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

Scott Hanold - RBC Capital Markets, LLC, Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division H. Monroe Helm - Barrow, Hanley, Mewhinney & Strauss, Inc. Jeffrey W. Robertson - Barclays Capital, Research Division David W. Kistler - Simmons & Company International, Research Division David Wheeler Brian Singer - Goldman Sachs Group Inc., Research Division Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Good day, and welcome to the Chesapeake Energy 2012 First Quarter Earnings Results Conference Call. Today's conference 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 conference call today. I'd like to begin by introducing the members of the management team that are on the call today: Aubrey McClendon, our Chairman and CEO; Steve Dixon, our Chief Operating Officer; Nick Dell'Osso, our Chief Financial Officer; and from the Investor Relations Research team, John Kilgallon, joining us as the Senior Director. And we have a new person to the team I'd like to introduce to you, Gary Clark, who joined us from an investment firm in Tennessee. As usual, our call will last one hour. And so now I'll turn it over to Aubrey.

Thanks, Jeff. Good morning, and thank you for joining us today. Let me begin by acknowledging what everyone is clearly aware of. This has been a very challenging 2 weeks for all of our shareholders, bondholders and other stakeholders and also for our friends and employees. There's been enormous and unprecedented scrutiny of our company and of me, personally, and a great deal of misinformation has been published and uncertainty created. Your mother told you not to believe everything you read or hear for a good reason, and that's certainly been the case for the past 2 weeks. I am deeply sorry for all the distractions of the past 2 weeks. Through all of this, I've learned that there was a desire for more information regarding the FWP Program, which, as a reminder, has been in place since 1993, the date that of company's IPO, was approved by shareholders in 2005 and, I believe, has always aligned my interest with the company's interest and ensured that I had skin in the game, uniquely among other CEOs. Consequently, last Thursday, I disclosed a substantial amount of personal financial information regarding my FWPP interest. Furthermore, Chesapeake's preliminary proxy filed on April 20 also includes enhanced disclosures regarding the FWPP and discloses a multitude of positive governance changes that you should take the time to review. Hopefully, those measures, along with the decision to split the role of CEO and Chairman and to terminate the FWPP 18 months early adequately address the questions and misunderstandings that have been bouncing around in the marketplace and the media. I would like to reiterate that as part of the agreement, I will not receive any compensation or any benefit for the 18 months of the FWPP rights that I have agreed to forego. The board and…

Thanks, Nick. First quarter 2012 was another very successful quarter in our transformation from an exclusively natural gas-focused driller and producer a few years ago to a more balanced liquids-focused driller and operator today. I'm pleased to report overall production for the quarter grew to nearly 3.66 Bcf a day, which is now 19% from oil and natural gas liquids. That's up from a 13% liquids mix a year ago. This tremendous organic liquids growth is quite an amazing feat for a company of our size. Our liquids production has increased from 30,000 barrels per day back in fourth quarter of '09, up to 67,500 barrels per day in the first quarter of 2011 to now approximately 113,600 barrels a day in this quarter. That's an increase of 46,400 barrels per day or 69% in just one year. Taken alone, that 46,400 barrels per day of growth would place Chesapeake's last 12 months of production growth as the 21st largest producer of liquids in the U.S. These results are a positive reflection of the great liquids assets that we've built, our flexibility to move quickly as a result of our vertical integration and the operational skill of our organization. Anyone who thinks we're still just a natural gas story, please take another look. In fact, we are one of the world's best oil growth stories. Our frontend-loaded CapEx spending in the first quarter on drilling completion activity includes a sizable lag for much higher drilling activities in the fourth quarter. This gas drilling and completion activity that's accounted for over half of this year's expected activity in just one quarter, as well as we had a considerable amount of non-op participations. Even though gas rig activity reductions are well underway from 50 operated rigs at the beginning of 2012 to…

[Operator Instructions] We'll take our first question from Scott Hanold with RBC Capital Markets.

So obviously, there's a lot of focus on your free cash flow or the deficit that's out there over the next 18 months, excluding planned monetizations. But when you step back and look at it -- and obviously, there's a pretty call on you guys being successful due to the monetization. When you look at it, what is the minimum on the spending you all think you need to do in, like, 2012 to hold your acreage? I mean, could you cut a little bit more? Or are you basically running at bare minimum right now to hold your acreage?

From our perspective, it's not really the consideration that drives us. I mean, our goal is to get away from being this overweighted towards gas producer. And to do that, we have to spend money. The good news is we can spend more money than our cash flow quite significantly and yet still reduce our debt and not increase our share count. So to me, that should be the focus. Sure, we could cut our rig count significantly from here, but I think that does expose some of our leasehold to potential expiry. On the gas side, we're basically about done. I think when we get down to 2 rigs in the Haynesville, that's all we'll need. The Marcellus, we're actually in a lease renewal program to try and enable us to get down to that 12 rigs we talked about. So again, this is all a very deliberate plan, and we could -- today, the focus of the call could've been we're going to live within our cash flow, it's all going to come from gas. And frankly, I think that would be a pretty sad story. So our plan instead, starting over a year ago, was to make this transition. And we knew we had enough assets in the attic, so to speak, that we could sell them and yet still grow our production by 25%, still pay down debt by 25% and make that transition. And of course, to do so in a $2 gas world’s tough. But we're up to it and that's what we intend to do. So back to the heart of your question, we have a lot of optionality with regard to rig counts. Right now, we're trying to find the optimum level that minimizes leasehold problems and minimizes firm transport problems and also accelerates the transition away from assets that don't produce much cash flow today, which are gas assets, to assets that produce a lot of cash flow, which are oil and natural gas liquids assets.

Okay. And so I mean, the bottom line is, I guess, I'm not questioning your ability to execute on the monetizations because you've got a pretty good track record. And can you sort of give us an update then with where you are with regards to, I guess, the next few important ones, like the Permian, Mississippi and as well as the Eagle Ford VPP?

Yes, sure. I'll let Nick speak to the VPP, but that's in the not-too-distant future, I think. And with regard to Permian, the data room opens next Monday, our physical data room. I think the virtual data room has been opened a little bit. We have a long line of people want to be in it. It's the hottest basin in the world in all likelihood. And from our perspective, it's just not a place we were ever going to be #1 or #2. And I think when all the dust settles here and you look at the company, what do we want to achieve, and we want to achieve the best returns in the business. And to do that, I think you've got to be the best at what you do. And for us, that's going to be, to be #1 and #2 in 11 of the most important plays in the nation after we sell the Permian. So the Permian will get bought either in 3 packages, a group of 3 packages, or individually in those 3 packages. And there will be companies that either want to establish a presence in that basin or who want to solidify that. So we hope to have an announcement there in the first part of the third quarter and to get it closed in the third quarter. The Miss Lime data rooms have been open now for several weeks. And I'm pleased with the interest that we see in that asset and look forward to announcing that as well. That will probably happen, I would think, before the Permian. Nick, do you want to add anything on the VPP? Domenic J. Dell’Osso: No. It's like you said, it's relatively near-term and we're working through that. Those are transactions, obviously, that we have a lot of confidence in. We've completed 10 before and we have a lot of confidence in this one, as well.

Okay. Fair enough. And one last question, on your Founders Well Program, if I'm not mistaken, I mean, that wasn't necessarily like a conveyance of wellbores. Do you hold, I guess, acreage when you sort of opt in to the wells, that right to. Any kind of like future downspacing opportunities which would you also be involved in?

Yes. I believe, Scott, the language is governmental spacing unit. And so yes, and I pay for that acreage and then I receive an assignment of the governmental spacing unit.

Next, we'll move to Doug Leggate with Bank of America Merrill Lynch.

My question is on the projected guidance, net of the asset sales, because clearly, it seems, I guess, you've got confidence in the line of sight now to give us an indication what happens when you monetize the assets. What I'm trying to understand is the longer-term guidance hasn't changed. And obviously, you're knocking out a fair amount of production on liquids next year. Can you help us with the moving parts? What are you assuming from the VPP, the Permian asset sale and the Miss Lime? And then looking longer-term, what's coming in extra that's making up a difference that allows you to stand by the 250,000 barrels in your target by 2015?

I’ll take the longer-term target and let Nick talk about the shorter-term. Long term, Doug, is simply that we don't have to have all of the assets we have today to meet those targets. And so while selling the Permian or selling 25% of the Miss Lime certainly impacts 2012 and 2013 production, that's why we brought down our guidance. It doesn't do anything in terms of our ability to meet our out-year targets because we'll simply have drilled more Eagle Ford wells and more Utica wells and more Cleveland Tonkawa wells than we otherwise would have. Of course, remember, the Miss Lime JV also allows us to accelerate drilling on the asset. So not only does it save us CapEx, but it also drives our production higher from an asset after we do a JV. So the company has the ability through all of its liquids-rich asset plays to meet its out-year goals. It's simply the $2 gas that's required us to take a little bit of a step-back here and so more deeply into the portfolio. But it doesn't have anything -- any impact on '14 and '15. So I'll let... Domenic J. Dell’Osso: Yes. From a near-term perspective, Doug, we baked all of this into our guidance now, as you point out. And one of the changes is that from previous looks at this, we've moved our Eagle Ford VPP up in the year. And so that has a bigger impact on near-term cash flow as a result, near-term production as a result. VPPs, of course, are assets that we've transferred the rights to production but only in certain wellbores; those wellbores decline. So the impact of that VPP sale over time diminishes greatly. And so that's one of the reasons why you saw a lot of production upfront and that changes your near-term production guidance, but it doesn't change it as much in the out-years. And of course, we don't sell any rights or anything around those wellbores, and so we retain all of that growth prospectivity around the Eagle Ford. And that's really what drives some of that difference.

Okay. I appreciate. My follow-up, Aubrey, is really more of a conceptual question. Clearly, the market doesn't really seem terribly receptive to what's been happening here recently. And looking at your share price now, you're basically lining out more than $15 billion of asset sales over the next 2 years. My understanding is some of your newer leases, the liquids-rich leases, have longer-dated expiries. So maybe you've got a little bit more flexibility there perhaps. But my question is why not redirect some of that capital back to buying back your stock at these levels?

We first have to get our debt down to where we want it, Doug, and then I think that's actually a legitimate portion of -- can be a legitimate portion of our strategy going forward. I mean, clearly, you get half of something for free here when you buy our stock, in my opinion. You buy our gas business and you get the oil business for free. Or you buy the oil business and you get the gas business for free. You buy -- Nick mentioned the PV-10 of our proved assets using just -- the 10-year strip is $24 billion. That doesn't include our Oilfield Services business, our Midstream business. So that means you get all the uncrude for free. So there's something free here that's substantial no matter how you look at it. And so we're trying to get to that promised land as quickly as possible. And maybe some people think you should just sit there and be stuck in the mud of $2 gas prices. But we don't believe that's the way to go. And so as a consequence, we're going to spend the capital needed to make that transition, but we're going to decrease our debt and not increase our share count to do that, and I think it's pretty extraordinary. If in 2013, we get to a point where our debt reduction targets have been met, we're satisfied that our funding has been met and the stock price still represents a compelling opportunity, there's no reason why we couldn't redirect capital towards that.

Aubrey, I don't want to labor the point, but let me be clear what I'm asking you. If you've got a lot of flexibility in your capital expenditure, why not just defer that and buy back your stock today?

Because the board and management's #1 goal is – twin #1 goals are to reduce our debt, as we've said we will, under the 25/25 Plan and to make a transition from gas to oil. That's the best way to be -- have a long-term sustainable company. And to buy back our equity at this point, in our view, does not create the long-term sustainability that we want from a balance sheet perspective and from a corporate asset productivity perspective.

We'll hear next from Neal Dingmann with SunTrust.

Just 2 questions. First, Aubrey, Just wondering in your comments on -- I noticed you tended to go nonconsent on a few more wells than typical; kind of your comments on that. Going forward, is that going to be kind of a routine pattern? Or how do you see that playing out?

Yes. But that's really only gas wells. And specifically, primarily, the Haynesville, we had a couple of operators there that still are more active there than we would care to be. And so we only lose a wellbore when we do that. And I'm not exactly sure on the nonconsent penalties, but they can be 300%, 300% or 400%, 400%, so you're back at it at some point. But we have now close to, I think, 6,000 wells left to drill in the Haynesville. So if we lose our wellbore rights to a few that are operated by others, that's okay. And we didn't do that in the first quarter because the election for those wells would have been made in the third and fourth quarters of 2011, when gas prices were projected obviously to be about double where they are here. So we're in a situation where gas prices have been halved from where we thought they would be at the beginning of the winter. And that doesn't halve your cash flow from those assets. It basically wipes it out because you have obviously fixed costs. So at any rate, as a consequence of where we are in the gas price world, we're obviously making lots of changes here, and not the least of which is to not elect in gas wells being drilled by others on a much more selective basis.

Okay. And then just move onto maybe obviously either you or Steve, just wondering on 2 things here. First, either in the Utica or then look at the Eagle Ford. Obviously, I think in the Utica, because the state always wants that pre-peak [ph], I understand why you've put that out. It was just maybe seeing if you could help us understand behind either like the Shaw or the Burgett or, I mean, the 3 that were talked about, maybe what the typical sustained rate is today versus just that peak rate out there. And maybe if you could do the same thing in the Eagle Ford, around that McKenzie D 3H and as well as the Blakeway.

Well, I, Neil, don't have that with me on what those wells are making today. They're declining like most all of our shale plays. We're very pleased, the results, I mean, good IPs, it's oil, high liquids. So this is a great play. But the reality is we only have 9 producers, and so not much data yet.

That's all right. I was just going to point out that the Buell is really an important well. And the Buell was the well that was shut in for the longest before it came on. And so one of the approaches we've taken in here is that our wells are -- we're not bringing them on immediately after completion. Sometimes that's due to pipeline delay, but sometimes, it's due to certain engineering and production performance benefits that we get by leaving them shut in for a while. So if you look at the Buell, at least 575,000 barrels of liquids and 13 Bcf of gas, it may very well be our best shale well ever. And so I think that's a great indication of what's likely to come going forward in that play. But you're never going to get the information you probably desire from the state reports because it's never going to report liquids and it's always going to be at peak rate. So I think you'll just have to watch the play develop. And the good news is a lot of other producers are getting in the area and starting to talk about it more, I think you'll be able to triangulate in to what we see, which is how could we be more pleased with the play when in one of your first wells, you drilled your best shale well ever after having drilled thousands of shale wells. So I think it really bodes well for the play going forward.

Aubrey, what's your sort of forecast, I guess, about the western flank of the Utica? I mean, what’s your expectation, it’s a little bit even further less than you've drilled.

Well, if you think about -- if you mean by western flank, if you meaning the oil window, I would probably characterize it a little bit differently. We would look at our oil window as not being on the flank but instead being right up against our wet gas window. And again, we've been careful not to say how much of our oil window acreage, which is around 400,000 acres, is likely to be prospective because we just don't know yet. We haven't drilled enough wells there. But obviously, we're very encouraged by the Anadarko wells that have been drilled down to the south in the oil window. And so I think we'll know a lot more in the next 60, 90, 120 days both from our own drilling but also that from others. So there were a lot of people who said we couldn't crack the code in the oil phase of the Eagle Ford as well. And we routinely bring in wells of 500 to 1,000 barrels a day there. So we remain confident about the oil window of the Utica. It's just our focus to date has been on something that we knew would work well, and that was the wet gas side of the play.

We'll hear next from Monroe Helm with Barrow, Hanley. H. Monroe Helm - Barrow, Hanley, Mewhinney & Strauss, Inc.: I'd just like to follow up on the comment that you -- one of your colleagues made earlier about taking hedges off last year. Can you kind of walk us back through what precipitated you reducing your -- or taking off your hedges on the gas side?

Sure, be happy to, Monroe. So first of all, to give you some context, since 2006, I think our gains have been about $8.5 billion. I think that's, by far, the best in the industry. Our track record is not perfect, but I think that's pretty good. And so what happened last fall was in one of the Greek euro market swoons, oil prices dropped down to lower levels; gas prices dropped, we thought, without any regard to the fundamentals. And so we took them off and look to put them back on when things stabilize. In oil, we did. We got, I think, all of our oil hedges back on at I think it was $7 or $8, maybe higher than where we had put them on. So that created a lot of value for us. And gas, just we never got the chance again. And obviously, we are not happy with that decision. If we had to do it all over again with the hindsight of winter, we would've obviously done something different. But to me, it's a little bit like owning a stock and everybody's owned a stock. It's met 80% of your expectations and then you begin to think about is it time to sell, is this what I came for. And from us, we thought we had received a gift, a downdraft that was unrelated to fundamentals in the U.S. gas market. And we thought we would take advantage of that. We have routinely done this in the past and have been quite successful. This is the only time that I can remember that we took hedges off and then it just fell away from us. So we got most of what we came for. And honestly, we would've probably never kept them until today.…

I don't think we've had to make any firm transport payments yet. But Nick, correct me, but... Domenic J. Dell’Osso: Yes. We've made -- as we discussed in our filings, we've made some payments to, under minimum volume commitments, Chesapeake Midstream Partners over the last couple years. If we've made any other FT payments thus far, they've been relatively small. It's been part of our calculation to determine how much gas we wanted to or we were comfortable with curtailing this year. And so there are optimal points where you might be willing to make some of those payments versus producing the gas. But in general, our transportation costs are just -- the transportation costs around the industry are relatively high. Getting gas out of the Barnett is quite expensive. All that infrastructure had to be built and it eats into our differentials considerably. Further, gas transportation out of the wet gas plays or the liquids-rich plays can be expensive because the volumes are not all that high, but the infrastructure still has to be built in order to get the oil supply.

And Monroe, we did increase our expected differentials, I think, in our outlook as well to try and account for that. And then in NGLs going forward right now, they're low, but we think plant turnaround season will bring them back up. So long-term, we see that we spend a lot of time studying NGL markets and believe that the growth in NGL demand will keep up with the supply generally. But there will be times perhaps when NGL prices can be weak for a couple of weeks.

And we'll move next to Jeff Robertson with Barclays.

Aubrey, in the oil part of the Utica play with the results you all anticipate later this year, is that a candidate for some sort of monetization in the future, either a joint venture or another one of these asset-level preferreds that you all have done?

Yes, definitely. Jeff, we really have 2 more JVs we could do in the Utica. One is on the dry gas side and the other is on the oil side. So I think, ultimately, we could do 3 there. And the question at this time, I don't think now is the time to do one on the dry gas side. If someone approached us with the right idea, we might look at it. But in terms of -- and then on the oil side, we just have to wait to be able to confirm that we've got a viable play there. And we think we do, but don't have enough wells yet to prove that. I think if you look into 2013 and say okay, well, you've got another funding gap in '13. As you continue to make this transition to liquids from gas, where is that going to come from? I think the Utica is certainly another area that you can look at for us to do JVs that would create quite a bit of value for us.

Would a monetization there, I guess, it would then probably impact the liquids progression that you laid out, which, I think -- or will it?

No. It wouldn't, Jeff. I mean, we really have very little contribution modeled from that area right now. So I wouldn't -- these out-year estimates really do assume that we continue to meet our obligations. For example, in '13, we've already accounted for the fact that we'll be selling some assets. So we think that we've got that all accounted for in both our short-term and our longer-term asset models.

Then secondly, do your asset sale targets for this year include any other acreage monetizations, like the Woodford deal you all announced a month or so ago? You've got acreage in, I think you said the Woodbine and you all have had acreage up in the Williston and probably other areas as well.

Yes. We're still working our Williston acreage. It doesn't look like it's going to work for the Bakken or the Three Forks, but we've got some other ideas there. So I haven't given up there. We're getting ready to complete a well in another formation. DJ Basin has not worked for us in the Niobrara, although the Powder River has worked quite well. So those are 2 areas, plus you mentioned the Woodbine, all of which we've accounted for in our go-forward plans. So again, we tried -- sometimes you try to get in plays and sometimes you're successful with where you want to be and sometimes you're not. So again, as we look at the company going forward, we want to be real simple about our goals, which is, if we own it, we're going to be #1 and #2 in it. If we can't get there, then we're going to sell it and let somebody else consolidate their position. We're big believers in the vertical integration and also to have scale in these plays because it’s an important point. Going forward, the company is going to look dramatically different than what it's looked in the last 7 years. We've gone through a tumultuous time in our company's history and in the industry's history. The industry has been -- 100 years of history has been completely remade in 7 years, and we helped make some of that history and we participated in the rest of it. But going forward, we're not looking to take what we've learned and go overseas or go to Canada. All we want to do is drill wells on acreage that we already own and to turn this into a high-margin manufacturing business, and I think we can do that. And it's -- to go retool your factories while they're running and while they're running today, producing 84% gas, when the gas doesn't make much money, it's a daunting challenge. But the alternative of sitting there and doing nothing and just waiting for gas prices to recover, I know that's a losing strategy. And I think our strategy will be a very winning strategy going forward and we just got to get through what's going to be a tough year this year and a lot of concern about our asset monetizations. But of all things that we've done well over the years, I think to deliver those have been certainly one of the things we've done best. So looking forward to getting into a time of better gas prices, but more importantly, a more balanced strategy with regard to gas and oil and winnowing our asset base down to those things where we're only #1 or #2.

We'll take our next question from David Kistler with Simmons & Co. David W. Kistler - Simmons & Company International, Research Division: Real quickly, in your prepared remarks, you mentioned being free cash flow positive in 2014. Can you give us a little bit more color around the assumptions that drive that? And would CapEx ultimately be the plug to achieve that commitment?

I'm sorry. Was what the plug, Dave? David W. Kistler - Simmons & Company International, Research Division: CapEx maybe?

Well, sure. That, and if we had to sell an asset, that would be the plug. But right now, we are anticipating around $7 billion of cash flow. I think the oil price there is around $100 and I think gas prices are in the $5 range. So that's not much higher than where the strip would be, I think, particularly once we get through the summer and work off a lot of this balance. So you have prices today that are unsustainable. And the good news about unsustainable trends is that they're unsustainable. So this will get itself fixed in at least the next year, if not closer in. And so anyway, that's our goal in 2014 and we'll toggle CapEx to get there. If we have to have a little bit of an asset sale at some point, we can do that, as well. David W. Kistler - Simmons & Company International, Research Division: Okay. And that's helpful. And then just maybe following up on that, in your forward guidance for 2013, gas price is now targeted around $3.50 an Mcf, down from $5. You talked a little bit about the 10% to 12% reduction and gas production between '12 and '13. It seems like that might be a little inconsistent with that $3.50 number that's obviously contributing to a larger cash flow deficit versus CapEx that year. Can you just give us color on why you think it's $3.50? Are you erring on the side of caution? Or is that firmly where you think you are? Domenic J. Dell’Osso: Yes. No, Dave, that's exactly right. We are erring a bit on the side of caution. We try to true up pretty close to the strip. I think actually now we're a little even below the strip for…

Well, I think the question is complicated, in the sense that you'd have to factor in a winter, where you didn't burn a Tcf of gas, which is 4% of all the gas consumption in the U.S. just didn't happen. So a lot of people, in my opinion, are looking at today's gas price and saying that, that is a function of where gas supply and demand are at this price when the reality is this has put a Tcf of extra production or less demand into the market. And as a consequence, you've got to get rid of it. And to do that, you've got to lower the price. And the good news is for producers, I mean, while this is a very painful year, we're going to incentivize decades' worth of increased gas consumption as a result of what's happening this year. So you just got to get through it, and we'll get through it. And my view is that we'll overcut on gas drilling and you'll probably be surprised by the rebound in pricing. It's one of the reasons why I'm so in favor of LNG exports because I think it provides a relief valve. I mean, this kind of yo-yo back and forth on gas drilling activity is hard on the industry. It's hard on its shareholders, it's hard on service companies. And ultimately, it doesn't help consumers to stay concerned about it as well. Whereas if you had an export capability, when you had a winter like this, you could just step up exports and have a balanced market. So I think we're headed there, and Shiner will get us there plus other facilities. And so we view that we're taking the proper steps by curtailing production and slashing our gas drilling to a minimum, and we're determined to be a big part of the solution to the gas market overhang that exists today as a result of the winter. And we'll see what the summer brings. Hopefully, it'll be 120 in Boston and 140 in Houston, and we'll get rid of this in the same way that it came to us. David W. Kistler - Simmons & Company International, Research Division: Appreciate that. One last just quick one on the curtailments. Looking at the levels for Feb and January that you've done so far and then looking at what you're projecting for the balance of the year, it looks like at some point this year, you're going to be reducing those. Can you give us kind of a timing of that? Are you reducing them currently and then expecting you might have some more in the fall? Or how does that map out to true up to your guidance on that?

Yes. We're not going to disclose specifics on that. No need to telegraph our plans to the market. But clearly, if you look at our previous guidance to now, we anticipate the market cleaning itself up faster than maybe what we thought before we've seen pretty strong demand increase on the power side. And so we feel like we'll be able to reduce some of our curtailments going forward, but at this point, have no interest in being any more specific than that. I hope you'll understand that. Domenic J. Dell’Osso: To clarify one point you made though, we did not start curtailments until February.

We'll take our next question from David Wheeler with AllianceBernstein.

Aubrey, on the finding and development costs, you talked about $10 going forward. I always think of the oil and liquids plays when I talk to companies and they give you the well costs and the EURs as something like a $15 to $20 F&D. Can you talk a little bit about why -- how you see the $10 F&Ds? Is that sort of a benefit of the JVs carrying some of your capital?

Yes. David, I think there are quite a few things embedded in that. First of all, we will go forward always be able to find gas. And so I think our Marcellus finding costs are less than $1. And Haynesville and Barnett, if we ever get going there again are solidly just above that range. So you always have contribution, and then we're in some low-cost plays. I mean, if you look at the Mississippi finding costs, you look at Eagle Ford finding costs, we think on a blended basis that we should be able to be in that $10 per barrel number. And remember, Dave, that's almost a 40% increase from where we are today, so we are modeling that as we go forward, those costs should jump up as more and more of our finding is related to liquids plays rather than gas plays.

Yes, as well the margins. But you mentioned cash flow. I just wanted to ask you a couple questions on the long-term growth expectations. You mentioned cash flow positive in '14 and cash flow on the order of $7 billion. So is that also -- and you also mentioned a 10% to 15% growth rate for production and cash flow. I think that was a longer-term number. So is it the right way saying, what they’re saying about this, $7 billion of spending-ish should get you 10% to 15% growth?

Yes. I think that's the right way to look at it, Dave. And of course, it is dependent on gas prices. If gas prices never get above $3 or $4, then we would continue to need to make asset sales. But in our models, at the $5 gas and at $100 oil, we're balanced in 2014, and that's our goal. And we've been trying to get to a point where we have a business model that we think what we have today is defendable and sustainable. But when it depends on selling part of what you find every year, people will never be comfortable with signing on for that. And so what people always want to do, and this is proper, is to look at what your operating cash flow is and your projected CapEx and look at whether you've got a deficit or if you've got a surplus at that point. And that's where we want to get to. But we could never get to that balance in 2014 if we were to remain a 90% natural gas producer. So that's why all the heavy lifting in 2011, '12 and '13 to take the nation's second-largest gas producer and turn it into a top 10 oil producer. Probably by the time we get done, we'll be close to a top 5 oil producer in the country. And I think people will be, frankly, astounded that we've been able to do it and been able to do it without increasing our share count and while still bringing our debt down.

Okay, good. And one last one for you. Gas reserves, you guys -- given the slowdown in drilling for gas wells, you guys have, I think, 7 Tcf of 1P gas reserves that are undeveloped. Do you anticipate some reduction in the proven gas reserves because of the slowdown in drilling?

I don't think it will be slowdown. We'll probably lose reserves through this year as the impact of the SEC pricing rolls through. You remember we're now on a basically trailing last 4 quarters basis. And so some of those PUDs certainly will be exposed to lower gas prices, but they won't go away from a resource base and they will come back to us in 2013. So the 5-year rule is we're fine there because again we project to get back after it once gas prices recover. And we think the market will continue to need more gas as these demand initiatives kick in. So if you see us lose reserves through the year, it will be from the mandated SEC pricing, not from having no expectation of being able to drill the wells.

We'll take our next question from Brian Singer with Goldman Sachs.

Following up on Dave Wheeler's question. If we look at your 2013 guidance for proved well costs, unproved well costs, midstream, capitalized interest and dividends, i.e. your ongoing cash outflows, we get to about $10 billion at the midpoint. And as you were just discussing, it seems like you're assuming a much lower ongoing rate of spending. Can you speak more specifically about where that flexibility is to reduce? And assuming that you do plan to maintain your 2013 rig count in future years, shouldn't we see some upward pressure as a result of carried interest from JV projects -- different joint ventures rolling off?

When you say pressure, you mean higher CapEx?

Yes, exactly. One would assume that your 2012 and '13 spending is benefiting from some of the carries from joint ventures; of course, you're planning on consummating new ones. But wouldn't we see as sort of carries roll off and you don't reduce your account, that your CapEx pressure would rise?

Yes. Let's review where we are right now. Steve, help me on this. But obviously, our Haynesville carry is gone. Our Barnett carry is gone. Our Eagle Ford carry is gone. Our Marcellus -- where are we on the Marcellus? It's done. So we have no more left there. So really, the only carry we have left right now is the Utica and the Utica wet gas.

And the Niobrara.

And sorry, we do have CNOOC carrying us in the Niobrara. So actually, as those continue to roll, we'll actually be rolling on new ones, I think, for the Utica dry gas, Utica wet oil -- not wet oil, Utica oil, and then also, the Mississippian as well. So actually, we've calculated all that in. Steve, you might just hit us with some percentages. I think in 2013, our budget is 30% Eagle Ford. Is that right?

Yes. But that's actually greater than that. It’s almost 40%.

30% in 2012, about 40% in 2013.

39%.

And just to get through some -- glancing at our schedule for 2013, we're going to average -- I think we've got 11 rigs on the gas side, and then just in plays like the Mississippi, we're at 22. The Utica, all-in, around 22. And then if I add up the -- back up to around 33 in the Eagle Ford. And then if I add up the Anadarko Basin, you are at around 23 to 25 or so. So basically, when you look at the company in 2013, the Eagle Ford, Anadarko Basin, Utica will be the prime drivers of it. So again, a focus on almost all oil. And based on what oil prices do, based on gas prices do, we'll modulate around that. But the goal is to be at 2/3 in '13 and have our CapEx be right line with where our cash flow is. I'm sorry, that's 2014.

Right. So I guess, going from kind of a $10 billion number to a $7 billion number, is there anything specific beyond potential rig count reductions where that one could then -- people might not be focusing on as one-offs aspects of the 2013 budget?

I mean, the major thing, Brian, is just rig count. In the fourth quarter, we were running 172 rigs. In the third quarter this year, we're running 125. That's almost a 1/3 decline. So I think it should be pretty obvious where it's coming from, on rig count. And then we do think we'll see lower costs, and the first quarter took the brunt of third and fourth quarter 2011 per unit cost. And Steve, frac costs and all that are down, sometimes 25%, 30% or more.

Yes. I mean, per unit costs are way down; efficiencies are going up because we've done some ramp-up. But like in Eagle Ford, we're just getting better every week. And as you said on cost, I mean, we did have some overhang. We had 20 frac crews running in gas plays at the end of the year and we have 6 today. So it’s just, that spend is just way down.

Got it. Okay. And separately, as you move more into development mode and as your lease acquisitions are reduced, do you anticipate needing any meaningful human capital shifts away from those focused on land acquisition? Or are there meaningful land and title-related issues that remain? Do you see any G&A savings…

Yes. Those numbers will continue to go down as they have. We probably, at our peak, had over 5,000 people in the field, some -- obviously, most leasing, but a lot doing work getting wells ready. And so – and that's why you make them contract employee – or not employees but why they are contractors. And we're continuing to shed in the field and will going forward because we'll be down in maintenance CapEx levels of, I think, not more than $500 million a year in 2013 and beyond. You'll still need people in the field to make final deals with holdouts and to get damages settled and get abstracts built for title opinions and so forth. But in terms of having the massive army, it's not needed anymore because from my perspective, and I think the rest of the management team shares this, is we embarked on a journey 7 years ago to participate in the remaking of the industry. And I think after this year, it will have been remade. And if you stayed with conventional assets, you completely lost out. If you started late to unconventional assets, you're probably now forced to go buy them in the form of a company or in the form of an asset collection. And I think going forward, companies like us will be incredibly favored as we have these #1 and #2 positions in 11 plays and all we do is focus on driving returns higher from our existing assets. And that's -- 95% of the people who have ever heard of us, who have ever followed us have never known us in that kind of a mode. And it's going to be a big surprise for people. But it's going to be the absolute, inevitable transition from this participating in the 7-year unconventional resource revolution. And we're excited to turn the page. This has obviously been stressful. It's hard work. It's not easy. But the prize that we're after is to have the best asset base in the industry, and I think we've achieved that. And now from that best asset base in the industry, our goal is to achieve the best returns in the industry. And if we can do that, I think that we are likely to be a company that will be a great performer for investors going forward.

One last very quick one, did the increase in your 2013 liquids differential reflect a more cautious view on NGL prices or a greater percentage of NGLs in your mix?

Mix stays the same, just all about the problem with ethane prices that we're going to encounter from time to time.

We'll take our next question from Matt Portillo with Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just 2 quick questions for me. In terms of the infrastructure side of the equation, could you first provide some color on the possible volumetric commitments for takeaway from your dry gas plays? And does your current guidance for 2012 and 2013 ensure that you'll meet those commitments? And then the second question, just along the lines of the VPP and the Eagle Ford, could you provide any detail on how much production you may actually put into that VPP? Domenic J. Dell’Osso: No. We're not ready to provide exact guidance on a VPP that hasn't yet closed. So I'll just hold off on that until we have a completed transaction to talk about. But I will just reiterate that it is baked into our guidance that we've provided today. On the commitments related to minimum volumes, et cetera, those are detailed in our filings. And we take all of that into account when we set our drilling schedule and expectations around how much we want to spend in wells that we want to bring online. So at end of the day, it can all be a part of a financial analysis. We think that we will potentially have some payments to some of our midstream partners under those agreements. But at this point, we do our best to minimize them and timing will affect some of that. And we'll continue to try to optimize that analysis as much as possible.

Very little in 2012; it would not come into effect really until our gas starts dropping in 2013. Domenic J. Dell’Osso: And we'll do our best to keep those as close to 0 as possible. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And is that included in your LOE guidance, just so that from a modeling perspective, we can take that into account? Domenic J. Dell’Osso: It would come in, in our differentials.

Next, we'll go to Charles Meade, Johnson Rice. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Two things. I guess, maybe this first one for Nick, just the nuts and bolts of the guidance on liquids for 2012. As far as I appreciate it, the liquid being guided down versus what we had for February 21, that's -- new in the Eagle Ford VPP. Am I correct? Domenic J. Dell’Osso: We had a VPP in there, but we had it later in the year. So one of the big changes is the timing, and it was smaller. So we brought a lot of wells online there this year, and so we've expanded the size of it as well. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: And is the kind of the composition of the Permian transaction the same in both of those books? Domenic J. Dell’Osso: Well, we did not have the Permian transaction baked into our forecast in our previous outlook, so that's new in this outlook and it's a big driver in the change downward, as the Mississippi Lime was not baked into our outlook the last time either.

Plus the Texoma sale of Exxon was not in it, as well. Domenic J. Dell’Osso: Right. So there's really a lot more monetizations in there this time. And at the last time we provided outlook, we tried to be clear about what was not in there. Even though it was announced intentions, they were relatively early in their process and we did not yet have enough feel for exactly how those transactions would come together. So we provided guidance without them and just tried to indicate how we thought you might think about framing those transactions in your analysis. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Got it. Great. That's exactly what I was after. And the second piece, looking at the presentation you guys put out today, there's a lot of, I guess, really good, new interesting detail on a lot of your plays, but particularly on the Eagle Ford. I was wondering if you guys could talk a little bit about what you're seeing across your pretty wide acreage spread there, if there's any parts of it that you're more excited about or parts that you're still left to be figured out and what you're seeing in well costs there.

This is Steve. We're very excited about results really across our whole play. Our science and engineering teams have done a good job on picking our acreage. As we got into the play kind of late, so we had a little better understanding when we bought our leasehold. And so really, it's working across our whole play. So we're very excited about it. We've had excellent results now, and we run on 60 wells this quarter. So certainly, our knowledge base and history is growing and it's all looking good. And now that we've kind of leveled off on rig count, not ramping up, our teams are really performing well. And so as I mentioned, our cycle times, our drilling times are down about 20% already. We've had some excellent service cost reductions, like our stimulation, pumping services, latest bids there are down almost 25%. So really good things are happening in the Eagle Ford. And that's where we're putting our money. Like I say, next year, it's almost 40% of our capital. So it's performing quite well and we're very excited about it. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Got it. And I guess, what I was after there was that this is shallower than a lot of the other Eagle Ford. And I know that, for example, in your Dimmit County acreages, Anadarko has had some really great success there, not so much with the eye-popping IPs, but more just because the shallower and lower well costs or drilling complete costs. But I guess you guys kind of don't want to disclose that at this point.

No. And this is in Texas and on some big ranches. And so we're drilling a lot of 6,000, 7000-foot laterals there also. So good wells but not necessarily super cheap because they're long laterals with lots of frac stages.

We'll take our next question from Michael Hall with Robert W. Baird.

We'll take your call, Michael, and we'd like to just kind of just wrap up the call with your call. I know that there's probably several other questions left. But please call John or myself later today. But we'll go ahead and take your call, Michael -- or your question. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: I appreciate that. Just one for me. Given the increased, I guess, dependency on NGLs, consistent with the wider differential there, there seems to be -- my understanding is there's a less robust hedging market around NGLs. I guess are you seeing any developments in that market? Or does that fact kind of increase the risk profile of your growth plan in your perspective?

Well, I guess -- well, first of all, there's not a good way to hedge natural gas liquids so I agree with you there. There's not much you can do except just kind of go with the market. But we do spend a lot of time talking to fractionators and crackers, and we believe that those folks are making the requisite investments that are needed to keep up with the supply growth. And remember, those are things that can be, for the most part, exported either in a liquid form or in a solid form. So we're pretty confident that NGL values at the end of the day in the U.S. will be supported by what's happening around the world. But people need to recognize that, for example, in Conway, Kansas, NGL -- ethane prices are only 20% of what they are at Belvieu. But that's going to get fixed. And just like WTI to Brent is going to get fixed, with the Seaway Pipeline and additional pipelines, you're going to see the Belvieu to -- or Conway to Belvieu discount get fixed as well. So that will happen in time. And the U.S. has the lowest feedstock for the petrochemical industry in the world. And as a consequence of that, you'll see plenty of demand pick up over time as well. It would be delightful if there was a forward liquid market that we could hedge NGLs into, but we can't. So we'll continue to look at hedging opportunities for oil and natural gas when the time is right. Jeff, back to you.

Yes. I think we'll go ahead and wrap up the call. And if you have any questions, please contact myself, Jeff Mobley or John Kilgallon. And our contact information is at the bottom of yesterday's earnings release. Appreciate your attendance on the call, and we'll talk to you at the next quarterly conference call.

And again, ladies and gentlemen, this does conclude today's conference. We thank you for your participation. You may now disconnect.