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

Good morning, and thank you for joining our 2011 second quarter earnings and operational's 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 Director of Investor Relations and Research. Our prepared remarks, by Aubrey and Nick, should last about 20 minutes, and then we'll launch into Q&A. Aubrey?

Good morning. We hope you've had time to review yesterday's 2011 second quarter operational and financial release. The quarter was very successful on a number of fronts and they have set the stage for further successes in the second half of 2011 and throughout 2012. Because the quarter progressed quite smoothly, operationally and financially, I will focus my comments on providing an update on 4 of our best liquids plays, about which you haven't heard much from us until now. These 4 would be the Mississippi Lime play in northern Oklahoma and southern Kansas; the Cleveland and Tonkawa tight sand plays in the Anadarko Basin of western Oklahoma and last, but certainly not least, the Utica Shale play in eastern Ohio. First, with regard to the Mississippi Lime horizontal play. Chesapeake discovered this play in April 2007 with the drilling of the Howell 1-33H well in Woods County, Oklahoma. This was the first modern horizontal Mississippi Lime well drilled in Oklahoma. The well's cost was approximately $2.7 million, and we found approximately 285,000 BOE in this well, a very, very successful first effort. However, 2007 was also the year in which we discovered the Colony Granite Wash play in western Oklahoma, a play that has now seen us drill 126 wells and developed 225 million gross barrels of BOE reserves from those 226 -- 126 wells. Because we were unsure of the ultimate size of Mississippi Lime play and unsure how predictable the rocks would be, we ended up developing our Granite Wash assets more quickly. However, in the past year, it has become more clear that we have a major play on our hands in the Mississippi Lime, and so we ramped up our leasing and drilling efforts quite significantly. Today, we own 1.1 million net acres in the…

[Operator Instructions] And we'll first hear from David Heikkinen of Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Aubrey, as you think about the $15 billion to $20 billion valuation, is that before a monetization or after?

It's basically just what we think the acreage is worth in a monetization and so in this guidance -- yes, 8 8s exactly. Now over time, of course, as we convert the leasehold into producing assets, it'll be worth a lot more than that. I'm just saying, today, based on what we've seen in JVs and what we think we've got here, it's not unreasonable to think about an 8 8s valuation of the asset at that level. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And would you classify the wells you've drilled so far as oil wells?

Dave, we're not going to release anything further about the play than what we've said. But in time, we certainly will. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And the split of what 3 regions you've actually leased in either?

[indiscernible] but I mean -- you're a research analyst and other people are as well. I mean, there's public records out there and wells are hard to hide, so there's plenty of information out there if people want to go find out about it. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then seeing large companies now start splitting up to unlock value and you all have talked a lot about the sum of parts value, how do you think about the benefits of being a larger company as you kind of aggregated the assets? Even splitting up and selling parts, how do you keep the whole thing together, or do you think about a bigger benefit of splitting up to unlock value?

I think that -- couple of things. First of all, we've spent between $1.5 billion and $2 billion acquiring leasehold in the Utica. If we were a smaller company, we wouldn't have be able to take on that risk. We've put together one of the nation's largest collections of oilfield service assets, which are going to give us, have given us, a hedge against rising service costs that nobody else has. Our -- the frustration here is that yesterday, we have to increase our drilling CapEx by $500 million in 2011 and 2012, but we also couldn't say, "Hey, we think we made more than that in just the increase in value of our service assets during that same time." So to me, the integrated approach makes sense. Our size and scale enables us discover things that we wouldn't otherwise be able to do. So Nick may have some comments on -- or some thoughts on that as well. Domenic Dell’Osso: Hey, David. You commented on the breakups that you see in the industry, and that's really counter to the strategy that we've outlined here and that we're trying to pursue. We would like to pursue partial monetizations of these businesses, not dissimilar to what we achieved with our Midstream business, so that we can point to the value that we've created in these businesses and also capitalize them separately. We believe there are different cost of capital for each one of these businesses. And it's efficient and, frankly, a little clearer for the Wall Street community if we do it separately. So we like that model. We think it gives us an opportunity to recognize value from what we've created. But vertical integration is core to our strategy, and we don't want to give up the control and ability to affect how we use those assets in the field everyday.

And would you think differently about our 2011, 2012 CapEx budgets if we're able to show that our service assets are worth $7 billion rather than $1 billion or $1.5 billion as our cost basis? That's our plan to be able to do that and think we will be able to do that and think investors will benefit from investing in a company that is uniquely able to offset almost all, if not more than, the service company inflation that it faces in the operating environment today. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. And then that actually segues into the final question I have. If I, just back of the envelope, looked at the 30 to 40 rig program, 25 rig program in the 3 plays or 4 plays you just outlined. Do you get multiples of your drilling budget, just in those plays potentially? Can you talk about how you overall fund a 2014 plan, and what's your total budget would be or the implied budget is from what you just outlined?

Sure. David, we've budgeted out through 5 years, so out through 2016. And I also saw your note this morning. Remember that the CapEx that we talk about here is a net CapEx, so there's $2 billion this year of carries in that and about $2 billion next year as well. And as we move forward in developing these plays, we'll have a carry in the Utica. We'll have a carry in the Mississippi Lime as well. So when you talk about a 2014 plan being $3 billion net to the Utica at 40 rigs, that's true, but we don't expect to be paying 100% of that. So... David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Yes, I was trying to get to the 8 8s value as well.

I understand, I understand what you did. And I thought you did a great job on doing that, maybe a couple of billion dollars light on the low side, but still thought it was a great piece of work. But we're aware of the capital obligations, and that's why we entered into these JVs to help us shoulder the load. With regard to where we end up, I think you've been with us on the road, and you know that we are targeting about $10.5 billion to $11 billion of EBITDA in 2015, and cash flow would be right underneath that of course. And so with those resources, which come from both expanding production, but also from a much more profitable mix of production, as our production becomes more liquids focused, we believe we'll have plenty of capital to do everything that we need to do. And I reiterate, that's with keeping our debt where we targeted to be, which is right around $10 billion at the end of 2012 and also, of course, not to be selling any stock during that time as well.

Next, we'll hear from Brian Singer of Goldman Sachs.

Can you add a bit more color on the reasons beyond the geography of the stronger gas production? How much of that was related to well performance versus using longer laterals, reducing drilling days, reducing backlogs? Just give us some sense as to the reason, in both the Haynesville, the Marcellus and it seems like in some of the other plays as well, for the strength in gas production.

Well, I think it's related to kind of the opposite of what you read in the New York Times these days perhaps, which is that as you drill more wells in these plays, they get better, not worse. And so -- Steve, as I think about our first Marcellus estimate, I think we were around 3 Bcf a well.

Yes.

We've steadily stepped it up as have others, and so the evidence just became overwhelming to us. And our core part of the play, in northeastern PA and southwestern PA, that we're finding at least 5.75 Bcfe. So production has been overrunning our estimates, which were predicated on lower EURs. Haynesville, we started out with 6.5 Bcfe, and I think that's where we still are. Production rates still, over time, have certainly tended to increase as we learn more about the play. And I think sometimes people forget -- these are not -- these 200-foot thick shale formations, there's a lot to be learned about then once you establish initial production, with where's the right 20 feet, where's the right 30 feet to drill. And we were starting to discover that in all of our plays, and so were able to more optimally placed wellbores going forward. If you think about the Barnett -- Steve, I think we started at 1.6 Bcf on -- I think. And today, we're up to 3.2 Bcf per well?

3.3.

3.3, 3.3 Bcfe. So anyway, just -- this is what's so different about what we do today. In the old days, your first well at play was your best play and every well thereafter seem to get worse. Today, we drill our worst wells first, and that's what makes us so -- one of the reasons that we're so optimistic about the Utica. We have not drilled our best wells here right out of the chute. We probably drill our worst well. So that gives us a lot of optimism about what we're likely see down the road. So specifically, unless Steve wants to say something else, the out performance is generally across the board, but our strongest wells, gas wells are in the Marcellus and Haynesville.

And in the Marcellus specifically, with the EUR increase, that is completely well performance, or you -- have you also increased your lateral links?

Yes. I think it's all well performance.

Our lateral links, Steve, on average in the Marcellus is around what?

Oh, 5,000.

So -- and then in Haynesville, we remain constrained by the boundaries, that are 640-acre spacing units. So those laterals are about 4,500 feet.

Great. And then switching to the Utica. I guess looking where the -- looking at where the state has indicated you permitted horizontal wells relative to your map of the play, it would appear your permitted horizontals are focused more on the wet gas window or on the border between the wet gas window and the oil window. Can you add a bit more color on location selection, and where you see the best rates of return?

Yes, I think when you look at the Eagle Ford, you see the best rates of return in the wet gas window. It's got a lot of energy and got a lot of hydrocarbon stuck -- stacked into place. And so we -- I think you can learn something about our approach to the play by seeing where are laterals are and -- or perhaps, seeing where are leases are. So we like gas and got a lot of gas and so do not focus as much on the dry gas window, which also by the way, I might add, is much deeper. We've noticed some companies buying in areas where they're going to be drilling wells to 12,000 and 13,000 feet TVD with 5,000-foot laterals. We're talking 17,000, 18,000 feet. These are going to be at least $10 million wells or maybe $12 million to $15 million wells, and that's just simply not as attractive to us as drilling wells TVDs of 7,000 and 9,000 feet, say, in the wet gas window where you're going to have much more highly valued outputs and much lower cost inputs as well.

Got it. And I guess -- look, comparing the wet gas window to the oil window, are there any issues as you start to move west [wet], regarding pressure or gas drive, that do make that west gas window -- wet gas window superior to the oil window?

We won't be talking about issues other than same issues that you see in every play. There are boundaries to every play, and we have an opinion on those and other companies apparently have different opinions about those. But we'll just see how it all plays out. But right now, we are interested in pursuing all 3 phases of the play. But we have tried to focus our acreage right in what we think is the heart of the play, core of the play, and specifically, the wet gas side of it.

Next, we'll hear from Jeff Robertson of Barclays Capital.

Aubrey, can you talk about any midstream needs in the Utica and the value for Chesapeake Midstream in participating in some of that development?

I'll let Nick talk about that. Domenic Dell’Osso: Sure. Jeff, the midstream needs, of course, in the Utica will be very large. There'll be both gathering needs, processing needs and, further down the stream, transportation needs out of the basin. And the way that our model works is that we develop greenfield assets in our subsidiary, which we call Chesapeake Midstream Development, which we own 100% of. And then over time, we look to drop those assets down into the MLP, Chesapeake Midstream Partners. So we're very early in the stages of designing and identifying what our buildup program will be in the Utica, but you can be assured that Chesapeake Midstream Development will be right in the middle of those plans and attempting to capture a big part of Chesapeake Operating Inc.'s production into its gathering system.

And then secondly, on the rig increases that you outlined, Aubrey. Can you talk about how much of that is or would be supplied by redirecting gas rigs you all currently own, or do you all need to build new rigs? Or do you have enough with Bronco to meet most of your needs in -- or -- over the next several years?

Yes, good question, Jeff. We typically set out to be able to meet about 2/3 of our drilling needs by our own fleet. So today -- Steve, we have 115? So we are at 115 and we're drilling with 168 rigs, 167, whatever the number is. So we're probably a little short of the 67% mark. So over time, we'll continue to add rigs as we have in the past, and I think we'll probably end up doing those organically. I think since we bought Bronco, the Rowan wet rigs went through much more than what we paid for the Bronco rigs, and we think probably, organically, it's the best way to do that. So we'll continue to add, but I don't think it's anything spectacular. But we do -- I would move you back to Nick's comment that on a recent analysis of our wells in the Eagle Ford, we can drill about 20% cheaper than others in the industry when we integrate our services. One other thing we haven't talked about this morning, but just to alert everybody, we will roll out, on October 1, the first parts of our initial 250,000-horsepower fracture pressure pumping fleet, and so we'll be pumping our first wells in the first couple of weeks of October. So another way we are addressing oilfield inflation, and we'll do that through additional rigs, we'll do it through more horsepower. Remember, we need about probably 1 million horsepower a day. And so that would give us the opportunity to build a pretty significant pressure pumping fleet over time.

Next, we'll hear from Scott Wilmoth of Simmons & Company. Scott Wilmoth - Simmons & Company International: A few more details on the Utica leasehold position. Can you guys disclose your term length? What your cost position is in the play? And are you looking to continue to add acreage?

Scott, the answers are yes, we're continuing to acquire acreage in the field on a -- certainly in our strongholds. We are -- we're not working too much on the fringes, where most other companies have moved into. I think I said earlier on the call, we've spent between $1.5 billion and $2 billion on leasehold to date. And on length, generally, we have -- well, we a lot of HBP leases. We went in early and made deals on deep rights with a lot of shallow producers. Much of the acreage we acquired from EnerVest and Anschutz. Some people may recall we made a deal with Anschutz last fall that did not meet with popular acclaim, but we knew we were getting a lot of the Utica leasehold pretty cheaply in that. So a lot of that's HBP. The stuff that we bought off the ground is mainly 5 plus 5 so we feel like we'll have some no trouble getting it all HBP and won't have to be in as big a rush as we were on the Barnett or the Haynesville, although we certainly do have more acreage here that we do need to get HBP. Scott Wilmoth - Simmons & Company International: Do you have a split of the HBP versus the 5 by 5? And what's your average royalty percentage across the play?

I'm not going to give you the -- that much detail. But I think if you look around in the field today and go check our leases, you might find net revenue interest that for us are between 83% and 85%. That's kind of the usual, which is pretty attractive given they're lower than that in Texas and Louisiana. Scott Wilmoth - Simmons & Company International: Okay. And then when I think about a potential JV or you mentioned some alternative structure, would an alternative structure still have a component that you guys have used in the JV, as you look to recover that initial cost basis, the acreage? And then -- or how are you thinking about that?

Yes, I think you need a solution that we choose. We'll have a upfront cash component to it. I mean, it's part of our strategy. We find things. We go acquire the leasehold, and then we bring bigger partners in and -- bigger partners today are not just international energy companies, but they are sometimes national and international financial companies as well. So we want to get our money back for shareholders and derisk the play and then accelerate the drilling. So it needs to have both of those aspects into it for it to be of interest to us. Scott Wilmoth - Simmons & Company International: Okay. And then on a broader basis, you guys mentioned some liquids constraints in certain regions. Can you specify which basins you're seeing the most constraint? And is that on the infrastructure side, the service side, and is it focused on oil versus NGL or one or the other?

It's not really on the service side. It's basically just waiting on the pipelines and waiting on trucks. Again, we're not complaining, and we're meeting the challenge. I think -- Steve, yesterday, we hold our first oil ourselves, is that right, or this week, we did? So we're -- I think we're building 150 oil trucks ourselves to move the oil around and we've got big pipes coming on in the Eagle Ford Shale. So really, across the board, there's a shortage of oil-hauling trucks, a shortage of drivers, a shortage of pipeline, but through our Midstream entity and through our relationships with other midstream companies and then to our own service companies, we're out there meeting those logistical challenges. So we're sorry that we have had to move 2 million barrels from 2011 in 2012. We had hoped that would not be possible but decided now is the time to recognize those constraints and that we're going to work through them and work through them a lot with the solutions that are homemade. Scott Wilmoth - Simmons & Company International: Okay. And then lastly just on the Haynesville, you mentioned rig count going down to 15 over time. At what time period do you get to that level? And then, what's your outlook for the Haynesville production longer term over the next couple of years?

As Aubrey said, we've got 9 of those rigs on their last well right now. We will be at 15 by December. That will have an effect on our production next year. We're not providing any guidance on that.

Well, I mean, it's embedded in our production estimates. I mean, the -- whatever impact it has, it's simply that we won't grow our gas production there as much us we could have if we kept 35 rigs on it. So it's embedded in -- you can look at gas production for -- well, in fact, if you go to Slide 18 in our slide deck that was posted this morning, you'll be able to see how our production growth over time, and just see that virtually all of it is in oil and natural gas liquids. And our gas production goes up a couple of hundred Mcf a day over the next year. Scott Wilmoth - Simmons & Company International: Yes. If -- I think I recall correctly, I think you guys gave a chart specific to the Haynesville in the Analyst Day, and it looked like '12 was fairly flattish. Is that probably still the same fair assumption?

Yes, that's absolutely right, maybe even a little bit down over time. But again, I would emphasize, Scott, that if we're successful with our demand initiatives and you need more gas, we can ramp back up pretty quickly. It's just at this point, we can make a lot more money with taking Haynesville rigs from the Haynesville and moving them to the Utica and moving them to the Eagle Ford or Cleveland and Tonkawa, any of our other liquids plays.

Next, we'll hear from Neal Dingmann of SunTrust.

Aubrey, just couple of questions. First, back to the Utica. Just -- they did add throughout the infrastructure. Just wondering about completion services in the area. Do you already have enough there, or will you be continuing to bring more in the region?

Like everywhere we've been, we've moved in some areas where there's not much infrastructure there, and we quickly overwhelm it. But again, we're pretty good on logistics. And so where we go, service companies follow including our own service company. So we'll -- all delays and all challenges in a play like the Utica, we've met before in the Barnett or we've met it in the Haynesville or we've met it in the Utica -- or sorry, the Eagle Ford. So we'll meet them here. One thing I would say this -- is the location of this play has a number of advantages to it. There's plenty of water. The topography is much less challenging than, say, in West Virginia, eastern PA. We're in a part of Ohio which, frankly, is ground 0 for what used to be the manufacturing belt of America, and unfortunately, the last 30 years has been the rust belt. But we think that our activity can help rejuvenate this area, and we're actually quite pleased with the quality of the workforce, the size of the workforce. And we think, of course, there's great transportation alternatives here, and we're pretty close to the Ohio River. So if we need to barge out tomorrow, we can do that. So there's lots of advantages to doing business in eastern Ohio. And so if you could have picked -- if I could have picked another place for a play to develop, it's pretty much the most ideal place I could think of in America for a big new play to develop. We're excited about it and recognize that our activity is going to create a lot of logistical challenges, but we'll meet them all and create tens of thousands of job while we do it.

And then, Aubrey, in that area, will you target or I guess would say, would you co-mingle some zones? I mean, will you actually be going after some Marcellus as well Utica? And then within the Utica will you be targeting Point Pleasant or just entire Utica?

I'll just leave it at this, that we're focused on the Utica at this time.

And then just last question for you, just maybe a general comment, not just only on the Utica, just overall on the oilfield service costs, in general, as you see it maybe the remainder of the year, kind of your thoughts about that.

We may have different thoughts. My thoughts are that we hope we've seen the last of them or the worst of them, I guess I should say, as we and others put a lot of equipment into the field, whether it be fracturing or whether it be rigs or trucks. So the good news about service infrastructure bottleneck, it can be solved pretty quickly, just call it 24 months or so. And I think that's the same with the problem we have at Cushing. A lot of people are concern about a long-term differential between WTI and LLS. But we think in 24 or 30 months, we'll have it, we, being the industry, of which we'll be a participating part of that I think and we'll have that solved. But, Steve, are you worried about any big new increases in service costs?

No, I think their margins are plenty high today, and there's a lot of equipment being built, lot of the horsepower in place like the Haynesville that can get redirected. So I don't see any further inflation.

Next, we'll hear from Bob Brackett of Bernstein Research. Bob Brackett - Sanford C. Bernstein & Co., Inc.: Question on the Utica monetization strategy. Would you prefer a JV with one of your existing partners, maybe a new partner or you're thinking royalty trusts? Can you shed some light on that?

Bob, I really can't. I mean, we have had repeat customers, and we've had new customers and new partners. So I think, for us, it's whoever comes in the door with the most attractive offer for the opportunity that we've offered are the guys that we'll worked with. We worked with Frenchmen, we've worked with Norwegians, we've worked with Americans, we've worked with British, we've worked Chinese and we get along with them all quite well. Certainly, it stretched our cultural and language upbringing, but it's all part of life, a good part of life, I think. So we really don't have a preference. We -- the process is underway, and we look forward to a successful outcome for our shareholders. Bob Brackett - Sanford C. Bernstein & Co., Inc.: And so a royalty trust could be on the table?

Royalty trusts are attractive and, unless Nick wants to offer anything, I'll just say we filed one. And I think probably we'll need to see how that goes and then decide where to go from there. Nick, anything else you want to add? Domenic Dell’Osso: No, just that, Bob, it's a product that requires a significant amount of proved reserves. So if we were to pursue a royalty trust in the Utica, it would be quite a period of time before we have proved reserves. But -- that would be required there, so that's...

It's a good solution to an asset like the Granite Wash or what SandRidge did in the Mississippian, where they have a nice combination of proved reserves and also some PUDs. So we're not -- we don't have PUDs and we don't have PDP yet of any size in the Utica.

Dan Kecskes of Morgan Stanley.

You guys have mentioned in the past that the rating agencies don't fully appreciate some of the things you've been doing like VPPs. Have you received any recent guidance from them to achieve guiding [ph] metrics by 2012? Domenic Dell’Osso: No, we haven't had any direct recent guidance from those guys, but we do stay in regular contact with them. They ask questions about our earnings release much in the same way that you guys do. In fact, I'm sure they're all listening this morning. And we work with them on any number of questions that they have. So no revised specific guidance, but they're well up to speed on what we're doing.

And clearly, we're increasing the credit worthiness of the company, really, every quarter that goes by as our assets increase. And our debt has now down to the $10 billion number, and it will modulate up and down. But we remain focused on delivering that value at the end of 2012. And I hope, just as Nick mentioned in his comments, that -- we've had to abandon 130 in our 25/25 Plan because our production is overrunning our estimates. We certainly hope that we can go with the 30-30 plan in 2012 and get our debt down even further. So that remains management's goal to make sure that your asset target of $10 billion of long-term debt at year-end 2012. And by that time, our proved reserves will be significantly higher than they are today, and our EBITDA will be higher. All of our credit metrics will be quite a bit stronger at year-end 2012 than they are even today.

[Operator Instructions] We'll now hear from Joe Allman of JPMorgan. Joseph Allman - JP Morgan Chase & Co: Aubrey, what was it that made you announce the Utica, the discovery in this release? Was it the production results from these 3 producing wells?

Yes. Joe, if you just kind of look at the opportunities we have to talk about things, primarily it's 4x a year. And at the last quarterly announcement at the end of April or first part of May, we didn't have producing wells and didn't think it was time to talk about it. We look at the calendar and thinking 3 months from now it's too late. So we just felt like it was the right time to answer some questions and to comment on some rumors that are out there. So we'd always like to say more rather than less when we can, and this is one of the occasions when we feel like this is a nice first release of information about the play, people can digest it. And then over time, we'll be able to be more chatty, and of course, other companies will as well with their results. We expect other companies to start drilling wells pretty quickly. And like the Eagle Ford and Haynesville and plays before it, things kind of go hockey stick here pretty soon, with the information flow that comes out of the play. Joseph Allman - JP Morgan Chase & Co: That's helpful. And so I'm assuming that your apparent excitement about this play is based on these 3 wells not just being clustered together. So I'm assuming these wells are somewhat spread apart. So can you just talk about the distance between the furthest wells?

Joe, I don't want to do your all's job for you. So I'll just say that you can go look at where our permits are and you'll see that we are trying to spread our drilling activity out. So we haven't gone out and drilled 3 wells right next to each other to then declare a victory. We have spread them across several counties. And remember also that this is not our first shale rodeo, and so we now have a pretty good model of when you work up the geological and petrophysical model today. We know from working in the Barnett, the Haynesville, the Fayetteville, the Marcellus, Eagle Ford what's likely to happen, but you got to wait till you drill your first wells. And then when your first wells come in and they impress you, then you have quite a bit of confidence about your overall model. So we try to do a good job of spreading our wells out. We'll continue to test both the core of the play as well as the edges. And we have drilled 15 wells, so we've got quite a bit of information. And I don't know if you thought about 3,200 feet of core, but -- 3/5 of a mile of rock that we've pulled, and these are our wells. This is proprietary core that we evaluated here at our proprietary rock technology center, Reservoir Technology Center rather. So we're quite confident and about what we know about the play and what's likely to happen from here based on what we've seen in all of the other plays today. Joseph Allman - JP Morgan Chase & Co: That's helpful. And then just back to the royalty trust question for the Granite Wash, one that you filed. I'm wondering why you did that. Was -- is there not a cheaper source of financing available to you?

I'll let Nick talk and then I think the way -- the ones that I've seen so far trade pretty attractive to be able to sell assets at basically PV7 including a lot of puds. So I don't know if that's the right number now. And, Nick, talk to us on that. Domenic Dell’Osso: Yes -- no, it's a very attractive form of asset monetization. Similar to VPP, there's a reversion of some tail interest here. There's some beneficial tax treatment associated with it. And at the end of the day, you get to monetize an asset for -- a very discreet asset. One of the things we like about VPP's royalty trust is that you're selling wellbores only and you're selling them within a defined depth. And one thing we've proven, as Aubrey talked about earlier today with Cleveland and Tonkawa and we talked about a lot with the washes in the past, is that these basins, where we have these large acreage positions, as we continue to evolve technology, we continue to find additional fantastic drilling opportunities. And so these are very discreet monetization vehicles, and they allow us to capture value for projected production at a very low discount rate and frankly beat out what you would get in the A&D market if you were to go sell this asset, where you'd have to give up all the upside drilling associated with it and not get a whole lot more value for it. Joseph Allman - JP Morgan Chase & Co: Yes, that's helpful. And then, if I can, just lastly. Aubrey, when you think about the various shale plays you're in, in terms of environmental risk, what are the biggest environmental risks that you -- that concern you?

Joe, you mean across all of our plays or place? Joseph Allman - JP Morgan Chase & Co: Really, across all the plays. I think some of the ones in the northeast get the most attention, but.

Yes, I mean, they're all well known. I mean, you have obviously, a lot of confusion about what we do on the hydraulic fracturing side. And if you had asked me a couple of years ago, would I ever be concerned about something we've done 15,000 times, somebody would object to it, and I'd have said, no way. But we've got some of those issues, particularly in the east, not really in the southwest, and we're dealing with them, I think, successfully. Luckily, the claims about hydraulic fracturing are so incredibly over-the-top that all you have to do is kind of bring people out and show them what you do and show them the aftermath. And then they kind of say, "What was I supposed to be really worried about here?" So we deal with that. Certainly, water consumption, water disposal are issues, but again, we continue to pursue solutions where we use less water, where we recycle more water. And again, 2 years ago, if you had asked me would we ever recycle water, I'd ask you, why would we ever need to do that. And today, in a place like Pennsylvania, we're obviously close to 100% water recycling. Beyond that, maybe, Steve can think of a few things, but -- air emissions. We've certainly had to tightened up on the air emissions side of things, and we're working with the industry and EPA to make sure that we are following best practices there. We're part of the something called the STAR Program, which is run by EPA, which is just targeting fugitive emissions, and of course, for us, that's cash into the air. And we want to stop fugitive emissions. So those are the primary things, I think, and little of hurricane water over South Texas would be a good thing and help the Eagle Ford out right now.

Next, we'll hear from Biju Perincheril of Jefferies. Biju Perincheril - Jefferies & Company, Inc.: I was hoping you could talk about your Bakken or Williston Basin activities a little bit. I saw some of your recent permitting, which, at least on some of the maps I have seen, is a little farther than most of the other activities and maybe outside of where -- the Bakken formation itself. Can you talk about the concept that you're targeting there?

Yes, sure. I think, Biju, we are on the southern side of the Williston Basin. We probably 10 or 15 years ago had assets in the central part of the basin and drilling for more conventional targets and, frankly, just missed the Bakken, and we regret that, of course. But Williston Basin is a big basin, and we -- I think we announced either one quarter -- I guess -- I think it was in the January conference call, that we were building a position there. At the time, we had around 100,000 acres. I think we're up to 320,000 or so now, and probably we'll push 400,000. As you correctly point out, we have permitted some wells. We haven't started to drill them yet. I think our first well spud's next week, Steve? And then I think our second one within a couple of weeks after that, and then start to add some rigs after that. So I'm really not in a position to say much more about what we're targeting, other than we -- to be late to a basin like we were late to the Williston, you need to have perhaps a different idea than what other folks have. And so we'll see if we have such an idea, and we'll see if it works. Then hopefully, we'll have some results for you when we talk next. Biju Perincheril - Jefferies & Company, Inc.: So now that you're up over 300,000, does it now rise a scale that, depending on success, maybe you'll look to bring it in a partner or?

Yes, I think that's sufficient size, Biju. I think we have 2 other areas that are more urgent for us to get partners in and more important for us to do, and that's in the Utica and in the Mississippian. And so I think if you just kind of look at how we got things scheduled out, the Utica will be what we work on through the rest of the year here and then Mississippian in the first part of 2012. And maybe a year from now or so, we'll be working on a Williston solution as well. Our acreage was acquired at a very attractive price up there. So we really don't have overwhelming need to derisk it like when we go into the Utica and spend a $1.5 billion to $2 billion. That's a significant risk for shareholders, and we need to derisk that. In a play like the Williston, we just haven't spent that much money yet.

And there are no further questions at this time. I'll turn the conference back to our presenters for any additional or closing comments.

Nothing further here. If you have additional questions, please direct them to John or to Jeff, and we appreciate your interest in our company. Thank you.

And that does conclude today's conference. Thank you all for your participation.