Jeffrey L. Mobley - Senior Vice President of Investor Relations & Research Aubrey K. McClendon - Co-Founder, Chairman, Chief Executive Officer and Chairman of Employee Compensation & Benefits Committee Domenic J. Dell’Osso - Chief Financial Officer and Executive Vice President

Brian Singer - Goldman Sachs Group Inc., Research Division Jeffrey W. Robertson - Barclays Capital, Research Division Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division Biju Z. Perincheril - Jefferies & Company, Inc., Research Division Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Joseph D. Allman - JP Morgan Chase & Co, Research Division Scott Hanold - RBC Capital Markets, LLC, Research Division Timothy Rezvan - Sterne Agee & Leach Inc., Research Division David W. Kistler - Simmons & Company International, Research Division Jason Gilbert - Goldman Sachs Group Inc., Research Division David R. Tameron - Wells Fargo Securities, LLC, Research Division David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Good day, and welcome to the Chesapeake Energy 2011 Third Quarter Earnings Results Conference Call. As a reminder, today's conference is being recorded. At this time, I'd like to turn the conference over to Mr. Jeff Mobley. Please go ahead, sir.

Good morning, and thank you for joining our conference call this morning. We understand there are a few other companies overlapping with us, and so we'll be short and to the point. Aubrey, Nick and myself are in Boston for an offering that is underway. Steven Dixon and John Kilgallon are in Oklahoma City. I'll turn the call over to Aubrey.

Thanks, Jeff. And I'll begin by clarifying that the offering is for Chesapeake royalty trust units, not anything else. All right. Good morning. We hope you had time to review yesterday's 2011 third quarter operational and financial release, as well as our Utica transactions release. Before I begin, I would like to respectfully request that you access our website at chk.com and pull up our slide show labeled November Presentation. It's under the Investors button, and then you can go to Presentations to find it. Later in my remarks, I'll ask you to look at some slides that I hope you will find useful. Thanks very much for doing this. As promised, our oil and natural gas liquids production continues on its strong and steady ascent, while we are delivering yet again another impressive JV transaction. If you are keeping track, this new JV would make our seventh. We started with the Haynesville in July of 2008, and in the 3 years since then, we have also brought in partners on the Fayetteville, Marcellus, Barnett, Eagle Ford, Niobrara and now into 1 phase of the Utica play. In these 7 JV areas, the company initially acquired approximately 5.1 million net leasehold acres at a cost of $11.1 billion. That's around $2,200 per net acre overall on average. We then sold 1.5 million of those acres for total consideration of $16.4 billion in cash and carries, meaning we recovered 150% of our total leasehold costs in all the plays combined, while leaving ourselves with 3.6 million net acres in 7 of the nation's very best plays, at a negative leasehold cost of $5.3 billion. That's about a negative $1,500 per net acre. I really don't think the magnitude or significance of what we have accomplished by owning 3.6 million net acres…

[Operator Instructions] We'll take our first question from David Heikkinen with Tudor, Pickering. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: First question on the Utica plans going to 30 rigs. Can you walk us through the rig split inside the joint venture and outside the joint venture?

David, we haven't done that, but basically, we plan for about roughly 75% to 80% of our drilling to be inside of the joint venture area. I can't be more specific than that because some of it is going to depend on the success we have in the oil phase of the reservoir, as well as what gas prices do and what incentives we have to develop the dry gas side of it. So the vast majority, though, will be in the middle of the play, the wet gas phase. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then what role do you expect your joint venture partner to play in the Midstream and marketing side on NGLs or...

They'll have the right to participate alongside us on a pro rata basis for any investments that we make in the Midstream area. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And thinking about additional joint ventures and plans from here forward, can you just update us on kind of overall number of joint ventures and areas you're working and your thoughts there?

Sure. Well, we've done 7 to date, and I mentioned that we had 3 more areas where we had significant-enough leasehold positions, and I guess significant-enough leasehold positions in areas where we haven't already accelerated our drilling and would like to have a partner. And I believe I identified those as the -- potentially the Mississippi Lime, the Williston Basin, and then also we have a third play where we're accumulating acreage. It's on the oil side. In places like the Permian and the Anadarko Basin for the Cleveland Tonkawa and Granite Wash plays, we really have already ramped our drilling up. We don't have a big leasehold cost position that needs to be de-risked. So those are areas where we wouldn't pursue a JV partner. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And maybe specifically on the oily part of the Utica and what you did in joint venture, would you expect to potentially move something forward there?

A good question, David. Sorry. I think on the dry gas phase, we want to get a number that's great for our shareholders. And in this gas price environment, that would be tough to do. So we'll wait until we get a rebound in gas prices. And as both Nick and I alluded to, we think that will start to begin to be visible in the next year or so. And so we can wait. A lot of our acreages are already HBP in the Utica. And then on the oil phase, we just need to focus our attention there. And when we feel like we've got a body of work that justifies going forward with a JV there, we will likely pursue something like that. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then just a question on Chesapeake Oilfield Services. As we started looking at margins relative to kind of oilfield services peers, they looked a little bit lower. Can you walk us through kind of how you set pricing? Is it lower because it's operated? I mean, just relative. And then an outlook as far as how pricing gets set if that business moves forward.

Sure, I'll let Nick address that for you. Domenic J. Dell’Osso: Sure. We set pricing based on what we pay others in each basin, and so it's a model that matches what we view as a market price. And we, of course, have great clarity into what we pay others because we plan to and typically don't use any more than 2/3 of our own services in any 1 basin. So we are a significant customer of many other services companies everywhere that we operate. As far as our margins being a bit weaker than others, it probably depends on who you're looking at, David. But we think that with the advent of PTL coming into our business in 2012, you will see the margins within COS increase pretty dramatically. We also have a new management team who's focused solely on this business and improving the overall margin and return to investors here. So I'd say you'll see that come up over time.

And remember, David, to date, a lot of our COS revenue comes from drilling and from trucking areas, which don't traditionally have the highest margins in the service industry.

We'll take our next question from Dave Kistler with Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Real quickly on Chesapeake Utica, L.L.C. Can those shares convert into Chesapeake shares at any time? And noticed that your diluted share count has gone down, so I'm guessing the answer is no.

That's correct. They are not convertible into big Chesapeake shares, and in fact, they're not even convertible into common of the sub. That's an important distinction between the EIG deal that we've done with PXP, where those preferred shares are convertible into common stock of the sub that owns those Gulf of Mexico assets. So basically, they have the right to convert into basic ownership of the asset. Here, there is no upside participation other than the small override that we granted. So it's a really important distinction. And I did see in at least 1 research note some analyst who was saying that we had issued 1.25 billion of preferred shares from Chesapeake. That is absolutely not true. We are selling from a subsidiary that -- and those shares have no ability to convert into common of the company or into the sub itself. David W. Kistler - Simmons & Company International, Research Division: I appreciate that clarification. So then as we think about this going forward, is it ultimately an obligation that you retire in cash? And we just think of it as kind of a 7% interest-bearing security that, for all intents and purposes, the only other additional stream for it is the 0.5% interest in your ultimate drilling plans or ultimate working interest in the Utica? Domenic J. Dell’Osso: The latter part of what you said, Dave, is spot on. It is perpetual preferred, which comes with a 7% dividend rate. And it does have the -- like you said, the royalty, very small royalty associated with it. Should we pay out cash flow from this entity, it will go towards retiring this security, but it is callable solely at our option when and how we choose to do so. The preferred can stay outstanding forever…

Yes. Sure, Dave. This is Aubrey. Let me correct, you said 5,000 acres. David W. Kistler - Simmons & Company International, Research Division: Sorry, 500,000. Sorry.

We don't have 500,000 in hand. We're headed that way. We have multiple hundreds of thousands, but that's kind of our goal. The acreage is really inexpensive. So it's not part of -- a significant part of our leasehold spend for the quarter or for the year. And I really don't want to say more than that. We'll be drilling in this area in the early part of 2012, and we'll see how we go. But I do confirm that it is a oil- and liquids-based play in the U.S.

We'll go next to Jeff Robertson with Barclays Capital.

Aubrey, in the Utica, can you talk a little bit about the capital profile over the next several years for the assets that are covered by the joint venture?

Jeff, if you're referring to what's our projected CapEx per year -- is that what you're looking for?

Well, yes. I guess you talk about it in the release on the joint ventures that the proceeds and the funding you have in place will cover your development capital, along with cash flow, for the next several years. So I'm just curious if you can lay out how you think this part of the asset will evolve in terms of capital spending and activity over the next several years. And then also, I guess secondly to that is, in your projections for liquids volumes going out through 2015, are you able to talk yet about how much of that is expected to be from the Utica play?

No. I mean, I could, but I'm not. We've still got a reasonably significant risk factor on Utica volumes going forward. So they do not -- I think they'll have a heavier weight as we go forward. But you could see clearly that we've been de-risking some plays as we moved along. As this -- in this release, we talk about moving forward from exit rates in 2013 and 2015, 2012, for that matter, from exit rates to averages for the year. So clearly, we're feeling more comfortable about some plays all across the board. With regard to the first part of your question, remember that although the EIG and unnamed company JV will -- along with cash flow, will handle our expenses in this area, the CapEx will still get reported that is not subject to the JV. So remember, the EIG deal gives us money today for spending that we will do over the years in the future. So even though we won't -- even though we are fully funding what we will do in the years ahead, we'll still report that CapEx. And in terms of giving you specific dollar amounts, we're just not ready to do that yet. But we have given you our rig schedule. And so I think you can basically begin to see how you could make the correlation from rigs to CapEx.

And then is it safe to say, based on your comments about the risking in your liquids forecast, that as the Utica evolves over the next several years, the numbers you would have in your current liquids forecast are very heavily risked and therefore, they could go up?

I think that's something that we can all be hopeful about.

We'll go next to Brian Singer with Goldman Sachs.

Following up on Jeff's question, your Slide 18 highlights, that sharp liquids -- sharp oil growth that you're planning beginning in 2012, and we noticed you did narrow your differential for liquids prices in your guidance. Was the narrowing of the differentials a function of assuming more oil within the mix or just stronger NTLs prices? And can you kind of talk about your outlook or maybe a little bit more color for your outlook for Utica oil growth in light of what appeared to -- from your initial wells to be being a bit more NGLs-rich relative to oil-rich?

Yes, Brian, this is Aubrey. So 2 things. We narrowed the differential in 2012 because we believe that, in 2012, there will be a solution to the cushing to Gulf Coast differential or call it Brent, call it LLS, whatever you want to call it. It's already come in from $28 a barrel at its high to $17 or $18 today. We believe there will be a physical solution to that emerge this year, and we'll be part of it, honestly. And then for 2013, we continue to believe that, that narrowing of that oil differential will occur. But also, by the end of 2013, we'll have seen at least 1, maybe 2 pipeline solutions that will take care of the ethane discount that exists at Conway today to Bellevue. You may be aware that Bellevue ethane prices are almost 3x what they are at Conway in Kansas, where a lot of our production does ultimately get priced and/or processed. So those are the reasons why we are planning for increased or shrinking differentials, not really a big shift in our oil versus NGL percentages. In fact, you can look at that slide on, I think Slide 18, and see that, over time, I think our oil portion of our liquids is about 60% and NGL is about 40%.

And I guess when you think about drilling in the Utica in the AMI and the JV, should we expect similar type NGL -- should we expect the wells to predominantly be more NGLs? Or should we expect rising levels of oil and condensate?

Well, it depends where we drill. Obviously, to the extent we drill to the eastern side of our acreage, it'll be gasier. And to extent we drill to the western side, it'll be oilier. So at that point, I'm not willing to suggest anything other than that, given the competitive pressures in the field today from other companies trying to figure the play out.

And lastly, the language in your CapEx guidance seemed to change to proved well costs from drilling and completion costs previously. And you now seem to be breaking out well costs on unproved properties separately in your cash flow statement. Can you add more color on whether we should anticipate additional upstream CapEx going forward beyond the proved well costs in your guidance? Domenic J. Dell’Osso: Sure. Brian, I'll take that. No, is the short answer. Over the last quarter, we saw a big increase in the spending we've had on wells that are drilling, drilling and completed, variety of stages, but not yet having had a flow test and so, therefore, not yet proved reserves. And so in review of our data and reviewing our results with our auditors, we felt it was appropriate to spike this out separately. We've always forecasted our drilling and completion CapEx on a cash basis. So we think about what we're going to spend drilling wells for a year, inclusive of whether or not the well is immediately proved and put into our full-cost pool or not. Given the delay in some of the basins like the Marcellus that is so significant at times in bringing wells online, it has been appropriate to separate this out into its own category. So, no, we were -- with our CapEx guidance for next year, and there's a lot of things to consider as we roll through the next year. Remember, oilfield services costs have seen a lot of inflation throughout 2011. We think we're over the hump on that. A big part of that for us will be the bringing online of our Performance Technologies, L.L.C., which will be pumping our own frac jobs and providing a big cost savings to us. But there's certainly some things to watch there as we get into 2012. Also, I think -- we've gone out with 2013 now. We've had our '12 guidance out for a year. We do try and give you guys as much guidance into this as early as possible. And so I certainly hope that you all understand that we're looking pretty far into the future at times when we try to give you this guidance, and it is our best estimate at the time. But for now, our 2012 CapEx guidance stays where it is.

We do appreciate the early look on '13. Domenic J. Dell’Osso: And, again, so it stays where it is, inclusive of this separate category.

We'll take our next question from Scott Hanold with RBC Capital Markets.

Maybe staying on that same subject of CapEx and being a little bit more direct with some of the questions that have been asked out there. You've obviously been picking up some acreage in some plays and have done a very good job of monetizing some of these acquisitions or I'm sure some acreage purchases. But as you look forward into 2012, 2013, I mean, in terms of what you're planning to do, I mean, how big could that leasehold acquisition number be? I mean, we've seen your numbers on a quarterly basis get upwards of $1 billion plus. Is that -- should we think something consistent in '12?

Well, there's lots of ways to think about it, Scott. First of all, our budget this year will be, as promised, significantly less than last year's. So our spend has been going down. And probably next year, it will be less as well. But it's always a curious question to me. We just announced a deal where we're going to make 10:1 on our money in less than a year. And I'm a little surprised people don't ask us why we don't spend more on leasehold. It's clearly a huge area of profit for us, and it is unique in the industry. And it is one of the greatest mysteries of life for me, why people wouldn't encourage us to spend more in that area. The reality is, we're not going to, and we don't need to. But I would look at what we're doing this year as having been down about 1/3 from last year. And next year, I would expect it to be down at least another 1/3 and maybe 1/2. We're just simply, I think the industry, including us, is running out of places where you could go put together big leasehold positions. And we're not chasing anything in California, and we're not chasing the -- for example, the Tuscaloosa Marine Shale and some other things that would be pretty pricey to get involved in. So continue to ramp it down. I'll note that most of our leasehold spending this quarter was in the Utica, in the Anadarko, in the Permian and in the Marcellus. And so those areas continue to be strong, continue to attract strong amounts of capital from us. But going forward, we expect that, that will diminish over time.

Aubrey, do you believe that's true that the opportunities to pick up acreage are sort of dwindling now that a lot of these plays have been found? I mean that's kind of similar commentary we've heard in the past from you. But it seems like, every year, there's another new play that adds a lot of value. Is it different this time?

Well, when we said that we've thought that the big plays were over, I always said I thought there was one more, and that was the Utica. I knew about that one. These other little things that we're working on -- ask any company what's left in the Williston? What's left in the Anadarko? What's left in the Permian? What's left in the Marcellus? What's left in the Utica? There's really just not much out there, and that's why we were in a hurry. When you look back on this 5 years from now, 10 years from now, companies are going to say, "Wow, I wish I had negative $1,500 an acre in my cost pool for the great acreage like Chesapeake does," rather than having to pay $5,000, $10,000, $15,000, $20,000, 25,000 an acre for it in the future. So we love what we've been able to accomplish and know that it's created strong value for our shareholders, in fact, unique value. And so there's nothing other than to point to the numbers and show what other companies, much bigger than ours, for example, are willing to pay for assets that we own.

Okay, appreciate that. And one last question, on this new subsidiary you created with -- in this Utica, with this Utica acreage. With the perpetual preferred, what is your preference in terms of, would you rather see that thing be outstanding for more of a lengthy period of time? Or do you generally have a preference of sort of a plan to redeem that at some point? Domenic J. Dell’Osso: It'll probably be redeemed over time. That would be our plan. That's the way that we will bring cash out of this entity. But ultimately, that's a decision we'll get to make from a cost of capital and what our alternative places to put capital are. And so just like our decisions around retiring debt, we've gotten to a point where we thought it made sense on our balance sheet to monetize assets and put the proceeds towards retirement of debt as we've come to what we believe is the later stages of the acreage acquisition phenomenon in the U.S. We'll have an opportunity to do that with this security over time as well. But again, there's -- it's totally up to us from a timing perspective.

So it sounds like more in sort of tranches when you have capital to do so. Is that correct? Domenic J. Dell’Osso: It's a decision we'll make as we evaluate our free cash flow over time. But it's -- I mean, the best way to think about it is, it's a financial decision that we're free to make based on what our relative opportunities are.

We'll take our next question from David Tameron with Wells Fargo.

A couple of questions. Nick, can you give -- so what's your total CapEx budget for '12? You have the 6th -- whatever that range is on the E and D [ph] side. And then should we be adding in that additional service in -- or how should we think about your total CapEx budget for '12? Domenic J. Dell’Osso: Remember this, our Services business now has its own balance sheet. We've raised a significant amount of bonds for it, and we have a $500 million undrawn revolving credit facility that closed yesterday for that business. And we do plan to monetize equity in that business next year. So I would not include Services CapEx. We think that business is pretty well funded in and of itself. The Midstream CapEx, you can see from the guidance we've provided, does have what would be a funding gap, if you will. The EBITDA doesn't typically grow to a big size within that entity, because once an asset does generate sizable EBITDA there, we generally like to sell it to CHKM through a drop-down, which brings asset sale proceeds to offset our spending. And so there's some additional capital that will be funded by the parent company there. And then the only other thing we guide to, as you know, David, is just our drilling and completion capital, which is in our guidance this year for '12, and for '13 as well. So that's how we think about our CapEx.

Okay. And how do you guys think about -- all the questions out there this morning, there are twofold. I'm just going to throw them out there and let you guys address them. One, Aubrey, the people are saying this is an LOI, and therefore, there's a lot more wiggle room and blah, blah, blah. Can you address that? And then second, what do you guys think -- if you look at, again, the funding gap type number, what do you think that is for 2013?

Okay, 2 things. First of all, the LOI is an LOI. You're right about that. But I would look at our track record and say, how many times have we failed to convert an LOI into a closed deal? I'll tell you the answer to that, which is 0. And so, I mean, would people prefer that we have not done a deal at $15,000 and not have an LOI? I mean, it's a little crazy that somehow we would be better off to not have an LOI at $15,000 an acre. So we'll -- we'll do what we always do, which is we get our deals done and we bring them to the finish line. And we'll do it here. We've always done it in the past. With regard to whatever funding gap, I mean, it's just a real easy answer. We will come up with all the cash that we need to run our business and to improve our balance sheet and hit our year-end 2012 target like we've always said we will. And it's not that hard, and there's lots of ways to do it. And it's a little bit, to me, like asking an investor who has no current salary, but he makes $1 million a year from capital gains on his stocks, asking him how he's going to fund his gap because he's got no salary. Well, he makes $1 million a year when he sells assets. And we create a lot of value, along with our operating cash flow. We have a large -- the company has the equivalent of a large salary from its operating cash flow, and we supplement that with capital gains from assets. And at the same time, we still are able to add 1.3 billion barrels of oil equivalent and proved reserves or 4 Tcf a year, while still meeting all of our obligations and reducing our debt. So, I mean, I can't say it anymore simply than that. We've said we're going to do by year-end 2012, and we'll do it. And you can look at our debt at 9/30, yes, it's up, sure. We spend a lot of money on the Utica leasehold, but we turned around and sold part of it for a 10:1 profit that will close by the end of the quarter. So our 12/31 balance sheet will look a lot different from our 9/30 balance sheet.

We'll take our next question from Tim Rezvan with Sterne Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: I know you've touched on this a bit, but any more color you can provide on kind of how we're looking at this $2.3 billion in proceeds around year end and how that can address debt reduction in absolute format, would be appreciated. And any specific color you can kind of provide other than what's been mentioned so far?

Well, Tim, it's pretty, again, straightforward. The cash will come in, and it'll be applied against our revolving line of credit and our debt will go down at the end of the quarter. So we won't be buying any bonds in the quarter, but our debts will float up and down, and it just floated up last quarter because of the -- we didn't close a big deal in the third quarter, plus we spent some money on leasehold. The fourth quarter will be the reverse of that.

[Operator Instructions] We'll take our next question from Biju Perincheril with Jefferies. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Aubrey, a couple of questions. Just looking at your early completions in the Utica, it looks like you're using a much bigger frac [indiscernible] more sand and more water than [Technical Difficulty] I was asking about, looking at some of the early completions in the Utica, it looks like you are using a lot more sand and water than you typically in some of the other plays. And I was just wondering, does the reservoir need that? Or are you experimenting? And when you talk about the $5 million to $6 million well cost in development phase, does that anticipate you getting to a more normalized frac job, if you will?

Yes, I think that's a good way to think about it. And I think that's normalized on a lot of things. We won't be taking cores, we won't be doing a lot of other experimentation. So we're still tweaking our frac job. It's still a new play. And we'll be trying lots of different things in the future. So some jobs will use more sand, some jobs less, some jobs more liquids, some jobs less. So we're still tweaking. But certainly like what we've seen to date, and look forward, like we do in all plays, to get into kind of the manufacturing phase of it, which will be in full speed in 2012. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. So it's not a reflection that, that's what the reservoir requires.

No, I wouldn't look at it that way at all. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. And then in the Niobrara, the planned acreage sale there, can you tell us how the JV -- the drilling carries there is going to work? Do those carries get reduced by the acreage that you sell?

No, the carries do not get attached to specific acreage. They are just a corporate obligation on behalf of our partner and, of course, a corporate asset on our account. So if we sold all the acreage in a play, I guess we'd obviously have to talk about how to deal with it then. But in the Niobrara, we do have a lot of acreage, and some of it we're just simply not going to get to. And some of it is in other companies' strongholds and a relatively weak position from our perspective so we're doing some trimming on the northern side of some of our leasehold there. The carry will get still spent or still earned, I guess, is the way to think about it on our side, as we drill wells more in our core areas. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Got it. And then lastly, I noticed that you've been recently somewhat active in the Woodbine. First of call, can you say how that compares to your Eagle Ford position? And then second, is that an area where you can get much larger than what you are today?

I don't know. I don't think anybody knows how large we are there. But we're not all that large. I think we drilled 4 wells and like what we've done so far. But it's an area that's pretty tied up. And so we'll be able to piece together some other things. But that's not a multi hundred thousand acre play for us. And I think it would be difficult for anybody else just because there's a lot of overlapping existing production on it right now. But we do like what we've seen to date from our wells. And when I'm talking about the Woodbine, I'm talking about the East Texas Woodbine, which I presume you're talking about as well. Or with some companies, I guess they're calling it Eaglebine.

We'll take our next question from Neal Dingmann with SunTrust.

Aubrey, couple of questions. First, Aubrey, a number of your peers have announced on conference calls about problems with gathering systems and takeaways. Just wondering your comment, as you look at the Utica and some of your other big plays, how you feel about that.

Well, there's a lot of aspects to our business that are challenging, and certainly building infrastructure in new play areas is one of those. But that's one of the advantages to the Chesapeake business model, in that we are vertically integrated all the way from our service operations up to our midstream operations. So there'll be some delays, but we've built those in. I mean, for example, in the Eagle Ford, we've only lately have had kind of a surge of production there because we were waiting on a lot of infrastructure. We just, I think, did a pretty good job of modeling for that. And you don't see us miss our numbers and then blame unforeseen circumstances. We plan for those and take it in stride. And, again, through our balanced and diversified asset base, we can have issues in one area and not affect our overall performance.

Okay. And then just lastly, just obviously, you got the nice price for the Utica. I just wonder how you view here, for the remainder of the year, what your thought is on the M&A market, not only in the East, but just kind of domestically overall.

Well, I think our transaction shows that there is still healthy demand by bigger companies for the assets that smaller companies have. I don't know how else to describe it. And every time everyone feels like that's over, there's an M&A transaction like a Statoil for Brigham or something like that. And we just -- we've got something that the world wants, which is the highest return on assets in the worldwide oil and gas business. And so, until returns in the rest of the world rise to meet those here -- and I don't think they will, and I don't think they can because of the basic terms of those deals. And when you apply the risk factors, both political and geological and timing risks to all those, I think all roads lead back to the U.S. And that's why there's not a big oil company in the world that I'm aware of that's not seeking to increase the size of its commitment to North America. So I think that's a trend that will continue for years and years to come.

We'll go next to Jason Gilbert with Goldman Sachs.

Aubrey, I hear what you're saying about the rationale for pursuing leasehold acquisitions even at the cost of higher leverage in the short term. I was just wondering, overall, if you view IG ratings as nice to have for a company of your size and scale or as a must-have, and what's the urgency there?

Well, I think we've been on record that it's something that we think is an inevitable outcome of our business strategy. It's not so much that we have to have it by a certain time. Obviously, we have access to any capital markets we want. And the company's debt trades is a strong crossover credit, I think. So -- but at the same time, we think we have investment grade assets, we think we've got investment grade strategy. I honestly think if people were to allocate part of our debt to our Midstream and our Service businesses, I mean, on Page 27 or 30, I can't think right now, in our slideshow, we talk about $17 billion of non-E&P assets. Think about our Midstream as part of that and our Service assets as part of that. If we were to be able to allocate 30% or 40% of the capital structure of those companies with debt that is today burdened against our E&P assets, you'd see that we have an investment grade balance sheet already on our E&P assets. So that's why we're eager to get Chesapeake Oilfield Services public and continue to grow our Midstream business, so that we can reflect the fact that a lot of the company's leverage that rating agencies put all against our oil and gas reserves are, in fact, more properly -- should be more properly distributed across the company's asset base. Domenic J. Dell’Osso: I'll add to that, that, again, in my comments, I pointed out that even without doing that allocation, our total debt at the end of the quarter was -- pro forma for the transactions we've been working on this week is $0.54 per Mcfe. So even without that allocation, that's a pretty attractive number and it's really beginning to look like an investment grade metric.

Okay. Yes, I hear you. And a second unrelated question, just on back to the land-grab question. I was wondering, what are you seeing in terms of international shale opportunities, potential for an international strategy and timing and scale of what that might look like?

We've consistently, over the last couple of years, said we have no interest in international shale assets or any kind of assets. And that includes Canada, and that includes Mexico. And nothing's changed. We are focused on the good old U.S.A., and that's where we will always remain.

We'll take our next question from Bob Brackett with Bernstein Research. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: As you guys transition from gas, when do you think you'll start splitting NGLs and black oil in your financial reportings to help us with our homework?

Bob, I'm not aware exactly when we'll cross that line. We need to do it. I suppose it'll be in 2012. But Jeff or Nick, I don't know if you-all have a different answer to that. Domenic J. Dell’Osso: We don't have a different answer to that yet. But we're looking at it, Bob, and it'll certain happen at some point.

We generally say we're around 60% oil -- 55% to 60% oil, and the rest is natural gas liquids. So I can save you some homework, if you'd like, by using those numbers.

We'll take our next question from Joe Allman with JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: So in terms of CapEx for 2011, it appears that you didn't change your drilling and completion CapEx from the $6 billion to $6.5 billion. But year-to-date, I think you spend about $5.2 billion. That implies in the fourth quarter, you're going to spend $0.8 billion to $1.3 billion. So is that reasonable? Domenic J. Dell’Osso: That's where we are today. Yes, that's where we are today, inclusive of the $875 million that's in there for the...

Yes, you quote the 5 point -- Domenic J. Dell’Osso: Our range for the year is $6 billion to $6.5 billion, and that range is still relevant. Joseph D. Allman - JP Morgan Chase & Co, Research Division: I think in the third quarter, you spent about $1.95 billion, and in the prior 2 quarters, about $1.6 billion, $1.7 billion. So what's going to bring the number down so much in the fourth quarter? Domenic J. Dell’Osso: Well, again, the $5.3 billion that you talk about year-to-date includes the $875 million of the work in process. And so we do think that was a bit of an anomalous quarter, we think, on a go-forward basis. And so we had a lot of stuff to do in the third quarter. And we think just as the normal flow of business ebbs and flows, we're still looking at $6 billion to $6.5 billion for the end of the year, total.

And, Joe, that's what's comparable to the number on Page 12, the $4.5 billion number. So you need to be comparing apples and apples. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. And then -- okay. So you changed the name of that category. So what's -- again, you might have covered this in the beginning, but I missed it. what's the purpose in changing the name of the category from drilling and completion costs, which seems to be more comprehensive, to proved well costs? Domenic J. Dell’Osso: Well, the purpose of changing the name is just to try and be accurate with the way that we're having to report this now. I mean, it has gotten to be a big number. We can't and shouldn't continue to put a number that large in our proved reserve cost because it does represent costs associated with assets that are not yet proved. And so it skews inappropriately our F&D costs if we were to do it, and it would skew inappropriately going forward our depletion costs. And so it needs to be broken out separately. And we're trying to be clear about how we're spending money. There's an element of money that we spend every quarter on wells that take a period of time to come online. And again, we've had some very large infrastructure projects in the industry that you read about every day that are being worked on and that are the result of us having spent, in this past quarter, $875 million on assets that have yet to be proven. And so it's only appropriate to leave those costs out of our full-cost pool for the moment. Those costs will flow into our full-cost pool as these assets are -- as these wells are flow-tested and the reserves are proven. That number will move up into proved drilling and completion costs. So that $875 million will flow up into that line at some point in the future. And it's reasonable to think that it'll be within a year or so.

Joe, one other way to think about it, our reported finding costs on Page 12 were $1.8 per Mcfe. And even if you were to throw the work-in-process costs into that equation and don't give us any credit for the Tcf associated there, our costs are $1.29 per Mcfe. So, again, I think the emphasis is misplaced on what we're spending, not on what we're finding. And if you can find reserves at $1.08 or $1.29, our view is we ought to be doing as much of it as we can. That's how we create value, and that's how we're going to continue to do it. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. So let me clarify. So this $6 billion to $6.5 billion, are you saying that this is the money you're spending on PUDs, drilling PUDs? Domenic J. Dell’Osso: No. Not necessarily, no. The money, that could be -- those could be -- in fact, those are not PUDs. If they were PUDs, they would be in the dollars spent on proved reserves. So generally, we don't often drill -- well, I shouldn't say often. We do, of course, drill PUDs. But a significant portion of the wells that we drill are on non-proven locations because we're out trying to hold leasehold in early stages in our plays. And so these are wells that exist in a probable or possible category on an internal reserve report. Once they're drilled, they become proved developed producing wells, and then an offset to them is called the PUD. And we typically won't come back and drill that PUD if it's already being held by leasehold for some period of time. Of course, there's a 5-year rule on PUDs. And so, generally, these are dollars that are…

Joe, we are in Boston, and we've got to run and see some investors on this Chesapeake royalty trust deal. So I'm sorry to ask you to take that offline. But... Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. I've just got a couple more. So just in terms of long-term debt, it was up by $1.7 billion from the second quarter to the third quarter. Was that pretty much all a draw on the revolver? And what is the status of the revolver now?

Joe, it was all from the revolver, and you'll see it kind of reverse itself in the fourth quarter as we bring these deals to fruition and close them to cash. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Got you. Okay. And just a couple of quick ones. So when you guys put out that Utica well release with the first 4 wells, I think you put out peak rates, which my interpretation is from talking to you guys, it means not 24-hour rates. So is that true? And what's the value of that data? And why would you put that out?

Joe, we think it's important data to put out. We don't say whether it's 24 hours or 6 hours or 2 hours or whatever. It's just industry-standard to use peak spot rates, and we've done that. And there's nothing unusual about it. We've drilled some really good wells and felt like the industry -- our investors, rather, ought to know about it. Of course, the industry jumped on it, and leasehold prices went up pretty dramatically. So just at this point, it doesn't make -- it's not in our best interest, our shareholders' best interest to throw more gasoline on the fire. Other companies obviously are starting to talk about their wells. Rex did it. I'm sure Range will have some results before too long. So, again, very pleased, and, of course, our partner has had access to all of our drilling results as well. So obviously, their decision was based on results that they've seen on a level of detail that you or anybody else hasn't been able to see. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Got you. And then just a last quick one. So the fact that you closed out your hedges, is that reflective of just a need for cash in the near term?

Joe, I think we made it pretty clear that we feel like the bottoms are in, in the natural gas markets. We also took advantage of some days when there was worldwide financial chaos. And oil price is way down, and gas price is way down that we didn't think were justified by supply-demand fundamentals. So we went ahead and cashed out a good bit of them and then will look to the opportunity to put them back on. We've done this on several occasions in the last 5 years and, typically, we've been pretty successful at being able to put it back on. Maybe you noticed, we've made $8.1 billion on our hedges since 2006. So we don't always get it right, but we've got a pretty good track record there. Okay. I think -- I'm told that, that was the last question. We appreciate your interest. And, again, we'll be a little hard to get ahold of today as we're in Boston, but we'll do our best to get back to you with any additional questions that you have. Thanks very much.

Again, ladies and gentlemen, thank you for your participation. This will conclude today's conference call.