Chesapeake Energy Corp (CHK) 0 Q0 法說會逐字稿

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 your host, Mr.

Jeff Mobley.

Please go ahead, sir.

Thank you, and I appreciate everybody joining us for our 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 Kilgallon, Manager of Investor Relations and Research.

Our prepared remarks should be brief, and then we'll turn it over to Q & A.

Aubrey?

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 periods.

Because of the strength of this production performance and our anticipated ongoing drilling success, we've also increased our 2010 and 2011 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's 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 2009 and 16 TCFE by year-end 2010.

It looks like today, we will easily exceed our year-end 2010 goal of 16 TCFE and that 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 approved reserves by that date, 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 approved reserves using SEC pricing.

So compounding that over the next three years would add 7 to 10 TCFE improved reserves.

So we feel very comfortable projecting only a 6 to 8 TCFE increase over the 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 stand-alone company, it would be a top 10 US gas producer that we will form inside of Chesapeake in just 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 Six rather than the Big Four, given the emerging Bossier Shale play in Louisiana and given our newly acquired leasehold 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 wells in each play that have produced more than 500 barrels of oil-equivalent per day on a multiday 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 to 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, the RTC has analyzed as many feet of core samples as the two largest commercial facilities that are available to our competitors did on a combined basis.

Please keep that in mind these six oil plays do not even include the Granite Wash play or 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 risked net wells to drill.

And with average gross reserves of approximately 900,000 barrels of oil-equivalent possible, that is another 650 million barrels of oil-equivalent of potential liquids-rich reserves net to Chesapeake.

In addition, these calculations do not include our emerging position in the liquids-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 have 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 Pennsylvania part of the Marcellus play.

In the area where Anadarko sold 100,000 of its 300,000 net acres to Mitsui, for $14,000 per net acre, Chesapeake owns approximately 370,000 net acres of leasehold.

That is 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 holdings.

In closing, we hope that all this information helps highlight for you the 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.

Thank you Aub and good morning everyone.

I'd like to begin this morning by discussing our coal cost ceiling impairment.

I've seen a comment or two expressing surprise at the charge, given year-end pricing.

Of course, 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 the 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 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 costs against which the ceiling test is measured, and likely 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 when we last faced an 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 do reduce any charge to the extent that the hedges are in the money.

I hope you will take time to review our updated valuation analysis in the first part of our investor slide shown on our website.

You 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.

A discount that's 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 events for Chesapeake.

Also, we're beginning work on our seventh VPP transaction, and find the interest levels very 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 costs in the Fayetteville, Haynesville and ultimately the Marcellus and other shales that we're now pursuing.

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

Thank you.

(Operator instructions)

And we will take our first question from Mr.

David Heikkinen from Tudor, Pickering and Holt.

Good morning, guys.

I had a quick question on your reserves, just on the proved reserve base.

How much of that is inside the shaleco, and how much of that is more of the conventional business, now just the splits that you had given at the analysts' day, just trying to update that.

David, I don't think we have it precisely, but we maybe able to calculate it during the call.

But roughly, it's about 60% shale and about 40% on -- conventional, rather.

Okay, and then as you think about the oil business that you're 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.

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.

Good point, David.

Or good question, rather.

When you say "characterize" we presume you just mean more descriptive information.

-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 them unconventional plays.

Basically, there's a shale play or two embedded in there, but for the most part, it's tight sands plays that just haven't worked from a vertical perspective and they're all west of the Mississippi in areas where we either have traditional operations, conventional operations or perhaps in some new areas as well.

Some of these areas that were in our plays that have been talked about we've even mentioned, for example, the Cleveland horizontal play and the Anadarko basin is one of those where we've carved out a big position.

We're not ready to talk a whole lot more about them because, as I mentioned in my call, 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 the biggest oil play of all right now, that we have, is the Granite Washes, and there we have a commanding presence I think in both the Colony Wash play and the Texas Panhandle play.

And, as you look at the guidance on the oil side, the oil growth, it implies a big uptick as you think first quarter, second quarter.

Can you talk at all about the trajectory of the quarterly progression for that increase in oil volumes through 2010 and '11?

David, it'll be a little bit more back-end loaded, but as you know we don't give quarterly production forecasts any more so, can't really break it out for you by quarter.

I would note that our oil production was down, in the fourth quarter of 2009 and that really represents the transition that we are probably more than in the middle of, but actually coming out of, that transition that we 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.

Okay, thanks Aubrey.

Our next question will come from Mr.

Scott Hanold with RBC.

Please go ahead sir, your line is open.

Thanks good morning.

Could you all talk a little bit about how you approached the new SEC reserve book and requirements?

When you looked at putoffs, that is relative to some of your plays.

Obviously the maturity level of what you have in say like the Barnett and the Fayetteville -- and some other areas, can you kind of give a little color on that?

Sure, we'll turn that over to 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 existing PDP well.

We have, I think, 1,800 wells that were in, in the Fayetteville, and others to use in 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 the Haynesville.

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

Okay so that when you look at the Fayetteville and Barnett, I guess I will have to do the math, but what does that well a -- how many offsets, on average, are you looking at there?

Well, it wasn't a number of offsets.

It was defined in a proven area and then our ownership within it.

The ratio in Barnett of PDP to PUD is actually less than one and in the Fayetteville, it is one-and-a-half so I think still plenty of room to grow in the future in those plays.

Okay.

Appreciate that.

And you know, you talked about increased activity in the Eagle Ford, and obviously identified the Bossier as obviously one of the new Big Six shale plays that you have right now.

How active do you expect to get in the Eagle Ford and what could be 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?

It'll remain the same as it's 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 am saying "P-u-g-h" for those of you not familiar with the concept.

Basically these type leases only allow you to hold what you drill through so you drill 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 by the end of '11 and the first part of '12, we'll be pretty much all HBP?

Yes, by next year.

By the end of 2011, we'll be all HBP so, Scott, at that point we could begin 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're 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 the first part of your question, was it about the Eagle Ford?

Yes, the Eagle Ford.

Obviously it is one of the two new to get to the six so, you talked about stepping up activity, and 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?

You know, there's 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 built, 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 looks promising to us and, we passed on the original part of the play, where 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 that there was a significant combo play and an oil play, we jumped in and I think have 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 to 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 have drilled with 20 rigs in the Fayetteville.

We'll be basically 100% HDP there by the end of 2010.

And we will have cut our rig count in half.

And actually I think that's something that the rest of the industry will do as well.

You 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 is to get that acreage HBP.

But except for the Marcellus, all of that HBPing activity will happen here in the next 12 to 24 months.

That's an interesting point you made that you cut your rig count in half in the Fayetteville, once you hit HBP status.

How do your JVs sort of alter some of that decision-making in terms of, your requirements to drill x number of wells?

Is there any kind of thing there that would drive you to be more active in any given play?

Only, Scott, to have a level activity that allows us to earn our carries.

So, for example, in the Barnett and in the Marcellus, the only 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 as short a time as possible.

So there are really two things at work here.

One, when you hit HBP status, and when have you earned your carries.

That's why I specifically didn't mention the Marcellus, because it's an area we wouldn't ramp down in.

With regard to the other areas, it'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 rigs for a few years before we level out.

But definitely plan to drop in Haynesville and Fayetteville, once we reach HBP status.

Appreciate it.

Thanks, guys.

Scott, one other thing to get back on.

You mentioned in your question about reserve booking and particularly in the Fayetteville and Barnett, I would like to remind everybody on page 4 of our operation release, we do have a table showing what our proved reserves are and what our risked unproved are.

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 4.

I think Marc Rowland also had a more complete answer to the question that David Heikkinen had about our reserves that are split between the shale plays and conventional plays.

This is back to David's question, even though Scott is on, but the big four 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 he called it shaleco, 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 of 53.5% of the production that we're doing on a daily basis is coming from the big four 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.

Our next question comes from Jason Gammel with Macquarie.

Please go ahead, sir, your line is open.

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?

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 would rather not take any risks of jeopardizing those.

At the same time we felt like we owed it to our investors, to at least mention that we were building a position in the play.

I kind of figured that'd be a strike.

Back to the comments about shaleco.

Could you talk about what the growth rate on the production of shaleco alone would be?

I'm assuming that your activity levels on the conventional assets are actually fairly low right now and that it is actually contributing in decline?

We're deciding who is going to answer.

I'm going to defer to Marc.

Thank you.

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 conducted 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 and the conventional stuff is going down.

But I don't have an exact number on a piece of paper here do you, Steve?

I may have some.

I bet we can get it for you by the end of the call.

Okay, great.

Maybe one more, if I could then.

The hedge volumes in prices were both up relative to the last disclosure that you made.

Can I assume that there's some premium on some embedded sold calls in there and, if so, is there any collateralization obligation that comes if those go into the money?

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 one of our 13 counter-parties and 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 counter-parties, on additional collateral required, as long as it's within that facility.

So, we don't risk having $100 oil call go to $150 and being short $50, have to rush out and send the money or have to do anything.

Does that get to the gist of your question?

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 sold calls that had helped the pricing on the swaps that you disclosed?

Yes, we talked about this at our last call.

We have written swaps that, in combination with calls that we've written both for oil and gas, have increased the swap value for 2010.

And that's the way we've approached some of our hedging here.

I think you'll note that in 2010 we have virtually no knockouts, and we've pursued a strategy that has largely eliminated that from our hedging strategy.

We're basically either riding straight swaps, issuing calls to collect that premium or to have that premium enhance the 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.

Jason, remember, you can sell an $80 out-year oil call for the equivalent of about $3.50 per MCF.

So, you know, there's a lot of additional gas value that can be generated by being willing to sell out your oil volatility and value.

Okay I understood that.

That made it very clear.

Thanks guys.

Aubrey, I've got the shale growth.

Alright.

Looks like this year, it was about 60%, we're projecting next year from a bigger number about 40% growth in the shales and then 2011, 25%.

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.

Our next question comes from Mr.

Dave Kistler with Simmons and Company.

Good morning, guys.

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 your actions it would seem like you're highlighting that you think oil's going to be a premium fuel for quite awhile.

Yes, I think so.

If you just look at the curve you've got basically a $14 to $15 MCF equivalent oil curve out there, and you've got a 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.

So, success in finding 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, you know, sometimes producers are accused of not being rational.

We think we're a lot more rational than people give us credit for, and we're 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 parity in the US.

Around the world, as we talk to our partners at 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 2013, we're likely to get back into a scenario where world gas prices approach world oil prices, and we're likely to be short gas on a world wide basis.

One thing I think we've learned so far in the past year, is that the world is not going to be awash in shale gas in the next five to 10 years.

The success of that proposition, I think, is unique to North America, and will it be many, many years before it has any impact on worldwide gas balances.

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 states.

If we think about where rig counts are being directed over the last 12 months, it looks like it is going to highly economic plays or plays 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'd be great.

Sure, I think we'll approach that question maybe two ways.

One is when you say sub $5 gas prices, I assume you're 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 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 in some of the conventional plays.

And we stand by our conclusion 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, production performance in the fourth quarter, there are more companies that are showing sequential production decline than increases.

And so we think the 914 data will likely begin to reflect what we're beginning to see in company data, and of course keep in mind that the 50% of production that we all see through public company reports, is the best 50% of the the gas production in the US, and you're not seeing the worst 50% and we think that's probably in fairly substantial decline at this point.

Great.

Thank you for that.

Then one last question, just on the Granite Wash.

Are there specific geologic targets you're looking to hit there, kind of Marmonen or Red Fork, Cherokee, Atoka -- any specific areas you could highlight, that you're going to be going after?

We call the Granite Wash the Granite Wash, David, and so we wouldn't include Marmonen or Red Fork or Atoka -- any other Pennsylvanian age formations are discrete and separate potential horizontal targets for us.

However, inside the Granite Wash, there are multiple Granite Wash targets, whether they are 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 stratographic column is one that we think is very conducive to oily development, or liquids-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.

Great.

Thank you guys very much.

Thank you, David.

And our next question comes from Brian Singer with Goldman Sachs.

Please go ahead, sir.

Thank you, good morning.

Good morning, Brian.

Following up on a couple of the earlier questions, kind of going back to oil versus gas drilling and your rig count, are you at the minimum rig count in your core areas and really in all the areas, to either hold acreage or per your joint venture agreements?

And so, if were 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?

Brian, you saw a little bit of an uptick in our CapEx in 2010 and 2011.

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 use the term "minimum" rig?

I almost think about it as maximum rigs that we're using to get to that HBP status before 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 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 reserve numbers going forward as well.

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 or changes in thoughts in terms of potentially trying to either monetize the additional joint ventures or via spinning off portions of your portfolio?

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're through with our leasehold acquisitions or the primary portion of our leasehold acquisition there.

With regard to any spinoffs or any other ways to highlight the value that is embedded here, I'll just highlight what Marc said in his prepared remarks, that it is a somewhat inexplicable discount, that is measured in the tens of billions of dollars, and I'll just say it has our attention.

Great, thank you

And we'll move on to our next question from Chris Gault with Barclays.

Please go ahead.

In regards to the SEC PUD booking rules changes, and I know you all said that the Barnett and Fayetteville were two areas that benefited from that.

Can you quantify those PUD quantities that you booked there, just related to the change in rules, not related to pricing?

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

Well, and we didn't do it two ways either, so I don't have 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 there's an answer we have for you.

If not, we apologize and we'll just continue to disclose with the level of detail that we've set forth in our releases.

Okay.

That's fair, thanks, guys.

Okay, thanks, Chris.

And our next question comes from Ronnie Eisman with JPMorgan.

Please go ahead, sir.

Hi, good morning.

I just had a question about the six new oil plays.

How many of them, if there are any that are based in the Rockies, and if you wouldn't mind providing any color on that?

Ronnie, I'll just say that less than a majority are.

So, I don't intend to be cute, but also want to protect, you know, 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, that's pretty easily discoverable.

So, if it would be all right with you, I'd like to leave it at that for now.

All right.

Thank you, guys.

Thank you.

We will move on to Ray Deacon from Pritchard Capital.

Good morning.

I had a question about the Bossier.

Can you give details on how many wells have been completed and maybe average IP rates?

Yeah, Ray.

For us, the well is one.

We have a second well that we'll be bringing online, probably in the next 30 days or so.

Steve, help me.

I don't think we're drilling a Bossier well right now.

Is that right?

We're not.

We're not.

We've got a 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.

There's probably less than ten out there, but you can tell quite a bit about the rock from the core samples that we have.

And, we're pretty comfortable using a 5.5 BCFE EUR, versus a 6.5 in the core part of Haynesville.

Got it, great.

And the thought is, still southern DeSoto Parish looks like where it's best, then?

Yes, southern DeSoto is kind of in the center of the universe for both Haynesville and Bossier.

The Bossier does cover more than just southern DeSoto, but that's a pretty good spot to be.

Got you.

Great, thanks.

Can you just walk me through a little bit, how your thinking works with the IPO as far as will further assets drop down into that?

And could it potentially give you higher growth rates in '11 and '12 than what you're showing now, I guess.

Ray, we're on a pretty short leash here from our lawyers on this so I will defer to Marc so, any mistakes that are made are his, not mine.

Sure.

We are under some restrictions here, so I won't talk about it from the midstream side of the entity that has filed.

I will just reiterate from the Chesapeake side.

The Chesapeake Energy strategy for some time, going back to the announcement of the formation of this joint venture with Global Infrastructure Partners back in 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're spending a lot of money that ultimately needs to be recouped, either through the sale of assets to a venture such as Chesapeake Midstream, or to a third party or some other formation of a capital raise.

There are many avenues attractive to us, and these types of assets are easily financeable, 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 green field, midstream, gathering-type assets that we have been 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, '11, and that will continue into the '12, '13, '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.

Got it.

Thanks very much.

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

Please go ahead.

Yes, just a couple of questions.

One, on the 90% risking in Eagle Ford, is that because you've drilled so few wells or do you view that play as substantially higher risk than other plays, or what are your thoughts behind that?

Marshall, 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 would have a risk factor.

I think much less than 90%.

But where our acreage is, we just feel comfortable -- or feel uncomfortable I suppose, risking any less than that.

I don't have any production to talk about so like all of our shale plays, though, you've got the rocket there, the gas and oil is in place, the technology exists, the capital exists, the drilling and expertise exists.

It's just a matter of going out and proving all that we know is, in fact, a hundred percent true.

We'll be doing that through 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 will drop to 10% or 15%.

Okay.

That's helpful.

And, one more question.

When I look at the exit rates, you give net exit rates by the Granite Wash and the Big Four shale plays.

When I add all those up, it looks like they're 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, or bigger declines in the conventional plays, or would it be more just conservative guidance for the total company?

Well, we'd like to think there's some conservative guidance in there, but there was another question and I think we tried to get to on this, that part of our company is in decline, with what I guess you'd call conventional co.

Shaleco 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 shaleco has to be increasing more than, say the 16% to 18%, for example, of growth that we projected for 2011, or the 8% to 10% for 2010.

So that is, in fact, the case and will remain the case for basically an indefinite time in the future that the shaleco part of the company will be growing faster than the whole company.

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 spelled out in there, but conventionalco not only is declining normally, naturally through the depletion rate, but we're also reducing production estimates in that, because of monetizations that we've talked about.

Okay thank you.

That's all for me.

Thank you.

Just to kind of highlight that at various times during the next four months, March through 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 pull cash out of our conventional assets.

Okay, we will go to the next question.

Our next question comes from Jeff Robertson with Barclays Capital.

Please go ahead.

Thanks.

Marshall asked a 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 in, say the Marcellus and the Bossier and Eagle Ford, are you able to give a number on where you think those might be at the end of 2010 and maybe 2011?

Oh, I think we probably could.

They'd be guesses at this point, and my guesses might be a little different from some other folks, but, you know, 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's at 40%.

Some of that reflects that we have some acreage that we're going to sell, and once we get that sold, that by definition would derisk our leasehold position.

So, you know, 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 is likely to be 10% or 15%.

It's at 15% today.

Bossier and Eagle Ford are at 80% and 90% respectively, and certainly within the next couple of years I would hope to get those closer to 50% as well, which naturally increases the potential risk unproved reserves quite substantially in our overtime.

And then, secondly, I think Marc mentioned that you all are now working on VPP7.

That's correct, Jeff.

Is a part of the preference 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 like to sell if the market is there just to sell them outright?

I think that that's certainly part of it.

I think there's 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 to a traditional buyer.

After eight or ten years of production, really, you're getting zero value from the buyer, on the tail of that production.

So, in some of our VPPs, 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 a 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 overtime in Oklahoma and the 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 is certainly one way to think about it.

And then the third thing, honestly, is that in this market the financial players with the VPP that might be equivalent to an investment-grade type of investment, significantly broadens the potential universe of 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, the 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 VPPs are attractive to us.

The good news is, Jeff, nobody else seems to like them but us.

So, we like that the whole market is ours.

Okay.

Thanks.

And, if I could, one more question, just in terms of your proved undeveloped reserves, Steve, did you all make any adjustments -- to what you might have carried for PUDs in areas where you're just not drilling PUDs and where you're just doing horizontal work?

In terms of taking things off the books?

Yes, sir, Jeff.

We did quite a bit.

We extensively went through really looking at intent over the next five years, on what the wells will either be drilling.

And so there was a lot in some of our older areas where we get 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 a proven area, it was not in our intent to drill within the next five years.

Okay.

Thank you

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

Please go ahead.

Hi, good morning.

Still got one more question, believe it or not.

Marc, if we go back to the impairment charge, help me out with the mechanics.

So, you're saying that first quarter you had that number of whatever it was, three, mid-three's.

You took the impairment charge and then you circled back at the end of the year, and applied the 12-month price to the -- once again to the entire book, is that what happened?

Yes, that's exactly right.

The SEC rule change that many people have asked questions about, about how we 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.

So on an unweighted basis, January 1, February 1, and so forth, through 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, you know, the end of the year price was a couple 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 that going forward, although we don't think that will yield any additional impairment charge.

Okay.

So, just to make sure I'm hearing this right.

So, first quarter 2010, March 31, 2010, you'll once again, take the first of the prior 12 months.

So go back through April 1.

That's correct.

You'll use April 1, and then the succeeding 12 months up through March 1, to measure the average price for those 12 months, at March 31.

All right.

Thanks.

And I'd like to throw in one more answer to Jeff Robertson's question about revisions due to aging PUDs.

That was about a half a TCFE number.

So, Steve's right, we scrubbed it very clean and still had enormous reserve growth, even though we took out half of TCFE, due to aging and also no 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?

Yes, we do.

Our next question comes from Rehan Rashid with FBR Capital Markets.

Good morning, Aubrey.

On the oil play, the comfort we're talking more about it, 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?

Rehan, I think two things really to think about.

One is we have more acreage than we had in the past and so 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, you know, we have some production results from some of these plays that we didn't have 90 days ago or 180 days ago.

So, it's a combination of we've actually have 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 a ways to go, and would rather talk more about them later in the year, once we have more production to talk from, and a larger acreage base as well.

So, not really any kind of a frac or a prop that would work better or process that would work better?

Well, all that is evolutionary.

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.

Okay, thank you.

We will move on to our next question, from Shilpa Kumar.

Please go ahead.

From Jefferies, excuse me.

Hi, this is actually Biju.

Quick question, Aubrey, going back to your guidance on oil volumes.

I look at your oil production numbers for 2009, more or less flat even though 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 a difference in the completion that would yield higher liquid volumes or the increased guidance, you know, is there a significant amount coming from the new plays that you're talking about?

I think the answer is both, Biju.

We only had three to four rigs running in Colony Wash during 2009.

We're doubling that in 2010.

So that's what takes us out of 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 and natural gas liquids in there as well.

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.

Okay, and one other question.

When you look at, you know, the plays that look promising, that are shale plays that look to be oil prone, any reason more of them are popping up in the Rockies region, looking at the activity that you have and others, any reason for that from a geologic setting?

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 a super-basin, if you will, and there are a lot of geochemical reason for that, geological reasons for that.

A lot of gas heads found in those areas, but I think that is what has so many Rockies players excited about the area.

We're disappointed that our two attempts to buy big property sets in the Balkan in 2005 and 2007 did not work.

Otherwise I think we'd 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're at 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 the last couple of years to focus more on the oil side of the bad news and that's what we're doing, and that shift takes time, and the generation of new ideas, and acquisitions of acreage, and then the 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, 2008, that we were going to look far more seriously at developing oil plays.

And that's taking 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.

But areas that we think are oil prone, and areas where we think we ought to have a big presence.

Great.

That's all I had.

Thank you.

Okay, thank you.

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

Please go ahead.

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 shale zones that are more are oily and would that eventually be able to really give you a ramp-up to a major percentage of oil, because right now it looks 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 in the future?

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'll be tough for oil to increase to, you know, 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 positioning in that area, and we'll have more to talk about as the year progresses.

Okay.

Go ahead, I'm sorry.

That's alright.

I think we're in overtime and we were just getting ready to wrap up.

We appreciate everybody's questions 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.

That concludes today's presentation.

Thanks for your participation.