Chesapeake Energy Corp (CHK) 2008 Q4 法說會逐字稿

Good day, everyone and welcome to the Chesapeake Energy conference call.

Today's conference is being recorded.

At this time, I would like to turn the conference over to Mr.

Jeff Mobley.

Please go ahead sir.

Thank you.

I would like introduce the other members of the management team who are with me on the call today.

Aubrey McClendon, our Chief Executive Officer, Marc Rowland our Chief Financial Officer, Steve Dixon, our Chief Operating Officer and Mark Lester, our Executive Vice President of Exploration.

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

I now turn the call over to Aubrey.

Thanks, Jeff and good morning to each of you.

I believe our results for the year 2008 were very good, especially when you consider that we were required to take a non-cash after-tax impairment charge of almost $2 billion and yet we were still profitable by more than $600 million for the year, stripping away impairments and other non-cash items, during 2008, we earned almost $2 billion in net income, on record production of 843 bcfe.

Operating cash flow exceeded $5 billion and adjusted EBITDA exceeded $6 billion, both of which were company records.

Also in 2008, we sold undeveloped leasehold that had a cost basis of only $1.1 billion for $4.5 billion -- sorry for $5.3 billion in cash, and $4.6 billion of future drilling carries creating $8.8 billion of profit in the process.

And importantly, we retained a stake in the assets worth an indicated value of $26 billion.

On the operational side, we discovered the Haynesville Shale and built a dominant leasehold position in this field, which we expect to become the largest producing gas field in the US by mid-decade.

Furthermore, we helped to prove the Marcellus play as highly commercial and established the largest leasehold position in that play.

Our Barnett Shale production increased over the past year by 50%, to 925 million per day gross operated and 610 million per day net.

In addition, our Fayetteville Shale production increased over the past year by 80% to 285 million per day gross operated and 180 million per net, even after we sold off 25% of our assets in the play to BP in the third quarter.

Also during the year, we established through our joint ventures with Plains, BP and StatOil a transaction template that we believe will become the industry standard.

Further, we are engaged in discussions with several large international energy firms wanting to enter into new joint ventures with us.

Through the three JVs we also created a $4 billion receivable that is not on our books but will be highly beneficial to us over the next three year as we will have three other companies paying a significant share of our drilling bills during what will be a time of exceptionally low drilling costs.

This represents almost three tcfe of future reserve additions at no capital cost to Chesapeake.

Simply put, we created more value in 2008 than in any other one-year period in our Company's history.

In fact, I believe we created more value in 2008 than we did in the entire five-year period from '03 to '07, when our stock price increased by 400%.

Despite this, our stock price in 2008 declined by 60%, amid the global financial crisis.

Nevertheless, Chesapeake's value creation accomplishments of 2008 were real, and they remain embedded in our Company to be recognized and rewarded in the months and the years ahead.

We have prepared the Company well to withstand rough financial markets and low near-term gas prices and our substantial competitive advantages have positioned the company to prosper through 2009 and 2010 and, in fact, for decades to come.

I will next highlight that Chesapeake has at least four competitive advantages that should enable us to be an industry outperformer for years to come.

First, our asset quality is second to none.

This period of low gas prices will drive home what we have been saying in recent energy conferences - that is, while the last quarter of 2008 may have been all about balance sheet strength, from here on, it will be about asset quality strength.

And the foundation of asset strength in the US in 2009, and beyond, we believe will be determined by how skillfully companies have positioned themselves into the four best plays in the United States: the Haynesville, Marcellus, Barnett and Fayetteville Shales.

which we now are referring to as the Big 4 shales.

If a company is not in these in a major way, we don't see how such a company creates value competitively with those companies who are in those plays.

The simple reality is this-- conventional assets and marginal unconventional assets will see higher finding costs while the Big 4 shale will experience lower finding costs over time.

For years I believe major industry players have all had about the same type and quality asset base, but now I see a steadily widening gap between the Big 4 shale "haves" of which there are not more than 10 companies and the Big 4 shale "haves nots" of which there could be as many as 10,000 companies in this industry.

Over time, the "haves" will have lower finding costs, lower operating costs, lower maintenance CapEx, lower risk, higher returns on capital and higher growth rates.

On the other hand, the "haves nots" will be burdened by high finding costs, higher operating costs, higher maintenance CapEx, higher risk, lower returns on capital and lower growth rates.

The differences can be discerned today by close observers of the industry, however in years ahead, the differences between the "haves" and the "haves nots" will be there for all to see plain as day.

I would like to emphasize that Chesapeake is the only company with the top two positions in these Big 4 shale plays.

No other company had a top two position in more than one of them and to acquire a top two position today in one of these Big 4 shale plays would be almost impossible.

Chesapeake has a unique and irreplaceable asset base in these Big 4 shale plays and this asset base will drive relative out performance for years to come.

Chesapeake's second major competitive advantage is $4 billion of drilling carries created by our three joint ventures with Plains, BP and StatOil, these carries are as good as gold.

They will, be earned by us tax-free and received over the next four years with approximately $1.2 billion coming to us in 2009 and about $1 billion in 2010.

And if drilling costs fall significantly in 2009, these carries will be worth even more as they will enable Chesapeake to develop more reserves than we had previously modeled in our higher cost world.

I wish we could have booked this $4 billion as a receivable during the fourth quarter 2008, or perhaps even factored this receivable for cash.

It sure might have saved some balance sheet anxiety along the way.

Nevertheless, these carries are real.

They are big, and they are unique in this industry.

Chesapeake's third major competitive advantage is our hedge positioned.

Today we have hedged almost 80% of our projected 2009 production at an average NYMEX price of approximately $7.71 per mmcfe and as of last Friday, we had a positive mark-to-market gain of $1.6 billion on our open positions, which, of course, after yesterday's gas price decline would be even larger today.

Few companies are as well hedged as we are, and the days of companies saying we don't hedge because our balance sheet is so strong will probably come to an end under investor pressure as during this time of low gas prices, it will be seen that a tremendous amount of balance sheet strength can be lost if a company is not well hedged during an extended period of low gas prices.

Even though the economy is still weak, with the gas rig count dropping so quickly, our bias will be to maintain our 2009 hedges, but look for an opportune time later in the year to lift some or all of our second half to 2010 hedges and maybe some first half 2010 hedges as the year rolls along.

Chesapeake's fourth major competitive advantage results from a combination of the first three.

And it's that Chesapeake can replace the produced reserves with only 15% of its projected cash flow in 2009, and only 20% in 2010.

You have seen other companies in the industry report that they will have maintenance CapEx requirements greater than 100% of their projected cash flow in 2009.

This is a very important Chesapeake competitive advantage and we believe investor understanding of our very low maintenance CapEx requirements in '09 and '10 will be a key driver behind why our Company will likely substantially out perform its peer group.

With regard to today's very low natural gas prices, we are excited about them because the seeds of the gas recovery have been sown and they are being well watered as we speak.

In fact, the lower gas prices go today, the better it is for Chesapeake.

Perhaps a surprising statement, you might notice.

But for starters we have $4 billion of our drilling costs that are going to be paid for during next few years, no one else in the industry has anything like this.

Furthermore, these carries are worth more in a low gas price environment because drilling costs will be lower.

It's even possible that our $4 billion of carries will end up acting as if they are worth closer to $5 billion as drilling costs decline in 2009, perhaps by as much as 25%.

In addition, we are more hedged than anyone else in the industry and so we are more able to ride out a low gas price environment with less pain than most others.

As to the visibility of the seeds of the gas price recovery being sown, all you have to do is look at the gas rig count.

It will likely bottom out in the first half of 2009, down anywhere from 50% to 70% from the 2008 peak.

In fact, down to as much as a five-year low.

Therefore by year-end 2009, you should see gas production in full retreat in the US, setting the stage for a strong rebound in gas prices in 2010 to 2011.

Please remember that no matter how bad the economy gets, gas demand cannot fall faster than the 25% to 30% rate that supply can deplete.

This fundamental law of depletion will restore gas prices to equilibrium more quickly than most observers believe possible.

If you have any additional questions about play results or macro issues, I will be happy to answer them during the Q&A session.

I will turn the call over to Marc Rowland for his further comments.

Thanks, Aubrey and good morning.

Welcome to everyone.

My additional comments today will be brief.

You may have noticed that our depreciation, depletion and amortization rate for the fourth quarter was down to only $2.12 per mcf equivalent.

This is down from a high of $2.60 per mcfe in the second quarter of 2007, and, in fact, the last time it was this low was the fourth quarter of 2005.

I would also call your attention to our outlook where we have guided to a full year rate of between $1.90 and $2.00 for 2009.

This may well prove to be a high estimate but assuming it's accurate, the mid-point of guidance would represent a 17% reduction from the full year 2008 rate of $2.34 per mcf equivalent.

There are several important reasons for this.

First concentration of drilling activity in the Big 4 shale plays where our finding costs are superior to other shale and almost all conventional plays.

The drilling carries, secondly, that Aubrey emphasized that began to kick in during 2008 will be in full force for all of 2009.

Finally, and very important, reduced service costs, that really just began to kick in, in late 2008 in our opinion.

We are renegotiating rates downward with every vendor, large and small on every new well.

I wouldn't be at all surprised to see our year-over-year costs down in 2009 by over 25% compared to 2008.

Nearly every day vendors are approaching us with new reduced rates and we're negotiating with each and every one of them earnestly.

We believe production costs and general and administrative costs can also be lowered although we have not changed our guidance for either category for 2009.

Like most every natural gas producers, recent field differentials to NYMEX have blown out in most basins.

Our average differentials is noted in our release were a negative $2.07 per mcf in the fourth quarter of 2008 as compared to only $0.59 negative per mcf in fourth quarter 2007.

While we have some basis protection on for 2009 through 2012, as noted on page 26 of our release in the outlook section, it's clearly not enough and has not been enough to protect us fully this year.

In Q4, we averaged selling gas in the Barnett for $3.97 at the well head, $4.13 in the midcontinent, as compared to $6.65 in Appalachia and $6.16 in the Gulf Coast, differentials that we never in our many years of history seen.

This negative bias to the western basis will cause rigs to come down obviously very quickly in these areas, but the question remains, does this get better and how?

In our opinion, three ways.

First, additional pipeline capacity is generally being added in the worst basis markets.

New projects are coming on or will soon come on in Haynesville, Fayetteville and Barnett.

Second, we have committed gas volumes substantially to a number of these projects for a fixed firm transportation fee that will get the base -- that will get the gas out and into better markets at much less of a cost than the current basis differentials.

Third, there is some evidence that Rockies gas production has peaked and may have already begun a decline based on transportation utilizations recently being below 100%.

On the firm transportation side, we now have four projects committed to in Haynesville, including the ETC project recently announced and several more that are nearing conclusion of negotiations.

We see Fayetteville starting up with NGPL in April, Boardwalk in May with Fayetteville Express also committed to by Chesapeake for the out years.

In the Barnett, there are host of commitments for projects already in and operating and numerous ones to come on in the near future.

As a final point, I want to remind you that CHK has recently concluded two senior note issuances totaling $1.425 billion and the proceeds have already been applied to our revolving credit facility.

Several additional liquidity or monetization projects are still underway, but we don't have anything to add firm at this time to report to you.

We remain committed to a disciplined spending program that will have CapEx be in line with our ongoing cash resources as we have recently stated.

Operator, with that, we would like to turn it over to the Q&A session

(Operator instructions ) We'll have our first question from Michael Hall with Stifel Nicolaus.

Thanks very much.

Good morning.

Quickly, on the macro front, maybe if you could talk to your expectations on LNG this year and how concerned you are with potential of rising imports in the U.S.

Well, clearly that threat exists out there, Michael, and I think to get to the answer of it, you have to know where the economy is as the world goes, especially Asia and Europe over the summertime.

So it's something that we can't -- we can't know the answers to that, of course, but I think it's baked in the gas prices that there will be more LNG that comes to the U.S.

I still think that the US gas prices are likely to remain below European and Asian gas prices and so not as much gas will come here that some people are projecting.

It's clearly an issue for us, and as long as the economy around the world remains weak, I think it will remain a risk and likely keep a ceiling on the summertime gas prices.

I do want to emphasize that by the third or the fourth quarter -- the fourth quarter for sure, US gas production should be declining pretty sharply and we think it could be on a year-on-year basis as much as 3 bcf to 4 bcf or even 5 bcf a day.

And so I think that the -- that if any LNG comes in, it will simply be replacing some gas production and at that the margin will be in full retreat.

So some people have asked whether or not shale plays and LNG are in competition with each other for the US market and I don't see it that way, because shale play gas is only about 8 bcf a day today, versus the US market of about 60 bcf a day.

So I believe to the extent that any LNG lands here, it will be because the 52 bcf a day of conventional gas will be declining so rapidly that they are willing to bring in LNG.

It's certainly a risk but we believe that depletion risks are greater and will serve the balance of the market even with additional LNG importation.

Great.

Thanks for the color.

And then looking further out as you talk about US production turning perhaps by the third quarter, certainly by the fourth, how quickly are -- or how hard do you think it is to turn that back around and for the industry to start growing again?

How many rigs do you think would have to be applied back to the rig count?

Things along those lines.

Well, I think what you are going to see is even if you get price signals that would encourage the industry to begin drilling again, I think the industry will be slow to do so.

A lot of buckets are being emptied today that had been filled up over the last three or four years with cash from relatively strong prices.

As those buckets get empty during the year, I think any increase in price during 2010 and 2011 will probably go to fill up those buckets again before you start to see people get real aggressive with the drill bits.

I think if you just go back in time and at other price declines and rig declines like we are going through, I think the decline comes fast and hard and the recovery comes slow.

I guess the only other thing that I would say is that the industry is capable of producing as much gas as the country requires.

If the country, through policy choices that are made through the next few years decides to favor gas over coal, for example, and electrical generation or decides to more aggressively move our transportation network away from imported oil, and towards domestically produced natural gas, the industry can respond very quickly if we're given the proper price signals to do so.

Thank you that's helpful.

Moving over to Haynesville-- can you talk about what you are seeing on the east Texas side of the play?

We are drilling our first well there, I think it's called the Roxbury Well and it's in Harrison County, I believe.

And Steve are we in the horizontal portion?

Yes

So we probably won't have results there for another 30 days.

We don't have an opinion there, although clearly reservoir quality does degrade as you go to the east and I think our expectations -- sorry to the west.

Sorry.

To the west.

So our expectations take that into account.

Most of our acreage is on the Louisiana side, about 75% of our acreage is in Louisiana as opposed to Texas.

Okay.

Thank you.

Appreciate it.

We'll go next to Scott Hanold with RBC Capital Markets.

Good morning.

Hi, Scott.

Hey.

On that Barnett Shale joint venture that you indicated that there's some interest by some international players.

Can you give a little bit of color?

Is this something that we can see in the next couple of months and what does this mean to relative activity levels?

I know the Barnett is one area where you toned activity down and if you did do a JV, would that require stepping it up a little bit?

Good questions.

Let me say in general that there is a high degree of international energy company interests in gas shales in the US and if you are one of those companies, I think you -- as you survey the US gas scene, you are looking for companies that have a large asset base in the shale plays and probably you are looking for someone who did business with international energy companies.

So I think most, if not all roads lead to Chesapeake in terms of those conversations.

So we have multiple ongoing conversations with multiple international energy companies, some of which involve the Barnett and some of which involve some other plays.

We are very excited about the possibilities that could come out of these discussions, and at this point, I would rather not comment on what it might mean to the Barnett or any other play, but just suffice it to say that we have been able to create enormous shareholder value through the 2008 transactions and in 2009 we expect to create additional value by using this template that we have established to introduce various international energy companies into the US gas shale scene.

Okay.

Would you -- could you comment on whether or not you have looked to structure in a similar fashion to what you did with some of your other JVs?

Yes, I think the hallmarks of the JVs are that we have a majority interest and some of the consideration is paid in cash up front and some is paid in carries over time.

Typically these transactions have all involved the transfer of both production and proved reserves as well as an interest in the up side.

So those are the three features, the main features of the JVs and I would expect any future JV would have those same hallmarks.

Okay.

Great.

And one question, relative to your comments on the US rig count probably needs to drop 50% to 70% from peak levels and probably somewhere around halfway there.

I know when you take a look at the activity levels, I think you are thinking in terms of a 30% reduction overall from your peak levels and as the largest producer of natural gas in the US, how do you see your role in trying to help balance the market, versus letting some of the marginal guidance forced to drop rigs?

Well, I think we have kind of approached it two different ways.

First of all, we have done two things that are absolutely unique in the industry.

We are almost 80% hedged and we have $4 billion of our drilling bills paid for by other companies.

So we have built ourselves to be ready to drill in a time like this.

This is the time to drill, when prices are low.

And while other companies are dropping their rig counts much more aggressively than we are, the reason is because we don't have to.

We anticipated this downturn and got ready for it and built several competitive advantages that are, again, unique.

Having said that, we do feel some responsibility to be helpful in the industry and show some leadership.

So we have gone from 158 operated rigs to we're at 111 today.

We will bottom probably in late spring around 105, 106.

So I do think it is the responsibility of those who chose not to hedge and those who have higher finding costs to have to cut their CapEx much more aggressively than we're going to have to and this will be a huge competitive advantage as we get a lot of money spent, much of it paid for by other companies in a time of very low service costs.

Appreciate that.

Thanks.

We will have the next question from Shannon Nome with Deutsche Bank.

Thanks.

Good morning, Aubrey.

Good morning, Shannon.

Any risk of non-performance on the part of your joint venture partners.

I guess obviously you have comfort with their capacity and their intention to perform but I'm wondering if contractually they have any outs in terms cutting of back spending vis-a-vis current plans?

Or how is that set up?

They don't have any options in that regard and we are fully confident that BP, StatOil and Plains can and will meet all of their obligations.

Great.

Second question relates to one of the concerns we've had surrounding a production response to the rig count, agree that by late this year, we will start seeing some pretty aggressive declines.

The question is how long it takes and some of my companies have weighed in that they have at least a quarter, in some cases two plus quarters of wells drilled but not yet completed in their backlog.

Is that something that you all have as well, bottlenecked and/or do you see that elsewhere in the industry?

Shannon, this is Marc.

I think we do see that.

We have in the Barnett Shale ourselves -- Steve probably, 250 or so wells either not completed, waiting on pipeline and certainly we've heard others comment about similar numbers, particularly in the Barnett logistics there a little bit tougher.

We do not, outside of the Barnett ourselves, have much of any inventory that's not just the usual due course of business sort of-- takes a while to complete kind of stuff.

Certainly that's going to add some months probably.

I think it's already sort of figured into our numbers.

I did mention that there's some early evidence, perhaps that Rockies production has already peaked.

We have seen some anecdotal but also pipeline evidence here in the last few weeks that capacity out of the Rockies was going unused.

The only reason that could be in my opinion is that production is off already.

An of course drilling there has probably slowed faster because of the wider differentials than other places.

So it's one of about a zillion factors that go into trying to estimate whether it's end of third quarter, fourth quarter, beginning of the first quarter.

I think we get the trend and all of us probably know the trend is our friend here, but as to the exact minute or quarter that it starts that's pretty hard to guess as you would think.

I completely agree.

Interesting point you make on the Rockies.

One of, I guess, the other wrinkles here is that it's possible companies are doing some drilling due to rig obligations but not completing -- deferring completion, thus adding to the backlog.

I would think the Rockies in particular would be an area where if we are seeing excess capacity on the pipes that that could be readily refilled given the recovery and price.

Is that a concern at all?

We don't operate in the Rockies to any great extent at all.

And so I'm not sure I know the answer to that.

Our closest connect there is with our own joint venture with Delta and the DHS drilling, almost all of our rigs are laid down now in that venture.

I think there's three or four operating out of 18 or 19 capacity.

So I'm not really seeing any evidence, nor have I heard of anything where in the Rockies they are drilling but not completing.

But certainly that's one option if you've got a drilling rig commitment or if you have got perhaps a lease that allows to you establish commercial productivity without fully completing the well and turning it on.

I'm sure there's some of that going on without question.

Thanks, Marc.

Appreciate it.

We'll have our next question from Jason Gammel with Macquarie

Thank you, good morning guys.

I had a couple of questions on Haynesville results.

Aubrey have you --many of the changes in what you are thinking about in terms of IPs or have you really come into what you think is going to be optimal in terms of lateral length and frac stages at this point?

And then further would you have any comments on what you're seeing in terms of decline rates after six months?

Well, we continue to refine our pro forma with really monthly results coming in, we are still seeing a 6.5 bcfe pro forma as the best fit.

We have had to adjust the model to account for really high IPs that are coming in, however we continue to layer on top.

Very aggressive first year decline rates, I think, Steve at 82% to 85%, first year decline.

We don't know if they will actually decline that much.

It's what you almost have to model when the wells come in at 10 to 15 to 20 million a day.

It's in all likelihood that the wells that come in at 20 million a day are going to better than 6.5 million bcfe.

As you look across the Barnett and the Fayetteville, there are areas that are better than others.

And we're going to see that in the Haynesville, despite the homogeneity of the rock, still there will be some sweet spots.

So far we are seeing some of those emerge, but even the wells that appear to be not in the 20 million a day wells are still comfortably fitting our pro forma.

We are excited about what we see and, of course, you are seeing almost monthly additional confirmation from other operators of what they are finding in the play as well and I think the industry is kind of coalescing around this 6 to 7 bcfe range.

You have noticed that some operators have had trouble drilling horizontal wells in the play to date, and I'm sure they will get that straightened out.

But in the meantime, it's been a big competitive advantage for us to be able to hit the ground running here, having already been successful in other horizontal plays, most specifically the Barnett and the Fayetteville.

I appreciate that.

I'm not sure if you will be able to comment on this or not, but a Barnett Shale joint venture, would you envision that that would take -- with your existing production, be a component of the joint venture or would that be essentially undeveloped acreage only?

Oh, I think there's several ways to approach that.

First of all, some flat-panels are interested in -- some companies are interested in more starter set type opportunities and others might be interested in larger opportunities.

So I think what I mentioned before is that a feature of Chesapeake JVs to date have been some element of existing production and reserves and then the up side associated with acreage in the area.

So I would expect that any Barnett JVs we do, or for that matter JVs in other parts of the company would follow the successful template that we have established so far.

Great.

One more bookkeeping one if I could, the reserve additions, would you be able to provide what percentage of those additions were PUD or if your overall PUD percentages changed materially?

I think this is Marc.

I don't have the exact editions PUDs versus PDPs, but Steve-- our PUD percentage was almost exactly the same.

Which was what?

34% or 35%.

I think the answer is -- without having the exact answer and knowing our PUDs did not change in component, would not have been proportionately different than it's been in the past.

Okay.

Great thanks a lot guys.

Thanks, Jason.

We'll go next to David Heikkinen with Tudor, Pickering, Holt & Co.

Securities.

Good morning.

Marc.

You casually mentioned that services costs could be down 25% year-over-year for every new well you are driving rates down.

I'm curious, two things, one, can you give us some thoughts as far as the breakdown of those services on the pressure pumping versus drilling side and then the follow-on question, can you give us an update on leasing and the current rates for each of the plays where you are doing leasing, Haynesville, Marcellus primarily?

Sure.

I'm more familiar with the first part of that question.

The pressure pumping costs are coming down.

Of course, we have a venture FracTech where we own 20% of it and so we're pretty close to that -- that business, but as Frac -- or as pumping services lag coming up, they are now lagging coming down a little bit because of the backlog of wells that Shannon referenced and we talked about earlier in this call.

But we are now seeing sort of those costs coming down full force in really in the middle of this quarter and going forward.

Drilling rig rates we talked about in our last call.

We actually had an example of the Haynesville 1500-horsepower rig that we were offered by a vendor and actually are paying -- Steve, is it $10,000 a day or thereabouts for that rig?

Because it was top drive, I guess it would be around $11,000.

Yes, with top drive, $11,500 or something like that.

At the peak, that particular item would have probably been at $23,000, $24,000 a year ago.

Really substantial rig rate decreases.

Steel prices, of course, have fallen considerably and will be going down and just about every other component, diesel costs particularly, transportation costs, surrounding trucking and every other item is down.

So I think 25% is really a conservative estimate on year-over-year.

As we talked earlier, the rig count goes down on the gas side to 700, 650, 800, whatever the number ends up being.

That will be off so substantially that the capacity that was built to service basically a 2,000 rig count is still in place and will remain in place and I believe based on conversations we've had had with our various vendor partners that they are going to be more concentrated in market share rather than margins going forward.

That's my flavor of what is going on on the service side.

Aubrey do you have any comments on acreage?

Yes sure I do.

Certainly we have seen acreage costs decline across the board.

It's been extremely helpful to us.

You might have noticed that our forecast for CapEx for acreage crept up a little bit this go around versus where we were in -- with our last guidance in December.

And the reason for that is simply, we don't have clarity on whether or not our JV partners are going to share with us in additional acreage purchases this year.

They have the right to share in that acreage on either a monthly or quarterly basis and our acreage gets offered to them at a promoted price.

So it's possible that some of them may make elections not to participate.

So we are in the $350 million to $500 million range for acreage this year, which will function as a much higher number than that given how aggressively acreage costs have come down in all of the Big 4 shale plays for where we are still nibbling at acreage.

Can you talk at all about the equity that you are issuing on some of the renegotiations?

Any update us on the number of shares exposed or anything along those lines.

I think, David, we set aside 25 million shares to do that and we have been in discussions with various parties over the last two to three months to try to clean up some of the deals that were discussed at -- in a different economic environment than the one that we are in.

So I think we have said pretty consistently that we established that number as one that we thought we would use and we're not through using it yet but we expect to use it over time.

Okay.

And then as you think about the services costs coming down by 25%, implies that you'll get a third more wells in each of the carries.

Can you update us?

Is that basically how you're thinking about the carries lasting longer as services costs come down and far that actually gets you in each area now for the drilling carries.

It should take us a long time-- deeper into the future, no doubt.

I think on the Fayetteville, we were previously expecting that the BP carry might run out in October of this year.

We are now projecting that it will probably extends to the full year.

So it's just a function of how low prices go or costs go and then you just do the math on just $4 billion, active $5 billion or $4.5 billion or $5.3 billion - It depends how low costs are.

Have you factored that into your CapEx thoughts for '09 or '10 is a more specific question.

No, we have not.

Nor have we factored in these kind of cost declines or any of or cost structure going forward.

All right.

Thanks.

We'll go next to David Tameron with Wachovia.

Hi, good morning.

Just following up on David's question there.

Going back to '07 or maybe we are in the $6.50 or $7 price range.

How much do service costs have to come down on your current drilling program in order to get the same margins that you enjoyed back in '07.

Is that -- what's the magic number there?

Well, remember, that we're kind of are looking at the world differently than maybe others are, or even we used to, which is we view that the cost curve across the whole industry used to be relatively flat.

And the reason for that is everybody owned about the same kind of assets.

Today we see this widening gap between companies that have hung on to their conventional assets or have wandered into some unconventional areas that are high costs and we think those areas get worse over time.

And the reason is simply that most of them are increased density plays.

I mean, take East Texas, for example, or parts of the Anadarko Basin.

For the last 10 years, the industry has been drilling in these areas, not finding really new reserves but just doing drilling rate acceleration wells and that worked when gas prices went up by about $1 mcf per year.

Well we think those days are over.

So now we see that the vast majority of the industry's asset base deteriorates over time and quality and finding costs go up while on the Big 4 shale plays we think the finding costs will go down.

We don't think the most efficient plays that we're involved will set gas prices.

We think it will be the least efficient, which actually will tend to support higher gas prices than you would think.

So in your $6.50 to $7 gas world, we would expect Chesapeake to become more profitable over time than we were in the last $6.50 to $7 environment, because our costs will be lower.

However, we expect for many companies in the industry, their profitability to be less in that gas world going forward than it was a year or two ago, simply because of the asset quality deterioration that we think takes place in these non-Big 4 shale areas.

So Aubrey, from an industry perspective, does that imply more M & A over the next six months as far as the industry consolidation?

I don't know, David.

I would suspect not.

I mean, for example, we wouldn't want to go acquire more conventional assets at this time.

So maybe -- maybe it does, among the other companies that feel like if you can't upgrade asset quality, maybe you can downgrade your cost structure by doing some consolidation.

Everybody always talks about consolidation that doesn't really occur very much.

I think the more -- I see two things that occur in 2009, and I think will be pretty significant.

One is this widening gap between the "haves" and the "haves nots" that I have spoken quite a bit about.

The second thing is I think the arrival of some new international energy players into the North American gas market will be significant.

I doubt, frankly that they do it through M & A.

I think they are likely to do it through the joint venture concept, and hopefully they will do it with us.

Okay.

Thanks.

One more question for Marc.

Obviously working caps is an issue for all CFOs right now throughout the industry.

Can you give us a feel for what your monthly working cap number that you need to fund is?

Well, we have talked about this quite a bit, David.

Working capital, basically swings from a high point in the end of the month for us, receiving all of our revenues for oil and gas sales and our hedging gains kind of concentrated in the last few days of the month to the mid-part to the third week of the month being the low point, which is 3.5 weeks later we paid all of our bills and CapEx and so forth for the month with basically no revenue.

And so if you basically look at our revenue on a monthly basis, and just think that that's our revenue swing, or our working capital swing, that's about what we do.

It's $700 million to $900 million per month depending on prices.

All right.

Thank you very much.

You're welcome.

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

Thank you.

Good morning.

Good morning, Brian.

A couple of questions on kind of CapEx and financial conditions as you mentioned with the senior note issuances and the financial conditions until last couple of days have improved a bit.

I guess the question is as the tight capital conditions ease, should we expect you to get more aggressive with your budget, either for drilling or lease acquisition, and then I guess in parallel with that, could we regard your comments on investment grade credit rating as a priority within the Company or more of an aspiration?

In the latter part, I think it is more of an inevitable outcome, rather than either aspiration or a direct goal.

As we have said in the past, we are not going to go rushing out and issue a bunch of equity to pay off $2 billion or $3 billion of debt prematurely just to reach investment grade.

We function just fine where we are.

We are comfortable with our balance sheet, and I think at the various debt conferences I have spoken about investment grade as being an outcome over the next couple of years of the plan that we have in place.

We're going to add several trillion cubic feet of proved reserves on the existing standards and maybe more than that on the revised standards that are coming up from a reserve booking standpoint and really add no net debt issuance over the next couple of years, which segues into the first part of your question.

Additional liquidity at this point is meant to be just that.

We are -- we have not and are not planning to increase our capital expenditures at all.

We have rolled out the same drilling budget unchanged from our guidance a couple of weeks ago and really unchanged from our December 7th guidance where we substantially lowered what we are spending.

Costs will help us probably to reign in capital expenditures even below what we budgeted if the forecast that we kind of hold amongst us for lower service costs is realized, which, again, has not been fully baked into our budget at all.

So there's not one ounce of us that wants to change capital expenditures up, either per acreage or for acquisitions which we have none that we have done or talking or contemplating, nor capital expenditures.

So honestly, we want to sit here in a position where we have plenty of liquidity in case we're wrong about how low gas prices go or how long they stay low.

Obviously, as we talked about during the note issuances, this was sort of a CFO belt and suspenders action and I feel really comfortable where we are today.

And so I think -- I think what I heard you say is to the extent that service costs for the down side or relative to what is in your budget, you would drill the same number of wells and spend less as opposed to spend the same amount to drill more.

That's correct.

Could you discuss specifically well costs trends in the Haynesville and Marcellus, both from the perspective of efficiencies as you get to know the plays better and whether the service cost decreases apply to both those regions given that they seem to be hot?

I will pass you over to Steve Dixon.

These are both new plays, so we are -- were changing our procedures and the size of our stimulations and so there's really not a baseline to measure total well cost on a used basis though we are seeing substantial savings from our various vendors in 20%, maybe as much as 30%.

So things are going our way.

Great.

And could we expect that there's potential, I guess, downside to the guidance you put out for well costs in the past, in both of those two plays.

I think it will come both from those unit costs but also just drilling efficiencies and completion efficiencies.

We are still -- we will still have a very significant element of science and -- and all that we are doing in the Marcellus and a fair amount of science still being done in parts of the Haynesville.

Those science projects cost money and as we gather that information, the need for additional science will tend to decrease over time.

Great.

Thank you.

Thank you, Brian.

We'll go next to Gil Yang with CitiGroup.

Good morning.

Continuing on the Haynesville for a second, what's the terminal decline rate that you are modeling in to get that 6.5 and how soon do you reach that?

Gil, I'm sorry you faded out.

You said something about the decline rate in Haynesville.

What is the terminal decline rate you are using in Haynesville and how many years do you model that out?

I will let Steve answer that.

Terminal decline is 5%, and when we reach that, I don't have that in front of me, but probably eight, 10 years.

Okay.

Yeah, I think I saw one about a week ago and it may be in the 10 to 15 year period of time.

I think it gets down to 6% or 7% by year, 8, 9 or 10.

We see in all of our shale plays is 5% terminal.

Well, that's what we are using.

Actually what we see in older shale plays like back east in the Devonian shales, they are 3%.

We are artificially cutting these all off at five.

We have Devonian shale wells in Appalachia that have been producing for over 100 years.

Shale should continue to bleed in for a long, long time.

Right.

Is that what Netherland Sewell allows for decline curves, 80% the first year and then getting out to 5% in 15 years is that what Netherland Sewell is allowing you to book there?

I don't know who did our Haynesville reserves and -- but, yes, that's our curve, that 82% and 5% finals.

But, again those terminal declines are not different than any other shale play that we have got and you are picking on -- or you are asking about Haynesville, but independent reservoir guys do the eastern reserves and they do the Barnett Shale and the Fayetteville and all of these are independently prepared by third party reservoirs.

I guess the question is just that since there's no history beyond maybe a year or two, are they comfortable giving you that typical shale well decline out in years three to infinity?

I mean, you have to start somewhere and obviously if you don't have a well that's older than two years old in Haynesville, you have to rely on what other shale plays have done.

Again, I don't think any company with the possible exception of Equitable has older shale wells than we do.

We have been looking at decline curves in the east from shales that are over 100 years old.

I think we have a pretty good handle on what happens in the out years-- they break over and the oldest wells in the Barnett now that are horizontal are up to 10 years old so you clearly have good information there.

Every shale play is a little different.

At the end of the day, they are all hyperbolic decline curves with first year decline rates of somewhere between 60% and 85% and we project based on experience and expectation that the terminal decline rates on all of these will be about 5%.

We, Steve how many different outside reservoir engineers do we use?

Four.

Four or five main ones.

So they all pretty much have to get to the same answer on those terminal decline rates.

I do believe we cut off our tail reserves at 65 year range.

Okay.

There's no PV out, there but there will be some day.

Okay.

And then last question is, just going back to the capital structure if you are investment grade in two years, understanding Marc, you said this is a result as opposed to a goal.

Nonetheless, if you get to investment grade at the end of 2010 your carries will be rolling -- some of your carries will be rolling off and what will then be happening to Chesapeake at that time?

Will capital expending need to rise to fill the void left by the carries or do you see yourself going going to 20% debt-to-cap by 2012?

Well, I honestly haven't modeled it out to think about it that carefully.

The carries don't roll off at the end of 2010.

We talked about a 2009 and 2010 budget, and how much of the carries are in place, but actually, I think about half the carries still remain going forward from that point.

So I wouldn't focus too much on the end of 2010 being different.

If we are crossover or if we are investment grade, I really don't see much changing and that's why we are not in such a flurry to get to investment grade.

Our debt will still be outstanding or most of it from the senior note standpoint.

What is callable will be callable at a premium and I don't know what interest rate environment we'll be in, but I presume that it will possibly be substantially higher than we are today.

So our current rates on our existing non-investment grade debt might be actually quite attractive and we may just keep it all in play.

So pretty speculative question, actually and I probably don't have a very good answer for it.

I might just add that what we would see on the asset side, again, is this continued differential widening between what happens on finding costs.

So I think that what we would see in 2011 and 2012 is I would expect our finding costs to be lower in the Big 4 shale plays than they are today on a combination of better efficiencies and perhaps lower costs, while at the same time our conventional assets probably do not get better over time and therefore, require a higher gas price than -- than we have seen the last couple of years to make those plays work.

Okay.

Thank you.

Okay.

Thank you.

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

Good morning, Tom.

Just a few follow-on questions in the Haynesville and the Barnett.

With respect to the Haynesville, can you address the gross off take capacity constraints?

Sure we can.

We have said publicly in the past that we think it will be a take away capacity will come into play in terms of restraining the overall growth of the Haynesville, but we have been very proactive and establishing our own corporate take away capacity.

I think you might have seen the take of bcf a day of capacity on the latest pipe out of the area, the Tiger pipeline that's an energy transfer project.

I believe that that takes us up to 1.8 bcf a day of firm transport.

So we have our needs covered for quite sometime, I think.

With regard to how the whole play develops it really depends a lot on gas prices and what happens to Barnett production.

If Barnett production is close to a peak, as the rig count and the Barnett has declined from around 200 rigs, I believe, to around 120 or so today, maybe even 110 today, this, huge surge of production that we have seen out of the Barnett, that has hurt gas prices throughout East Texas and into Louisiana, I think we'll back off some, and maybe even create some capacity at Carthage and at Perryville, which will open up the ability -- or increase the ability of the Haynesville gas to come on.

So at any rate, what we have done, we know our acreage, we can model what our production does for years to come in the Haynesville and, again, be taking out 1.8 bcfe per day firm transport and believe that while others may struggle to get their gas out, we will be in good shape.

And the Tiger comes on in mid-2011.

I think we have got it scheduled for July of '11.

Okay.

So do you see industry pumping against -- bumping up the capacity constraint before you get to that time period?

We are barely able to hear you, but I understand what you are asking Tom, and will there be industry constraints?

Again, I think that's so dependent on what the overall rig count is in the Barnett and the East Texas and Haynesville that's difficult to answer.

But I do suspect that if you haven't grabbed or created your own pathway to firm transport, I think there's a good possibility that some companies will have a hard time getting their gas out of the area.

Gotcha.

Thanks for that.

And follow on to Gil Yang's line of questioning, if you will.

In the Haynesville, do you have a specific horizontal well that's demonstrated the steep initial declined mitigating to a significant degree?

Well, I think our oldest well has been online nine or 10 months, I believe, and so we plot the declines monthly and that's -- it's based on that experience is why we are projecting this 82% first-year decline rate.

So we have seen nothing that has changed that.

I think we started before the play even started, I think we anticipated something like a 75% decline rate.

So what has changed over the past year from experience is that the wells are coming in at a higher IP rate.

They also decline quickly and so we have honored that by adjusting that first year rig decline.

So is the risk to the upside or the downside there on the 6.5 bcf at this point in your view?

Well, based on what we are seeing, I think the first month production to get to 6.5 has to average about what?

No.

On our current pro forma, only 8, 8.5 first month average.

So they come on initial production, I think to get to the 8.5, you anticipate they come on 11 or 12 million a day on day one for the first month they average 8.5 So given that the wells that we have been bringing in lately are well above our pro forma, in fact, we have circulated a report daily that green lights, yellow lights and red lights all of our wells and I believe something like 85% to 90% or all but two of our past 10 wells I believe are in the green light category which is -- they are tracking above pro forma at this point.

Great.

Just one quick follow-up question in the Barnett.

Does the lower activity there put the 6 to 6.5 bcf day a peak in 2012 that was discussed at your analyst day at risk?

Probably a little bit, yeah, for sure.

It really depends on what other companies are doing.

I mean, at the time we had no knowledge of what Devon and others would I do.

I think they announced they are going from 32 rigs to eight rigs, if I recall.

We have gone from 43 rigs to 28 rigs, I think 27 rigs and so I think we end up going to about 25 rigs.

So everybody has dropped rigs pretty aggressively there and I read analyst comments that only vertical oil rigs are coming down.

It's not true.

And the Barnett has been the biggest driver of incremental gas production and that rig count is off more than what you have seen the rig count drop across the nation.

So I would suggest that -- I mean, it would seem to us, as we track industry production in the Barnett, that I think the latest that I saw if the gas rig count goes to 100, from here and stays there, is that we're pretty much at -- at peak right now if the rig count goes to 120 and stays there, I think you do get into the high fives and it would take a rig count, I think in the 140 to 150 range to get out to that 6 and 6.5 number and it might take another year or two beyond the 2012 range.

So the end user, these are great wells but they come along with big declines and you have to keep drilling to sustain that.

So if the market the price for gas does not support additional drilling, then the cause of this gas over supply right now will quickly -- quickly adjust, and, again, it can adjust faster than gas -- than gas demand can go down.

The gas supply will go down a lot faster.

We go next to Joe Allman of JPMorgan.

Thank you.

Good morning, everybody.

Hello, Joe.

Hey, Aubrey, previously you spoke about I think five oil resource plays and we know that one is WEHLU.

Any update open the other oil plays.

Yes, let's see, Joe.

I'm kind of ticking through them, one has for sure not worked.

We are working on a couple of others, of course, probably none of them work at $35 oil.

So we are continuing to press forward there.

But it does -- the challenges of finding new plays of significance does I think support what we said about shales on the gas side, which is we think the major wells have all been found and a number of shale plays have not worked in the last couple of years and we have discovered a few that have and, of course, they are big and they are important.

But to keep that in perspective we don't believe that we're going to see additional Barnetts, Haynesvilles, Fayettevilles or Marcellus' developed in years to come.

There's just simply no place for them to hide in the stratographic column after the industry has spent so much time and effort identifying shales over the last five years.

So it's tough to move oil through shales and that's why there are so few oil shale plays that work and I think we still have a shot at a couple of them working but that's a tough business to go out and find shales that allow oil to move through them.

We are certainly encouraged by a couple of results that we have, but we will wait until later in the year to decide if they are going to be commercial and a lot of it will depend on price.

Okay.

That's helpful.

And then separate issue, late last year, you were looking at some acquisition leasehold acquisitions that you had agreed to and you are hoping to renegotiate for a lower price to potentially use Chesapeake stock.

Any update with those transactions?

Yeah.

I don't remember if it was David Heikkinen or someone else asked about that earlier.

I said we put aside 25 million shares of stock to deal with those outstanding issues and we have made a few deals and are in negotiations on a few more and suspect that we'll have the decks cleared of those sometime during 2009.

Okay.

Sorry about that.

Missed that.

No problem.

And then on your negative -- on your reserve revisions do you have a number for the proved developed revisions versus the PUD reserve revisions?

I don't know that we have a reserve report reconciliations report with us.

That will be in our 10-K.

I don't have that number.

That was sort of asked earlier, Joe, and I didn't have the specific component between PDP and PUD.

But our PUD percentage -- the answer was our PUD percentage did not change.

Okay.

Sorry about that.

And then in terms of your E & D spending from your prior outlook to the current outlook the E & D spending did not change.

I know you said that you are not baking in a whole lot of service cost reduction, but is your assumption about service cost reductions the same from your prior outlook to this outlook?

So that your spending is effectively the same for E&D.

It's the same but we've now seen a lot greater reductions than we we're seeing in December.

In fact, they are kind of accelerating as we speak.

We've have had major vendors come to see us in the last couple of weeks who basically said what would it take to keep some rigs running and we are talking about big percentage declines not the 5% and 10% we kind of saw in November and December.

So we have not baked those in because we have not seen the bottom, but the bias is going to be definitely towards being able to spend less money as the costs come down.

We will not -- we will not adjust our rig count upward if costs go down, our rig count is set where it is.

And we're happy with that.

And it covers our acreage, it covers or obligations to our partners.

And if we can squeeze out another billion dollars, or $500 million from our drilling costs over the next year, per year, then that will be additional liquidity that we create.

I may have risked missing this one.

East Texas, Haynesville your acreage in East Texas and north Louisiana based on some results that you have seen from others or yourselves.

Yes, we are drilling the first well there in Harrison County.

We are at horizontal and won't know anything for 30 days but the way we have it mapped, we like the core area that we have in Louisiana better and thankfully it's where 75% to 80% of our acreage is.

Great.

Thank you.

Thank you.

We'll go next to Eric Kalamaras with Wachovia.

Hi, good morning.

A little more clarity as to what the potential monetization strategies might be for later this year.

Is it something where it would look similar to what we have already seen or are there different types of things that could potentially be offered up.

I think what we talked about in the past is a VPP and also some JVs.

I'll see if Marc wants to add anything further than that.

Well, the four or five things that we spoke about include VPPs, they include sale of some properties.

They include some sale leaseback transactions.

We are in the process of negotiating a sale and leaseback on some of our surface locations.

They include the joint venture projects that we talked about.

All of those things are -- are still on the table and we're working on -- and I failed to mention the midstream partnership or monetization of some of those assets which is still very active as well.

So nothing, Eric, has changed in regard to those things proceeding.

Obviously it's been a volatile time and one of the reasons we wanted to secure the debt that we used to pay down our revolver, was because the timing and the amount and the price variability of all of these things is always in question and when you are relying on some other party to come to the table and write you a check for any of those transactions we don't have a specific date and none of these things are in ink, but they are all in process.

Okay.

Great.

And then additionally is it your hope or do you expect most to be front end loaded?

The way we got it scheduled now, actually, is towards the end of the first quarter would be the first thing that we are looking and then sort of evenly between the second, third and fourth quarter thereafter.

Okay.

And I guess further going forward, regarding lifting hedges through 2010.

That is- presumably-- it will be partially gas price driven.

Can you give an indication as to what size we might be looking at for that?

You can look at our hedge position which is outlined in the outlook for 2010 and know that that is the maximum that we could do.

It's a big volume and so we are not going to wake up one morning and say we are going to remove all of our hedges just like we legged into those hedges, I suspect if we do anything, it will be a leg out kind of a deal.

But we have spoken about being well hedged in 2009.

We think there's the possibility of down side here to prices during this year and so we have only talked about the possibility again, not even the probability, but the possibility that if we do anything, it will be for the 2010 time range and the back half of 2010.

And I would like to emphasize that the bias is towards keeping hedges on because I think we have to run the business with more attention, of course, to the down side than the up side.

Having said that, though, there could be gas prices that come before and in 2009, it's simply so completely guarantee a recovery in 2010 that would feel like we need to take advantage of that.

Of course, it would be rig driven as well.

I don't know what this week's rig reduction will be but, of course, we are running at the rate of almost 200 rigs a month minimum over the last couple of months.

So it doesn't take much more of that to get to a point where you can really regain some confidence about what's going to happen in 2010/2011 and I know everybody is looking for kind of historical precedence here to see where the rig count goes to, but I would remind folks that this is the first time that I can recall in 25 years that you have not only a bad commodity price environment, but you've got enormous -- enormously restricted access to credit and those two factors together will absolutely drive the rig count down probably further than most people thought.

And we started to say late last fall, that we thought that the credit market might even have -- might be a larger factor on driving the rig count down that even gas prices.

That rig count decline has accelerated in the last couple months and I think it will continue for the next couple of months.

Thanks for that context.

And I guess one last question regarding any sort of capital markets activity.

Aubrey, can you give your position as to where you would see the need for increased capital as we head through the rest of '09 and specifically the first half of '09 and under what conditions might you come back into the market place?

Well, this is Marc.

I will speak for all of us in saying we don't see any need for any type of market capital at this point.

We took advantage of a robust capital markets and the debt markets and feel like we are very well positioned in the debt markets and have not only no thoughts of doing anything but see no need to do anything either.

Great.

Thank you.

We'll go next to Marshall Carver with Capital One

Yes, most of my questions were answered.

I did have a question on the guidance issued yesterday for cash in flows and out flows which basically puts a $7 NYMEX gap for 09.

It sounds like you think gas is going to be below that with your commentary about the 2010 hedges and just curious why you chose the $6 to $7 NYMEX price and if gas would be at $5, would you be inclined to lay down more rigs or what your thoughts are on that?

Well, clearly we are not going to out spend cash and we have said that on numerous occasions.

We think that as the year rolls on and the visibility of gas production declines becomes more obvious to industry observers and we are optimists and so we hope at some point the economy stops worsening that that range of six to seven is something that's achievable.

The whole industry is hemorrhaging cash right now--the worldwide oil industry is hemorrhaging cash and industries like this can hemorrhage cash for a while but when the worldwide oil depletion rate might be 7% or 8% per year, and the US first year gas decline rates 25% to 30%, it can't hemorrhage very long before the depletion takes over and restores the market place.

It's still my view that $6 or $7 is going to be an uneconomic NYMEX price for probably 50% of new drilling in the U.S.

And so I don't think that's a particularly heroic gas price.

If we're wrong and the economy doesn't contribute or, sorry, doesn't cooperate and if we don't see the rig count go down as much as we had hoped for, we are still in good shape and you can look at our guidance in our slide show and see that even at $5 natural gas prices, that's on page 15, our operating cash flow for 2009 the difference between $7 and $5 for us is $110 million.

Our operating cash flow goes from $4 billion and $20 million to $3.91 billion.

So you can run gas prices at zero this year and we still are going to generate somewhere north of $3.5 billion of operating cash flow.

So that's why it really doesn't matter and I have said in my introductory spiel, the lower the gas prices go this year, the better it is for us, it sets up the rebound and it differentiates our strategy from the strategy of other companies, which for various reasons choose not to hedge.

Thank you.

We'll go next to Monroe Helm with CM Industry Partners

Thanks, guys.

Great job on hedging.

Aubrey, just a follow-up on that thinking.

If you went to your four big shale plays, what kind of 12-month NYMEX price would cause you to think about not being able to drill in those four particular basins to meet your hurdle rate of return?

Can you go by basin if a, what type of NYMEX 12 month price you need to keep the drilling going and without concern of hedges, I guess.

Yes, really, we look at numbers in those basins without hedges but we certainly look at them with carries for the context of your question and so in a play like the Fayetteville, where we will spend no money this year, and BP will pay all of our expenses obviously we will drill there, no matter what gas prices are.

With regards to the Haynesville and the Marcellus plays, again, in the Haynesville, 50% of our costs are being picked up so we think our finding costs are going to be about $0.65 to $0.70 per mcfe there this year.

And the Marcellus, StatOil is picking up 75% of our costs so we think our finding and development costs will be about $0.30 per mcfe there.

You can see that there's really not a gas price that I think can be imagined that is going to be to affect our activity in those three shale plays.

Where it could affect our activity further is in the Barnett if we don't do a joint venture there, don't pick up some carries and gas prices get weaker from here, then we will continue to cut in the Barnett and continue to cut in other areas of the company.

Going forward, Monroe, I would just say if you run an average of finding costs for those plays for us without carries of less than $1.50 in mcfe and look at LOE for those areas and look at differentials you can see that those areas will be successful at some pretty low gas prices.

But it's what's happening at the opposite end of the asset quality spectrum that's going to determine gas prices in '09 and '10 and '11 we think.

The other question was on the September balance sheet, I think had you $11 billion in unevaluated properties.

Do you know what that number was at the end of the year and what is your impairment charge related to the unevaluated properties?

I think it was right at $11 billion as well on the unevaluated leaseholds.

So whatever we added during the fourth quarter got essentially -- the equivalent amount got moved to the full cost pool.

I think with regard to acreage that was impaired, I'm pretty certain that we impaired all of our Alabama acreage that we moved it into the full cost pool.

I think that was $100 or some odd million dollars, unless Marc is, aware of any other area where we condemned the whole area.

No, Aubrey, you are right.

$11.1 billion of unevaluated at September, $11.2 billion at 12/31.

Okay.

Thanks for your answers.

Thank you for your questions.

We'll go next to Jeff Davies from Waterstone Capital.

Good morning, guys.

Thanks for keeping the line open.

Just some quick housekeepings.

What is the impairment of investments there?

The impairment of investments is related to, I think five different items, Jeff.

We have a -- in addition to the impairment on the cost pool, we had an impairment on a gas processing plant in southern Oklahoma that's uneconomic at these prices, to little volumes going through.

We had an impairment related to our interest in a refining operation in western Oklahoma.

We also had impairments in our rig investments, one of which was a 50/50 joint venture with Lehman Brothers and the other one was a venture with Delta Petroleum.

And then finally we had some impairments in our other investments in different companies.

Okay.

What's the $100 million increase in other PP&E?

The increase in other PP&E is rig, compressors, computers, just general --

Midstream?

I think Midstream is in "other" Aubrey

Okay.

And then how would you characterize the M & A market today and some of my fear of the reliance on some asset sales and I heard your response that some of them may be here in the first quarter but then equally weighted throughout the remainder of the year.

My expectation is as gas prices continue to move lower here barring basis getting redetermined lower, we could be seeing some distressed sales some in the context of, you know, needing to sell assets and competing against distressed sales.

What are your thoughts there?

Let's be clear on a couple of things.

We don't need to sell assets.

We are selling some assets in the context of a potential joint venture because we would like to build additional liquidity this year.

So to the extent that troubled companies put assets up for sale, that's -- we are not going to be competing with that.

The international companies that we're working with are not going to look for $100 million of bad assets from some company.

They are looking for something that Chesapeake uniquely has which is big time shale positions in all four of the best shale plays in America and with a management team that knows how to put together some joint ventures and a JV template that works for both us and them.

We can't comment on the M & A market.

We are not engaged in it.

Don't intend to be engaged in it.

We are focused on one market, we think a market of our making which is the international joint venture market.

Also I would add Jeff, that our Midstream, for example, while we have not put together anything together yet is not oil and gas price dependent, actually, it is improved as steel prices and other costs have come down.

We are investing less dollars per foot of pipe in the ground and it's all volume metrically determined based on a fixed fee arrangement.

So that asset, particularly, probably has gotten better, not worse in this price environment, and as Aubrey mentioned on the joint ventures, various of our joint ventures won't peak in production until 10 or 15 years out and so I don't think price decks on a long term have changed from the investors perspective that much on a long term potential of these plays.

I might push back a little bit on the -- if I combine your net leasehold transactions and midstream financings the total of those two is-- of cash inflows is in excess of your net cash change shown on your schedule.

So without some asset sales you are going to be pre-cash flow negative in a year when you have huge carries helping you so I might push back on Aubrey comments that you are not relying on asset sales.

We will let you push back all you want.

I suspect you didn't think that we could do a deal with StatOil last fall or probably BP or Plains either.

So we will get done what we said we are going to get done just like we did in the second half of 2008.

Thank you.

Thank you.

We'll go next to by Biju Perincheril with Jefferies

Yes thanks.

A couple of quick questions.

In East Texas can you give us some color on your plans for the rest of the year--how many wells you planned?

It looks like you have permits in all three counties there.

I will let Steve answer that.

We are planning to keep two rigs running in East Texas and evaluate our Haynesville position there.

Okay.

How many wells might that be this year and are you testing all three counties?

We missed -- we missed one of your words?

How many what?

Oil count.

Yes, how many --

How many wells will that result in?

12, 13.

Okay.

Okay.

And then over in Louisiana, in areas where you do have -- you have no infrastructure issues, what are the lead time to drill complete and hook up a well?

Probably about 90 days average.

From spud to sales.

From spud to sales.

Okay.

And then any new Marcellus results that you can share with us either in West Virginia or northeast PA?

What you would you like us to share with you?

Marcellus.

No and we have mentioned how well we've done in northern West Virginia.

We just took our first well in northeastern PA.

Our first horizontal well is in northeastern PA to sales.

That well is in Bradford county.

That's a very impressive well and we won't discuss rate at this point, but I think we have two rigs up there right now.

Three rigs in northeastern P A.

And, again, we are drilling right along a couple of pipelines up there.

So we're -- we'll have more information as the year rolls on, but at this point, we prefer to keep flow rates -- we prefer to keep flow rates to ourselves.

I think that given that we have been on here for an hour and a half, I think it's fair to all of our callers to go ahead and sign off.

We appreciate your questions.

If you did not get to have a question answered, please send it in to Jeff and we'll get it answered today and appreciate your interest in our Company.

Take care.

Bye-bye.

That concludes today's conference.

We do appreciate your participation.