Chesapeake Energy Corp (CHK) 2005 Q4 法說會逐字稿

Good day, everyone and welcome to this Chesapeake Energy fourth quarter 2005 conference call.

Today's call is being recorded.

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

Please go ahead, sir.

Actually, good morning.

This is Jeff Mobley.

Thank you for joining our 2005 fourth quarter and year-end 2005 earnings release conference call.

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

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

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

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

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

These are all non-GAAP financial measures.

Reconciliations to the comparable GAAP measures can be found on pages 16 through 19 of our press release issued yesterday.

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

Our prepared remarks this morning should last about 15 to 20 minutes, and then we'll move to Q&A.

Aubrey.

Thanks, Jeff.

And good morning to each of you.

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

Marc Rowland, our CFO;

Steve Dickson, our newly promoted COO;

Mark Lester, our Senior Vice President of Exploration; and finally we have a very special guest with us today, my good friend and Chesapeake's Co-founder, Tom Ward.

Tom announced his retirement from the Company as our President and COO two weeks ago but is consulting with us for the next six months so we thought it made sense to have him available to answer any questions you might have surrounding his retirement.

My comments today will focus on the words growth, value, and opportunity.

As I look back over a very successful 2005 for Chesapeake I keep returning to those three words as an excellent summary of what Chesapeake delivered to investors in 2005 and what we can continue delivering in the years ahead.

Most definitely we are first and foremost a company focused on growth.

However, that doesn't mean we don't also focus on returns.

For example in 2005 we increased our reserves per fully diluted share by 25%, our earnings per fully diluted share by 64%, and our operating cash flow per fully diluted share by 53%.

In addition, our return on average common equity employed during the year was 25%.

The market noted those achievements and during 2005 our stock price increased by 92% bringing our total return to shareholders since our IPO in 1993 to more than 2300%, for a compound annual stock price increase of 28%.

We believe this is the second best performance in the industry during the past 12 years.

As I look forward into 2006 and 2007 Chesapeake's remarkable growth should continue.

I anticipate that we can organically grow our production in proved reserves by 10% or so in 2006, and by another 7 to 10% in 2007.

In doing so, I believe we can increase our net asset value by at least 20% each year without ever making an acquisition.

You might ask, how can we be so sure of that NAV growth?

Well, it's actually pretty straightforward.

In 2006 we anticipate generating 3.7 billion in cash flow if gas prices stay about where they are today.

Keep in mind there's minimal risk to achieving that cash flow number because we are about 71% hedged for the year at an average NYMEX price of $9.43 per mcf.

So if we spend 3.1 billion of that cash flow through the drill bit to find gas in 2006 at no worse than $2.25 per mcfe, then we will find 1.4 tcfe while only producing about 42% of that amount.

That means we should be able to grow our proved reserves by about 800 bcfe or 11%.

We believe those newly discovered reserves will be worth about $2.8 billion and combined with our 500 million of excess cash flow overall NAV growth in 2006 should be about $3.3 billion, or about $7.50 per fully diluted share.

We think that is a very attractive return on a $30 stock especially when you consider that we have virtually no operational or commodity price risk to worry about this year.

This is also a good time to highlight our maintenance CapEx requirements.

In 2005, through both acquisitions and drilling, we developed reserves at an average of $1.74 per mcfe.

We produced 469 bcfe, so assuming all we wanted to do was tread water, we could have done that last year with CapEx of less than $850 million.

Looking forward that's only 23% of 2006 expected operating cash flow.

That must surely be among the lowest in the industry and reflects our lower than average decline rate and our excellent finding costs.

But I'd also like to include in this discussion about growth the consistency of Chesapeake's operational performance over time.

In 2006 we increased our production organically by 12% which is exactly what our five-year average has been which we believe is the highest in the large cap E&P sector.

When you consider the scale of our company today is almost five times bigger than it was five years ago I believe our 2005 performance of delivering 12% organic growth is even more remarkable.

I would also note that 2005 fourth quarter marked our 18th consecutive quarter of sequential production growth.

Next I'd like to discuss value.

Currently our proved reserves have a PV10 value of almost $21.5 billion using the five-year strip of 850 per mcf and $60 oil.

In addition we have 8.4 million net acres of leasehold on which we've identified 28,000 locations that we believe contain unproved reserves of almost 9 tcfe.

We believe these would be worth somewhere between 5 to $10 billion.

Further, we believe all of our other non-E&P assets have a value of about 1.5 billion.

So on what we believe is a pretty reasonable five year price deck the asset value that we have built for investors equals a range of between 28 to $33 billion.

After you subtract our debt, you have remaining shareholder value of somewhere between 21 to $26 billion, or about 48 to $60 per fully diluted share.

Over the years, our stock price has generally moved in tandem with the value that we create here, so I have no doubt about the market's ability to some day catch up to the steadily increasing intrinsic value that we have been creating for investors.

Next I'd like to talk about the word opportunity.

Much earlier than most companies, in fact, as far back as 1999 and 2000 Chesapeake's management team recognized the trends that have driven remarkable changes in oil and gas prices during the past six years.

Of course, it's one thing to identify a trend.

It's something different to seize on the opportunities that a trend creates.

Again, I believe earlier than most and more aggressively than most we have captured an enormous number of opportunities for our investors.

Keep in mind that the three building blocks of value creation in this business are people, land, and science.

During the past six years we have aggressively captured opportunities in each of these building block areas.

For example, before talented people became scarce in the industry we were snapping them up.

Before prospects in land became scarce, we built a system of prospect generation and leasehold acquisition that we believe is second to none in the industry.

Finally, when others were reluctant to invest in science and new ideas we jumped into every major gas resource play in America east of the Rockies.

While our aggressive investments in new leasehold and 3-D seismic have certainly been a drag on our finding costs and returns on capital during the past few years, today these very same investments provide Chesapeake with some very serious competitive advantages.

We have used your capital wisely to establish a premier onshore gas franchise that would be impossible to duplicate today and that for years to come should continue delivering growth, value, and opportunity.

I'd like to close by reminding you about another strength of our company, and that's risk mitigation.

My job, and this management team's job, is to create and deliver the highest risk adjusted returns possible for our investors.

Many times I believe investors don't fully appreciate how much risk there is in this industry and how well we have mitigated it at Chesapeake.

For example, in a year when gas prices could decline to below 6 or $7 per mcf we've hedged 71% of our gas production at $9.43 per mcf.

We've also hedged 36% of our 2007 gas production at $9.85 per mcf.

And have also hedged 22% of our 2008 gas production at 9.10 per mcf.

Additionally, in a time of great political unrest around the world, especially in those areas blessed, or cursed, as it sometimes seems with abundant oil and natural gas resources, the majors and many large independents face the prospect in many areas of the world of losing their assets over time to arbitrary tax and royalty changes, or even outright cancellation of their production sharing contracts.

Except for occasional chatter about a windfall profits tax Chesapeake's assets are safe from such political risk.

I might also add that Chesapeake's assets are all high and dry in a time of what appears to be an emerging cycle of greater hurricane activity in the Gulf of Mexico, I believe investors do not fully appreciate the very high risk profile their investments in the Gulf of Mexico may face in hurricane seasons to come.

Finally, I believe we're the only E&P company that has actively hedged its exposure to rising service industry costs through our rig building and investment program.

We have gains of at least 200 million in this program to date and the ownership of our own rigs is proving to be very helpful in acquisition is and in operations.

The risk of asset confiscation by some foreign potentate, or the risk of asset annihilation by rogue weather, or the risk of not having access to rigs to develop our assets are simply not risks that we wish to have exposure to.

That is why dollar for dollar we believe investors can achieve some of the very best risk adjusted returns in the industry right here at Chesapeake.

Before I wrap up, I thought you might be interested in where our operated rigs are currently drilling.

So I will give you the numbers by state and then by play description.

In Oklahoma we have 31 operated rigs.

In Texas 29 rigs, in New Mexico 4 rigs.

In Louisiana 4 rigs, in Arkansas 3 rigs.

In West Virginia 3 rigs.

And 1 rig each in North Dakota and Kentucky for a total of 76 operated rigs.

In addition we are a nonoperator in 84 rigs being used by others, giving Chesapeake access to more than 10% of all the new drilling information being generated every day in the U.S.

Just as more information makes you better investors, more information makes us better gas finders.

By play type we have 19 rigs in the Granite Wash, Cherokee Wash, Toca Wash, and Red Fork gas resource plays of the Anadarko basin.

We have 11 rigs in the Sahara gas resource play of northwest Oklahoma, 10 rigs in the Tight Sand gas resource plays in the Ark-La-Tex region. 8 rigs in the Permian Basin, including 4 in the Deep Haley area, 6 rigs in Dipota county in south Texas, 5 rigs in the Barnett Shale, 4 in the Arkoma basin, 2 rigs in the Fayetteville Shale, 4 rigs in the deep Anadarko Basin of western Oklahoma, 4 rigs in Appalachia, 3 rigs in the Bray, Cement, and Golden Trend areas of southern Oklahoma, and 2 rigs along the Gulf Coast.

During the remainder of 2006 we expect our operator rig count to move up to 100 or so as we continue to take delivery of additional drilling rigs.

I will conclude by reminding you that I believe Chesapeake today offers a truly unique investment opportunity.

We have captured visible, sustainable, high level profitable growth for years to come at a very attractive present day valuation.

I appreciate the investments many of you have made alongside my own and look forward to continuing to create significant value for you in the years ahead.

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

Thanks, Aubrey, and welcome everyone we won't consume any of your time this morning reviewing data that's already been exhaustively presented in our press release.

I would like to begin by reminding you that by next Monday at the latest a new PowerPoint presentation will be posted on our website.

Jeff Mobley has done a great job in packing this presentation with a lot of very good and new material.

All of the numbers including our projections for 2006 and 2007 at various gas prices have been updated for actual 2005 numbers, our recent acquisitions and financing activity and our hedges.

Couple of areas I'd like to focus on this morning.

First, everyone is aware of the large amount of oil field inflation that all in this sector are being hit with.

It's probably one of the most frequently asked questions to our management team.

However, in 2005, Chesapeake's total cash operating costs were just $1.82 per mcfe produced.

Including preferred dividends, interest expense, G&A costs, production taxes, and lifting costs.

Yes that is up from $1.28 in 1999.

But our realized price of 6.90 per mcfe gave us a 2005 record net cash operating margin of $5.08 per mcfe produced.

With all in cash F&D costs, including significant investment in acreage and seismic for the future, of just $2.30, much of which the value won't be realized until well in the future, we have a reinvestable cash margin of $2.78 above maintenance CapEx.

It's a different way of looking at the very rosy outlook for risk-free growth that Aubrey discussed, but the bottom line is while costs have expanded, our margins have expanded more and are now at record levels.

We're very proud of the reserve position in the Company.

Terrific reserve adds at a reasonable cost with positive performance revisions for the fourth straight year.

Reserves per fully diluted share increased 25% in 2005 and have increased at a 17% annualized rate since 2001.

All while debt per mcfe has held steady.

The value of each mcfe has increased substantially and the unproved reserve position now exceeds proved reserves in this company.

Our RP position has also continued to lengthen and is now 13 on a forward looking basis and 16 years on a backward looking basis.

The wisdom of our investment in Appalachia was certainly evident in November and December results.

Our realized price in the fourth quarter excluding Appalachia production was $9.85 per mcf.

Our Appalachian gas sales were $13.76.

The btu content and the positive basis differentials of Appalachia make those molecules significantly more profitable and valuable to Chesapeake.

A few housekeeping notes.

We will then wrap up.

During 2005, Chesapeake made 20 acquisitions greater than $10 million ranging from 10 million to 2.9 billion.

We reduced 2003 series 5 preferred stock and our 4 and 1/8 preferred stocks by $294 million during the year converting those into common stock.

We grew our book common equity by $1.926 billion during the year.

We capitalized interest costs in the fourth quarter of $24.2 million and $79 million for the entire year.

Other internal costs, primarily G&A, related to our extensive drilling program, caused us to capitalize 26.9 million of those costs in Q4 and $102.2 million during the year.

One note on our outlook that we released with the press release.

Our effective book tax rate has gone up slightly to 38%, but I would point out that all of that expense remains projected to be deferred.

We paid no cash income taxes in 2005 and our current estimates are to pay no cash income taxes in 2006 or 2007.

With that, moderator, we're prepared to take any questions.

Thank you. [OPERATOR INSTRUCTIONS] We'll go first to Joe Allman at RBC Capital Markets.

Good morning, everybody.

Aubrey, any reason why acquisitions might slow down going forward versus what they've been historically?

And then also, I saw your comments on the Sable shale in the release.

Could you give us some more details on what the drilling looks like there, what the results look like there?

I know it's only with vertical wells but just want to get some sense of what you're seeing out there.

The second question is a lot easier than the first.

Our results there remain inconclusive, and that will be the extent of our comments about the Fayetteville other than to reiterate that we now have passed the million acre mark in our leasehold buying across that area With regard to acquisitions, Joe, the answer would be the same as I would give you at the start of any year, which is we can't predict when and if we'll make any acquisitions.

We obviously have a great organic drilling program, and so we never feel pressure to make acquisitions but in the past few years as we've seen opportunities that provide us with excellent returns, particularly when we factor in hedging we take advantage of those.

So you have already seen us make about 800 million of acquisitions in January of this year when we were able to buy some great properties from seven different sellers, and we hedged them at very attractive returns.

Going forward, I can't predict the shape of the curve, I can't predict what my competitors will do, nor can I predict what would be -- which sellers will likely sell.

So very difficult question to answer.

We'll remain opportunistic on the acquisitions front, but at the same time have that organic drilling program here that will always carry the day without any acquisitions.

Just a follow-up.

Not in terms of what, of course, the market is a huge factor in making acquisitions but what about in terms of just manageability?

The bigger you get the more production you need to replace every day with new reserves.

Can you just comment on that?

Well, that certainly is a fact, but actually I would say that if you look at our results this year, you would say that it was a year in which we produced the most gas ever and might have been a year in which our drilling replacement adds were as good as any other year we've had.

So this gets back to I think, efficiencies of scale, and when you build the kind of regional dominance that we've been able to build in several areas, actually scale gives you an easier ability to replace reserves than maybe when we were a smaller company or if we were a company with less focus in certain areas.

So our view is that we have shown when we were producing 300 million a day, and we've shown when were producing 1.4 billion a day, five years later that we can still generate 12% organic average growth, which is what we've done over the last five years.

We think that will be a little lower in '06, and we're projecting it in '07 as well, but still pretty good numbers for a company our size, and if not the best in the industry, we would certainly expect to be in the top two or three.

Thank you.

Okay.

Thanks, Joe.

We'll go next to Wayne Andrews at Raymond James.

Hey, Aubrey.

Could you give us an update just quickly on your Appalachian area and how things are integrating there?

I think you mentioned that you had four rigs running.

So what level you expect to get to there by the end of the year.

Sure, Wayne.

We are at four rigs right now, three in West Virginia, one in Kentucky.

We are well on our way to fully integrating that transaction, what maybe is a bigger challenge, or even bigger than the integration effort will be the -- kind of restaffing of our efforts.

I've got Marc Lester here.

Mark, when we bought that, we inherited how many geoscientists out of that?

Four geo scientists, and I think we might be headed to at least 10 to maybe 15.

We've added three to staff, and we've got two that are transferring to Charleston from Oklahoma City.

So our goal would be continue to build out our ability, Wayne to increase our activity.

We'll be at I guess nine to ten rigs by the end of spring, and the challenge will be at that point, not to keep them busy through the summer that will be no problem.

But traditionally there's been a big slowdown in activity through the wintertime, and we will be evaluating that through the year.

So I think we're pretty excited with what we've seen.

A great combination of various types of plays, and we don't yet have our team fully constructed there, but when we do, I think we will have a program that will give us organic growth that will at least be competitive with what the rest of the Company can do and hopefully even do better.

Very good.

We've seen a lot of good results coming out of the area.

You're going to be a big large player there.

Thanks for your comments.

Thank you, Wayne.

Next we'll go to Jeff Robertson at Lehman Brothers.

Good morning, Aubrey.

You talk a lot about the internal growth on the assets you have.

Can you talk a little bit about the decline curve and how that has changed in the last year or so with the acquisitions, and also with the drilling program that you envision for 2006 and 2007 as to whether that stays flat or with a very active drilling program, might it increase?

Jeff, this is Marc.

If you could think back a couple or three years ago, our initial decline rates that we were talking about measured in, say, full 2007 production over 2006 production, using that style of calculation, we were running in the 28, 29% first-year rate.

We've lined this out for you in our press release for the first five years right out of our reserve report on page 4, the bottom paragraph, and just to remind you those five-year decline rates are 24 -- Aubrey I can't see that, sorry -- 24, 16, 13, 11, then what we kind of call a terminal decline rate of about 10%, or slightly less after that.

You point out a good factor in your question, which is the greater the internal drilling program, adding new reserves from areas that frequently decline much faster than any base production, and this is true with any company, could lead to a perception that you might have an increasing decline rate.

Actually, the amount of our reserves, versus our drilling and what we're adding is such that we are not really projecting anything happening to our decline rate over the next couple of years.

As I mentioned in my prepared remarks, our RP ratio is now 16, and when we make acquisitions for properties like the Appalachian basin, which has the longest RP in the Company, and added to the significant drilling program in the Sahara region, which after the first year those declines are very light, too, we're just not anticipating with the mix of properties we see in our future to have a material change in our decline rates.

Jeff, I think you also had a question about CapEx in '06 and '07.

You'll notice on page 22 of the release we detailed what our CapEx from drilling and land and seismic investments will be, and we are projecting about a 10% increase in '07 versus '06.

You might say, won't inflation be up that amount?

We really budget on a flat gas and oil price index, and in that kind of environment, we simply would imagine that there would not be oil field service inflation, so that would be a real increase in CapEx.

If, on the other hand, oil and gas prices go up, then our CapEx might go up.

Of course, it might not under a hyperinflationary environment, but basically you would see about a 10% year-over-year increase in real CapEx as the plan for right now.

Aubrey, one question on -- or Marc, on the cost side.

With the land fleet in general expected to increase in the next few years with additional capacity what do you think that will do to drilling costs, not just for you all, but for the industry?

Well, I think it's going to be completely dependent on what prices do.

Obviously, there is a pretty significant amount of equipment now flowing in.

We're responsible for adding 60 rigs in the last few years, plus the ones that are on order in 2006, early 2007 delivery.

Others are building out new rigs as well.

Rumors of the Chinese bringing in crews and rigs.

I guess more than rumors, they're actually doing it.

All would be a counterweight to substantial increases in rig cost particularly.

We understand there's more frac equipment being built out for areas lake the Barnett, and there's some private companies FracTech is one name that comes to mind that are providing quite a bit of incremental services in the Barnett Shale particularly so all of that is weighed against what are oil and gas prices going to do.

And if oil and gas prices continue to be sort of reduced a little bit, or just flat, then we think that the overall service environment will be flat, and if they go back up, which we are bulls on natural gas and continue to be very strong, then prices probably continue to go up.

It's just that our belief is that margins will remain at or perhaps even increase from this point forward.

Jeff, I'd also ask you to consider the fact that it is relatively easy to increase service company infrastructure capacity compared to the difficulty in creating E&P capacity as measured by increases in production.

So I think we actually see an environment that might be actually quite benign in terms of service costs over the next two to three years as there will for sure be significant increases in service capacity -- service industry capacity, while I think you can be reasonably certain that gas production is going to stay more or less flat in the next few years.

So we have a contrarian view to those that think that service companies are going to capture an increasing share of our margins.

Our view is that in fact our businesses can continue to grow as a result that our businesses are much more difficult to build and our strategy is more difficult to execute than it is to build and run a rig and do other things associated with service.

So a slightly different take on things than what is the popular view out there.

Thank you, Aubrey.

Thank you, Jeff.

And we'll move next to Brian Singer at Goldman Sachs.

Good morning.

I might try to ask another Fayetteville question, if that's allowed.

How many wells do you plan to drill this year, and could you talk about where the acreage is that you recently acquired and whether your drilling is going to occur principally on the recently acquired acreage or on some of your earlier acquired acreage?

Brian, all questions are allowed.

Some answers aren't.

So I'll jump in though by saying that remember we just started to acquire acreage about 13 months or so ago, I guess.

Let's call it a year.

We've been consistent in our buying I think throughout the play starting from basically in the same area where southwestern had -- was originally buying their acreage.

I want to call it the western part of the play.

We have bought acreage to the east as well and have drilled a fairly spread out series of wells on a -- across the area to date.

In terms of CapEx, well, it depends on how we do.

If we keep two rigs running there right now, you basically could see every rig drilled -- let's call it 15 wells in a year, so we'd drill about 30 wells.

If we happen to be successful in the play, we have the capacity to ramp up our drilling there to probably 10 to 12 rigs by the end of the year.

So again, we have the capacity probably to drill somewhere between 75 and 100 wells over the next 12 months.

Again that would require -- that would be something other than inconclusive and we've not been willing to make that judgment yet.

I guess as it relates to the inconclusiveness, do you have greater confidence that the acreage you've just acquired in the last quarter, which seems to be substantial, is more attractive than the acreage you've drilled on before, or I guess could you talk about the relative attractiveness of that acreage?

Well, I think we would view that it's all possible in perspective, but as yet, that's a lot different than results to date that we have.

I will say that we are not without quite a bit of information in the play.

We're in about 40% of all southwestern's wells that have been drilled to date in the play, and I think I noticed last night that we were in 10 wells that they're either drilling or completing or preparing to drill horizontal on.

So we've got lots of information, and the horizontal wells that they have drilled to date look like about 1.2 bcfe wells to us.

So if we can hold costs down, and if we can achieve 1.2 bcfe VARs across the play, then it probably would be a successful play.

It may not be the best play the world's ever seen, which apparently some investors think that it might be, but certainly could be a competitive play for us.

Thanks.

Could I also ask for an update on Haley?

Sure.

We're at four rigs in Haley, and we'll be increasing our rig count through the year.

Not quite certain yet to what level.

We have three 3-D shoots in the general area, one of which -- I guess two of which we're now in and we're processing them -- I'm asking Mark Lester for a little help here.

We have two shoots in processing.

We have one shoot--.

All right.

So our hope is that through the information that both Anadarko and Chesapeake is obtaining through the drill bit and through the information that we're obtaining through our 3-D seismic that we will be able to kind of crack the code on the play, and results to date have been inconsistent, but the very good wells have been exceptional and have carried the program.

So still makes a lot of sense, but we know there's a lot of gas in place.

It's a true gas resource play we think, which you have an overpressured reservoir with lots of different play types and reservoir types, and the question is simply how do you avoid drilling the poor wells and drill more of the better wells.

So we're in a close communication with Anadarko on it and I'm pretty confident that this two-company play will end up being attractive to us both in the years ahead.

We're just not quite -- we just don't yet quite have all the answers to some of the questions that we have.

Thank you.

Thank you.

Next we'll move to Ellen Hannan at Bear Stearns.

A couple of questions.

One, you haven't really mentioned much on the investment you made recently in the deep Bossier play.

Can you give us any color on that?

I think we can.

First of all to remind everybody, deep Bossier play is in east Texas, kind of spreads across three or four counties, basically in that area.

Our first exposure to it, I guess really came simultaneous with our investment in Gastar, a small public company in which we now own 19% of, and they have something called the Hilltop area, and we acquired 1/3 interest in their acreage as well as an interest in their stock, which is up, last time I looked, I guess about 50% or so.

And so we now have about -- let me check the acreage we have there Ellen, we have about 125,000 acres net in that play.

We'll be drilling our first deep wells in the second half of this year, and certainly companies like Burlington and EnCana and Anadarko have all had success there and of course Gastar has had great success as well.

So we're pretty enthusiastic about it and they have stepped in and 125,000 acres will keep us busy for a long time.

So your acreage there really is through your investment in Gastar?

No, sorry, I didn't say that very clearly.

The 125,000 acres would include our net share of the acreage we did pick up from Gastar, and, Ellen, I am just guessing here, but I doubt that would be more than 10,000 acres that we got through Gastar, and everything else we've bought off the ground.

This is a question for Marc, just a little housekeeping.

Could you tell us why you're looking for an increase in your effective tax rate?

And also do you have an estimate there for capitalized interest in G&A for '06?

Sure, Ellen.

Good morning, by the way.

Good morning.

The effective tax rates changing primarily because of our entry into Appalachia.

The state tax rates there are much higher than what we've experienced back in our core areas.

For example, Texas is virtually nothing.

Maybe 1% if you include their franchise tax rates.

I believe West Virginia, for example their top tax rate for us is 9%.

So we're picking up most of the 200 basis points change as a result of our entry into those areas.

I expect that the capitalized costs will increase this year as a result of the drilling budget, both in terms of activity and in dollars being up.

The activity level is primarily what governs this because as you can imagine the people required to run 100 drilling rigs on average versus 73 drilling rigs on average, it just takes that higher number of people.

So just going from the drilling rig activity budget that we have presently, I would expect capitalized costs to be up about 1/3, interest costs probably up about 1/4.

Great.

Thank you.

Of course, one last -- I wanted to congratulate Tom on your impending retirement.

Is he there?

He's here.

Thanks, Ellen.

I think it's not so impending.

Should we read anything into this, Tom?

Not at all, Ellen.

I did just -- I'll go ahead and say what I was going to mention here.

I continue to love the strategy of growth that Chesapeake has.

However, over time, the strategy really outgrew my ability to oversee the operations in the same detail that I was accustomed to for more than 20 years.

I found myself questioning if I should move over and let the management team continue.

I came to that decision fairly quickly, and as soon as I did I advised Aubrey that I should move out of the way and let the Company move forward without me.

I haven't decided what I'm going to do but assume I will spend time looking for a way to use my abilities on a smaller scale.

Great.

I wish you all the best.

We do, too, and obviously goes without saying, Ellen, you've known us for long time, and you know that this company wouldn't exist today without Tom, and just to remind you and others, we've been partners together for 23 years, which is exactly half of our lives.

And I hope for the next 23 years we're partners in a lot of things going forward as well.

So thank you for the question.

I was hoping somebody would give Tom the chance to comment.

So that's great.

I couldn't let it pass.

Thank you very much.

Thank you.

We'll move next to David Khani at Friedman, Billings, Ramsey.

How much of your current production would you say is from your unconventional sort of resource plays if you throw Barnett and others and where do you see it going?

How much of a percent would you see of your outgoing production, maybe say three or five years down the road?

That information is embedded in a bunch of stuff here.

We may be able to pull it out.

Mark?

I've got it here, generally speaking.

Let me give you kind of the broad details here.

In the fourth quarter, which is, of course, representative of the current run rate, 58% of our production came out of Mid-Continent. 14.5% came out of the Ark-La-Tex area.

Almost exactly the same amount came out of our Gulf Coast area in -- because Appalachia was only 1.5 months during the quarter, only 7% of the value, 4.8%, came out of the -- and I was giving this to you by value. 4.8% of the volume came out.

That is going to be about 9 or 10% on a today's basis, not on the fourth quarter.

So those are the major areas that we break it out.

We don't then go in any of our filings break it down to, say, a Barnett Shale area.

That's just part of a broader area.

So I don't have that exact number.

We've always tried to avoid that simply because in our view, gas is gas, and it so happens that we think the future of the gas industry in the U.S. and largely the future of our company, the ability to generate sustainable, repeatable, predictable results is going to come out of our ability to conquer some resource plays going forward.

So I think our view would be that an increasing percentage of our gas would probably come from plays today that are so-called unconventional, but I will mention that we've always had an eye towards unconventional plays and the Austin Chalk was, in fact, probably the first one, where everybody knew there was oil and gas in place.

We just weren't sure if we could extract it economically.

Of course, we and Union Pacific did in Texas and struggled to do that in Louisiana, and that will be the story of many unconventional plays going forward.

Some will work, and some won't work, but we've had -- we've spent basically all of our careers looking for unconventional assets because when Tom and I started the Company in '89 we didn't have any conventional assets, and it seemed like a fair number of the conventional assets were already locked up, so we had to look for oil and gas in areas that other people did not think were attractive, and for the most part, we had to solve engineering challenges rather than geological challenges.

So today, for us, it's a little bit of back to the future there.

Okay.

Shifting over just a little bit, you sold down your Pioneer drilling rigs, and you bought the Martex rigs.

It looks like you sold 9 and you bought 13, but what's the quality of the rigs that you acquired and what's sort of the net quality that you ended up selling?

Well, our ownership in Pioneer, of course, was kind of synthetic, so it's tough to comment exactly on the quality, but our view is that across the board, the rigs that we picked up were as good as the rigs that we let go, and through taking advantage of public company valuations versus private company valuations, we were able to acquire rigs at about 1/3 discount to the public market.

Keep in mind we were in Pioneer because in the beginning, when we acquired our assets, or acquired our ownership in Pioneer that public company was selling less per rig than the private market was.

So we analyzed that opportunity, jumped on it, and then when the markets flipped, we jumped out of the public market valuation and jumped back into the private valuation.

The other thing I would say is I don't have firsthand knowledge of Pioneer's crews.

I assume they're all good crews, but Martex had truly excellent crews.

It's a company based out of Marshall, Texas.

All they've ever done basically is drill around the east Texas area and so a lot of stability in their employee base.

We are building rigs and certainly having success in crewing those up, but it is certainly a lot more favorable to take over 13 rigs that are fully staffed and up and running than it is to bring out, say, 13 rigs and go find the 300 or so guys you've got to have to go staff those rigs.

How many of those Martex rigs were you using and how many were others using?

I think we were -- let's see, Steve Dixon, are you on the phone?

Yes, sir.

Steve is reporting in from our Charleston, West Virginia, office.

Good morning, Steve.

Question.

Do you -- I think the number is one rig.

Is that right?

Yes, we already had under contract, and we are taking those over as their existing contracts expire.

I think we agreed for a two-year period to let Martex's E&P subsidiary keep using the rigs, and so we'll get, we'll eventually -- or I think within the next -- maybe by the end of this year we'll have 11 of 13 Martex rigs.

Keep using the two that they are currently using.

Yes.

I must not have said that clearly.

But, yes, they keep for two years and then we get the other 11 as contracts roll off this year.

So basically grabbing them from our competitors and putting them to use to accelerate our own development plans.

Great.

Good.

Last, I guess, what do you think -- what keeps you up at night?

Obviously you hedged the commodity.

What are you worried about?

Tom kept me up at night a couple weeks ago, so this week -- it's just -- scale of the enterprise, managing that, and still having an enjoyable way of life.

The thought processes that Tom went through, has been going through over the past couple of years are certainly thought processes that go across our minds as well as I think anybody in the industry.

Every management team in the industry has done well financially.

We're not getting any younger.

And so I think there's all kinds of questions that develop, but I think we love what we do here, and the management team here is younger than most.

That used to be perhaps a criticism of us but today maybe it's a competitive advantage.

I just -- I don't worry -- here's the things I don't worry about.

I don't worry about somebody taking our production from us.

I don't worry about rogue weather patterns.

I don't worry about accelerating depletion rates.

I don't worry about gas prices collapsing.

In fact, I wish they would.

That would give consumers a well deserved break.

Maybe take a little froth off the A&D market and certainly bring down service costs and would again highlight the value of our aggressive and active and opportunistic hedging programs.

And we've got 3300 employees here, so we're well staffed.

I actually sleep pretty well.

It's just that there's a lot to do during the day when you're not sleeping, and I guess that's what makes sure that we all sleep well at night is that we have plenty to do during the day.

Great.

Good quarter.

Thank you.

We'll go next to David Tameron at Jefferies and Company.

Congratulations on a great year.

Couple quick detail questions, then a big picture question.

Marc, what's your NOL position at 2005 year end?

We haven't completed our tax work yet, but I'm going to anticipate that it's going to be not terribly different than last year, and I believe that number was 564 or $584 million.

We do our tax work after we've completed all our financial reporting, and those returns for '05 just haven't been completed yet.

So you're still looking at three, four years before your big spend cash saving--?

It's dependent on your estimate of prices, and, of course, then, our drilling activity level, the IDC of which is deductible, so if we were to see a tremendous amount of price increase and we were to see the hyper inflation theoretically that Aubrey mentioned is possible, and drilling costs, and we were to for some reason cut back, then we could pay taxes earlier but not in the next two years.

If we go along under our estimates of 750 or $850 price environment where we're spending about 80% of our cash flow growing the Company 10, 12, 15% a year, then our estimates are that we won't pay any federal taxes through, I believe, about 2010.

It's conceivable that we could be paying some state income taxes in places like Kansas, where we don't have a real active drilling program, and the revenues would be coming off of those molecules up there, but it's so different than most businesses, most other sectors, even if we were to start paying some state cash income taxes out of the 38% accrual, we would be talking about a few basis points, really, 2, 3, 4%, and so the cash income tax component of any reasonable time estimate over the next several years is virtually 0.

Thanks.

Aubrey, the Barnett transaction, the Arlington properties you bought, was all that in Johnson County?

Yes, it was.

Oh, no, no, no, there was a little bit in eastern part -- a little bit in Hill County.

Sorry.

Vast majority is in Johnson County.

I think we've now got -- let's see here.

We have 79,000 acres, probably, net acres, and that's probably up into the 80s now, and I would guess 90 to 95% of that is in Johnson County.

Okay.

By the way, we drill monster wells also, so we've got great production in Johnson County that's proving to be the real sweet spot of the play.

Okay.

Then one more follow-up for you.

Big picture, how fast can you increase CapEx?

Assuming you don't make any other acquisitions on a year-over-year--?

That's not a question -- go ahead, sorry.

I was just going to say on a year-over-year basis, can you -- how fast can you increase it and still keep efficiencies?

I mean is it a 10, 15% number?

It's not a question we get asked very often.

Most people--.

Yes, I'm just trying to test the infrastructure.

Certainly our plan this year is to increase rig count, and we're still discussing what the opportunity set will be at the end of the year, but we're at 75 or 76 rigs today, and we've talked about going to 100, and that's an increase of 1/3.

So clearly we think we have the capacity within the organization to do that kind of an increase.

We won't -- I don't think we'll average 100 rigs for the year, but I wouldn't be surprised if we get to that level.

That will assume some level of success in some of our areas, but it also assumes that we just ramp up.

In the Barnett, we've got so much acreage that we're going from 5 rigs to probably 15 rigs there.

Sometime in the summer Sahara we're moving up our rig count.

East Texas, we're moving up our rig count.

So we've been preparing all this year for 2006 to be a year where we structurally could ramp, and we could do it in a way that wouldn't drive up industry costs.

What's -- what will allow us in '06 to increase our rig count by 1/3 and rig rates shouldn't increase as a result of that is simply our own building campaign.

So we initiated these moves in '04 and '05, and they're coming to fruition now in '05 and '06 and '07.

So I think we can probably more than most companies, to the extent we want to push down on the accelerator, we've built an organization that's capable of doing that.

Okay.

That was my question.

Do you feel you can grow without -- get to that 100 rig mark without driving up your internal cost structure?

I think that's actually -- that's a great advantage.

I think unfortunately I guess you've already seen in that our people, but we remain very efficient, and so our G&A costs remain pretty flat.

But if you were to come see us, you would see lots of activity and lots of action, lots of building, and lots of hiring as we get ready for kind of the next phase of our development.

All right.

I'll let somebody else.

Thanks.

Thank you.

We'll move next to John Keller at UBS.

Mr. Keller, your line is open.

Good morning, gentlemen.

Just had a quick question about Tom's role.

I understand that he will be on board for the next six months performing consulting services.

I just wanted to understand what that actually means and how do you expect to back-fill or sunset those services after the six months, and why six months specifically was chosen.

Well, you're asking a timeless question, which is what do consultants in general do.

And consultants in general provide expertise in targeted areas, and Tom will be providing that in areas in which he has traditionally provided that expertise, and I'm going to identify kind of three broad areas.

The first would be in thinking through commodity price trends.

All of our hedging in the past has been made at the unanimous -- or on the unanimous decisions of Tom, myself, and Marc.

And so he will remain engaged with us in discussions about where oil and gas prices are going.

Next, Tom's been fully involved and obviously the leader here over the last 16 years in terms of directing the Company's geological and land processes and helping direct us into new plays and make sure we are aggressively developing the plays that we have at hand, and during the next six months he will be assisting in the transition of that decision making to other folks.

Finally, in the operations and drilling areas as well.

Tom was one of the first, I think, in the industry, if not the first in the industry, to recognize that rigs were going to be the choke point in companies' growth plans.

And while I was more focused on the acquisitions and making that happen, or making acquisitions that required lots of drilling, Tom correctly identified that there was a greater risk to our acquisitions if we couldn't go out and capture that upside.

So Marc and I quickly agreed and we embarked on a program of taking care of that particular risk.

So in all three of those areas, Tom will continue to give his expertise.

He is here today, so I will let him speak further on that.

I would just also say that Steve and Marc and I have worked together for all of these years over 16 years together, and the Company is in very capable hands.

We all made decisions operationally together, and I'm happy to help in any areas that they'll have questions on, but there really is going to be very few operational issues that, especially those two won't be able to take care of.

With regard to time, I think that we all felt like a day was too short, and for Tom to make the transition he wanted to make, a year or two was too long, and so it just kind of seemed like six months was the right time.

Great.

Thanks, guys.

Great quarter.

Thanks, John.

Next we'll go to Matt Jones at Catalyst.

Hi, guys.

Good quarter.

Apologize for keep ripping on -- asking the same questions here, but has anyone said anything about what Tom is planning on doing with his stock?

He's quite a large shareholder of the Company.

Once again, I apologize for having to ask the question, but as a shareholder, that is a lot of stock.

I'll let Tom speak for himself there but I will remind you that if and when -- or if Tom decided to sell his stock, it's about a day, day and a half trading volume, so you'd have one of the top 15 most liquid stocks in America, so whatever his plans are, I don't expect it to be disruptive to the market, but again, here's Tom.

I haven't made any decisions, so I can't answer that one yet.

We hope that we can provide him with a competitive return on his investment.

Absolutely.

I would agree with you there.

Very good.

Next we'll go to Kent Green at Boston American Asset Management.

Great quarter, Aubrey, fellows.

Congratulations, Tom.

My question pertains to acquisitions.

Now that the gas prices have come down are you seeing a little bit less adamancy above these people for realizing higher prices on PUDs and that kind of stuff?

No, I don't think we've seen that yet, because really what matters isn't prompt month gas it's what matters out in the back months.

And so while the '08, '09 and '10, and '11 have come down somewhat from their peaks, if you compare where we were in September or October, when you had $14 prompt month gas you actually have the '07, '08, '9, '10, '11 beyond strips actually higher than that time.

And they were already higher than what we were using for evaluation purposes anyway so.

So really I don't think -- now, I hope psychologically it will have some effect on people, but at the end of the day, I think, the people that we compete against are all very well run companies with highly intelligent management teams which have the capabilities that we have to look out into the future and see the curve.

Now, not everybody likes to hedge out as far as we do, and if they don't, that may be a competitive disadvantage that they might have compared to us, but, at the end of the day, we think the -- one of the wonderful things about our business is that the storage situation resets every year, and so the fact that we have too much gas today because of the warmest January in 133 years of record keeping really only affects 2006, and in our opinion, it affects 2006 to Chesapeake's advantage because of the decisions we made in 2005.

So again, we focus more in the out years, and the out years are beginning to reflect the reality that the U.S. is not likely to get flooded by LNG, or cheap LNG in 2008, and 2009, and beyond, and it also properly reflects the fact that gas is harder and harder to find, refining costs will continue to go up, depletion rates should accelerate, and so in my view you might see some future scenario where you actually had futures prices in gas and oil markets that are in containing contain-go or a carry, as opposed to the backwardation that exists today.

Have you changed -- your acquisition team changed any of their parameters about paying for gas in the ground?

And then also, tie that into infrastructure, particularly in Appalachia, you may not have the infrastructure to take care of the volumes that you hope to achieve there.

Actually, I think we're going to be in good shape in Appalachia on infrastructure.

We're clearly moving all the gas that we're producing today.

Our ramp-up schedule there is actually pretty modest over the next couple of years, and we and others will make the necessary arrangements to get gas to market, so I'm not concerned about that.

With regard to our acquisitions team, we're using the same price decks today that we would have used two months ago, and for that matter six months ago even basically pre hurricane.

We use a whole matrix of some surprisingly low prices on the low side and some prices on the high side that aren't very high.

And so at this point, again, we stay focused on the out years, and the out years are higher today than at any other point they've been with the exception of the past 30 days but certainly more attractive today than they have been throughout most of 2005 if not all of 2005.

Thank you for your question.

Next we'll go to Ken Carroll at Johnson Rice.

Just to see if we can get a quick update.

I know some other operators have kind of been pounding their chest on the Caney Woodford shale and if there's any update there?

And then Aubrey, just love to kind of get your quick and dirty two-minute on the storage/macro situation here in Georgia.

The Caney Woodford chest pumping is a bit of a mystery to us.

We'll just be charitable in saying maybe we don't understand economics the way that others do, but we have a big acreage position in the play, we're in every horizontal well that's been drilled to date in the play in the Woodford play, and many or most in the Caney play.

It is true that gas is being found.

What nobody is asking questions about is what is the cost to find that gas.

We have better projects than finding costs that, in our view, are 3 to 4 to $5 an mcfe to date.

So maybe that will get better over time.

We hope so.

We'll be a big, if not the biggest beneficiary of those plays working in Oklahoma, but at this point the Caney Woodford play is uneconomic to us.

With regard to the gas macro, I think I've mentioned that.

I just think 2006 is shaping up to be a great year for Chesapeake.

Gas consumers are getting a well deserved break.

Remember, we've got 15 plus or 16 tcf of gas we've got to sell to somebody down the road, so we don't need prompt month gas prices of $20.

We actually like low prompt month gas prices and then, of course, kind of Contango'd or higher back year gas prices.

Hopefully we've been agile enough to hedge at higher prices any low prompt month prices.

So, I don't know, I feel like oil prices are likely to remain above 60.

I think that will keep gas prices in the 6 to 7 range, and that will hopefully generate enough recaptured demand for the surplus to get worked off.

There does not appear to be a big concern about an equally anomalous hot summer as people have placed on anomalous hot winter, or mild winter.

So if you just look at the curve it seems to me that there's not -- that has not been priced into the market in, say August, September, October, and it appears to me that there is no hurricane premium built in, either, and most things I read say that '06 is likely to be as busy as '05.

Hope it's not as destructive.

We're hoping down here as well, don't worry.

All right, guys.

Appreciate it.

Thank you, Kent.

Next we'll go to Eric Kalamaras Wachovia Securities.

Good morning, Aubrey.

Hi, Eric.

Question regarding the capital spending budget set forth for either '07 or '06.

I'm curious about the organic growth rate of 7%.

If we look at the amount of capital that's being spent what could we reasonably expect, excluding acquisitions, of course, into '08, based on that sort of capital budget over the next two years?

Regardless of what we budget, we're not going to go above 7% in an out year projection.

If you look at the history of our projections, we establish what we think are reasonably attractive targets, but they're targets that we feel very comfortable about meeting and hopefully exceeding, and so if you just think about the history of the Company, I think I read this morning that we've beaten consensus production estimates 25 of the last 28 quarters.

And so that should tell you a little bit about the built-in conservativism that we use in establishing production targets.

So you can use whatever you want, in terms of out year organic growth but I would think a company that could generate 7% or better on a go-forward basis with virtually no operating, and little financial risk, presents to at least this shareholder a pretty attractive risk/return ratio.

Related to the decline rate that's in the press release, the 24% for the first year of production, I'm curious as to how much of that 24% is C&R assets.

How much of it is C&R assets?

Yes.

Well, our C&R assets are about 10% of the total assets, maybe a little bit more, but the decline rate of the C&R is going to be, of course, less than 24 as the decline rate of other assets are greater, but that is fully integrated into that and captured in calculating that number.

So if I think of 10% is in the neighborhood of 5 to 7?

Is that about right?

I'm sorry, say it again.

Excuse me, I was thinking about production.

Appalachia is actually 17% of proved reserves as of 12/31, and a little less than 10% of production.

So the RP there is considerably longer.

Now, what was your final -- yes--?

I was just thinking about the initial decline.

Would that be some of the 5 to 7% range in Appalachia?

Steve, do you have an opinion on that?

No, it's 10% for first year.

Final decline is between 5 and 6, but first year is a little under 10.

Great.

Thank you.

Other companies talk about managing decline rates as somehow unique advantage.

The reality is we do it and I suspect other companies do it as well, you're always trying to balance the returns, the high returns you get from wells that are drilled with high decline rates up front, versus making acquisitions that have a broader and slower base.

Certainly one of the many reasons we went into Appalachia was we felt like it allowed us to continue to be very aggressive up-front with the drill bit generating great returns while also not finding ourselves in a position of accelerating our decline rates which companies that rely only on organic growth are going to have, and certainly that was our -- excuse me, that was our experience in the '90s, and certainly we don't want to repeat that experience today.

Thank you.

One last question, Aubrey.

With Tom's departure, is the -- what is your thought process and your role at Chesapeake and do you have, for lack of a better word an exit strategy that you're contemplating at some point in time?

Just whatever clarity you can give us there.

I probably can't.

I know it's a difficult question.

Well, I mean, my exit strategy could be -- well, I was going to say I could get hit by a bus this afternoon, but I'd rather not jinx me like that.

The reality is I like what I do, Tom's departure obviously caught me a little by surprise but at the same time, it didn't, and certainly the thoughts that he's had have crossed my mind from time to time, but not to the extent that they obviously affected his decision making.

So I think for me and the rest of the management team, we're fully engaged here, we like what we do, like the fact that we create value and I haven't yet discovered anything else I might be decent at, and so my intention is to continue to be engaged here and to help the team create value on a go-forward basis until there's no longer a reason to do that.

And at this point, I cannot imagine that set of circumstances.

Okay.

Thank you.

Thank you.

Next we'll go to David Cohen at Loomis Sales.

Hi, guys.

I'm wondering if you can comment on the west Texas Delaware Basin shale play, your position there, if you're continuing to add acreage in your development plans?

We've actually sat that play out, whether or not you call it a Stealth play or a Woodford play or Barnett play, I guess our assessment has been that we've been concerned about thermal maturity there.

We've been concerned about remoteness.

We've been concerned about depth, and, therefore, costs.

So it's just not something that at this point has warranted our -- us diverting dollars from other plays that we think on a risk-adjusted basis are going to have better returns.

We're certainly monitoring it, but at this point have seen nothing that has made us want to change our mind about the prospectivity of those plays.

They're fun to talk about because you can throw the word Barnett around, or maybe Woodford, but we've not seen anything that makes it look like they're going to be plays as successful as the Barnett or perhaps parts of the Fayetteville have been today.

So no plans to drill any wells?

We have no acreage, so no plans to drill wells, that's right.

Thanks, David.

Next we'll go to Kelly Krenger at Banc of America Securities.

Just a quick question on your current view of what you're seeing in the basis and how you think that's going to play out over the course of the next few months?

I know it's kind of a broad question, but just kind of in general what's your current views are.

Well, Kelly, good morning.

Our view of basis has been evolving.

If you go back to 2002, basis in the Mid-Continent, which was virtually where all of our production was at the time, or quite a good amount of it, basis would be as little as $0.14, $0.13 in the summer and sometimes in the winter it could be $0.21 or $0.22 and it had been like that for years and years.

But we started to worry about the amount of gas that was being developed in the Rockies, and we saw that incrementally there or in Canada, as pipeline projects were being discussed and being implemented, that that gas, for the most part, was going to come east, and by coming east into the Chicago markets or coming east into the upper Midwest markets, it was going to put gas on gas competition that previously had been limited to the Rockies or to Canada in direct competition with Mid-Continent gas.

So at that time we embarked on a very unique, to my knowledge, no one else at all was doing this, hedging program, and we entered into 900 bcf of future production hedges, locking that basis in.

And to date the amounts of money that we've realized off of that in cash would exceed $300 million.

In actual received cash.

And I think our mark to market position on it is about 400 million.

And so it's been a very successful program, and we still have a great amount of those hedges left on.

They're detailed in the outlook.

I think close to 500 bcf at this point all the way through 2009.

That's to say that we did a good job back then, the last quarter was the largest basis differential that we've ever seen, and today the spot market on gas, as futures have collapsed, has narrowed a little bit, but even looking forward, the future basis in most of the areas, and I'm excluding Appalachia where we have positive basis, but most of the areas in the Midwest, the future basis is till projected to be anywhere from mid-$0.80s, $0.88, to depending on the season, well up into the $1.20, and $1.30 range.

We continue to monitor it very carefully.

Our view is that continuation of additional gas out of the Rockies is likely.

There are additional projects being discussed today.

We are taking one further step, which is to attempt to enter into some firm transportation contracts with the volume of our production on an 8-8's basis today.

We are dominating production out of the state of Oklahoma and there are several projects that we're interested in entering into multiyear firm transportation arrangements which will have the effect of locking in our bases at basically whatever the transportation cost is to get it to the markets, whether that's in the southeast into Louisiana or additional markets in Chicago or even new markets that will develop as pipelines are built due east of Oklahoma.

And those pipeline tariff rates are considerably less than where basis is today.

So this basis flow out will not last.

It will be arbitraged away by the building of additional east-west pipelines which are underway.

And as Mark says, we will be the foundational gas transporter on several of those projects.

Okay.

Thank you.

Aubrey, I'm assuming that when you said 6 to $7 gas over the next, whatever period of time, few months, that that's a NYMEX based estimate.

Yes, it is.

And I'm not saying personally I believe it will go there.

I'm saying most people think it will, and if does it, we're going to be differentially advantaged.

Thank you.

Thanks, Kelly.

We'll go next to Dan Morrison at Aperion.

Mr. Morris, your line is open.

You may be on mute.

Sorry about that.

I'll prolong the call by inept phone operation.

I would observe that it's good that Oklahoma City doesn't have a big bus system.

But if you could comment quickly on the Appalachian acquisition, the thing that's concerned me the most and not in a horrible -- I'm not losing any sleep over it -- but the biggest challenge I think you have there is integration culturally as much as anything else.

It's just a completely different operating environment.

Could you just speak to some of the things you're doing to ensure a smooth integration there?

Sure.

And I wasn't quite sure where you were headed at the beginning, but lest you think we are total rubes, we do have a bus system here.

So don't want you to -- do want you to think about that.

With regard to Appalachian culture, my guess is most of them would think it to be superior to our own culture here in Oklahoma, but if you're thinking about corporate culture, we do have some changes to make and those changes are underway.

We have great leadership there under our VP there, Mike John, and, of course, Steve Dixon is there today.

Have been hiring a lot of talent and the reality is, the people that have been there have been operating under a different motivational system and a different strategy than what would be our strategy going forward, and our strategy is one of growth.

Their strategy was one of predictability and focused more on cost than on growth.

So it's typically been the case in the whole basin where if you look at who dominates it, it's bunch of players who have been focused on gas supply to their LDCs and we're kind of the first true big E&P company to go in there with a exploration initiative and with a growth strategy, and I think the people that we have hired in West Virginia are responding very favorably to that.

A few have left us who wanted a different strategy, but many, many more are applying, and we're having no trouble hiring the kind of talent that we need.

So I'm -- I think I've used the words in the past, we're cautiously optimistic or have low expectations but kind of high aspirations in the area, and I think that will continue on a go-forward basis.

Thank you.

Okay.

Thank you.

Next we'll go to Gabar Globnar at Janney Capital.

Mr. McClendon, I'm wondering if you could comment on the recent acquisition values terms of enterprise value to reserves, and the enterprise value to reserves ratio of your own stock, and why, given that situation, you preferred to make the acquisitions instead of buying your own stock?

Sure.

We always have been focused on how do we create the greatest terminal value for our shareholders, and over the past six or seven years as we rebuilt the Company's strategies from our IPO strategy, the process has been that we wanted to take advantage of what the market was giving us in terms of being able to buy assets that were relatively cheap compared to what we could hedge them for.

The reality is, it's -- we can go hedge an acquisition that we make for three or four years, the reality also is that we can't hedge more than about a year and a half of our own gas here because of limitations in the market.

So the same strategy that we apply to buying assets and extracting value from our people's assets is not available to us because of the scale of the enterprise.

So we think we can create lots of value for our shareholders and have our stock continue to appreciate as we continue our NAV creation process, which, as we went through earlier, is going to be $3.5 billion a year for at least the next couple of years.

So we think that's a pretty attractive return on a $30 stock.

Does this suggest you have no interest in making buybacks at all, given the current--?

At this point, probably -- I mean that is a true statement.

Keep in mind that we do have some leverage, and to actually reduce our equity base at this time would probably not give us a higher credit rating, nor would it give us a -- probably a greater equity multiple, and so at this point I think our goal is to continue to build the equity base in our company and hopefully we'll have a higher debt rating in time, and a multiple expansion on the equity side as well.

Thanks for your question.

Thank you.

We'll go next to Gil Yang at Citigroup.

Hi.

I thought I'd never get on.

But let me just ask one question to avoid prolonging.

Aubrey, could you just talk about growth.

What limits your organic growth rate more?

Is it the decline?

Is it the well performance?

The combination of well performance and rig availability?

Or is it some, what sort of limits you at 10%?

I don't think it's any of those three things.

I think it's just really management, desire, and capacity.

At this point, we've -- we work pretty hard to get to where we are, and while some other companies may need to accelerate their growth at this point, we certainly have that option, but we're not required to do it.

So at this point, I think we want to have a sustainable business enterprise that can grow for many, many years, if not decades into the future, and there's no desire on our part to push forward at an unsustainable pace.

So it's more of a human capital capacity issue than a geological or a -- some other issue?

Yes, and specifically, it's human capital at the highest level of the Company, in terms of our management team's desire to continue to continue to create lots of value while at the same time not creating lifestyles that make a bunch of people retire when they're all wealthy enough to do so today.

I need the management team to continue to love what they do and have fun at what they do, and you can do that at a certain growth pace and you can make people's lives obviously less attractive if you go too fast.

So we're trying to be mindful of that.

Okay.

Thanks.

I think that's about it, Jeff.

Is that right?

Thank you for those of you who hung on to the end.

Once again, appreciate my partner Tom's contributions to the call today.

It was his 52nd earnings release call.

You may not have known that but it's certainly a record of some sort I'm sure.

Anyway thanks again, and if you have additional questions, Jeff, Marc, and I will be here all day.

Thanks, bye, bye.