Expand Energy Corporation (EXE) Q2 2010 Earnings Report, Transcript and Summary

Good day, and welcome to the Chesapeake Energy 2010 Second Quarter Operational Update and Earnings Results Conference Call. [Operator Instructions] 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 2010 Second Quarter Earnings and Operational Update Conference Call. Joining me today is Aubrey McClendon, our Chief Executive Officer; Steve Dixon, our Chief Operating Officer; Marc Rowland, our Chief Financial Officer; Nick Dell'Osso, our Vice President of Finance; and John Kilgallon, Manager of Investor Relations and Research. Our prepared remarks this morning should last 10 to 15 minutes and we will then move to Q&A. Aubrey?

Thank you, Jeff, and good morning to you all. We hope you had time to review Monday's operational release and yesterday's financial release. We always strive to provide the most detailed information in the industry to our investors. On the operational side, our daily production for the first quarter was very strong at 2.8 Bcfe, up 14% year-over-year, and that's after selling a significant amount of production through various VPPs, asset sales and our Barnett joint venture deal with Total. On a sequential basis, our production was up 8%, and most importantly, our liquids production was up 41% year-over-year. Because of the strength of our drilling program and the outstanding performance of our wells, we are increasing our 2010 and 2011 production growth forecast to 13% for 2010 and 18% for 2011. Much of that growth will come from our rapidly increasing liquids production. In fact, we expect our liquids production to increase by 60% in 2010 and 80% in 2011, both of which are remarkable numbers, especially for a company of our size. Next, I'd like to highlight our exceptionally low finding cost rate in for the first half of the year. We added a net 1.2 Tcfe at a drilling and completion cost of only $0.87 per Mcfe. I don't believe there's another company in the industry as capable of adding 2.5 to 3 Tcf per year to there proved reserves at under $1 per Mcfe. And this success has been achieved by the nation's most active and highest quality drilling program, led by our industry-leading leasehold positions in America's best unconventional natural gas liquids plays. The growth in our liquids production and in our proved reserves and our planned slowdown in natural gas drilling are our most important messages today. I want to make clear, in fact, crystal clear that Chesapeake is pursuing a differentiated growth model for many of our colleagues in the industry. The CHK model is not a commitment to increasing gas productions without regard to natural gas prices. Quite the opposite, in fact. Unless gas prices increase over $6 per MCF, Chesapeake is committed to continuing to reduce its gas drilling CapEx, increase its liquids drilling CapEx. In fact, in 2011, we will see an $800-million swing as we reduce gas CapEx by $400 million and increase liquids CapEx by that same $400 million, all the while planning to keep year-over-year CapEx flat. I'll repeat, we are reducing natural gas CapEx, while increasing liquids CapEx, while planning to keep overall drilling CapEx flat in 2011 versus 2010. With regard to the oil and liquids plays that will drive Chesapeake's growth model in the years ahead, I want to remind you that we started to make this transition back in 2008 when it became clear to us that oil prices were likely to outperform natural gas prices for a long time to come. However, because of the long lead time in developing the technological expertise to find and test unconventional oil plays and the length of time it takes to put leasehold plays together, it is only now that we are really starting to see the payoff from the strategy shift that we initiated in 2008. This will be the single largest strategy shift in Chesapeake's history. And once it has been completed during the next few years, it will generate huge benefits to our shareholders. And we believe that unlike with natural gas, Chesapeake's success in finding large new reserves of unconventional oil in the U.S. will not negatively affect oil prices. Obviously, this has not been the case with our large discoveries of unconventional natural gas during the past few years. One final thought on our liquids plays. For now, we are disclosing the names and locations of 12 of these plays, but there are more on the way. In these 12 plays, we have drilled about 280 wells and have a amassed an industry-leading position of 2.4 million acres, on which we have identified more than 8 billion barrels of potential unrisk liquids-rich resources. We now own the largest inventory of leasehold in two of the top three new unconventional liquids plays in Niobrara and the Eagle Ford Shale, where we now on 675,000 and 550,000 net acres, respectively, located very strategically in the liquids-rich portion of each play. We are especially pleased about our position in the Eagle Ford and are very excited to move forward with the JV on this acreage. We are in good position here with many potential partners, all of whom we believe are working hard to get to the right answer. Speaking of acreage, I am well aware of the huge amount of capital we have laid out for acreage so far this year as we transition away from our former gas-only strategy and towards our more balanced gas-and-oil strategy. First of all, some of our gassy peers have chosen not to make this transition and appear willing to take their chances with future gas prices. That is a risk to which I am not willing to expose our investors. On the other hand, if you believe oil and NGL prices will be much stronger than gas prices for a long time into the future, as we do, then you have two choices: You can either buy your way into more liquids production through acquisitions, or you can organically grow your way into more liquids production through leasing and drilling. The first approach is one that has been taken by some companies recently, but it is a very, very expensive route. We prefer the second approach, provided it is onshore and in the U.S.A. We started building the foundation for this transition back in 2008 with our discovery of the Granite Wash play in Western Oklahoma. During the past two years, our move to oil has been gaining momentum until this year, when the pace greatly quickened as about 10 new oil plays developed either under our initiative or, in a few cases, by some of our peers. My review of the recent history of the unconventional gas business tells me that it took only about three years from the confirmation of the Barnett size and the Fayetteville discovery in 2005 to the discovery of the Haynesville, Marcellus and down-dip Eagle Ford in 2007 and 2008. I hope you'll recognize that there hasn't been another big unconventional gas play since those discoveries of two years ago. If you didn't play big in those three years from 2005 to 2008, then you are left behind or relegated to paying big premiums to established positions in these premier new unconventional gas plays. Paying up after the fact can work just fine for big international companies, but it doesn't work for us. In moving from unconventional gas history to thinking more about how the history of unconventional liquids will be written, it was my assessment that 2010 would be the year that companies either lockdown positions in this big new liquids plays or were left out and left behind or perhaps relegated to paying very big premiums down the road. I decided that Chesapeake had to play, while costs were still affordable for companies of our size, and we have played in a big way. While we still have more leasing to complete in the second half of 2010, the spend will not be as heavy as it was in the first half. Furthermore, starting in the third quarter of 2010, we will begin selling off minority positions in some of these new oil plays to recover much, if not all, of our initial leasehold investment. That process will continue into 2011. And when it's all said and done, we will have locked down the best unconventional liquids position in the industry and we will have very low remaining costs in our retained acreage. If you do not believe that we are capable of this, then I respectfully refer you to the $10 billion of joint ventures we entered into in the big four shale gas plays in 2008 and in early 2009, in which we sold about $2 billion of leasehold cost for $10 billion in value. There is one more aspect of our leasehold buying and selling I'd like to discuss. For CHK tax reasons and for partner cash flow reasons, when we sell acreage into a JV, we only receive a portion of the total consideration in upfront cash. The rest comes in drilling carries over time, i.e., a reduction in our CapEx for drilling. For starters, we can't book this drilling carries as receivables because their contingent on us drilling wells to earn the carry. That's always a disappointment as our financial statements do not reflect these very big and very valuable drilling carry, which total right now about $3 billion. I can assure you that we will drill the wells over time, and we will receive this cash. However, when we receive the cash, we record it as a reduction in our drilling CapEx, not as a reduction in our leasehold CapEx. However, it is in fact very much a recovery of leasehold CapEx that has simply been triggered by drilling, but that's not the way it shows up on our financial statements. Since many analysts routinely kick out our carries in their analysis of our finding costs because to them they are somehow not real, we end up with the worst of all world. Our industry-leading low finding costs are virtually disregarded, and our industry-leading leasehold CapEx investments are overstated by the amount of the drilling carries received. Therefore, our true leasehold CapEx should always be evaluated by looking at what we spend, less what we collect in upfront cash and then also less what we will collect in future drilling carries. This is a big issue, and I hope you will now have a better appreciation of how our leasehold CapEx is always overstated and in my view, therefore, very likely underappreciated as our number one profit center over the years. One more thing in regard to profit centers, I do hope you will recognize that our cash hedging gains since 2001 have now reached $5.4 billion. I offer congratulations to the other two members of the hedging committee, they are here with me today, Marc Rowland and Jeff Mobley. We have delivered outstanding value to investors here in far greater amounts than anyone else in the industry has, and I do believe this is a vastly underappreciated aspect of management's performance over time. So I'd like to close my commentary with reading you an excerpt from our press release that we believe very clearly states what we are seeking to accomplish this year and in the years ahead. We plan to reduce drilling and natural gas well, except for those required to hold leasehold by production or to use a drilling carry provided by a joint venture partner until such time as natural gas prices rise above $6 per MCF. We plan to lease and develop substantial new liquids-rich plays in which the company can acquire very large leasehold positions of 250,000 to 750,000 net acres. Within one year of acquisition, we plan to sell a minority position in a new play recovering all or virtually all of the costs acquired to leasehold in the play and to fund a significant portion of Chesapeake's future drilling costs in the play. We plan to accelerate drilling of liquids-rich plays until year-end 2012, when the company's drilling capital expenditures are balanced, approximately 50-50 between natural gas and liquids. We plan to continue adding proved reserves, net of monetizations and divestitures, of approximately 2.5 to 3.0 Tcfe or up to 500 million barrels annually. And we project by the end of 2012, we are likely to own 18 Tcf of proved reserves and about 1 billion barrels of oil. I encourage you to consider what that would be worth. And finally, we plan to accomplish these goals without the issuance of additional equity and with a reduction of debt levels, such that the company becomes investment grade within the next few years. The key challenge we face in implementing this strategy is to allocate capital between our very large gas asset base and our emerging unconventional liquids plays. We have considerable gas drilling that we need to drill to earn the $3 billion of outstanding carries and also to hold very valuable and very high-quality gas acreage, but we also have tremendous opportunities in new unconventional liquids plays. These two activities result in very large capital needs. Fortunately, our assets are exceptional, and we've been able to attract partners, or expect to, who will finance much of our new liquids projects. Because our assets are so valuable, we will be able to accomplish the oil and gas industry hat trick in the years ahead. We will grow reserves and production by 13% to 18% annually, reduce leverage and not issue any additional equity. Our assets give us the ability to use a range of asset-level financing tools to raise money at significant premiums to our cost bases in these assets. In summary, having helped to revolutionize the onshore U.S. natural gas business, we look forward to doing the same for the U.S. oil business, but we will do so receiving $10 to $15 per production unit versus the $4 to $5 per production unit we're receiving for our gas right now. This brighter, more profitable tomorrow cannot arrive soon enough for me. This completes my commentary, and I'll now turn the call over to Marc.

Thanks, Aubrey, and good morning, everyone. Very solid and profitable quarter in our opinion. Also, one that's a lot of attractive financing transactions. Notably, we completed in May the issuance of $2.6 billion of cumulative convertible preferred stock, including approximately $1.5 billion that was sold to prominent Asian investors for the first time ever. We used the proceeds to redeem $1.3 billion of senior notes in June, and additional $0.6 billion of notes that were redeemed in July after the quarter closed. The remaining proceeds were used to reduce our bank debt. So with the issuance of $2.6 billion of face amount of preferred, we reduced our debt by a similar amount. In June, we closed on our VPP number seven, or volumetric production payment, for $322 million of proceeds or about $8.75 per Mcf equivalent for around 38 Bcf of sales. Obviously, monetization at a rate well above what our company is valued at in total. We also concluded two other asset sales that we had spoke about earlier in the year for $330 million in proceeds, one in the Permian Basin and one in the Appalachian area. So a busy quarter that resulted in end of quarter cash and undrawn credit facilities of $2.8 billion. As Aubrey noted, our hedging gains over the last many years, particularly powerful in quarter two, giving us an additional unrealized cash revenues of $2.26 per Mcf equivalent. Subsequent to quarter end, we were successful in launching our Chesapeake Midstream Partners' IPO, New York Stock Exchange symbol CHKM. We priced 21.25 million primary units at $21 per unit, the high end of our expected range. Today, those units are trading for about $23, giving CHKM an enterprise value of around $3.2 billion or $1.34 billion to Chesapeake's 41.45% interest. There's nearly $1 billion of cash and unused credit facilities to accomplish CHK drop-down acquisitions or other acquisitions inside of CHKM, something we intend to pursue in the near future. And as a sidebar to that, our remaining Midstream assets that were not put in CHKM have nearly the identical production profile as the assets that we've transferred to date. You may have also noticed that last night we announced a cash tender offer for an additional aggregate $1.5 billion of senior notes of various maturities. We intend to finance these with notes of longer maturities and the tenders conditions on our successfully placing these notes in the near future. I would end by saying our finding costs, the power of our joint ventures and substantial remaining drilling carries, along with the other ventures we are pursuing, particularly in the Eagle Ford and in the Midstream, lead us to be in excellent position to continue with outsized returns on our invested capital. Moderator, I turn it to questions please.

[Operator Instructions] And we'll take our first question from David Kistler with Simmons & Company. David Kistler - Simmons & Company: Real quickly, with the increase of liquids, as we look forward, are you guys going to be breaking out NGLs and oil specifically?

I don't plan to, David, at this point. I think what you can kind of count on going forward from here is, we anticipate about 2/3 of our growth will be in oil and about 1/3 in liquids. I believe, today, our production profile is about half and half, as we've increased our production more aggressively in our natural gas liquids play over the last couple of years than in our oil plays. David Kistler - Simmons & Company: And just kind of building off that a little bit, a lot of folks are increasing their oil and NGLs production. I wanted to get your thoughts on where you might be seeing bottlenecks or potential bottlenecks on the NGL side of things? And how you guys are thinking about managing that risk?

We manage it a number of ways. In ways similar to the way we managed our gas takeaway risk when we were in early stages of evaluating positions in the Marcellus and Haynesville and other gas plays, Barnett and Fayetteville, of course. And we have a big midstream team, and we have a big team underneath Marc and Nick who work on this kind of initiatives. And we are in constant communication with gas processors, and we believe that all the takeaway capacity we need for our liquids production will be in place at the right time. I'll see if Marc wants to augment that at all.

I would just say, you asked where those bottlenecks occur, and really, the three plays that we're in that are most concentrated in liquids are the Granite and Colony Washes, the Southwest Victory area and Marcellus and, ultimately, in the Eagle Ford. We, under our marketing arrangements and through Midstream, Mike Stice, we've made commitments to Mark West in the new plants that they're building up in that area, and we have additional capacity that we're negotiating in both washes and in Eagle Ford. David Kistler - Simmons & Company: And then just as long we're kind of on risk mitigation, looking a little bit at the hedging side of things, looks like you guys put on some pretty nice gas hedges. Curious if they were set up similarly to things you had done in the past or you'd forward-sold call options in the out-years? And if that is the case, can you just kind of give us a little bit of color on how much production you're willing to commit going forward to be able to augment that swap price?

David, I don't have the exact numbers in front of me. The hedges we put on are both of the nature, where we've sold some additional calls and collars and then some of them are just straight swaps. So the swaps and all of the collar arrangements and the calls are going to be set forward in the 10-Q that'll be filed on the ninth.

And next, we'll go to David Heikkinen with Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: Thinking about the drilling carries, why wouldn't you renegotiate the timing of one of your drilling carries until gas prices improve?

I assume, David -- this is Marc -- that you mean to defer those? David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: Exactly. Push them out, is there not an ability to do that? And why wouldn't you?

It requires a consenting partner and I think different people have different views about future gas prices. Plus lease partners have already put in a lot of capital into these plays to date. They're very PV-driven, and so we do not sense any interest from Statoil or in Total in what's going down. In fact, they encourage us to stay active and put their capital to work. And a lot of these carries are in areas remaining in the Marcellus and the Barnett, where we're still holding acreage by drilling new wells, and so there's that interplay that goes into that as well. And of course, if we're receiving the carry, even though gas prices are low right now, in our finding costs are so improved on that, that low costs doesn't really change our return very much at all.

And to just remind you, on those two plays, after carries, our finding cost are less than $0.30 per Mcf. So it's pretty tough for there to be a gas price not attractive to us. I would like to say that once the carries are used and once the acreage is HBP, then we move into a much different note and we've already said $6 is our bogey. And so we look forward to a time, a year from now, for example, in the Haynesville, when most of our acreage will be HBP. And if we need to, we can begin gearing down. In the Fayetteville, I remind you our drilling has gone down by half, seventeen to eight rigs. That's when we reached the point where we can comfortably kind of glide into the finished HBP position. So that will occur next in the Barnett after the Haynesville, and then next after that, the Marcellus. So at the mean time, a large portion of the industry drilling right now is for gas, anyway, is involuntary as it works to HBP leasehold, and most of those leasehold positions were established in '06, '07 and '08. And the time to finished HBP in net acreage will be this year and next year, and after that, I think the industry moves into a much different drilling phase. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: Just kind of continuing in that, Steve, the next question. From your partner's perspective, as you reduce activity below $6 gas price, obviously, impacted by the present value of the Total project. Are they willing to see production decline? And is that kind of built in to the expectations for those projects, those activity declining below $6? Or what's your partner's opinion of that?

Dave, I really can't speak for our partners, and so you'd really just have to ask them at this point. We've been asked to spend the carry dollars that have been given us. We're required to do so in yearly tranches, and these guys take the long view. And so I think I'm sure that the present course that we're on is likely the one that will be continued. But now that both those companies have established U.S. operations and have U.S. Investor Relations folks, encourage you to reach out to them for final answer to those questions David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: I guess, maybe then, what's your thought on reducing activity and allowing production to decline in any of those areas? The Fayetteville looks relatively stable at half the rig count, maybe you're thinking you stabilized production or do you think you're actually seeing a decline?

On the Fayetteville, I think it grows a little bit more. But at eight rigs, over the long period of time, it stays about the same. We're very comfortable with that. And in fact, if gas prices were a bit lower from here and our investment drilling is completely discretionary in the Fayetteville, we're comfortable reducing it further. I mean, we've reduced our drilling everywhere else in the company, except for a deep springer play in Western Oklahoma, where we are close to another carry arrangement there. So essentially, 100% of our drilling in shale play or in gas plays today is either carried by -- is in an area where there is a substantial carry of 75% of our costs, or is in an area like the Fayetteville where we already cut drilling dramatically, or is in the Haynesville where we are a year away from being able to start driving down. In the course of conversations in the Haynesville, we'll need to take plays with some regard to plays with views on the matter as well. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And then can you just, shifting gears, discuss your plans and kind of the structure or thoughts around your Marcellus, either equity infusion or how that deal will actually be structured?

I probably don't have a whole lot of detail for you right now, but we are engaged with discussions with a wide variety of people, some Americans, some international. I'll see if Marc wants to provide any further.

I think early on, it really hasn't changed from when we first announced that we said we would consider anything from the sale of additional minority working interest to equity infusion by some other type of entity, and we're still negotiating with people on every one of those type of deals. David Heikkinen - Tudor, Pickering & Co. Securities, Inc.: And timing for that is back half of this year? Is that in the monetization plans for this year or next year?

I think we've got that in the beginning of Q4.

I think we think we can get it done in the second half of this year, David.

And next, we'll go to Bob Morris with Citigroup.

Question on the 18% production growth that is for next year. How might that be impacted or is it already incorporated in your anticipated Eagle Ford joint venture? In other words, kind of one hand, you may give up 25% of projected production but you're going to get more of other people's money to spend the drill, and I would think that, that would probably more than offset what you give up in protective production in the joint venture.

We are far enough down the road in our discussion that it is baked into our production forecast for 2010 and 2011.

Second question, I know you mentioned that you would spend less on leasehold acreage in the second half of the year. Can you give us somewhat of magnitude relative to the $2.4 billion you spent in the first half of the year on acreage?

In terms of where it was or...

No, you said you will spend less. So obviously, you'll spend less than $2.4 billion, so are you anticipating spending $1 billion? Or what is the range you expect to spend in the second half of the year on leasehold acquisitions?

I'd rather talk about it in terms of net expenditures, and that's going to be dependent on where we end up structuring a JV or two. So I'm not willing to communicate to those potential partners that are out there, that are kind of backed into the number we're looking for. So I'll just say, at this point, I suspect it will be substantially less than what we spent in the first half, especially on that basis.

So for the full year, you still expect monetizations of divestitures to essentially match your leasehold acquisition outlay?

I doubt it will match. Well, when you conclude all monetizations, absolutely. In fact, we said, end up with excess cash this year, when you include monetizations. If you include just leasehold sales, we will not cover all of the CapEx that's been extended to date, that's because we were spending money on several plays that we won't be able to JV until 2011. So I kind of believe these things are over a full year cycle. We bought our first lease in the Eagle Ford in November of 2008, and we're at 855 acres today less than a year later. And I think within a year of having bought that first lease, that we will have executed the transaction and recovered a good bit of our leasehold expenditures. And I think that's a model that will work well for us going forward. So it won't always fit into the handy definition of a year. But also, I really do believe that this will end up being a lot like the gas plays, where they come at you fast and heavy and over the course of it took three years for gas plays to emerge and once the industry found out this kind of rock will work, and now the industry has found out a different kind of rock will work to move oil molecule through and at the pace at which life moves today, I think that three-year timeframe is probably going to be collapsed down to a year, a year and a half. And again, you either play or you don't play. And we've chosen to play and then to be risked by bringing new partners.

So just being apples-to-apples, I was just referencing your comment last quarter that asset sale should match leasehold acquisitions by year end? But now you're thinking that asset sales will come up short of matching leasehold acquisitions?

No, I didn't say that. I said asset sales will exceed leasehold investments if you are looking at asset sales defined as asset sale strictly from joint ventures. It will come up short this year. But if you look at it over the course of the first half of '11, I think you probably will get pretty close to matching that.

Then finally, you mentioned the sale of beginning to sell minority interest in some of these liquid to oil plays. When do you think those proceeds will end up totaling roughly?

It's impossible to know. But these are -- and these are big plays, they all end up being worth about the same at the end of the day. You know those net acre numbers as well as I do. And so if you look at our Niobrara position, we have the current 75,000 acres, you can work some math there if you'd like. And there are other plays where we have potential leasehold positions, not all of which are suitable to bringing in a partner. For example, in our Western Oklahoma, Cleveland, Tonkawa Mississippi play, I doubt seriously we'd bring in a partner simply because the plays are so kind of integrated with our Anadarko Basin, the gas operation. So I think we'll be looking at doing JVs on discrete plays. The Eagle Ford is easy to put in a box. The Niobrara is easy to put in a box. And there are a couple of plays as well that plays that will fit that definition as well.

And next, we have Brian Singer with Goldman Sachs.

First, I think you mentioned in response to an earlier question that you had about half NGLs and oil now going to 2/3 oil, 1/3 liquids. And I was wondering if you could give a little bit more color on the timing of when you see that happening in the context of widening out the guidance for differentials for oil relative to WTI or liquid drills in the WTI in both 2010 and 2011?

Brian, I think to be perfectly clear, I hope what I said was, our existing production base is about 50-50 and our additions going forward are going to be 2/3 to 1/3, so it will take us several years, if not, in the mid part of the decade, to get to a point where we're fully 2/3, 1/3. So that's the goal, but some of these plays are relatively immature and it's not always noble yet today, exactly what that exact percentage would be. But I think if you use 50-50 today and 2/3, 1/3 oil versus NGL over time, we would expect that the differentials that we've recently widened to account for NGLs, will hopefully narrow over time as more of our oil gets more of our liquids production comes in the form of oil.

Do you think that you and others in the industry need to kind of begin a process similar to maybe what you're doing with natural gas to try and encourage demand for NGLs or additional sources of export? Or are your comments that the rise in production will not impact liquids markets applicable to NGLs as well as crude?

Well, we're certainly mindful of that. And we're, I guess, single-handedly trying to restore high profitability to the plastics and chemical industry, as well as natural gas as we've driven grass prices lower and provided more abundant liquids. The difference, I guess, between liquids and natural gas is that liquids, virtually all liquids can be exported. So NGLs do have a floor under them, I think, associated with the worldwide NGL market. And of course U.S. gas world, we haven't yet achieved that. So I think there is much less risk of an NGL pricing collapse in the U.S. But having said that, we're certainly taking our message to consumers of NGLs, that we're going to be increasing supply for a long time to come and they should make appropriate investments to be able to handle our new NGL production.

In your operational updates, you talked about three wells and three different counties in the Eagle Ford. Can you just talk about what those wells say with regard to prospectivity countywide? Or is it kind of too early to then kind of deem a much larger percentage of your first perspective of this one?

No, I don't think it's too early at all. These wells are very prolific, as you can see from our press release. And we think that they, along with other activity, seriously derisk the acreage that we've established across the South, Frio, Duval Counties and the northern and southern portions of those four counties, the northern portion of the two and the southern portion of the other two, form the foundation of our holdings. And we believe that we've tested basically all four corners of our leasehold and are quite happy with the results that we're getting today, and really accelerating our activity. Steve works seven rigs, I guess?

Yes, and eight this month.

And the eighth one that comes later this month. So all systems are go there. It's really nice to drill 900 barrel a day, an oil well that's at $80 a barrel, it's quite a change from drilling 5 million or 10 million a day gas well at $4 in MCF.

And next, we have Joe Allman with JPMorgan. Joseph Allman - JP Morgan Chase & Co: Aubrey, in terms of the strategy, what's the ultimate strategy? Is it to be in terms of production and reserves, roughly 50-50 oil, gas. And how would that, whatever the strategy reflects your long-term view of the oil and gas markets?

I think, given where we're starting from, with our size and given that we've started the year at 90% gas and 10% oil, I think it's probably unlikely that we ever get to 50-50 oil and gas from a volume-reserves perspective. But I do think we can get to a 50-50 value proposition and we can get there, of course, pretty quickly, we hope. Something to look forward the mid part of the decade. And that's predicated on basically the continuation of what we have, which is strong oil markets. I suspect it's stronger, just have to look no further than what's happening in China again. You go back five years and look at what their oil consumption was. I think very few people would've guessed that five years later, they would be at 9 million barrels a day. Nobody seems to believe that in five more years, China could be at 15 million barrels a day, but that's, I think, unavoidable. And when you look at that and you look at what's happening in other Asian countries and you look at oil consumption stabilizing in the OIC countries, then I don't see how you get away from an analysis that said oil prices are going to be strong basically for a long time until this world figures out that you can substitute something cheaper for that oil, which is natural gas. And that's a very obvious fact that completely escapes apparently most American policymakers. But at some point, we're going to have to revisit that as we will be unable, in my view, to compete with China for oil supply in the years ahead. So I still feel that oil will be strong, gas will be kind of range bound here for another year or two. And so the industry is able to reduce its drilling and have more of its drilling become discretionary rather than non-discretionary, and for more coal-fired power to get converted to natural gas. And I think, hopefully, someday, we'll see some inroads on the transportation side. So I do feel like the gas coal switching floor has come up over the last year, so we're not talking about $3 gas price like last year. Today, we're talking about a switching price of about $4. And hopefully, next year can it'll be a little higher as well. So we're just doing what I think anybody would do. You can go out and spend money and find a unit that you can sell for $4. Or you can go out and spend money and finding a unit yourself for $14. And our problem before was we just didn't find -- we didn't think we can find any of the $14 unit. Now we know we can find them and is as quickly as possible, we're making that acceleration in transition over from $4 units to $14 units. And when you ask about the ultimate goal, the ultimate goal is to make a bunch more money doing what we're doing. And the way to do that is to replace $4 unit to $14 unit. Joseph Allman - JP Morgan Chase & Co: And then just different topic. Your JV with Statoil and your search for international gas shale, could you just give us an update on what you've done so far and how that's worked out in the different places? And does your kind of transition here affect such that you might be searching for unconventional oil?

I don't want to say anything that is out of school, so I probably will direct the question more towards Statoil. But the only public announcement we've made is that we're looking at a leasehold block in South Africa, and there are many reasons to look at that. But for us, the primary one is to develop a relationship with Sasol and to maybe work with Statoil and Sasol and hopefully, achieve the holy grail in the Gas business, which would be to turn natural gas into a liquid transportation fuel. I've spent a lot of my time in the last few years trying to get the U.S. transportation switched over from a liquid-based system to gas-based system, and maybe it would be a lot easier to take the fuel and transition it from gas to liquids, and force that conversion where I've been trying to force the conversion of large segments of the U.S. transportation system from liquid to gas. Joseph Allman - JP Morgan Chase & Co: And then in terms of buying additional acreage, what's the advantage of actually buying a bunch of acreage and then flipping a minority part of it versus just buying less acreage from the beginning?

Well, and the once instance you can go buy acreage for x, and in your second scenario, you can go buy acreage for x and that's what you own. Or you can go buy acreage for x and sell it for many, many times x in year x becomes zero. And I'm always attracted to owning less or some are more -- I guess less of something for essentially zero cost than I am on the more of something and have full cost in it. So also you, spred your acreage around. You're able to cover your bases and when you run out of a certain amount of money, you have to choose which part of the play you're going to play in. And when you're able to go buy bigger acreage block and then diversify your working interest by selling down, you can mitigate a few geological risks that way. Joseph Allman - JP Morgan Chase & Co: The $6 gas threshold that you're using for ramping up gas drilling, what is that price? Is that a 12-month strip or...

It's probably the best way to think about it for us, it's almost more of a kind of a psychological level. But I don't think if we saw prompt month gas go to $6, in the curve, it was $4, that it would cause much of a change in our behavior. But if you saw the outyear curves get out above $6, and I think, including something close to the prompt 12 months, that's the signal for us that the market has cured itself enough, that we can get out there and do some more gas drilling. Joseph Allman - JP Morgan Chase & Co: Marc, in terms of capitalized interest, what's the guidance for capitalized interest going forward? And what's the best way to model that? And how much discretion do you have in that number on a quarterly basis?

We have no discretion on a quarterly or any other periodic basis because everything is dictated by GAAP. And with respect to how it's calculated, it's simply the amount of unevaluated acreage taken at our capital rate and then that's what it is on a quarterly basis. Guidance, I think, for that, of course, it shows up in our 10-Q and 10-K all of the time. For Q2, our natural gas and oil properties we had capitalized interest of $171 million. And then with G&G, which is a separate pool and some of our construction, which is very minor on Midstream assets, the total was $178.8 million for the quarter. Most of the folks that follow us, particularly on the debt side, of course, extract that back out. We always show it clearly in our filings with the SEC and put it into interest expense for a calculated basis, so for an adjusted basis. So anyway, I don't know how else to say. It was $161 million last quarter, $178 million, and if you go back a year ago, it was basically not too much different, $152 million in the second quarter of 2009. So is that good to your question, Joe? Joseph Allman - JP Morgan Chase & Co: And I guess, just guidance going forward...

It's totally a function of what our unevaluated acreage is from a GAAP standpoint. So to the extent we've transferred unevaluated acreage into evaluated, then we quit capitalizing interest on it. and to the extent we sell unevaluated acreage in a joint venture or another sale then proceeds for that reduce unevaluated acreage and to the extent we buy into a new play and that acreage is unevaluated at the time that we buy it, then that adds to the amount. So I'd have to look and be knowledgeable about all the future joint ventures we were going to do and how much of it was unevaluated acreage and where we're going to buy acreage and how fast we were going to convert our drilling program unevaluated into evaluated, before I could begin to know how to project what the interest might be that's capitalized.

[Operator Instructions] We'll go next to Dan McSpirit from BMO Capital Markets.

Regarding your very pronounced strategy of selling minority interest to fund drilling activities, how do you view that as a lesser form of delusion maybe versus selling equity to fund those same activities?

Well, it's clearly a lesser form in a sense that there's no dilution of equity, of course. And I think our view is that you can go buy a new lease plays, but once you sell equity, of course, you can't recapture that. So we take a very, i think, stingy view to issuing equity and the fact that we did so this year was a special situation to a group of special investors and it accomplished pretty substantial one quarter deleveraging, and we think it was the absolute right thing to do. Going forward, we just don't see any need for that further, and we'll continue to settle down in new play. But also, we'll continue to monetize some gas assets. One of the ways to get to a more balanced revenue model is not only to add oil, but to subtract gas also.

Yes, Dan, I think about dilution a little bit of the same way that Aubrey does. Obviously, equity is pure dilution. But to calculate what your dilution is, you have to look and see how the acreage is being valued inside of our CHK's common stock price. And I think the work that Jeff and John and others have in developing that asset value slides that we show frequently, indicates that almost no value for unevaluated acreage is being scribed and the stock, if you look at our proved reserves and the investments that we have in CHK and CHKD our development part of that and the other assets we have. And you just look at what we traded then, there's really not much implied value for all of the unevaluated acreage. And clearly, like we've done in the last two years to sell those for evaluation of $10 billion, you just look at it and say, that's much less dilutive from a value proposition, not just from a pure accounting standpoint.

You lay out and repeat your strategy like no other independent in the business from leasing to attracting partners to now getting to an investment grade status. Yet the equity capital markets fail to move on this strategy. What is it do you think the equity capital markets, investors either don't get or don't like about that strategy? Or do you think it just simply takes time to play out?

I think it probably takes time to play out and we're still a 90% gas company and everybody hates gas prices and hates gas prospects in the future. So I think it's difficult for us to escape the gravitational pull of oil or the gravitational pull of low gas prices until we prove that the transition of oil will work. So I just encourage people to look at it this way. By the end of 2012 to latest, 2013, the company's going to have 24 tcfe, same share count and less debt. So today, our enterprise value is $21 billion. So just tell me if in two and a half years that 24 tcf of gas is worth $29 billion. I kind of doubt it. And I think it is worth more like $50 billion to $60 billion. And if that's oil or the same, even the share count has only increased by employee stock grants, then it doesn't take a very smart person to do the math on dividing $50 billion by our number of shares outstanding and seeing where you end up in two and a half years. It's completely mechanical, as it does not require a new discovery, it doesn't require a new slug of capital. It doesn't require anything other than really, in our 9,000 colleagues show up for work everyday and continue to deliver reserve growth of 2.5 to 3 tcfe a year. We create every year a new company inside our own company that the market would capitalize at $8 billion to $10 billion. And you can ignore that for a while. But I don't think it gets ignored over the long term.

And next, we'll go to Biju Perincheril with Jefferies & Company. Biju Perincheril - Jefferies & Company, Inc.: Aubrey, as you look at future monetizations, can you talk about what role VPPs will continue to play? Is there some sort of limit to see how much you can do? Are you considering that assuming the banks look at those transactions as debt?

Yes, we like VPP a lot for a number of reasons, tax-free and we get to keep the sale and get to keep the upside on drilling. But I'll let Mark address the kind of liquidity in that market and other thoughts that he has on VPP.

Biju, our plan is to continue to have one or two VPPs per year. We will size them and assign a tender to them to maximize the oil-gas relationship and to maximize the sweet part of the market for what we see the economic demand. Right now, we're seeing probably as much interest as we ever have and I think the reason for that is at least partly, the nature of the banks being heavy on capital and light on investment opportunities. And remember, while the rating agencies might consider part of these to be debt for GAAP purposes, there are sale the reserves are taking off. We have no dollar obligation going back to '06 when we did our first VPP. There's never been one month in any VPP where the production wasn't satisfied from the curve that we sold to the investor. Today, the capital rate on those is probably close to what our bonds trade at. I would think a five-year VPP probably could come inside a 7.5% pretty easily. And think about what the investors are getting for 7.5% and a 50 bps two-year treasury market, we're getting an investment-grade product that is completely bankruptcy proof. They own the assets, it's fully hedged. And so that becomes a secured hard asset loan for them, which is really an investment, obviously, because they don't book it as a loan. And so there's a lot of demand for that product. And we've continued to work with the big financial institutions that we've sold to in the past. And I know from Nick Dell'Osso who specializes that and our team and discussions we've had with those players, that they have a lot of appetite right now. Biju Perincheril - Jefferies & Company, Inc.: And the banks in your lending group, do they generally look at VPP obligations as debt or not?

I think the banks in our lending group, there's several lending groups in our big revolving credit facility. I think there's 34, 35 players, something like that. I think they look at them as asset sales. I don't know of any...

Really, it's only the rating agencies which you find yourself in this perverse scenario where before you receive and proceed from a VPP sales, the worst the rating agencies think it is. If you get to sell 100 bcf of reserves and you receive $500 million. If you could somehow get $800 million floor, they think that's worse. So if you sold it for $100 million, they would say that's better. So you kind of can't compete with that kind of logic, really.

And we'll go next to Yves Siegel with Credit Suisse. Yves Siegel - Crédit Suisse AG: Have you given guidance as to the CapEx spend on the Midstream over the next several years, what might be a good run rate? And the second part of that question would be, how do you view the MLP in terms of also in respect to future monetizations and helping to finance the growth of the overall entity?

I don't think we've given specific guidance on the MLP around Midstream out several years, currently. And of course, all of this depends on who we do joint ventures with and how much of the Midstream that the joint venture partner takes on. But generally, we've been spending on the $500 million to $700 million range, outside of the CHK and the new MLP publicly traded entity. I think that's probably going to not be more than that as we take on additional joint ventures and as we do drop-down sales similar to the one that Western and Anadarko announced just this last week. Where I think we'll be from a guidance on drop-downs is that I think we'll be in a position to do a couple of them per year at anywhere from $250 million to $500 million each in size and that they'll either be part of one of our systems like Haynesville, or Fayetteville, or other opportunities. And not only will we receive capital in that scenario, but then, that will in turn, reduce the capital spend for the further development of the systems that are transferred. And it's completely consistent with our partner, GIP, and what we have told the market with respect to our sponsorship of CHKN, that we want to do drop-downs in a very favorable setting for the partnership. We own 41.25% of it. We don't intend to sell any units. And so this is going to be another form of capital that will benefit those investors and that partnership on an accretive basis and it will provide us the capital and capital relief from further expenditures as we go forward. All right, I think that's it for today and appreciate everybody's participation. If you have additional calls or questions, please call Jeff or John. Thanks very much. Goodbye.

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