Chesapeake Energy Corp (CHK) 2010 Q1 法說會逐字稿

Good day and welcome to the Chesapeake Energy earnings conference call.

Today's conference is being recorded.

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

Jeff Mobley.

Morning, everyone.

Thank you for joining our 2010 first quarter earnings and operational update conference call.

With me this morning is Aubrey McClendon, our Chief Executive Officer, Marc Rowland, our Chief Financial Officer, Steve Dixon, our Chief Operating Officer, Nick Dell'Osso, our Vice President of Finance, and John Kilgallon, our Manager of Investor Relations and Research.

Our call should last approximately an hour, in courtesy to other companies who have earnings calls today.

So with that, we will turn it over to Aubrey.

Good morning.

Thanks, Jeff.

We hope you have had time to review Monday's operational release and yesterday's financial release.

On the operational side, our daily production for the first quarter was very strong at 2.6 BCFE up 9% year-over-year.

Adjusted for the sale of our volumetric production payment number six, and for our Barnett and JV deal with Total, our production was up 19% year-over-year.

On a sequential basis, our production was up 5%, adjusted for those two asset sales, and even with those sales included, our production was down less than 1% on a sequential basis.

Because of the strength of our drilling program, we have also increased our 2011 production forecast for the second time in six weeks.

This time to a range of 16% to 18% with the increase being completely driven by our oil and natural gas liquids plays.

In particular, we hope that you notice that our liquids production was up 35% year-over-year.

Chesapeake's proved reserve growth rate, in the first quarter of 2010, kept pace with our very impressive production growth.

Proved reserves rose from 14.3 TCFE at year end 2009 to 14.8 TCFE at the end of the first quarter.

That's after selling about 900 BCFE during the first quarter, through our joint venture with Total and VPP number six.

Excluding asset sales, we actually increased our proved reserves by 1.4 trillion cubic feet of gas equivalent, or 10% in just the past three months, we believe an incredible achievement.

Using ten year strip pricing in effect at the end of the first quarter, our proved reserves actually increased to 15.8 TCFE So, we are well on our way to becoming a 20 TCFE to 22 TCFE proved reserve company by year end 2012 and, potentially, even earlier than that.

I would also like to highlight our remarkably low finding costs during the first quarter.

We added 1.6 TCFE at a drilling and completion cost of only $0.67 per MCFE I don't believe there's another company in this industry that is capable of finding 1.6 TCFE in 90 days, much less finding it at $0.67 per MCFE.

This success has been achieved by the nation's most active and highest quality drilling program and led by our industry leading leasehold positions and America's best Shale Plays.

Speaking of leasehold, some of you probably noticed, that on a net basis we invested $622 million in new leasehold during the quarter.

Of that $622 million, $210 million was invested in the Eagle Ford, $100 million in various Anadarko Basin oil plays, $100 million in the Haynesville, $75 million in the Marcellus, $75 million in various Permian Basin oil plays and $60 million in the Barnett and Fayetteville combined.

For that investment, we acquired about 340,000 net acres, or about $1,800 per net acre cost.

We know that every acre we buy today could be resold for much more than we were paying for it, plus every acre gives us the right to develop new reserves at less than a $0.05 per MCFE cost to us.

Please recall that in our JV's to date, we have made more than $7 billion in profit by selling acreage that had a cost basis to us of only about $2 billion.

In our newest big acreage play, the Eagle Ford, we now own 400,000 net acres at a combined cost of about $550 million, or less than $1,400 per net acre.

Based on our well results to date, and recent deals in the industry, we believe we likely already have a built in gain of at least $1 billion, and maybe $2 billion, in our Eagle Ford position.

You might further recall, we did not own one acre in Eagle Ford just nine months ago.

It remains our expectation that by the end of 2010, we will have raised as much money from selling acreage this year as we have invested in acquiring acreage this year.

As for why we are seeking new plays, it's because we continue to focus primarily on oil and liquids rich areas.

That's where the money is these days, with oil to gas values now exceeding three to one.

As for oil plays, it does surprise me that some analysts have commented that Chesapeake is a Johnny-come-lately to the unconventional oil business, and that is simply not true.

In March 2008, after two years of quiet development, we announced the discovery of the Colony Granite Wash, which over time, could net Chesapeake more than 800 million barrels of oil equivalent.

At that same time, we also announced Chesapeake would embark on a program to develop new unconventional oil plays.

Back then, we had five unconventional oil plays in mind, four of which have turned out to be successful.

We have now supplemented those original four plays, with eight additional unconventional oil plays, and across our company every Asset Team, plus our new Ventures Group, is very focused on continuing to develop new oil plays.

If you thought we were a leader in revolutionizing the onshore US natural gas business during the past five years, just wait and see what we can do to the onshore US oil business in the next five years.

Our horizontal drilling expertise and our unconventional geological target identification skills, combined with our leasehold acquisition skills, are second-to-none in the industry.

They've been perfected over the past 20 years, and will increasingly allow us, to separate ourselves from the industry pack in the years ahead.

For now, we are disclosing just 12 liquids rich plays, but there are more on the way.

In these 12 plays, we have drilled more than 200 wells to date, and have amassed an enviable position of 1.9 million acres of leasehold, on which we have identified nearly seven billion barrels of potential liquids rich resources.

We are the largest leasehold owner in these plays, and with the exception of the Eagle Ford Shale, where we had moved into Third place with 400,000 net acres, that is situated very strategically in the wet gas and oil portions of the Eagle Ford play.

Finally, in response to continued low natural gas prices, in the ongoing success in our liquids rich play, we have redirected capital from our natural gas shale plays to focus more on oil.

On our gas focused plays, we now plan to spend about 12% less in 2010, and 17% less in 2011, than we previously had planned to spend.

These capital savings will be used to further accelerate our oil program.

This oil focus should lead to at least a three fold increase in our liquids production by year end 2012, to more than 100,000 barrels of oil per day production, versus the 32,000 barrels per day we produced on average in 2009.

By 2012, we look for our liquids mix to be about 15% to 20% of our total production, and perhaps 40% to 50% of our total revenues.

That will be a tremendous accomplishment, given how strong we expect our growth to continue to be, from natural gas shale plays during that same time frame.

This completes my commentary.

I'll now turn the call over to Marc.

Thanks, Aubrey.

Good morning, everyone.

I just have a few notes this morning.

I want to begin by reminding you of the status of our midstream business.

Our affiliate Chesapeake Midstream Partners, LP, which is a 50/50 partnership between Chesapeake and Global Infrastructure Partners, LP, whom is based in New York City, currently has a registration statement on file with the Securities and Exchange Commission relating to its initial public offering.

We have received an initial round of comments from the SEC, and in response, have filed our second amendment to the registration statement.

So, this initiative continues to move forward as expected.

Outside of this entity, we have a wholly-owned business, Chesapeake Midstream Development.

That entity is developing the Fayetteville, Haynesville, Marcellus and Eagle Ford gathering plays, that we think have at least as much value as the IPO entity.

Our liquidity remains very strong at the end of this quarter with about $2 billion in cash and available lines of credit.

In addition, to those lines of credit, we have close to $400 million of availability inside of CMP, through that stand-alone revolving credit facility.

Looking to the second quarter, we note in our release, and I would emphasize, that we are on track to monetize about $750 million through asset sales, or VPPs, during this second quarter.

Two of four transactions that were expected to close have already closed to date.

You may have noticed we had a non-cash, non-recurring charge below the line, so to speak, this quarter.

For inquiring minds, this is a result of the new January 1, 2010 authoritative guidance for variable interest entities, which is quite a mouthful, since we no longer consolidate our midstream joint venture as a result of that.

Because we have shared control with our 50% partner, GIP, our investment in Chesapeake Midstream is now accounted for under the equity method.

Unfortunately, the adoption of this new guidance resulted in an after tax charge of about $140 million, which is reflected in our statement of operations as a cumulative effect of the accounting charge this quarter.

This charge actually reflects the difference between the carrying value of our initial investment, going back into the joint venture last year and that was recorded, of course, at a carry-over basis under common control and the accounting change resulted in us switching to a fair value entity based on what GIP came into.

Finally, you may have noticed a substantial increase in our oil and gas liquids production, as Aubrey pointed out, this quarter.

This is mainly a result of our shift in drilling focus and the impact from the Granite Wash and new Anadarko emerging oil plays and, of course, the Eagle Ford play in south Texas and the southwest Marcellus play in northwest West Virginia and southwest Pennsylvania.

But also, conforming to what we believe is industry practice, we are now reporting some liquids that are separated from gas and sold as liquids by us, that were previously treated as part of the gas revenue stream.

So, a little bit of a change there.

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

Thank you.

At this time we will start the question-and-answer session.

(Operator Instructions) We will take our first question from Brian Singer with Goldman Sachs.

Good morning.

Good morning, Brian.

Couple questions.

First, can you just talk to, for the remainder of the year, how we should think about any additional leasehold acquisitions and other capital spending beyond drilling and completion and, then Marc mentioned, the expectation for the asset sales in the second quarter, but what is your thinking in terms of additional asset sales for the remainder of the year?

I'll take the first part of it and leave the second to Marc.

On leasehold it's really impossible, Brian, to project where we will be.

There are new plays, kind of, breaking all the time that we're involved in, but as I mentioned in my comments, our plan is to remain at least flat on leasehold purchases.

So, our goal is to continue to sell positions in our plays that become more mature and where we have embedded profits in them and then use those harvested profits to go buy cheaper acreage in some new plays.

So, that's something we've obviously shown a fair amount of skill at, in the past few years and it's something we will continue to do so going forward.

Brian, good morning.

On the additional asset sales, there are really three or four categories that we continue to expect additional activity in.

First, we do anticipate additional joint ventures.

Those could be in the Eagle Ford, for example, or it could be in some of the emerging oil plays that we have.

We have a whole group of minor assets that are under review for additional sales this quarter.

We've already closed on about $210 million of miscellaneous properties in the Permian Basin.

We have another group of properties in Virginia that we don't think have a lot of prospectivity for additional deep drilling.

That's under consideration for about $150 million.

So, that's some of the type of assets that we're considering and I think we will continue to monetize those type of assets.

In another category, we're continuing to develop assets that we think will be monetized in the midstream business.

I mentioned Chesapeake Midstream Development, which is 100% owned by Chesapeake.

We do have a considerable CapEx allocation to that business to develop the gathering systems, particularly in the Haynesville and the Marcellus play, and to a lesser extent, developing out the Fayetteville and the emerging Eagle Ford play.

Some of those might be taken up by third parties.

We've occasionally sold some assets to third parties, but primarily going forward, I expect those to be offered to and perhaps taken by Chesapeake Midstream Partners in a drop-down scenario.

And then finally, the VPP market remains very robust, particularly in the oil pricing related properties.

So, I think, we'll continue to look for opportunities to do that.

I don't have a particular budget for that but we've outlined our overall cash-in and-out summary in our releases in our slide shows, et cetera.

So, I'd expect that the sales will exceed the amount that we spend in those additional categories of acreage and development of pipelines and so forth.

Great, thanks.

Aubrey, just as follow-up, the 1.95 million acres and the unconventional liquid plays, if we're looking out one or two years from now, how big an acreage position do you think that ultimately could get to or do you think you kind of have the right size where it is today?

Well, some of it depends on the plays themselves and where our partners are.

The Granite Wash Play, for example, where we have 195,000 acres is basically spoken for.

There's not much else that can be done there.

In the Eagle Ford, we're at 400,000 acres.

We might be able to get to 450,000 or 500,000, but that's quickly becoming a play with all the positions locked down.

A lot of up side in the Anadarko Basin.

We have about 665,000 acres there, chasing three different plays there, and we'll continue to add, but most of the area is HBP.

So, it's just kind of one section at a time kind of stuff.

Permian Basin, a fair amount of leasehold upside there.

We've got 290,000 acres.

Then in the Rockies, which is both the Powder River Basin oil plays and then also the Niobrara in9 the DJ basin, we have 400,000 acres, and that could probably increase a fair amount.

What we're finding, is the big companies around the world that are oil companies have clearly loved what we have found in gas in the US, but given their druthers, they'd probably just as soon us bring them into oil deals as well.

So, they have a big appetite, have a lot of money and it takes big leasehold positions to create the kind of billions of barrels of oil equivalent impact to them that we think we can deliver.

So, we'll continue to do what we do really well, perhaps singularly well, which is to identify new plays and buy the acreage and then bring in partners at a very advantageous cost differential to us.

It's been a model that's worked well for us and we'll continue to do so going forward.

Great.

Thank you.

We will now take our next question from David Heikkinen with Tudor, Pickering, Holt.

Good morning.

Had a question, as you think back since March 2008, can you break out the oil leasing costs and carries for us?

The oil leasing costs since March 2008?

Just an idea of how much you've committed over that time frame.

I just went through with Brian the number of net acres that we own in each play.

And I don't have our last two years of leasehold cost in each of those plays.

But just glancing at them, I disclosed this morning the Eagle Ford we're at about $1,400 per net acre, and in everything else we'd be well below that because of how early we were to those plays.

Okay.

And then thinking about the split, 50 rigs targeting oil, and you've given us acreage, now trying to think about activity level on each one of those and then your gas activity levels for each of the gas shales.

Can you talk about going forward, after the joint ventures and kind of carries are done, what your activity level will be in each play?

Well, it's completely dependent upon gas prices, and to a lesser, extent oil prices.

Right now, as I have stated on numerous occasions, at least half and probably two-thirds or three-quarters of our gas drilling is what I would call involuntary.

It's being incentivized by something other than the gas price.

It might be the realization of a carry in Marcellus or in the Barnett.

It might be the need to hold acreage in the Haynesville, for example, or could be a combination of those two things.

I think that's in large part true across the industry, that there's an enormous amount of drilling today that is economic.

It's just economic for reasons other than what current gas prices are.

David, how we look at it, a couple years from now, our gas plays will be largely HBP.

We will have ramped up our oil drilling quite aggressively.

We'll then be moving into a phase of needing to HBP our oil leasehold as well.

But the difference between our gas plays and our oil plays is, of course, first the oil plays are valued at three to one, on a unit of production basis on the price alone, plus there is no amount of success that I think we, and our colleagues, can have in the industry to really drive down oil prices with our success in finding new reserves of oil onshore in the US.

My guess is offshore oil drilling just got a little more difficult, and probably more expensive, and so, I think, the stage is set for there to be a real rejuvenation in onshore American oil production.

It will be led by the same people that led the rejuvenation of the gas business which, of course, we're one.

If you get into a world where gas prices remain at $4.00, two years from now, then could I see a scenario where the majority of our drilling is simply on oil projects, and we'll let our gas projects sit HBP.

If you get back to a scenario where gas prices are $6.00 to $7.00, which we expect, you'll probably see a more balanced approach.

So, highly price-dependent.

What it sounds like, is we can expect an Eagle Ford joint venture in the near term.

And then as you think about going beyond that, what is the willingness to get into oily joint ventures?

I mean, you're already in discussions.

The desire is high because we have the ability to find the idea, to drill the initial development wells, buy a bunch of acreage, at a cost of X, and then go bring in a partner at three, four, five X.

That's not too much of a profit to pay for someone coming in because, at the end of the day, your leasehold typically only costs you pennies at most, a dime or two per mcfe.

So, it's a very low price of admission for companies to get in.

So, because of we're never concerned about running out of new ideas, we're very happy to bring people in for a quarter of our deals, get all of our costs back, and have typically one of the world's largest energy companies as our partner, which our view is a very simple one.

In life, we don't think you can have too many rich friends and we intend to have as many as we can.

So, just kind of getting into the last three years of gas leasing and then looking forward as you make capital allocation decisions, we should think that the majority of your leasing willing be oil directed?

Yes, definitely.

And how, you kind of answered the question, of it's going to stay balanced.

How much in asset sales, Marc, do you think you can actually do with the three different knobs that you're turning?

Is it $3 billion of opportunity, or can you put a number, a bread box number out there?

Oh, a bread box number, sure.

I mean, it's completely discretionary, and in terms of an Eagle Ford or other emerging oil joint venture play, that could easily be measured in $0.5 billion to $1 billion dollars in cash.

Drop down activity per year could easily be measured in $500 million to $750 million per year, and small asset sales and VPPs could easily be measured in $1.5 billion to $2 billion a year.

The latter being probably the most discretionary of anything we could do.

We can go out and sell any asset that we have, and we have $50 billion worth of them.

So, that's a bread box number.

Okay.

Thanks.

We will now take our next question from Dave Kistler with Simmons & Company.

Good morning, guys.

Good morning, Dave.

Just looking at the $700 million that you're reallocating from gas to oil, can you talk about what areas you're moving that from and maybe tie that to your comments about what areas are held by production and what aren't?

Sure.

Basically, it's being moved to all plays that we have mentioned, but primarily, you are going to see the ramp-up occur in the Eagle Ford and in then the Granite Wash.

We've already almost doubled our rig count in the last, oh, I guess 90, 120 days.

Steve is that fair to say?

Then, the Anadarko Basin is going to take a lot more rigs than Permian and Rockies.

So, it's really scattered across the whole suite of oil plays.

It's not like we're going to take one and add 30 rigs and ignore the others.

A little bit more specifically though, can you talk about the plays you're taking rigs from, so those areas, that I am assuming, at this point, are either held by production or the schedule to hold them by production?

I can tell you that.

We're planning to take, I think versus our old plan, one rig from the Marcellus, six from the Haynesville, four from the Barnett and two from the Fayetteville.

I think that's a combination, or a total of, 13.

Okay.

That's helpful.

Then just looking back historically on the gas hedging side of things, you guys have done a very admirable job there.

As you look towards increasing your oil side of production, I would imagine, that will be a core part of the strategy as well.

Is there anything different that you have to do there?

Do you have to think about the world differently on a macro level, as opposed to North American and do you have to add people one way or another to facilitate that?

Certainly don't need to add people for the hedging side of that.

We will have to develop a little more sophistication on the natural gas liquids hedging side, but we think, we're capable of getting up to speed there.

And we've been good hedgers of oil over the years.

We have used -- occasionally we've sold some oil volatility to enhance some gas prices.

We might do that going forward.

So, actually having more oil production is, at the same time, very helpful to protecting our gas production from lower prices as well.

Dave, this is Marc.

I would just add that in terms of practical application, Aubrey mentioned, we don't need to add a people.

We can hedge oil, I think, equally as well as we hedge gas under our existing facilities.

There's no distinction.

Our counter parties are prepared and every day make liquid markets, and forgive the pun, in oil and natural gas liquids.

In fact, I would point to the oil market probably itself being more liquid in terms of hedging counter parties than the natural gas markets.

So, I don't think you should expect anything different.

We'll sell swaps primarily.

We would consider collars on oil, because of the up-side volatility might increase the put-level for us on a non-cash or no-cost basis.

As Aubrey mentioned, we're moving into the natural gas liquids market right now, and we'll separately hedge those products as they are available at attractive prices to us.

Great.

One last question, just thinking a little bit more longer term on oil and gas, you've been very specific in the past, and in this call, talking a little bit about your view in the near term on pricing there.

Can you talk a little bit more on a longer term basis of oil and gas, possibility for convergence, you mentioned, Aubrey, that you thought gas would get back to a $6.00 to $7.00 range in the future.

Can we talk a little bit about the drivers of that, et cetera?

Well, one of the best drivers probably, everybody hates gas right now and they hate it now and forever.

So, I think you've got to get to that kind of a level before you probably form a base.

But, I think there are a couple of encouraging things out there.

First of all, supposedly, we were going to be awash in LNG this year.

I think that marks the fifth or sixth year since 2001 I was told the US producer would be swamped in LNG.

I don't think it's ever happened and, I suspect, it will never happen.

So, the world LNG supply demand balance is fixing itself pretty rapidly through increased demand and, I suspect, a couple years from now you'll be back in position where you see a re-linkage of worldwide gas prices to worldwide oil prices.

Not on a one-to-one basis, but certainly, over the last year and a half we've seen world gas prices gravitate towards Henry Hub rather than towards oil equivalency.

I think going forward, you will see them head back the other way.

So, that is, I think, something, favorable out there for a couple of years from now.

I think the whole rush to HBP acreage right now, which occurs at almost any gas price, will have essentially run its course a couple of years from now, and will be done by then, and all of a sudden our drilling, rather than becoming involuntary or being involuntary, will become voluntary and we will only drill gas wells when we think the price curve pays to us do it, not because of the ancillary benefits of picking up a carry or HBPing acreage.

Finally, I think -- well two final thoughts - One is, the coal floor, I think, is continuing to come up.

Clearly, the accident in West Virginia is going to make coal more expensive to mine going forward.

It's going to make it more difficult to mine.

Yesterday's coal ash rules proposed by the EPA could be game changers for the burning of coal in the US.

And so, I wouldn't be surprised to see the coal floor come up by 50 cents a mcf in each of the next few years and that will help provide some support.

Then, I think, there's also the possibility that we'll see some demand initiatives kick in two or three years from now as utilities begin to close some of their oldest coal plants and begin to run their natural gas plants harder.

So, I think we're scraping along bottom.

I don't know if that's $3.50.

I don't know if that's $4.00 right now.

But I do think the bottom is continuing to come up and I do think there's some reasons to be optimistic about a return to $6.00 or $7.00 gas price in the US over the next few year which, I think, is very favorable to consumers and is a decent price for producers as well.

Great.

Thank you guys so much.

Thank you.

(Operator Instructions) We will take our next question from David Tameron with Wells Fargo.

Good morning.

Aubrey, can you talk about, we've heard about some of the other plays, but can you talk a little more about what you guys are doing out in the Rockies, Niobrara and Frontier, et cetera?

What's the concept there and just more color there?

Probably not really able to do that, David.

I guess we are able to.

I guess we are unwilling to.

There's some other acreage that is not locked down up there right now, and so I think, it is a matter of public record that we've drilled two wells.

I think it is a matter of public record that one of them is in the Niobrara and one is in the Frontier, in the Powder River Basin.

I think, it's a matter of public record that EOG has a rumored good well in the Niobrara in the DJ Basin.

So, based on those results that are clearly from a small set, but I think, what we've learned these days is when you get well results that meet your geological model, your geological model can be trusted over a pretty wide area that you've mapped.

So, we're going to be adding some rigs up in the Rockies soon, and I think, it can be a big play for us.

Now, in the past, I haven't wanted to be in the Rockies because I haven't liked the gas prices there and I haven't liked the environmental issues, but at least in these areas of Wyoming most of the land that we're involved in is going to be fee land rather than federal land.

In the DJ basin, it is going to be fee land as well.

So, I think there will be a lot more visibility on those plays going forward.

The state of Wyoming requires you to disclose a fair amount of information, so that will become matters of public record as we drill more.

All right.

Any color on the split of acreage?

I think you said 400,000.

I'd rather not at this time, although, there are areas of play where the two formations overlap.

But we haven't double counted there.

An acre is an acre, whether it's perspective for one or the other or both.

One more.

Just thinking about the Rockies oil, do you have a feel for what the end market would be?

Where that oil would be going to?

I don't happen to know where our oil in Wyoming is going.

Steve, do you happen to know?

I guess to Casper, but honestly, I don't know.

All right, that's all.

David, if it's that's important to you, we'll find out and Jeff, or John Kilgallon, can get back to you.

Okay.

I could track it down on this end, but thanks.

Nice quarter as well.

Very good, thank you, David.

We will take our next question from Dan McSpirit with BMO Capital Markets.

Gentlemen, good morning and thank you for taking my questions.

You are about to transact your seventh VPP, and clearly, you have a track record of raising capital with this arrangement.

Why don't we see the industry do more of the same?

Why aren't these VPPs more popular in your opinion?

Maybe the same question can be applied to JVs as a way of creating greater transparency on value and generating that cash-on-cash return.

Oh, I think there are various reasons.

First of all, we're thrilled that other people don't because there's less competition into the financial market.

But rating agencies see these things mainly as debt which is something that, of course, hurts us on our debt ratings and a lot of other companies may not want to deal with that.

We like them, though, because we are able to monetize mature assets at what, we think, is a very favorable value.

Basically the buyer is paying what these days, 8%?

So, there are very few asset buyers out there in the industry that will pay PV-8, and let you keep the tail, and let you keep deed rights, and let you keep the increased density and they don't make you pay taxes.

So, there are about five reasons why we like them as being superior to an asset sale, and frankly, I'm thrilled that no one else appears to like them very much.

Marc may have some other thoughts there.

On the JVs, you have to, first of all, be able to acquire the idea and acquire the acreage, then have an operation that an international major wants to affiliate with and that's not true with every company.

And I like having to raise our game to meet the standards of a BP, or a StatOil, or a Total around the world.

I think that's made us a better organization for having to meet their international standards with our domestic operations.

Also, look, if shareholders value your Marcellus acreage at $15,000 a net acre, you don't sell into it a JV at $14,000.

If shareholders value your Marcellus acreage at $2,000 an acre and you can get somebody to pay you $10,000 or $15,000 an acre for it on a JV basis, then that's what you do.

So, we'd love for investors to do us some of the parts here and realize we have assets worth over $50 billion and have our stock price be $75 that we think the assets support.

But if they're not willing to do so, we know, there are industry players out there that will give us fair value for those assets so, we'll bring them in and create the value that way.

Dan, I really don't have anything to add on the why others don't do VPPs.

I think others are looking at them, based on contacts we have with various purchasers.

I mean, clearly, you have to be fairly established as an operator for a counter-party to want to take a long-term relationship with you.

Clearly have to have some hedging skills because all of these products are hedged, either simultaneous or prior to conveying the asset to them.

Aubrey mentioned the rating agencies.

I think it is cleaner for some companies, with the rating agencies, to simply enter into a sale rather than a VPP type of arrangement.

We happen to disagree with the rating agencies pretty vociferously.

Doesn't mean they've changed their minds.

Clearly this, for a GAAP purpose is a sale.

We take the reserves off of our books.

We legally transfer them.

We don't show any production from those and then the result is, that we don't have any obligation except to deliver their volumes to them in the form of cash when they are -- or we market them.

So, there is no ongoing dollar obligation for us at all.

Got it, thank you.

One more if I may?

Depending on gas prices, and certainly your outlook on the commodity of course, does the day ever come that Chesapeake exits a natural gas play entirely?

And if so, how would you rank the plays as first to go?

Well, it's a good question.

We've already exited one.

We sold the Woodford, the Arkoma Basin Woodford, in fall 2008.

I think, we had $235 million invested in it, I think if I recall, and we sold for $1.75 billion to BP.

So, if the price is right and someone wanted to buy one of our big gas shale plays, we'd certainly take a look at it.

Right now, it looks like the better thing to do is to go buy acreage for X, prove up the concept and go sell for 5 or 10 X, or go sell 25% of it for 5 to 10 X.

That's a model that we think can work time-after-time.

It's really, really difficult to communicate clearly here how many companies around the world want to be in the US and really how few companies, A, would meet their operating standard, B, would have acreage in the right plays and C, would be willing to bring a partner in.

A lot of companies aren't willing to do so for various reasons.

So, we've got a high degree of traffic through here from some very interesting companies from around the world and we're happy to meet new people all the time and see where those discussions go.

Much appreciated and, again, thank you.

Thank you.

We will now take our next question from Biju Perincheril with Jefferies & Company.

Good morning.

Couple of quick questions.

Marc, you mentioned a part of the liquids volumes is, attempt in how you account for profit, can you break out how much that was of the sequential growth?

Biju, I don't really have that in my mind right now.

Steve Dixon has just said it's about half of the incremental.

And, of course, a lot of that incremental would be incremental liquids added and, I think, of the Granite Wash plays particularly where the very rich natural gas stream there, we are selling the liquids separate from the gas.

So, as production has ramped up there, it's not so much a conversion from where the accounting was, but an additional incremental liquids volume and then we've added quite a bit of oil in the Eagle Ford, in our first three wells down there, and quite a bit in the in the southern Oklahoma plays as well.

So, going forward, we'll be happy to discuss liquids separately, but it is going to be reported as a liquids and oil stream together.

Okay.

So 50% is, of the sequential growth, was coming from NGLs?

Was that what you meant?

That's what I meant.

Okay.

Do you know roughly what percent of the total liquids is now NGLs?

I don't have that number off the top of my head.

Steve, do you know?

I will be happy to get back to you on it, Biju.

We'll just have to go over to our accounting department to look it up.

Okay.

Then looking at asset sales, 1.5 million net acres in the Marcellus.

I'm not sure if that's all something that you want to develop, obviously not getting full credit for it, how close are you to fully assessing how much of that you want to keep and perhaps monetize part of that, either additional JVs or outright leasehold sales?

Oh, we sold some of our acreage in the far eastern part of Pennsylvania.

We sold Amarott, not Amarott, but to Hess and Newfield.

We did that in the first quarter, I believe.

We're happy to have them take on Wayne County and the thrill of drilling wells in the Delaware River Basin.

We'll continue to nip-and-tuck.

We're still waiting for things to fall out in New York.

We have a fair amount of acreage there that, right now, remains to be seen how we're going to be able to develop that.

But going forward, we actually see people drilling wells in places where we've been a little nervous about acreage values in those areas, and they seem to be making some pretty good wells.

If you look what it Reliance paid Atlas, or what Mitsui paid Anadarko at $14,000 an acre, we think that's a pretty good marker and are thrilled that we own 1.5 million acres in the play.

We think that makes our acreage worth a large amount and believe that, in time, what he get full value for that.

So, no plans in the near term to monetize a large chunk of that?

Is it something that you want to hold on to and develop?

I don't think to sell additional leasehold is something that we're interested in doing on an across the board basis, because I think life would become too complicated with having two partners in rather than one.

When we sold the acreage to Hess and Newfield, Stat Oil joined us, so there will be places from time to time we probably peel off some acreage jointly to somebody else, where maybe it's not core to us and it is core to them.

Got it.

Thank you.

We will now take our next question with John Oakley with Cairn Capital.

Just wanted to ask a couple of other questions.

Firstly, going back to any conversations you may have had with the ratings agencies.

Just your thoughts on current rating and where you see that progressing over the next 12 to 24 months as business mix changes slightly?

Secondly, although kind of like, couple of years away still, if you had any thoughts about pushing back maybe the 2013 and the 2014 bond maturities as they become callable?

Sure, John.

Pretty good questions.

The rating agencies we have regular telephone conferences with.

We have not taken a missionary step to go and campaign for any change.

My personal feeling is that in this environment, based on body language with very low prices today and I think the rating agencies probably have at least as negative a view as the street, if not lower, on future gas prices, I doubt that we would be in line for an upgrade without taking some other dramatic step to improve or decrease the amount of the debt.

With respect to the 2013 and 2014 maturities, we are considering every day the opportunities to call those, refinance them, to move out the maturities, and I think, over the last 14 years, 1994, I guess 16 years, since we've had long-term senior notes traded in the market.

We've always had a track record of moving maturities when they get within three or four years out, and I think we could easily do that today.

It's just our feeling has been that rates would remain relatively benign and that the closer we get to a call date in this environment, probably the better our net present value exchange is with refinancing those notes.

But, I suspect within the next few months you'll see us do something on those notes.

Probably in the near term mode, expect then -- no further questions, actually, sorry.

Thanks, John.

Thank you, John.

That is all of the questions that we have at this time.

At this point way like to turn the conference back over for any closing or additional remarks.

Great, thank you.

On behalf of the Management Team, we appreciate your interest.

If you have further questions please give John or Jeff a call.

Thank you.