Chesapeake's finding costs to the drill bit are particularly impressive.

I might also add that Chesapeake's drill bit finding costs for our own operated wells were roughly 25% lower than our drill bit finding costs from outside operated wells, and given that we are both the nation's most active operator and the nation's most active non-operator, we have a unique data base to draw on from determining how the rest of the industry is doing.

As a third focus of my remarks I would like to bring you up to speed on some operational achievements.

I will begin with an update on the Fort Worth Barnett Shale play where our growth production now is running 275 million cubic feet of gas per day and our net production is 175 million per day.

Our full -- our net full year 2006 Barnett production increased almost 90% from our full year 2005 Barnett production volumes.

We believe that we are likely to see an even bigger ramp-up in Barnett production in 2007 probably on the order of 100%.

Our proved reserves in the Barnett are now 1.1 Tcfe, and we expect that number to increase by at least 75% during 2007.

Today we're drilling in the tier 1 heart of the Barnett Shale play with 24 rigs and should be utilizing up to 35 rigs by mid-year 2007.

Once fully ramped up, we will be completing on average a new Barnett Shale well every day in the tier 1 area, and with average initial production rates of around 2 million cubic feet of gas per day, you can easily imagine how our production from the Barnett will jump dramatically this year.

I might also remind you that our strategy from day 1 in this play has been to focus only on acquiring acreage in the tier 1 area of Johnson, Tarrant, and Western Dallas Counties where we now own 160,000 net acres of prime leasehold.

This tier 1 area is the heart of the play and remains the best place to develop largest Barnett Shale reserves and the best production.

Recently an independent publication called the Powell Barnett Shale news letter analyzed all horizontal wells drilled in the play to date which was to find the October 31, 2006, and identified that Johnson and Tarrant Counties were the crown jewels of the play.

In addition, the report showed that Chesapeake has to date drilled the best horizontal wells on average in the play and further confirms that per well reserve recoveries in all counties south and west of the tier 1 area are either subeconomic or barely economic.

We expect to lengthen our lead in this area in the years to come as many of our peers will -- have begun or will soon need to begin pushing their drilling programs south and west into counties that are less prospective.

In contrast, Chesapeake has more than 2,000 net tier 1 wells left to drill in the years ahead representing nearly 3.5 Tcfe of potential future proved reserve additions.

This also highlights a paradox in valuing our company today.

The bright line that once existed between proved undeveloped reserves and probable and possible reserves has largely disappeared due to the advancement of scientific and engineering knowledge and technology and the application of that knowledge and technology on various unconventional plays especially the Barnett Shale.

I can assure you that the 3.5 Tcfe of gas reserves that I just mentioned do indeed exist underneath Chesapeake's Barnett leasehold, but because the SEC says these are not proved reserves in the eyes of most investors they do not exist.

Recall -- in addition, please recall that these unproven Barnett reserves represent just 20% of our total inventory of 18 Tcfe of risked unproved upside that we have captured for our investors, and we believe this is a unusually large underappreciated asset in our company.

As well positioned as Chesapeake is now in the Barnett, we are not sitting still.

Our acreage machine continues to roll up prime tier 1 acreage.

In the fourth quarter alone we acquired 10,000 tier 1 net acres from more than 10,000 -- through more than 10,000 individual lease transactions.

Think with me, please, about that achievement.

Using an average spacing unit of around 60 acres, that means that during the quarter our Barnett land team acquired the rights to drill more than 160 new wells adding 300 Bcfe of potential new reserves to Chesapeake.

To put that achievement in context, I will remind you that we spudded 60 Barnett wells during the quarter, so we actually added a net 100 wells to our Barnett backlog.

In addition, the Company in its entirety produced 152 Bcfe, so we achieved a 2:1 reserve replacement for the whole company just through our Barnett acreage acquisitions during the fourth quarter.

Plus in the first quarter of 2007 we have continued to successfully acquire additional tier 1 acreage.

It should be noted that despite the fact that we are not from Fort Worth Chesapeake has quickly become the Company of choice for most big landowners in the Fort Worth area.

In recent months, for example, we've made deals to lease prospective Barnett acreage from such well known names in the area as the Bass family, Union Pacific Railroad, General Motors Corporation, and most recently Colonial Country Club.

Moreover we are now the only public company that has extended its operating infrastructure into urban Fort Worth, and we believe Chesapeake will continue to roll up more urban leasehold in the years to come.

In addition, we are just completing our unprecedented 3D seismic shoot over the 18,000 acres at the DFW airport.

This was an incredibly complex undertaking requiring the assistance of the DFW airport management team, the FAA, the EPA, the office of Homeland Security, and countless other regional and national organizations that have partial or full jurisdiction over the DFW airport.

I would also like to tip my hat to Chesapeake's geoscientists who designed and managed the shoot, and we also appreciate the efforts of Dawson geophysical who actually gathered the 3D information.

By the way, the 3D looks great so far, and we see very flat and very thick Barnett Shale underlying the airport.

We will begin drilling our first saltwater disposal well on the airport in April and expect to drill our first horizontal Barnett well in May.

Next I would like to highlight our achievements in Appalachia.

You may recall we acquired our initial position in this area in November 2005 through the $3 billion acquisition of Columbia Natural Resources.

When Chesapeake acquired CNR we acquired production of 117 million cubic feet of gas per day, proved reserves of 1.1 Tcfe, risked unproved reserves of 1.4 Tcfe, and total 3-P reserves therefore of 2.5 Tcfe.

Today our production exceeds 130 million cubic feet of gas per day.

That is an increase of 11%.

Our proved reserves are up to 1.5 Tcfe, an increase of 35%, and our risked unproved reserves now exceed 2.4 Tcfe, an increase of 60%, and finally our total reserves now exceed -- the total 3-P reserves now exceed 3.9 Tcfe which is an increase of 55%, all of this in just over one year.

Furthermore we have recently drilled our first deep well in the basin, and it is a very encouraging discovery.

We have also shot or are shooting the three largest three-dimensional seismic surveys ever acquired in Appalachia, and we have more planned in 2007 and 2008.

During 2007 our Appalachian drilling program will continue focusing on numerous targets, some of which will be structural deep targets identified on our 3D surveys.

While we will also targeted various new vertical and horizontal plays in a variety of promising shales and tight sands.

It is an exciting time to be in Appalachia and Chesapeake is leading the way in bringing modern exploration and development principles and technologies to a basin that has largely been ignored by the mainstream E&P industry for decades.

Watch this space for more Appalachian excitement from Chesapeake in the quarters ahead including news from our first horizontal shale well later this year.

I will wrap up my remarks this morning with an update on the Fayetteville Shale in Central Arkansas.

We continue to like this play very much and are gearing up accordingly.

Our rig count will be increasing from 3 rigs to 12 rigs by mid-year, and our strategy of drilling longer wells and deeper areas or longer laterals rather in deeper areas appears to be paying dividends.

Our 2007 completed well cost should average around $3 million to drill wells to an average true vertical depth of around 6,000 feet and then drill horizontal laterals of 3,500 to 4,000 feet.

This is deeper and longer than other companies have been drilling to date and is the reason our wells have been more expensive to drill.

However, we believe our greater investment per well is well worth it as our Fayetteville wells are now routinely seeing 2 Bcfe and EURs and we have even drilled some 3 Bcfe wells to date.

When Chesapeake gets rolling in the Fayetteville by mid-year we should be completing a new Fayetteville well every other day on average.

I hope that my excitement about Chesapeake's accomplishments in 2006 is obvious to you, and I also hope that my excitement about the year to come is equally apparent.

Chesapeake has never been in a better financial or operational position than we are in today, and I believe you will remain very impressed with what we can deliver in terms of shareholder value in the years ahead.

I will now turn the call over to Marc.

Thanks Aubrey, and good morning, to everyone.

It is great to be speaking with you this morning regarding Chesapeake's terrific financial results for the fourth quarter and the full year 2006.

As we've reviewed various results from our peers this earnings season, a notable theme has been reduced profits among many of our peers, particularly in the fourth quarter on reduced revenues per production unit.

That was certainly not the situation at Chesapeake with our very robust hedging program really kicking in resulting in record annual earnings.

In the fourth quarter alone we locked in additional revenues of 447 million through hedging, almost $3 per Mcf equivalent.

For the year those additional revenues were a stunning $1.25 billion or $2.17 per equivalent unit.

The result of which is the most important measure, adjusted earnings per share where in 2006 despite significant equity issuance and balance sheet improvement during the year we were up 40% over our 2005 numbers.

Those numbers are $3.61 per fully diluted share this year versus $2.57 in 2005.

We are focused here on production reserves and income growth as you might know but measured on a per share not an absolute basis.

Many people have questioned the sustainability of our hedging strategies.

We look at the ongoing volatility of natural gas prices and the effects of highly variable weather as we've seen yet again this winter and believe that these do not appear to be going away any time soon.

For 2007 and 2008, we have 48% and 60% of our gas volumes swapped already at $8.63 and $9.20 respectively.

Also for those years we have about 55% combined of our oil volumes hedged at almost $72 per barrel.

That's not the whole story.

For 2007 we've already realized $1 per Mcf through hedges that we previously reversed in 2006, so at the present time our price realizations for gas are predicted to be above $9 per Mcf again next year.

Callers and call options sold aid in boosting our realizations as well, and we're not including the volumes that I just mentioned.

Based on information reported to date and most companies have released earnings, we believe we have the highest unit operating profit in our large cap peer group.

While our DD&A rate was above the group average, it partially stems from buying valuable assets in a more recent cost environment, having non-cash tax basis step-ups, booking no goodwill but generating more margin through hedging and superior basis differentials particularly in Appalachia.

Our return on equity in 2006 of 27% ranks us above the peer average of that large peer group -- large cap peer group average of 25%.

Let's turn to a different topic for a minute.

We are often asked what part of your business is not well understood by investors.

I think one answer to that question is the power and the value of our ancillary integrated service operations.

We now own and operate almost 70 of our own drilling rigs headed to the low 80's by the end of this year including our trucking operations, gross profit contribution for the quarter alone was almost $14 million and for the full year $62 million.

This only captures a small portion of the value as most of the work that we do is for Chesapeake on Chesapeake-owned wells.

Accounting rules do not let us book that contribution on the income statement but instead it is booked as a credit to our full cost pool.

For the quarter the credit alone was $33 million and for the year $82 million.

Said another way, on a run rate basis for Q4 total benefit was $46 million or almost $200 million annualized.

At a 5.5 times multiple this implies a value of our drilling rig and trucking operations of [$1] billion [Audio Difficulties] billion.

But then we also owned marketing, gathering, compression, and processing assets.

The gross profit from those operations for the year were $55 million after eliminations per service performed by Chesapeake which was a $21 million elimination which showed up in the increased revenue per unit or decreased lifting cost area.

We are frequently pitched the idea which is certainly a hot idea in the investment arena today of monetizing these assets giving the receptiveness of the market for MLP Midstream assets.

At the current multiples in the market of 8 to 10 times our Midstream assets are easily valued at $0.75 billion.

Additionally, our investments in Chapparel, Fractech, Eagle Energy Marketing, GasStar, and others exceed $0.75 billion in value and like last year with pioneer drilling we expect to earn at least $100 million this year monetizing one or more of these assets.

We pride ourselves in being our best contractor and think the services we provide to ourselves and our partners are top rate and value-added.

It is just that value-added part that is frequently not realized by our stakeholders.

A few accounting facts, capitalized interest for the fourth quarter was 59.9 million and for the full year 179 million.

That compares to 2005 of fourth quarter 24 million and for the full year $79 million.

Our capitalized internal costs related to our drilling programs for the fourth quarter were 41.4 million and for the full year 160 million, again comparing 2005 fourth quarter of 26.9 and for the full year 102 million.

Let me wrap up by talking about costs a little bit and reserves.

Our reserves increased substantially during 2006 aided by both successful drilling and acquisition activity.

As Aubrey mentioned our goal is to continue that success in 2007 and see 2007 year end results of at least 10 trillion cubic feet equivalent and proved reserves by the end of 2008 at 11 trillion cubic feet equivalent, all without additional acquisitions and without additional external funding source.

A complete reconciliation of our adds including our fifth consecutive year of positive performance revisions is provided in our release.

Service cost trends is always a question we receive with CHK being the largest user of on-shore drilling services in the industry.

Drilling rates started to fall in fourth quarter of 2006, and drilling rig utilization flattened as incremental rigs became available.

We see indications of as many as 300 new U.S.-based land rigs in place by the end of 2008, so we see that trend continuing downward.

Pumping services have stopped going up, and at least in the Barnett Shale where there are many new competitors, new bids are now down 10% as significant new equipment is coming online there as well.

If the rig count does not increase from here, we think that there is room for some price decreases here through the end of 2007.

Steel costs are slightly lower, and other miscellaneous costs are either flat or declining.

Our goal is to see overall cost decline in 2007, perhaps by as much as 10 to 15% although that will depend on the path of natural gas prices this year.

We are not yet budgeting for a decrease but remain hopeful.

In any event, this would be the first time since 2002 that costs have not increased year-over-year, if our prediction comes true.

Moderator, we are now ready for a question and answer session.

[OPERATOR INSTRUCTIONS] We'll take our first question from Scott Hanold, RBC Capital Market.

Aubrey, you guys obviously focused a lot on the Barnett Shale.

Can you dig a little bit deeper into maybe some of the assets you acquired from Dale resource?

Kind of talk about some of the results you've seen to date.

It sounds like they've been pretty strong, and importantly what do you think of sort of that simultaneous frac technique they used to complete the wells?

Is that something you think you can institute across a larger area and your thoughts on activity in that area as well?

Sure.

For the second part of your question I will ask Steve Dixon to address that in a second.

I will take the first part which is a transaction that helped us -- well, there are two transactions that helped us enter the kind of inner core of urban Fort Worth.

The first was the four 7s transaction that we announced in 2006 that was $845 million.

The other transaction which I don't believe was announced by name, and that was with Dale operating we actually did two transactions with Dale, and that put us really in the heart of Fort Worth along the Trinity River bottom extending around downtown and out to the east.

Our view is that probably the best rock in the -- in the Barnett underlies urban Fort Worth, and so we have made a concerted effort to build a position in this area.

We have numerous agents working for us here close to 1,000 land in the Barnett Shale alone working urban kind of a urban door to door guerrilla warfare campaign if you will.

The prize, though, is quite significant.

Wells that we have drilled and our predecessors in title have drilled will lead us to believe that again we think over time the best results and the play to date will probably be underneath the heart of Fort Worth.

So -- but to be successful there you have to have a land machine in place.

You might have heard me say that we acquired 10,000 net acres in the fourth quarter.

That required 10,000 leases to be signed.

That is a huge barrier to entry in this play if you don't have a land machine like we have, plus you have got to get gas out, water in and out, and so as we continue to expand our infrastructure into urban Fort Worth it does create barriers of entry to other companies.

I will let Steve talk about both simultaneous fracing and also something that's kind of inseparable from that which is pad drilling.

We see a big plus with subcutaneous fracing for two reasons.

One, we're putting more energy into the rock and so it will do a better stimulation, and secondly, it is -- it adds efficiencies to our process and allows us to get more work done in a day and to get more fracs done with our high activity level there in the chalk.

Okay.

Is that technique something that you think you guys can expand to other parts of the Barnett then and get some better results out of?

Yes, sir.

We're routinely doing that now.

We've gone to -- what percentage, we probably have 14 rigs anyway on pads today.

All of those pad drillings will be on the simulfrac.

Roughly 60% of our current drilling is pad drilling today which reduces our footprint and adds to the drilling and completion efficiencies which Steve mentioned.

Okay.

One last question.

Aubrey, you guys talked a little bit about service costs.

Sounds like you're calling for potentially some softening here in '07.

We have heard some evidence of not only has there been sort of a reduction in utilization due to some new builds but potential pullback in the total rig count across the U.S.

Can you sort of shed some comments to that and if that's the case, where could we be seeing a pullback?

Well, I don't think we really see the pullback in total rigs in use.

I think a lot of people were looking for it, and if we hadn't had a cold spell from January 15, to February 15, I think you would probably see a rig count today maybe 100 rigs below where we are today, and say today we're around 1,700.

Cost trends we really start to talk about this almost two years ago.

We felt like the second half of '05 and the full year '06 would be the worst year for costs that our industry would face for years to come as obviously producers react first to the cash that comes in from high well head prices, and then we use up all the service industry capacity in the service industry is naturally -- wants to see the sustainability of future business before committing to extents to an increase in the supply of their services.

That buildout started to occur in '06 amounts hitting the market in '07 and '08.

We see a very virtuous world for E&P companies this year and next year where the rig count could stay where it is or maybe even go up, yet we see unit costs for drilling for pressure pumping and really for everything in the oilfield to continue to come down on a unit cost basis.

It is not a bad world for service companies either as their per unit cost declines may be more than offset by continued increase in rig activity, so we have been driving a good bit of this as over the last couple of years we've added 50 or 60 new rigs to the industry's fleet and know that as a result we have helped at the margin keep costs lower than they otherwise would have been.

We're very excited about cost trends this year.

We have got gas production locked in at almost $9 an Mcf and we think we're going to see costs decline for the first year and five years.

We think it will be a fabulous year for value creation at Chesapeake and perhaps in the larger E&P business as well.

Thank you.

Thank you for the questions.

We'll that our next question from Shannon Nome from Deutsche Bank.

Good morning.

Good morning, Shannon.

A couple things.

First on the acquisitions market, any assets in the market of interest to you?

And, of course, I'm thinking specifically if it turns out that Dominion decides to split up its package, are there any pieces there that would represent a good fit or what are your thoughts in terms of the acquisition market right now?

Shannon, as you know we've moved from a strategy that featured resource capture to one that favors now resource conversion.

If you consider the Dominion assets and the Anadarko assets, there have probably been $20 billion of assets that have been for sale in the last six months and you don't see Chesapeake's name besides either or any of those.

I think what it tells you is that what we said was true which is we thought we would be much less active in the acquisitions market going forward.

You probably continue to hear rumors about us because we do attend data rooms.

There are things that we will be interested in from time to time, but the market for acquisitions today appears more competitive than it has been in the last five years when we bought over I believe about $12.5 billion of assets and with the advent of private equity money into the equation, the likelihood of Chesapeake being competitive on to many acquisitions these days is probably quite low.

The good news is we don't have to be active.

We have got so many opportunities for drilling and increasing our drilling count.

We're running between 130 and 135 rigs today, and that's still yields well over a ten-year inventory of things to do.

Exactly what I would hope to hear.

That's great.

In fact, in your slides you note that -- I think you explicitly say the big payout for your shareholders is the resource conversion phase, just to sort of tie this question down, is there any upper limit on the size of the acquisition you'd target or just kind of remain opportunistic in continuing to focus on the drill bit side?

We've made a couple of 20 to $50 million tuck-in leasehold acquisitions.

We'll continue to do that.

I would be surprised this year if we don't do close to 750 million or $1 billion of just little deals at 20, $50 million at a pop, but those are what I would call tactical acquisitions.

I don't think the cards favor something real big.

Okay.

Great.

Just before I hang up, your unit LOE was quite low again in the fourth quarter, flattish with Q3.

Looks like you're sticking with guidance which I think is a little higher than that.

Is that just some intentional conservatism or what do you think the realistic chances are you can hang with where Q4 unit costs were on the LOE side?

Shannon, I am probably responsible for that.

It is first of all an element of conservatism.

We've been just so spooked or I have about cost increases in the last eighteen months which have really been substantial.

I listen to all of our peers conference calls, and they talk about 10 or 15% price increases, and I don't know what wells they're in, but we've seen price increases of that every quarter, so if prices -- gas prices remain like they are, and we're accurate about our trends in service costs, I think that we have a chance for LOE to remain about where we are.

Certainly the new wells that we're bringing on in the Barnett have extremely low lifting costs, and as you bring that new production on, it tends to dampen the effect of overall service increases, so I hope we're being conservative, and I would not be surprised if costs don't remain about where they are.

Shannon, one additional thought there.

What I like about this discussion is of course I like the conservativism of it, but also we're talking about kind of pennies and nickels on the cost side.

Where on the revenue side the opportunities that we see in selling volatility, taking advantage of volatility give us revenue realizations that can be higher by others in the industry of up to $1 or more per Mcfe.

In fact, I think if you compare our fourth quarter realization versus the industry average we were close to $3 I believe above the industry average, so it is really a real opportunity for us to highlight that while costs are obviously very important in this business, where you separate yourselves from the pack is on the revenue side of the business, and that's where we tried to really highlight that for investors last year, and we think this year as well.

Thanks very much, Aubrey.

Thank you, Shannon.

Thank you.

We'll take our next question from Jeff Robertson, Lehman Brothers.

Aubrey, as a follow-up to the discussion on acquisitions, can you talk a little bit about the competition for your capital between drilling your own wells and chewing on this very large inventory you have and the opportunities you do see in the acquisition market?

Well, Jeff, we start with -- everything starts in the drill bit side.

We don't budget for acquisitions other than these little tuck-in numbers that I talked about, so our budget and our focus is completely on converting our inventory of drill sites to prove developed producing reserves, and we've communicated that now for the last six months and we'll continue to have that as our focus.

We will, as I mentioned to Shannon, continue to look at opportunities simply because we learn quite a bit when we evaluate things that other people end up buying, so we'll continue to do that, and theoretically there is always something out there that might be of value to us, but at this point I don't see anything on the horizon, and what we look at is how can our organization most efficiently and effectively convert this ten-year inventory of drill sites into PDP, and so that's why you've seen us double our drilling rig utilization during the past year and why over this year and 2008 it will probably continue to drift up as plays like the Fayetteville begin to work and it requires a ever-larger number of rigs to kind of telescope down that present value creation that rather than it taking ten years we would like it to take a lot shorter period of time than that.

Secondly, can you or maybe Steve talk about how far down the learning curve you expect to be in 2007 in West Texas where I think you indicate 25 wells will be drilled this year?

First of all, we hope to always be moving up the learning curve rather than down the learning curve.

I will let Steve talk about beyond that.

We have a ways to go.

It is a brand new play, and so we will double and triple our knowledge whether we'll have the code cracked a year from now I wouldn't guarantee that but we'll be much better at it.

Pouring the well today, shooting 3D seismic, again, applying much needed well control, so we'll get better every month.

Jeff, I will just highlight the size of the prize there.

We control or own on a net basis 1,100 square miles of land.

We do know how much gas is in place.

We've taken cores.

We are producing dry gas from these rocks.

We know there is about 500 Bcf of gas in place below every square mile of land in the stacked play of Woodford and Barnett.

On an unrisked basis we're still -- I can't tell that you any of it will be economic to recover, but I think it is a great place to start with that kind of reserve potential in place, and there is nothing like it in the Fort Worth Barnett in terms of that amount of gas in place per square mile.

The challenge is this is much deeper and to date the wells are expensive and we haven't yet cracked the code on how to best drill these wells and how to best complete them.

I like the odds of -- if anybody can crack the code in the Delaware shale, I think it is our company which today drills more shale wells than any other company in the business, and we see more shale information than anybody else, in fact, we're within a month away from completing what we think is the newest and the best rock technology center in the U.S. that will be right here on our campus, and we'll be able to analyze our own cores for our own benefit plus we expect to be able to analyze rocks on behalf of other companies that may come to us and invite us in their plays as a result of our ability to offer a proprietary opinion about what their cores look like, so exciting time to be in the shale business, and we are very hopeful that we can create some value in the Delaware basin shales.

Thank you.

Thank you, Jeff.

We'll go next to Marshall Carver with Pickering Energy.

Yes, thank you.

Question on the timing and the target for the Appalachian shale well that you're going to be drilling this year.

Timing I think we get under way in the second quarter if I am not mistaken.

Second quarter, so we expect in the second half of the year to have some information on our horizontal shale wells, and we are going to target various horizons, won't be all in the same horizon.

I would suspect that we won't be overly forth coming with information about that or our deep activities, as we still view that there is some acreage in the area that is prospective for us that we will continue to pursue.

Okay.

Thank you, and on the proved developed reserves, where did those stand at year end?

Chesapeake proved development?

For the total company.

The total company is 9 trillion cubic feet equivalent.

Proved developed is less than that.

We're at 65.6 proved developed.

Okay. 65.6%?

No, no.

Do you want a percent or do you want number?

Either.

Okay.

Sorry.

Jeff has got it right here.

Marshall, the proved developed reserves were 5.6 Tcf and proved undeveloped were 3.4.

And one last question on the Delaware basin shales.

I assume all of those wells will be vertical and will those be spread across the acreage or will you be concentrating in one area?

They won't all be vertical.

We will drill a series of horizontal wells.

We have done some horizontal work in the Barnett.

We've done some of the Woodford.

We're thinking about drilling wells that go horizontal in the Barnett and are vertical in the Woodford.

We're thinking about wells that will go horizontal in the Woodford or actually in the Mississippi and limestone above the Woodford, so lots of -- this is a huge area spread over 100 miles from northwest to southeast, and we will be trying a variety of different techniques across an area that stretches over 2 million acres and prospectivity of which we own about 700,000 net acres in that play.

Do you have a feel for horizontal costs versus the verticals?

We have got feel for it, it will be more expensive.

Right now the verticals we're thinking about, 5 to 6 million range, and then you can probably look at horizontals somewhere in the probably 6 to 8, something like that.

Okay.

Thank you very much.

Okay.

You're welcome.

Thank you.

Thank you.

We'll go next to David Tameron with Wachovia.

Hi.

Good morning.

Quick question.

The Fayetteville, looked like you raised your EUR from 1.4 to 1 .6.

Can you confirm that?

You talk about if you had overage, what's your production levels looking like?

What should we expect to see come mid-year and end of the year?

We're 10 million a day now.

We can confirm that we've moved to 1.6.

I know that I think southwestern is still at 1.4, but I would mention to you that we are drilling longer laterals than they are.

I think they have settled on about 2,500 feet as the ideal lateral length, and we are drilling 4,000 foot laterals, so just a difference of opinion there, and we do think that our longer laterals will, over time give us the opportunity to have EURs that hopefully will exceed 2 Bcfe.

That's actually been our average to date is 2.

Our kind of public number for anybody wanting to evaluate the play is 1.6 Bcfe, so if you think about us there at 1.4, and we're at 2, and their laterals are about 60% of our length, then it is more or less makes sense that we should be seeing more EURs per well than they are given our higher investment per well in the Fayetteville today.

Okay, Aubrey, and then are you -- you said you target a cost of 2.9 million.

Are you guys at that today?

We are when we don't do science, when we're not coring or not drilling pilot wells or where we have 3D to guide us, and so right now we're probably slightly over that, but I would say once we get kind of rolling that should be a number that we feel like is certainly achievable.

We've done a couple things to save some more money.

We've brought in spudder rigs that take us down to about 3,000 feet I guess, and then we turn it over to bigger rigs after that.

We're building our own lake out there for water supply which will cut down -- which all of our water will be piped in and out, so that will cut down tremendously on trucking costs, so there are a lot of things that we're doing that will enable us to continue to work costs down in this area.

Okay.

And if you had 10 million a day today, where would you expect to be end of year, 40 million?

I don't think we have a -- I think it will be more than that, but we don't give that information out publicly.

Okay.

That's fair.

And then rumor has it that you have drilled some horizontal wells up in the granite wash with some pretty nice rates.

Is there anything in common on it?

I am hearing numbers of 5 to 6 million a day horizontal up in the granite wash.

Well, since we're the largest producer of gas in the Granite wash and the Cherokee wash and the Colony wash and the Atoka wash, I can confirm all that is true.

We have been drilling horizontal Granite wash wells for better part of three years and have the largest leasehold position and the largest production position, so we have drilled some exciting new wells in the area, and a slightly different horizon than other people are targeting, and we will continue to push that program forward.

What I am hearing is probably in relation to some new wells that you drilled recently?

I would guess.

I am not sure.

Do you want to throw a number at me as to what you're hearing?

6 million a day.

We would not deny the existence of that possibility.

Okay.

All right.

Fair enough.

Thanks.

We'll take our next question from Wayne Andrews of Raymond James.

Hi.

This is probably a question for Aubrey.

I think most of my E&P questions have been answered but maybe some investors have expressed some concern over investments in non-E&P and you have tried to quantity the value there, but some would argue that those are lower margin businesses.

I would suggest that most of those have been related to directly tied to particularly under capitalized services that are required by Chesapeake to improve your overall cost and efficiencies of your E&P operations.

And then if you even consider final divestment of those businesses, maybe the returns get approach closer to E&P, but that's been something that I have heard fairly regularly and maybe I could get you, Aubrey, to comment on your philosophy in non-E&P investments, and then maybe some other areas that you're recognizing that could require additional capital?

I am going to let Marc answer the bulk of that.

From a philosophical perspective, we entered the drilling rig business in 2001 when we developed the notion that gas prices were structurally underpriced and that they were headed up for a long period of time.

We were right about that.

We were going to be short of people, and we were going to be short of lengths and we were going to be short of rigs, and so we set about to make sure that there would not be any chuck points in our -- in the ability for Chesapeake to execute its business plan, and what developed as a plan to serve as a hedge against rising service costs has actually worked out to create numerous operational advantages as our rigs routinely do better than rigs that are owned by other companies, and it should make sense.

These are our employees working on our rigs, and these are rigs were built for our needs and purposes and so an integrated operation should always be more efficient than one that tries to tie together disparate companies that own disparate assets.

In terms of the returns associated with that, I am pretty proud of our returns to date.

Our first move in the rig business ten years ago on a $10 million investment we ended up selling it for $90 million, and our Pioneer investment, Marc, we had how much in it?

Well, we gained 115 million on total revenues of 159 million, so we had about 40 something million invested in it.

Of the 3:1 return.

Yes.

Today Marc talked to you about a drilling rig business that is worth at least $1 billion, and we have less than 500 million in it.

I will turn it to Marc to talk more about some of the returns that he sees associated with these businesses.

We get that question a lot, and I am always a little puzzled at the question because the returns -- I dispute that the returns are less than what our core business returns are.

We drill 130 different wells at a time right now, all of which have differing rates of return, finding costs, et cetera, some with low finding costs, longer payouts, lesser rates of return, some with very high rates of return, but short life and a little higher finding costs.

We're in the compression business.

It carries returns to us that are complete payouts in three years against rented equipment on assets that will last 50 years properly maintained, and we have a unending need for new compression and continued compression in our business, and I guess our compression equipment on a horsepower basis now would be the fifth or sixth largest compression business.

If we wanted to monetize that we could do that and probably pull out 3:1 on our investment easily that we have today.

Trucking and drilling rigs we've already talked about.

When you're drilling 1,500 wells a year to 2,000 or even 2,500 wells a year, and you have decades of inventory as Aubrey mentioned operationally it is great but financially those could be monetized for two or three times our investment.

We're thoughtfully integrating in areas where we have foreseeable needs that are unending on assets that don't deplete and any of those can and will at the right time need monetized if we think it is better than owning it ourselves.

The return question, though, I think is not -- it is just unfounded that the returns are not adequate to our business and certainly much greater than our capital costs.

Virtually all of these, Wayne, Chesapeake was going to create substantial equity value anyway, and so our view was why not capture that equity value for our own shareholders.

You see that with our Eagle Energy subsidiary or investment where we own a third of a gas marketing company that's I guess become a top 10 gas marketer in America.

Valued at nearly $400 million now.

Our investment base in that?

36 million.

36 million.

We helped create that business with the principles of Dynegy, that investment will be monetized at some date, and probably 2007 for a very substantial gain.

Same with our investment in Fractech, and we were going to -- we felt like we were going to drive equity value creation there, so why not capture that for our own investors, and I think that's been a strategy that's worked very well today.

Excellent response.

Thank you.

By the way, Wayne, those total numbers that we think those businesses are worth is about $2.5 billion.

It is about $5 a share.

That goes to answering Marc's rhetorical question of what type of business do we think is least well understood.

He would argue it is that $5.

I might argue it is the $15 or $20 in our risked upside reserves that I don't think we get value for because we're in all of these plays rather than being a single play company which the market seems to be willing to value differently than a company that has a collection of leading positions in all the important plays in the U.S.

Right.

Plenty of opportunity there.

Thank you.

Yes, sir.

Thank you, Wayne.

We'll go next to Brian Singer with Goldman Sachs.

Good morning.

Good morning, Brian.

Wanted to ask an Appalachia question here.

You highlighted in your opening comments the increase in resource potential, unbooked resource potential.

Can you talk more specifically about what drove that between the third quarter and the fourth quarter and are you assuming anything from the deep well that you mentioned was an encouraging discovery?

What specifically is new that's made your outlook a little more rosy?

Brian, this is Aubrey.

I can talk about it, but I am going to choose not to.

We are not going to be as chatty as some of our colleagues have been in that area, and again we are still building our team there and still building our leasehold position, so my line or my -- what I hope our competitors in the industry are saying, because Appalachia continues to be the overworked low return area that people have assumed it to be for decades, and we have a different opinion of it, but we'll keep the specifics of that opinion to ourselves for now.

I guess should we expect another couple quarters of upward revisions to your unbooked resource without shall we say more specific explanation for what's driving that?

Probably.

You can anticipate that, and that is something that you can probably anticipate across a number of our plays where there is just no reason at this point to be giving away trade secrets to the rest of the industry.

Okay.

Switching to Hailey, somewhat of the opposite, looked like there was a little bit of a decrease in both in the PUDs and in the unbooked resource.

Could you talk about what you're seeing there?

We're still making progress there, but unfortunately we still have a wide variety of outcomes.

It is binary.

We drill some wells that are 2 to 4 million cubic feet a day of IP which is really not what we're trying to achieve.

What we're trying to achieve is somewhere first month production of say 6 to 8 million so we can get 6 Bcfe.

Our most recent well is an exceptionally strong well.

It is making 32 or 33 million a day right now, so we continue to be intrigued by the upside.

That would be our second 30 million plus per day well, and we are confident that through further drilling and further scientific analysis, further geological analysis that we will get to a point where we can more routinely drill good wells.

The challenge is we're trying to HVP a lot of acreage, too, and we're drilling these wells 1 per every 640 acres.

It is a very different operation than in the Barnett for example where you're drilling wells every 500 feet.

There is just not much variety in the rock over 500 feet over ten times that amount,1,280 feet you can get a lot of geological variety there, so we'll remain active in the area.

Steve, we have how many rigs there is now?

Seven.

Seven rigs.

We also have a bone springs play, oil play that's developing in the area that we have hopes for, so Hailey can -- it remains an area of intrigue for us an enormous amount of upside, and we've just got to get a little further up the learning curve on how to drill more 30 million a day wells, and fewer 3 million a day wells.

Thank you.

Thank you.

We'll go next to Ray Deacon with BMO Capital Markets.

Hey, Aubrey, I was wondering if you had a comparable number for the 18 Tcf risk captured potential a year ago, I guess?

Well, I bet my colleague Jeff Mobley can come up with that.

Give me one second.

Any other questions, Ray, while he kinds of--?

Sure.

Just if if you have got a ballpark number for what you think development costs would would be associated with that potential, and I guess the other question would be you mentioned on your last call that your operated rig count at 2006 doubled, and I would assume that as you continue to focus more on the same plays, there may be some -- I guess what do you see as the trend in F&D costs?

Would you expect that to go down as a result of efficiencies, having the same crews and the same equipment?

I think there are two drivers that can likely give us lower finding costs in '07 than in '06.

The first is the unit cost declines that Marc and I both talked about earlier in the call where we expect our unit costs to decline by as much as 10 to 15% this year, assuming gas prices remain where they are, if you get $9 to $10 gas somehow this summer then that probably goes out the window.

The other thing we will -- that is working to reduce costs is the efficiencies that you talked about, and as we get better and better and as plays like the Fayetteville and plays like Hailey and as plays like Delaware become less experimental and more of a manufacturing type operation, then I think you will see those efficiencies deliver us lower costs as well.

So again I really look at 2007 for Chesapeake as a golden year for value creation because of the amount of revenue that we have locked in through our hedges both existing and closed, and through the cost trends that we're already seeing here at the beginning of the year.

Jeff has on -- by the way, just to alert everybody on the call, we've posted a new slide show yesterday afternoon which introduces our new corporate logo as well, and this slide show has been pretty much completely reworked and offers a lot of new information for you, and I hope you have time to take a look at it.

On page 4 of that presentation we do contrast where we were a year ago on those numbers that you asked for, Ray, versus where we are today, and I will let Jeff give them to you.

Yes, Ray, just to remind you that last year's proved reserves increased 19% from 7.5 Tcf to 9 Tcf, our risked unproved reserves increased from 8.5 Tcf to 17.7 Tcf, so a near doubling, and our unrisked reserves increased from 37 Tcf to 71 Tcf, about a 92% increase.

Okay.

Got it, thanks, Jeff.

Directly related to the enormous amount of acreage we captured last year and the further maturation of some plays including the Barnett and Fayetteville.

Great.

Great.

Can I ask Marc one more question?

I guess I was looking at the -- you talked about the dollar with the closing out of the 2000 hedges on gas basically you realized a dollar gain, so is -- from an economic standpoint essentially this year you're going to -- you will have received $1 higher than that $8.63 hedge price that you have got in place for this year?

That's correct.

Great.

Thanks, Marc.

It will be booked or reflected in the production month that we hedged for in the income statement, so if we pulled the hedge off in September of '06 for July of '07 in July of '07 it will be reflected as increased revenue per unit in July of '07.

Got it.

Got it.

Thanks.

Thank you.

We'll go next to Tom Gardner with Simmons and Company.

Good morning, guys, this is actually Dave Kistler.

Hi, Dave.

How are you doing?

Good.

As part of your hedging program you guys have about 146 Bcf that fall into a knockout clause at around 650ish.

Yes, sir.

While your hedges have gone up, that actually reflects kind of bullish to me that your view is that prices stay above the 6.50 range.

Can you give us a little color on that and can you also take a little bit of time to talk about your macro view?

I didn't catch that at the beginning.

Okay.

I will take the first part of that and Aubrey is our macro guru, so the knockout provisions that we have used along with three-ways and calls and other inventory of hedging strategy exactly reflect what you indicated which is a more bullish view on the fact that, or our belief that gas is unlikely to be below 6 or $6.50, and actually it is all over the board.

We have some 5.50, 5.75, $6 knockouts.

The way those work for some of you on the line that may not know this, is simply we are selling volatility in the form of a put to increase our strike price for the swap.

So if gas on the last day of the settlement month closes let's say below $6, then we do not receive the swap value for that, and it is as if we never hedged, but for that we've received a premium for volatility, and our swap price is as much as $1 higher than we could otherwise receive, and that's reflected in the realizations and some people have called Jeff or I and said gosh, how did you ever swap gas at that high level?

Well, it is because we have either sold calls or sold puts in the form of the knockouts, and what we're really doing is capturing that volatility that we have the availability of because we have a long stream of natural gas that we're long and the market's willing to pay us for that in the form of increased realization.

So it does imply and in fact it exactly reflects our view that gas is unlikely to spend much if any time below $6 or 6.50.

We recently recapped all of the knockouts that we've done since 2002, and we had received approximately $115 million of incremental premium for entering into knockouts, and there were two months during that entire stretch where we got knocked out of our swap and did not realize the money, and that cost us $8 million in swap value, so to us it is a 12:1 return on entering into those kind of positions over five years that we've been able to capture incremental value for the Company.

Aubrey, is there something I missed there?

No.

Other than I just wanted to emphasize also that how the knockouts work, it is on one day of the month, either the final settlement day or the penultimate settlement day.

Just because there are times during the month when gas prices might plunge, it has to be on a specific day and for the hedge to be ineffective for the whole year it has to be on twelve days out of 222 or 225 trading days.

The odds of that are remarkably low in our view and our experience has shown that we've been knocked out twice out of the last 60 months.

Again it would show that we're good at choosing the right levels, and also we understand fundamentals of the gas markets well enough to know that gas prices below certain levels and certain years are frankly not sustainable and our view is right now those levels are around $6 an Mcf.

We certainly have benefited by what's happened in the weather market in the last 30 days as well which we think has taken away a great deal of the risk associated with these knockouts in 2007.

Then I guess I was -- okay.

So if Marc is the tactician here on the gas markets I guess I am the strategist and Jeff is a nice blend of both of those skills.

I think what we talked about in the fall with you all was that we felt like that by the end of January we would see a year-over-year storage deficit appear.

What we missed is that -- in September we actually thought that would be by the end of December, and then we got the exceptionally warm weather in December, and obviously the spare set in about whether or not it will ever be cold again in our country.

So we missed it by six weeks or so and today we have deficit for the first time since late '05, and I believe it will be a rather persistent deficit this year, so I think the market is set to have some excitement to the upside from here on, dampened by the potential increase in LNG imports, but we're already seeing around the world that there is a lot of demand for natural gas.

Remember, the U.S. consumes about 60 Bcf of gas a day.

The world consumes 275 Bcf of gas and demand for gas around the world has been increasing about 2.7% per year.

That's 8.5% Bcf per day of demand increase every day in the world, and we don't see the liquefaction facilities coming on line at 8.5 Bcf per day per year add infinitum into the future.

We actually think the world gas market rather than being awash in LNG will actually be short LNG in some years to come.

We've always been happier when we've had contrarian opinions on things and find ourselves having some of those contrarian thoughts today.

My final thought is it is remarkable to me how the risk has been taken away from gas markets in 2007 and how healthy gas markets are today and E&P stocks have done nothing.

I think E&P stocks today probably today represent the best buying opportunity I probably have seen in the last three or four years.

Don't know, don't understand why, but can only point to the disengagement between where the strip is and where E&P values are, particularly our own company.

Great.

Thanks.

Also following up on that a little bit, yourself and many of the other public companies have been talking about year-over-year production growth going forward of 10% plus, yet we see kind of forecasts or as we work through things the natural gas market that looks to be increasing production marginally at best in the U.S.

Can you kind of help me put those two pieces together?

I will try.

The first thing is a lot of the companies won't make those forecasts.

You can count on that, I think.

The second thing, the majors will continue to decline at probably 5% per year which has been a pretty standard number for them, in fact if you go back over the last five years the five majors collectively on average have lost as a group a Bcf per day and so we really don't see that changing very much as they have no ability that we're aware of to turn around the production declines in the U.S.

The third factor is the non-public companies, and I view that going forward those companies are increasingly at a technological disadvantage to the public companies and I would be surprised if their production ramp-up can keep pace with the public companies.

Great.

Finally, one last thing, just looking at the price related negative reserve revisions in your press release, can you talk specifically about what areas were affected the most, and obviously this is impacted just by, as you highlighted before pricing set on one specific day, so--.

Keep in mind all those gases are now kind of back on the books.

Exactly.

At today's prices.

Rather than spend time delving into the exact geography, you can just basically assume across the Company we would lose reserves when gas prices go to 5.50 or whatever they were at 12/31.

The reserves that are most affected are the longest lived reserves because your economic value is truncated on those reserves which quantitatively is a greater percentage than the shorter-life reserves at lower prices.

Obviously Appalachia and longer-lived reserves at a $5.64 level is going to be effected more than a Gulf Coast reserve that might have a half life of three or four years.

Present value virtually doesn't change because you're truncating reserves 30 or 40 years from now and the present value of that is probably less than 1%.

Well, that's it for me.

Thank you so much, guys.

Thanks for your questions.

Thank you.

We'll go next to Gil Yang with Citigroup.

Aubrey, can you comment on what your geologists are seeing in terms of the difference between the Fayetteville and the Barnett that is inducing you to drill the longer laterals?

I'll let -- Mark Lester, are you with us?

I am.

Do you want to take that question for us?

The difference between the Fayetteville and the Barnett and as to why perhaps we're drilling longer laterals in the Fayetteville than say Southwestern is?

Well, I think a lot of that is on the completion side we're able to stage complete those.

Therefore we're able to stimulate our beyond 2,500 and 3,000 feet in those we wills, so I think a lot of it is really geologically the gas is there, and if we can expose more rock to the well bore, then -- and get that stimulated, then we're going to have better performance.

I think the key is in the completion part, being able to stimulate the further length of the well bore.

For the lateral that's 4,000 people, and how many stages of stimulation are you doing, using and are you doing slick water or something else?

Primarily slick water fracs and we're doing generally four to five stages.

I think for awhile Southwestern went away from slick water to a gelled or cross-line gel frac and I think it is our understanding that they moved back to slick water where our analysis of their EURs was that the cross-link gels were not performing as well as the slick water.

So it is the same answer for the Barnett.

We drill 3,500 to 4,000 foot laterals there, and your constraint is sometimes an engineering constraint in terms of being able to drill out a certain length you run the risk of twist-offs and things like that once you get beyond a certain length.

Also you just run into the practical realities of spacing units in Arkansas if we're drilling on 640 acre well and drilling them with an orientation of Northwest to Southeast so there is just a practical limit to how long the wells can be and we're going to, in the corners of the sections if you can imagine that with your mind's eye we might be drilling a few 2,500 foot wells, but for the most part in the heart of the section we'll be drilling 3,500 to 4,000 foot laterals spaced about 560 feet apart compared to about 500 feet apart in the Fort Worth Barnett.

That will give us about 8 wells a section we believe in the Fayetteville.

Okay.

Aubrey, can you just comment on where the 3 Bcf wells that you're seeing are in the grand scheme of your acreage there?

Did you say where are they?

Right.

We're probably not going to get that granular with the data, but our area of most wells so far is our Little Creek area, and so you can just kind of assume they might be in that area.

We're getting ready to finish -- well, I think we finished shooting -- Marc, how big is our 3D shoot in Little Creek.

Little Creek 3D is 140 squares, we finished the North half and have that data in, the South half will be out in mid-April.

That will really help us stay away from faults, and also help us find some up hole reserves, we have made a nice discovery in a hail sound lately, and I think through my conversations with Harold Correl at Southwestern, I think that they are enthusiastic about Pennsylvania and other opportunities as well, Pennsylvania and Rochester.

Obviously, shallower above the Fayetteville.

So there will be some serendipity here as we evaluate our 3D and see things that can't be seen just drilling blindly into the Fayetteville.

Aubrey, last question is sort of a strategic one.

Obviously the ownership of the rigs has done some good things for the Company, but it seems like everyone today talks about having these new fit for purpose rigs that allow them to do things more efficiently.

Do you run the risk of owning rigs that become obsolete in terms of technology and how do you deal with that?

Well, I think we were actually a first mover in building fit for purpose rigs.

The rigs that we have built for our account were built the way Chesapeake wanted them to be built.

We built them for plays like Sahara, we built them for plays like the Barnett and we built them for plays like the Fayetteville.

There was no need really for us to advertise the concept of built for purpose because we're not a public rig company, but that's exactly what we started to do three years ago, and feel like we were a first mover and realizing that the advantages of if we're the only guys ever going to use this rig then we're going to build it exactly the way we want it to be built.

If you're a public company drilling contractor, you've got to build a rig that compromises in a lot of areas because you got to build it to appeal to the largest number of customers where as we only have one customer, so we're very much in favor of fit for purpose rigs and have been building them for years.

Are you confident that the technology doesn't evolve that quickly, that the fit for purpose of three years ago isn't obsolete five years later?

I am confident that we will remain at the cutting edge of all technological developments in the E&P and drilling industry.

Okay.

Thank you.

Good.

Thanks.

Thank you.

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

I promise to not let you go over the hour-and-a-half mark.

Dan, I don't think that's going to be possible.

There is nine more in the queue.

We're right here with you, Dan.

One quick thought back to kind of strategy in acquisitions.

Your position in Chapparel, with Chapparel being a tertiary oil player, does that indicate more interest in building more exposure to oil production?

Sure.

If you gave me the chance to own 1.5 billion barrels of oil in the U.S. that could be delivered at the same rates that our 9 Tcfe of gas could be delivered, I would choose oil.

First of all, I would get an 8:1 conversion rather than a 6:1 conversion, but just looking around the world and looking at production issues in Mexico and Iran and looking at Iraq and looking consumption trends around the world, we're very bullish oil.

Problem is we can't find, if we're finding 1.5 Tcf of gas this year through the drill bit, that's 215 million barrels of oil.

I can't find that, and so on occasion, though, we will find some oil plays.

We do have 9% of our reduction that's oil and we would like to expand that, and we thought Chapparel had a very interesting approach to tertiary oil recovery in Oklahoma, and we felt like if properly capitalized they had the opportunity to really tie-down some first mover advantages and bringing Co2 to oilfields in Oklahoma, and something that we didn't anticipate and I am not sure they did initially although they reacted to it very quickly thereafter was the huge buildout of the ethanol plants in southwestern Kansas and northwestern Oklahoma, and besides ethanol those plants kick out as their second biggest product that will be carbon dioxide, and nobody is really focused on that right now, but if you can take that carbon dioxide and than vent it through the atmosphere and put it down into an aging oilfield, then we think that's a real win-win, and that's why the main reason why we put our money to work in Chapparel.

Thanks.

Thank you.

We'll go next to David Khani with Friedman Billings Ramsey.

This is Andrew Coleman.

I just had a couple quick questions for you.

There was a question earlier about the deep Haley and that the PUD and upside reserves gone down.

Could you -- I guess similarly look at the Ark-La-Tex, looks like there was a similar decline there.

Is there any well performance issues out there or can you comment on that?

Jeff, is the keeper of that particular spreadsheet, so I will let him address that.

On the Ark-La-Tex I think we're still expecting 1 Bcf there, we did increase the cost from 1.6 to 1.7 million per well.

But did your acreage go down?

It was the acreage that changed.

You're talking about the number of reserves in the area that went down.

The overall assumptions didn't change.

I think that some of the acreage that we moved--.

Moved the deep Bossier.

That's right.

It is the categorization on which part of the play.

Looking at also when I look at the Delaware basin shells, acres went down a little bit there.

Is that lease expiration or just consolidating your holdings out there?

That was really from all of the JVs that we had done getting the correct net number entered in the system.

Okay.

That number is 670,000 net acres, is that right?

Right.

And then can you comment at all the PV 10, the underlying assumptions there?

It looks like by my math that probably both your future production costs and future development costs probably declined relative to where they were last year.

Is that an accurate assessment?

David, I don't think that could be possibly true.

Our future development costs I know have boosted significantly, and future operational costs could only have gone down as a percentage of ad valorem taxes that would be related to the revenue, so I don't have the exact number in front.

Steve, do you have the--?

You're talking about pud costs and, Andrew, what are you referring to again?

Just the total PV-10 that came to 10 billion, and just kind of looking out the top line prices that you guys put out there of 541,5625, it implies something like 51 billion cash inflow.

Just as I try to net those down to get to the 10 billion it just looks like it kind of changes.

Year-over-year our operating and costs assumptions embedded in our reserve report we want up as did our future development costs and that would account for the reduction in apples-to-apples year-over-year PV-10 comparison.

And the last question is I guess since we've been comparing shales here for the last 30 minutes, could you just log in your opinion on what the Caney Woodford looks like relative to the other Woodfords and the Fayetteville and the Barnetts?

We have a rig running in the Woodford.

The Caney really hasn't developed and just to make sure everybody is on the same page, the Caney is the Oklahoma name for the Fayetteville Shale, and so the Caney and the Fayetteville are the geologically equivalent of the Barnett.

The Woodford is generally called the Woodford off the play except when you get into Arkansas and Mississippi and Alabama it is called the Chattanooga.

Using that as a reference, the Southeastern Oklahoma Woodford play is one we continue to participate in and I think we're in virtually every well that Devon or Newfield drills in the area.

We have one rig going ourselves.

Our evaluation of the play to date is that average reserves EURs are 1.8 to 2 Bcfe across the entire play, and we have information on roughly 75% of the wells that have been drilled and our information database is 75 -- actually 75 wells are producing of which Chesapeake has a interest in 64 of those.

Our view is that over time these reserve estimates will go up, and that's why our pro forma is for 2.2 Bcfe for $4 million of drilling.

To date average well costs for the first 75 wells is approximately $5 million.

There has been talk about wells being drilled at $3 million, that is talk at this point, so we're hopeful that it will continue to be a play that gets better over time, but right now for $5 million -- to spend $5 million to find 1.8 to 2.0 Bcf is not very competitive with other places where we have to spend money, but our pro forma is that the play will get marginally better.

Costs will come down, and we think we can make it work at 2.2 Bcfe found for $4 million.

We have 100 thousand net acres in the play which Jeff gives us how many unrisked reserves?

I don't have it in front of me.

519 Bcf.

Of unrisked.

Unrisked is Tcf and then we've risked our acreage there by 50%, so that's where you get to an unrisked basis of half a Tcf.

Hope that helps.

Thank you.

Thank you very much.

We'll go next to Chris Edmonds of ERC Partners.

Hello, Chris.

How are you?

Good, thanks.

How about you, sir?

A couple of quick questions.

Can you just talk, Aubrey, a little bit about the progress with EnerGen and the Black Warrior and what your plans are this year and what the science is showing?

Just to remind everybody last fall we entered into a 50/50 statewide AMI with the highly regarded EnerGen Resources out of Birmingham, and we're looking at the Conasauga shale there, we're looking at the Floyd, and we're looking at the Chattanooga.

So I think as most people know Dominion had drilled some wells in the area to the Conasauga.

One of them tested a high right of gas and we're working to start drilling our first wells in there, Steve--?

It will be Conasauga Shale.

We'll start drilling for the Conasauga in second quarter of 2007.

Any idea of number of wells this year?

And I assume they will all be focused, or at least mostly focused in the area that EnerGen and Dominion developed Northeast of where everybody else is looking?

I think we'll probably drill some in different places along the play, but there is still some acreage capture that is occurring as we speak, and so play kind of runs through the heart of Birmingham and I think most of the drilling will take place to the Northeast in the Canoe Creek area ad that is where the acreage play is probably most mature.

We're eager to get underway, and I think EnerGen is eager to get underway and we'll see what we've got there.

Then moving to the Bossier in East Texas you have acquired independently of the GasStar investment a significant amount of acreage.

Can you talk a little bit about what you plan to do there this year sort of independently and then how the GasStar JV is progressing?

I will take the second part and let Steve take the first part.

The joint venture is progressing just fine.

We have an equity interest in the Company, I guess, today of about 17%, I believe, and they are drilling -- I think they have got three rigs working right now, and so we have I believe one rig, is that right, Steve?

So our plan is to continue to test the area.

We're actually complete willing our first deep Bossier well right now as we speak.

We're very optimistic about the opportunities for the deep Bossier.

There have been numerous wells come in drilled by Encana and Burlington and others at 20 to 30 million cubic feet a day, so we hope to achieve that through the GasStar well as well as our own drilling.

There are other interesting plays in the area, some horizontal opportunities that have turned out to be really nice, are not quite as deep as the deep Bossier.

Steve, is there anything you want to offer on the--?

A couple 3Ds being shot now that we're waiting on and we'll add a couple rigs later in the year.

That's an important point.

All of this drilling to date has been done on 2D work, so to drill kind of blindly to 20,000 feet without 3D is not something we really like to do, so we're very -- we've been real cautious here until we get our 3D in and can be a little more particular about where we drill these wells?

Good.

Then, Marc, you made a comment about gains from sales of either public or private investments you have made through the year.

Can you just elaborate on that a little bit?

Again, what was the number you expect this year and what your criteria will be in examining and determining what goes, what stays?

Sure.

Basically I think we're like most people, almost everything that we have is for sale at the right price.

The number I mentioned was 100 million.

We gained 115 million from Pioneer.

I think we'll at least do that this year we, have a couple things that we're looking at exiting right now.

The criteria is constant evaluation just like our hedging program of the factors that you would expect, what's the market, what is our anticipation for market increases or decreases.

We exited Pioneer at the time when we thought it was likely based on what Aubrey talked about earlier that service prices were likely flattening or headed lower, and that turned out to be a pretty good evaluation of the exit timing there.

It is obviously buyer demand as well.

We mentioned Eagle Energy as being an asset that we have owned for several years, and that company has really performed tremendously.

It is one of the top physical marketers now in the country, and I think that there is demand for that from a number of sources, so without revealing specific strategies, I look for some north of $100 million gains again this year.

Very good.

Thanks, fellows.

Thank you.

Thank you.

Next to [Eric Schlein] with NSL Capital.

Hi, Aubrey, good morning.

Good morning.

I got a quick question.

I know you talk a lot about the net asset value of the Company.

I was just curious if you can give me a brief breakdown of the net asset value in regards to the hedges and proven and unproven reserves.

I think we can do that.

We got a slide that's -- what page are we on?

It is on page 40.

Eric, once again we recommend that you go to our slide show, page 40 of that slide show details at various price decks each one of the components of our net asset value.

All right.

I am actually not at the computer right now.

What are you currently predicting the net asset value as of now?

It depends on what price deck you use.

What you will see is $7 we calculate NAV at 44.08 a share and at $8 on a gas price strip of 56.11.

We give you five other possibilities to look at on that slide, and I encourage you to find a computer and get on slide number 40.

All right.

Just let me make one comment too, that I am a wicked pumped about the future of this company.

I appreciate being a shareholder.

I appreciate that, and no one has ever in my life told me that they were wicked pumped about anything I was doing so that's a first.

I feel very complimented by that.

Thank you, Eric, appreciate it.

No problem.

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

Hey, Kelly.

Can you top that?

I guess he didn't.

Your line is open.

I think we are going to need to move on.

All right.

We'll go next to Eric Kalamaras with Wachovia.

Good morning, Aubrey, no I can't top that, although I would love to.

Question for you.

I can kind of buy into the maintaining the 2007 capital spending guidance.

Thoughts into '08 given your thoughts on gas pricing reaching higher peaks than we have in the past, I understand the manufacturing strategy that you're trying to employ.

Is it achievable by '08 to continue to look at relatively flat F&E costs going forward?

I think it is.

I think it is predicated on something that we are seeing every day and I see no reason for it to stop, which is the continued buildout of the service industry infrastructure.

The service industry is incredibly liquid right now, balance sheet is in great shape, very profitable returns on incremental investments that they're making.

So I see no trend that I'm aware of that would lead to service and the three to stop reinvesting in the growth of their own enterprise.

One of the things that's really going to become more self evident I guess is the value of our strategy of having made the investments in acreage which obviously that investment sunk and fixed, won't go up in terms of price.

The rig that we've invested in are going to constitute the majority of our total rig counted.

That's essentially a fixed price which won't be changing.

Our compression business, our trucking, all of which is already a sunk cost I guess from a negative standpoint, but it allows us to have a long-term view of relatively fixed prices that we'll benefit rom.

Sure.

Great.

Marc, a little bit of housekeeping question.

On the changes in FAS 69, do you have the E&D number?

The what number?

The extension and discovery number in the changes?

Yes, I do.

There is a complete reconciliation of those reserves, and I am going to have to just flip to it.

I don't have it off the top of my tongue.

Extensions and discoveries were 828.6 Bcf equivalent, Bcfe.

I am sorry, I am specifically thinking of the changes in the discounted cash flow off the E&D line.

That would be in FAS 69, right?

Do you guys have that completed yet?

I do have it.

I don't have it in front of me.

We'll be filing our 10-K next week.

I just don't have it in front of me.

No worries.

Thank you.

Okay.

Next.

Thank you.

We'll go next to Joe Allman with JPMorgan.

Good morning, everybody.

Hey, Joe.

Could you talk about West Texas a little bit?

How many wells have you drilled to date out there and what have your results been so far?

When you talk about West Texas, I assume you're talking about the Delaware shale as opposed to deep Hailey.

Yes, I'm sorry, the Delaware shale.

There is a lot of proprietary information there that probably not going to get into, but let's just call it around a dozen wells, and let's call it kind of high side 2 Bcf that we've seen to date, and low side worse than that, so--.

Verticals.

Yes.

Mainly verticals although we have got a couple horizontals there as well.

Joe, it is tantalizing.

I can look at it half full and half empty, and half empty would tell me that, gosh, we've drilled some wells there, and I would love to be finding the three or four Bcf a well that I think we should be able to extract from recovery factors that we've seen in other shale plays, but we haven't seen that yet.

The half full is that this first dozen wells is a lot better than the first dozen wells, for example, drilled in Johnson County to try and develop the Fort Worth Barnett shale play.

It is just -- it is a big gas resource play, and I feel like we've got as good a chance as anybody else to try to make it profitable and all I can tell you is that if you're shareholder of the Company I don't think you have to buy anything, so -- or you don't have to pay anything for this play.

I think you got a free option on 55 Tcf of potential upside.

What's the reason for not being able to book any PUDs out there?

Well, because to book a PUD a PUD has to be profitable, and at 1 to 2 Bcf at 6 to $8 million you don't have profitability.

Got you.

Okay.

In the Fayetteville shale, what is it that has made you warm up to that play?

Is it really just simply the well results or is it kind of--?

It is just a bigger data set.

It is -- let me see what our data set looks like there, Joe.

We have drilled 19 horizontal wells to date.

We have got 14 reducing by our count.

Southwestern has drilled 237 wells.

That's probably a little low.

Their count obviously would be better, but we're in 90 of those 237 wells.

There are 126 producing wells that we can find so far to date, so it is just a matter of watching these curves, and any kind of shale play, the key element is what your B factor, or when do these wells go fend into a hyperbolic decline curve.

So we're now getting some pretty good links on some of these curves and we're now able to extrapolate better results than what we've seen to date and we're getting better at where we are positioning our well boards within the Fayetteville.

We've got such physics staff here that it has really helped us in terms of evaluating these plays, and we think our rock reservoir technology laboratory that we're building will also help us as we model frac jobs going forward and think about different preparation techniques.

All those things at the end of the day as we move shale drilling and completion technology across the various plays across this company should enable us to continue to develop better and better results in some of these plays and the Fayetteville should be no exception to that.

Are you seeing a difference -- I am sure you have seen Southwestern's decline curve.

Are you seeing a different decline curve?

Because it looks like their decline curve because it looks like their decline curve is more exponential than hyperbolic.

We don't have any dispute with the decline curve that they're using and we see it as a good fit to the wells they have drilled and the data that we have produced.

We are just seeing better results on our well simply because we have got more rock exposed on a per lateral basis, and I would suspect if for any reason they wanted to start drilling 3,500 or 4,000 foot laterals, we suspect that they would see the same kinds of enhanced reserves that we're seeing.

Got you.

Could you comment on the infrastructure needs out there if you're going to ramp this up in a big way, what do you need to do out there infrastructure wise and then can you also comment on the hail briefly, too?

Sure.

You need more of everything out there, Joe.

You need more people, you need more pipelines, you need more water, you need more service companies, but it is all coming.

We're building our operational base out of CIRSI.

I think Southwestern has chosen Conway.

I think it is good that we've chosen different towns and we'll have service industries probably build up around both of us, and so I think that will help, so I mentioned we're building a 40-acre lake out there that will help us meet the frac water issue, and it is all coming together and we have quite a bit of experience in large scale staffing large scale plays like this.

The second part of the question?

I think he asked about hail.

The hail sands.

Hail we've encountered really nice looking hail sands at relatively shallow depths, a couple thousand feet, some of it -- some of the tests have been wet, and some of have been productive, and so we're just learning how to integrate our stratographic and our structural models there to make sure that we anticipate correctly when we're going to get gas out of a good-looking log out of the hail.

Is the hail present throughout most of your acreage?

We've seen is pretty frequently.

We're pretty encouraged by at least in the Little Creek areas the upside potential of the hail.

Then just lastly on the Woodford Shale, there is a discrepancy obviously between sort of the costs that other operators have seen and what you're seeing today.

What would you attribute to that discrepancy?

Can you explain that in any way?

It is inexplicable to me.

We are in other people's wells.

We get their bills.

We total the bills up.

We know what the wells are costing, so the only thing I can imagine is that somebody is talking more prospectively and we're talking historically, and that's the only way I could attempt to resolve the difference from what we see on field reports and see in our bills versus what other folks are seeing.

Got you.

And expect the EURs to increase or you expect that your estimate of EURs will increase over time from the 1.8 to 2?

Any idea what they might go up to?

We're hoping they get to 2.2.

That's our goal.

Okay.

You're very generous with your time.

Thank you.

Thank you, Joe.

So are you if you're still around.

We're kind of trapped here, but we're happy if we have got any other questions.

We'll go next to [Monroe Helm] with CM Energy Partners.

Congratulations on three things, executing on your game plan, having the best hedging strategy, and now being in the Guiness' Book of World Records for longest E&P conference call.

Thank you, Monroe.

That might be a dubious achievement.

Tell he is what's on your mind today.

Was interested in your prospective on what you think the recoverable reserve potential is in the Trending River bottom play that you have versus what you are seeing in Johnson County.

In other words what do you think the recoverable reserves per well might be in that play versus the best total play you have right now?

I guess we saw the other day at somebody else's presentation that some of our wells are being talked about with EURs as high as 10 Bcf.

We can confirm that we have got some pretty strong wells in that area, and so what makes it better, I mean it is thicker.

Steve, any other thought characteristics you want to identify in that area?

There is a lot of gas many place.

It is thicker.

We need to drill some of our own wells up there.

Right.

We just brought on south of Fort Worth in Tarrant County just the other day, we just brought on a 5.2 million a day well, so we've always suspected that the better rock -- the rock got better and thicker as you got underneath Fort Worth, and so that's what we're seeing today, and we have not adjusted our EURs for this thickness because we need to see more information.

But right now we're at 2.45 Bcfe, Monroe for 500-foot wells with a 3,500 foot lateral in Northern Johnson and in Tarrant Counties.

We'll stick with that for now, but I think there is some reasonably considerable upside potential associated with that particular area.

Okay.

I would assume given your production pro forma, Barnett Shale for this year that most of the gas take away issues have been solved at this point in time.

They will remain an issue.

We have, Steve, how many wells do we have waiting on pipeline or completed at this point?

Close to 50?

40 something.

High 40's number of wells we're actually have drilled, are completing or waiting on pipeline, so we've got a bore underneath roads and railroads and buildings and there are issues there, but having stitched together an infrastructure that if you think about starting at DFW airport where we have gas outlet to the north, we have a gas outlet to the south, and then as you move south through the GM industrial complex there where Six Flags and GM are, and then you move West along the Trinity River Valley into Fort Worth and then you move south along I-35 and tie into the Crowley area.

We've got a really nice urban footprint there, and we've got some good right aways where we can get our gas out and our water in and out.

So we've got a team of guys that work very, very hard to get pipelines in and out of urban areas and I will just say that it is not easy, but we will get it done.

Okay.

One other one.

Those of us in North Texas have been enjoying your TV ads here lately.

What is that all about?

Is that just a local thing?

Our TV ads about our little company?

Yes.

Okay.

Those are intended to help establish Chesapeake's name in the Fort Worth area, certainly we -- people are going to see a lot of Chesapeake rigs in their back yards and neighborhoods, and we want people to have a favorable impression on our company, and we intend to make that impression both how we conduct our business, but also how we brand our business, and to do that you have to advertise out of Dallas, so a lot of Dallas people are getting to see those ads as well.

We've also introduced a new -- a modification of our logo to emphasize that we think natural gas is the solution to global warming, and kind of got a little more green in our logo than we've had in the past.

Okay.

Thanks for the answers.

All right, Monroe.

Thanks for the questions.

Thank you.

With no further questions I will turn the conference back over for any additional or closing remarks.

We're not going to talk for five more minutes.

We very much appreciate everybody having exhausted their questions and if you have further questions let us know today and thanks for your interest in our company.

Take care.

Bye-bye.

Thank you.

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

Central time running through March 8, at midnight Central time.

To access this, simply dial 1-719-457-0820 and use the pass code 3952942.

Thank you.

Have a good day.