Good day, and welcome to the Chesapeake Energy Earnings Conference Call. [Operator Instructions] At this time, I would like to turn the conference over to Mr. Jeff Mobley.

Good morning, everyone. Thanks 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 as courtesy to other companies who have earnings call today. And with that, we'll turn it over to Aubrey.

Good morning. Thanks, Jeff. We hope you've had time to review Monday's operational release and yesterday's financial release. On the operational front, 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 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 noticed 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. And that's after selling about 900 bcfe during the first quarter through our joint venture with Total and in VPP number six. Excluding asset sales, we actually increased our proved reserves by 1.4 trillion cubic feet of gas equivalents or 10% in just the past three months, we believe a incredible achievement. Using 10-year strip pricing in effect at the first quarter, our proved reserves actually increased to 15.8 tcfe. So we're Well, on our way to becoming the 20 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…

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, L.P., which is a 50-50 partnership between Chesapeake and Global Infrastructure Partners, L.P., who 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 additional 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 standalone 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, nonrecurring 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 ventures' result to that. Because we have shared control with our 50% partner, GIP, our investment in…

[Operator Instructions] We will take our first question from Brian Singer with Goldman Sachs.

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's 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'll 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 that we'll continue to do so going forward.

Brian, on the additional asset sales, there's 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 a third-party. 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. And 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 cash our summary in our releases, in our slide shows, et cetera. So I expect that the sales will exceed the amount that we spend in those additional categories of acreage and development of pipelines and so forth.

And then Aubrey, the 1.95 million acres in the unconventional liquids plays, if we're looking out one or two years from now, how big an acreage position that ultimately could get to you? 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 the 450,000 or the 500,000, but that's quickly becoming a play with all the positions locked down. A lot of upside in the Anadarko Basin. We have about 665,000 acres there and chasing three different plays there and we'll continue to add. But most of the areas is HBP, and 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. And then in the Rockies, which is both the Powder River Basin oil plays. And then also the Niobrara play and the D-J 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 U.S. But given that there are others, they'd probably just assume it's bringing them into oil deals as well. And so they have a big appetite and a lot of money, and it takes big leasehold positions to create the kind of billions of barrels of oil and 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.

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

As you think back since March 2008, can you break out the oily leasing costs incurred for us?

The oil leasing costs since March 2008?

Yes, just an idea of how much you've committed over that time frame.

Now 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 costs 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 then everything else would be well below that because of how early we were to those plays.

And then kind of thinking about the split now of 50 rigs targeting oil, and you've given us acreage. Now, I'll try 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 among gas prices and to a lesser extent oil prices. I mean right now, as I've stated on numerous occasions, I believe at least half and probably 2/3 or 3/4 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 the Marcellus or in the Barnett. It might be the need to hold acreage in the Haynesville, for example or it could be a combination of those two things. And 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. But how we look at is a couple of years from now, our gas plays would be largely HBP. We will have ramped up our oil drilling quite aggressively. We will then be moving into a phase of needing to HBP our oil leasehold as well. But the difference between our gas plays and oil plays is of course first, the oil plays are valued at 3x:1 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, I think, new reserves of oil onshore in the U.S. And 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'll be led by the same people that led the rejuvenation of the gas business, of which of course we're one. So if you get into a world where gas prices remain at $4 two years from now, I could see a scenario where the majority of our drilling is simply on oil projects and we'll let our gas projects HBP. If you get back to a scenario where gas prices are $6 to $7, which we expect, then you'll probably see a more balanced approach, so highly price dependent.

So it sounds like we can expect an Eagle Ford joint venture in the near term. And then kind of as you think about going beyond that, I mean what is the willingness to get into oily joint ventures? I mean are you already in discussions and...

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 3, 4 or 5x. And that's not too much of a profit to pay for someone coming because at the end of the day, your leasehold typically only costs you pennies or at most a dime or two per mcfe. And so it's a very low price of admission for companies to get in. So because 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 cost back and have -- typically, one of the world's largest energy companies is 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 of them 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 will be oil-directed?

Yes, definitely.

And how -- I mean, you kind of answered the question if it's going to stay balanced. How much in asset sales, Marc, do you think you can actually do with because of 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 for us?

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 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. I mean 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.

We will now take our next question from Dave Kistler with Simmons & Company. David Kistler - Simmons & Company: 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 the plays that we have mentioned. But primarily, you're going to see the ramp-up occur in the Eagle Ford. And in the Granite Wash, we've already almost doubled our rig count in the last, I guess, 90 to 120 days. Steve, is that fair to say? And then at the Anadarko Basin, it's going to take a lot more rigs and then 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. David Kistler - Simmons & Company: I guess a little bit more specifically there, 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 to the schedule to hold them by production?

I can't 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. And I think that's a combination or a total of 13. David Kistler - Simmons & Company: And 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'll be a core part of this 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 America? 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 are capable of getting up to speed there. And no, we've been good hedgers of oil over the years. 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 the lower prices of oil.

Dave, this is Marc. I would just add that in terms of practical application, Aubrey mentioned we don't need to add people. We can hedge oil, I think, equally as well as we hedge gas under our existing facilities. There's no distinction. Our counterparties are prepared and everyday, make liquid markets, and forgive the pun but in oil and natural gas liquids. And in fact, I would point to the oil market probably itself being more liquid in terms of hedging counterparties than the natural gas markets. So I don't think you should expect anything different. We'll sell swaps primarily. We'd consider primarily callers on oil because of the upside volatility might increase the put level for us on a non-cash or no-cost basis. And then 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. David Kistler - Simmons & Company: 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 I think kind of a $6 to $7 range in the future. Can we talk a little bit about the drivers of that, et cetera?

Well, one of the best drivers probably is everybody hates gas right now and -- 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 that U.S. producer will be swamped in LNG, and I don't think it's ever happened. And I suspect it will never happen. And so the world LNG supply-demand balance is fixing itself pretty rapidly through increased demand. And I suspect a couple of years from now, you'll be back in a 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'll 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 occurred at almost any gas price, will have essentially run its course a couple of years from now. And it will be done by then. And all of a sudden, our drilling, rather than becoming involuntary or being involuntary, will become voluntary. And we only drill gas wells when we think the price curve pays us to do it, not because of the ancillary benefits of picking up a carry or HBP in acreage. Finally, I think -- well, two final thoughts: one is the coal floor, I think,…

[Operator Instructions] We will take our next question from David Tameron with Wells Fargo.

Aubrey, we've heard about some of the other plays, but can you talk a little more about what you guys are doing on the Rockies and Niobrara and Mowry, Frontier, et cetera, kind of with the concept thing? Just more color there.

Yes, probably not really able to do that, David. I guess we are able to. I guess we're 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's a matter of public record that one of them is in the Niobrara and one of them's in the Frontier, in the Powder River Basin. I think it's a matter of public record that EOG has a rumored goodwill in the Niobrara and the D-J 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. And 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 hadn't liked the gas prices there and I hadn't liked the environmental issues. But at least in these areas of Wyoming, most of the land that we're involved in, it's going to be fee land rather than federal land. And in the D-J Basin, it's going to be on fee land as well. So yes, I think there'd be a lot more visibility on those plays going forward. The State of Wyoming requires you to disclose a fair amount of information, and so that'll become matters of public record as we drill more.

Any color on the split of acreage? I guess at 400,000. . .

Yes, I'd rather not at this time, although there's areas at play where the two formations overlap. But we haven't double counted there in acres. In acres, we're on audit whether it's prospective for one or the other or both.

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 oil in Wyoming is going to -- Steve, do you happen to know? I guess to Casper. But honestly, I don't know. Dave, if it's important to you, we'll find out. And Jeff or John Kilgallon, he'll get back to you.

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

You're 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? That is, why aren't these VPPs more popular in your opinion? And I guess 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.

Well, I think there are various reasons. First of all, we're thrilled that other people don't because well, there is less competition at the end of the financial market. But rating agencies see these things mainly as debt, which is something that of course that hurt 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, what we think is a very favorable value. Basically, the buyer is paying what these days? 8%? 9%?

8%.

Yes, 8%. So there are very few asset buyers out there in the industry that'll pay you PV8 and let you keep the tail and let you keep deep 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 and 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 BP or a Statoil or a Total around the world. And I think that's made us a better organization for having to meet additional standards with our domestic operations. Also, look, if shareholders value your Marcellus acreage at $15,000 a net acre, you don't sell it into a JV at $14,000. If shareholders value Marcellus acreage at $2,000 an acre and you can get some 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 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, then we know that there are industry players out there that will give a fair value for those assets. And we'll bring them in and create value that way.

Dan, I really don't have anything to add on 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 counterparty to want to take a long-term relationship with you. Clearly, you 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 arrangement. I mean we happen to disagree with the rating agencies pretty vociferously. It doesn't mean they've changed their minds. But I mean clearly, this is for GAAP purposes of 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 or we market them. So there is no ongoing dollar obligation for us at all.

Depending on gas prices and certainly your outlook on the commodity of course, does the day ever come that Chesapeake exits the natural gas play entirely? And I guess 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 Arkoma Basin Woodford in the fall of 2008. I think we had $235 million invested in it, I think if I recall. And we sold it 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 though the better thing to do is to go buy acreage for x, prove up the concept and go sell it for 5 or 10x. And we'd go sell 25% of it for 5 to 10x, and that's a model that we think can work time after time. Now it's really, really difficult to communicate clearly here how many companies around the world want to be in the U.S. and really have 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. And a lot of companies aren't willing to do so for various reasons. So we've got a high degree of traffic through hear 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.

We will now take our next question from Biju Perincheril with Jefferies & Company. Biju Perincheril - Jefferies & Company, Inc.: Marc, you mentioned a part of the liquids volumes is it says on how you account for processing. 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 with the very rich natural gas stream there. We are selling the liquids separate from the gas. And 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 southern Oklahoma plays as well. So going forward, we'll be happy to discuss liquids separately, but it's going to be reported as a liquids and oil stream together. Biju Perincheril - Jefferies & Company, Inc.: Is that 50% of the sequential growth was coming from NGLs, is that what you meant or...

That's what I meant. Biju Perincheril - Jefferies & Company, Inc.: And 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'll be happy to get back to you on it, Biju. We'll just have to go over accounting print. We'll look it up. Biju Perincheril - Jefferies & Company, Inc.: And then so you're looking at asset sales in the 1.5 million net acres in the Marcellus. I'm not sure if that's something that you want to do or -- and obviously, not getting full credit for it. How close are you to either fully assessing how much of that you want to keep and perhaps monetize part of that, either additional JVs or an outright leasehold sales?

We sold some of our acreage in the far eastern part of the plain in Pennsylvania. And we sold to Amerada Hess and Newfield. We did that in the first quarter I believe, and we're happy to have them take on Wayne County and drilling wells in the Delaware River Basin. And 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, and if you look at what 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. And I think that makes our acreage worth a large amount and believe that, in time, we will get full value for that. Biju Perincheril - Jefferies & Company, Inc.: So no plans in the near term to monetize a large chunk of that? It's something that you want to go out and develop?

Yes, 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, Statoil joined us. So there will be places from time to time. We'd probably peel off some acreage jointly to somebody else or maybe it's not core to us than it is core to them.

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

Just 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, 24 months as the business mix changes slightly. And then secondly, although kind of like a couple of years away still, just if you had any thoughts about pushing back maybe the 2013 and 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 '13 and '14 maturities, we are considering every day the opportunities to call those, refinance them, to move out the maturities. And I think over the last I guess 14 years that -- 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. 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.

And that is all of the questions that we have at this time. At this point, I would 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.