Good day, and welcome, everyone, to the Chesapeake Energy 2011 First Quarter Earnings Results Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Jeff Mobley. Please go ahead, sir.

Good morning, everyone, and thank you for joining our 2011 first quarter financial and operational results conference call. With me this morning are Aubrey McClendon, our Chief Executive Officer; Steve Dixon, our Chief Operating Officer; Nick Dell'Osso, our Chief Financial Officer; and John Kilgallon, our Manager of Investor Relations and Research . I will have prepared remarks by Aubrey and Nick, and then we'll go to Q&A. Aubrey?

Good morning. We hope you had time to review yesterday's 2011 first quarter operational and financial release. We are off to a very good start to 2011, and I would like to begin my remarks by highlighting three significant achievements in the first 90 days of the year. First, I hope you noticed that we have already reached our 25% debt reduction goal of the 25/25 Plan. Now we just need to maintain where we are from here on, and that is our plan. Secondly, we have efficiently and uniquely built an internal oilfield service company as a way to counter oilfield inflation and enhance the efficiency of our operations. We believe this enterprise is worth at least $7 billion and we intend to seek a partial monetization of it in 2012. Third, we have established industry-leading leasehold positions in two potentially very significant new liquids-rich plays. The first of these is the 1.2 million net acres that we have acquired in Utica Shale play of far Western Pennsylvania and eastern Ohio. The second is the 1.1 million net acres that we have acquired in the Mississippian Carbonate play in Northern Oklahoma and Southern Kansas. We expect to initiate JV efforts in both of those plays in the 2011 second half, and to provide more production results from our efforts in both plays as the year progresses. In the meantime, I would remind you that recent liquids-rich JV acreage values have been in the range of $5,000 to $20,000 per net acre. Using something in the $10,000 per acre range, would indicate that these positions could be worth $23 billion to our company, combine that with the $7 billion of service company value pickup, and you can say that we are highlighting more than $30 billion of potential value creation…

[Operator Instructions] And our first question comes from Dave Kistler of Simmons & Company. David Kistler - Simmons & Company International: Real quickly, looking at the VPP, recently some other folks have entered into royalty trust instead of VPPs, and I was curious maybe you could comment a little bit about how rating agencies treat the, well, how they treated this debt even though it probably it shouldn't be treated as debt, and whether there's an advantage to maybe looking at royalty trust and is that something that you'd consider going forward? Domenic Dell’Osso: Dave, that is something that we have talked about and will consider. We don't yet have a real clear picture about how the rating agencies will look at them. I did spend some time with the rating agencies last week and reviewed our VPP position with them. They don't all look at VPP's the same. And so I think that -- a hope that we have is that we can continue to make the case that these are in fact royalty interest sales similar to a royalty trust, and we'll see where this all plays out. But the royalty trusts that have been done are very effective monetization tools and something that we would consider. David Kistler - Simmons & Company International: Okay. That's helpful. I appreciate that. And then just focusing on your vertical integration strategy for a moment, can you talk a little bit about, are there people constraints that you're encountering? And as you pursue vertical integration, I would guess you're sourcing some of the people from existing service companies that might have more stability with a service company that's internal to an E&P company, and just kind of wondering how that's affecting the landscape with service providers outside of those that you've vertically integrated?

Dave, several good questions there. In reverse order, even though we do provide a lot of our own services if you strip away our internally provided services, I still think we are the largest US-based customer for service companies in general, so in total. And so there's still plenty of business, Chesapeake business for outside service providers to compete for everyday, and they do so. With regard to the benefits of what we do, certainly, enhanced coordination of operations is the easiest thing or the most important thing that we can talk about when you get people on location that all work for the same company. Communication is easier, you share the same financial incentives and everything is better, and we think safer as well. With regard to the hiring of people, you hit on a very important note. If a fellow works for a third-party, drilling contractor, for example, he knows that he's likely to be laid off every 2 or 3 years. No fault of the company that he works for, it's just that's the rhythm of the business. And when a guy comes to work for us, he knows that we won't ever lay down our own rigs. And so we know that just looking, for example, at the turnover inside of Bronco, which was basically an industry average company, was somewhere between 150% and 200% per year, the turnover at our own drilling company is somewhere around 25% per year. So dramatically different approach to the business and outcome where you're not in this constant cycle of hiring, training, firing, hiring, training, firing, we're able to keep guys and attract the very best. So lots of reasons to do it, and again to hit on a point Nick made and from several people today, that they are upset that we increased our CapEx guidance for the year by $500 million. But we didn't increase our activity with this kind of mark-to-market where we think frac costs are going to be, but we have an almost perfect offset to that through our investment in Frac Tech. And I hope people will recognize that we built not only a service company that will create efficiency and lower funding costs, but also acts as a unique hedge against the rising oilfield service costs. David Kistler - Simmons & Company International: Great. Thanks for the clarification. And one last thing, more of a cleanup item. Looking at the unproved properties acquisition, which I'm assuming is incorporating lease hold or it has in the past, running about $880 million, give or take, is that particularly front-end loaded? In the past you talked about your acreage acquisition cost being about 1/3 of what it was last year. And if I ran that forward, it will be a little bit above that. So just trying to tie that up.

Sure. We would expect that to be an attention that some people would pay to during this release. There is a lot of 2010 spillover we talked about that, that we had probably $600 million to $700 million of deals that were signed in 2010 that would spillover into 2011. The vast majority of that is going to be in the first quarter. I would also direct you to the line under that, which is sale of leasehold during the quarter, which was $3.3 billion, which is the result of our Fayetteville sale, but also our Niobrara sale. And so for the quarter, we are $2.5 billion ahead. I have said on many occasions whether we spend $2 billion gross or $2.5 billion gross, it will remain my goal for the company to end up the year with negative leasehold cost, and we're obviously off to a good start there.

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

Can you talk about your liquids realizations and the drivers of the change in your guidance widening out the differentials as a percent of WTI? And beyond 2012, should we expect that, that differential will narrow based on what you know about the mix within your liquids portfolio, particularly maybe some comment on the Utica and how that plays a role as well?

Sure. Good question, Brian. During the quarter, about 53% of our production was NGL are long term -- I'm sorry 53% was oil rather than NGL, 47% was NGL. Our long-term model is 60% oil, 40% NGL. It's simply a function right now of the Granite Wash's throwing off so much, so many volumes of NGLs in our kind of black oil plays, if you will, the Eagle Ford, the Niobrara and Cleveland, Tonkawa and Mississippian, for example, plus our Permian plays are certainly just in the very beginning of their ramp up. So we expect that we'll trend up to around 60% oil. NGLs are running today, depends on where you deliver them, either Bellevue or at Conway, but they're running 47%, 48% of WTI, so you're kind of $52 or $53 a barrel. And so that's $9 or so per mcf compared to $4 or so per mcf on natural gas. So natural gas liquids are highly valued and not as high as oil, and that's why we are focused more on finding oil. We widened our guidance simply because we also took our long-term oil price up to $100, and when we did so, we basically didn't increase our realizations very much and this attributed the whole $10 increase to a wider guidance. There's a second thing at work, of course, which is you do have take away issues in many of these plays, which have led to a greater basis differential against WTI, and of course there's also the WTI differential as well. And there are lots of initiatives underway to correct the basis differentials in the various fields but of course, also, several recently announced projects that we're engaged in also that will help fix the basis differential from WTI to Brant[ph]. So lots of progress to report over the next couple of years and closing those basis differentials. In the meantime we are on track to meet all of our liquids production goals and to reach that 60% oil percentage as well.

And what's your expected split in the Utica in terms of oil versus gas versus NGLs?

I don't have enough information to project that yet, Brian, I'm sorry about that.

Okay. And lastly, can you provide a little more color on your Williston position and activities there. I may be recollecting incorrectly, but I believe you've mentioned in the past that you're testing more new concepts as opposed to the Three Forks/Bakken, but I think you mentioned the Three Forks/Bakken here. Can you just give us an update on what you're seeing there?

Yes. We actually haven't started to drill there yet, Brian, so I can't update you but I can just confirm that we have around 200,000 acres in the play and I think we'll end up in the 250,000 to 300,000 range. And probably we'll look for a partner during the course of the year, but that's all that we have mentioned about the Williston at this point.

Okay. Are these new concepts or is this the same kind of Bakken/Three Forks that others are pursuing?

We just need to limit it to conversation about the Williston if I can at this point.

Our next question comes from David Tameron of Wells Fargo.

Couple of question. Eagle Ford, it looked like rigs increased production is that -- am I reading into that or is that a function of bottlenecks in the play or can you talk a little bit about that?

I'm not sure, David, what you're referring to.

Just looking at the quarter-over-quarter production kind of the Eagle Ford. I guess, bigger picture, getting away from that specific detail, can you talk away take away right now?

Yes. Sure, David, you're referring probably to the table on Page 6.

Yes.

We still have -- and I'll let Steve jump in here too. But we have lots of logistics issues in the Eagle Ford where we are limited by the amount of oil that we can produce. And so we have a whole lot of oil shut in, and maybe Steve has more.

Yes. And there is a lot of bottlenecks associated with trucking, part of it was also completion prohibitions during the dear hunting season over the winter. And so we were able to get some oils drilled but a lot didn't get completed until the spring. So we should have a very good quarter in the second quarter.

Okay. In any particular part as far as your entire acreage? Any region that's more impacted than the others?

They're everywhere.

Well, in the oil hauling, the trucking choke, it kind of affects everyone. We are putting in quite a bit of the liquids pipelines so that will get fixed.

Okay. And then Aubrey, in the press release, there was a comment there about you could spend $100 billion over the next decade. Can you talk -- can you give us some more color around that or just kind of what that message was coming from that state?

Sure. It's just growth, it's just what we're possible that we'll be able to spend based on what our asset is and what our cash flow will grow to. So it's a big company, and it's going to become a bigger company as we create the value out of these huge liquids positions in 12 of these 13 leading plays. And we're going to be a leading oil producer in the country in the next few years, and that will continue, we think, for many more years after that. Domenic Dell’Osso: But David, that would be gross.

And our next question comes from Neal Dingmann of SunTrust.

Say, Aubrey, just wanting your general thoughts on current M&A activities and prices in areas like the Permian, Eagle Ford, Powder River and DJ, including the Niobrara, kind of what you're seeing today versus the start of the year and is it kind of sort of playing out as you thought?

Neal, are you referring to -- I think you said M&A is that right?

Yes, sir. I'm just kind of want to...

Honestly, we don't play in the M&A market and don't really even look in the M&A market. We, by acreage, post sale and then try to sell it at retail through JVs. So if you're referring to acreage values, I think that you can look at the Anadarko transaction with KNOC in the Eagle Ford and you'll see a $20,000 acre print. You can see some other deals. You can look at SandRidge's royalty trust and back into an acreage value there, that's probably the same amount. So we see continued strong interest in participations and what we think is the most profitable place in the world to look for and produce a barrel of oil. And that's in the U.S. and so we had these commanding leasehold position that we think are going to continue to increase in value. So if you're referring to corporate M&A or producing property M&A, not in a good position to comment because we simply don't look at that anymore.

Got it. And then your comment about the oil services, obviously, your down in position in a lot of those. Do you continue to look for a little privates, I mean, whether it's on the fluid side or some other parts of the completion area that you would think that sort of add to your stable?

Well, we bought 3 rig companies in the last 6 months or so, 2 private companies that were kind of special situations that brought us, I think, 13 rigs, if I recall. And then we're doing Bronco. And Bronco just happened to be an opportunity that we thought we should take advantage of. Everything else we've done really through organic growth, that's how we're building our own pressure pumping operation. That's how we're building all of our other service lines. So again, on occasion, on the service side, I guess, we might look at existing small, private companies, primarily in the Oklahoma City area, but for the most part it will all be organic growth.

And are all the Bronco rigs, are those still operating? Did you keep those basically in the same location and you're still operating those as they were kind of when you took that over?

Just to reminder you, we haven't -- we don't own Bronco. Yes, we are tendering for Bronco and that date, tender date, I believe, is May 23. So it is business as usual for Bronco. And afterwards then our goal is to use those rigs for our own benefit as their contracts roll off with the existing E&P companies.

Our next question comes from Gary Stromberg of Barclays Capital.

You have some comments in your other report on the benefits of achieving an investment grade rating? And then Aubrey in your comments you talked about having already achieved your 25% debt reduction goal and your plan is to maintain that level of debt reduction. You have more monetizations obviously in the works here with the JVs and oil service potentially next year. What do you do with those proceeds? And I guess part 2 is, Nick, you mentioned you may met with the rating agencies last week. What did they say about that have to do to get to investment grade?

I'll take the first part and go over to Nick. I want to remind you, Gary, that we do have other CapEx demand other than E&P. We have midstream demand, we have service company demands, and so our goal is to have our debt stay where it is our go down, while of course our asset size will continue to grow up to increase over time. And we can pull off, I don't know what we'll get from an asset monetization on our service company, we tend to be pretty conservative than what our expectations are. But like we did with the Fayetteville sale, when we can hit a home run and we'll propose to use that excess to pay down debt. So that remains our goal. Of course, one of the problems in attacking our debt structure is the premium at which our debt trades today. So we have to be mindful of shareholder value as well. And so in this case, we took about half of the Fayetteville proceeds and use them to repay long-term debt that trades in the open market. We took the rest to pay down our revolver. So going forward, this company is going to continue to increase its asset size, while its debt level will remain where it is or go down. And we will continue our steady march towards investment grade. The more important thing to me than the rating is where the market -- how the market sees where the company is today and its credit statistics. I don't think we'll ever see eye-to-eye with the rating agencies on VPPs, they're quite simply just wrong in their approach to that. But that doesn't mean that, that is they are -- anything other than tremendous economic and financial monetizations on our part. So the market though sees us as a strong crossover credit. And I hope in the next year or so that, that will continue to trade in the investment-grade territory. And how long it takes the rating agencies to get there, I can't predict. But I know it will trade there before our rating gets there. I'll turn it over to Nick now. Domenic Dell’Osso: Yes. So the second part of your question was really what the rating agencies have told us we need to do, and of course it's not quite that formulaic. There's many reiterations that they go through on their side, and they have reacted well to our 25/25 Plan progress thus far this year, and we'll continue to keep them apprised of what we plan to do in the future, but there's no specific target we can give you guys. I'll just point out again the 25/25 Plan like Aubrey said, attacks both sides of what we think is the key equation, which is debt to assets and it lowers the numerator and increases the denominator pretty aggressively. So we're eager to continue to make progress there and have those show up on our results.

We'll go next to John Abbott of Pritchard Capital Partners.

Aubrey, I had a question about the breakdown of the segment contribution from the oil services side. Do you have kind of a rough breakdown between gathering pressure pumping, transportation and drilling? I guess, just...

No. We don't break it down. Just to remind you, gathering is not in there. So that's in our midstream business. So at this point, we prefer to just think about it as one consolidated, integrated business rather than break it out by business line. Domenic Dell’Osso: And we currently account for our Frac Tech investment on the equity method, and don't have any of our pressure pumping equipment in the field yet. So primarily, you're talking about rigs and traditional other service equipment.

Okay. And the pressure pumping that you're constructing is the 100,000 horsepower this year and 200,000 next year, I'm not remembering that.

100,000 this year and 150,000 next year for a total of 250,000.

Okay. Got it. And just, can you -- are you disclosing -- I think you have said in the past your acreage cost in the Utica was about $1,100, $1,200 in acre. Is that...

No. I think the last conference I was with, I talked to about around $1,500 or so. So that's more or less in the ballpark.

Okay. Got it. And the Mississippian or the Bakken or the Williston are you disclosing that or?

I don't think that we have -- but Mississippian would be well less than that. And a lot of our acreage there is legacy leasehold that have essentially today no cost basis. So when you get a little further down the road, we'll be happy to talk more about our cost basis there. But the Utica acreage is by far more expensive than the Mississippian acreage.

Okay. Got it. Great. And just one question, any update on Susquehanna County and the EPA trying to get involved. When do you expect to be...

Sure. I'll let Steve Dixon address that.

Well we have provided all the data of the incident to the DEP, and we expect to be able to get back to work fully, hopefully, later this week. We provided both data on chemicals used, the release and the failure itself that was in the wellhead where a leak developed on the connection at a flange. And so we got basically all that data to them late Friday and expect to be able to move forward again later this week.

Might also add that the cessation of our completion operations was voluntary on our side. We just needed to make sure we had double checked all of the other wellheads, but didn't have a repeat of this incident.

[Operator Instructions] And we'll go next to Rehan Rashid of FDR. Rehan Rashid - FBR Capital Markets & Co.: On your 39,000 well to drill, $100 billion of CapEx to spend over time, from a people standpoint, what functionality is the most acute to address and just in general people adds over time that we need to address?

We don't really think about having people bottlenecks because we have been so successful at building our culture here and attracting a particularly young employee base. We have about 11,000 employees today, about 4,000 of which are in Oklahoma City. Half of those 4,000 are 33 years of age and younger. So we are certainly building the next generation of leadership in our company and the industry right here. I think we're receiving about 500 resumes a day. So we have no problem running out of potential people to hire. So I don't really think about that as a chokepoint. We've got the leasehold, we've got the partners, we have oil prices where we think they're going to be strong for years to come, and we think gas prices that -- maybe have another year or so to struggle. But after that, we'll start to pick up as well. So we think we're really well-positioned to meet a growing industry's needs. And we think the world needs more clean energy in the form of natural gas and it certainly needs more liquids energy in the form of oil. Rehan Rashid - FBR Capital Markets & Co.: One more quick one, for next year, the CapEx, does that include some more level of service cost inflation or how much of it?

Yes. We really had built into next year some things that we weren't sure we're going to take place this year. So I think we're in pretty good shape with where we are. But the prediction of CapEx is difficult because it's, really, two things have affected us lately. One is the dramatic increase in completion cost, which again I think we fully offset by our hedged position in Frac Tech. The second though is that we have such a huge leasehold inventory base that as the industry ramps up it's drilling, we spend a lot more money on non-op participations. And so you've seen the oil rig count really aggressively move up in the last 90 days. That has probably caught us even by surprise. And another portion of that CapEx increase for the year is non-op. And we really don't focus or spend a lot of time modeling production growth from those incremental non-op rigs, but they do have a CapEx increase. So those are the two main drivers of this year's increase. And next year, we'll see, but we think we like where we are there.

And we'll go next to Scott Hanold of RBC Capital Markets

It's Scott Hanold at RBC. And a quick question for you on CapEx in terms of spending for your oilfield services, some of the stuff you're building internally. What amount do you look at for 2011 and 2012, and I'm assuming that's not included in your drilling and completion expenditures?

I'm sorry, what -- did you ask what the amount is, Scott?

Yes, that's right.

We haven't -- yes, we haven't disclosed that because we're -- for various competitive reasons. We do tell you what our drilling CapEx is likely to be to the best of our abilities. But at this point, we haven't set forth the public specific CapEx budget for service side nor have we done so on midstream. It is reported though in our, I guess, in our Qs. If we want to -- Nick if you want to talk more about that or just wait until the Q comes out and let it speak for itself. Domenic Dell’Osso: Yes, we spent relative charge, really, in completion of CapEx. We spend a modest amount of capital on our services business every year, and we'll continue to do that. We are growing it right now the way that I would think about it for you guys as we were at approximately 160 rigs at our peak back in 2008. We're at approximately at our peak level again now and we're growing, and so our need to invest in the services businesses is front and center of our minds, again, as we get to the point where we're increasing our operated rig counts. We'll continue to invest there but it's relatively modest compared to what our joint completion CapEx is.

Okay. Can I ask you, in terms of the pressure pumping you all are building, is a lot of expenditure yet to be done or is there a certain amount that you, obviously, have to commit initially to get that process started? Domenic Dell’Osso: Yes. There are progress payments made along the way and there's -- some has been made and some is yet to come. So it will be kind of a methodical quarter-by-quarter payment program there as we continue to add crews over time. We talked about a 2011 and a 2012 delivery of horsepower, but of course, they don't all show up on one day.

Okay. Understood. One last question. In terms of your hedging and sort of using these -- selling forward or I guess the written calls on the oil. It looks like you indicate that you've got 41% of your forecasted production that's covered by these. But if I'm not mistaken, you had indicated that roughly 55% of that production though is NGLs -- or I'm sorry is oil. So when you kind of look at that balance, where do you want to be in terms of how much of your oil do you want to commit to some of these hedges?

Well, if the price were right, and we didn't want to keep some oil open for further increases. We could hedge 100%. Natural gas liquids do trade pretty closely to oil. If you look back where they were a year ago when oil was $30 a barrel less. And Conway was at 43% and Bellevue was at 53%. And within 1 percentage point, that's where they're both are today even though the price of oil has gone up by 40% in the past year. So we think you can hedge NGLs pretty effectively through hedging oil. But we are pretty optimistic about the price of oil going forward, and we sold some calls to enhance our ability today to brighten that oil future to buy leasehold that we wouldn't otherwise have been able to afford in some of these oily plays. And so right now, as I look at our overall hedge position versus our entire resource base, we've hedged at about 1% of our entire resource base. In the meantime, we've made $7 billion in cash hedging in the past 10 years. So hopefully, we can make that much more in the next 10 years.

And just to clarify a little bit, because maybe I wasn't clear there. How much of your oil volumes would you be willing to commit to that? Like if I were look at -- right now you're seeing about 41%, but if you're just to look at the actual oil volumes itself, it's probably somewhere closer to 75%. Would you be willing to go in excess of that because of those NGL volumes or would you kind of limit it to where the oil volumes would actually be?

Scott, I think I tried to just answer that by saying that we're certainly willing under certain circumstances go to a 100%. But on oil, it's highly unlikely that we would find ourselves incentivize to do so, unless you had a really rapid spike in oil prices from here. We believe that world oil demand will continue to grow. World NGL demand will continue to grow. And we're optimistic about oil prices, and so we'll periodically hedge. But at this point, we're not looking to take oil hedges to 100%. Okay. Thank you, and thanks to everyone else. And we look forward to further conversation with you, and hope you have a good day. Thank you.

And that does conclude today's conference, ladies and gentlemen. Again, we appreciate everyone's participation today.