Chesapeake Energy Corp (CHK) 2008 Q3 法說會逐字稿

Good day everyone.

Welcome to the Chesapeake Energy conference call.

Today's conference is being recorded.

At this time, for opening remarks and introductions I turn the conference over to Mr.

Jeff Mobley.

Please go ahead, sir.

Good morning and thank you for joining Chesapeake's 2008 third quarter earnings conference call.

Hopefully you've had a chance to review our press release we posted to our website yesterday afternoon.

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

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

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

Additional information concerning these statements is available on the company's SEC filings.

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

These are all non-GAAP financial measures.

Reconciliations to the comparable GAAP measures can be found on page 16 of our press release issued yesterday afternoon.

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

Our prepared comments should last about five to 10 minutes this morning then we will move to Q & A.

Aubrey?

Thank you, Jeff.

The third quarter of 2008 was the most successful, yet the most unusual in the company's history.

On June 30, Chesapeake stock price was $66 per share.

Natural gas prices were $13 per MCF and oil prices were $140 per barrel.

Just 100 days later, Chesapeake's stock price was down 75% and natural gas and oil prices were down 50%.

And yet, during that 20 days, and the 20 days since that period, the company's expected operating cash flow and earnings for the fourth quarter of 2008 and for the full year 2009 and 2010 remained unchanged.

These are indeed unusual times, but I am absolutely convinced that better days lie ahead for all of us.

Because we just hosted a two-day investor conference two weeks ago, Marc and I will both keep our comments brief today.

For my part, I just wanted to share with you 10 observations about the quarter behind us and the world before us, and then I will turn the call over to Marc.

First, we open the third quarter with a bang and announcing a very innovative sale of 20% of Chesapeake's Haynesville acreage position to Plains for $3.3 billion in cash and drilling carry.

This was a great transaction for both parties and established a $13 billion value for our remaining 80% in the Haynesville, a value that today, ironically exceeds our entire market cap.

That does seem very unusual to me.

In the Haynesville, our results continue to be impressive.

We're producing more than 80 million cubic feet of gas per day there and our two most recent wells, both of which have the name Walton on them, are producing a combined 25 to 26 million cubic feet of gas per day.

Second, in early August, we completed another innovative JV transaction.

This time in the Fayetteville shale with British Petroleum to whom we told 25% of our Fayetteville assets for $1.9 billion, leaving our remaining 75% position in the Fayetteville worth about $6 billion or roughly $10 per share which is about one-half of our stock price today.

For the record, only about four percent of our proved reserves are booked to the Fayetteville, yet this transaction alone established a remaining Fayetteville value equal to 50% of our stock price.

Again, very unusual.

Third, after that we sold our Arkoma Woodford assets to XTO and to British Petroleum for $2 billion or over $3 per share, and at the time of the sale, less than 2% of our proved reserves were in the Arkoma Woodford.

Fourth, also in August we sold our third volumetric production payment or VPP for $600 million at a value of $6.27 per MCFE.

You might have noticed our year-to-date finding and net acquisition costs were only $1.35 per MCFE.

I like finding gas for less than $1.50 per MCFE and selling it for up to four times that amount per MCFE.

I believe property sales can and should remain an integral part of our business strategy.

Some people seem to question the wisdom of that strategy, but I wonder why.

Why hang on to every MCF you find to sell at a distant time in the future at some unknowable price?

Why not sell some MCFs now at a big profit and take some chips off the table?

We think it makes great sense to do so and believe that credit markets will likely improve from here, giving us more confidence about our ability to continue selling VPPs later this year and in 2009 and 2010.

We also believe the asset acquisition market remains more liquid than other people give it credit for and believe that will strengthen in 2009 and 2010 as well.

Fifth, our hedging positions demonstrated their value as they created over $6 billion of mark-to-market value improvement during the quarter leading to record earnings of nearly $3.3 billion.

Sixth, our quarterly production reached a record level of 214 BCFE.

This is despite asset sales, involuntary hurricane shut-ins and voluntary price related shut-ins.

Our asset portfolio is performing very well,and as we outlined in our investor and analyst meeting earlier this month, many years of continued production growth lie ahead particularly given the ongoing impressive results from our big four shale plays; the Haynesville, Marcellus, Barnett and Fayetteville.

Seven, our proved reserves have increased to 11% year-to-date to 12.1 BCFE or 2 billion barrels of oil equivalent even after sales of over 600 BCFE of proved reserves during the first three-quarters of the year.

This was achieved by a very attractive year-to-date drill bit finding cost of only $1.94 per MCFE for almost 2.3 TCFE of additions.

Our finding cost goals for 2009 and 2010 remain the same, and that is to find and develop about 3 TCFE of natural gas every year for between $1.50 and $1.75 and to produce about one-third of that and add the remainder to our proved reserve.

We're excited about taking advantage of the upcoming significant reduction in drilling and completing costs as well as the almost $3 billion value of the drilling carries we have earned through various joint ventures.

As I mentioned at our analyst meeting, I also would like to highlight that the SEC is in the middle of amending the modernizing the reserve recognition standards which we think will have a significant uptick -- will provide a significant uptick in Chesapeake's proved reserves such that it is possible by the end of 2009 and the beginning of 2010, Chesapeake could have 20 TCFE of proved reserves.

Eighth, our DD&A rate declined 15% year-over-year from $2.57 per MCFE to $2.25 per MCFE.

We would suspect that no other large E&P company, or for that matter, any E&P company, has been able to generate a similar reduction in their DD&A rate during the past 12 months, especially during the inflationary part of the oil and gas business cycle that we have experienced during the past year.

Our goal is to take advantage of the current deflationary part of the cycle, utilize our drilling carries and execute further asset monetizations at attractive prices to drive our DD&A rate well below $2 per MCFE for both 2009 and 2010.

Ninth, we remain optimistic that our previously announced asset monetization plans for the fourth quarter of 2008 remain on track.

Our goal is to end the year with approximately $3 billion of cash on hand or bank credit availability, and to grow that cash stock pile by at least $1 billion per year in each of 2009 and 2010.

Tenth, and in conclusion, I am enormously proud of our company's achievements during the third quarter.

Although natural gas and oil prices have both dropped by more than 50% in the past four months, it is only a matter of time before demand growth kicks back in and supply growth, especially in oil, will inevitably lag and prices will likely rise in response and maybe very significantly.

In my view, deferred demand growth is much easier and faster to restore than deferred supply growth.

I would like to end on an optimistic note.

No matter how high oil prices become in the future, I believe we will always have sufficient quantities of clean burning, affordable, American natural gas to save the day, and I look forward to watching it all play out very profitably for our shareholders in the years ahead.

I will now turn the call over to Marc before we head to Q & A.

Thanks Aubrey, and good morning.

Happy Halloween to everyone.

As Aubrey noted, we completed a two day investor conference here in Oklahoma City just two weeks ago and remind that you the webcast replay of that with slides is still available, so I will be very brief here this morning.

In the asset disposition area, we continue to work, as Aubrey mentioned, on the Marcellus joint venture, the south Texas asset sales where bids are due next Tuesday.

We have had very good interest in those assets.

On the VPP transaction, what we call VPP Number 4, we have had several serious indications of interest.

We closed on our south Oklahoma asset package for $180 million in proceeds.

And our Chesapeake Midstream bank facility is now closed at $460 million of committed availability.

We have worked hard over the last two weeks to restructure many of our kickout swaps for November 2008, through October of 2009.

We have generally restructured most of those into straight swaps or collars.

Most, but not all of this restructuring shows up in our new hedging guidance contained in the press release.

Also, we are restructuring calls as we speak.

Previously written, we're restructuring those into collars as there is virtually no chance an $11 or $12 call will be "in the money".

Further reductions in CapEx, particularly in acreage acquisition, are underway.

And as a lack of new leasing activity occurs across many of our plays, acreage prices are falling, particularly in the Barnett and in the Haynesville.

Finally, I would note we have exchanged some convertible notes, highly discounted for common stock in the last couple of weeks.

And just to alert you, there will be an 8K filing on that this afternoon that I want to call your attention to.

Moderator, let's open up our question-and-answer session please.

Thank you.

Today's question and answer session will be constructed electronically.

(OPERATOR INSTRUCTIONS) We will take as many questions as time permits, and we will take your question in the order that it was received.

And our first question comes from Tom Gardner with Simmons and Company.

Aubrey, how are you doing?

I am doing good, Tom, thank you for asking.

All right.

Hey, Aubrey we're seeing CapEx reductions 20% to 25% announced by publicly traded companies.

Wanted to get your thoughts on what that meant to a reduction in rig count, and how fast you think gas supply responds to that reduced rig count.

Tom, like everybody in the industry, we have been thinking about that a lot.

And I think you know over the past 60 days or so, we pulled our own CapEx down by $4 billion or so for the remainder of this year in 2009 and 2010.

We hit a high water mark of 158 rigs in August.

We're down to 145 now, headed to a low of 128 by the end of the year.

We do have contingency plans to take that further down if we need to as we have stated before.

We will not outspend our cash resources in 2009 and 2010.

The exact number of rigs that goes away is really anybody's guess, but from my perspective, it would seem to me that probably at least 300 maybe as many as 400 or 500 are likely on their way down, and previously, I guess I would have thought that it would take well into 2009 to achieve those levels, but I think with the credit crunch now probably playing a bigger role even than lower gas prices in affecting producer's drilling plans, I think you will start to see that melt away pretty quickly.

The only reason that I think it might be stickier than what anybody from the outside looking in would say, is that companies do have -- often times have multi-well rig commitments or even multi-month or multi-year rig commitments.

So, that will keep things perhaps a little stickier, and maybe that's why things haven't dropped off as quickly as some people think.

So with that, I suspect we will start to see much healthier supply/demand balances in the first part of 2009.

Certainly by the summer of 2009, I think things will be back on the upswing and I think I can almost guarantee a much better 2010 than I would have guessed just a few months ago.

I am pretty upbeat about where we're headed with gas prices, say, in the next nine months and beyond.

And also, I think gas will be treated very favorably, in an Obama administration, if he were to be elected, and I think that there is a number of other favorable macro trends out there that will help natural gas prices in the years ahead.

Thank you for that.

I just -- with respect to the asset -- M&A market, if you will.

Can you give us a sense on where that is today relative to where it was?

I mean, perhaps as a fraction of value, what are you sensing?

What does it take to get a deal done relative to what expectations might have been six months ago?

Well, I mean clearly, values are down, but so is the value of the enterprise that is selling those assets, so I think on a relative basis, things remain pretty much as they were, if you look at it just on a relationship between commodity prices and asset prices and companies, corporate values and asset prices.

So we heard it two weeks ago at our investment conference, that people think there are no buyers for assets in the industry, or that if there are, they can't get any credit and we're just not seeing that.

But we'll get some feedback next week on an asset sale.

We're working on another VPP, as Marc talked about and have had multiple parties express interest in that.

So clearly not the easiest time, but in terms of whether or not there is just a complete shutdown in asset activity, I have never seen it in the past and I don't believe it is true today and I think that we will be successful in achieving our objectives as we have laid them out for the fourth quarter.

Thank you for that Aubrey.

Just one last housekeeping question, then I will hop off.

Just wanted to understand the driver behind the reduced 4Q guidance in yesterday's release.

Yes, simply -- I believe it is all responsible to shut-ins.

We have about got about 100 million a day, net shut-in, I believe that's about 160 million a day of gross gas shut-in.

And we have seen some real dislocations in the Mid-Continent gas price market in the last 60 days or so, and we expect these to continue into November...December it's anybody's guess, but we decided to go ahead and in our guidance, assume that we kept those volumes off the market.

We're being affected by some REX issues right now and some back-up issues that we think some pipelines that come on line in December of this year and also in the first quarter of '09 are likely to help fix, but Oklahoma gas prices are pretty poor right now and as a consequence, we have elected to shut-in some of our Oklahoma production rather than let it go on the market at what we think would be prices that would diminish shareholder value.

I understand.

Thanks for the color, Aubrey.

Okay, Tom thank you for your question.

Our next question comes from David Heikkinen.

The question, kind of looking at the amendments, the senior note indentures and repayment -- or conversion of the converts and then the also repayment of the $300 million of notes.

Could you just walk through the logic of each of those transactions and what the benefits are of each?

Sure.

I will take a stab at that David, sort of in reverse order.

The notes that we have redeemed for common stock, I think that's a pretty obvious value creation equation.

These notes are currently in the market trading for as little as $0.45, $0.48 on the dollar, and we're able to go out and give current value of common stock to redeem those, not costing us anything in cash and equating to selling stock at substantially higher values if you use the inverse of that.

And that's before we count the value of interest saved and future potential dilution when the stock returns to levels that were originally contemplated when those issues were issued.

On the amendments, the single amendment that we passed around that covered several qualifying or quantifying situation, that was simply to allow us to freely transact our bank credit facility in Chesapeake Midstream.

And, there was -- in some of -- actually, what we call our investment grade indentures there was some question as to whether having a restricted versus unrestricted conflict which wasn't contemplated in those indentures, this is fairly technical, but whether or not that was actually doable so we were making sure that that language was clear and acceptable for the transaction that we did and we had to do that to actually put in place our credit facility down at the Chesapeake Midstream level which is an unrestricted subsidiary for our non-investment grade indenture language.

Was there one other question embedded in the middle?

Talking about the senior note redemption that started the third quarter as a follow-on from the nets we issued in the second quarter?

Oh, the $300 million issue was simply called at the time and replaced, because the replacement debt costs were less than the call value, and it actually -- we extended the maturities on that, we were able to call them at no present value costs, and that's something that we have routinely done when it makes sense.

We actually have another note issue that is callable as of this past September.

Obviously, the interest rate costs on the existing notes are much less than what we could replace it for.

So, we have not chosen to call those.

Okay, that's perfect.

And on the comments about new SEC reserves, a lot of that additional reserves is just bookings offset to horizontal wells.

Can you kind of walk through where you see the biggest changes?

Is it mainly just in your horizontal shales, or what are your initial thoughts there?

It is wherever -- I think the words are continuous accumulation reservoirs and ideally, or more likely, that does cover the shales.

But there will be some plays in our, say in Oklahoma and perhaps up in the Sahara area and maybe in western Oklahoma where we can prove that a reservoir extends across a large area and that we're not restricted to one offset per proved developed producing rule.

So it has been something that we have been working on, really for the last couple of years, because it has been my view that we have been making poor public policy choices with regard to natural gas for years based on the perceived shortage of natural gas or scarcity of natural gas and that is normally arrived at by market observers through noticing that the industry basically never has more than a 10, 11, 12-year RP.

So some of our competing fuels are able to point to that short reserve life and say that natural gas is a fuel that can't be relied on to generate more electricity or can't be relied on to fuel our transportation network, and so I have felt personally that it is very important, for the SEC to understand that the rules needed to be modernized from 30 years ago and that by doing so, investors and physical market participants could see just the true extent of the nation's natural gas reserves.

So, we welcome this rule.

We're active in making recommendations and comments to it and expect to be one of those companies that benefits through greater transparency into our asset base and into our proved reserves that will result as a consequence of the modernization of the SEC reserve recognition rules.

If I have got it right, I believe it takes effect for any reserve report prepared as of 12-31-09.

So really, it is defining the field boundaries and extending that to a much larger area, is the biggest change.

Yes, I mean you still have to prove all the things you have to prove today, that the reservoir exists and that it has hydrocarbon in it and that those hydrocarbons are recoverable and we think you'll have to prove that you have got the resources to be able both technological as well as financial to be able to recover those, and I think there probably is likely to be some restriction on just -- on how many years you can assume in your development plan and I think that -- Steve, is that still an item of open discussion?

right?

Yes.

So, that will have some restriction.

Companies won't be able to just say, we're going to be booking PUDs that we will drill over the next 100 years.

That's not going to happen.

So those rules have not been finalized and many in the industry have helped with that and certainly, we have as well and look forward to the final rules being issued in the coming months.

Thank you.

Thank you, David.

Our next question is from David Tameron with Wachovia Securities.

Good morning, everyone.

Marc, can you talk about the cash income tax piece ramped up over the quarter?

Is that just a reflection of the acquisition mix?

Can you talk about that for the fourth quarter?

It is a reflection, Dave, of a couple of different things.

First of all, the additional sales that we have, we have now consumed our net operating loss carryovers both for AMT and regular way tax.

So to the extent we sell properties in excess of our basis, for example, the $180 million transaction we're going to owe cash income taxes.

And also, the second part of that is a reflection of reducing our rig count.

We will have less IDC deductions, and so as we have less of those against the same mix of otherwise unchanged cash income, we will be paying a little bit more income tax as well.

Okay, thanks.

And there's one more question, and maybe this is for Aubrey.

The oil plays that you have kind of alluded to and people, I guess software stand in the lab and on the tour when we're out at the campus.

Can you talk a little bit about the timing of those, where you see that playing out over the next 12 months, when we will hear more about those type of plays?

I think we will know more over the next 12 months.

If you will recall, David, when we talked -- really started to mention these in March of this past year, we talked about, I think five different oil plays, we actually have developed a sixth idea that we're working on, but of those, one was a non-shale play and I think some of you all had an opportunity at the investor day conference to go look at that.

That is the WEHLU, West Edmond Hunton line unit, field up in northwestern Oklahoma County that Petrohawk is in as well.

But that is working well for us and we're looking at extending the field limits of that into other areas surrounding that field where we have an extensive leasehold position.

We are -- all I can say there is that we have rigs at work, testing the extendibility of that concept.

I think our last well in the WEHLU unit came in, Steve or Marc, 500 barrels a day, something?

The last one was something --

It was 400 to 500 barrels a day.

-- 400 to 500 barrels a day.

So those are wells we have found up to half a million barrels of oil per well, and that's an old field developed right before the 1940s and kind of blown down, or blown through during World War II and as a consequence, a lot of oil was left behind.

With regard to the shale plays, I am just thinking off the top of my head, but I think we have rigs working on three of those, I think -- what did you say, four?

Three.

Yes, three of those plays right now, we have rigs that have either just finished drilling and we're analyzing core results, or have rigs on them right now.

So the trick on all these is not so much finding the oil in place, we think we have done that before now.

Now the question is, what is the right technological solution to getting the oil out?

Is it vertical wells on tight spacing?

Is it horizontal wells, is it multi horizontal laterals?

Is there a CO2 component to any of the recovery drive mechanisms?

So I think 2009 will be obviously the year in which we're going to know whether or not any of these oil shale plays work, but we were optimistic seven or eight months ago when we first started to talk about it, and we remain so today.

Okay, and then one more big picture question for you Aubrey.

If I go back to the start of the year, there was a lot of chatter, the capital gains tax was I guess an incentive or a motivation for a lot of private families to sell.

It seems like reading some of the literature now sounds like that capital gains tax may be pushed back a couple of years as far as a potential increase.

Are you hearing any chatter about that on the M&A market?

Is that in the conversations today like it was six months ago?

I am tempted to say something about capital gains and private companies selling stock, but I'm going to not going to go there.

(laughter) But what I -- I think what you're referring to, of course, are oil and gas held in private hands and whether or not we have seen any rush for people to sell prior to that.

And I think people sell all the time for lots of different reasons.

We have bought a lot of private assets over time.

I would think anybody today would probably take the chance on perhaps higher taxes down the road and wait on a recovery in gas prices.

So that's another reason why I think there is going to be good reception for the assets that we we'd like to sell in that a lot of buyers are probably not going to see the traditional flow of assets from private sellers simply because I think they will hold assets off the market in a lower price environment like we're in today.

What happens going forward, don't know, and I will just say one more political comment, which if the election were held today, it appears that Senator Obama would win and we think actually that could be very favorable to natural gas prices going forward.

We feel like President Clinton's policies greatly favored natural gas demand growth.

We feel like President Bush's policies have more favored coal than they favored natural gas, and we look forward -- if Senator Obama were elected we look forward to 4 or 8 years of federal policies that we think will impose some kind of carbon cost on fuels, and we believe that will be very favorable to natural gas and we also view that this administration will be very favorably inclined to try to do something about introducing natural gas into the transportation network in a more aggressive way than what has happened in the past four to eight years.

So we're looking forward to that with some optimism.

All right, thanks.

Okay, David, thank you.

And our next question comes from Michael Hall with Stifel Nicolaus.

Thank you.

Trying to keep it on the policy topics.

Natural gas has proven to be a pretty volatile commodity, relative to some competing fuels.

When you're talking with policy makers and consumer groups, how do you kind of address the concerns of volatility in a fuel as it relates to gas?

Michael, other than just to let everybody know that it is there, there is not much we can do about it, as you well know.

Most of it has to do with weather pattern volatility, and I think most people know we have our own meteorological service here at Chesapeake and I did notice in their report on Wednesday that I think it was Tuesday of this week we set over 200 temperature records in the US, and about 100 were for record cold, record lows and the other 100 were for record highs.

And so that is just a feature of weather patterns today that I thought that day absolutely kind of highlighted that.

I then say to people about volatility that -- I mean, use volatility, take advantage of volatility.

We take advantage of it from a producer perspective.

At the end of the day, I have been on record many times that Chesapeake in general favors low prices for natural gas.

We think it is great to stimulate long-term demand.

We have, we think, at least -- well, more than 12 TCFE approved reserves and many, many 10s of TCFs of probable reserves, and those need to be consumed by somebody some day.

So, we generally favor lower prices.

Having said that, every year or two, we need two or three months of higher prices to get our hedging done and we have been pretty good at being able to take advantage of those market opportunities.

And to the consumers, I say the same thing.

Now is a great time to be locking in your natural gas needs for the next couple of years.

Prices are probably below industry break evens today and any time you can buy a commodity below an industry's break even, it is probably a pretty good time to buy that.

So I think volatility creates opportunities both ways.

It is often times difficult to endure when you're in the middle of volatile swings, but we know that prices will be higher at times in the future, and we will take advantage of that.

And prices will be lower at times in the future, and we hope consumers will take advantage of that as well.

Very good.

And then, we hear about profit shortages in some regional markets in the past have taken an active role in alleviating some supply constraints in the service markets and things along those lines.

Any intention of getting in that market?

Yes, let me -- I am going to make a comment then turn it over to Steve Dixon, our Chief Operating Officer for further comment.

Just to remind everybody, we own 19.9%, I think it is, of Frac Tech Energy Services which Marc Rowland today which is the country's what, third largest --

Second I believe, or third.

I think we're the second or third largest pressure pumper in America, and I think by 2009, the end of the year, maybe 2010, they expect to have the most horsepower.

So, we get pretty good visibility into what is happening in the profit market and have been working with Frac Tech to make sure they have adequate supplies of profit for us, but I will let Steve further comment for you.

That's all I can say about our other vendors also is communication.

We work with them on forecasting our needs and we're a very large customer for them, so we just, through planning, make sure that we have enough profit to meet our needs.

At the end of the day, it is good that it is sand.

It is relatively abundant resource that the earth has.

You just have to have the ability to get it mined and then get it treated if it needs to be resin coated or something like that.

Very good, thank you.

Michael, thank you.

And our next question is from Eric Hagen with Merrill Lynch.

Good morning, Aubrey, Marc.

Some questions for Marc on liquidity.

Can you talk -- during the (inaudible)

Eric, your question is not coming through.

If you're on a speaker phone can you pick up your hand set, please?

Moderator, are we still live on the line?

It seems we have lost Mr.

Hagen.

Okay, let's move on and maybe Eric can come back to us.

Our next question comes from Brian Singer with Goldman Sachs.

Good morning.

Hi, Brian.

Can you give us an update on leasehold values in the Barnett, Marcellus and Haynesville?

Obviously, as you have mentioned, you're probably doing a little less activity than you were, but can you comment on the impact that current markets have had in terms of acreage value today?

Sure, be happy to.

Brian, we have seen a dramatic reduction in leasehold values in the Haynesville and in the Barnett.

I guess I shouldn't use the word values, I should say costs because the values remain very attractive to us.

But in the Barnett, we, I think, led the way by saying that in this gas price environment, it no longer made sense to pay $15,000, $20,000, $25,000 an acre, and we're on public record in Ft.

Worth as not being willing to pay more than $5,000 per net acre there, and I think the rest of the industry has followed suit.

And while we're still all acting independently and competitively of each other, it is an absolute truth that leasehold values have been dramatically pushed down -- not values, sorry, leasehold costs, acquisition costs have been dramatically pushed down in the Barnett.

That is also true in the Haynesville and I they we've had some leadership there as well.

In the Marcellus, actually prices never got -- never went through the roof there, and those prices have remained resilient, and we expect them probably to go up over time rather than go down.

So I would separate the Marcellus from these other two areas.

Particularly, let me chime in on the Marcellus.

We have not seen basis separation there and so the value of both BTU contribution and location of the molecule has further distinguished it from the many other plays, such as the Mid-Continent.

Aubrey mentioned that we have some dislocation going there right now.

We have seen well head prices down in the $3 range in the Mid-Continent recently where well head prices in the Marcellus are $8 or plus.

So, really distinguished that play from the ones back behind the pipeline problems.

Thanks.

So, I guess to tie that in with Tom's earlier question to kick things off, if you think about the amount of acreage or assets that you would be selling in the Marcellus today should we assume that that hasn't changed from where you were a few months ago to get the same cash proceeds or change modestly, or how should we think about that?

We think about it all the time and remain in discussions with multiple parties about our plans there.

So, at this point I will just say that we -- those discussions and negotiations, are ongoing, and we will have more to say when we're able to say more.

Great.

And lastly, when are you assuming that the production you have shut-in currently comes back online and from a Mid-Continent basis perspective, it sounds like you think things can improve, even in the absence of REX East getting Rocky gas away from Mid-Continent area.

Yes, we have formally budgeted for those shut-ins to continue through 12/31, so we will see how that goes.

A lot of it will depend, of course, on weather during the next 60 days or so, but yes, it is not -- it is Rex that has caused the problem and it is now up to two pipeline projects, one that will specifically help -- both will end up helping Oklahoma gas, one more specifically eastern Oklahoma Gas and the other western Oklahoma Gas, and those projects should be completed in the next four to five months..

Actually -- sorry, one of them we completed this year and the other in the first part of 2009, sorry.

Thank you.

Okay, Brian thank you.

And our next question comes from Gil Yang with Citi.

Hi, Aubrey.

I was wondering if you could elaborate a little bit about the SEC rules in the sense of what is your philosophy going to be in terms of taking full advantage of the ability to book more reserves?

Would you do so to the fullest extent allowable, or would you do it more moderately and pace out your ability to keep F&D lower for a long period of time rather than just -- I'm not sure how the rules would be stated, but presumably, if you booked multiple Ts one year, all of a sudden your F&D would be very low for that year.

Yes, we really haven't talked about that internally or reached any conclusions, Gil.

I think it's going to be completely dependent on how the rules are written.

All I've tried to say is that were we under those rules today, our preliminary work would indicate that our reserves would be in the 20 TCF range rather than the 12 TCF range, so there are all kinds of interpretive issues that will come with those rules.

You still have third party reservoir engineers that you will have to satisfy as well.

So it is not simply that the SEC writes it and the industry reacts to it.

You will also have to have kind of three-way discussions with all the third party reservoir and independent reservoir engineers as well.

I can't really predict for you whether or not we would say the rules are the rules and we followed them before to the strict -- in the strictest way possible, and we're going to do so now and so book it all at once, or do more of a ramp-in as you suggested we might want to.

We'll see.

And in terms of what my conclusion will be rather than it vastly understating our costs in any one year, I think what this is going to show is that our costs have been vastly overstated in the past, and I still see some analysts calculating our finding costs by including in that calculation the leasehold that we buy today to which we are not booking any reserves and leading people to the conclusion that our finding costs are $3 an MCFE when they are absolutely not.

So, our company has been buying acreage over the last three to five years that in our view -- not necessarily in the SEC's view, but in our view, had reserves associated with them.

We were not able to book those, but most people did include those costs in their finding cost calculations.

We think that was not the appropriate way to do it, and this will fix that going forward.

So, I think again, we will see not understated costs going forward but accurate costs going forward that will helpfully correct the overstated costs over the past few years, specifically with regard to our company.

Okay that's fair insight.

But the basic message, more directly to my question, just that we should not necessarily expect on January 1, 2010 that you will be at 20-plus TCF.

You may be or may not be, depends on how you implement the rules.

Yes, that's true.

We may or we may not be.

(laughter)

Gil, keep in mind the rules haven't been finalized yet.

We're reacting to a couple of additions of inquiry and response by the industry and at this point, nothing has been finalized so we're kind of speculating here, and I would just leave it at that.

It is speculation as to what the rules will say and how we will react to it.

The second question, Aubrey is, if you do get into this range of 300 to 500 rigs being laid down, what do you anticipate would happen to your service costs in that kind of scenario?

Well, we're very excited to talk about that.

We think it could result in a -- as much as a 15% to 20% reduction.

We think it is already happening today.

Of course, diesel prices are down.

We consume a lot of diesel in the drilling process, and those prices are now in half.

Steel prices have rolled over and we have certainly seen the worst of that and I think we're about to get the better end of that stick.

Drilling rig rates are starting to come down.

I think that will accelerate and then you will see it all across.

We won't be just -- some people I have seen have said well, it is drilling rig rates, it will be cost -- cost across the industry and across all -- sorry, across the industry and across all components of well costs.

So again, we're, I think, the biggest consumer of drilling completion services in the US and these things go up and down and as our margins get squeezed, we think it is only fair, of course, that our partners on the service side lower their prices to enable us to continue to make a profit on what we're doing.

So, we expect to continue to work hard on that and see very visible responses to those initiatives during the next couple of quarters.

Would there be any downward pressure on labor costs possible?

Oh, I think so for sure.

We were already working to get land brokerage costs down, for example.

I can't comment specifically on personnel on rigs, but obviously, with the unemployment rate rising in the US, oil field service jobs are going to become I think even more competitive in the future, and we will see more people try to get those jobs, so I would expect labor costs to go down throughout the industry as well.

And how about operating costs?

Other than fuel component operating costs, which obviously would be down.

Well, one of our components that definitely will be down is ad valorem taxes.

Many of our states have ad valorem taxes which, on an annual basis, is assessed on the value of the oil and gas in the ground, and that value is based on the well head price.

So if prices are down 50%, ad valorem taxes without a rate increase would be down 50% as well and that could easily change operating costs for us by a nickel an MCF just right there, which is approximately 5%.

The other components which are pumper fuel costs, driving their pickup trucks, diesel and so forth --

Chemicals.

Chemicals, all of those kinds of things will be off and are already coming down.

Okay, great, thanks a lot.

Our next question comes from Eric Hagen with Merrill Lynch.

Thanks good morning, I'm back.

The question was for Marc.

In light of the comments you made at the analyst day, that your working capital -- I think you said it could swing by $600 million, $700 million either way each month.

Given you ended the quarter with about $1.9 billion in cash and cash equivalents, can you give us an idea of what you have on the balance sheet now, cash and cash equivalents, and how that might look at the end of this quarter, if you don't get the asset sales, the planned asset sales done?

Sure, Eric.

Today we have well over $1 billion dollars in cash on our balance sheet.

And I did say that at any 30 day period, as cash comes in and goes out during the month, that you can have $600 million think to even $800 million of swing, depending on prices.

Obviously, our plan is to have several deals closed by the end of the quarter, and we talked about our projected cash balance.

To the extent any one of those doesn't close, then it would reduce the expected cash on hand, but, I don't know how to handicap what is four or five different transactions, each one has a substantially different potential value.

The bids for our south Texas assets I mentioned are due next Tuesday.

I haven't seen any bids at this point, so I don't know what the expected value or whether we will even sell if the value is not there.

But we have had a lot of interest.

Many people through, some have already sent notices confirming that they have fully financed offers and to make sure that we don't sell before they get their chance to bid.

So almost impossible to answer the question without knowing the results of each one of these different transactions and the amounts.

So we will just keep adequate liquidity and -- as we have in the past.

And adequate liquidity would be that $600 million or $800 million you need to manage that working capital swing?

Is that correct?

I think -- yes, Eric I think at the investor day, I said that was the swing, and that on top of that then, we would want to keep $0.5 billion to $1 billion of surplus.

We want to have as much liquidity as we can, obviously.

Okay, and the follow-up final question was, what is the rationale -- beyond the $3 billion target, Aubrey mentioned you were going to add a $1 billion per year of additional cash and cash equivalents.

What is the rationale behind keeping that much cash on hand?

We would love to be able to pay our bank lines down.

We just want to make sure the banks are capable of giving it back to us if we need it.

So when we talk -- I think it's unlikely we end up at 2010 with $5 billion of cash and a $3.5 billion revolving line of credit fully drawn.

We do anticipate at some point things get back to normal.

The rationale is simply that we think it makes sense to build cash over time and use that cash to buy back debt, opportunistically or perhaps stock, and we have obviously answered a lot of questions over the last few months about cash, and those do become tiresome over time.

So, we want to make sure that we always have plenty of cash on hand and people find something else to worry about besides that.

Okay.

Thanks, Aubrey.

That is more of a like a free cash flow number.

I won't ask any more questions on cash.

Thanks, appreciate it.

(laughter) You can.

I will just tell that you they become tiresome after awhile.

All right.

Thanks, gentlemen.

And our next question comes from Michael Ainge from TIAA-CREF.

Can you hear me?

Yes, Michael, we can.

Actually, my question has just been answered so thank you.

Good to know you're on the line.

And our next question is from Jeff Davis with Waterstone Capital.

Thanks.

Curious, what is the total amount, if any, of committed leasehold purchase -- committed but unpaid leasehold purchases?

Jeff, this is Aubrey.

That's not a number that we discuss publicly.

We always have a backlog of projects underway, or -- I guess, undertaken.

Some of which are subject to, negotiations, some are subject to hand shakes and some are subject to definitive documents.

Okay and then what should we think about G&A costs as the company gets a little smaller here as lay down some rigs, those types of things.

It is up 75% year-over-year.

How should that kind of go, moving forward?

Okay.

The -- I mean, the company is not getting smaller, so the first part of your question, I will say that while I acknowledge our G&A cost have been higher, but you said as our company gets smaller over time, we'll actually probably become somewhat less active, but we will be increasing our production, as I am sure you have noticed, by 17% in 2009 and 16% in 2010.

So, on a compounded basis, in two years the company will be probably a third higher.

I will take probably personal responsibility for a good bit of the G&A expense increase, which is as we have embarked over the last six months on a public education campaign about the values of natural gas, all that has flown through the G&A account.

If you look back at our G&A over the past four or five years, basically, it has remained pretty much unchanged in the, oh, the, let's call it the low-to-mid-$0.20 per MCFE.

And just as the company added people over time, we added production and so, there was proportionality between G&A costs and between the size of the company and number of people.

But we have spent several tens of millions of dollars in the past six months and especially in the third quarter promoting our product.

Given all the financial crisis concerns of the past month or two and given the political campaign, we decided to dramatically reduce our advertising campaign over the last 30 days given that we just didn't think it was money well spent in this environment, and so we kind of got it on the shelf, and we will wait for the new president to come on board and new Congress to convene and then consider what needs to be done at this point.

But we're the only industry I know that really doesn't do much to try to stimulate long-term demand and for its products.

And I don't particularly understand that, I certainly don't agree with it.

And we hope to develop some conversations with some of our colleagues over time to make sure that they are doing that, that they are helping out as well.

But for right now, we're not spending as much as we were and that is I think the most significant factor in the G&A cost increase versus the previous quarter and also year-ago quarter.

Okay.

Marc, the converts you talked about inducing, is that the preferred or is that actual, the notes?

Actually, that is the 2.25% and 2.5% and 2.75% convertible notes, and I hope I didn't use the word induce, we don't have any program.

We've just been approached on an unsolicited basis by numerous holders of those.

Evidently, and I am not expert at this, but evidently in the convertible market, the opportunity for those people to sell on in this market has been particularly hampered by some people's perception of not being able to short certain stocks and do an arbitrage on those.

So particularly in those converts, the value went down substantially.

I saw some trades on the 2.25 notes that were as low as $0.45 on the dollar.

And about two weeks ago, we began to be approached by some holders of those, when they couldn't evidently develop liquidity, they were willing to trade for common stock at those distressed values -- in our perception, distressed values.

And then, evidently, satisfied their previously shorted positions by us delivering stock forms, so that's what we have been doing.

We have not done anything recently on the preferred stocks, I think 90 to 100 days ago was the last preferred stock we did, and that was a relatively small amount.

I would like to emphasize that the program is one that has been opportunistic and been driven by the face value of those instruments.

It is not that we want to issue a bunch of equity at $20 a share, it is simply that if we can reduce a liability --

At $0.45 on the dollar.

It seems to make pretty good sense to us.

Yes.

By the way, are you doing that at parity or parity plus something?

Well, we are doing it at -- if you were to look at the conversion, technically, I think you're referring to what the notes would be convertible into.

Yes.

It is slightly greater than parity, but we look at it as face value.

If is $0.45 or it's $0.52 or $0.53 on the dollar at face, parity doesn't mean anything if you're not in the money.

What is the notional of -- how much have you done of that?

We have done just over 300 million so far.

At face.

Face value, yes, right.

And the VPP looks like the midpoint and the update last night -- I wasn't down at the analyst day meeting, but I think it is a little bit lower than you guys had communicated in the past.

I was thinking 600 million.

The midpoint is now 450.

Is that a function of lower prices, is that a function of what is going on in the credit markets, continued choppiness, what is going on there?

Yes, I believe it is identical to what we said at the analyst day.

It is down from our earlier guidance when we first initiated the efforts to get it done.

It is a function of the discount rate effectively increasing in this credit market and of lower future gas and oil prices.

Okay.

That's it for me, thanks.

Thank you.

And our next question comes from Marshall Carver with Capital One.

A quick question on your two most recent Haynesville wells.

Were those in Southwest Caddo where most of your activity has been concentrated, or were those some of the stepout wells that you mentioned at the analysts meeting?

They were not stepout wells.

I think these are in 15-16 or 15-15, I'm not quite sure of the township.

I think Steve or Mark might be able to come up with that, Dixon might be able to, but they are in the same general area as Southwestern Caddo.

The other wells are all underway, and I don't believe we have completed any of the ones that would be starting to kind of look at the four corners, although of course Petrohawk has had excellent results in their Elm Grove area and other people at some four corners are doing as well.

There have been disappointing results perhaps to come out of some of the play in east Texas.

I just remind you what we reminded everybody of at the conference which is, when we started in the Barnett, we started with a very specific buy area that was essentially two counties, Johnson and Tarrant.

And a lot of people wanted to buy acreage over 17 counties and we said we acknowledge the rock exists under 17 counties, but we're going to go where we think the best is, and the Haynesville today -- we have an outline of where we want to be that is just under 3.5 million acres, and a lot of people claim to have Haynesville acreage and they do, but just remind you that not what everybody else claims is Haynesville perspective is something that we would give any value to.

So people need to be prepared for disappointing results from time to time from companies that do not have assets in the heart of the play and we're still very excited about what we're seeing there, and I think these latest two wells -- Steve Dixon, were we eight stages or 10 where were we on those?

Those were 10, I believe.

I think these were our first two 10-stage completion treatments and they are not --

Those were in 15-15.

They were in township 15 north, 15 west.

And not coincidentally, they are our two best wells so far, I think.

Okay, thank you very much.

Okay Marshall.

And our next question comes from Monroe Helm with CM Energy Partners.

Thanks a lot.

This is for Marc Rowland.

Just trying to -- I will probably get in trouble for asking about cash flows again, but just looking at what you reported in your second quarter Q about the proceeds that were coming in after June for the cash portion of the Plains sale on Haynesville on a volumetric production payment, Woodford sale, common stock offering, looks like that was about $5.3 billion in cash coming in.

Looks like your CapEx to that cash flow difference in the third quarter was a shortfall of $300 million, so that leaves about $5 billion of cash, it's a little hard to reconcile on your abbreviated cash flow statement, but you've got cash then to the third quarter of $1.96 billion, which included $1 billion dollar draw down to your bank line.

So I am just wondering what happened to the other $4 billion of cash.

I can't quite follow all of that.

But generally, I think you're asking what is the reconciliation of all of our expenditures for the quarter.

Obviously, we will have a complete detailed analysis here in another week on our 10-Q which will identify every item.

We tried to identify most of it, in our reconciliation of expenditures on page 12 of our press release, but I don't have in front of me, nor am I going to go through every --

Monroe, the obvious answer is that most of it went to Haynesville acreage, and we have said on page 12 how much went for acquisition of approved properties and it hasn't been much this year.

If you looked at unproved properties almost $7 billion, so --

Okay.

Those are year-to-date numbers, but you can go back to the June 30 and solve the differences between those two.

Okay.

So it is pretty transparent.

I am sorry, I don't have that break down right in front of us.

That's okay.

It also -- just to follow-up, there is a big change in working capital between the second quarter and the third quarter.

It looked like a swing of over $4 billion.

And, just wondered if you had any comments on that.

That's an easy one as well.

There has been some change and there frequently is, but I think you will find a lot of that is related to the derivative change.

Short term derivatives of the value of our obligations that come due in a year under our derivative programs.

I think at the end of the second quarter, Monroe, if I recall, there was something like $4 billion of short term liabilities that were related to our mark-to-market losses on derivatives which would have gone away in this quarter.

Okay, well thanks for your comments.

Okay, Monroe.

Thank you.

And our next question comes from Joe Magner with Tristone Capital.

-- At the end of the quarter, you recorded actual balances around $2 billion.

At the analysts meeting you mentioned cash at the end of the third quarter was around $1.5 billion.

And then also year-end balance of cash and available capacity expected around $3 billion, down from 3.5 you discussed at the analysts meeting.

Can you just explain maybe the reason for the difference in the actual Q3 balance, and then, any changes or to either the timing or the expected value of any of the divestitures in the fourth quarter that may have affected that expectation?

Well, I'll take a crack at that.

I think I did use the number of approximately $1.5 billion.

I was hoping to be, and I was in fact, conservative.

We hadn't closed out our final books yet and it turned out to be 1.9 and some change, billion dollars versus the 1.5.

With respect to our expected cash, as of 12-31, it is not materially different than what we talked about before.

We have reduced our expectations, as we just talked about slightly for the VPP and perhaps the asset sales.

But again, hopefully we're trying to be conservative on that.

Okay.

I guess the change from -- well --

If you will look at the second page of the outlook, you will see that the potentially cash resources is very similar to the October 14 guidance.

The only minor difference that is we're using a lower range for Nymex gas prices in the fourth quarter.

Yes, our operating cash flow expectation went down a couple hundred million dollars alone for the fourth quarter simply because of -- we moved our gas price expectations down.

And already have knowledge of what October gas prices were.

Okay, thanks.

And Aubrey, just one question with respect -- you mentioned comments about excluding leasehold costs from your F&D calculations.

Can you just explain how and when those costs are ever accounted for or when you capture those in your F&D calculations?

Yes, when they go in -- when they move through the whole cost pool, obviously, we think our DD&A rate is a pretty good way to look at what our finding costs are.

So I -- you could do it that way.

And going forward, it depends -- we always report out what our actual finding costs were, on a per MFCE basis for the quarter - excluding those costs, and you can do it any number of ways.

One, you can add back, as some people do, all of current quarter costs and the current quarter drilling, you will get a number.

The number will be meaningless as to what we actually did during the quarter.

Or you can develop your own math and say, as the company works through its leasehold inventory over certain number of years, you can allocate part of that.

Or you can simply do it the way GAAP requires you to do it, which is, as we evaluate leasehold we move it from the unevaluated to the evaluated, and it moves through our cost pool that way.

Okay.

Just -- yes, I guess it just seems like in the way it is reported or calculated, it never quite gets captured in the quarter-to-quarter evaluation but --

Well, I think it is pretty clear that when we report what our costs are, we always give it to you every way.

Which is we give it to you for drill bit finding costs, we define those drill bit finding costs.

We give you acquisition costs, and we define what those are.

And then we give it to you on the roll forward on page -- Marc is looking for that, where it puts it all in.

And then we also give it to you net of acquisition, or divestiture proceeds as well.

It is a calculation that seems like everybody has their own little approach as to what is the right way, so I think we try to give you four different ways to look at it.

Thanks for your comments.

Okay, thank you.

Our next question is from Michael Hall with Stifel Nicolaus.

Thank you for follow-up.

I wanted to summarize what Gil was getting at on cost, maybe wasn't getting it, but I want to see if you could summarize where you think break even costs are moving, or industry's break even price as you see all those costs coming in.

I think you're seeing, a real bifurcation in the industry develop, something that I don't think we've really had in the past where the shale players are going to have significantly lower break even costs than the conventional players.

I know it is conventional wisdom in the industry to consider that shale costs break evens are higher, but that is not actually the case.

Certainly not the truth in our company and finding costs and our four important shale plays on drill bit costs alone are all under $2 whereby -- but in comparison or contrast that the finding costs in most of our conventional plays are well over $2.

So, we also are the nation's most active non-operater and have an insight into what other companies costs are.

I think during the quarter, we were using an average of 118 non-operated rigs, so we get great information from what everybody else is doing and we see, again, this clear line developing in the industry between the haves and the have nots on shale.

The haves, with regard to shale, I mean there are probably only a dozen companies that really matter when you look at shale and probably only half a dozen of those that are the key drivers in the shale plays.

We see that in general, as the industry moves forward, that you're likely to see higher finding costs across the industry and higher break evens, yet we believe our break evens will be moving lower, and believe that all shale players break evens will probably be lower as well over time.

So the rig lay downs in my view are likely to come more from the non-shale plays than from the shale plays.

Thank you.

(OPERATOR INSTRUCTIONS) And then we'll pause for just a moment to give everyone a chance to signal.

Our next question comes from Dustin Hansen with Wells Fargo.

Hey, good morning gentlemen how are you?

Doing fine, thank you.

Excellent.

I had to step away for a second.

Can you tell me -- I understand that the south Texas asset packages, bids are due next Tuesday.

But can you kind of give me a -- when do you expect the anticipated closing of those divestitures and then also the Marcellus joint venture.

We still expect both of those to close in the fourth quarter and since it is October 31, we're -- it won't happen this month.

Probably happen in late November or early December.

So we will -- got a couple holidays to work around in there, but we're quite confident, again, that we will be able to get something done on both of those.

The good news is, we don't have to have them both.

And of course, we got a VPP in there as well, so we don't know yet which of these will end up with attractive results, but there is a good chance that all three of them will, if not, any one or two of the three will be fine to meet our liquidity goals.

Thank you gentlemen.

I think that wraps the call up.

It just wanted to mention also that we will a press release this morning that -- I don't know how many of you all saw, but wanted to highlight that we added a new gentleman to our senior management team, Mike Stice comes to us from Conoco Phillips.

Mike will be President and Chief Operating Officer of Chesapeake Midstream Partners.

This is our Midstream limited partnership.

Also, Mike will have the title of Senior Vice President of Gas Projects, and Mike comes to us with an extensive background in liquefied natural gas projects, both on the re-gas side and on the liquefaction side.

Very excited about Mike joining the management team, and as we look to broaden our initiatives with regards to expanding demand for US natural gas, we know that Mike Stice will be a key player with us in that, and we welcome Mike, who will be here this weekend to start working on Monday.

So thank you very much for your attention today.

If you have any additional questions, please direct them to Jeff.

We would be happy to respond.

Thank you.

And that does conclude today's conference.

You may now disconnect.