Chesapeake Energy Corp (CHK) 2007 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third quarter 2007 Chesapeake Energy Corporation earnings conference call.

My name is Jackie, and I will be your operator for today's call.

At this time all participants are in a listen-only mode.

We will be facilitating a question and answer session towards the end of today's conference.

(OPERATOR INSTRUCTION)

I would now like to turn the presentation over to your host for today's conference, Mr.

Jeff Mobley, Senior Vice President of Investor Relations and Research Analyst.

You may proceed.

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

Hopefully you've had a chance to review our press release and updated investor presentation posted to our web site yesterday afternoon.

Before I turn the call over to Aubrey and Marc, I need to provide you with a disclosure concerning forward-looking statements that Chesapeake 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 during the course of our discussion this morning we will mention terms such as operating cash flow and EBITDA and we'll also mention items that we believe are typically excluded from analyst estimates.

These are all non-GAAP financial measures.

Reconciliation to the comparable GAAP measures can be found on pages 22 through 25 of our press release issued yesterday afternoon.

While these are not GAAP financial measures the financial performance -- 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 shall last about 15 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 other members of the management team on the call today.

Marc Rowland, CFO, Steve Dixon our COO, Mark Lester, our Senior VP of Exploration, and Jeff Mobley, our Senior VP of Investor Relations and Research, are all with us here this morning.

The third quarter 2007 marks Chesapeake's 25th consecutive quarter of sequential production growth, and I believe, it is the 23rd consecutive quarter in which we have raised future production guidance.

It might just have been our best operational quarter ever, not only with our production up 27% on a year-over-year basis, it was also up 8% on a sequential basis.

That's a compound annual growth rate of 34%.

In fact, if you combine last quarter's 9% sequential growth with this quarter's 8%, you can see that our half-year growth number is 17%.

Remember, please, that we voluntarily shut in 3 Bcfe of production this quarter, had we not our third quarter sequential production growth would have been an astonishing 11%.

It should be crystal clear to all of our investors that Chesapeake's growth is accelerating even from an ever larger base of production.

Perhaps this is somewhat surprising to those who have been asking us for years when the law of large numbers would catch up with Chesapeake.

We see our growth this year as an obvious confirmation of the benefits of our large scale, our distinctive technological abilities and our unmatched leasehold in three seismic inventories.

In addition to impressive percentage growth numbers our absolute growth numbers are remarkable as well.

Our third quarter year-over-year production was up 429 million cubic feet of gas equivalent per day.

This means that in the past year we have increased our production by an amount that if it were a stand alone company would be the 17th largest U.S.

natural gas producer.

Meanwhile our sequential production growth was 158 million per day and without curtailments would have been 191 million per day.

At Chesapeake we are creating through the drillbit the equivalent of a good-sized U.S.

natural gas producer every single quarter.

As a result of our production performance, we have increased our growth expectations for future years.

We are now anticipating 21 to 23% production growth in 2007, 18 to 22% in 2008, and we have reaffirmed our 2009 production forecast of 12 to 16%.

However, please note that will be from a significantly higher base of production.

In addition, our proved reserve growth is closely tracking the pace of our production growth.

Accordingly we have also increased our proved reserve expectations to 11 Tcfe by year end 2007 and 12.5 to 13 Tcfe by year end 2008 and 14 to 15 Tcfe by 2009.

What makes these growth numbers even more remarkable is that we are now can achieve them while also being cash flow positive and without taking on any significant commodity price or operational risk.

In addition to our operational plan working almost perfectly, drilling and lease operating costs are coming down as we hope you noticed in our reduced DD&A and LOE cost numbers per unit of production in the third quarter.

We are hopeful the favorable cost trends will continue in the quarters ahead.

All of our important areas of production reserve growth are performing as expected or better, and we are also developing multiple new conventional and unconventional play concepts in several new and existing areas.

We will tell you more about these as we confirm their viability and acquire all of the available leaseholds in the prospective areas.

Moving on to our most important existing plays, I'd like to highlight first of all the Barnett.

In this play Chesapeake's net production increased by an incredible 43% on a sequential basis.

That means during the quarter we added 100 million cubic feet per day of net production.

On a gross basis this would have been about 160 million per day.

We're responsible for 6/10 of a Bcf of increased gas production in the U.S.

on an annualized basis in just one company and just one play using just 25% of our cash flow.

We have maintained for several years that by being willing to take on the challenges of leasing and drilling in urban Tarrant County, Texas, we could create a distinctive Barnett franchise for Chesapeake.

We have done just that and believe we're barely beginning to scratch the surface of our capabilities in the Barnett.

One more thing, as our drilling shifts northward into Tarrant County from Johnson County our well results are getting better and better.

And so this quarter we increased our projected EURs, or estimated ultimate recoveries, to 2.65 Bcfe per well from our previous expectations of 2.45 Bcfe per well.

To recap the Barnett, we have 235,000 net acres of leasehold.

We have booked 1.8 Tcfe of proved reserves.

We have unbooked Barnett reserves of 4.4 Tcfe, and believe we can increase our leasehold position by 40,000 net acres per year for at least the next few years.

By doing so we believe we can add a backlog of 600 wells per year which should fully offset the 600 wells per year we plan to drill.

So for at least the next five years we have built the equivalent of a perpetual motion machine in the Barnett.

In the Fayetteville our production growth during the past three months was up by a smooth running 100%.

We have really hit our stride in this play.

Our well results keep getting better.

Our costs keep coming down, and we have increased our targeted EURs by 25% to 2.0 Bcfe from 1.6 Bcfe previously.

Our leasehold inventory continues to grow as well.

We're now up to 420,000 net acres of core Fayetteville leaseholds.

On this leasehold we have 60 million per day of production, have booked just over 200 Bcfe of proved reserves and have at least 5 Tcfe of risked unproved reserves.

We're also continuing to consolidate our lease holdings in this play, and believe we will exceed 500,000 net acres here within the next year.

A final play I will highlight is the Deep Bossier trend in east Texas.

The value of this play was dramatically confirmed this week when EnCana paid $2.5 billion to acquire privately held Leor Energy.

Leor had 70 million per day of production in the trend and 55,000 or so of net acres lease hold.

While we do not yet have any deep Bossier production of our own we are completing two promising wells now.

We have three rigs drilling new wells and we have 380,000 net perspective Bossier acres.

If you want to drill big gas wells onshore America today, wells that can make more than 30 million per day, we believe there are only three places to go, the deep end at Anadarko basin in western Oklahoma, the Deep Haley area in west Texas and the deep Bossier trend in east Texas.

Chesapeake has a premier leasehold position in all three areas and so we believe our big gas well exposure is unique in the industry.

Finally, Chesapeake's leasehold and seismic inventories in other areas of the Company continue to grow.

We now own a record 23 Tcfe of risk, unproved reserves that nicely complement our 11 Tcfe of proved reserves.

These large unrisked -- I am sorry, these large, risked, unproved reserves give Chesapeake great forward growth visibility in both production and proved reserves for many years ahead.

It is a very nice position to be in.

We are an increasingly long energy company in an increasingly short energy world.

In summary the benefits of Chesapeake's strategic shift from resource capture to resource conversion that began in 2006 are noticeably accelerating.

Chesapeake's production and reserve growth is tops in our peer group.

We will be cash flow positive indefinitely.

Many of our unit costs are on the decline.

Our share count and debt levels are static or declining, and we have $100 oil on the horizon.

Surely higher natural gas prices are not far behind.

Imagine the impact of all these favorable operating and financial trends on Chesapeake's stock market valuation, if, by year end 2009, Chesapeake is producing 40% more gas and oil than we are today and we have 40% more proved reserves than we have today.

Given our present enterprise value of $33 billion, this would mean we could deliver to shareholders at least $13 billion of additional market equity value.

That would be roughly $25 per share in two years or more than a 60% potential increase.

To deliver that potential, we just have to keep executing our plan, there are no leaps of faith or issuances of securities needed to get from here to there.

I will now turn the call over to Marc for his commentary.

Thanks, Aubrey, and good morning, everyone.

A few comments this morning related to cost trends, CapEx guidance and updates related to our various financing initiatives and then we'll be off to Q&A.

On the cost side of our business, drilling rates continue to come down using a 1,000 horsepower rig as a standard measure.

New contracts today are in the $15,000 to $17,000 per day range down from three months ago by $500 to $750 per day and down from the beginning of the year a fully 10% to 15% when they ranged from 17.5 to 21.5.

Sahara footage rates on the Shallow River rigs are down slightly.

Pressure pumping is down as well.

Cementing costs, we've seen recent drops from 2 to 5%.

The only exception in that would be the Fayetteville where we're seeing some increased competition and fewer services at this moment.

Logging and casing prices are flat to down 5 or 6% so far this year.

On a separate note, want to point out that the average number of days in areas where we have a number of wells for comparison over a period of time are down also.

For example, both the Fayetteville and Colony Wash horizontal wells, the average days are down there per well about 10% for third quarter compared to second quarter going from 27 days on average to 24 days.

Haley, we're dropping the day count there by about 5% as well.

The Barnett has seen some efficiencies this year, but in this last quarter was essentially flat.

With regard to our outlook, you may have noted that we have expanded our guidance to include approximately $600 million per year of acquisitions.

This is previously been leasehold only and is now leasehold and property acquisitions.

We've seen at least one analyst comment this morning where they made the mistake of calling this an increase in CapEx.

Of course that is wrong, as we have been spending much more than that annually without guiding to any specific target.

Our new outlook is completely consistent with the plans we laid out in September and not at all a change except to say we generally expect to do much less in acquisitions.

I would point you to page 9 of our November presentation which is posted on our web site where we have a complete analysis of the cash in and out forecast for 2008 and now 2009.

A quick update on various financing initiatives.

Of course in the done column, successfully completed the rig and natural compression sale and leaseback.

I would point out the compression facilities also provide for future funding.

We have future orders for a couple of 100 million to meet our expected build out needs and compression in 2008 and 2009.

We also have a new compression fabrication facility in Oklahoma City that we have purchased to enhance our cost savings and efficiency in this area.

Also on the done column, our new $3 billion debt facility both expands the amount of liquidity available to the Company and extends the maturity to 2012.

In the works today our Appalachian asset monetization is proceeding very well.

We've had very strong interest from a number of very large financial players.

The anticipated proceeds from our first 35% working interest initiative has been so attractive it has caused us to increase the expected size of that deal and now we're looking for proceeds in excess of $1 billion that we expect to wrap up by the end of this year.

Something new that we haven't really mentioned before is the monetization of our non-core E&P assets in the Rocky Mountains and some sale of Woodford shale.

Both are anticipated to close by the first quarter of 2008 at the latest, and we expect proceeds somewhere in the neighborhood of 300 million for those on a combined basis.

Next up for us and most important probably is our monetization of the MLP assets that -- midstream MLP assets that we have.

We're currently in the process of examining the formation of this with the help of UBS.

We're putting the financial packages together.

What we have discovered in laying out our growth plans is that the growth in this area will be on the very high side.

This is making it very attractive to both strategic and financial players.

We've had many reverse inquiry calls in this area, and we would expect the valuation of this business to be well in excess of $1 billion sometime to be partially monetized in the first quarter of 2008 with either a private, strategic or financial partner.

That wraps it up for me, and, moderator, we'll go to the question and answer session, please.

Thank you, gentlemen.

(OPERATOR INSTRUCTIONS) Your first question will come from the line of Dave Kistler from Simmons & Company.

You may proceed, Dave.

Good morning, guys.

Dave.

Quick question, just looking at your hedging profile, and the comment you made just a bit ago on better gas prices kind of looking around the corner.

When I look at your latest changes to your hedging, looks like you increased Q4 '07, Q1 '08 and decreased the balance there after.

Can I read much into that?

I think that is really just growth in our production forecast, and I do not believe we changed our hedge positions in those out quarters at all.

That's correct, Dave.

Q1 and Q2 are - or last quarter of '07 and Q1 ' 08 we have increased our hedging from previous positions and now we're virtually 100% hedged including our calls and callers and so forth.

We have actually increased the amount of hedges we have on all the way into 2009 and simply the guidance has caused the numbers to perhaps look like it is a slight decrease in the percentage hedged.

That makes a lot of sense.

Then on kind of that same thought about gas but tying it a little bit to oil, can you discuss your thoughts on the economic dislocation we're seeing between gas and oil right now?

And your thoughts on when or whether they'll actually come back into historical equilibrium?

We probably don't expect them to any time soon, really don't think they should.

We think they're being influenced by two completely different markets.

Oil today is reflecting the fact that it is an increasingly short scarce resource in the world, and the visibility of forward production is increasingly opaque.

On the other hand, natural gas production growth both in the U.S.

and around the world is much more clear, and as a consequence, markets are much more well supplied both presently and they are expected to be in the future.

With as little true substitute ability as there is, we really don't expect gas prices to trade on an historic 6 to 1 BTU relationship.

We do think at the end of the day that there will be a move towards natural gas as we move into increasingly crude or oil short world as we believe some part of the world's transportation system is going to have to move natural gas, whether it is natural gas directly into vehicles or whether it is a derivative of natural gas supplied by electricity for some kind of plug in capabilities for cars.

To us the world oil market has been what it should be doing.

It is looking for a price that is capable of restraining demand, and obviously we haven't seen anything from $50 to $100 oil yet and until we find that price we expect oil to continue to go up, we do think it will help sustain higher gas prices than maybe what otherwise would be out there, but we certainly are not calling for a return any time soon in the 6 to 1 relationship.

In the longer term, though, I definitely believe gas has considerable value as it could be used as a transportation fuel in the oil short world.

Great.

Thanks for those thoughts.

Switching just to one last question on the asset specific question, with the Woodford shale, you guys upgraded it into the -- out of the emerging play category, and yet at the same time are making a decision to sell a portion of it.

Can you give me a little color around both of those components?

And then also can I infer there is potentially a sweet spot within the Woodford similar to the Barnett.

Well, we love the play.

We have 65,000 acres to sell and think it is a fabulous play and look forward to the value that we're going to receive by selling 65,000 acres to somebody else.

Okay.

I guess with separating the piece you're selling the piece you're keeping, and I guess comments from other folks, is there or have you guys been able to ascertain if there is a sweet spot like the core in the Barnett?

Yes, Dave, sorry, that was a little tongue in cheek.

Yes, there certainly is a place we would rather be, and so we're going to keep 35,000 acres and sell the other 65,000.

And excuse me, that 65,000 is in plays that other people have considered more prospective than we have.

So it is, it's a play that we're going to put capital into, and in that 35,000 acres we think we've got upside of half a TCF, so we're going to go do everything we can to develop that while at the same time monetizing a bunch of leaseholds that we probably wouldn't be able to get to ourselves.

Great.

Thanks for the color.

I will let someone else hop on.

Thank you.

Thank you very much, Dave.

Your next question will come from the line of Brian Singer from Goldman Sachs.

You may proceed, Brian.

Thank you.

Good morning.

Good morning, Brian.

In the Fayetteville you took up your expected EURs, likely as a result of the longer laterals.

Are you seeing the uplift in the wells that you're operating that's causing an increased debt or is that more a function of Southwestern?

And can you talk about how you see that 3-point or that $3 million cost moving up or down in the next -- over the next year?

First of all, we've always been a long lateral company, they were short lateral company, so we've been seeing these kinds of EURs really for the last six months.

We just wanted to see some more production before we confirm them.

We have not changed really anything in our development plan over what we've been doing, we always fraced our wells with slick water, we always drilled long laterals, and so we're not, I think other companies are coming to what we have always done rather than vice versa.

With regard to cost, we're at $3 million, and believe that we'll continue to be able to drive that down.

It is an area that is still not built out as well as we would like it to be from a service company infrastructure bases, but given that we've got around 12 rigs running in the area and Southwestern has 20 or so and there's probably 8 or so from other companies, that's about 40 rigs, and that will support a pretty good service basin there, and that's getting built outright now.

So I think our long-term goal is to be able to drill these wells for 2.5, $2.6 million, and we hope the EURs will continue to creep up over time as we drill more wells that are second, third, fourth, fifth, sixth wells in sections where you have a lot more geological control.

We are also still drilling a significant number of wells without the benefit of 3D.

And when we get our area fully shot with 3D, we think that our well results will be better and our costs can be lower.

Great.

Thanks.

On the asset sale front, how much production, I think you mentioned this individually, but overall how much production is being targeted for asset sales?

And has any of that been removed from your production guidance based on the accounting that how you're planning to account for that?

Right now, Brian, it looks like we'll be doing likely a transaction that will result in what we call pre pay accounting where you book the cash received as deferred revenue and then take the production through your income statement in the future, amortizing that deferred revenue over the time of actual production.

Right now we're looking to be in the neighborhood of approximately 60 million a day of Appalachian production that would be monetized, but that's not come out of the guidance for the reasons that I just listed, so I think we made that clear in our footnotes to our outlook as to what -- how we had handled that.

You now see 60 million a day as a yearly, a yearly sale?

That would be the rate at the time that we anticipate selling it which is an effective date of January 1.

Of course going forward that will decline just like all production does.

Great.

Thank you.

Thank you, gentlemen.

Your next question will come from the line of David Heikkinen from Tudor, Pickering & Co..

You may proceed, David.

I think that's me.

Just wanted to go through Fayetteville you talked about six wells per section, orientation of those wells and kind of the plan of how you develop.

There has been some discussion of north-south orientation and trying to drill forward a 5,000-foot laterals.

Is that what you're talking about there, Aubrey?

No, actually, I just -- as an example, I talked about by the time we drill fourth, fifth or sixth wells we'll be doing better.

Our plans right now are to drill eight per section, and we are doing some work alongside some work that Southwestern is doing to try north-south orientations that we believe might lead to more efficient drilling patterns as we are able to drill longer laterals.

They're also working on some four section kind of unit areas that we're also experimenting with as well.

So right now most of our drilling is still oriented northwest to southeast, but we're playing with alternative orientations of wells to figure out what both produces the best and also what gives us the most amount of exposed rock per 640 acres.

Okay.

Then your Rockies asset sales, what are those properties?

We have got properties in the Williston basin mainly, and then we have a little bit of gas production in Colorado that we inherited, I believe, from our Hugoton acquisition and continue to maintain it over time.

So it is a heavily oil-weighted package, and we think it will be attractive to a number of players.

Okay.

And then, the property acquisition as you roll in the $600 million, any production with that or bolt-on or how do you think about that as far as your numbers and guidance?

There'll always a little bit of production probably, but we've not modeled any as we presume this will be mainly bolt-on Barnett and bolt-on Fayetteville acquisitions.

And one kind of unusual thing in the Fayetteville with the oil and gas clearing house move for leasing, how do you think that process is going to go by Anadarko and do you think that will be a trend of ways to monetize leases over time?

It is an interesting question and concept.

We will take a look at it.

I am sure other people will take a look at it as well.

The problem is it is a relatively scattered group of leases that are -- some of them are in we think real attractive areas.

Some of them are not.

If you believe in the auction process which gives you the best outcome, we think it is a pretty good way to go.

However, we have been involved in many sealed-bid transactions where somebody throws in a number that's pretty high over the threshold as well.

So I don't think it is knowable but surely this is the most transparent way to do it, and we hope to participate in the process and see what comes out of it.

But we do -- we are seeing more banding together of mineral owners in various hot plays in the country, whether it be neighborhoods in Fort Worth or whether it be mineral owners in southern Oklahoma, so that's just an aspect of where we are today in the industry.

I will say that it is certainly -- we still believe that for the most part that in every important play in America that the land grab is largely over and are pleased with what we've been able to grab along the way.

Okay.

Thank you.

Thank you, gentlemen.

Your next question will come from the line of Scott Hanold from RBC.

Scott, you may proceed.

Thank you.

Good morning.

Good morning.

Could you talk about the deep Bossier a little bit?

What would it take for you to move that from your merging play to more of a focus area?

Kind of where are you at there, and what are sort of the key milestones do you see there going forward?

The key milestones would be successful drilling, and some production.

We don't have any operated deep Bossier production right now, and we certainly see it all around us and we waited on seismic to come in before we kicked off our drilling program.

I think as I mentioned in my introductory comments we are completing two wells, on logs looks like they'll be productive so hopefully in the next 30 days we'll have deep Bossier production.

And then we have three rigs drilling right now which should give capability of drilling about 12 wells per year.

Obviously that's a number that can be accelerated pretty quickly if we started to have anything close to the kind of success that EnCana has had to date in their part of the play.

Okay.

So looking into 2008, I guess one could suspect you guys had -- if you results look on par with other operators, you could at least run those three rigs on out there?

We haven't planned through 2009, and the bias would be of course for them to go up.

For example, we're drilling a well right now, I believe it's 1.3 miles away from the Laxton well, which is their new big well it's making 65 million a day, so we're in the hunt on a lot of stuff, we just got a little later start as we were waiting on shooting some 3D to give us a little more clarity into what our acres position looked like.

Is there any opportunity to consolidate more acreage out there or is it pretty tough?

We're always on the hunt, in every area, but we have 380,000 acres, so I don't know what you all think EnCana paid for non-producing leasehold in the Leor acquisition, but if you put any kind of number on it and put it on our acreage, you can see that we've got an enormous asset there that needs some value to be generated from.

We think we can best do that through the drill bit.

Fair enough.

One last question on the Fayetteville.

You sort of indicated that it appears at this time there may be service and infrastructure constraints.

Do you foresee there being bottlenecks for completing wells and getting production out of there at this point in the next 6 to 12 months or is there enough stuff being done to provide some comforts over the next, say, year?

We move the gas ourselves, so there are no delays there.

Marc mentioned what had we're doing on the monetization of our mid-stream gas assets through an MLP.

One of the big growth areas for that MLP will be in building out gas gathering infrastructure in the Fayetteville, so no problems there.

With regard to infrastructure, I mentioned simply that costs are higher than they might be if it was in a little more populated area or in an area of more historic production, but that's improving, and we think it is getting better every day, and really don't see any delays in getting anything done.

It is just a matter that the unit costs are a little bit higher than we would like them to be.

Thank you.

Appreciate your time.

Okay.

Thanks, Scott.

Thank you, gentlemen.

Your next question will come from the line of Eric Kalamaras from Wachovia Capital Markets.

You may proceed, Eric.

Good morning.

Question on the cash resource plan that you provided.

You'll have the ability to clean down most of your revolver looks like by certainly the first half of '08, and to the extent that acquisitions don't materialize for '08, and '09, how do you foresee the use of cash away from those other acquisition opportunities?

Well, Eric, I think that if you study the overall annual plan, which as I mentioned is laid out on page 9, our revolver today is 2.1 outstanding, and we call for potential surpluses over the full two years of only 2.9 million, and obviously all of that is not going to be front loaded in the first quarter, there will be ups and downs.

And, yes, it is possible that the acquisitions that you mentioned won't materialize, but we're continuing to see in the Barnett Shale, for example, which is one area where we continue to spend a lot of money because of the value that we're creating down there, we were just going over some numbers internally today, and we think that there is still a couple 100,000-acres at least available in that play.

Now, it is going to come at small units at a time.

But nonetheless, when you have the activity level that we have down there, and we're leasing from many different players both ourselves and we have groups of people working for us, there will be a lot of acreage acquisitions that will come out of that.

So kind of, with all of that as being a caveat, we do anticipate being able to reduce our bank lines over time as we execute this plan, but I don't really see us getting into any kind of a stock buyback or a note buyback.

We've got some notes that are callable first in 2008, and right now it looks attractive for us to go out in the market and probably refinance those with longer maturities perhaps pushing the maturities out to 2019.

I don't see us going into the market and making any kind of a move to tender for any of our securities that is are outstanding today.

That's helpful.

Thanks, Marc.

Thank you, gentlemen.

Your next question will come from the line of Jeff Hayden from Pritchard Capital Partners.

You may proceed, Jeff.

Thanks.

Hi, guys, nice quarter.

Real quick, in the Barnett Shale, especially in the core area and now even expanding out into tier 1, you're hearing a lot more people talk about the 500-foot spaced wells.

Now we're starting to hear more and more people talk about 250-foot well spacing.

Just wondering if you guys have done any pilots on 250-foot well spacing or just what your opinion is with regard to that right now?

We have not done any of that and at this point kind of have our hands full drilling our wells down to 500-foot spacing.

I will note, however, that our experience has been, I believe this is true throughout the industry, that every time you decrease a spacing by 1/2, i.e., go from 2,000 feet to a 1,000 feet apart, 1,000 feet apart to 500 feet apart, your reserves drop by about 30%.

Per well.

Per well.

Sorry.

We would expect if you were to go to 250s, that that would happen as well, and you might get into some tougher economics.

But that's the kind of upside that I think that we think we've got that we really haven't seen begun to try and quantify, and that's the reason why we continue to build acreage in this area that we think will be producing gas here for decades, and will be figuring out more and more ways to get the gas out.

Remember right now we think we're only probably recovering about 20% or so of the gas in place per section, so that 80% will consume the attention of lots of people around here for probably decades to come.

Great.

Just one other quick one.

You guys talked about the Marcellus shale a little in Appalachia.

How much of your ache rack acreage is prospective for the Marcellus?

Right now, about 750,000 acres I believe is what we have, and that's a combination of leasehold that we acquired through our CNR acquisition as well as acreage that we bought off the ground.

We're drilling our first few vertical and horizontal wells right now, and kind of excited about the play.

So I have seen a few other numbers out there, but I don't think anybody has any amount of acreage that is close to the 750,000 or so that we believe we have.

All right.

Great.

Thanks a lot, guys.

Thank you, gentlemen.

Your next question will come from the line of Gil Yang from Citi.

You may proceed, Gil.

A couple of my questions have been answered already, but Aubrey, I just have one for you.

That is that in earlier discussion about oil versus gas, it was an interesting discussion.

You've also made the comment in the past that you would gladly trade your reserves for oil, just that you can't find any.

Are you thinking of taking the portfolio or the efforts of the Company and skewing that towards a little more effort in looking for oil?

And does your technical expertise, that the Company clearly has in discovering natural gas, help you in any way in give you competitive advantage in looking for oil?

I think so.

The exploration process is similar, I think, particularly when it comes to unconventional resources, and as you know, there are some unconventional formations that are potentially oil producers, and there are many more of course that are gas producers.

So I would love to change all of our almost 2 billion-barrels of oil equivalent reserves into oil, but it is not possible, and I would note -- would point to the fact that our oil production increased, I think, about 25% year-over-year.

So it is still unfortunately a small number, only about 9% of our production, but we definitely have an all hands alerted around here looking for oil, and we do have a lot of plays that are prospective for oil, just nothing on the scale that could move the needle the way that the Barnett moves the needle and the Fayetteville moves the needle and plays like the Bossier and Haley.

So I think where we are is recognizing that it is great to find every barrel that we can, but in terms of building an enterprise here that is sustainable on a sustainable asset foundation for decades to come, we believe that over time the world would increasingly want to and have to turn to natural gas to power its transportation grid either again directly into vehicles or through the electricity grid.

I view that the current separation between oil and natural gas is probably a historic --- at historic high going forward, and out years we would suspect that that gap would somewhat close, mainly through the value of natural gas and increasing as it gets priced more for its availability, affordability and cleanliness as well.

All right.

Thank you.

Okay.

Thank you.

Thank you, gentlemen.

Your next question will come from the line of Ellen Hannan from Bear Stearns.

You may proceed, Ellen.

Thanks.

All my questions have been answered.

Ellen?

[ Laughter ] we had some technical difficulties.

I couldn't get on earlier.

I apologize.

We couldn't either.

Sorry about that.

(laughter)

Okay.

We shared the same difficulty.

Thanks, Ellen.

Thank you.

Thank you very much, gentlemen.

Your next question will come from the line of Michael Angle from TIAA CREF.

You may proceed, Michael.

It is actually Michael Ange.

I have a question about your debt levels.

Obviously you have got some of these asset monetizations in the next quarter, and then some in the quarter after that.

I am just curious how we should be looking at that, whether we should be looking at that to have debt come down or really to have that just sort of slow the growth in debt?

I am wondering if you can clear that up for me?

Michael, I think there is two-ways that we look at it.

The plan is laid out is for no increase in debt at all, so saying that we're going to slow the increase in the rate of growth of debt is not correct.

We are planning to decrease our debt levels with the plan that we've laid out.

Most of that initially will go to reducing our revolving credit facilities, which are of course are fungible daily as to drawing and repaying.

The bigger picture for us, make sure that this point gets communicated, the asset monetizations for us are taking what are no-growth, long-lived, fully-developed properties, that is can be monetized, call it a cap rate of around 7% and taking that cash and moving it into 35 or 40% on average internal rates of return in the Barnett Shale and the Fayetteville and other drilling areas that we have going on, without increasing our debt and without increasing our shares, while building the overall reserves and production levels of the Company at a record pace.

We are by far the largest growth company in the large cap universe, and if we can sustain those growth levels over several years with no increase in our share count and a decrease in our debt levels, we will accomplish something that few companies have ever been able to do on the scale we think we can do it.

So sell high and buy low through the drill bit and keep the balance sheet improving.

These results, I think, will reward all of our shareholders and our debt holders.

Okay.

And then just one more clarifying question.

So, like I said, looks like you're going to do out of the Appalachian asset monetization somewhere around $1 billion, looks like you're saying that's going to close by year end.

So should we assume at least a chunk that far gets used to pay down the revolver some by year end?

Well, I think you could assume that the day that we close 100% of it would go to the revolver.

Okay.

And then may go back up as you continue drilling and what not?

Exactly.

Got it.

Thank you.

Thank you, gentlemen.

Your next question will come from the line of Scott Palmer from Janney Montgomery Scott.

Scott, you may proceed.

Good morning.

Thanks.

Aubrey, good quarter as usual.

My few questions are, when do you anticipate becoming investment grade?

Number two, as far as weather is concerned, last year you made some just general comments about what your crack meteorological staff anticipated for the winter.

I was wondering if you could share any generalizations again this year?

And my last question is in regards to supply and demand, is that you have consistently over the last number of years had in your investor slide presentation that your vision has been growth and demand of 1 to 2% per year, and growth of supply minus 1 to 2% per year, and I notice that's not there any more.

Do you feel significantly different now about that supply and demand relationship?

And since the growth in supply this year was fairly significant how do you feel about things?

I think we took that out some time ago to modify it to a view today that gas supply is definitely growing, and probably by anywhere from net of growth decline, somewhere in the probably 2 to 3 to maybe 4% range, so we think that's a great thing for both the industry as well as consumers.

Over the last couple of years gas got kind of a bad rap as being a volatile priced commodity, and some people thought its price was too high.

We believe that it is an amazing product that burns cleanly, and also trades right now, of course, at about half the BTU values of oil, so we think consumers ought to love the situation that they're in.

So from a supply/demand perspective, I think what we see is that during the wintertime LNG importation into the U.S.

will be dramatically reduced from what it has been in the past, and so other parts of the world call that gas away with higher prices and many of which will be linked to oil in some way.

And then the summertime we'll probably take in a little more gas than perhaps in the past as we are the swing storage provider to the world.

In general, though, we like the fact that gas depletes at the fact -- at the rate of about 35% per year, so know that if there is any extended period of rig activity declines, such as what's been experienced in Canada, there will be fall-off in supply, but for right now companies like our own and a handful of other mid and large-cap companies that are growing rapidly through the drill bit are providing consumers in the U.S.

with a real windfall, we think.

With regard to weather over the last ten years it just keeps getting warmer.

And while I pay a lot of attention to the forecast that our guys give out, the trend has been towards warmer, so we approach every winter with a bias towards warmth really regardless of what our fellows opinion is.

And with regard to investment grade, I already think we are, so you're probably asking the wrong guy.

When you compare us to at least one or two other investment grade companies, I think that we compare actually pretty favorably.

Clearly, my opinion is not one that has much impact on rating agency opinions, so I will defer further comment on that to Marc.

I think that the trend is definitely toward that.

Our goal is to get there ultimately.

We think it is more inevitable than it is that we're going to go out and radically change our business plan because that's an absolute essential.

It is not to us.

If I look through the stuff that Jeff's laid out for us in our presentation, and you go to page 7 of the presentation, and you start to look at the debt per Mcfe numbers that we're projecting, by the end of '09, and you look at the production rates and the asset coverage test, and I reflect back on S&P, and their evaluation of our September announcement, which was that all of the moves that we were moving toward are credit enhancing, and we remain on positive outlook there.

I can see easily during the latter part of '08 with the accomplishments of the monetization, the enterprise value growth, where we'll be approaching $40 to $50 billion in the next twelve months, the value that I think ,which will be tremendous in the MLP space, that alone could be a $3 to $5 billion enterprise within a year.

We may not be at investment grade then.

But I think we could be a cross over in kind of looking forward to potential upgrades in '09 that might get us there.

All right.

Thanks.

Just a follow-up.

Since natural gas in the last three weeks rallied and supply is still very significant at this point, any thoughts as to why that is?

I think that the two markets for natural gas as there are for any commodity, there is a cash market and there is a futures market, and futures market of course is mainly financial market, and we think they can become separated from time to time, so our view is that oil has provided a pretty strong up draft, and I think it is not clear yet what kind of winter we're going to have.

You had an investment community that was largely short natural gas, so we think the last month or so has been a fairly predictable -- followed a fairly predictable pattern as most Octobers and early Novembers do, you generally see a rise in gas prices during that time in anticipation of winter.

So no big surprises here.

And, of course, the question about where natural gas prices go this winter is largely dependent on the weather and secondarily dependent on where oil prices go.

But it is really kind of irrelevant to us.

We are essentially 100% hedged through the winter, and so we just as soon gas prices go to 0 and give all gas consumers a big break and get them fully back in the game and geared up to consume a lot of gas in 2008 and beyond.

Great.

Thanks.

Appreciate your time.

Thank you, gentlemen.

Your next question will come from the line of David Tameron from Wachovia Capital Markets.

You may proceed, David.

Thanks.

Good morning.

Could you talk a little about what you're doing, I guess you're calling it the colony wash in the Texas Panhandle.

Can you talk a little about the horizontal program that you mentioned in the prepared remarks?

Sure.

Actually the colony wash area is in Washita County, Oklahoma, and it is a home-grown prospect that we've drilled, probably ten wells in to date, and have had very nice results and I think that we have a large number of wells left to drill in that area, and one nice benefit to it is it is a little bit oilier than some of the other wash plays that we have been involved in.

All right.

And are you guys doing the same thing on the Granite and Atoka side, you doing some more horizontals over there or not?

We have got probably half a dozen distinct wash plays, some of which are Granite wash plays, some Atoka wash plays, some are Cherokee wash plays, so they're probably all a little bit different, but generally speaking most of them are horizontal plays, and we've been really encouraged with our horizontal results to date.

All right.

Thanks.

Okay.

Thank you.

Thank you, gentlemen.

Your next question will come from the line of Joe Allman from JPMorgan.

You may proceed, Joe.

Good morning.

Aubrey, in terms of the Woodford package there, is that related to lease expiration issues in any way?

No, Joe, just related to the fact that we have some other plays that we've allocated more capital to, and this is a play that, I think has been clear for a couple of years that some other companies are more excited about than we are, so we're going to let them express their excitement by buying some of our leaseholds.

Got you.

That's helpful.

In terms of the deep Bossier, your production right now is relatively small.

Can you talk about how many wells that's coming from?

And can you talk about any differences in geology that you folks see right now versus the EnCana acreage?

And that's it on that one.

Sure, Joe.

I think as I said, our production is zero, so that I think meets your definition of relatively small, and that's coming from zero wells also.

But we are -- we do have two wells completed and three wells drilling, and from a geological perspective, obviously there is going to be -- we think it is obvious that there will be other accumulations found in the trend.

Hopefully, some that are as good as the Amarosa that EnCana and Leor have discovered.

It's really hats off to those guys.

It is an incredible discovery in wells that have come in at 50 to 65 million cubic feet of gas per day.

Nothing really to toot our horn on yet except we have a lot of acreage, and we're kind of right in the middle of the road, and hope to get run over by some 50 million a day wells here in the next year or so.

Got you.

Your press release indicates you're producing 7 million a day.

Jeff pointed out to me that's non-op.

I said from an operated basis it is zero.

I should have done a better job of --

How many wells is that on a non-op basis?

Do you know?

No, I don't, Joe.

On a net basis, Jeff is signaling to me that it is five wells.

Got you.

Lastly for Marc, you increased your forecast for the share count.

Can you talk about the reasons behind that?

There are a couple of small reasons and it is up a minor amount.

The first reason is because we are putting out some additional common shares in our assumed preferred stock induced conversion, so their share count went up slightly as a result of that, and then just the continuation of stock grants as part of our executive compensation program.

As we get larger, every employee in the Company receives some stock grant, and as the number of our employees increase, and particularly our highly paid technical staff, a large part of that compensation comes from additional stock grants.

So it is just a normal course of business for employee count to go up with the large production increases and the amount of reserve increases, everything is shifting up and to the right, and the minor amount of shares is part of that.

Okay.

Appreciate that.

Thank you.

Thank you, Joe.

Thank you, gentlemen.

Your next question will come from the line of Monica Verma from Gilford Securities.

You may proceed, Monica.

Good morning.

I just have two quick questions, the first one dealing with your conventional resource plays, and just wondering if you guys could talk a little bit about the monetization of those plays and the potential for MLP?

Well, in our conventional plays and I think the way we monetize those is we just produce them and hopefully grow them as well.

In some of our older areas they do present opportunities to do the kind of asset monetization that we've talked about coming out of our Appalachian assets.

For example, in the Hugoton infield in Kansas and the west Panhandle field in the Texas Panhandle, we have assets that decline at 3, 4, 5% per year on a terminal basis that have decline curves that are 50 years of age or often more.

And so, they're the perfect kind of assets that a financial buyer would want to evaluate when trying to buy a stream of cash flow from production.

It will be just through production of our assets as well as potentially down the road in '08 or '09 putting some of those low-declining rate wells into an asset monetization program probably will not be an MLP but instead will be a financial monetization.

Okay.

And just to get a sense going onto like Appalachia and Sahara and the Ark-La-Tex can you talk a little bit about the reserve revisions down, especially in Appalachia the 1.5 Tcf?

Let's see.

When you say down, down from?

From the previous quarter.

Sorry.

It looks like in the previous quarter Appalachia had unrisked somewhere around 9 and then now it's looking at 7 Tcf?

Monica, I had a second quarter earnings release here that I could compare to, but most of it just stems --

I am sorry, 8.6.

Just different risk factors that we're applying, sometimes acreage gets moved around between different plays, so I tell you what, if you don't mind, I'm going to let Jeff call you back and reconcile that.

Sure.

You should see some kind of inter-category movement from quarter to quarter as play outlines change and risk factors are modified, but there is no -- maybe Jeff has something.

Just in summary, the actual proved reserves went up from second quarter to third quarter, and our risk unproved reserves went from 2.5 Tcfe the previous quarter to 2.8, so they've actually grown.

What has been a change is that we've made an assumption that some of the acreage will be developed on horizontal drilling so you'll drill fewer wells, but our expectation is you would get more, obviously more reserves per well.

But the growth is up, the growth is still apparent in the area.

Okay.

I will give you a call later.

Thanks.

Thanks, Monica.

Anyone else?

Thank you very much, gentlemen.

You do have a question from Kent Green from Boston American Management.

You may proceed, Kent.

Yes, great quarter, Aubrey and fellows.

Question pertains to MLP and other monetization of outside assets which could be detached.

The primary question is, when do you figure out that you want to sell it into these tax deferral type situations or whether you want to own part of the MLP and the GP because of its potential in the future?

And then also, that really pertains to production assets versus, say, midstream assets such as pipeline gathering systems, storage, et cetera, et cetera, compression.

I will take a swing at that pitch.

We've been pretty clear that it is not our intent to form any kind of producing asset MLP.

We think that there are some potential governance issues and conflicts that might exist with our business strategy if we were to form our own production MLP, and instead we would rather go either the pre payment, the VPP, the NPI, or just an outright sale of those assets.

Again, carving out deep rates and development rights and essentially just selling a stream of existing production into what will generally be labeled either the financial market or an MLP market.

Where we really see the opportunity for us, though, is to take a very latent type of asset which is our midstream asset base, where we're growing it in excess of 100% per year and form a separate MLP, which ultimately probably will become a public MLP but not initially, and use that marketing to raise the funds to continue to grow that asset, and then as it becomes a little more mature and the growth rates drop, perhaps into the 30 to 50% per year forecast, then to take advantage hopefully of the public market.

Whether we remain the exclusive G P or not from a financial standpoint, we're going to remain the operator, and these assets will be managed by Chesapeake and Chesapeake employees and the financial outcome, with respect to either a private partner or ultimately public partners, I am assuming will be just like every other MLP, there will be incentive distribution rights and there'll be governance -- independent governance all of which is yet to come, and we are not close to doing that, but hopefully that answers your question.

There is a big distinction in our mind between a midstream MLP and a producing asset MLP, and we don't have any plans to go into the producing asset MLP market.

Thank you for that clarification.

The second question pertains to the controversy the entire company about whether you're going to keep issuing share counts, buying everything in sight, want to move into the oil field, want to go offshore, never going to sell anything, and then whether you're going to harvest this large amount of land acreage and unconventional drilling potential that you've had going for a number of years, seems to be two sides to this issue.

Just wondering if you would reiterate the plan that you said earlier?

Sure.

I hope there is not too much controversy over most of those things now.

I think we've been quite consistent in communicating what our plans are.

We have no intent of moving offshore or going to the international markets.

We're in all of the major plays east of the Rocky Mountains that we currently want to be in or see opportunity in.

We have reduced the amount of capital expenditures this year over last year with respect to acquisitions, and we've got budgeted reductions going forward.

We've made it quite clear that we are not in the market to issue additional shares or additional debt, and in fact our plan will be to reduce the amount of capital expenditures in combination with operating cash flow and asset monetizations such that we should have surplus cash that will further reduce our bank lines.

So hopefully all those things are clearly set forward in our investor presentation and anybody that will take the time to go through what's probably one of the more detailed presentations in the whole sector I think the plan should be very clearly laid out there.

Thank you very much.

You're welcome very much.

Thank you, gentlemen.

You do have a follow-up question from David Heikkinen.

You may proceed, David.

Marc, could you just compare and contrast the prepay accounting asset sale with the VPP?

Just want to understand the logic of the two different structures.

I think actually the VPP and the prepay are virtually synonymous.

Neither one are taxable at the moment of the monetization, and for book purposes both are treated as deferred revenue rather than an asset sale.

So VPP and prepayment accounting is essentially a deferred revenue accounting, and what you're contrasting are those two against an asset sale, where the asset actually leaves your books and there is no further income statement treatment in the future.

Okay.

Thanks.

Okay, David.

Thank you, gentlemen.

At this time you have no further questions.

I would like to turn the call over Aubrey McClendon for closing remarks.

I have none.

Appreciate your participation in the call.

Give us a call if you have any questions.

Thank you.

Bye, bye.

Thank you, ladies and gentlemen for your participation in today's presentation.

You may now disconnect and have a wonderful day.