Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

Executives

Jeff Mobley – SVP, IR and Research

Aubrey McClendon – Chairman and CEO

Marc Rowland – EVP and CFO

Steve Dixon – EVP, Operations and COO

Analysts

David Heikkinen – Tudor, Pickering & Holt

Scott Hanold – RBC

Jason Gammel – Macquarie

Dave Kistler – Simmons & Company

Brian Singer – Goldman Sachs

Chris Gault [ph] – Barclays

Ronny Eisemann – JPMorgan

Ray Deacon – Pritchard Capital

Marshall Carver – Capital One Southcoast

Jeff Robertson – Barclays Capital

David Tameron – Wells Fargo

Rehan Rashid – FBR Capital Markets

Biju Perincheril – Jefferies

David Snow – Energy Equities Incorporated

Chesapeake Energy Corporation (CHK) Q4 2009 Earnings Call Transcript February 18, 2010 9:00 AM ET

Operator

Good day and welcome to the Chesapeake Energy earnings call. As a reminder, today's conference is being recorded. At this time, I’d like to turn the conference over to the host, Mr. Jeff Mobley. Please go ahead, sir.

Jeff Mobley

Thank you and I appreciate everybody joining us for 2009 fourth quarter and full year earnings and operational update conference call. With me today is Aubrey McClendon, our Chief Executive Officer; Steve Dixon, our Chief Operating Officer; Marc Rowland, our Chief Financial Officer; Nick Dell'Osso, our Vice President of Finance; and also John J. Kilgallon, Manager of Investor Relations and Research.

Our prepared remarks will be brief and then we will it over to Q&A. Aubrey?

Aubrey McClendon

Thank you, Jeff, and good morning. We hope you've had time to review Tuesday’s operational release and yesterday's financial release. On the operational side, our production for the fourth quarter hit a new quarterly record with a daily average of 2.618 Bcfe. In addition, our production for the year hit a new annual record with a daily average of 2.481 Bcfe. These are increases of 13% and 8% over the year-ago period. Because of the strength of this production performance and our anticipated ongoing drilling success, we have also increased our 2010 and ‘11 production forecast for the second time in six weeks.

With the current gains coming from our oil and natural gas liquids plays, particularly the Granite Wash, we are now anticipating a 50% increase in our liquids production over the next two years. For all of our production, we are now projecting 8% to 10% growth in 2010, and 15% to 17% growth in 2011. These are of course net of property divestitures.

CHK proved reserve growth in 2009 was even more impressive. Proved reserves rose from 12.1 Tcfe at the beginning of the year to 15.5 Tcfe at year-end using 10-year strip pricing and to 14.3 Tcfe using SEC pricing assumptions. This time one year ago, we had forecasted CHK’s proved reserves would reach 14 Tcfe by year-end ’09 and 16 Tcfe by year-end 2010. It looks like today we will easily exceed our year-end 2010 goals of 16 Tcfe and we are well on our way to producing 3.5 to 3.7 Bcfe per day by year-end 2012 and owning 20 to 22 Tcfe of proved reserves by that day and maintaining unproved reserves on a risk basis of well over 100 Tcfe.

To back test our ability to reach these goals over the next three years, I remind you that for 2009 we added 3.4 Tcfe of proved reserves using 10-year strip pricing and 2.2 Tcfe of proved reserves using SEC pricing. So compounding that over the next three years would add 7 to 10 Tcfe in proved reserves. So we feel very comfortable projecting only a 6 to 8 Tcfe increase over next three years. Although I use the word only to describe our increase of 6 to 8 Tcfe over the next three years, you might note that if that were a standalone company, it would be a top 10 US gas producer that we will form inside of Chesapeake in jus the next three years. We believe that will add a reserve value that should translate into per-share value growth of at least $25 to $30 per share.

We continue to execute the nation’s most active drilling program, both overall and in the Barnett, Haynesville, Marcellus, and Granite Wash plays specifically. As for new plays, I would highlight that we will now be referring to our shale plays as the Big 6 rather than Big 4, given the emerging Bossier Shale play in Louisiana and given our newly acquired leaseholds in the Eagle Ford Shale in South Texas.

In the Bossier, we have 180,000 net acres and in Eagle Ford, we are now up to 150,000 net acres and hope to have 300,000 to 400,000 net acres before it’s all said and done. In addition, our liquids production is set to begin expanding rapidly due to the success we have established in six large, new, unconventional oil plays. Collectively, in these six plays, we own almost 600,000 net acres, expect to add 400,000 more net acres in the year ahead. We are the leader in each play technologically and also we own more acreage than any competitor in each play.

In addition, we have completed well in each play that had produced more than 500 barrels of oil equivalent per day on a multi-day basis in each play. If we are correct about these plays’ potential, we believe Chesapeake will have 3,000 to 5,000 oil wells to drill with an estimated per well average ultimate reserve recovery of 300,000 to 500,000 barrels of oil equivalent each. That means these six new plays that are primarily oil contain approximately 1 billion to 2.5 billion barrels of oil recoverable net to Chesapeake. Our horizontal drilling expertise and our unconventional geological target identification skills are second to none in the industry have been perfected over the past 20 years and will increasingly allow us separate ourselves from the industry pack in the years ahead.

I might also note that our Reservoir Technology Center continues to provide significant technological advantages. Since opening the RTC in April 2007, we have processed almost 23,000 feet of Core. Moreover, during the past three years, RTC has analyzed as many feet of Core samples as the two largest commercial facilities that are available to our competitors on a combined basis.

Please keep in mind these six oil plays do not even include the Granite Wash play of the Anadarko Basin, a very oily area in which our industry-leading acreage position is now 190,000 net acres. In this play, we are producing 200 million cubic feet of gas equivalent per day. We have 1.1 Tcfe of proved reserves. We have 3.1 Tcfe of risked unproved reserves. We have 4.4 Tcfe of unrisked unproved reserves.

We have completed 137 horizontal wells and have developed and delivered average gross reserves of approximately 900,000 barrels of oil equivalent per operated well. In the Granite Wash, we believe we have 900 more risk net wells to drill, with average gross reserves of approximately 900,000 barrels of equivalent possible. That is another 650 million barrels of oil equivalent at potential liquid rich reserves net to Chesapeake.

In addition, these calculations do not include our emerging position in the liquid rich portion of the Eagle Ford Shale play, a play in which we now have 150,000 net acres and expect to achieve a final level of 300,000 to 400,000 net acres. We are just beginning production from our first well and recently set pipe on our second well. We will begin ramping up our drilling activity in this area in the coming months and years.

Finally, we do wish to point out the fact that we believe was overlooked this week, following Anadarko’s impressive deal with Mitsui in the Northeastern Pennsylvanian part of the Marcellus play. In the area where Anadarko sold 100,000 of 300,000 net acres to Mitsui for 14,000 per net acreage, Chesapeake owned approximately 370,000 net acres of leaseholds that is of at least equivalent value to what Anadarko sold. This would put a value of $8 per share just for our acreage in the Anadarko area and Northeastern PA, and of course this is less than one-third of our total Marcellus holding.

In closing, we hope that all this information helps highlight for you a remarkable asset base that Chesapeake has assembled over the past five years. We believe it will form the foundation of industry-leading shareholder value creation in 2010 and for many years to come. This completes my commentary, and I’ll now turn the call over to Marc Rowland.

Marc Rowland

Thank you, Aub. And good morning, everyone. I’d like to begin this morning by discussing our full cost ceiling impairment. I’ve seen a comment or too expressing surprise at the charge given year-end pricing. Of course, the year-end pricing as of 12/31/09 is no longer the rule. The SEC has invoked a number of changes effective as of that date governing reserve bookings. One of those was with regard to the use of pricing.

We are now required to use the average price as of the first day of each of the trailing 12 months preceding that measurement date. This resulted in a NYMEX gas price of only $3.87, and a wellhead realization price of just over $3 for Chesapeake. I would note that we have not booked any goodwill in any of our acquisitions as compared to many of our peers who have substantial amounts of goodwill booked and remaining on their books today. Goodwill reduces the pool of cost against which the ceiling test is measured unlike we would have eliminated any such charge for us during the year.

Another factor in taking this charge as compared to 3/31/09, which was the date of our last charge and last based on impairment charge, was the reduced level of qualifying cash flow hedges we have in place as of 12/31, all of which from an accounting perspective can and will reduce any charge to the extent that the hedges are in the money. I hope it will take time to review our updated valuation analysis in the first part of our investors slide shown on our website.

We will see that the value estimates for each of our plays are conservatively estimated relative to multiple actual transactions in the industry, including the recent Anadarko sale to Mitsui that Aubrey just mentioned, our sale of Barnett assets to Total, and of course the XTO sale to Exxon. This analysis indicates that CHK today trades at a 60% to 75% discount to our actual net asset value. The discount was frankly inexplicable to us and one which we will work hard to eliminate this year.

Looking into 2010, we are continuing to successfully execute on our announced strategy. I note that the $2.25 billion joint venture was closed in January with Total in the Barnett, whereby CHK received $800 million in cash and will receive $1.45 billion in drilling carries. Further, we executed on a $180 million VPP in February. We have several asset sale transactions in the works in West Texas, East Texas, and the Appalachian Basin that are likely to be Q2 of this for Chesapeake. Also, we are beginning work on our seventh VPP transaction and find the interest levels buried active and high in this area.

Lastly, but importantly, I want to call your attention to our press release announcing the registration statement filed on Form S-1 for Chesapeake Midstream Partners LP earlier this week. We believe at Chesapeake Energy that there will be ample opportunities to achieve liquidity for CHK in the future, which could fund most, if not all, of our future CapEx midstream gathering cost in the Fayetteville, Haynesville and ultimately the Marcellus and other shales that we are now pursuing.

Moderator, I’d like to turn it over to the question-and-answer session, please.

Question-and-Answer Session

Operator

Thank you. (Operator instructions) And we will take our first question from Mr. David Heikkinen from Tudor, Pickering & Holt.

David Heikkinen – Tudor, Pickering & Holt

Good morning, guys.

Aubrey McClendon

Who is this?

David Heikkinen – Tudor, Pickering & Holt

I don’t even know anymore. I had a quick question on your reserves, just on the proved reserve base, how much of that is inside the shale-co and how much of that is more of the conventional business now? Just the splits that you’ve given at the Analysts Day, just trying to update that.

Aubrey McClendon

Dave, I don’t think we have it precisely, but we may be able to calculate it during the call, but roughly it’s about 60% shale and about 40% conventional rather.

David Heikkinen – Tudor, Pickering & Holt

Okay. And then as you think about the oil business that you are growing with the six new plays, how are you going to characterize the results? I know you’re still leasing in each of those, or you probably would have given some more details. I mean, what do you think about as far as -- should we just think about those as -- are they all very similar, are there any big differences either quality-wise, differential-wise, cost-wise per well as we start trying to think about value?

Aubrey McClendon

Good point, David. A good question, rather. When you say characterize, we presently just mean more descriptive information, and we will be -- the common theme I guess is that we will be developing all of them with horizontal drilling. So in our view, it’s proper to call an unconventional play. Basically, there is a shale play or two embedded in there. But for the most part, it’s tight sand plays that just haven’t worked from a vertical perspective. And they are all west of the Mississippi. So -- and in areas where we either have traditional operations, conventional operations or perhaps in some new areas as well.

And some of these areas that were in our plays that -- have been talked about, we’ve even mentioned, for example, the Cleveland horizontal play in the Anadarko Basin is one of those, where we’ve carved out a big position. So we’re not ready to talk a whole lot more about them, because as I mentioned in my call, we’re only about 60% -- in my comments, we’re only about 60% of the way done in terms of where we want to end up leasing. But I do want to emphasize that the biggest oil play of all right now that we have is the Granite Wash. And there we have a commanding presence, I think, in both the Colony Wash and the Texas Panhandle play.

David Heikkinen – Tudor, Pickering & Holt

And as you look at the guidance on the oil side, the oil growth -- it implies a big uptick, as you think, the first quarter, second quarter, can you talk at all about the trajectory of kind of quarterly progression for that increase in oil volumes through 2010 and ’11?

Aubrey McClendon

David, it will be a little bit more back-end loaded, but as you know, we don’t give quarterly production forecast anymore. So I can’t really break it out for you by quarter. I would note that our production was down in -- our oil production was down in the fourth quarter of 2009. And that really represents the transition that we are, I think, probably more than in the middle of, but actually coming out of that transition that we’ve made in 2009, away from some conventional plays that we had that produced oil to these unconventional plays that produce even more oil. And so you saw the effect of that I think in fourth quarter production, and likewise you will see the kind of boomerang effect on that starting in 2010, but really more of a back-end load I think.

David Heikkinen – Tudor, Pickering & Holt

Okay. Thanks, Aubrey.

Operator

Our next question will come from Mr. Scott Hanold with RBC. Please go ahead, sir. Your line is open.

Scott Hanold – RBC

Thanks. Good morning. Could you talk a little bit about how you approached the new SEC reserve booking requirements when you looked at PUD offsets relative to some of your plays, obviously the material level of what you have in, say, like the Barnett and the Fayetteville from other areas? Can you kind of give a little color on that?

Aubrey McClendon

Sure. We’ll turn that over to Steve Dixon.

Steve Dixon

Yes. We looked at all of our plays with the new SEC rules. And the Fayetteville and the Barnett were the only two that we felt we had enough statistics to be able to go further than one direct offset to the existing PDP well. We have, I think, 1,800 wells that we are in, in the Fayetteville and others too using that statistical approach and even more than that in the Barnett. I would speculate that by the end of this year, we would probably be able to do that in Haynesville.

Aubrey McClendon

And I would note that some other operators that have fewer wells than us in the Haynesville did book more PUDs in just one offset. So we feel like we took a very conservative approach in the Haynesville.

Scott Hanold – RBC

Okay. So then when you look at the Fayetteville and Barnett, I guess I have to do the math, but would that well (inaudible), how many offsets on average are you looking at there?

Steve Dixon

Well, it wasn’t a number of offset. It was defined a proven area and then our ownership within it. The ratio in Barnett PDP to PUD is actually only -- is less than 1. And in the Fayetteville, it’s 1.5. So I think there is still plenty of room to grow in the future in those plays.

Scott Hanold – RBC

Okay, appreciate that. And you talked about increased activity in the Eagle Ford and obviously you identified the Bossier is obviously one of the new Big 6 shale plays that you have right now. How active do you expect to get into Eagle Ford and what could be the limitations there? And then if I could ask a question on the Bossier, Aubrey, I know you’ve talked in the past regarding Pugh clauses, how would that impact your decision to drill Haynesville versus Bossier in that sort of fairway?

Aubrey McClendon

Well, it will remain the same as it has been, Scott, which is an almost complete focus and bias towards the Haynesville because the Bossier lies above and Louisiana leases commonly do have Pugh clauses in them. And I’m saying P-U-G-H, for those of you not familiar with the concept. But basically these type of leases only allow you to hold what you drill through. So if you’re drilling a Bossier well, typically you wouldn’t be able to hold Haynesville rights. And so until we get 100% HBP in the core part of the Haynesville, we won’t be doing much Bossier activity. We suspect that, Steve, by the end of ’11 and first part of ’12 will be pretty much all HBP.

Steve Dixon

Yes, by next year --

Aubrey McClendon

By the end of 2011, we’ll be all HBP. So Scott, at that point, we could begin in more aggressive development of the Bossier, but right now, it really doesn’t make much sense. We have a second well, I think, that we are getting ready to complete, and off and on, we’ll be drilling some Bossier wells just to gather more information. And I’m sorry, I missed your -- the first part of your question, was it about the Eagle Ford?

Scott Hanold – RBC

Yes, the Eagle Ford. Obviously it’s one of the two new to get to the six. And so how -- you talked about stepping up activity. Clearly you’ve already picked up a vast amount of acreage here in a short period of time since year-end. How active could you get in that area? And are there any infrastructure limitations because you’re focused on the high liquids part of the play?

Aubrey McClendon

There is always infrastructure issues in new play areas, but we are dealing with big ranches where once you have negotiated surface rights agreements, it’s actually probably easier to get infrastructure build rather than more difficult . So right now we’re taking a wait-and-see. We don’t even have our first well fully tested yet. But the play was promising to us. And we passed on the original part of the play that Petrohawk had their discovery and other companies were drilling up to the northeast because it was our view that we didn’t need more gas. When we investigated further and of course realized there was a significant combo play and an oil play, we jumped in and I think we’ve had a great deal of success in the oilier part of the play.

So as you probably are aware, we can get geared up pretty fast to address a play. And so we will see how we go here in the first part of 2010, but I would expect there would be a pretty rapid ramp-up here as well as in our other oil plays. And what will happen over time here is as we reach the level where the vast majority of our Haynesville, Fayetteville, Barnett acreage is HBP, we will begin ramping down activity in those areas and allocating those rigs to the oilier areas. For example, the last couple of years we drilled with 20 rigs in the Fayetteville. We will be basically 100% HBP there by the end of 2010, and we will cut our rig count in half. And I actually think that’s something that the rest of the industry will do as well. We see a lot of drilling today that maybe to investors and analysts doesn’t seem supported by pricing and that’s probably true, but there is a secondary driver in that activity and that’s to get that acreage HBP. But except for the Marcellus, all of that HBP in activities will happen here in the next 12 to 24 months.

Scott Hanold – RBC

That’s an interesting point you made there. You (inaudible) half in the Fayetteville, once you hit the HBP status, is that -- how do your JVs sort of alter some of that decision-making in terms of your requirement to drilling X number of wells? Is there any kind of thing there that would drive to be more active in any good play?

Aubrey McClendon

Only, Scott, to have a level of activity that allows us to earn our carries. So for example, in the Barnett and in the Marcellus drilling plays left where we have carries, we obviously would want to maintain a level of activity that would allow us to capture those carries in a shorter time as possible. So there are really two things that work here. One is, when do you hit HBP status, and when have your earned your carries? And so that’s why specifically we didn’t mention the Marcellus because it’s an area we wouldn’t ramp down. And with regards to the other areas that’s all collaborative, we will talk to our partners, Plains, BP, and Total, and make sure that our go-forward plans are consistent with their go-forward plans. And the Barnett actually will be increasing (inaudible) years before we level out, but definitely plan to drop in Haynesville and Fayetteville once we reach HBP status.

Scott Hanold – RBC

Got it. Appreciate it. Thanks, guys.

Aubrey McClendon

Hey, Scott, one other thing to get back on, you mentioned in your question about reserve booking and particularly in the Fayetteville and Barnett, I’d like to remind everybody on page four of our operations release, we do have a table showing what our proved reserves are and what our risked unproveds are. And so even though we took advantage of the new SEC rules in the Fayetteville and in the Barnett, we still believe we are only one quarter booked in the Fayetteville and only one-half booked in the Barnett. And so lots of future reserve booking upside there, and I encourage everybody to study page four. I think Marc Rowland also had another answer to -- more complete answer to the question of David. I can add that our reserves that are split between the shale plays and the conventional plays.

Marc Rowland

Yes. In respect to David’s question, even though Scott is on, but -- the Big 4 as of 12/31 represented almost exactly 50% of our total proved reserves. And if you consider the Washes to be part of that, I think you called it shale-co, is another 8%. So just under 60% is represented by those plays. If you look at the production, it’s remarkably similar. Our run rate in February, 53.5% of the production that we’re doing on a daily basis is coming from the Big 4 shale plays and the Wash represents 8.3% of our production during February. So a little over 60% on a production basis. We’re ready for the next question. Thank you.

Operator

All right. Our next question comes from Jason Gammel with Macquarie. Please go ahead, sir. Your line is open.

Jason Gammel – Macquarie

Thanks, guys. First of all, I just wanted to ask on the Eagle Ford leasing, would you be able to share any information on what counties you’ve already acquired leases on?

Aubrey McClendon

Jason, I’d rather not at this time although by disclosing that we are in the oilier part of the play, you kind of generally know what side of the play we’re on. So we’re just not there yet. We’ve got some projects that we’re working on, and we’d rather not take any risk of jeopardizing those. At the same time, we felt like we owe it to our investors to at least mention that we’re building a position in the play.

Jason Gammel – Macquarie

I kind of figured that it would be a strike. Back to the comments about shale-co, could you talk about what the growth rate on production of shale-co alone would be? I’m assuming that your activity levels on the conventional assets are actually fairly well right now and that it’s actually contributing a decline.

Aubrey McClendon

We’re deciding who is going to answer. I think -- I'm going to defer it to Marc.

Marc Rowland

Jason, I don’t have the exact numbers in play here. But obviously from our drilling activity level, about 90% of our drilling right now is being conducting either in the shale or the Washes, and that includes the coming shale plays as well. As to what the actual exit rate of our production, say, by the end of 2010 in those plays versus overall, clearly they are increasing in the conventional stuff that’s going down. But I don’t have an exact number -- on a piece of paper here. Do you, Steve --?

Steve Dixon

I may have some.

Marc Rowland

We can get it for you by the end of the call.

Jason Gammel – Macquarie

Okay, great. Maybe one more if I could then. The hedge volumes and prices were both up relative to the last disclosure that you made. Can I assume that there is some premium on some embedded sole calls [ph] in there? And if so, is there any collateralization obligation that comes if those go into the money?

Aubrey McClendon

The answer is kind of in reverse order, the calls that we have written are not embedded in the swaps. They are written for different periods of time. They are all written with our -- with one of our 13 counterparties in our secured hedging facility. So there is no call on any hedges that might be out of the money for us or in the money for the counterparties on additional collateral required as long as it’s within that facility. So we don’t risk having $100 well calls go to $150 and being short $50, have to rush up and send the money, or have to do anything. Does that get to the gist of your question?

Jason Gammel – Macquarie

I think it does. And I guess the other part of it is, because the price was increasing on the hedges in what was basically a declining gas price environment, I was just wondering if there was any premium from further sole calls that had helped the pricing on the Wash that you disclosed?

Marc Rowland

Yes. We talked about this in our last call. We have written swaps that in combinations with calls that we’ve written both for oil and gas have increased to swap value for 2010. And that’s the way we’ve approached to some of our hedging here. I think you will note that in 2010 we have virtually no knock-outs and we pursued a strategy that has largely eliminated that from our hedging strategy. So we’re basically either writing straight swaps. We are issuing calls to collect that premium or to have that premium enhanced to swap, or we do have some collars on. But all of those are true hedges and protect us completely in those hedges for that percentage if the price goes down below that strike.

Aubrey McClendon

Jason, remember, you can sell a $80 out-year oil call for the equivalent of about $3.50 per Mcf. So there is a lot of additional gas value that can be generated by being willing to sell out-year oil volatility and value.

Jason Gammel – Macquarie

Okay, understand. That made it very clear. Thanks, guys.

Marc Rowland

Aubrey, I’ve got the shale group. Looks like this year it was about 60%. We’re projecting next year a bigger number, about 40% growth in the shales, and in 2011, 25%.

Aubrey McClendon

Okay, great. So David, hope you got that and anybody else want to ask a follow-up, we’ll talk to you about it. Okay. Next question.

Operator

Our next question comes from Mr. Dave Kistler with Simmons & Company.

Dave Kistler – Simmons & Company

Good morning, guys.

Aubrey McClendon

Good morning.

Dave Kistler – Simmons & Company

With kind of the increasing focus on oil plays and talk about dropping rigs eventually once you’re holding production in some of the shale plays, can you just talk a little bit about your thoughts around Btu convergence between the two products? By actions, it would seem like you’re highlighting that you think oil is going to be a premium fuel for quite a while.

Aubrey McClendon

Yes. I think if you just look at the curve, you’ve got basically a $14 to $15 Mcf equivalent oil curve out there and little less than half of that on the gas side. So clearly every producer in America has got to be looking at how they can increase their oil production. It won’t matter with regard to world oil balances, the success we find in oil in the United States is not going to affect negatively oil prices, whereas on the other hand, obviously when you find more gas, it has the potential of negatively affecting gas prices. So sometimes producers are accused of not being rational. We think we’re a lot more rational than people give us credit for, and we are responding to price signals.

With regard to the ability to see price convergence, I hope in my career we are able to see that. I think it would be through an uplift of gas prices rather than a downdraft in oil prices. And whether it be gas to liquids or whether it be a big increase in the transportation sector’s demand for natural gas, either directly through CNG or indirectly through additional electricity, that is obviously the Holy Grail for our industry is to have gas achieve oil pricing imparity in the US.

Around the world, as we talk to our partners, Statoil and Total and BP and other people, and talk to them about how they see world LNG balances, I think there is an emerging view that beyond 2012 and ’13, there are likely -- we are likely to get back into a scenario of world gas prices approach world oil prices and we’re likely to be short world -- gas on a worldwide basis. One thing I think we’ve learned so far in the past year is that the world is not going to be a wash and shale gas in the next five to 10 years. That is proportion -- the success of that proportion, I think, is unique to North America and will be many, many years before it becomes -- has any impact on worldwide gas balances.

Dave Kistler – Simmons & Company

Great, thank you. Maybe a follow-on to that. Can you talk a little bit about your current expectations for threshold gas prices in the state? If we think about -- in North America, if we think about where rig counts being directed over the last 12 months, it looks like it’s going to highly economic place or place that are economic sub $5, not a whole lot of rigs moving to conventional plays. And accordingly, does that put pressure on that threshold gas price that you guys have talked about in the past? Maybe just if you could elaborate around that, that would be great.

Aubrey McClendon

Sure. I think we’ll approach that question maybe two ways. One is, when you say sub $5 gas prices, I assume you are referring to NYMEX prices. And when you include basis differentials as well as gathering and compression, $5 NYMEX really means about $3.50 at the wellhead. And despite the success that many of us have had in developing shale reserves, I think $3.50 gas at the wellhead does not create enough cash flow in the industry to maintain even today’s drilling pace. And so I think $5 gas is not a sustainable gas price for even the best shale plays.

With regard to the unconventional or rather the conventional stack, it’s still our view that gas prices will be set by the gas price required to incentivize another couple hundred rigs to go back to work on some conventional plays. And we stand by our completion on that that we’ve set forth over the last year so that we think that number is somewhere between $6 and $8, and have seen nothing in our own company or in the industry to persuade us that we’re wrong. I would note that based on what we’ve seen so far in the industry’s production performance in the fourth quarter, there are more companies that are showing sequential production declines and increases. And so we think the 914 data will likely begin to reflect what we’re beginning to see in the company data. And of course, keep in mind that the 50% of production you all see through public company reports is the best 50% of the gas production in the US, and you’re not seeing the worst 50%. And we think that’s probably a fairly substantial decline at this point.

Dave Kistler – Simmons & Company

Great. Thank you for that. And one last question just on the Granite Wash. Are there specific geologic targets you are looking to hit there, kind of Marmaton or Red Fork, Cherokee, Atoka, any specific areas you could highlight that you’re going to be going after?

Aubrey McClendon

We call the Granite Wash the Granite Wash, David. And so we wouldn’t include Marmaton or Red Fork or Atoka, any other Pennsylvanian age formations or discrete and separate potential horizontal targets for us. However, inside the Granite Wash, there are multiple Granite Wash targets, whether they be called pulses or zones. And in the Colony Wash area, there are roughly three of those. In our Texas Panhandle area, oftentimes we have up to five stacked plays. So we’re still experimenting with how best to develop those stack plays within the Granite Wash. But the whole Anadarko Basin’s stratographic column is one that we think is very conducive to oily development or liquid rich development. And given our enormous leasehold position in the heart of that basin, we expect to have success with a lot of other formations in that area besides just the Granite Wash.

Dave Kistler – Simmons & Company

Great. Thank you guys very much.

Aubrey McClendon

Thank you, David.

Operator

And our next question comes from Brian Singer with Goldman Sachs. Please go ahead, sir.

Brian Singer – Goldman Sachs

Thank you. Good morning.

Aubrey McClendon

Good morning, Brian.

Brian Singer – Goldman Sachs

Following up on a couple of the earlier questions, kind of going back to oil versus gas drilling and your rig count, are you with the minimum rig count in your core areas and really in all the areas to either hold the acreage or per your joint agreements? And so if we’re looking at the period until your acreage is held by production, should we expect that additional oil drilling would be additive to your CapEx, or is there any room to pull anything off on the natural gas side to make room for more oil drilling?

Marc Rowland

Brian, you saw a little bit of an uptick in our CapEx in 2010 and ’11. And that is the net impact of somewhat reduced gas drilling going forward with probably greatly increased oil drilling. And the net-net of that was a slight increase in CapEx. So that transition is already underway. I think you used a term minimum rigs, I almost think about it as maximum rigs that we’re using to get to that HBP status before our leases start to expire. And as I mentioned, it’s different with every play. That’s 2010 for the Fayetteville, 2011 for the Haynesville, probably 2012 for the Barnett, and then kind of the mid-teens or so are going to be for the Marcellus. So that process is well underway of transitioning in our budget, which we budget internally out to 2012. We only disclose budgeting out to 2011. But that shift from gas to oil is already underway and will begin becoming more obvious in our numbers -- in our production and reserve numbers going forward as well.

Brian Singer – Goldman Sachs

Great. Great, thanks. And then secondly and separately, you’ve never been shy about talking about the bottoms-up resource value and resource potential. Any recent changes in thoughts in terms of potentially trying to either monetize the additional joint ventures or spinning off portions of your portfolio?

Aubrey McClendon

Well, with regard to additional joint ventures, clearly the Eagle Ford would be an area where we would probably look for a partner once we are through with our leasehold acquisition -- a primary portion of our leasehold acquisition there. With regard to any spin-offs or any other ways to highlight the value that’s embedded here, I’ll just highlight what Marc said in his prepared remarks, that is a somewhat inexplicable discount that is measured in the tens of billions of dollars. And I’ll just say it has our attention.

Brian Singer – Goldman Sachs

Great. Thank you.

Operator

And we will move on to our next question from Chris Gault [ph] with Barclays. Please go ahead.

Chris Gault – Barclays

Hey. In regards to the SEC PUD booking rules changes, I know you all said the Barnett and the Fayetteville were two areas that benefited from that. Can you quantify those PUD quantities that you book there just related to the change in rules, not related to pricing?

Aubrey McClendon

I don’t think we are willing to disclose that level of detail, Chris. I’ll --

Marc Rowland

We didn’t really do it two ways either. So I don’t have a one booking versus the other -- Chris, why don’t we do this? Just to be clear on your question, I might ask you to get with Jeff afterwards and see if it’s -- if there is an answer we have for you. If not, we apologize and we’ll just continue to disclose what level of detail that we’ve set forth in our releases.

Chris Gault – Barclays

Okay. That’s fair. Thanks, guys.

Aubrey McClendon

Okay. Thanks, Chris.

Operator

And our next question comes from Ronny Eisemann with JPMorgan. Please go ahead, sir.

Ronny Eisemann – JPMorgan

Hi, good morning. I just have a question about the six new oil plays. How many of them, if there are any, are in the Rockies? And if you wouldn’t mind providing any color on that.

Steve Dixon

Ronny, I’d just say that less than a majority or so -- I don’t intend to be cute, but also want to protect what we’re working on. We do drill wells under our own name. So if somebody wants to find out where we’re drilling anywhere in the US, it’s pretty easily discoverable. So if it would be all right with you, I’d like to leave it at that for now.

Ronny Eisemann – JPMorgan

All right. Thank you, guys.

Aubrey McClendon

Thank you.

Operator

(Operator instructions) We will take our next question from Biju Perincheril from Jefferies. Please go ahead.

Aubrey McClendon

Hi, Biju.

Operator

It looks like his line disconnected. We will move on to Ray Deacon from Pritchard Capital.

Ray Deacon – Pritchard Capital

Yes. Hi, good morning. I had a question about the Bossier. Just can you give details on how many wells have been completed and maybe average IP rates?

Aubrey McClendon

Ray, for us, the well is one. We have a second well that we will be bringing online in probably next 30 days or so. Steve, help me. I don’t think we’re drilling a Bossier well right now. We’ve got few on the drilling schedule. In the industry, I think that I’ve seen that Petrohawk is about to drill and I think a couple of other companies have reported some Bossier wells. EnCana, I think, said four wells. There are probably less than 10 out there, but you can tell quite a bit about the rock from the samples, the core samples that we have, and we’re pretty comfortable using a 5.5 Bcfe EUR versus 6.5 in the core part of Haynesville.

Ray Deacon – Pritchard Capital

Got it. Great. And you -- the thought that it’s still Southern De Soto Parish looks like where it’s best then.

Aubrey McClendon

It’s where -- yes. I mean, Southern De Soto is kind of in the center of the universe for both Haynesville and Bossier. The Bossier does cover more than just Southern De Soto, but that’s a pretty good spot to be.

Ray Deacon – Pritchard Capital

Got you. Great, thanks. And I guess can you just walk me through a little bit -- how your thinking works with the Midstream JV -- or I mean, with the IPO as far as -- I mean, will further assets drop down into that and could it potentially give you higher growth rates in ’11 and ’12, and what you’re showing now, I guess?

Aubrey McClendon

We’re on pretty short leash here from our lawyers [ph] on this. So I’m going to defer to Marc, so any mistakes that are made are his, not mine.

Marc Rowland

Sure. We are under some restrictions here. So I won’t talk about it on the Midstream side of the entity that is filed. I’ll just kind of reiterate from the Chesapeake side. The Chesapeake Energy strategy for sometime going back to the announcement of the formation of this joint venture with global infrastructure partners back to September has been a growth oriented story with Chesapeake inside of the entity not filing, developing the Fayetteville, the Haynesville, the Marcellus and some other assets on what is a very big and capital-intensive program. We are spending a lot of money that ultimately needs to be recouped either through the sale of assets to, A, ventures such as Chesapeake Midstream, or to a third-party or some other formation of a capital raise.

There are many avenues that are attractive to us, and these type of assets are easily financiable [ph] either through issuance of notes or equity-type ventures. So I think it’s pretty clear that Chesapeake’s growth in the shale plays demands a lot of Greenfield Midstream gathering type assets that we have budgeting for, and you see it on our cash flow that Jeff and others have prepared for our kind of overview of what we’re spending in 2010 and ’11. And that will continue into the ’12, ’13, and ’14 period as well. So I think it’s pretty clear what our strategy is from a Chesapeake Energy standpoint, and the filing of this registration statement is just one avenue that we’re pursuing.

Ray Deacon – Pritchard Capital

Got it. Thanks very much.

Operator

And our next question comes from Marshall Carver with Capital One Southcoast. Please go ahead.

Marshall Carver – Capital One Southcoast

Yes. Just a couple of questions. One, on the 90% risking in Eagle Ford, is that because you drilled so few wells or do you view that play as substantially higher risk than other plays, or what are your thoughts behind that?

Aubrey McClendon

Marshall, it’s really -- I mean, I think those two things are really one and the same. We’ve not drilled many wells. The industry has not drilled that many wells. Certainly in some parts of the play you have a risk factor -- I think (inaudible) 90%. But our acreage is -- we just feel comfortable -- or we feel uncomfortable I suppose risking at any less than that. I really don’t have any production to talk about. So like all of our shale plays, you’ve got the rocket [ph] there. The gases and oil is in place. The technology exists. The capital exists. The drilling expertise exists. It’s just a matter of going out and proving all that we know is in fact 100% true, and we’ll be doing that in the course of 2010. And you’ll see that risk factor drop pretty dramatically to ultimately to levels that in all of our plays we think it will drop to 10% or 15%.

Marshall Carver – Capital One Southcoast

Okay, that’s helpful. And one more question on the -- when I look at the exit rates, you give net exit rates by the Granite Wash and the Big 4 shale plays. When I add all those up, it looks like they are going up on a higher percentage basis for the 2010 exit rate and 2011 than the full year -- than the total company production. Over the last two or three months, has there been an increase in implied asset sales or bigger declines in the conventional plays, or would it be more just conservative guidance for the total company?

Aubrey McClendon

Well, we’d like to think that there is some conservative guidance in there, but there was another question that I think we tried to get to on this. But part of our company is in decline what I guess you’d call conventional-co. Shale-co is growing much more rapidly than the rest of the company overall, because the rest of the company is burdened by a 40% production base that is declining at the moment. So shale-co has to be increasing more than, say, the 16% to 18%, for example, of growth that we projected for 2011 or 8% to 10% for 2010. So that is in fact the case and will remain the case basically. In an indefinite time in the future, the shale-co part of the company will decline faster than we hope it would [ph].

Marc Rowland

And it is also accurate to say that we have predicted or projected conventional company monetizations through the VPPs and through asset sales. So it’s not sold out in there, but conventional-co not only is declining normally, naturally through the deflation rate, but we’re also reducing production estimates in that because of monetizations that we’ve talked about.

Marshall Carver – Capital One Southcoast

Okay, thank you. That’s it for me. Thank you.

Aubrey McClendon

Just to kind of highlight that, at various time during the first six months of -- or actually the next four months, March to June, we would expect monetizations to reduce our production by about 60 million cubic feet of gas per day in the first month. And that would all come out of the conventional base, and it is of course built into our production forecast. But just to remind you, the growth that we’re generating is net of continuing to put cash out of our conventional assets. Okay. We’ll go to the next question.

Operator

Our next question comes from Jeff Robertson with Barclays Capital. Please go ahead.

Jeff Robertson – Barclays Capital

Thanks. Marshall asked couple of the questions I was going to try to get, Aubrey. But in terms of the risk factors that you all are using, with the drilling plans you have and say the Marcellus and the Bossier and the Eagle Ford, are you able to give a number on where you think those might at the end of 2010 and maybe 2011?

Aubrey McClendon

I think we probably could (inaudible) guesses at this point and my guesses might be a little different from some other folks. But if you’re looking at the Marcellus, it’s at 70%. Today I don’t see why that wouldn’t be headed towards under 50% in the next couple of years. The Haynesville is at 40%. Some of that reflects that we have some acreage that we’re going to sell. And once we get sold, that by definition would derisk our leasehold position. So I would think that would get down into the 20% to 25% range. The Fayetteville is at 20, that’s going to be probably a 15% number. The Barnett likely to be 10% to 15%. It’s 15% today. Bossier and Eagle Ford are at 80% and 90% respectively. And certainly over the next couple of years I would hope we’d be able to get those closer to 50% as well, which naturally increases the potential risked unproved reserves quite substantially over time.

Jeff Robertson – Barclays Capital

And then secondly, I think Marc mentioned that you all are now working on VPP-7.

Marc Rowland

That’s correct, yes.

Jeff Robertson – Barclays Capital

Is the part of the preferences for VPPs have to do with just maintaining the assets for the optionality that either commodity prices or technology opens up new opportunities on some of the assets that you do VPPs on versus some that you might look to sell -- if the market is there, just to sell them outright?

Marc Rowland

I think that’s certainly part of it. I think there is really three things that I think about VPP and why we might use that versus an asset sale. One is the lengthy nature of some of our conventional production when sold through a traditional buyer after eight or 10 years of production, really you’re getting zero value from the buyer on the tail of that production. So in some of our VPP’s, the tail of the production and the coverage ratios are 70% of the total asset value or more. So by getting nearly as much proceeds as you could from a conventional player, which by the way would be taxable where the VPP is not taxable. We can maintain a large kind of optionality as you put it.

The second thing I think about is the technology in the deeper drilling. Reserves over time in Oklahoma and in Appalachian Basin, for example, new plays have come out just like the Marcellus, which underlies much of the assets that we bought back from CNR in 2005. And so we did a VPP there, keeping the optionality of new technology, new plays that are deeper. So I think that’s certainly one way to think about it. And then the third thing honestly is that, in this market, the financial players with a VPP that might be equivalent to an investment grade type of investment, significantly broadens the potential universe that people that are willing to give us money. We operate for those people. We keep our skin in the game. And so they come forward at discount rates that are lower than what I’ve seen the potential competing asset buyer discount rates being lower for the financial players than what the industry, let’s say, is willing to accept. So those are several reasons why I think VPP is attractive to us.

Aubrey McClendon

The good news is, Jeff, nobody else seems to like them but us. So we like that the whole market is ours.

Jeff Robertson – Barclays Capital

Okay, thanks. And if I could one more question, just in terms of your proved undeveloped reserves, Steve, did you all make any adjustments in it to what you might have carried for PUDs and areas where you’re just not drilling PUDs and where you’re just doing horizontal work? Is everything is off the books?

Steve Dixon

Yes, Jeff, we did a -- quite a bit we extensively went through really looking at intent over the next five years on what the wells we’ll be drilling, and so there was a lot in some of our older areas where we had drilled historically, like in Sahara and some of the shale gas plays that we removed those reserves from our books even though they would be in proven areas, it was not in our intent to drill within the next five years.

Jeff Robertson – Barclays Capital

Okay, thank you.

Operator

And our next question comes from David Tameron with Wells Fargo. Please go ahead.

David Tameron – Wells Fargo

Hi, good morning. I still got one more question, believe it or not. Marc, if we circle back to the impairment charge, help me out with the mechanics. So you are saying that first quarter you had that number of -- whatever it was, 3, mid-3s. You took the impairment charge. And then if you could circle back at the end of the year and apply the 12-month price to the -- once again, to the entire book, is that what happened?

Marc Rowland

Yes, that’s exactly right. The SEC rule change that many people have asked questions about, about how we’ve booked and so forth included, a new requirement that as of that date and going forward, each one of your impairment test measurement dates uses the first of the month pricing from the trailing 12 months on an unweighted basis, January 1, February 1, and so forth. In 2009, the unweighted average price for gas was $3.87. Now going forward every quarter, it should obviously get better because prices have been going up. But at the end of the year, price was a couple of dollars higher, and of course we would not have had an impairment charge. Second rule that changed is that just because prices go up after your measurement period, which was true in June and September such that we didn’t have a charge. That rule was revoked, if you will, and is no longer in place. So the mechanics of how it’s applied has changed and will be (inaudible) going forward, although we don’t think that will yield any additional impairment charges.

David Tameron – Wells Fargo

Okay. So just to make sure I’m hearing this right. So first quarter 2010, March 31, 2010, you will once again take the first of the prior 12 months, so you go back to April 1?

Marc Rowland

April 1, that’s correct. The April 1 and then the succeeding 12 months up through March 1st to measure the average price for those 12 months at March 31st.

David Tameron – Wells Fargo

All right. Thanks.

Aubrey McClendon

I’d like to throw in one more answer to Jeff Robertson’s question about revision due to aging PUDs. That was about 0.5 Tcf number -- 0.5 Tcfe number. So Steve is right. We scrubbed it very clean and still had enormous reserve growth even though we took out 0.5 Tcfe during aging and also know plans to go back and drill wells that maybe were once attractive conventional targets and today are not particularly attractive. Okay. Do we have any further questions?

Operator

Yes, we do. Our next question comes from Rehan Rashid with FBR Capital Markets.

Rehan Rashid – FBR Capital Markets

Good morning, Aubrey. On the oil play front, the comfort we’re talking more about it, was there -- was the driver here, maybe any kind of a technological milestone or achievement that is making more sense to kind of go after these oilier plays?

Aubrey McClendon

Rehan, I think -- two things really to think about. One is that we have more acreage than we had in the past. And so we’re willing to be a bit more chatty about it, and as our acreage position in these plays grows over the next year, we will be able to talk more about it. In addition, we have some production results from some of these plays that we’ve been at 90 days or 180 days ago. So it’s a combination of we’ve actually had more than a concept. We have a play that looks like they are beginning to unfold before us. And in reaction to that, we’ve been rapidly increasing our acreage position in these plays and still have ways to go. And we would rather talk more about them later in the year once we have more production to talk from and a larger acreage space as well.

Rehan Rashid – FBR Capital Markets

Got it. So not really any kind of a frac or a proppant that would work better or a process that would work better?

Aubrey McClendon

Well, all that is evolutionary. I mean, clearly I think we’re doing better in these plays, drilling wells today than we would have a year or two ago. And I suspect that we’ll be better a year from now as well. So the answer to that is yes, but I wouldn’t think of it as a revolutionary breakthrough, more as an evolutionary part of the process.

Rehan Rashid – FBR Capital Markets

Okay. Thank you.

Operator

We’ll move on to our next question from Shilpa Kumar [ph]. Please go ahead -- from Jefferies. Excuse me.

Biju Perincheril – Jefferies

Hi, this is actually Biju. Quick question. I’ll be going back to your guidance on oil volumes. I look at your oil production numbers for 2009 more or less flat, even though you were ramping up activities in Colony Wash. So going forward, I guess the question is, is there a different zone within Colony Wash that you’re targeting or is there a difference in completion that would yield higher liquid volumes, or the increased guidance, is there a pretty significant amount coming from the new plays that you’re talking about?

Aubrey McClendon

I think the answer is both, Biju. We only had three to four rigs running in Colony Wash during 2009. We are doubling that in 2010. So that’s what takes us out of not flat growth, but I mean, modest growth to pretty aggressive growth when you double the rig count. And then the other part is the increase in these other oil plays that we have targeted. And remember, every time I say oil, I’m also including condensate natural gas liquids in there as well. So it’s just the whole liquid side of the company is getting more emphasis and is growing quite rapidly and will continue to, we hope, for years and years to come.

Biju Perincheril – Jefferies

Okay. And one more, but when you look at the plays that are -- looks promising, shale plays that looks to be oil prone, any reason more of them are popping up in the northeast region, looking at the activities that you have and others? Any reason for that from a geologic setting?

Aubrey McClendon

Well, sure. I mean, if you just look at the whole part of the country from the Williston Basin down into the Rockies, particularly the northern Rockies, it’s just an oil prone basin and I guess kind of super basin, if you will. And there are a lot of geochemical reasons for that, geological reasons for that. Lot of gas heads found in those areas, but I think that’s what has so many Rockies players excited about the area. We are disappointed that our two attempts to buy big property sets in the Bakken in 2005 and 2007 did not work, so I don’t think we have a big position there. And as a result of that and our success with gas, I think it’s the one strategic weakness that the company has, which is we are, in the fourth quarter, 93% gas, in a world that does not value gas molecules the way they value oil molecules.

So we and others have been shifting over the past couple of years to focus more on oil side of the business, and that’s what we’re doing. And that shift takes time, and the generation of new ideas and the acquisition of acreage and then drilling and completion of wells, and watching the production, all really gets measured in years, not in months. And so what you are going to see unfolding in our company in 2010 and ’11 is actually something we signaled in March of 2008 that we were going to look far more seriously at developing oil price. And that’s taken some time, but we’ve had a great deal of success. And it has taken us to some parts of the US where we’ve not traditionally been a player, both areas that we think are oil prone and areas where we think we ought to have a big presence.

Biju Perincheril – Jefferies

Great. That’s all I had. Thank you.

Aubrey McClendon

Okay. Thank you.

Operator

(Operator instructions) Our next question comes from David Snow with Energy Equities Incorporated. Please go ahead.

David Snow – Energy Equities Incorporated

Yes, hi. I’m intrigued by your saying that the Anadarko Basin’s strata have a lot of different opportunities for oil. I’m wondering -- are you envisioning horizontal drilling in a lot of the shallower zones that are more oily or what’s your -- and would that eventually be able to really give you a ramp-up to a major percentage of oil? Right now it look like through 2011 you’re still going to just make a slight dent in the percentage of oil. Is that going to be something that you will really hit going into the future?

Aubrey McClendon

David, we certainly intend to have oil be a bigger part of our percentage of production going forward, starting with a base of only 7% and with a gas production profile that’s rapidly increasing as well. It will be tough for oil to increase to much more than probably in the teens for the foreseeable next few years. But you’re right. The Anadarko Basin has a lot of potential for horizontal drilling and oil prone plays. And we’re focused on it and have a commanding position in that area and we’ll have more to talk about them as the year progresses.

Operator

Okay. Go ahead, I’m sorry.

Aubrey McClendon

That’s right. I think we’re all -- I think we are in over time and we’re just getting ready to wrap up. So -- and we appreciate everybody’s question today and look forward to talking to you again. If you have follow-up questions, please let John Kilgallon or Jeff Mobley know. Thank you.

Operator

That concludes today’s presentation. Thank you for your participation.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Chesapeake Energy Corporation Q4 2009 Earnings Call Transcript
This Transcript
All Transcripts