Good day, and welcome to the Chesapeake Energy 2010 Third Quarter Operational Update and Earnings Result Conference Call. [Operator Instructions] At this time, I would like to turn the conference over to Mr. Jeff Mobley. Please go ahead, sir.

Good morning, everyone, and thank you for joining our conference call this morning. With me today is Aubrey McClendon, our CEO; Steve Dixon, our COO; Nick Dell'Osso, our CFO; and John Kilgallon, our Manager for Investor Relations and Research. Our prepared comments this morning should be about 10 or 12 minutes and then we'll open it up for Q&A. Aubrey?

Good morning. Thank you, Jeff. We hope you had time to review yesterday's operational and financial release, and we're pleased with our results. On the operational side, our daily production for the second quarter was very strong at 3.0 Bcfe, up 23% year-over-year and 9% sequentially. An added highlight is our rapidly growing liquids production, which was up 50% year-over-year. We are currently producing more than 55,000 barrels of liquids per day and have our sights set on exceeding 150,000 barrels per day by year end 2012 and 250,000 barrels per day by year end 2015. We think that will make us a top five producer of liquids in the U.S. by the end of 2005. Next, I'd like to highlight our exceptionally low finding cost during the first nine months of the year. We added, on a gross basis, 4.0 Tcfe of proved reserves at a drilling and completion cost of only $0.97 per Mcfe. Basically, we are building a top 10 U.S. natural gas producer every year inside our company, an incredible achievement we believe. And not only are we good at finding gas cheaply at the $0.97 per Mcfe level, we are also good at selling it for much more. To date this year, we have received well north of $3 per Mcfe when we have sold properties through VPPs. It's always good to buy low and sell high, and that's what we try to do around here, whether it's leasehold or proved reserves. Our latest JV, the CNOOC deal in the Eagle Ford, is expected to close in the near future. And our data room is open for the Niobrara Shale JV, in which we own 800,000 net acres, evenly split between the Powder River and D-J Basins. We expect to also sell a 33% working…

Thanks, Aubrey. Good morning. I'm pleased to be joining you on the conference call as Chesapeake's new CFO. As Aubrey discussed and I'm sure you have seen in our earnings release, Q3 was another successful quarter for CHK. A couple of quick items I will point out in addition to Aubrey's comments are a continued decrease in LOE per Mcfe, which came in this quarter at $0.95 per Mcfe, as well as our finding cost at $0.97 per Mcfe. If you'd like to consider what it takes Chesapeake to find oil and gas on an organic basis, without the effect of our drilling carries, it comes to $1.16 per Mcfe. We achieved these low cost through four major advantages. First, we have a top one or two leasehold position in every important unconventional play in the U.S. Second, we have drilled more horizontal wells than anyone else in the world. Third, we are vertically integrated through most of our key service needs. And fourth, we have a size and scale that lends itself to great efficiency in our drilling and production processes. The third quarter was also a very productive period for us on the financing front as we completed the balance sheet restructuring made possible by our preferred equity offering, which closed in June of this year. The net effect of this series of transactions is to have added $2.6 billion of equity to our balance sheet, have reduced long-term debt by $1.4 billion and retired or redeemed all bonds that were issued under our older, more restrictive form of indenture. Just to remind you, this was the first step in our ongoing multi-year strategy of balance sheet improvement. Additionally, I'd like to point out the closing of our eight volumetric production payment transaction on September 30 for $1.15…

[Operator Instructions] Your first question comes from David Tameron with Wells Fargo.

Aubrey, you mentioned the 100,000 acres in the Bakken, is that -- I'll just get to it. There's speculation that you guys bought Anschutz's property up in the Bakken. Can you tell us where you got that acreage or if you didn't?

I cannot tell you where we got it. I mean, I can, but I won't. But we did not get it from Anschutz. We are not the buyer of the Anschutz Rockies package.

Second question. If I think about your position in the D-J and the Powder, can you give me a split of the federal acreage versus like state acreage in those two areas?

I don't think I got that kind of detail with me right now, but I would say it's probably less than a third, probably more than a quarter. But that's a little bit of a guess, Dave.

And where I was going with it is I hear there's been an issue with chargeability from time to time with different option of terms.

Yes. We're mindful of chargeability issues and know where we are. And keep in mind also that you can relieve yourself of chargeability issues when you form federal units. And our goal across the, especially the Powder River, is to get virtually all of our leasehold there in a federal unit, which also helps us quite in terms of getting things HBP much more easily than in a traditional play.

The 2012 production uptick in oil, I assume -- you talked about CNOOC and then acceleration there. And then I assume Bakken's a part of that as well. Is that the right way to look at it?

Actually, we haven't modeled any production from -- and you said that we would refer to it as really the whole Williston Basin, but we are not modeling any production there. The 2012 uptick is simply now greater confidence in what we're going to see out of the Eagle Ford that we have a partner. I think we'll be able to obtain a partner in the Niobrara, which will help us uptick activity there. So I think those two issues are the ones that gave us the confidence that our 2012 production would be considerably higher than what we had previously modeled for.

Your next question comes from Jeff Robertson with Barclays Capital.

Aubrey, on the acreage you all acquired in the Appalachian Basin, can you talk a little bit about the 25% you want to sell and where that's located? And also how does the rest of it fit into the Appalachian Basin that you all had talked about finding a partner for?

Yes. I would just say, Jeff, that approximately 25% of what we're buying is not a great fit for us and will be a better fit for probably a handful of other companies in which the acreage is embedded with. And with regard to the remaining acreage, it's a really good fit for what we have. And we believe that we'll be able to probably do a JV on that idea some time in the first half of 2011.

That transaction would be in addition to the one you all have outlined before about finding a partner for Chesapeake Appalachia?

Well, we already have a partner, of course, in our Marcellus play. If you're referring to the idea that we've talked about in the past about bringing in a equity partner in our Marcellus play, we are still pursuing that. Statoil has expressed some interest in a little more ownership in our asset as well, but that's really a optional part of our plan. I have no idea either of those conversations will result in a favorable outcome. So this would be a different idea than either of those.

Your next question comes from Scott Hanold with RBC.

I guess I'll press to Williston a little bit here. So you all didn't say what you paid for the 100,000 acres. I know you disclosed the price in the Anschutz stuff. Can you kind of give us color on that? And maybe some indication, are you looking at Montana, North Dakota or both?

Scott, it's still pretty early. And that's a basin that, historically, we've not done well in. We've made a run on it Lyco in 2005 and Headington in 2008. We wanted -- both of those deals would've given us a really strong position in the Williston today, and we failed in both those opportunities. So we've been poking around. And we saw something that we liked, and we acquired it. It does not have any production on it. It's just acreage, and it's an idea that we have that it's a little early to talk about in any more detail. We suspect that it probably doesn't get to a size of needing a joint venture partner, but we'll see. But I can confirm it's in the Williston Basin, and it will be an oil play for us.

Is there a lot of industry activity around you? And obviously, it was almost 160 rigs in the basin. It's hard to believe there's a lot of acreage of oil production on that.

Yes, I mean, we didn't buy -- we don't buy fringe stuff. It's not really our style. We try to buy core acreage. But occasionally, we have a different idea than some folks about how the world works. And so we'll see how this plays out.

When do you start getting active? When could we -- when will the deal probably -- has the deal closed? And when could you put some rigs out there?

I don't believe it's closed yet. And we'll probably wait until winter's over and hit it probably in the spring of 2011.

On the Granite Wash, there's been some indication that from, I guess, other people in the industry that they've seen some communication on some of the Granite Wash wells. Has that been something that you've seen as well?

Scott, this is Steve. Yes, we've seen some frac interference when you're pumping your product. But I don't think we've seen much on negative depletion from offset wells, though we haven't downspaced that much either.

And we've done some full-well deals in the colony.

Yes, 160 spacing and...

And we're trying to get an idea of what recovery diminution is going to be on Anschutz so...

I think those are just mostly frac hits, Scott.

Your next question comes from Brian Singer with Goldman Sachs.

Scott, can you talk to what the drivers are of the widening of guidance for differentials for both liquids and natural gas? Is that just the market? Is it the increased gathering cost or transportation cost?

Well, I think there's probably two things, Scott (sic) [Brian], and I'll see if Nick or Jeff wants to jump in with any further information. But one, of course, is liquids, natural gas liquids are in the kind of 50% of crude range and as crude has gone on a little run. In the third quarter, NGLs didn't really keep up, so I think that's one issue. And then on the gas side, as gas prices are lower, your differentials widen on a percentage basis, because you do -- most of your transportation costs are fixed and when you have a variable cost change than your percentage. So that basically -- you may have noticed that we reduced our expected gas price for -- well, we're running at 2011 and 2012, $4.50 and $5.50 on expected gas prices. And when we just studied the historical differentials, we were seeing when gas prices were at those levels, we felt like we were a little on the light side and decided to step it up a little bit.

And then I guess continuing on the Williston Basin path here, ultimately, where do you see yourself positioned in the plays? Is it just a onetime acquisition of a small acreage position? Or do you see this as something that you could spend more capital on and meaningfully more capital on but from a drilling and acreage acquisition perspective?

First of all, I'm encouraged that you referred to 100,000 acres as small. That means you got your mind right about how we think about things around here. But we don't know where this leads, and I don't know the size. But I have expressed confidence in the past that in certain plays, we'd get to 500,000 or 1 million acres, and that would be big enough to bring in a JV partner. As I mentioned in previous answer to your question, I suspect this does not reach JV size.

And then, I guess, is it fair to say then that you're testing different plays from the Sanish and Three Forks that others are testing, or that concept is different? Can you add a little bit more color to maybe what you're doing differently than others?

I can't really offer much color, just sometimes, we have different ideas about things. And most of the times, they work. Sometimes, they don't. So we'll see how this one works out.

Your next question comes from Dave Kistler with Simmons & Company. David Kistler - Simmons & Company International: Real quickly, with the amount of drilling that you guys do on the natural gas side, can you talk a little bit about the inventory we're hearing about these drilled uncompleted wells maybe both from the perspective of Chesapeake and the perspective of the non-operable you have in a lot of wells that are drilled with the likes of a few of the service companies throwing out 2,500 and above? Just be curious to get your perspective.

With 140 rigs running and we'll drill 2,500, 3,000 wells this year. We're always going to have a backlog. I've heard commentary from some other companies that they are having a hard time getting wells frac-ed or whatever their excuse might be at the time. We just view that as a normal part of our business. It's one of the reasons why we're vertically integrated. We've got the fifth largest drilling contracting company in America. We're the second largest compression company in America. We have our own trucking company. We have a lot of specialized-service companies that do things for us. We own 26% of Frac Tech. And given our scale, we think we're generally able to step to the front of the line with most service companies, and we're their biggest North American customer, generally, by far. We think we're doing fine. We'll always have a backlog, but I don't view that this is much different than it's been over the last couple of years, where backlogs have ebbed and flowed. David Kistler - Simmons & Company International: So not necessarily just specific to Chesapeake, but you think the numbers that the service companies are throwing out might be a tad overstated, or as you have highlighted, maybe just excuses from other folks.

Well, we don't have a way to count it. And if the service companies say that's the number, I'm not going to dispute their count. It's not something we track around here. David Kistler - Simmons & Company International: And then just looking at your hedging portfolio and as you start entering into more WTI hedges, as you're growing your liquids portion, will you be hedging more WTI than potentially you produce, using some of that as a dirty hedge potentially for NGLs? Or how should we think about your philosophy on that?

Well, I think you -- first of all, we think about our philosophy as being generally optimistic about oil prices going forward. So I think we'll try to plan our hedging with that in mind also realizing that whatever we're hedging today with regard to out-year oil will be a relatively small percentage of what we expect our oil production to be by that time frame. With regard to dirty hedges, we're not familiar with the term. But if you define it, cover it in detail. . . David Kistler - Simmons & Company International: Well, just in terms of having a very thin NGL hedging market, oftentimes people have used WTI hedges as a proxy for NGL hedges.

Yes. What we're concerned about these days are natural gas prices, and that's what we spend most of our time focused on, trying to make sure we've got those shored up. Oil, of course, is relatively easy to hedge, and geos are relatively different or difficult, rather. So we'll stay focused on gas and occasionally do some oil hedging and realize a course that our expanding production base in the out-years gives us a lot of flexibility there that maybe other companies without such rapidly growing oil base don't have when it comes to hedging.

Your next question comes from Biju Perincheril with Jefferies & Company. Biju Perincheril - Jefferies & Company, Inc.: Aubrey, you talked about two possible joint venture opportunities: one in Appalachia, combining the Anschutz acreage with some of yours; and second, you said in a new liquids play. Are we talking about one and the same?

Yes, let me clarify that, Biju. When I talked about two JVs in '11, I'm talking about the Niobrara, which we are marketing today, but it won't close until 2011 in all likelihood and then a new play idea that we have. So those would be the two that we're talking about. Biju Perincheril - Jefferies & Company, Inc.: So those two are separate from the one in Appalachia that will be combining some of your acreage with the newly acquired acreage from Anschutz?

No, that's a conclusion you're drawing that I wouldn't draw. Biju Perincheril - Jefferies & Company, Inc.: The acreage that you bought from Anschutz, can you talk about the targets there? Is it at Marcellus? Or is it more Utica? And then the Utica sale that you guys are targeting, can you talk about the liquids potential for that?

Biju, I appreciate the question and obviously, the interest, but it's not really something that we're at liberty to talk much about today, with the highly competitive process and the pleas before we've ended up. But that's really a 2011 project, and I'll have to politely ask to be able to beg off that question until then.

We'll go next to Dan McSpirit with BMO Capital Markets.

You state that 45 of the 140 operated rigs running today are drilling liquids-rich plays. What does that ratio look like at year end and then further out, year end 2011 and year end 2012?

We have that information, Dan, let's see if we can produce it.

Page 17, the slide on the left.

If you're on our website or go to it at some point, note Slide 17, which is a projected CapEx budget over the next, well, I guess, three years going out to 2012. And in 2010, we'll spend 31% of our money on liquids CapEx, 2011 that should be 45%. And by 2012, we'll be spending almost 2/3 of our capital on liquids plays. So I suspect that people really don't appreciate that impact when we start replacing $3 and $4 Mcf with $13 and $14 Mcf. On a similar cost basis, you really see a huge move in per-unit value creation, and that will drive some numbers in 2012 and beyond and I think most people are not currently not modeling for. So that will remain a focus of the company. Of course, if gas prices, for some reason, were to come back at higher levels, we can always pick our gas drilling back up. But at this point, our goal is to go from 90% natural gas CapEx in 2009 to go to 35% gas CapEx in 2012. A few companies are really going to be able to make that kind of a shift, particularly of our size.

Dan, just to clarify, you mentioned 145 rigs. And you said drilling liquids, we have 145 total rigs running today, about 140 to 145.

Dan, did you say 45 rigs drilling liquids or 145?

No, 45 for the 140, correct?

Yes.

That's right.

And my question was what does that ratio look like at year end 2011 and...

Then just -- we gave it to you in dollars, so just flip it. If we're running 150 rigs in 2012, which I think we'll be running more, you will see -- but actually, as I look at it, on Slide 17, we also have a graph that shows exactly what our rig count will do overall, as well as what the components of it will be. So you might want to flip to Page 17.

And then second question here, the 150,000 barrels a day in liquids production expected to come by year end 2012, how much of that is oil versus NGLs?

I think we're still modeling about 60% oil or so. We'd like it to be 65% oil. But right now, we're at 60-40.

And then lastly here, in your discussions with the ratings agencies, how do they view of the use of JVs and VPPs in the context of achieving investment-grade status, assuming it's at all relevant to the conversation?

I'll let Nick answer. They see VPPs largely as debt, which is kind of nutty. But I'm sure Nick will give you a good example of why that is beyond nutty, but go ahead.

Yes. They do see VPPs as debt. JVs, they see as having a partner. They have a lot of questions about what those JVs mean, but they don't necessarily view those any differently than the rest of you guys would. VPPs, we've had lengthy discussions with the agencies on this point, and they continue to view them as debt. Again, we sell the reserve's transfer title to them. We take the reserves off our books. The only obligation we have ongoing is to be a prudent operator of the property, and they are a partner in the property like anyone else is. We do have the obligation, as they are now a royalty owner in the property, to pay their operating cost. So that's no different, really, than any other royalty owner. And if you think about the way that those guys are going to look at it as debt, one of the things that we always scratched our head about is if we do a VPP in a gas price environment of 2011, where the strip is going to average something in the, let's call it, mid-fives to low fives versus having done a BPP in 2007, 2008, where the strip was much higher than that. It's actually going to result in more debt in 2008 than in 2011 for the same property just because the price was higher. And it's really just an obligation in volumes, and it can't be measured as debt.

We said in other way, this last deal that we did on the Barnett was -- Nick, how many Bcf did we sell?

390 Bcf.

So filled about 400 Bcf, that we sold for $1.15 billion. If we had sold it for $1, they would consider that a better deal than if we had sold it for $4 billion. They would consider $4 billion a bad deal, because it's more money and therefore, more debt. Of course, they ignore the cash that you get from selling it. So it's one of the insanities of dealing with rating agencies, and there's probably no greater, better definition of it than that one.

Your next question is from Joe Allman with JPMorgan. Joseph Allman - JP Morgan Chase & Co: Aubrey, on the same topic, do you still plan to reduce debt and become investment grade? Or have other priorities risen to the top?

That's still the plan, Joe. When we look out by year end 2012, we think we'll be a 22 to 24 Tcfe company. That's almost 4 billion barrels of oil. By that time, we shouldn't have more than $10 billion of debt. So is $0.40 in Mcfe or $2.50 per barrel debt, are those investment-grade stats by year end 2012? Absolutely. Looking at our book cap today, I guess, guys what's our debt? 42%. Our debt's 42%. If you just look at the earnings capability of the company over the next few years, we will be earning close to $2 billion a year. You'll see that percentage continue to drop. So we absolutely think we're there. And our goal is to drop absolute levels of debt, which we've stated as our goal. But certainly, on a relative basis, as we increase our reserves by 2 1/2, 3, 3 1/2 Bcf per year or Tcf per year, rather, you will see that drop very dramatically on a relative basis for sure. Joseph Allman - JP Morgan Chase & Co: And to achieve that goal, as you buy more assets and acreage, does it get more difficult to -- I mean, I know you can certainly flip acreage. But the fact that you sold some of your producing assets, like the Barnett Shale and others, does it get more difficult to make sales going forward, especially core kind of producing assets that are more valuable?

No, because our machine converts so many buds and probables and possibles in the PDPs per year. I mean, our out-year projections already anticipate that we'll be selling $1 billion a year of VPPs. And we still talk about the growth that we're delivering as 18% in '11, 18% in '12. Those are after projected asset sales. So you're seeing a lot of companies starting to come up with -- well, we can't make our growth targets, because we got to go sell assets, and when you include the asset sale, there is no growth. And what we've been able to show is that we think asset sales are important and vital and an everyday part of what we do to fund the business and also to monetize older assets. And we've chosen to do so through VPPs. The rating agencies don't care for them, but that's not what has to be the ultimate driver. The ultimate driver has to be what's the best way to create value and through asset monetizations. And we think the benefits, which Nick talked about, of keeping the upside, keeping the tail and not paying taxes on them are pretty important issues to keep in mind. So we want you to remember that as we talk about out-year growth of 18%, that is after asset sales that take care of any funding gap that we might have. So converting leasehold into PDP is what the machine does around here. We've got the capability of doing that of up to 4 Tcf per year, and we'll continue to do that year after year. Joseph Allman - JP Morgan Chase & Co: And then in terms of the Marcellus Shale, I guess it's interesting that you're going to take a quarter of that acreage that you bought and it sounds as if you're going to combine it with the acreage or assets in another play and do a JV there. And so that's an interesting idea. What would be the benefits of that to you?

Joe, you're talking about the Anschutz acquisition, and I'm trying to be responsive to questions without being overly transparent with what our plans are. I'll just say that we acquired about 500,000 acres. About a quarter of it doesn't fit us very well. We're going to intend to sell that. I'm sure it'll be a 2011 transaction. And then we have an idea with what to do with the rest of it that will fit in pretty nicely with some other acreage we have. And we'll see where that takes us in 2011.

[Operator Instructions] Your next question will come from Steve Carla with Affiliated Research Group.

Is there anything material that's behind the minimal widening of the 2010 production guidance and the increase in 2012? Or is that just the sharper pencil? And separately, as we listen to you speak about liquids growth out through 2015, is there any implication about what you expect the gas access to be out that far?

You bet. Good question, Steve. Let's talk about, first of all, the change in production guidance. For 2010, we did previously have just a spot number for our oil production at 19 million barrels. We went ahead and added a range there of 18 million to 19 million, and that really reflects some ethane rejection that occurred that took our NGL barrels down. We haven't properly accounted for that in our models and now are doing a better job of that. And then also some pickup delays related to some Midstream activity. So we'll see where we come out there, but we felt like it was prudent to put a range in rather than just a spot number of 19 million barrels. And then in 2012, I think Nick mentioned this, but just greater clarity on some of our plays, particularly the Eagle Ford, and I think I might have mentioned the Niobrara as well. So that's been able to give us that clarity. What's that mean with regard to our thoughts about gas prices? I mean, I think we just have to live with today's reality, which is the projection for gas prices going forward and comparing that to the curve would make anybody with a choice of drilling an oil well or drilling a gas well be inclined to drill an oil well. And so that's what we're doing. And then three years ago or so, we were a single-product company focused only on natural gas. We didn't really think we could find oil in any meaningful quantities. We didn't want to go out and buy it. But all that's changed in the last three years, and we have figured out a way to find liquids. And so we're going to back down our gas drilling over time. And again, as I mentioned before, we'll be down to a third of our drilling in 2012 will be gas compared to 90% last year. If gas prices rebound and the country says we need more gas, we can absolutely respond to that very quickly. But right now, the focus is on oil, because it's 3x or 4x more profitable to look for it than it is natural gas.

And obviously, you can lock in some of that differential right now.

Well, yes, sure can. We can lock it in. If you're talking about the differential between gas and oil, we can lock it in in terms hedging, absolutely.

With no further questions in the queue at the time, I would like to turn the conference back over to Aubrey McClendon for any additional or closing comments.

So we appreciate your participation today. If you have further questions, route them to John, Jeff or Nick. Thank you.

And that does conclude today's conference. We thank you for your participation.